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 March 31, ~~2018~~2019



¨	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 ~~April 27, 2018.~~May 2, 2019.



~~Class~~Title of each class	Trading Symbol	Name of each exchange on which registered	Shares Outstanding
Common stock, No Par Value	ATO	~~111,064,659~~New York Stock Exchange	116,988,209

GLOSSARY OF KEY TERMS




Adjusted diluted ~~EPS from continuing operations~~net income per share	Non-GAAP measure defined as diluted ~~earnings~~net income per share ~~from continuing operations~~ before the one-time, non-cash income tax benefit
Adjusted net income ~~from continuing operations~~	Non-GAAP measure defined as net 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
ASC	Accounting Standards Codification
Bcf	Billion cubic feet
Contribution Margin	Non-GAAP measure defined as operating revenues less purchased gas cost
DARR	Dallas Annual Rate Review
ERISA	Employee Retirement Income Security Act of 1974
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles
GRIP	Gas Reliability Infrastructure Program
GSRS	Gas System Reliability Surcharge
Mcf	Thousand cubic feet
MMcf	Million cubic feet
Moody’s	Moody’s Investors Services, Inc.
NTSB	National Transportation Safety Board
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


	March 31, 2018			September 30, 2017			March 31, 2019			September 30, 2018
	(Unaudited)						(Unaudited)
	(In thousands, except share data)						(In thousands, except share data)
ASSETS
Property, plant and equipment	$	11,903,715		$	11,301,304		$	13,272,148		$	12,567,373
Less accumulated depreciation and amortization	2,142,386			2,042,122			2,300,414			2,196,226
Net property, plant and equipment	9,761,329			9,259,182			10,971,734			10,371,147
Current assets
Cash and cash equivalents	71,074			26,409			108,353			13,771
Accounts receivable, net	407,134			222,263			419,612			253,295
Gas stored underground	89,265			184,653			78,148			165,732
Other current assets	55,263			106,321			65,068			46,055
Total current assets	622,736			539,646			671,181			478,853
Goodwill	730,132			730,132			730,419			730,419
Deferred charges and other assets	242,125			220,636			301,616			294,018
	$	11,356,322		$	10,749,596		$	12,674,950		$	11,874,437
CAPITALIZATION AND LIABILITIES
Shareholders’ equity
Common stock, no par value (stated at $0.005 per share); 200,000,000 shares authorized; issued and outstanding: March 31, 2018 — 111,060,328 shares; September 30, 2017 — 106,104,634 shares	$	555		$	531
Common stock, no par value (stated at $0.005 per share); 200,000,000 shares authorized; issued and outstanding: March 31, 2019 — 116,982,903 shares; September 30, 2018 — 111,273,683 shares							$	585		$	556
Additional paid-in capital	2,951,545			2,536,365			3,485,794			2,974,926
Accumulated other comprehensive loss	(85,011		)	(105,254		)	(116,810		)	(83,647		)
Retained earnings	1,854,257			1,467,024			2,138,532			1,878,116
Shareholders’ equity	4,721,346			3,898,666			5,508,101			4,769,951
Long-term debt	2,617,892			3,067,045			3,528,713			2,493,665
Total capitalization	7,339,238			6,965,711			9,036,814			7,263,616
Current liabilities
Accounts payable and accrued liabilities	230,823			233,050			244,042			217,283
Other current liabilities	538,702			332,648			495,097			547,068
Short-term debt	129,602			447,745			—			575,780
Current maturities of long-term debt	450,000			—			125,000			575,000
Total current liabilities	1,349,127			1,013,443			864,139			1,915,131
Deferred income taxes	1,107,036			1,878,699			1,251,836			1,154,067
Regulatory excess deferred taxes (See Note 6)	737,798			—
Regulatory excess deferred taxes (See Note 13)							712,681			739,670
Regulatory cost of removal obligation	484,746			485,420			462,249			466,405
Pension and postretirement liabilities	237,448			230,588			176,593			177,520
Deferred credits and other liabilities	100,929			175,735			170,638			158,028
	$	11,356,322		$	10,749,596		$	12,674,950		$	11,874,437

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three Months Ended March 31						Three Months Ended March 31
	2018			2017			2019			2018
	(Unaudited) (In thousands, except per share data)						(Unaudited) (In thousands, except per share data)
Operating revenues
Distribution segment	$	1,199,291		$	962,541		$	1,057,889		$	1,199,291
Pipeline and storage segment	120,955			111,972			135,650			120,955
Intersegment eliminations	(100,837		)	(86,327		)	(98,894		)	(100,837		)
Total operating revenues	1,219,409			988,186			1,094,645			1,219,409

Purchased gas cost
Distribution segment	727,053			513,096			570,348			727,053
Pipeline and storage segment	433			725			(90		)	433
Intersegment eliminations	(100,526		)	(86,327		)	(98,582		)	(100,526		)
Total purchased gas cost	626,960			427,494			471,676			626,960

Operation and maintenance expense	161,073			132,239			149,427			159,159
Depreciation and amortization expense	89,381			77,667			96,772			89,381
Taxes, other than income	73,007			65,614			79,093			73,007
Operating income	268,988			285,172			297,677			270,902
Miscellaneous (expense) income	(253		)	833
Other non-operating income (expense)							4,232			(2,167		)
Interest charges	27,304			26,944			26,949			27,304
Income from continuing operations before income taxes	241,431			259,061
Income before income taxes							274,960			241,431
Income tax expense	62,439			97,049			60,072			62,439
Income from continuing operations	178,992			162,012
Gain on sale of discontinued operations, net of tax ($0 and $10,215)	—			2,716
Net income	$	178,992		$	164,728		$	214,888		$	178,992
Basic and diluted net income per share
Income per share from continuing operations	$	1.60		$	1.52
Income per share from discontinued operations	—			0.03
Net income per share - basic and diluted	$	1.60		$	1.55
Basic net income per share							$	1.83		$	1.60
Diluted net income per share							$	1.82		$	1.60
Cash dividends per share	$	0.485		$	0.450		$	0.525		$	0.485
Basic and diluted weighted average shares outstanding	111,706			105,935
Basic weighted average shares outstanding							117,581			111,706
Diluted weighted average shares outstanding							117,756			111,706

Net income							$	214,888		$	178,992
Other comprehensive income (loss), net of tax
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $29 and $(276) (See Note 2)							97			(939		)
Cash flow hedges:
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $(825) and $6,575							(2,792		)	22,244
Total other comprehensive income (loss)							(2,695		)	21,305
Total comprehensive income							$	212,193		$	200,297

See accompanying notes to condensed consolidated financial statements.

~~ATMOS ENERGY CORPORATION~~

~~CONDENSED CONSOLIDATED STATEMENTS OF INCOME~~

Six Months Ended
March 31
2018 2017

(Unaudited)
(In thousands, except per
share data)
Operating revenues
Distribution segment $ 2,060,083
$ 1,717,197
Pipeline and storage segment 247,418
221,924
Intersegment eliminations (198,900 ) (170,767 )
Total operating revenues 2,108,601
1,768,354

Purchased gas cost
Distribution segment 1,190,811
908,442
Pipeline and storage segment 1,345
1,080
Intersegment eliminations (198,279 ) (170,723 )
Total purchased gas cost 993,877
738,799
Operation and maintenance expense 290,640
257,177
Depreciation and amortization expense 177,755
154,625
Taxes, other than income 135,780
122,663
Operating income 510,549
495,090
Miscellaneous expense (2,288 ) (161 )
Interest charges 58,813
57,974
Income from continuing operations before income taxes 449,448
436,955
Income tax (benefit) expense (43,676 ) 160,905
Income from continuing operations 493,124
276,050
Income from discontinued operations, net of tax ($0 and $6,841) —
10,994
Gain on sale of discontinued operations, net of tax ($0 and $10,215) —
2,716
Net Income $ 493,124
$ 289,760
Basic and diluted net income per share
Income per share from continuing operations $ 4.47
$ 2.61
Income per share from discontinued operations —
0.13
Net income per share - basic and diluted $ 4.47
$ 2.74
Cash dividends per share $ 0.97
$ 0.90
Basic and diluted weighted average shares outstanding 110,135
105,610

~~See accompanying notes to condensed consolidated financial statements.~~

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three Months Ended March 31					Six Months Ended March 31					Six Months Ended March 31
	2018			2017		2018			2017		2019			2018
	(Unaudited) (In thousands)										(Unaudited) (In thousands, except per share data)
Operating revenues
Distribution segment											$	1,896,724		$	2,060,083
Pipeline and storage segment											270,120			247,418
Intersegment eliminations											(194,417		)	(198,900		)
Total operating revenues											1,972,427			2,108,601

Purchased gas cost
Distribution segment											1,008,080			1,190,811
Pipeline and storage segment											(448		)	1,345
Intersegment eliminations											(193,791		)	(198,279		)
Total purchased gas cost											813,841			993,877

Operation and maintenance expense											288,027			288,204
Depreciation and amortization expense											192,837			177,755
Taxes, other than income											143,581			135,780
Operating income											534,141			512,985
Other non-operating expense											(3,491		)	(4,724		)
Interest charges											54,798			58,813
Income before income taxes											475,852			449,448
Income tax expense (benefit)											103,318			(43,676		)
Net income											$	372,534		$	493,124
Basic net income per share											$	3.22		$	4.47
Diluted net income per share											$	3.21		$	4.47
Cash dividends per share											$	1.05		$	0.97
Basic weighted average shares outstanding											115,690			110,135
Diluted weighted average shares outstanding											115,794			110,135

Net income	$	178,992		$	164,728	$	493,124		$	289,760	$	372,534		$	493,124
Other comprehensive income (loss), net of tax
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $(276), $879, $(338) and $403	(939		)	1,530		(1,046		)	702
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $29 and $(338) (See Note 2)											97			(1,046		)
Cash flow hedges:
Amortization and unrealized gain on interest rate agreements, net of tax of $6,575, $2,432, $6,026 and $54,861	22,244			4,230		21,289			95,444
Net unrealized gains on commodity cash flow hedges, net of tax of $0, $0, $0 and $3,183	—			—		—			4,982
Total other comprehensive income	21,305			5,760		20,243			101,128
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $(7,405) and $6,026											(25,050		)	21,289
Total other comprehensive income (loss)											(24,953		)	20,243
Total comprehensive income	$	200,297		$	170,488	$	513,367		$	390,888	$	347,581		$	513,367

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended March 31						Six Months Ended March 31
	2018			2017			2019			2018
	(Unaudited) (In thousands)						(Unaudited) (In thousands)
Cash Flows From Operating Activities
Net income	$	493,124		$	289,760		$	372,534		$	493,124
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	177,755			154,810			192,837			177,755
Deferred income taxes	116,023			148,657			96,885			116,023
One-time income tax benefit	(165,675		)	—			—			(165,675		)
Gain on sale of discontinued operations	—			(12,931		)
Discontinued cash flow hedging for natural gas marketing commodity contracts	—			(10,579		)
Other	12,252			10,391			5,334			12,252
Net assets / liabilities from risk management activities	812			26,757			(333		)	812
Net change in operating assets and liabilities	117,076			(54,862		)	(106,428		)	117,076
Net cash provided by operating activities	751,367			552,003			560,829			751,367
Cash Flows From Investing Activities
Capital expenditures	(693,978		)	(559,385		)	(777,586		)	(693,978		)
Acquisition	—			(85,714		)
Proceeds from the sale of discontinued operations	3,000			133,560			4,000			3,000
Available-for-sale securities activities, net	(1,175		)	(8,918		)
Debt and equity securities activities, net							777			(1,175		)
Other, net	4,009			3,787			4,388			4,009
Net cash used in investing activities	(688,144		)	(516,670		)	(768,421		)	(688,144		)
Cash Flows From Financing Activities
Net decrease in short-term debt	(318,143		)	(159,204		)	(575,780		)	(318,143		)
Net proceeds from equity offering	395,092			49,400			494,085			395,092
Issuance of common stock through stock purchase and employee retirement plans	11,902			16,984			10,344			11,902
Proceeds from issuance of long-term debt	—			125,000			1,045,221			—
Interest rate agreements cash collateral	—			25,670
Settlement of interest rate swaps							(90,141		)	—
Repayment of long-term debt							(450,000		)	—
Cash dividends paid	(105,891		)	(95,314		)	(120,328		)	(105,891		)
Debt issuance costs							(11,227		)	—
Other	(1,518		)	—			—			(1,518		)
Net cash used in financing activities	(18,558		)	(37,464		)
Net increase (decrease) in cash and cash equivalents	44,665			(2,131		)
Net cash provided by (used in) financing activities							302,174			(18,558		)
Net increase in cash and cash equivalents							94,582			44,665
Cash and cash equivalents at beginning of period	26,409			47,534			13,771			26,409
Cash and cash equivalents at end of period	$	71,074		$	45,403		$	108,353		$	71,074

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

March 31, ~~2018~~2019

1. Nature of Business

Atmos Energy Corporation (“Atmos Energy” or the “Company”) isand its subsidiaries are engaged in the regulated natural gas distribution and pipeline and storage businesses. Our 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 over three million residential, commercial, public authority and industrial customers through our six regulated distribution divisions, which at March 31, ~~2018,~~2019, 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 our distribution business in 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, aside from accounting policy changes noted below, 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, ~~2017.~~2018. In the opinion of management, all material adjustments (consisting of normal recurring accruals) necessary for a fair presentation have been made to the unaudited consolidated interim-period financial statements. These consolidated interim-period financial statements are condensed as permitted by the instructions to Form 10-Q and should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation included in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017.~~2018. Because of seasonal and other factors, the results of operations for the six-month period ended March 31, ~~2018~~2019 are not indicative of our results of operations for the full ~~2018~~2019 fiscal year, which ends September 30, ~~2018.~~2019.

~~Except for the filed formula rate mechanisms as discussed in Note 9, no~~No events have occurred subsequent to the balance sheet date that would require recognition or disclosure in the condensed consolidated financial statements.

Significant accounting policies

Our accounting policies are described in Note 2 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017.~~2018.

During the second quarter of fiscal ~~2018,~~2019, we completed our annual goodwill impairment assessment using a qualitative assessment, as permitted under U.S. GAAP. We test goodwill for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit. Based on the assessment performed, we determined that our goodwill was not impaired.

~~In May 2014,~~Accounting pronouncements adopted in fiscal 2019

During the ~~Financial Accounting Standards Board (FASB) issued~~first quarter of fiscal 2019, we adopted the following accounting guidance updates, effective October 1, 2018. The adoption of this new guidance, individually and collectively, did not have a ~~comprehensive new revenue~~material impact on our financial position, results of operations or cash flows.

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~~guidance, we are required to recognize revenue when ~~it transfers~~we transfer promised goods or services to customers in an amount that reflects the consideration to which ~~the company expects~~we expect to be entitled in exchange for those goods or services. ~~In doing so, companies may need to use more judgment~~See Note 5 for our discussion of the effects of implementing this standard.

Classification and ~~make more estimates than under current guidance.~~measurement of financial instruments - 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~~requires that we recognize changes in the ~~date of adoption.~~

~~As of March 31, 2018, we had substantially completed the evaluation~~fair value of our ~~sources~~equity securities formerly designated as available-for-sale in other non-operating income (expense) in our condensed consolidated statement of ~~revenue and the impact that the new guidance will have~~comprehensive income on ~~our financial position, results of operations, cash flows and business processes. Based on 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~~prospective basis from the date of adoption. ~~We are currently still evaluating~~Additionally, in accordance with the ~~impact on our financial statement presentation and related disclosures.~~

~~In January 2016, the FASB issued~~ guidance, we reclassified a net $8.2 million unrealized gain related to ~~the classification and measurement of financial instruments.~~these equity securities from accumulated other comprehensive income (AOCI) to retained earnings. The ~~amendments modify the~~ accounting ~~and presentation~~ for ~~certain financial liabilities and equity investments~~debt securities designated as available-for-sale did 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~~change as a result of this new guidance. Accordingly, changes in the fair value of these securities will continue to be recorded as a component of AOCI.

Presentation of the Components of Net Periodic Benefit Cost - The new guidance ~~on our financial position, results~~requires us to present only the current service cost component of the net benefit cost within operations and ~~cash flows.~~maintenance expense in the statement of

comprehensive income. The remaining components of net benefit cost are now recorded in other non-operating income (expense) in our condensed consolidated statements of comprehensive income. The change in presentation of these costs was implemented on a retrospective basis as required by the guidance. In lieu of determining how each component of the net periodic benefit cost was actually reflected in the prior periods’ condensed statement of comprehensive income, we elected to utilize a practical expedient that permits the use of the amounts disclosed for these costs in our pension and post-retirement benefit plans footnote as the basis to retroactively apply this standard.

In addition, under the new guidance, only the service cost component of net benefit cost is eligible for capitalization (e.g., as part of inventory or property, plant, and equipment). We continue to capitalize these costs into property, plant and equipment.

However, the Federal Energy Regulatory Commission (FERC), which establishes the regulatory accounting practices for rate-regulated entities, issued guidance that permits such entities the option to continue to capitalize non-service benefit costs for regulatory purposes. Since the accounting guidelines by the FERC are typically followed by our state regulatory authorities, for U.S. GAAP reporting purposes, we are prospectively deferring into a regulatory asset the portion of non-service components of net periodic benefit cost that are capitalizable for regulatory purposes.

Accounting for Implementation Costs Incurred in A Hosting Arrangement That Is A Service Contract - The new guidance aligns the requirements for capitalizing implementation costs incurred for these contracts with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). We elected to early adopt the new guidance on a prospective basis. Accordingly, we will capitalize the up-front costs incurred for cloud computing arrangements had they been capitalizable in a similar on-premise software solution.

