Atmos Energy - 10-Q quarterly report FY2019 Q1

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 December 31, 2018



¨	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 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 January 30, 2019.



Class		Shares Outstanding
No Par Value		116,897,373

GLOSSARY OF KEY TERMS




Adjusted diluted net income per share	Non-GAAP measure defined as diluted net income per share before the one-time, non-cash income tax benefit
Adjusted net income	Non-GAAP measure defined as net income before the one-time, non-cash income tax benefit
AEC	Atmos Energy Corporation
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
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



	December 31, 2018			September 30, 2018
	(Unaudited)
	(In thousands, except share data)
ASSETS
Property, plant and equipment	$	12,948,229		$	12,567,373
Less accumulated depreciation and amortization	2,250,000			2,196,226
Net property, plant and equipment	10,698,229			10,371,147
Current assets
Cash and cash equivalents	218,197			13,771
Accounts receivable, net	478,373			253,295
Gas stored underground	146,552			165,732
Other current assets	69,616			46,055
Total current assets	912,738			478,853
Goodwill	730,419			730,419
Deferred charges and other assets	274,403			294,018
	$	12,615,789		$	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: December 31, 2018 — 116,892,959 shares; September 30, 2018 — 111,273,683 shares	$	584		$	556
Additional paid-in capital	3,476,476			2,974,926
Accumulated other comprehensive loss	(114,115		)	(83,647		)
Retained earnings	1,985,250			1,878,116
Shareholders’ equity	5,348,195			4,769,951
Long-term debt	3,084,779			2,493,665
Total capitalization	8,432,974			7,263,616
Current liabilities
Accounts payable and accrued liabilities	301,734			217,283
Other current liabilities	578,764			547,068
Short-term debt	—			575,780
Current maturities of long-term debt	575,000			575,000
Total current liabilities	1,455,498			1,915,131
Deferred income taxes	1,191,824			1,154,067
Regulatory excess deferred taxes (See Note 13)	717,758			739,670
Regulatory cost of removal obligation	468,825			466,405
Pension and postretirement liabilities	176,582			177,520
Deferred credits and other liabilities	172,328			158,028
	$	12,615,789		$	11,874,437

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three Months Ended December 31
	2018			2017
	(Unaudited) (In thousands, except per share data)
Operating revenues
Distribution segment	$	838,835		$	860,792
Pipeline and storage segment	134,470			126,463
Intersegment eliminations	(95,523		)	(98,063		)
Total operating revenues	877,782			889,192

Purchased gas cost
Distribution segment	437,732			463,758
Pipeline and storage segment	(358		)	912
Intersegment eliminations	(95,209		)	(97,753		)
Total purchased gas cost	342,165			366,917
Operation and maintenance expense	138,600			129,045
Depreciation and amortization expense	96,065			88,374
Taxes, other than income	64,488			62,773
Operating income	236,464			242,083
Other non-operating expense	(7,723		)	(2,557		)
Interest charges	27,849			31,509
Income before income taxes	200,892			208,017
Income tax expense (benefit)	43,246			(106,115		)
Net income	$	157,646		$	314,132
Basic net income per share	$	1.38		$	2.89
Diluted net income per share	$	1.38		$	2.89
Cash dividends per share	$	0.525		$	0.485
Basic weighted average shares outstanding	113,800			108,564
Diluted weighted average shares outstanding	113,832			108,564

Net income	$	157,646		$	314,132
Other comprehensive income (loss), net of tax
Net unrealized holding losses on available-for-sale securities, net of tax of $0 and $62 (See Note 2)	—			(107		)
Cash flow hedges:
Amortization and unrealized loss on interest rate agreements, net of tax of $6,580 and $549	(22,258		)	(955		)
Total other comprehensive loss	(22,258		)	(1,062		)
Total comprehensive income	$	135,388		$	313,070

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Three Months Ended December 31
	2018			2017
	(Unaudited) (In thousands)
Cash Flows From Operating Activities
Net income	$	157,646		$	314,132
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	96,065			88,374
Deferred income taxes	40,339			53,149
One-time income tax benefit	—			(161,884		)
Other	6,231			6,915
Net assets / liabilities from risk management activities	(2,458		)	2,030
Net change in operating assets and liabilities	(133,139		)	(129,478		)
Net cash provided by operating activities	164,684			173,238
Cash Flows From Investing Activities
Capital expenditures	(416,404		)	(383,238		)
Debt and equity securities activities, net	(963		)	(135		)
Other, net	2,074			2,001
Net cash used in investing activities	(415,293		)	(381,372		)
Cash Flows From Financing Activities
Net decrease in short-term debt	(575,780		)	(110,929		)
Net proceeds from equity offering	494,734			395,099
Issuance of common stock through stock purchase and employee retirement plans	4,241			5,660
Proceeds from issuance of long-term debt	596,994			—
Cash dividends paid	(58,722		)	(51,837		)
Debt issuance costs	(6,432		)	—
Other	—			(1,518		)
Net cash provided by financing activities	455,035			236,475
Net increase in cash and cash equivalents	204,426			28,341
Cash and cash equivalents at beginning of period	13,771			26,409
Cash and cash equivalents at end of period	$	218,197		$	54,750

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

December 31, 2018

1. Nature of Business

Atmos Energy Corporation (“Atmos Energy” or the “Company”) and 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 December 31, 2018, 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, 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, 2018. Because of seasonal and other factors, the results of operations for the three-month period ended December 31, 2018 are not indicative of our results of operations for the full 2019 fiscal year, which ends September 30, 2019.