Accounting pronouncements that will be effective after fiscal 2019

In February 2016, the ~~FASB~~Financial Accounting Standards Board (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. Additionally, in January 2018,Subsequently, the FASB issued ~~amendments~~practical expedients to ~~the standard that provides a practical expedient for~~1) allow entities to not evaluate existing or expired land easements that were not previously accounted for as leases under the current ~~guidance.~~guidance and 2) allow entities the option to adopt the standard and recognize a cumulative–effect adjustment to the opening balance of retained earnings in the period of adoption rather than applying the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The new standard will be effective for us beginning on October 1, 2019. We are currently evaluating the effect of this standard and amendments on our financial position, results of operations, cash flows and ~~cash flows.~~business processes.

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 debt 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.~~permitted. We are currently evaluating the potential impact of this new guidance on our financial position, results of operations and cash flows.

In ~~January 2017,~~August 2018, the FASB issued new guidance that ~~simplifies~~modifies the ~~accounting~~disclosure requirements 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 toemployers 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. We early adopted the new standard, effective for our goodwill impairment test performed in our second fiscal quarter of 2018. The new standard did not have a 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~~sponsor defined benefit pension ~~and~~or other postretirement plans. The ~~new~~ guidance ~~requires entities to disaggregate~~removes the ~~current~~disclosure requirements for the amounts of gain/loss and prior service ~~cost component~~cost/credit amortization expected in the following year and the disclosure of the ~~net benefit cost from the other components and present it with other current compensation costs for related employees~~effect of a one-percentage-point change in the ~~statement of income.~~health care cost trend rate, among other changes. The guidance adds certain disclosures including the weighted average interest crediting rate for cash balance plans and a narrative description for the significant change in gains and losses as well as any other ~~components of net benefit cost will be presented outside of income from operations on~~significant change in 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~~plan obligations or property, plant, and equipment). The Federal Energy Regulatory Commission (“FERC”), which regulates interstate transmission pipelines and also establishes, through its Uniform System of Accounts, accounting practices of rate-regulated entities, has issued guidance that states it will permit an election to either continue to capitalize non-service benefit costs or to cease capitalizing such costs for regulatory purposes. Accounting guidelines by the FERC are typically also upheld by state commissions. As such, we plan to continue to capitalize all components of net periodic benefit cost for ratemaking purposes and will defer the non-service cost components as a regulatory asset for U.S. GAAP reporting purposes.assets. The new guidance ~~will be~~is effective for us in the fiscal year beginning on October 1, 2018 and for interim periods within that year. The standard requires retrospective application of the amendment related to the presentation of non-service cost components outside of income from operations in the statement of income and prospective application of the change in eligible costs for capitalization. We do not anticipate the new standard will have a material impact on our financial position, results of operations and cash flows.

In February 2018, the FASB issued new guidance as a result of the Tax Cuts and Jobs Act of 2017 (the "TCJA"), related to the treatment of certain tax effects from accumulated other comprehensive income. The new guidance allows entities to reclassify from accumulated other comprehensive income to retained earnings the stranded tax effects resulting from the adoption of the TCJA. The new guidance will be effective for us in the fiscal year beginning on October 1, 2019 and for interim periods within that year. Early adoption is permitted, including adoption in any interim period for public business entities for reporting periods for which financial statements have not yet been issued2020 and should be applied ~~either in the period of~~on a retrospective basis to all periods presented. Early adoption ~~or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the Tax Cuts and Jobs Act~~ is ~~recognized. We are currently evaluating the impact~~permitted. The adoption of this new guidance onimpacts only our ~~financial results and disclosures.~~disclosures; however we are still evaluating the timing of our adoption.

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 ~~a portion of~~ our regulatory liabilities are recorded as a component of other current liabilities and deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities and our regulatory excess deferred taxes and regulatory cost of removal obligation isare reported separately.

Significant regulatory assets and liabilities as of March 31, ~~2018~~2019 and September 30, ~~2017~~2018 included the following:


	March 31, 2018		September 30, 2017		March 31, 2019		September 30, 2018
	(In thousands)				(In thousands)
Regulatory assets:
Pension and postretirement benefit costs⁽¹⁾	$	20,918	$	26,826	$	7,843	$	6,496
Infrastructure mechanisms⁽²⁾⁽¹⁾	65,286		46,437		107,649		96,739
Deferred gas costs	—		65,714		3,490		1,927
Recoverable loss on reacquired debt	9,954		11,208		7,450		8,702
Deferred pipeline record collection costs	14,646		11,692		23,914		20,467
APT annual adjustment mechanism	—		2,160
Rate case costs	3,016		2,629		1,612		2,741
Other	8,064		10,132		6,691		6,739
	$	121,884	$	176,798	$	158,649	$	143,811
Regulatory liabilities:
Regulatory excess deferred taxes⁽³⁾	$	737,798	$	—
Regulatory cost of service reserve⁽⁴⁾	29,042		—
Regulatory excess deferred taxes⁽²⁾					$	736,634	$	744,895
Regulatory cost of service reserve⁽³⁾					6,175		22,508
Regulatory cost of removal obligation	526,483		521,330		524,067		522,175
Deferred gas costs	167,036		15,559		124,248		94,705
Asset retirement obligation	12,827		12,827		12,887		12,887
APT annual adjustment mechanism	5,081		—		48,524		35,228
Pension and postretirement benefit costs					70,328		69,113
Other	14,740		5,941		16,942		9,486
	$	1,493,007	$	555,657	$	1,539,805	$	1,510,997


(1)	~~Includes $7.8 million and $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)~~(2)

The TCJA resulted in the remeasurement of the net deferred tax liability included in our rate base. Of this amount, $24.0 million is recorded in other current liabilities. The period and timing of the return of the excess deferred taxes ~~will be returned to utility customers~~is being determined by regulators in ~~accordance with regulatory requirements.~~each of our jurisdictions. See Note 613 for further information.

~~(4)~~(3)

Effective January 1, 2018, regulators in each of our service areas required us to establish a regulatory liability for the difference in recoverable federal taxes included in revenues based on the former 35% federal statutory rate and the new 21% federal statutory rate for service provided on or after January 1, 2018. ~~This~~The period and timing of the return of this liability ~~will be returned~~ to utility customers is being determined by regulators in ~~accordance with regulatory requirements.~~each of our jurisdictions. See Note 613 for further information.

3. Segment Information

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

The distribution segment is primarily comprised of our regulated natural gas distribution and related sales operations in eight states.

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.

~~The~~ ~~natural gas marketing segment~~ ~~was 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 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 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. Income taxes are allocated to each segment as if each segment’s taxes were calculated on a separate return basis.2018.

Income statements and capital expenditures for the three and six months ended March 31, ~~2018~~2019 and ~~2017~~2018 by segment are presented in the following tables:


	Three Months Ended March 31, 2018											Three Months Ended March 31, 2019
	Distribution		Pipeline and Storage			Eliminations			Consolidated			Distribution		Pipeline and Storage			Eliminations			Consolidated
	(In thousands)											(In thousands)
Operating revenues from external parties	$	1,198,309	$	21,100		$	—		$	1,219,409		$	1,057,192	$	37,453		$	—		$	1,094,645
Intersegment revenues	982		99,855			(100,837		)	—			697		98,197			(98,894		)	—
Total operating revenues	1,199,291		120,955			(100,837		)	1,219,409			1,057,889		135,650			(98,894		)	1,094,645
Purchased gas cost	727,053		433			(100,526		)	626,960			570,348		(90		)	(98,582		)	471,676
Operation and maintenance expense	131,991		29,393			(311		)	161,073			117,621		32,118			(312		)	149,427
Depreciation and amortization expense	65,649		23,732			—			89,381			69,904		26,868			—			96,772
Taxes, other than income	64,692		8,315			—			73,007			71,053		8,040			—			79,093
Operating income	209,906		59,082			—			268,988			228,963		68,714			—			297,677
Miscellaneous income (expense)	393		(646		)	—			(253		)
Other non-operating income (expense)												5,263		(1,031		)	—			4,232
Interest charges	16,898		10,406			—			27,304			15,896		11,053			—			26,949
Income before income taxes	193,401		48,030			—			241,431			218,330		56,630			—			274,960
Income tax expense	48,158		14,281			—			62,439			46,137		13,935			—			60,072
Net income	$	145,243	$	33,749		$	—		$	178,992		$	172,193	$	42,695		$	—		$	214,888
Capital expenditures	$	224,235	$	86,505		$	—		$	310,740		$	293,270	$	67,912		$	—		$	361,182



	Three Months Ended March 31, 2018
	Distribution			Pipeline and Storage			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	1,198,309		$	21,100		$	—		$	1,219,409
Intersegment revenues	982			99,855			(100,837		)	—
Total operating revenues	1,199,291			120,955			(100,837		)	1,219,409
Purchased gas cost	727,053			433			(100,526		)	626,960
Operation and maintenance expense	130,077			29,393			(311		)	159,159
Depreciation and amortization expense	65,649			23,732			—			89,381
Taxes, other than income	64,692			8,315			—			73,007
Operating income	211,820			59,082			—			270,902
Other non-operating expense	(1,521		)	(646		)	—			(2,167		)
Interest charges	16,898			10,406			—			27,304
Income before income taxes	193,401			48,030			—			241,431
Income tax expense	48,158			14,281			—			62,439
Net income	$	145,243		$	33,749		$	—		$	178,992
Capital expenditures	$	224,235		$	86,505		$	—		$	310,740


	Three Months Ended March 31, 2017												Six Months Ended March 31, 2019
	Distribution		Pipeline and Storage			Natural Gas Marketing		Eliminations			Consolidated		Distribution			Pipeline and Storage			Eliminations			Consolidated
	(In thousands)												(In thousands)
Operating revenues from external parties	$	962,217	$	25,969		$	—	$	—		$	988,186	$	1,895,373		$	77,054		$	—		$	1,972,427
Intersegment revenues	324		86,003			—		(86,327		)	—		1,351			193,066			(194,417		)	—
Total operating revenues	962,541		111,972			—		(86,327		)	988,186		1,896,724			270,120			(194,417		)	1,972,427
Purchased gas cost	513,096		725			—		(86,327		)	427,494		1,008,080			(448		)	(193,791		)	813,841
Operation and maintenance expense	103,703		28,536			—		—			132,239		223,388			65,265			(626		)	288,027
Depreciation and amortization expense	61,302		16,365			—		—			77,667		139,613			53,224			—			192,837
Taxes, other than income	57,636		7,978			—		—			65,614		127,243			16,338			—			143,581
Operating income	226,804		58,368			—		—			285,172		398,400			135,741			—			534,141
Miscellaneous income (expense)	1,029		(196		)	—		—			833
Other non-operating expense													(1,214		)	(2,277		)	—			(3,491		)
Interest charges	16,925		10,019			—		—			26,944		34,106			20,692			—			54,798
Income from continuing operations before income taxes	210,908		48,153			—		—			259,061
Income before income taxes													363,080			112,772			—			475,852
Income tax expense	79,763		17,286			—		—			97,049		76,502			26,816			—			103,318
Income from continuing operations	131,145		30,867			—		—			162,012
Gain on sale of discontinued operations, net of tax	—		—			2,716		—			2,716
Net income	$	131,145	$	30,867		$	2,716	$	—		$	164,728	$	286,578		$	85,956		$	—		$	372,534
Capital expenditures	$	208,185	$	53,238		$	—	$	—		$	261,423	$	595,815		$	181,771		$	—		$	777,586



	Six Months Ended March 31, 2018
	Distribution			Pipeline and Storage			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	2,058,762		$	49,839		$	—		$	2,108,601
Intersegment revenues	1,321			197,579			(198,900		)	—
Total operating revenues	2,060,083			247,418			(198,900		)	2,108,601
Purchased gas cost	1,190,811			1,345			(198,279		)	993,877
Operation and maintenance expense	233,292			55,533			(621		)	288,204
Depreciation and amortization expense	131,083			46,672			—			177,755
Taxes, other than income	119,799			15,981			—			135,780
Operating income	385,098			127,887			—			512,985
Other non-operating expense	(3,443		)	(1,281		)	—			(4,724		)
Interest charges	38,266			20,547			—			58,813
Income before income taxes	343,389			106,059			—			449,448
Income tax (benefit) expense	(50,953		)	7,277			—			(43,676		)
Net income	$	394,342		$	98,782		$	—		$	493,124
Capital expenditures	$	465,484		$	228,494		$	—		$	693,978

Six Months Ended March 31, 2018
Distribution Pipeline and Storage Eliminations Consolidated
(In thousands)
Operating revenues from external parties $ 2,058,762
$ 49,839
$ —
$ 2,108,601
Intersegment revenues 1,321
197,579
(198,900 ) —
Total operating revenues 2,060,083
247,418
(198,900 ) 2,108,601
Purchased gas cost 1,190,811
1,345
(198,279 ) 993,877
Operation and maintenance expense 235,728
55,533
(621 ) 290,640
Depreciation and amortization expense 131,083
46,672
—
177,755
Taxes, other than income 119,799
15,981
—
135,780
Operating income 382,662
127,887
—
510,549
Miscellaneous expense (1,007 ) (1,281 ) —
(2,288 )
Interest charges 38,266
20,547
—
58,813
Income before income taxes 343,389
106,059
—
449,448
Income tax (benefit) expense (50,953 ) 7,277
—
(43,676 )
Net income $ 394,342
$ 98,782
$ —
$ 493,124
Capital expenditures $ 465,484
$ 228,494
$ —
$ 693,978

Six Months Ended March 31, 2017
Distribution Pipeline and Storage Natural Gas Marketing Eliminations Consolidated
(In thousands)
Operating revenues from external parties $ 1,716,483
$ 51,871
$ —
$ —
$ 1,768,354
Intersegment revenues 714
170,053
—
(170,767 ) —
Total operating revenues 1,717,197
221,924
—
(170,767 ) 1,768,354
Purchased gas cost 908,442
1,080
—
(170,723 ) 738,799
Operation and maintenance expense 196,417
60,804
—
(44 ) 257,177
Depreciation and amortization expense 122,459
32,166
—
—
154,625
Taxes, other than income 108,182
14,481
—
—
122,663
Operating income 381,697
113,393
—
—
495,090
Miscellaneous income (expense) 396
(557 ) —
—
(161 )
Interest charges 38,043
19,931
—
—
57,974
Income from continuing operations before income taxes 344,050
92,905
—
—
436,955
Income tax expense 127,541
33,364
—
—
160,905
Income from continuing operations 216,509
59,541
—
—
276,050
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 $ 216,509
$ 59,541
$ 13,710
$ —
$ 289,760
Capital expenditures $ 430,669
$ 128,716
$ —
$ —
$ 559,385

Balance sheet information at March 31, ~~2018~~2019 and September 30, ~~2017~~2018 by segment is presented in the following tables:


	March 31, 2018									March 31, 2019
	Distribution		Pipeline and Storage		Eliminations			Consolidated		Distribution		Pipeline and Storage		Eliminations			Consolidated
	(In thousands)									(In thousands)
Property, plant and equipment, net	$	7,202,673	$	2,558,656	$	—		$	9,761,329	$	8,126,906	$	2,844,828	$	—		$	10,971,734
Total assets	$	10,723,398	$	2,779,330	$	(2,146,406	)	$	11,356,322	$	11,904,290	$	3,071,654	$	(2,300,994	)	$	12,674,950


	September 30, 2017									September 30, 2018
	Distribution		Pipeline and Storage		Eliminations			Consolidated		Distribution		Pipeline and Storage		Eliminations			Consolidated
	(In thousands)									(In thousands)
Property, plant and equipment, net	$	6,849,517	$	2,409,665	$	—		$	9,259,182	$	7,644,693	$	2,726,454	$	—		$	10,371,147
Total assets	$	10,050,164	$	2,621,601	$	(1,922,169	)	$	10,749,596	$	11,109,128	$	2,963,480	$	(2,198,171	)	$	11,874,437

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 weighted average shares outstanding is calculated based upon the weighted average number of common shares outstanding during the periods presented. Also, this calculation includes fully vested stock awards that have not yet been issued as common stock. Additionally, the weighted average shares outstanding for diluted EPS includes the incremental effects of the forward sale agreements, discussed in Note 7, when the impact is dilutive. Basic and diluted earnings per share for the three and six months ended March 31, ~~2018~~2019 and ~~2017~~2018 are calculated as follows:

Three Months Ended
March 31 Six Months Ended
March 31
2018 2017 2018 2017
(In thousands, except per share amounts)
Basic and Diluted Earnings Per Share from continuing operations
Income from continuing operations $ 178,992
$ 162,012
$ 493,124
$ 276,050
Less: Income from continuing operations allocated to participating securities 161
193
459
348
Income from continuing operations available to common shareholders $ 178,831
$ 161,819
$ 492,665
$ 275,702
Basic and diluted weighted average shares outstanding 111,706
105,935
110,135
105,610
Income from continuing operations per share — Basic and Diluted $ 1.60
$ 1.52
$ 4.47
$ 2.61

Basic and Diluted Earnings Per Share from discontinued operations
Income from discontinued operations $ —
$ 2,716
$ —
$ 13,710
Less: Income from discontinued operations allocated to participating securities —
2
—
15
Income from discontinued operations available to common shareholders $ —
$ 2,714
$ —
$ 13,695
Basic and diluted weighted average shares outstanding 111,706
105,935
110,135
105,610
Income from discontinued operations per share — Basic and Diluted $ —
$ 0.03
$ —
$ 0.13
Net income per share — Basic and Diluted $ 1.60
$ 1.55
$ 4.47
$ 2.74



	Three Months Ended March 31				Six Months Ended March 31
	2019		2018		2019		2018
	(In thousands, except per share amounts)
Basic Earnings Per Share
Net income	$	214,888	$	178,992	$	372,534	$	493,124
Less: Income allocated to participating securities	170		161		301		459
Income available to common shareholders	$	214,718	$	178,831	$	372,233	$	492,665
Basic weighted average shares outstanding	117,581		111,706		115,690		110,135
Net income per share — Basic	$	1.83	$	1.60	$	3.22	$	4.47
Diluted Earnings Per Share
Income available to common shareholders	$	214,718	$	178,831	$	372,233	$	492,665
Effect of dilutive shares	—		—		—		—
Income available to common shareholders	$	214,718	$	178,831	$	372,233	$	492,665
Basic weighted average shares outstanding	117,581		111,706		115,690		110,135
Dilutive shares	175		—		104		—
Diluted weighted average shares outstanding	117,756		111,706		115,794		110,135
Net income per share - Diluted	$	1.82	$	1.60	$	3.21	$	4.47

5. Revenue

Effective October 1, 2018, we adopted the new guidance under Accounting Standards Codification (ASC) Topic 606. The implementation of the new guidance did not have a material impact on our financial position, results of operations, cash flow or

5.business processes. However, the guidance introduced new disclosures which are presented below. The following table disaggregates our revenue from contracts with customers by customer type and segment and provides a reconciliation to total revenues for the period presented.



	Three Months Ended March 31, 2019						Six Months Ended March 31, 2019
	Distribution			Pipeline and Storage			Distribution			Pipeline and Storage
	(In thousands)
Gas sales revenues:
Residential	$	695,827		$	—		$	1,243,755		$	—
Commercial	278,945			—			497,883			—
Industrial	35,887			—			70,424			—
Public authority and other	17,087			—			30,372			—
Total gas sales revenues	1,027,746			—			1,842,434			—
Transportation revenues	27,682			142,270			53,082			289,694
Miscellaneous revenues	7,364			2,773			14,314			4,455
Revenues from contracts with customers	1,062,792			145,043			1,909,830			294,149
Alternative revenue program revenues	(5,397		)	(9,393		)	(14,136		)	(24,029		)
Other revenues	494			—			1,030			—
Total operating revenues	$	1,057,889		$	135,650		$	1,896,724		$	270,120

Distribution Revenues

Distribution revenues represent the delivery of natural gas to residential, commercial, industrial and public authority customers at prices based on tariff rates established by regulatory authorities in the states in which we operate. Revenue is recognized and our performance obligation is satisfied over time when natural gas is delivered and simultaneously consumed by our customer. We have elected to use the invoice practical expedient and recognize revenue for volumes delivered that we have the right to invoice our customers. We read meters and bill our customers on a monthly cycle basis. Accordingly, we estimate volumes from the last meter read to the balance sheet date and accrue revenue for gas delivered but not yet billed.

In our Texas and Mississippi jurisdictions, we pay franchise fees and gross receipt taxes to operate in these service areas. These franchise fees and gross receipts taxes are required to be paid regardless of our ability to collect from our customers. Accordingly, we account for these amounts on a gross basis in revenue and we record the associated tax expense as a component of taxes, other than income.

Pipeline and Storage Revenues

Pipeline and storage revenues primarily represent the transportation and storage of natural gas on our Atmos Pipeline-Texas (APT) system and the transmission of natural gas through our 21-mile pipeline in Louisiana. APT provides transportation and storage services to our Mid-Tex Division, other third party local distribution companies and certain industrial customers under tariff rates approved by the Railroad Commission of Texas (RRC). APT also provides certain transportation and storage services to industrial and electric generation customers, as well as marketers and producers, under negotiated rates. Our pipeline in Louisiana is primarily used to aggregate gas supply for our Louisiana Division under a long-term contract and on a more limited basis to third parties. The demand fee charged to our Louisiana Division is subject to regulatory approval by the Louisiana Public Service Commission. We also manage two asset management plans with distribution affiliates of the Company at terms that have been approved by the applicable state regulatory commissions. The performance obligations for these transportation customers are satisfied by means of transporting customer-supplied gas to the designated location. Revenue is recognized and our performance obligation is satisfied over time when natural gas is delivered to the customer. Management determined that these arrangements qualify for the invoice practical expedient for recognizing revenue. For demand fee arrangements, revenue is recognized and our performance obligation is satisfied by standing ready to transport natural gas over the period of each individual month.

Alternative Revenue Program Revenues

In our distribution segment, we have weather-normalization adjustment mechanisms that serve to minimize the effects of weather on our contribution margin. Additionally, APT has a regulatory mechanism that requires that we share with its tariffed customers 75% of the difference between the total non-tariffed revenues earned during a test period and a revenue benchmark of $69.4 million that was established in its most recent rate case. Differences between actual revenues and revenues calculated under these mechanisms adjust the amount billed to customers. These mechanisms are considered to be alternative revenue programs under accounting standards generally accepted in the United States as they are deemed to be contracts between us and our regulator. Accordingly, revenue under these mechanisms are excluded from revenue from contracts with customers.

6. Debt

The nature and terms of our debt instruments and credit facilities are described in detail in Note 5 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017. There~~2018. Other than as described below, there were no material changes in the terms of our debt instruments during the six months ended March 31, ~~2018.~~2019.

Long-term debt at March 31, ~~2018~~2019 and September 30, ~~2017~~2018 consisted of the following:


	March 31, 2018			September 30, 2017			March 31, 2019		September 30, 2018
	(In thousands)						(In thousands)
Unsecured 8.50% Senior Notes, due March 2019	$	450,000		$	450,000		$	—	$	450,000
Unsecured 3.00% Senior Notes, due 2027	500,000			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			750,000			750,000		750,000
Unsecured 4.30% Senior Notes, due 2048							600,000		—
Unsecured 4.125% Senior Notes, due 2049							450,000		—
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 September 2019⁽¹⁾	125,000			125,000			125,000		125,000
Total long-term debt	3,085,000			3,085,000			3,685,000		3,085,000
Less:
Original issue premium / discount on unsecured senior notes and debentures	(4,412		)	(4,384		)
Original issue (premium) / discount on unsecured senior notes and debentures							263		(4,439		)
Debt issuance cost	21,520			22,339			31,024		20,774
Current maturities	450,000			—			125,000		575,000
	$	2,617,892		$	3,067,045		$	3,528,713	$	2,493,665


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

On March 4, 2019, we completed a public offering of $450 million of 4.125% senior notes due 2049. The effective interest rate of these notes is 4.86%, after giving effect to the offering costs and the settlement of the associated forward starting interest rate swaps. The net proceeds, after the underwriting discount and offering expenses, of $443.4 million, together with available cash, was used to repay at maturity our $450 million 8.50% unsecured senior notes due March 15, 2019 and the related settlement of our interest rate swaps for $90.1 million.

On October 4, 2018, we completed a public offering of $600 million of 4.30% senior notes due 2048. We received net proceeds from the offering, after the underwriting discount and offering expenses, of $590.6 million, that were used to repay working capital borrowings pursuant to our commercial paper program. The effective interest rate of these notes is 4.37% after giving effect to the offering costs.

We utilize short-term debt to 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-total-capitalization ratio between 50% and 60%, inclusive of long-term and short-term debt. Our short-term borrowing requirements are ~~affected~~driven primarily by construction work in progress and the seasonal nature of the natural gas business. Changes in the price of natural gas and the

amount of natural gas we need to supply our customers’ needs could significantly affect our borrowing requirements. Our short-term borrowings typically reach their highest levels in the winter months.

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. On March ~~26, 2018,~~29, 2019, we executed ~~one of~~ our ~~two~~final one-year extension ~~options~~option which extended the maturity date from September 25, ~~2021~~2022 to September 25, ~~2022.~~2023. The facility bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a ~~spread~~margin 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. At March 31, ~~2018 and September 30, 2017, a total of $129.6 million and $447.7 million was~~2019, there were no amounts outstanding under our commercial paper program. At September 30, 2018, a total of $575.8 million was outstanding.

Additionally, we have a $25 million 364-day unsecured facility, which was renewed effective April 1, ~~2018~~2019 and expires March 31, ~~2019,~~2020, and a $10 million 364-day unsecured revolving credit facility, which is used primarily to issue letters of credit. At March 31, ~~2018,~~2019, 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 facility to $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 of no greater than 70 percent. At March 31, ~~2018,~~2019, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 41 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 isif not paid at maturity. We were in compliance with all of our debt covenants as of March 31, ~~2018.~~2019. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.

~~6. Impact~~

7. Shareholders' Equity

The following tables present a reconciliation of ~~the Tax Cuts and Jobs Act of 2017~~

~~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 affects Atmos Energy is the reduction of the 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 accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized~~stockholders' equity for the ~~future tax consequences attributable to differences between the financial statement carrying amounts of existing assets~~three 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 enactment of the TCJA on December 22, 2017 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 24.5% for fiscal 2018.

The decrease in the federal statutory income tax rate reduced our net deferred tax liability by $903.5 million. Of this amount, $737.8 million 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 $165.7 million has been reflected as a one-time income tax benefit in our condensed consolidated statement of income for the six months ended March 31, 2018, because these taxes were not considered in our cost of service ratemaking. During the three months ended March 31, 2018, we refined the calculations performed to remeasure the Company's net deferred tax liabilities, which resulted in the recognition of a $3.8 million income tax benefit.

At March 31, 2018, we had $274.7 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 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 $5.2 million in remeasured charitable contribution carryforwards to offset future taxable income. The Company’s charitable contribution carryforwards expire between 2018 and 2023.2018.

The Company also has $21.5 million of state net operating loss carryforwards and $1.5 million of state tax credit carryforwards (net of $5.7 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.



	Common stock			Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total
	Number of Shares	Stated Value		Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total
	(In thousands, except share and per share data)
Balance, September 30, 2018	111,273,683	$	556	$	2,974,926	$	(83,647	)	$	1,878,116		$	4,769,951
Net income	—	—		—		—			157,646			157,646
Other comprehensive loss	—	—		—		(22,258		)	—			(22,258		)
Cash dividends ($0.525 per share)	—	—		—		—			(58,722		)	(58,722		)
Cumulative effect of accounting change (See Note 2)	—	—		—		(8,210		)	8,210			—
Common stock issued:
Public and other stock offerings	5,434,812	27		498,948		—			—			498,975
Stock-based compensation plans	184,464	1		2,602		—			—			2,603
Balance, December 31, 2018	116,892,959	584		3,476,476		(114,115		)	1,985,250			5,348,195
Net income	—	—		—		—			214,888			214,888
Other comprehensive loss	—	—		—		(2,695		)	—			(2,695		)
Cash dividends ($0.525 per share)	—	—		—		—			(61,606		)	(61,606		)
Common stock issued:
Public and other stock offerings	61,006	1		5,453		—			—			5,454
Stock-based compensation plans	28,938	—		3,865		—			—			3,865
Balance, March 31, 2019	116,982,903	$	585	$	3,485,794	$	(116,810	)	$	2,138,532		$	5,508,101

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 $165.7 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 has determined a reasonable estimate for the measurement and accounting for certain effects of the TCJA, including the remeasurement of our net deferred tax liabilities and the establishment of a regulatory liability, which have been reflected as provisional amounts in the March 31, 2018 condensed consolidated financial statements and are described in further detail above. The amounts represent our best estimates based upon records, information and current guidance. We are still analyzing certain aspects of the TCJA, refining our calculations and expecting additional guidance relating to the TCJA from the U.S.



	Common stock			Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total
	Number of Shares	Stated Value		Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total
	(In thousands, except share and per share data)
Balance, September 30, 2017	106,104,634	$	531	$	2,536,365	$	(105,254	)	$	1,467,024		$	3,898,666
Net income	—	—		—		—			314,132			314,132
Other comprehensive loss	—	—		—		(1,062		)	—			(1,062		)
Cash dividends ($0.485 per share)	—	—		—		—			(51,837		)	(51,837		)
Common stock issued:
Public and other stock offerings	4,621,518	22		400,737		—			—			400,759
Stock-based compensation plans	235,960	2		2,960		—			—			2,962
Balance, December 31, 2017	110,962,112	555		2,940,062		(106,316		)	1,729,319			4,563,620
Net income	—	—		—		—			178,992			178,992
Other comprehensive income	—	—		—		21,305			—			21,305
Cash dividends ($0.485 per share)	—	—		—		—			(54,054		)	(54,054		)
Common stock issued:
Public and other stock offerings	76,776	—		6,235		—			—			6,235
Stock-based compensation plans	21,440	—		5,248		—			—			5,248
Balance, March 31, 2018	111,060,328	$	555	$	2,951,545	$	(85,011	)	$	1,854,257		$	4,721,346

Department of the Treasury and the Internal Revenue Service. Any additional guidance issued or future actions of our regulators could potentially affect the final determination of the accounting effects arising from the implementation of the TCJA.

We 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 all our service areas that required us to establish, effective January 1, 2018, a 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 this regulatory liability relating to our cost of service rates resulted in a reduction to our revenues beginning in the second quarter of fiscal 2018. The period and timing of the return of these liabilities to utility customers will be determined by regulators in each of our jurisdictions.

During the fiscal 2018 second quarter, we received approval from regulators to update our cost of service rates to reflect the decrease in the statutory income tax rate in our Colorado, Kansas, Kentucky and Texas service areas. The return to customers of regulatory liabilities recorded for differences in our cost of service rates due to the change in the federal statutory income tax rate and the excess deferred taxes created upon implementation of the TCJA will be addressed in future regulatory proceedings. We are still working with regulators in Louisiana, Mississippi, Tennessee and Virginia to reflect the effects of the TCJA in our cost of service in rates.

~~7. Shareholders' Equity~~

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

On ~~March 28, 2016,~~November 13, 2018, 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~~$3.0 billion in common stock and/or debt securities, which expires ~~March 28, 2019.~~November 13, 2021. This registration statement replaced our previous registration statement that was effectively exhausted in October 2018. At March 31, ~~2018,~~2019, approximately ~~$1.2~~$1.3 billion of securities remained available for issuance under the shelf registration statement.

On November ~~14, 2017,~~19, 2018, we filed a prospectus supplement under the registration statement relating to an at-the-market (ATM) equity sales program under which we may issue and sell shares of our common stock up to an aggregate offering price of $500 million (including shares of common stock that may be sold pursuant to a forward sale agreement entered into concurrently with the ATM equity sales program), which expires ~~March 28, 2019. During~~November 13, 2021.

In February 2019, under the ~~six months ended~~ATM program, we executed forward sale agreements through the ATM with various underwriters who borrowed and sold 1,670,509 shares of our common stock at a weighted average price of $95.46 per share. Under the agreements we have the ability to settle these shares before March 31, ~~2018,~~2020 at a price based on the offering price established on the trade dates. As of March 31, 2019, no shares of common stock ~~were sold~~from these forward sale agreements had been settled. If we had settled all shares under these forward sale agreements at March 31, 2019, we would have received approximately $159.0 million, based on a net price of $95.19 per share.

As of March 31, 2019, the ATM ~~program.~~program (including the impact of the forward sale transactions discussed above) had approximately $340 million of equity available for issuance.

On November 30, ~~2017,~~2018, we filed a prospectus supplement under the registration statement relating to an underwriting agreement to sell 5,390,836 shares of our common stock for $500 million. After expenses, net proceeds from the offering were $494.1 million. Concurrently, we entered into separate forward sale agreements with two underwriters who borrowed and sold 2,668,464 shares of our common stock. Under the agreements we have the ability to settle these shares before March 31, 2020 at a price based on the offering price established on November 28, 2018. As of March 31, 2019, no shares of common stock were settled under the forward sale agreements. If we had settled all shares under the forward agreements at March 31, 2019, we would have received approximately $244.8 million, based on a net price of $91.75 per share.

On November 30, 2017, we filed a prospectus supplement under the previous registration statement relating to an underwriting agreement to sell 4,558,404 shares of our common ~~stock. We received aggregate gross proceeds of~~stock for $400 ~~million and received~~million. After expenses, net proceeds ~~after expenses, of $395.1 million~~ from the ~~offering.~~offering were $395.1 million.

Accumulated Other Comprehensive Income (Loss)

We record deferred gains (losses) in AOCI related to available-for-sale debt securities and interest rate ~~cash flow hedges and prior to the sale of Atmos Energy Marketing, LLC (AEM) on January 3, 2017, commodity contract~~agreement cash flow hedges. Deferred gains (losses) for our available-for-sale debt 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			Total			Available- for-Sale Securities⁽¹⁾			Interest Rate Agreement Cash Flow Hedges			Total
	(In thousands)									(In thousands)
September 30, 2017	$	7,048		$	(112,302	)	$	(105,254	)
September 30, 2018										$	8,124		$	(91,771	)	$	(83,647	)
Other comprehensive income (loss) before reclassifications	(167		)	20,454			20,287			97			(25,966		)	(25,869		)
Amounts reclassified from accumulated other comprehensive income	(879		)	835			(44		)	—			916			916
Net current-period other comprehensive income (loss)	(1,046		)	21,289			20,243			97			(25,050		)	(24,953		)
March 31, 2018	$	6,002		$	(91,013	)	$	(85,011	)
Cumulative effect of accounting change (See Note 2)										(8,210		)	—			(8,210		)
March 31, 2019										$	11		$	(116,821	)	$	(116,810	)

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 634
95,271
9,847
105,752
Amounts reclassified from accumulated other comprehensive income 68
173
(4,865 ) (4,624 )
Net current-period other comprehensive income 702
95,444
4,982
101,128
March 31, 2017 $ 5,186
$ (92,080 ) $ —
$ (86,894 )



	Available- for-Sale Securities⁽¹⁾			Interest Rate Agreement Cash Flow Hedges			Total
	(In thousands)
September 30, 2017	$	7,048		$	(112,302	)	$	(105,254	)
Other comprehensive income (loss) before reclassifications	(167		)	20,454			20,287
Amounts reclassified from accumulated other comprehensive income	(879		)	835			(44		)
Net current-period other comprehensive income (loss)	(1,046		)	21,289			20,243
March 31, 2018	$	6,002		$	(91,013	)	$	(85,011	)

The following tables detail reclassifications out of AOCI for the three and six months ended March 31, 2018 and 2017. Amounts in parentheses below indicate decreases to net income in the statement of income:

Three Months Ended March 31, 2018
Accumulated Other Comprehensive Income Components
Amount Reclassified from
Accumulated Other
Comprehensive Income

Affected Line Item in the
Statement of Income
(In thousands)
Available-for-sale securities $ 1,139
Operation and maintenance expense
1,139
Total before tax
(260 ) Tax expense
$ 879
Net of tax
Cash flow hedges
Interest rate agreements $ (593 ) Interest charges
(593 ) Total before tax
135
Tax benefit
$ (458 ) Net of tax
Total reclassifications $ 421
Net of tax

Three Months Ended March 31, 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 $ (136 ) Interest charges
(136 ) Total before tax
50
Tax benefit
$ (86 ) Net of tax
Total reclassifications $ (154 ) Net of tax

Six Months Ended March 31, 2018
Accumulated Other Comprehensive Income Components
Amount Reclassified from
Accumulated Other
Comprehensive Income

Affected Line Item in the
Statement of Income
(In thousands)
Available-for-sale securities $ 1,139
Operation and maintenance expense
1,139
Total before tax
(260 ) Tax expense
$ 879
Net of tax
Cash flow hedges
Interest rate agreements $ (1,187 ) Interest charges
(1,187 ) Total before tax
352
Tax benefit
$ (835 ) Net of tax
Total reclassifications $ 44
Net of tax

Six Months Ended March 31, 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 $ (273 ) Interest charges
Commodity contracts 7,967

Purchased gas cost⁽¹⁾
7,694
Total before tax
(3,002 ) Tax expense
$ 4,692
Net of tax
Total reclassifications $ 4,624
Net of tax


(1)	~~Amount is presented as part~~Available-for-sale-securities reported in fiscal 2018 include both debt and equity securities, while fiscal 2019 includes only debt securities. See Note 2 for further discussion regarding our adoption of ~~income from discontinued operations in~~ the ~~condensed consolidated statement of income.~~new accounting standard.

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 six months ended March 31, ~~2018~~2019 and ~~2017~~2018 are presented in the following tables. Most of these costs are recoverable through our tariff ~~rates; however, a~~rates. A portion of these costs is capitalized into our rate ~~base.~~base or deferred as a regulatory asset or liability. The remaining costs are recorded as a component of operation and maintenance expense or other non-operating expense. In the second quarter of fiscal 2018, due to the retirement of certain executives, we recognized a settlement loss of $2.4 million associated with our Supplemental Executive Retirement Plan and revalued the net periodic pension cost for the remainder of fiscal 2018. The revaluation of the net periodic pension cost for our Supplemental Executive Retirement Plan resulted in an increase in the discount rate, effective March 1, 2018, to 4.12%, which will increase our net periodic pension cost by approximately $0.1 million for the remainder of the fiscal year.



	Three Months Ended March 31
	Pension Benefits						Other Benefits
	2019			2018			2019			2018
	(In thousands)
Components of net periodic pension cost:
Service cost	$	4,045		$	4,575		$	2,703		$	3,019
Interest cost⁽¹⁾	6,801			6,433			2,958			2,727
Expected return on assets⁽¹⁾	(7,113		)	(6,916		)	(2,665		)	(2,001		)
Amortization of prior service cost (credit)⁽¹⁾	(58		)	(58		)	44			3
Amortization of actuarial (gain) loss⁽¹⁾	1,607			3,085			(2,044		)	(1,619		)
Settlements⁽¹⁾	—			2,415			—			—
Net periodic pension cost	$	5,282		$	9,534		$	996		$	2,129



	Six Months Ended March 31
	Pension Benefits						Other Benefits
	2019			2018			2019			2018
	(In thousands)
Components of net periodic pension cost:
Service cost	$	8,090		$	9,135		$	5,405		$	6,039
Interest cost⁽¹⁾	13,600			12,863			5,919			5,454
Expected return on assets⁽¹⁾	(14,226		)	(13,833		)	(5,330		)	(4,003		)
Amortization of prior service cost (credit)⁽¹⁾	(116		)	(116		)	87			6
Amortization of actuarial (gain) loss⁽¹⁾	3,215			6,174			(4,089		)	(3,237		)
Settlements⁽¹⁾	—			2,415			—			—
Net periodic pension cost	$	10,563		$	16,638		$	1,992		$	4,259


(1)	The components of net periodic cost other than the service cost component are included in the line item other non-operating expense in the condensed consolidated statement of comprehensive income or are capitalized on the condensed consolidated balance sheets as a regulatory asset or liability, as described in Note 2.

Three Months Ended March 31
Pension Benefits Other Benefits
2018 2017 2018 2017
(In thousands)
Components of net periodic pension cost:
Service cost $ 4,575
$ 5,217
$ 3,019
$ 3,109
Interest cost 6,433
6,297
2,727
2,670
Expected return on assets (6,916 ) (6,994 ) (2,001 ) (1,797 )
Amortization of prior service cost (credit) (58 ) (58 ) 3
(411 )
Amortization of actuarial (gain) loss 3,085
4,249
(1,619 ) (707 )
Settlements 2,415
—
—
—
Net periodic pension cost $ 9,534
$ 8,711
$ 2,129
$ 2,864

Six Months Ended March 31
Pension Benefits Other Benefits
2018 2017 2018 2017
(In thousands)
Components of net periodic pension cost:
Service cost $ 9,135
$ 10,433
$ 6,039
$ 6,218
Interest cost 12,863
12,594
5,454
5,340
Expected return on assets (13,833 ) (13,988 ) (4,003 ) (3,593 )
Amortization of prior service cost (credit) (116 ) (116 ) 6
(822 )
Amortization of actuarial (gain) loss 6,174
8,498
(3,237 ) (1,414 )
Settlements 2,415
—
—
—
Net periodic pension cost $ 16,638
$ 17,421
$ 4,259
$ 5,729

~~The assumptions used to develop our net periodic pension cost for the three and six months ended March 31, 2018 and 2017 are as follows:~~

Supplemental Executive Retirement Plan Pension Benefits Other Benefits
2018 2017 2018 2017 2018 2017
Discount rate 4.12% 3.73% 3.89% 3.73% 3.89% 3.73%
Rate of compensation increase 3.50% 3.50% 3.50% 3.50% N/A N/A
Expected return on plan assets N/A N/A 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 not required to make a minimum contribution to our defined benefit plan during fiscal 2018; however, we may consider whether a voluntary contribution is prudent to maintain certain funding levels.

~~We contributed $7.5 million to our other post-retirement benefit plans during the six months ended March 31, 2018. We expect to contribute a total of between~~ ~~$10 million~~ ~~and $20 million to these plans during fiscal 2018.~~

9. Commitments and Contingencies

Litigation and Environmental Matters

In the normal course of business, we are subject to various legal and regulatory proceedings. For such matters, we record liabilities when they are considered probable and estimable, based on currently available facts, our historical experience and our estimates of the ultimate outcome or resolution of the liability in the future. While the outcome of these proceedings is uncertain and a loss in excess of the amount we have accrued is possible though not reasonably estimable, it is the opinion of management that any amounts exceeding the accruals will not have a material adverse impact on our financial position, results of operations or cash flows.

We maintain liability insurance for various risks associated with the operation of our natural gas pipelines and facilities, including for property damage and bodily injury. These liability insurance policies generally require us to be responsible for the first $1.0 million (self-insured retention) of each incident.

The National Transportation Safety Board (NTSB) is investigating an incident that occurred at a Dallas, Texas residence on February 23, 2018 that resulted in one fatality and injuries to four other residents. Together with the Railroad Commission of Texas (RRC) and the Pipeline and Hazardous Materials Safety Administration, Atmos Energy is a party to the investigation and in that capacity is working closely with the NTSB to help determine the cause of this incident.

On March 29, 2018, a civil action was filed in Dallas, Texas against Atmos Energy in response to the February 23rd incident. The plaintiffs seek over $1.0 million in damages for, among with others, wrongful death and personal injury.

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

Purchase Commitments

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. AtThese purchase commitment contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2018. There were no material changes to the purchase commitments for the six months ended March 31, ~~2018, we were committed to purchase 55.0 Bcf within one year~~2019.

Leases

We have entered into operating leases for towers, office and ~~64.7 Bcf within two to three years under indexed contracts.~~

~~Regulatory Matters~~

~~Various regulatory agencies, including the SEC~~warehouse space, vehicles 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 inherentheavy equipment used in our ~~business may be further increased when~~operations. During the six months ended March 31, 2019, we executed amendments to some of our lease agreements that impacted terms as well as our future minimum lease payments. As of March 31, 2019, the remaining lease terms range from one to 20 years and generally provide for the payment of taxes, insurance and maintenance by the lessee. Renewal options exist for certain of these ~~expected additional regulations are adopted.~~leases. The related future minimum lease payments at March 31, 2019 totaled $193.3 million.

Regulatory Matters

Except for routine regulatory proceedings as discussed below, there were no material changes to regulatory matters for the six months ended March 31, 2019.

As of March 31, ~~2018, formula rate mechanisms~~2019, regulatory proceedings were ~~pending regulatory approval~~ in ~~our Louisiana and Tennessee service areas, infrastructure mechanisms were pending regulatory approval~~progress in substantially all of our ~~Mid-Tex, Mississippi and West Texas service areas as well as the Atmos Pipeline–Texas Division and rate cases were pending regulatory approval in our Colorado and Kentucky~~ service areas. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments. ~~On April 3, 2018, we filed formula rate mechanisms in our Mid-Tex and West Texas service areas, seeking increases in operating income.~~ Additionally, as discussed in further detail in Note 6,13, all jurisdictions are addressing impacts of the ~~TCJA.~~Tax Cuts and Jobs Act of 2017 (the "TCJA").

10. Financial Instruments

We currently use financial instruments to mitigate commodity price risk and in the past have also used financial instruments to mitigate 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 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017.~~2018. During the six months ended March 31, ~~2018,~~2019, 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.

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 ~~2017-2018~~2018-2019 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 2633 percent, or ~~15.0~~18.9 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges for accounting purposes.

Interest Rate Risk Management Activities

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

~~As of March 31, 2018,~~In fiscal 2014 and 2015, we ~~had~~entered into forward starting interest rate swaps to ~~effectively~~ fix the Treasury yield component associated with $450 million of the then anticipated issuance of $450 million unsecured senior notes in fiscal 2019. These notes were issued as planned in March 2019 ~~at 3.78%, which~~and we ~~designated as a cash flow hedge at~~settled the ~~time~~swaps with the payment of $90.1 million. Because the swaps were ~~executed.~~ effective, the realized loss was recorded as a component of AOCI and is being recognized as a component of interest expense over the 30-year life of the senior notes.

As of March 31, ~~2018,~~2019, we had ~~$49.1~~$116.8 million of net realized losses in ~~accumulated other comprehensive income (AOCI)~~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.~~2049.

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.~~statements of comprehensive income.

As of March 31, ~~2018,~~2019, 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 March 31, ~~2018,~~2019, we had ~~6,251~~6,065 MMcf of net ~~short~~long 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 March 31, ~~2018~~2019 and September 30, ~~2017.~~2018. The gross amounts of recognized assets and liabilities are netted within our unaudited ~~Condensed Consolidated Balance Sheets~~condensed consolidated balance sheets to the extent that we have netting arrangements with our counterparties. However, for March 31, 2019 and September 30, 2018, no gross amounts and no cash collateral were netted within our consolidated balance sheet.

Balance Sheet Location Assets Liabilities
(In thousands)
March 31, 2018
Designated As Hedges:
Interest rate contracts
Other current assets /
Other current liabilities
$ —
$ (85,948 )
Total —
(85,948 )
Not Designated As Hedges:
Commodity contracts
Other current assets /
Other current liabilities
602
(996 )
Total 602
(996 )
Gross Financial Instruments 602
(86,944 )
Gross Amounts Offset on Consolidated Balance Sheet:
Contract netting —
—
Net Financial Instruments 602
(86,944 )
Cash collateral —
—
Net Assets/Liabilities from Risk Management Activities $ 602
$ (86,944 )




	Balance Sheet Location	Assets		Liabilities
		(In thousands)
March 31, 2019
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	$	1,611	$	(38	)
Gross / Net Financial Instruments		$	1,611	$	(38	)

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, 2018
Designated As Hedges:
Interest rate swaps	Other current assets / Other current liabilities	$	—	$	(56,499	)
Total		—		(56,499		)
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	1,369		(235		)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	250		(103		)
Total		1,619		(338		)
Gross / Net Financial Instruments		$	1,619	$	(56,837	)

Impact of Financial Instruments on the Statement of Comprehensive Income ~~Statement~~

Cash Flow Hedges

As discussed above, in the past our distribution segment ~~has~~had interest rate ~~swap~~ agreements, which we designated as a cash flow ~~hedge~~hedges at the time the ~~swaps~~agreements were executed. The net loss on settled interest rate agreements reclassified from AOCI into interest charges on our condensed consolidated statements of comprehensive income for the three months ended March 31, ~~2018~~2019 and ~~2017~~2018 was $0.6 million and ~~$0.1~~$0.6 million and for the six months ended March 31, ~~2018~~2019 and ~~2017~~2018 was $1.2 million and ~~$0.3~~$1.2 million.

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 six months ended March 31, ~~2018~~2019 and ~~2017.~~2018. The amounts included in the table below exclude gains and losses arising from ineffectiveness because those amounts are immediately recognized in the statement of comprehensive income ~~statement~~ as incurred.

Three Months Ended
March 31 Six Months Ended
March 31
2018 2017 (1) 2018 2017 (1)
(In thousands)
Increase in fair value:
Interest rate agreements $ 21,786
$ 4,144
$ 20,454
$ 95,271
Forward commodity contracts⁽²⁾
—
—
—
9,847
Recognition of (gains) losses in earnings due to settlements:
Interest rate agreements 458
86
835
173
Forward commodity contracts⁽²⁾
—
—
—
(4,865 )
Total other comprehensive income from hedging, net of tax $ 22,244
$ 4,230
$ 21,289
$ 100,426


~~(1)~~	~~Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing jurisdiction for the three and six-month period ended March 31, 2017.~~


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



	Three Months Ended March 31					Six Months Ended March 31
	2019			2018		2019			2018
	(In thousands)
Increase (decrease) in fair value:
Interest rate agreements	$	(3,250	)	$	21,786	$	(25,966	)	$	20,454
Recognition of losses in earnings due to settlements:
Interest rate agreements	458			458		916			835
Total other comprehensive income (loss) from hedging, net of tax	$	(2,792	)	$	22,244	$	(25,050	)	$	21,289

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. The following amounts, net of deferred taxes, represent the expected recognition in earnings, as of March 31, ~~2018,~~2019, of the deferred losses recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments at the date of settlement. ~~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	$	(1,833	)	$	(4,212	)
Thereafter	(47,281		)	(112,609		)
Total	$	(49,114	)	$	(116,821	)

Financial Instruments Not Designated as Hedges

As discussed above, ~~financial instruments~~commodity contracts which are 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 comprehensive 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 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017.~~2018. During the six months ended March 31, ~~2018,~~2019, 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 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017.~~2018.

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 March 31, ~~2018~~2019 and September 30, ~~2017.~~2018. 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		March 31, 2018		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)⁽¹⁾		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral		March 31, 2019
	(In thousands)										(In thousands)
Assets:
Financial instruments	$	—	$	602	$	—	$	—	$	602	$	—	$	1,611	$	—	$	—	$	1,611
Available-for-sale securities
Debt and equity securities
Registered investment companies	39,783		—		—		—		39,783		42,412		—		—		—		42,412
Bond mutual funds	16,308		—		—		—		16,308		21,935		—		—		—		21,935
Bonds(2)	—		31,137		—		—		31,137		—		29,890		—		—		29,890
Money market funds	—		6,437		—		—		6,437		—		2,440		—		—		2,440
Total available-for-sale securities	56,091		37,574		—		—		93,665
Total debt and equity securities											64,347		32,330		—		—		96,677
Total assets	$	56,091	$	38,176	$	—	$	—	$	94,267	$	64,347	$	33,941	$	—	$	—	$	98,288
Liabilities:
Financial instruments	$	—	$	86,944	$	—	$	—	$	86,944	$	—	$	38	$	—	$	—	$	38


	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		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, 2018
	(In thousands)										(In thousands)
Assets:
Financial instruments	$	—	$	3,239	$	—	$	—	$	3,239	$	—	$	1,619	$	—	$	—	$	1,619
Available-for-sale securities
Debt and equity securities
Registered investment companies	41,097		—		—		—		41,097		42,644		—		—		—		42,644
Bond mutual funds	16,371		—		—		—		16,371		21,507		—		—		—		21,507
Bonds(2)	—		29,104		—		—		29,104		—		31,400		—		—		31,400
Money market funds	—		1,837		—		—		1,837		—		3,834		—		—		3,834
Total available-for-sale securities	57,468		30,941		—		—		88,409
Total debt and equity securities											64,151		35,234		—		—		99,385
Total assets	$	57,468	$	34,180	$	—	$	—	$	91,648	$	64,151	$	36,853	$	—	$	—	$	101,004
Liabilities:
Financial instruments	$	—	$	112,398	$	—	$	—	$	112,398	$	—	$	56,837	$	—	$	—	$	56,837

(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~~that are valued at cost.


(2)	Our investments in bonds are considered available-for-sale debt securities in accordance with current accounting guidance as described in Note 2.

~~Available-for-sale~~Debt and equity securities are comprised of ~~the following:~~

Amortized
Cost

Gross
Unrealized
Gain

Gross
Unrealized
Loss

Fair
Value
(In thousands)
As of March 31, 2018
Domestic equity mutual funds $ 25,515
$ 8,194
$ (95 ) $ 33,614
Foreign equity mutual funds 4,138
2,031
—
6,169
Bond mutual funds 16,548
—
(240 ) 16,308
Bonds 31,295
4
(162 ) 31,137
Money market funds 6,437
—
—
6,437
$ 83,933
$ 10,229
$ (497 ) $ 93,665
As of September 30, 2017
Domestic equity mutual funds $ 25,361
$ 8,920
$ —
$ 34,281
Foreign equity mutual funds 4,581
2,235
—
6,816
Bond mutual funds 16,391
2
(22 ) 16,371
Bonds 29,074
46
(16 ) 29,104
Money market funds 1,837
—
—
1,837
$ 77,244
$ 11,203
$ (38 ) �� $ 88,409

~~At March 31, 2018 and September 30, 2017,~~ our available-for-sale debt securities ~~included $46.2 million~~ and ~~$42.9 million related to assets held in separate rabbi trusts for~~ our ~~supplemental executive benefit plans. At March 31, 2018, we maintained investments in bonds that have contractual maturity dates ranging from April 2018 through January 2021.~~

~~These securities are reported at market value with unrealized gains and losses shown as a component of accumulated other comprehensive income (loss).~~equity securities. We regularly evaluate the performance of ~~these investments~~our available-for-sale debt securities on ~~a fund~~an investment by ~~fund~~investment basis for impairment, taking into consideration the ~~fund’s~~investment’s purpose, volatility and current returns. If a determination is made that a decline in fair value is other than temporary, the related ~~fund~~investment is written down to its estimated fair value and the other-than-temporary impairment is recognized in the ~~income statement.~~statement of comprehensive income. At March 31, 2019 and September 30, 2018, our available-for-sale debt securities amortized cost was $29.9 million and $31.5 million. At March 31, 2019, we maintained investments in bonds that have contractual maturity dates ranging from April 2019 through February 2022.

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 March 31, ~~2018~~2019 and September 30, ~~2017:~~2018:


	March 31, 2018		September 30, 2017		March 31, 2019		September 30, 2018
	(In thousands)				(In thousands)
Carrying Amount	$	3,085,000	$	3,085,000	$	3,685,000	$	3,085,000
Fair Value	$	3,291,629	$	3,382,272	$	3,965,641	$	3,161,679

12. Concentration of Credit Risk

Information regarding our concentration of credit risk is disclosed in Note 16 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017.~~2018. During the six months ended March 31, ~~2018,~~2019, there were no material changes in our concentration of credit risk.

13. ~~Discontinued Operations~~Impact of the Tax Cuts and Jobs Act of 2017

On ~~October 29, 2016, we entered~~December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the "TCJA") was signed into law. As a ~~Membership Interest Purchase Agreement (the Agreement) with CenterPoint Energy Services, Inc., a subsidiary of CenterPoint Energy, Inc. (CES) to sell all~~result 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~~implementation 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~~TCJA, we recognized a ~~net gain of $0.03 per diluted share on the sale~~$165.7 million income tax benefit 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 comprehensive income ~~as income from discontinued operations, net of income tax, for~~during the six months ended March 31, ~~2017. Accordingly, expenses~~2018 related to ~~allocable general corporate overhead and interest expense are~~a change in deferred taxes that were not ~~included in these results.~~

~~The tables below set forth selected financial information~~ related to ~~discontinued operations. Operating expenses include operation~~our cost of service ratemaking. The change in deferred taxes related to our cost of service ratemaking (referred to as excess deferred taxes) was reclassified into a regulatory liability and ~~maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income. At~~will be returned to ratepayers in accordance with regulatory requirements. As of March 31, ~~2018~~2019 and September 30, 2017 we did not have any assets or liabilities held for sale. As AEM was sold effective January 1, 2017, no operating results are reported on the condensed consolidated statement of income as discontinued operations for the three months ended March 31, 2017. During the three months ended March 31, 2017, we recorded a gain on sale from discontinued operations for $2.72018, this liability totaled $736.6 million ~~net of tax of $10.2~~and $744.9 million.

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

Six Months Ended
March 31, 2017
(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
Income from discontinued operations 10,994
Gain on sale from discontinued operations, net of tax ($10,215) 2,716
Net income from discontinued operations $ 13,710

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

Six Months Ended
March 31, 2017
(In thousands)
Depreciation and amortization expense $ 185
Capital expenditures $ —
Non-cash 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.

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 six months ended March 31, 2017.

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

~~Impact of Financial Instruments on the Income Statement~~

~~Hedge ineffectiveness~~We have and continue to work with our regulators in each jurisdiction to fully incorporate the effects of the TCJA into customer bills. As of March 31, 2019, we have received approval from regulators to update our cost of service rates to reflect the decrease in the statutory income tax rate in all of our service areas.

Regulators in all of our service areas issued accounting orders that required us to establish, effective January 1, 2018, a separate regulatory liability for ~~our natural gas marketing segment was recorded as a component of purchased gas cost, which is~~the difference in taxes included in ~~discontinued operations~~our rates that were calculated based on a 35% statutory income tax rate and rates based on the ~~condensed consolidated statements~~new 21% statutory income tax rate until the new rates could be established. As of ~~income,~~March 31, 2019, we received approval from regulators to return these liabilities to customers in Colorado, Kansas, Louisiana, Texas and ~~primarily results~~Virginia. This regulatory liability totaled $6.2 million and $22.5 million as of March 31, 2019 and September 30, 2018.

As of March 31, 2019, we received approval from ~~differences~~regulators to return excess deferred taxes in Colorado, Kentucky, Louisiana, Mississippi, Tennessee, certain jurisdictions in Texas and Virginia in accordance with regulatory proceedings on a provisional basis over periods ranging from 13 to 51 years. In our remaining jurisdictions, the ~~location and timing~~treatment of the ~~derivative instrument and~~effects of the ~~hedged item. For~~TCJA in rates is being addressed in ongoing or will be addressed in future regulatory proceedings.

The SEC issued guidance in Staff Accounting Bulletin 118 (SAB 118), which allowed us to record provisional amounts during a one-year measurement period, similar to the ~~six months ended March 31, 2017, we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $3.4 million. Additional information regarding ineffectiveness recognized~~measurement period in accounting for business combinations. The Company recorded provisional amounts for the income ~~statement is included in~~tax effects of the ~~tables below.~~

~~Fair Value Hedges~~

~~The~~TCJA for the fiscal year ended September 30, 2018. Although the Company no longer considers the accounting effects of the TCJA to be provisional under SAB 118, many aspects of the TCJA remain unclear and its impact ~~of our natural gas marketing segment commodity contracts designated as fair value hedges and the related hedged item~~ on the ~~results~~Company's income tax balances may change following further interpretation of ~~discontinued operations on our condensed consolidated income statement for~~TCJA provisions by issuance of U.S. Treasury regulations or guidance from the ~~six months ended March 31, 2017 is presented below.~~

Six Months Ended
March 31, 2017
(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

~~Basis ineffectiveness arises from natural gas market price differences between~~Internal Revenue Service. We continue to monitor and assess the ~~locations~~accounting implications 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 natural gas marketing segment cash flow hedges on our condensed consolidated income statements for the six months ended March 31, 2017 is presented below:~~

Six Months Ended
March 31, 2017

(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 six months ended March 31, 2017 was a decrease in purchased gas cost of $6.8 million, which is included in discontinued operationsTCJA developments on the ~~condensed~~ consolidated ~~statements of income.~~financial statements.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of

Atmos Energy Corporation

Results of Review of Interim Financial Statements

We have reviewed the accompanying condensed consolidated balance sheet of Atmos Energy Corporation as of March 31, ~~2018 and~~2019, the related condensed consolidated statements of ~~income and~~ comprehensive income for the three and six month periods ended March 31, ~~2018~~2019 and ~~2017 and~~2018, the condensed consolidated statements of cash flows for the six month periods ended March 31, 2019 and 2018 and ~~2017. These~~the related notes (collectively referred to as the "condensed consolidated interim financial statements"). Based on our reviews, we are not aware of any material modifications that should be made to the condensed consolidated interim financial statements ~~are the responsibility of the Company’s management.~~for them to be in conformity with U.S. generally accepted accounting principles.

We ~~conducted our review~~have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States). (PCAOB), the consolidated balance sheet of the Company as of September 30, 2018, the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended, and related notes and schedule (not presented herein); and in our report dated November 13, 2018, 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, 2018, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

These financial statements are the responsibility of the Company's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the SEC and the PCAOB. We conducted our review in accordance with the standards of the PCAOB. A review of interim financial ~~information~~statements 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,~~PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

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

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

May ~~2, 2018~~7, 2019



Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

INTRODUCTION

The following discussion should be read in conjunction with the condensed consolidated financial statements in this Quarterly Report on Form 10-Q and Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended September 30, ~~2017.~~2018.

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: state and local regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; increased federal regulatory oversight and potential penalties; possible increased federal, state and local regulation of the safety of our operations; the inherent hazards and risks involved in distributing, transporting and storing natural gas; the capital-intensive nature of our business; our ability to continue to access the credit and capital markets to execute our 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 performance or creditworthiness and interest rate risk; the concentration of our operations in Texas; the impact of adverse economic conditions on our customers; changes in the availability and price of natural gas; the availability and accessibility of contracted gas supplies, interstate pipeline and/or storage services; increased competition from energy suppliers and alternative forms of energy; adverse weather conditions; ~~the capital-intensive nature of our 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 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 change or related additional legislation or regulation in the future; ~~the inherent hazards and risks involved in distributing, transporting and storing natural gas;~~ the threat of cyber-attacks or acts of cyber-terrorism that could disrupt our business operations and information technology 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 in the regulated natural gas distribution and pipeline and storage businesses. We distribute natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers throughout our six distribution divisions, which at March 31, ~~2018~~2019 covered service areas located in eight states. In addition, we transport natural gas for others through our distribution and pipeline systems.

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

The distribution segment is primarily comprised of our regulated natural gas distribution and related sales operations in eight states.

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.

~~The~~ ~~natural gas marketing segment~~ ~~was 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 our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017~~2018 and include the following:

Regulation

Unbilled revenue

Pension and other postretirement plans

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 six months ended March 31, ~~2018.~~2019.

Non-GAAP Financial Measures

Our operations are affected by the cost of natural 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 condensed consolidated statements of comprehensive income ~~statement~~ as purchased gas cost. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe ~~contribution margin,~~Contribution Margin, a non-GAAP financial measure, defined as operating revenues less purchased gas cost, is a more useful and relevant measure to analyze our financial performance than operating revenues. As such, the following discussion and analysis of our financial performance will reference ~~contribution margin~~Contribution Margin rather than operating revenues and purchased gas cost individually. Further, the term ~~contribution margin~~Contribution Margin is not intended to represent operating income, the most comparable GAAP financial measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.

As described further in Note 6,13, 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 $3.8 million and $165.7 million for the three and six months ended March 31, 2018. ~~During the three months ended March 31, 2018, we recognized a $3.8 million benefit after we refined the initial measurement calculations performed during the first quarter.~~ Due to the non-recurring nature of this benefit, we believe that net income ~~from continuing operations~~ and diluted ~~earnings~~net income 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 net income ~~from continuing operations~~ and ~~consolidated~~ diluted ~~earnings~~net income per share ~~from continuing operations.~~in order to allow investors to better analyze our core results and allow the information to be presented on a comparative basis to the prior year. Accordingly, the following discussion and analysis of our financial performance will reference adjusted net income ~~from continuing operations~~ and adjusted diluted earnings per share, which is calculated as follows:



	Three Months Ended March 31
	2019		2018			Change
	(In thousands, except per share data)
Net income	$	214,888	$	178,992		$	35,896
TCJA non-cash income tax benefit	—		(3,791		)	3,791
Adjusted net income	$	214,888	$	175,201		$	39,687

Diluted net income per share	$	1.82	$	1.60		$	0.22
Diluted EPS from TCJA non-cash income tax benefit	—		(0.03		)	0.03
Adjusted diluted net income per share	$	1.82	$	1.57		$	0.25

Three Months Ended March 31
2018 2017 Change
(In thousands, except per share data)
Income from continuing operations $ 178,992
$ 162,012
$ 16,980
TCJA non-cash income tax benefit 3,791
—
3,791
Adjusted income from continuing operations $ 175,201
$ 162,012
$ 13,189

Consolidated diluted EPS from continuing operations $ 1.60
$ 1.52
$ 0.08
Diluted EPS from TCJA non-cash income tax benefit 0.03
—
0.03
Adjusted diluted EPS from continuing operations $ 1.57
$ 1.52
$ 0.05

Six Months Ended March 31
2018 2017 Change
(In thousands, except per share data)
Income from continuing operations $ 493,124
$ 276,050
$ 217,074
TCJA non-cash income tax benefit 165,675
—
165,675
Adjusted income from continuing operations $ 327,449
$ 276,050
$ 51,399

Consolidated diluted EPS from continuing operations $ 4.47
$ 2.61
$ 1.86
Diluted EPS from TCJA non-cash income tax benefit 1.50
—
1.50
Adjusted diluted EPS from continuing operations $ 2.97
$ 2.61
$ 0.36



	Six Months Ended March 31
	2019		2018			Change
	(In thousands, except per share data)
Net income	$	372,534	$	493,124		$	(120,590	)
TCJA non-cash income tax benefit	—		(165,675		)	165,675
Adjusted net income	$	372,534	$	327,449		$	45,085

Diluted net income per share	$	3.21	$	4.47		$	(1.26	)
Diluted EPS from TCJA non-cash income tax benefit	—		(1.50		)	1.50
Adjusted diluted net income per share	$	3.21	$	2.97		$	0.24

RESULTS OF OPERATIONS

Executive Summary

Atmos Energy strives to operate our businesses safely and reliably while delivering superior shareholder value. Our commitment to modernizing our natural gas distribution and transmission systems requires a significant ~~levels~~level of capital spending. We have the ability to begin recovering a significant portion of these investments timely through rate designs and mechanisms that reduce or eliminate regulatory lag and separate the recovery of our approved rate from customer usage patterns. The execution of our capital spending program, the ability to recover these investments timely and our ability to access the capital markets to satisfy our financing needs are the primary drivers that affect our financial performance.

During the six months ended March 31, ~~2018,~~2019, we recorded net income ~~from continuing operations~~of $372.5 million, or $3.21 per diluted share, compared to net income of $493.1 million, or $4.47 ~~per diluted share, compared to income from continuing operations of $276.1 million, or $2.61~~ per diluted share for the six months ended March 31, ~~2017.~~2018.

After adjusting for the nonrecurring benefit recognized after implementing the TCJA in fiscal 2018, we recorded adjusted net income ~~from continuing operations~~ of $327.4 million, or $2.97 per diluted share for the six months ended March 31, ~~2018, compared to adjusted income from continuing operations of $276.1 million, or $2.61 per diluted share for the six months ended March 31, 2017.~~2018. The period-over-period increase in adjusted net income of ~~$51.3~~$45.1 million, or 1914 percent, largely reflects positive rate outcomes, ~~weather that was 33 percent colder than the prior year,~~ customer growth in our distribution business, positive Contribution Margins in our pipeline and storage business due to wider spreads and positive supply and demand dynamics affecting the Permian Basin and the impact of the TCJA on our effective income tax ~~rate, partially offset by reduced revenues as a result of implementing the TCJA.~~rate. During the six months ended March 31, ~~2018,~~2019, we ~~completed ten~~implemented regulatory ~~proceedings, resulting~~actions which resulted in an increase in annual operating income of ~~$47.4~~$20.9 million and had ~~ten~~thirteen ratemaking efforts in progress at March 31, ~~2018~~2019, seeking a total increase in annual operating income of ~~$65.3 million. On April 3, 2018, we filed formula rate mechanisms in our Mid-Tex and West Texas service areas, seeking increases in operating income of $28.0 million and $4.0~~$159.3 million.

Capital expenditures for the ~~first~~ six months ~~of fiscal 2018 were $694.0~~ended March 31, 2019 increased 12 percent period-over-period, to $777.6 million. Over 80 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 ~~approximate $1.4~~range from $1.65 billion to $1.75 billion for fiscal ~~2018.~~2019. We funded our capital expenditures program primarily through operating cash flows of ~~$751.4~~$560.8 million. Additionally, we ~~issued $400 million of common stock~~completed approximately $2 billion in external financing during the six months ended March 31, ~~2018.~~2019 with the issuance of $1.1 billion in 30-year senior notes and approximately $908 million of common stock, of which proceeds of approximately $408 million were allocated to forward sale agreements. The net proceeds from ~~the issuance~~these issuances, together with available cash, were ~~primarily~~ used to repay at maturity our $450 million 8.50% unsecured senior notes, to repay short-term debt under our commercial paper program, to fund capital spending and for 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 ~~7.8~~8.2 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 March 31, 2018. 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.

As a result of implementing the TCJA, we remeasured our net deferred tax liability using our new federal statutory income tax rate, which reduced our net deferred tax liability by $903.5 million. Of this amount, $737.8 million was reclassified to a regulatory liability, which will be returned to utility customers. The remaining $165.7 million was recognized as a one-time, non-cash income tax benefit in our condensed consolidated statement of income for the six months ended March 31, 2018. Of this amount, $3.8 million was recorded during the second quarter as we refined the remeasurement calculations performed during the first quarter.

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 established regulatory liabilities in all our jurisdictions 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. The establishment of these regulatory liabilities for our cost of service rates reduced our revenues. The period and timing of the return of these liabilities to utility customers will be determined by regulators in each of our jurisdictions. During the second quarter of fiscal 2018, some of our jurisdictions have approved changes to customer rates as discussed in Note 6, which have been reflected in customer bills as of the effective dates stipulated in the regulatory or statutory proceeding. Return to customers of the regulatory liabilities related to the TCJA in these jurisdictions will be addressed in future regulatory proceedings.

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-to-total-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 2022.2019.

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~~to minimize regulatory lag and, ultimately, ~~separating~~separate the recovery of our approved ~~margins~~rates 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~~have 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~~We are generally able to pass the cost of gas ~~is passed~~ through to our customers without ~~markup. Therefore,~~markup under purchased gas cost adjustment mechanisms; therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Contribution ~~margin~~Margin 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 ~~contribution margin,~~Contribution Margin, over time the impact is offset within operating income.

~~As discussed above,~~Although the cost of gas typically does not have a direct impact on our ~~contribution margin. However,~~Contribution Margin, 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,~~Currently, gas cost risk has been mitigated ~~in recent years through improvements in~~by rate design that ~~allow~~allows us to collect from our customers the gas cost portion of our bad debt expense on approximately 76 percent of our residential and commercial margins.

Three Months Ended March 31, ~~2018~~2019 compared with Three Months Ended March 31, ~~2017~~2018

Financial and operational highlights for our distribution segment for the three months ended March 31, ~~2018~~2019 and ~~2017~~2018 are presented below.


	Three Months Ended March 31								Three Months Ended March 31
	2018			2017		Change			2019		2018			Change
	(In thousands, unless otherwise noted)								(In thousands, unless otherwise noted)
Operating revenues	$	1,199,291		$	962,541	$	236,750		$	1,057,889	$	1,199,291		$	(141,402	)
Purchased gas cost	727,053			513,096		213,957			570,348		727,053			(156,705		)
Contribution margin	472,238			449,445		22,793
Contribution Margin									487,541		472,238			15,303
Operating expenses	262,332			222,641		39,691			258,578		260,418			(1,840		)
Operating income	209,906			226,804		(16,898		)	228,963		211,820			17,143
Miscellaneous income	393			1,029		(636		)
Other non-operating income (expense)									5,263		(1,521		)	6,784
Interest charges	16,898			16,925		(27		)	15,896		16,898			(1,002		)
Income before income taxes	193,401			210,908		(17,507		)	218,330		193,401			24,929
TCJA non-cash income tax benefit	(3,791		)	—		(3,791		)	—		(3,791		)	3,791
Income tax expense	51,949			79,763		(27,814		)	46,137		51,949			(5,812		)
Net income	$	145,243		$	131,145	$	14,098		$	172,193	$	145,243		$	26,950
Consolidated distribution sales volumes — MMcf	134,046			97,754		36,292			139,242		134,046			5,196
Consolidated distribution transportation volumes — MMcf	45,932			39,915		6,017			46,190		45,932			258
Total consolidated distribution throughput — MMcf	179,978			137,669		42,309			185,432		179,978			5,454
Consolidated distribution average cost of gas per Mcf sold	$	5.42		$	5.25	$	0.17		$	4.10	$	5.42		$	(1.32	)

Income before income taxes for our distribution segment ~~decreased 8~~increased thirteen percent, primarily due to a ~~$39.7~~$15.3 million increase in Contribution Margin as well as a $1.8 million decrease in operating ~~expenses, partially offset by a $22.8 million increase in contribution margin.~~expenses. The quarter-over-quarter increase in ~~contribution margin~~Contribution Margin primarily reflects:

a ~~$27.6~~$24.1 million net increase in rate adjustments, ~~before~~after the effect of the TCJA, primarily in our Mid-Tex and ~~West Texas~~Mississippi Divisions.

a ~~$9.3~~$3.9 million increase from customer growth primarily in our Mid-Tex Division.

an $8.5 million decrease in residential and commercial net consumption, primarily ~~in our Mid-Tex and Mississippi Divisions.~~due to inconsistent weather patterns experienced during the quarter compared to the prior-year quarter.

~~an $8.9~~a $2.8 million ~~increase~~decrease in revenue-related taxes primarily in our Mid-Tex ~~Division, offset by a corresponding $5.4 million increase in the related tax expense.~~

~~a $4.3 million increase in transportation margin primarily in our Kentucky/Mid-States and West Texas Divisions.~~

a $26.2 million decrease in contribution margin due to the inclusion of the lower statutory rate in our revenues due to implementation of the TCJA. Of this amount, $4.8 million has been reflected in customer bills. The remaining $21.4 million relates to the establishment of regulatory liabilities for the difference between the former 35% federal statutory rate and the current 21% federal statutory rate as further described in Note 6.Division.

The ~~increase~~quarter-over-quarter decrease in operating expenses, which includes operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, ~~largely~~primarily reflects a $23 million decrease in nonrecurring expenses ~~incurred after we decided~~related to ~~undertake a~~the planned outage of our natural gas distribution system in Northwest ~~Dallas. In late February 2018, there~~Dallas in March 2018. These decreases were ~~gas-related incidents in Northwest Dallas, one of which resulted in a fatality~~partially offset by higher system integrity and ~~injuries to four other residents. The National Transportation Safety Board (NTSB) is investigating the latter incident. Together with the Railroad Commission of Texas~~maintenance spending, higher employee costs and the Pipeline and Hazardous Materials Safety Administration, we are a party to the investigation and in that capacity we are working closely with the NTSB to help determine the cause of this incident. On March 1, 2018, we initiated a planned outage of a portion of our natural gas distribution system in Northwest Dallas that affected approximately 2,400 homes. The outage

~~was initiated after we experienced a sudden and unexplainable~~an increase in leaks in this confined geographic area in less than a week’s time. Based upon our preliminary assessment, we believe an extraordinary combination of events and circumstances that could not have been predicted, anticipated, readily modeled or foreseen damaged our pipeline system in that area. These events and circumstances, include, but are not limited to, geology, hydrology, soil conditions and record rainfall. The system was replaced and placed into service by March 31, 2018. While the system was replaced, we provided financial assistance to the affected residents and incurred other related costs of approximately $23 million.

~~The remaining increase in operating expenses is attributable to incremental system integrity activities, increased~~ depreciation expense and property taxes of $8.8 million associated with increased capital investments.

Additionally, the quarter-over-quarter increase in other non-operating income primarily reflects the adoption of new accounting standards. As discussed further in Note 2, we are now required to recognize changes in the fair value of our equity securities formerly designated as available-for-sale on our condensed consolidated statement of comprehensive income.

The decrease in income tax expense reflects a reduction in our effective tax rate from ~~37.8%~~26.9% to ~~26.9%~~21.1%, as a result of the TCJA. As the Company's fiscal year end is September 30, the Internal Revenue Code required the Company to use a blended statutory federal corporate income tax rate for fiscal 2018 due to the enactment of the TCJA in the first fiscal quarter.

The following table shows our operating income by distribution division, in order of total rate base, for the three months ended March 31, ~~2018~~2019 and ~~2017.~~2018. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.


	Three Months Ended March 31							Three Months Ended March 31
	2018		2017		Change			2019		2018		Change
	(In thousands)							(In thousands)
Mid-Tex	$	78,190	$	90,809	$	(12,619	)	$	93,131	$	78,190	$	14,941
Kentucky/Mid-States	36,529		34,010		2,519			35,022		36,529		(1,507		)
Louisiana	30,760		30,362		398			32,901		30,760		2,141
West Texas	21,430		21,023		407			20,921		21,430		(509		)
Mississippi	25,096		25,802		(706		)	27,110		25,096		2,014
Colorado-Kansas	17,474		18,331		(857		)	19,704		17,474		2,230
Other	427		6,467		(6,040		)	174		2,341		(2,167		)
Total	$	209,906	$	226,804	$	(16,898	)	$	228,963	$	211,820	$	17,143

Six Months Ended March 31, ~~2018~~2019 compared with Six Months Ended March 31, ~~2017~~2018

Financial and operational highlights for our distribution segment for the six months ended March 31, ~~2018~~2019 and ~~2017~~2018 are presented below.

Six Months Ended March 31
2018 2017 Change
(In thousands, unless otherwise noted)
Operating revenues $ 2,060,083
$ 1,717,197
$ 342,886
Purchased gas cost 1,190,811
908,442
282,369
Contribution margin 869,272
808,755
60,517
Operating expenses 486,610
427,058
59,552
Operating income 382,662
381,697
965
Miscellaneous (expense) income (1,007 ) 396
(1,403 )
Interest charges 38,266
38,043
223
Income before income taxes 343,389
344,050
(661 )
One-time, non-cash income tax benefit (143,942 ) —
(143,942 )
Income tax expense 92,989
127,541
(34,552 )
Net income $ 394,342
$ 216,509
$ 177,833
Consolidated regulated distribution sales volumes — MMcf 220,353
172,184
48,169
Consolidated regulated distribution transportation volumes — MMcf 83,982
76,090
7,892
Total consolidated regulated distribution throughput — MMcf 304,335
248,274
56,061
Consolidated regulated distribution average cost of gas per Mcf sold $ 5.40
$ 5.28
$ 0.12



	Six Months Ended March 31
	2019			2018			Change
	(In thousands, unless otherwise noted)
Operating revenues	$	1,896,724		$	2,060,083		$	(163,359	)
Purchased gas cost	1,008,080			1,190,811			(182,731		)
Contribution Margin	888,644			869,272			19,372
Operating expenses	490,244			484,174			6,070
Operating income	398,400			385,098			13,302
Other non-operating expense	(1,214		)	(3,443		)	2,229
Interest charges	34,106			38,266			(4,160		)
Income before income taxes	363,080			343,389			19,691
TCJA non-cash income tax benefit	—			(143,942		)	143,942
Income tax expense	76,502			92,989			(16,487		)
Net income	$	286,578		$	394,342		$	(107,764	)
Consolidated distribution sales volumes — MMcf	240,940			220,353			20,587
Consolidated distribution transportation volumes — MMcf	87,238			83,982			3,256
Total consolidated distribution throughput — MMcf	328,178			304,335			23,843
Consolidated distribution average cost of gas per Mcf sold	$	4.18		$	5.40		$	(1.22	)

Income before income taxes for our distribution segment ~~was flat compared to the prior year,~~increased six percent, primarily due to a ~~$59.6~~$19.4 million increase in Contribution Margin, partially offset by a $6.1 million increase in operating ~~expenses offset with a $60.5 million increase in contribution margin.~~expenses. The year-over-year increase in ~~contribution margin~~Contribution Margin primarily reflects:

a ~~$53.1~~$16.7 million net increase in rate adjustments, ~~excluding rate adjustments resulting from~~after the effect of the TCJA, ~~primarily in our Mid-Tex, Kentucky/Mid-States and West Texas Divisions.~~

~~a $15.0 million increase in residential and commercial net consumption,~~ primarily in our Mid-Tex and Mississippi Divisions.

~~an $11.2~~a $7.7 million increase from customer growth primarily in our Mid-Tex and West Texas Divisions.

a $4.1 million decrease in revenue-related taxes primarily in our Mid-Tex ~~Division, offset by a corresponding $7.7 million increase in the related tax expense.~~

~~a $6.0 million increase in transportation margin primarily in our Kentucky/Mid-States~~ Division.

~~a $26.2 million decrease in contribution margin as a result of lower taxes included in our cost of service rates due to implementation of the TCJA, as discussed above.~~

The year-over-year increase in operating expenses primarily reflects ~~expenses incurred with the planned outage we initiated~~an increase in ~~March 2018, as discussed above, combined with incremental system integrity activities,~~depreciation expense and property taxes ~~and depreciation expense~~of $15.3 million associated with increased capital ~~investments.~~investments, combined with higher system integrity and maintenance spending. The remaining increase in operating expenses is attributed to an increase in employee costs. These increases are partially offset by a $23 million decrease in nonrecurring expenses related to the planned outage of our natural gas distribution system in Northwest Dallas in March 2018.

The decrease in income tax expense reflects a reduction in our effective tax rate from ~~37.1%~~27.1% to ~~27.1%~~21.1%, as a result of the ~~TCJA.~~TCJA, as described above.

The following table shows our operating income by distribution division, in order of total rate base, for the six months ended March 31, ~~2018~~2019 and ~~2017.~~2018. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.


	Six Months Ended March 31							Six Months Ended March 31
	2018		2017		Change			2019		2018		Change
	(In thousands)							(In thousands)
Mid-Tex	$	151,115	$	163,552	$	(12,437	)	$	165,537	$	151,115	$	14,422
Kentucky/Mid-States	64,658		56,748		7,910			59,474		64,658		(5,184		)
Louisiana	54,028		50,225		3,803			55,054		54,028		1,026
West Texas	37,191		35,951		1,240			36,744		37,191		(447		)
Mississippi	43,371		37,760		5,611			46,698		43,371		3,327
Colorado-Kansas	30,405		30,036		369			33,493		30,405		3,088
Other	1,894		7,425		(5,531		)	1,400		4,330		(2,930		)
Total	$	382,662	$	381,697	$	965		$	398,400	$	385,098	$	13,302

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 six months of fiscal ~~2018,~~2019, we ~~completed nine~~implemented eleven regulatory proceedings, resulting in ana $~~18.4~~20.9 million increase in annual operating income as summarized below. The ratemaking outcomes for rate case activity in fiscal 2019 include the effect of tax reform legislation enacted effective January 1, 2018 and do not reflect the true economic benefit of the outcomes because they do not include the corresponding income tax benefit we will receive due to the decrease in our statutory tax rate.


Rate Action	Annual Increase in Operating Income		Annual Increase (Decrease) in Operating Income
	(In thousands)		(In thousands)
Annual formula rate mechanisms	$	17,897	$	24,612
Rate case filings	84		(3,898		)
Other rate activity	457		214
	$	18,438	$	20,928

The following ratemaking efforts seeking ~~$23.1~~$110.1 million in increased annual operating income were in progress as of March 31, ~~2018:~~

2019:

Division

Rate Action

Jurisdiction

Operating Income Requested

Rate Action

Jurisdiction

Operating Income Requested

(In thousands)

Colorado-Kansas

Rate Case

Colorado⁽¹⁾

2,916

Infrastructure Mechanism

Kansas ⁽¹⁾

1,562

Kentucky/Mid-States

Rate Case

Kentucky⁽¹⁾

4,778

Kentucky/Mid-States

Formula Rate Mechanism

Tennessee⁽¹⁾

850

Louisiana

Formula Rate Mechanism

Trans La ⁽¹⁾⁽³⁾

1,195

Formula Rate Mechanism

Trans La ⁽²⁾

4,719

Louisiana

Formula Rate Mechanism

LGS ⁽²⁾

(1,521

)

Formula Rate Mechanism

LGS

7,124

Mid-Tex

Infrastructure Mechanism

Environs ⁽²⁾

1,604

Rate Case

ATM Cities ⁽³⁾

4,252

Mid-Tex

Formula Rate Mechanism

City of Dallas

9,452

Mid-Tex

Infrastructure Mechanism

Environs

2,435

Mid-Tex

Formula Rate Mechanism

Mid-Tex Cities

47,733

Mississippi

Infrastructure Mechanism

Mississippi ⁽²⁾

8,000

Infrastructure Mechanism

Mississippi

8,433

Kentucky/Mid-States

Formula Rate Mechanism

Tennessee ⁽⁴⁾

3,230

Kentucky/Mid-States

Rate Case

Kentucky ⁽⁵⁾

14,424

West Texas

Infrastructure Mechanism

Cities of Amarillo, Channing, Dalhart, and Lubbock ⁽²⁾

4,418

Infrastructure Mechanism

Cities of Amarillo, Lubbock, Dalhart and Channing ⁽⁶⁾

5,692

West Texas

Infrastructure Mechanism

Environs ⁽²⁾

826

Infrastructure Mechanism

Environs

1,006

23,066

110,062


(1)	~~These filings were filed prior~~On April 23, 2019, the Kansas Corporation Commission approved this filing with rates to the enactment of the TCJA. The impact of the TCJA along with other items considered in establishing rates will result in a difference between the requested amounts and the final amount approved by the commission.be implemented beginning May 1, 2019.


(2)	The ~~filing amount reflects~~proposed increase for Trans La customers was implemented on April 1, 2019, subject to refund.


(3)	On February 25, 2019, the Railroad Commission of Texas approved a ~~21% federal income tax rate resulting from~~partial settlement in Gas Utilities Docket No. 10779. Under the ~~TCJA.~~terms of the settlement, temporary rates were implemented on March 1, 2019. Permanent rates are expected to be implemented following a final commission decision in late May 2019.


~~(3)~~(4)	On April 15, 2019, the Tennessee Public Utility Commission approved a settlement in Docket No. 18-00097 that lowered the operating income increase to $2.4 million. The ~~Louisiana~~Company anticipates an approval in Docket No. 19-00018 at the commission's May 2019 meeting, with rates to be effective June 1, 2019.

(5)

On May 7, 2019, the Kentucky Public Service Commission ~~Staff issued~~(KPSC) approved a ~~report, reflecting the impact~~final order that resulted in an increase in operating income of ~~TCJA, which recommends a base rate decrease of $1.9~~$3.5 million with rates to be effective May ~~1, 2018.~~8, 2019. Additionally, the KPSC reinstated the Pipeline Replacement Program (PRP) on a forward-looking basis, to be filed in August 2019 with rates to be effective in October 2019.


(6)	The 2018 GRIP increase was implemented on May 1, 2019.

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 the 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 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, which reflect a 21% federal income tax rate resulting from the TCJA, were approved during the six months ended March 31, ~~2018:~~2019:



Division	Jurisdiction	Test Year Ended	Increase (Decrease) in Annual Operating Income			Effective Date
		(In thousands)
2019 Filings:
Colorado-Kansas	Colorado GIS	12/31/2019	$	87		04/01/2019
Colorado-Kansas	Colorado SSIR	12/31/2019	2,147			01/01/2019
Mississippi	Mississippi - SIR	10/31/2019	7,135			11/01/2018
Mississippi	Mississippi - SRF	10/31/2019	(118		)	11/01/2018
Kentucky/Mid-States	Tennessee ARM	05/31/2019	(5,032		)	10/15/2018
Mid-Tex	Mid-Tex RRM Cities	12/31/2017	17,633			10/01/2018
West Texas	West Texas Cities RRM	12/31/2017	2,760			10/01/2018
Total 2019 Filings			$	24,612

Division Jurisdiction
Test Year
Ended

Increase in
Annual
Operating
Income

Effective
Date
(In thousands)
2018 Filings:
Colorado-Kansas Kansas GSRS 09/30/2018 $ 820
02/27/2018
Colorado-Kansas Colorado SSIR 12/31/2018 2,228
12/20/2017
Mississippi Mississippi - SIR 10/31/2018 7,658
12/05/2017
Mississippi
Mississippi - SGR ⁽¹⁾
10/31/2018 1,245
12/05/2017
Mississippi
Mississippi - SRF ⁽¹⁾
10/31/2018 —
12/05/2017
Kentucky/Mid-States Kentucky - PRP 09/30/2018 5,638
10/27/2017
Kentucky/Mid-States
Virginia - SAVE ⁽²⁾
09/30/2017 308
10/01/2017
Total 2018 Filings $ 17,897


~~(1)~~	~~In our next SRF filing, the SGR rate base will be combined with the SRF rate base, per Commission order.~~


~~(2)~~	~~The Company completed our Steps to Advance Virginia Energy (SAVE) program. On October 1, 2017 a refund factor was removed from the rate resulting in an operating income increase of $0.3 million.~~

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 rate cases, which reflect a 21% federal income tax rate resulting from the TCJA, that were completed during the six months ended March 31, ~~2018.~~2019.

Division State
Increase in Annual
Operating Income

Effective
Date
(In thousands)
2018 Rate Case Filings:
Mid-Tex
City of Dallas ⁽¹⁾
$ 84
02/14/2018
Total 2018 Rate Case Filings $ 84

~~(1) The operating income reflects a 21% federal income tax rate resulting from the TCJA.~~



Division	State	Decrease in Annual Operating Income			Effective Date
		(In thousands)
2019 Rate Case Filings:
Kentucky/Mid-States	Virginia	$	(400	)	04/01/2019
Mid-Tex	Texas	(2,674		)	01/01/2019
West Texas	Texas	(824		)	01/01/2019
Total 2019 Rate Case Filings		$	(3,898	)

Other Ratemaking Activity

The following table summarizes other ratemaking activity during the six months ended March 31, ~~2018.~~

2019.

Division

Jurisdiction

Rate Activity

Additional

Annual

Operating

Income

Effective

Date

Jurisdiction

Rate Activity

Increase in

Annual

Operating

Income

Effective

Date

(In thousands)

2018 Other Rate Activity:

2019 Other Rate Activity:

Colorado-Kansas

Kansas

Ad Valorem⁽¹⁾

457

02/01/2018

Kansas

Ad Valorem ⁽¹⁾

214

02/01/2019

Total 2018 Other Rate Activity

457

Total 2019 Other Rate Activity

214


(1)	The Ad Valorem filing relates to ~~a collection of~~ property taxes ~~in excess of~~that are either over or undercollected compared to 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. 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~~eastern 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~~owns and operates 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~~supply areas that we serve, which may influence the level of throughput we may be able to transport on our ~~pipeline.~~pipelines. 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. Following the conclusion of its rate case in August 2017, APT made a GRIP filing that covered changes in net investment from October 1, 2016 through December 31, 2016 with a requested increase in operating income of $29.0 million. On December 5, 2017, the filing was approved. On February 15, ~~2018,~~2019, APT made a GRIP filing that covered changes in net investment from January 1, ~~2017~~2018 through December 31, ~~2017~~2018 with a requested increase in operating income of ~~$42.2~~$49.2 million.

On ~~December 21, 2016,~~May 7, 2019, the ~~Louisiana Public Service~~Texas Railroad 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.~~

Company's GRIP filing.

Three Months Ended March 31, ~~2018~~2019 compared with Three Months Ended March 31, ~~2017~~2018

Financial and operational highlights for our pipeline and storage segment for the three months ended March 31, ~~2018~~2019 and ~~2017~~2018 are presented below.


	Three Months Ended March 31									Three Months Ended March 31
	2018			2017			Change			2019			2018			Change
	(In thousands, unless otherwise noted)									(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue	$	89,631		$	84,292		$	5,339		$	94,291		$	89,631		$	4,660
Third-party transportation revenue	28,414			22,824			5,590			37,534			28,414			9,120
Other revenue	2,910			4,856			(1,946		)	3,825			2,910			915
Total operating revenues	120,955			111,972			8,983			135,650			120,955			14,695
Total purchased gas cost	433			725			(292		)	(90		)	433			(523		)
Contribution margin	120,522			111,247			9,275
Contribution Margin										135,740			120,522			15,218
Operating expenses	61,440			52,879			8,561			67,026			61,440			5,586
Operating income	59,082			58,368			714			68,714			59,082			9,632
Miscellaneous expense	(646		)	(196		)	(450		)
Other non-operating expense										(1,031		)	(646		)	(385		)
Interest charges	10,406			10,019			387			11,053			10,406			647
Income before income taxes	48,030			48,153			(123		)	56,630			48,030			8,600
Income tax expense	14,281			17,286			(3,005		)	13,935			14,281			(346		)
Net income	$	33,749		$	30,867		$	2,882		$	42,695		$	33,749		$	8,946
Gross pipeline transportation volumes — MMcf	237,167			195,233			41,934			254,833			237,167			17,666
Consolidated pipeline transportation volumes — MMcf	148,980			131,151			17,829			165,369			148,980			16,389

Income before income taxes for our pipeline and storage segment ~~was flat year over year,~~increased eighteen percent, primarily due to a ~~$9.3~~$15.2 million increase in ~~contribution margin,~~Contribution Margin, partially offset by ~~an $8.6~~a $5.6 million increase in operating expenses. The quarter-over-quarter increase in ~~contribution margin~~Contribution Margin primarily reflects:

a ~~$16.5~~$12.2 million net increase in ~~rates~~rate adjustments, after the effect of the TCJA, from the approved ~~APT rate case and the~~ GRIP filing approved in ~~December 2017.~~May 2018. The increase in rates was driven primarily by increased safety and reliability spending.

a net increase of ~~$1.7~~$1.2 million primarily due to wider spreads and positive supply and demand dynamics affecting the Permian Basin.

an $8.0 million decrease due to the inclusion of the lower statutory rate in our revenues due to implementation of the TCJA. Of this amount, $0.2 million has been reflected in customer bills. The remaining $7.8 million relates to the establishment of regulatory liabilities for the difference between the former 35% federal statutory rate and the current 21% federal statutory rate as further described in Note 6.

Operating expenses increased ~~$8.6~~$5.6 million, primarily due to higher depreciation expense associated with increased capital investments and higher system maintenance expense.

~~The decrease in income tax expense reflects a reduction in our effective tax rate from 35.9% to 29.7%, as a result of the TCJA.~~

Six Months Ended March 31, 2019 compared with Six Months Ended March 31, 2018 ~~and Six Months Ended March 31, 2017~~

Financial and operational highlights for our pipeline and storage segment for the six months ended March 31, ~~2018~~2019 and ~~2017~~2018 are presented below.


	Six Months Ended March 31									Six Months Ended March 31
	2018			2017			Change			2019			2018			Change
	(In thousands, unless otherwise noted)									(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue	$	183,529		$	166,760		$	16,769		$	182,723		$	183,529		$	(806	)
Third-party transportation revenue	57,345			45,044			12,301			80,822			57,345			23,477
Other revenue	6,544			10,120			(3,576		)	6,575			6,544			31
Total operating revenues	247,418			221,924			25,494			270,120			247,418			22,702
Total purchased gas cost	1,345			1,080			265			(448		)	1,345			(1,793		)
Contribution margin	246,073			220,844			25,229
Contribution Margin										270,568			246,073			24,495
Operating expenses	118,186			107,451			10,735			134,827			118,186			16,641
Operating income	127,887			113,393			14,494			135,741			127,887			7,854
Miscellaneous expense	(1,281		)	(557		)	(724		)
Other non-operating expense										(2,277		)	(1,281		)	(996		)
Interest charges	20,547			19,931			616			20,692			20,547			145
Income before income taxes	106,059			92,905			13,154			112,772			106,059			6,713
One-time, non-cash income tax benefit	(21,733		)	—			(21,733		)
TCJA non-cash income tax benefit										—			(21,733		)	21,733
Income tax expense	29,010			33,364			(4,354		)	26,816			29,010			(2,194		)
Net income	$	98,782		$	59,541		$	39,241		$	85,956		$	98,782		$	(12,826	)
Gross pipeline transportation volumes — MMcf	450,304			382,013			68,291			493,688			450,304			43,384
Consolidated pipeline transportation volumes — MMcf	304,085			266,127			37,958			335,896			304,085			31,811

Income before income taxes for our pipeline and storage segment increased 14six percent, primarily due to a ~~$25.2~~$24.5 million increase in ~~contribution margin,~~Contribution Margin, partially offset by a ~~$10.7~~$16.6 million increase in operating expenses. The year-over-year increase in ~~contribution margin~~Contribution Margin primarily reflects:

~~a $30.4~~an $18.1 million net increase in rate adjustments, after the effect of the TCJA, from the approved GRIP filings approved in December 2017 and May 2018. The increase in rates ~~from the approved APT rate case~~was driven primarily by increased safety and ~~the GRIP filing approved in December 2017.~~reliability spending.

a net increase of ~~$3.1~~$4.3 million primarily due to wider spreads and positive supply and demand dynamics affecting the Permian Basin.

~~an $8.0 million decrease in rates due to the implementation of the TCJA, as discussed above.~~

Operating expenses increased ~~$10.7~~$16.6 million, primarily due to higher depreciation expense ~~partially offset by the timing of~~associated with increased capital investments and higher system maintenance expense.

~~The decrease in income tax expense primarily reflects a reduction in our effective tax rate from 35.9% to 27.4%, as a result of the TCJA.~~

~~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.

As more fully described in Note 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 fully exited the nonregulated natural gas marketing business. Accordingly, a gain on sale from discontinued operations for $2.7 million was recorded for the three and six months ended March 31, 2017 and net income of $11.0 million for AEM is reported as discontinued operations for the six months ended March 31, 2017.

Liquidity and Capital Resources

The liquidity required to fund our working capital, capital expenditures and other cash needs is provided from a combination of internally generated cash flows and 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 three committed revolving credit 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-total-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. The liquidity provided by these sources is expected to be sufficient to fund the Company's working capital needs and capital expenditure program for the remainder of fiscal year ~~2018~~2019 and beyond. ~~Please refer to the TCJA Impact section above regarding anticipated impacts on our liquidity, capital resources and cash flows.~~

To continue to support our capital market activities, we ~~have~~filed a registration statement ~~on file~~ with the SEC on November 13, 2018 that permits us to issue a total of ~~$2.5~~$3.0 billion in common stock and/or debt securities. ~~Under~~This registration statement replaced our previous registration statement that was effectively exhausted in October 2018. At March 31, 2019, approximately $1.3 billion of securities remained available for issuance under the shelf registration ~~statement,~~statement.

On November 19, 2018, we ~~recently~~ filed a prospectus supplement ~~for~~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 $500 ~~million.~~million (including shares of common stock that may be sold pursuant to a forward sale agreement entered into

concurrently with the ATM equity sales program). At March 31, ~~2018,~~2019, approximately ~~$1.2~~$340 million remained available under the ATM equity sales program.

During the six months ended March 31, 2019, we completed approximately $2 billion of ~~securities remained~~long-term debt and equity financing.

In October 2018, we completed the public offering of $600 million of 30-year 4.30% senior notes. The net proceeds of $590.6 million were used to repay working capital borrowings pursuant to our commercial paper program.

In November 2018, we sold 5,390,836 shares of common stock for $500 million. The net proceeds of $494.1 million were used to fund our capital expenditure program and for general corporate purposes.

In March 2019, we completed the public offering of $450 million of 30-year 4.125% senior notes. The net proceeds of $443.4 million, together with available cash, were used to repay at maturity our $450 million 8.50% 10-year unsecured senior notes due March 15, 2019 and the related settlement of our interest rate swaps for ~~issuance under the shelf registration statement.~~$90.1 million.

In November 2018 and February 2019, we executed forward sales agreements with various underwriters who borrowed and sold 4.3 million shares of our common stock for initial aggregate proceeds of approximately $408 million. The following table summarizes these agreements as of March 31, 2019:



As of March 31, 2019
Issue Quarter	Issued Under	Shares Available	Net Proceeds Available		Maturity	Forward Price
December 31, 2018	Shelf	2,668,464	$	244,844,220	3/31/2020	$	91.75
March 31, 2019	ATM	1,670,509	159,022,309		3/31/2020	$	95.19
Total		4,338,973	$	403,866,529

The following table presents our capitalization inclusive of short-term debt and the current portion of long-term debt as of March 31, ~~2018,~~2019, September 30, ~~2017~~2018 and March 31, ~~2017:~~2018:


	March 31, 2018				September 30, 2017				March 31, 2017				March 31, 2019				September 30, 2018				March 31, 2018
	(In thousands, except percentages)												(In thousands, except percentages)
Short-term debt	$	129,602	1.6	%	$	447,745	6.0	%	$	670,607	9.5	%	$	—	—	%	$	575,780	6.8	%	$	129,602	1.6	%
Long-term debt⁽¹⁾	3,067,892		38.8	%	3,067,045		41.4	%	2,564,620		36.3	%	3,653,713		39.9	%	3,068,665		36.5	%	3,067,892		38.8	%
Shareholders’ equity	4,721,346		59.6	%	3,898,666		52.6	%	3,834,864		54.2	%	5,508,101		60.1	%	4,769,951		56.7	%	4,721,346		59.6	%
Total	$	7,918,840	100.0	%	$	7,413,456	100.0	%	$	7,070,091	100.0	%	$	9,161,814	100.0	%	$	8,414,396	100.0	%	$	7,918,840	100.0	%


(1)	In ~~March~~September 2019, ~~$450~~our $125 million ~~of long-term debt will mature. We~~term loan, which we plan to issue new senior notes to replace the maturing debt. We have executed forward starting interest rate swaps to effectively fix the Treasury yield component associated with this anticipated issuance at 3.78%.refinance, will mature.

Cash Flows

Our internally generated funds may change in the future due to a number of factors, some of which we cannot control. These factors include regulatory changes, ~~prices~~the price 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 six months ended March 31, ~~2018~~2019 and ~~2017~~2018 are presented below.


	Six Months Ended March 31									Six Months Ended March 31
	2018			2017			Change			2019			2018			Change
	(In thousands)									(In thousands)
Total cash provided by (used in)
Operating activities	$	751,367		$	552,003		$	199,364		$	560,829		$	751,367		$	(190,538	)
Investing activities	(688,144		)	(516,670		)	(171,474		)	(768,421		)	(688,144		)	(80,277		)
Financing activities	(18,558		)	(37,464		)	18,906			302,174			(18,558		)	320,732
Change in cash and cash equivalents	44,665			(2,131		)	46,796			94,582			44,665			49,917
Cash and cash equivalents at beginning of period	26,409			47,534			(21,125		)	13,771			26,409			(12,638		)
Cash and cash equivalents at end of period	$	71,074		$	45,403		$	25,671		$	108,353		$	71,074		$	37,279

Cash flows from operating activities

~~Period-over-period changes~~For the six months ended March 31, 2019, we generated cash flow from operating activities of $560.8 million compared with $751.4 million for the six months ended March 31, 2018. The $190.5 million decrease in ~~our~~ operating cash flows ~~are~~is primarily attributable to ~~changes~~the change in net income and working capital changes, particularly ~~within~~in 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 six months ended March 31, 2018, we generated cash flow of $751.4 million from operating activities compared with $552.0 million for the six months ended March 31, 2017. The $199.4 million increase in operating cash flows reflects the positive cash effects of successful rate case outcomes achieved in fiscal 2017 and changes in working capital, primarily as a result of the timing of gas cost recoveries under our purchase gas cost mechanisms as a result of a period-over-period increase in sales volumes. This increase in sale volumes also contributed to the period-over-period increase in operating cash flow.

Cash flows from investing activities

~~In recent years, we have incurred~~Our capital expenditures are primarily used to ~~support~~improve the safety and reliability of our distribution and transmission system through pipeline replacement and system modernization and ~~integrity enhancement efforts, expand our natural gas distribution services~~to enhance and expand our ~~intrastate pipeline network.~~system to meet customer needs. Over the last three fiscal years, approximately 8082 percent of our capital spending has been committed to improving the safety and reliability of our system.

We allocate our capital spending among our service areas using risk management models and subject matter experts to identify, assess and develop a plan of action to address our highest risk facilities. We have regulatory mechanisms in most of our service areas that provide the opportunity to include approved capital costs in rate base on a periodic basis without being required to file a rate case. These mechanisms permit us a reasonable opportunity to earn a fair return on our investment without compromising safety or reliability.

For the six months ended March 31, ~~2018,~~2019, cash used for investing activities was ~~$688.1~~$768.4 million compared to ~~$516.7~~$688.1 million infor the ~~prior-year period.~~six months ended March 31, 2018. Capital spending increased by ~~$134.6~~$83.6 million, or 2412 percent, as a result of planned increases in our distribution segment to repair and replace vintage pipe and increases in spending in our pipeline and storage segment to improve the reliability of gas service to our local distribution company customers. The period-over-period increase also reflects the absence in the current year period of $133.6 million in net proceeds received from the sale of AEM and the $85.7 million used to acquire the North Texas Pipeline in December 2016.

Cash flows from financing activities

For the six months ended March 31, ~~2018,~~2019, our financing activities ~~used $18.6~~provided $302.2 million of cash compared with ~~$37.5~~$18.6 million of cash used for financing activities in the prior-year period. ~~The $18.9 million decrease in cash used in financing activities primarily reflects an increase in operating cash flow that exceeded an increase in cash used for investing activities during~~

In the six months ended March 31, ~~2018.~~2019, we received $1.5 billion in net proceeds from the issuance of long-term debt and equity. A portion of the net proceeds was used to repay at maturity our $450 million 8.50% unsecured senior notes and the related settlement of our interest rate swaps for $90.1 million, to reduce short-term debt, to support our capital spending and for other general corporate purposes. Cash dividends increased due to an 8.2 percent increase in our dividend rate and an increase in shares outstanding.

In the six months ended March 31, 2018, 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 dividend rate and an increase in shares outstanding.~~

In the six months ended March 31, 2017, we issued $125 million of long-term debt under our 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 reduce short-term debt and support our capital expenditures program. Additionally, the return of cash collateral related to our forward-starting interest rate swaps due to an increase in interest rates provided cash from financing activities of $25.7 million.

The following table summarizes our share issuances for the six months ended March 31, ~~2018~~2019 and ~~2017:~~2018:


	Six Months Ended March 31		Six Months Ended March 31
	2018	2017	2019	2018
Shares issued:
Direct Stock Purchase Plan	90,042	54,366	61,237	90,042
1998 Long-Term Incentive Plan	257,400	426,835	213,402	257,400
Retirement Savings Plan and Trust	49,848	172,932	43,745	49,848
At-the-Market (ATM) Equity Distribution Program	—	690,812
Equity Issuance	4,558,404	—	5,390,836	4,558,404
Total shares issued	4,955,694	1,344,945	5,709,220	4,955,694

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 but not limited to, debt to total capitalization, operating cash flow relative to outstanding debt, operating cash flow coverage of interest and pension ~~liabilities and funding status.~~liabilities. 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). On December 14, 2018, Moody's affirmed our debt ratings and improved their outlook from stable to positive, citing improvements to our regulatory construct that reduces investment recovery lag and our balanced fiscal policy. As of March 31, ~~2018, both rating agencies~~2019, S&P 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~~two 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 March 31, ~~2018.~~2019. Our debt covenants are described in greater detail in Note 56 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 six months ended March 31, ~~2018.~~2019.

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,~~In the past we ~~manage~~managed 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 contribution 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 six months ended March 31, ~~2018~~2019 and ~~2017:~~2018:


	Three Months Ended March 31						Six Months Ended March 31						Three Months Ended March 31						Six Months Ended March 31
	2018			2017			2018			2017			2019			2018			2019			2018
	(In thousands)												(In thousands)
Fair value of contracts at beginning of period	$	(116,529	)	$	(121,722	)	$	(109,159	)	$	(279,543	)	$	(83,669	)	$	(116,529	)	$	(55,218	)	$	(109,159	)
Contracts realized/settled	(2,360		)	1,793			(1,200		)	11,756			89,916			(2,360		)	96,374			(1,200		)
Fair value of new contracts	(147		)	(2,560		)	(716		)	(1,597		)	405			(147		)	889			(716		)
Other changes in value	32,694			8,485			24,733			155,380			(5,079		)	32,694			(40,472		)	24,733
Fair value of contracts at end of period	(86,342		)	(114,004		)	(86,342		)	(114,004		)	1,573			(86,342		)	1,573			(86,342		)
Netting of cash collateral	—			—			—			—			—			—			—			—
Cash collateral and fair value of contracts at period end	$	(86,342	)	$	(114,004	)	$	(86,342	)	$	(114,004	)	$	1,573		$	(86,342	)	$	1,573		$	(86,342	)

The fair value of our financial instruments at March 31, ~~2018~~2019 is presented below by time period and fair value source:


	Fair Value of Contracts at March 31, 2018												Fair Value of Contracts at March 31, 2019
	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	$	(86,342	)	$	—	$	—	$	—	$	(86,342	)	$	1,573	$	—	$	—	$	—	$	1,573
Prices based on models and other valuation methods	—			—		—		—		—			—		—		—		—		—
Total Fair Value	$	(86,342	)	$	—	$	—	$	—	$	(86,342	)	$	1,573	$	—	$	—	$	—	$	1,573

Pension and Postretirement Benefits Obligations

For the six months ended March 31, ~~2018~~2019 and ~~2017,~~2018, our total net periodic pension and other postretirement benefits costs were ~~$20.9~~$12.6 million and ~~$23.2~~$20.9 million. ~~A substantial portion of those~~These costs isare recoverable through our ~~rates; however, a~~rates. A portion of these costs is capitalized into our rate ~~base.~~base or deferred as a regulatory asset or liability. The remaining costs are recorded as a component of operation and maintenance ~~expense.~~expense or other non-operating expense as discussed in Note 8.

Our fiscal ~~2018~~2019 costs were determined using a September 30, ~~2017~~2018 measurement date. As of September 30, ~~2017,~~2018, interest and corporate bond rates were higher than the rates as of September 30, ~~2016.~~2017. Therefore, we increased the discount rate used to measure our fiscal ~~2018~~2019 net periodic cost from ~~3.73~~3.89 percent to ~~3.89~~4.38 percent. ~~We lowered the~~The expected return on plan assets toremained consistent with prior year at 6.75 percent in the determination of our fiscal ~~2018~~2019 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 ~~2018~~2019 net periodic pension cost to be ~~approximately 25 percent~~ lower than fiscal ~~2017.~~2018.

The amount 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,~~2019, we were not required to make a minimum contribution to our defined benefit plan during fiscal ~~2018.~~2019. However, we ~~will~~may consider whether a voluntary contribution is prudent to maintain certain funding levels.

For the six months ended March 31, ~~2018~~2019 we contributed ~~$7.5~~$7.7 million to our postretirement medical plans. We anticipate contributing a total of between $10 million and $20 million to our postretirement plans during fiscal ~~2018.~~2019.

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 ~~six-month~~six month periods ended March 31, ~~2018~~2019 and ~~2017.~~2018.

Distribution Sales and Statistical Data


	Three Months Ended March 31					Six Months Ended March 31					Three Months Ended March 31					Six Months Ended March 31
	2018			2017		2018			2017		2019		2018			2019		2018
METERS IN SERVICE, end of period
Residential	2,964,137			2,929,455		2,964,137			2,929,455		2,995,438		2,964,137			2,995,438		2,964,137
Commercial	270,795			269,055		270,795			269,055		273,533		270,795			273,533		270,795
Industrial	1,673			1,690		1,673			1,690		1,669		1,673			1,669		1,673
Public authority and other	8,407			8,332		8,407			8,332		8,365		8,407			8,365		8,407
Total meters	3,245,012			3,208,532		3,245,012			3,208,532		3,279,005		3,245,012			3,279,005		3,245,012

INVENTORY STORAGE BALANCE — Bcf	29.7			40.0		29.7			40.0		30.3		29.7			30.3		29.7
SALES VOLUMES — MMcf⁽¹⁾
Gas sales volumes
Residential	80,525			56,931		129,473			98,431		84,757		80,525			144,621		129,473
Commercial	40,956			31,739		67,905			55,475		42,974		40,956			74,557		67,905
Industrial	9,708			6,708		18,166			14,140		8,727		9,708			16,901		18,166
Public authority and other	2,857			2,376		4,809			4,138		2,784		2,857			4,861		4,809
Total gas sales volumes	134,046			97,754		220,353			172,184		139,242		134,046			240,940		220,353
Transportation volumes	47,843			42,142		87,702			81,207		48,235		47,843			91,086		87,702
Total throughput	181,889			139,896		308,055			253,391		187,477		181,889			332,026		308,055
OPERATING REVENUES (000’s)⁽¹⁾⁽²⁾
Gas sales revenues
Residential	$	805,134		$	609,771	$	1,361,654		$	1,091,444	$	681,367	$	805,134		$	1,221,806	$	1,361,654
Commercial	318,312			251,174		541,892			451,662		275,031		318,312			492,091		541,892
Industrial	39,604			47,986		73,017			78,017		35,979		39,604			70,451		73,017
Public authority and other	19,008			17,607		32,569			29,716		17,023		19,008			30,130		32,569
Total gas sales revenues	1,182,058			926,538		2,009,132			1,650,839		1,009,400		1,182,058			1,814,478		2,009,132
Transportation revenues	29,939			24,307		55,301			46,788		27,532		29,939			52,882		55,301
Other gas revenues(3)	(12,706		)	11,696		(4,350		)	19,570		20,957		(12,706		)	29,364		(4,350		)
Total operating revenues	$	1,199,291		$	962,541	$	2,060,083		$	1,717,197	$	1,057,889	$	1,199,291		$	1,896,724	$	2,060,083
Average cost of gas per Mcf sold	$	5.42		$	5.25	$	5.40		$	5.28	$	4.10	$	5.42		$	4.18	$	5.40

See footnote following these tables.

Pipeline and Storage Operations Sales and Statistical Data


	Three Months Ended March 31				Six Months Ended March 31				Three Months Ended March 31				Six Months Ended March 31
	2018		2017		2018		2017		2019		2018		2019		2018
CUSTOMERS, end of period
Industrial	92		91		92		91		93		92		93		92
Other	231		226		231		226		230		231		230		231
Total	323		317		323		317		323		323		323		323

INVENTORY STORAGE BALANCE — Bcf	0.4		0.6		0.4		0.6		0.2		0.4		0.2		0.4
PIPELINE TRANSPORTATION VOLUMES — MMcf⁽¹⁾	237,167		195,233		450,304		382,013		254,833		237,167		493,688		450,304
OPERATING REVENUES (000’s)⁽¹⁾⁽²⁾	$	120,955	$	111,972	$	247,418	$	221,924	$	135,650	$	120,955	$	270,120	$	247,418

Note to preceding tables:


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


⁽²⁾	Operating revenues include revenues from our alternative revenue programs as defined in Note 5.


⁽³⁾	Other gas revenues include impacts of the TCJA.

RECENT ACCOUNTING DEVELOPMENTS

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



Item 3.	Quantitative and Qualitative Disclosures About Market Risk

Information regarding our quantitative and qualitative disclosures about market risk are disclosed in Item 7A in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017.~~2018. During the six months ended March 31, ~~2018,~~2019, 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 March 31, ~~2018~~2019 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 second quarter of the fiscal year ended September 30, ~~2018~~2019 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 six months ended March 31, ~~2018,~~2019, except as noted in Note 9 to the unaudited condensed consolidated financial statements, there were no material changes in the status of the litigation and other matters that were disclosed in Note 11 to our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017.~~2018. 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

The following exhibits are filed as part of this Quarterly Report.



Exhibit Number	Description	Page Number or Incorporation by Reference to
~~2.1~~3.1	~~Membership Interest Purchase Agreement by~~Amended and ~~between~~Restated Bylaws of Atmos Energy ~~Holdings, Inc. as Seller and CenterPoint Energy Services, Inc. as Buyer, dated as~~Corporation (as of ~~October 29, 2016~~ February 5, 2019)	Exhibit ~~2.1~~3.1 to Form 8-K dated ~~October 29, 2016~~February 5, 2019 (File No. 1-10042)
4.1	Global Security for the 4.125% Senior Notes due 2049	Exhibit 4.2 to Form 8-K dated March 4, 2019 (File No 1-10042)
10	Equity Distribution Agreement, dated as of November ~~14, 2017,~~16, 2018, among Atmos Energy Corporation ~~Goldman Sachs & Co. LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley & Co. LLC,~~ and ~~J.P. Morgan Securities LLC~~ the Managers and Forward Purchasers named in Schedule A thereto	Exhibit 1.1 to Form 8-K dated November ~~14, 2017~~16, 2018 (File No. 1-10042)
1210.1	Form of Master Forward Sale Confirmation	~~Computation of ratio of earnings~~Exhibit 1.2 to ~~fixed charges~~Form 8-K dated November 16, 2018 (File No. 1-10042)
10.2	Forward Sale Agreement between Atmos Energy Corporation and Goldman Sachs & Co. LLC dated as of November 28, 2018	Exhibit 10.1 to Form 8-K dated November 28, 2018 (File No. 1-10042)
10.3	Forward Sale Agreement between Atmos Energy Corporation and Bank of America, N.A. dated as of November 28, 2018	Exhibit 10.2 to Form 8-K dated November 28, 2018 (File No. 1-10042)
10.4	Additional Forward Sale Agreement between Atmos Energy Corporation and Goldman Sachs & Co. LLC dated as of November 29, 2018	Exhibit 10.3 to Form 8-K dated November 28, 2018 (File No. 1-10042)
10.5	Additional Forward Sale Agreement between Atmos Energy Corporation and Bank of America, N.A. dated as of November 29, 2018	Exhibit 10.4 to Form 8-K dated November 28, 2018 (File No. 1-10042)
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.

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: May ~~2, 2018~~7, 2019

4844



	Six Months Ended March 31, 2017
	Distribution		Pipeline and Storage			Natural Gas Marketing		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	1,716,483	$	51,871		$	—	$	—		$	1,768,354
Intersegment revenues	714		170,053			—		(170,767		)	—
Total operating revenues	1,717,197		221,924			—		(170,767		)	1,768,354
Purchased gas cost	908,442		1,080			—		(170,723		)	738,799
Operation and maintenance expense	196,417		60,804			—		(44		)	257,177
Depreciation and amortization expense	122,459		32,166			—		—			154,625
Taxes, other than income	108,182		14,481			—		—			122,663
Operating income	381,697		113,393			—		—			495,090
Miscellaneous income (expense)	396		(557		)	—		—			(161		)
Interest charges	38,043		19,931			—		—			57,974
Income from continuing operations before income taxes	344,050		92,905			—		—			436,955
Income tax expense	127,541		33,364			—		—			160,905
Income from continuing operations	216,509		59,541			—		—			276,050
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	$	216,509	$	59,541		$	13,710	$	—		$	289,760
Capital expenditures	$	430,669	$	128,716		$	—	$	—		$	559,385



	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	634		95,271			9,847			105,752
Amounts reclassified from accumulated other comprehensive income	68		173			(4,865		)	(4,624		)
Net current-period other comprehensive income	702		95,444			4,982			101,128
March 31, 2017	$	5,186	$	(92,080	)	$	—		$	(86,894	)



	Three Months Ended March 31, 2018
Accumulated Other Comprehensive Income Components	Amount Reclassified from Accumulated Other Comprehensive Income			Affected Line Item in the Statement of Income
	(In thousands)
Available-for-sale securities	$	1,139		Operation and maintenance expense
	1,139			Total before tax
	(260		)	Tax expense
	$	879		Net of tax
Cash flow hedges
Interest rate agreements	$	(593	)	Interest charges
	(593		)	Total before tax
	135			Tax benefit
	$	(458	)	Net of tax
Total reclassifications	$	421		Net of tax



	Supplemental Executive Retirement Plan		Pension Benefits		Other Benefits
	2018	2017	2018	2017	2018	2017
Discount rate	4.12%	3.73%	3.89%	3.73%	3.89%	3.73%
Rate of compensation increase	3.50%	3.50%	3.50%	3.50%	N/A	N/A
Expected return on plan assets	N/A	N/A	6.75%	7.00%	4.29%	4.45%



	Amortized Cost		Gross Unrealized Gain		Gross Unrealized Loss				Fair Value
	(In thousands)
As of March 31, 2018
Domestic equity mutual funds	$	25,515	$	8,194	$	(95	)		$	33,614
Foreign equity mutual funds	4,138		2,031		—				6,169
Bond mutual funds	16,548		—		(240		)		16,308
Bonds	31,295		4		(162		)		31,137
Money market funds	6,437		—		—				6,437
	$	83,933	$	10,229	$	(497	)		$	93,665
As of September 30, 2017
Domestic equity mutual funds	$	25,361	$	8,920	$	—			$	34,281
Foreign equity mutual funds	4,581		2,235		—				6,816
Bond mutual funds	16,391		2		(22		)		16,371
Bonds	29,074		46		(16		)		29,104
Money market funds	1,837		—		—				1,837
	$	77,244	$	11,203	$	(38	)	��	$	88,409



	Six Months Ended March 31, 2017
	(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
Income from discontinued operations	10,994
Gain on sale from discontinued operations, net of tax ($10,215)	2,716
Net income from discontinued operations	$	13,710



	Six Months Ended March 31, 2017
	(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



Division	State	Increase in Annual Operating Income		Effective Date
		(In thousands)
2018 Rate Case Filings:
Mid-Tex	City of Dallas ⁽¹⁾	$	84	02/14/2018
Total 2018 Rate Case Filings		$	84