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, 2018.

Accounting pronouncements adopted in fiscal 2019

In May 2014, the Financial Accounting Standards Board (FASB) issued a comprehensive new revenue recognition standard that superseded virtually all existing revenue recognition guidance under generally accepted accounting principles in the United States. Under the new standard, an entity recognizes revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. We adopted the new guidance October 1, 2018 using the modified retrospective method. See Note 5 for our discussion of the effects of implementing this standard.

In January 2016, the FASB issued guidance related to the classification and measurement of financial instruments. The amendments modify the accounting and presentation for certain financial liabilities and equity investments not consolidated or reported using the equity method. Effective October 1, 2018, changes in the fair value of our equity securities formerly designated as available-for-sale are now recognized in other non-operating expense on our condensed consolidated statement of comprehensive income. Additionally, in accordance with the guidance, we reclassified a net $8.2 million unrealized gain related to these equity securities from accumulated other comprehensive income to retained earnings. The accounting for debt securities designated as available-for-sale did not 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 accumulated other comprehensive income.

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

(FERC), which regulates interstate transmission pipelines and also establishes, through its Uniform System of Accounts, accounting practices for 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 followed by state commissions. As such, we continue to capitalize into property, plant and equipment 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 on a prospective basis in accordance with the new guidance.

We adopted the new guidance beginning on October 1, 2018. We continue to present the service cost component of net periodic benefit cost within operation and maintenance expense; however, other components of the net periodic benefit cost are now presented separately within other non-operating expense on our condensed consolidated statement of comprehensive income. The changes in presentation were implemented on a retrospective basis in accordance with the guidance. In lieu of determining how each component of the net periodic benefit cost was actually reflected in the condensed statement of comprehensive income, we elected to utilize a practical expedient that permits the use of the amounts disclosed for each component of the net periodic benefit cost in our pension and post-retirement benefit plans footnote as the basis to retroactively apply this standard to all prior periods presented. The new standard did not have a material impact on our financial position, results of operations or cash flows.

In August 2018, the FASB issued new guidance aligning the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract 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, beginning October 1, 2018. As a result of the new guidance, we will defer onto the balance sheet those up-front costs of cloud computing arrangements if they would have been capitalized in a similar on-premise software solution. The new standard did not have a material impact on our financial position, results of operations or cash flows.

Accounting pronouncements that will be effective after fiscal 2019

In February 2016, the FASB issued a comprehensive new leasing standard that will require lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The new standard will be effective for us beginning on October 1, 2019. 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. In January 2018, the FASB issued a practical expedient to allow entities to not evaluate existing or expired land easements that were not previously accounted for as leases under the current guidance. In July 2018, the FASB issued a practical expedient providing an additional and optional transition method to adopt the standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. We are currently evaluating the effect of this standard and amendments on our financial position, results of operations, cash flows and 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. We are currently evaluating the potential impact of this new guidance on our financial position, results of operations and cash flows.

In August 2018, the FASB issued new guidance that modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The guidance removes the disclosure requirements for the amounts of gain/loss and prior service cost/credit amortization expected in the following year and the disclosure of the effect of a one-percentage-point change in the 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 significant change in the plan obligations or assets. The new guidance is effective for us in the fiscal year beginning October 1, 2020 and should be applied on a retrospective basis to all periods presented. Early adoption is permitted. The adoption of this new guidance impacts only our 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 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 are reported separately.

Significant regulatory assets and liabilities as of December 31, 2018 and September 30, 2018 included the following:



	December 31, 2018		September 30, 2018
	(In thousands)
Regulatory assets:
Pension and postretirement benefit costs	$	7,188	$	6,496
Infrastructure mechanisms⁽¹⁾	85,071		96,739
Deferred gas costs	11,621		1,927
Recoverable loss on reacquired debt	8,076		8,702
Deferred pipeline record collection costs	22,122		20,467
Rate case costs	1,866		2,741
Other	6,422		6,739
	$	142,366	$	143,811
Regulatory liabilities:
Regulatory excess deferred taxes⁽²⁾	$	740,896	$	744,895
Regulatory cost of service reserve⁽³⁾	19,281		22,508
Regulatory cost of removal obligation	523,644		522,175
Deferred gas costs	85,820		94,705
Asset retirement obligation	12,887		12,887
APT annual adjustment mechanism	44,619		35,228
Pension and postretirement benefit costs	70,969		69,113
Other	14,354		9,486
	$	1,512,470	$	1,510,997


(1)	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.


(2)	The TCJA resulted in the remeasurement of the net deferred tax liability included in our rate base. Of this amount, $23.1 million is recorded in other current liabilities. The period and timing of the return of the excess deferred taxes is being determined by regulators in each of our jurisdictions. See Note 13 for further information.

(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. The period and timing of the return of this liability to utility customers is being determined by regulators in each of our jurisdictions. See Note 13 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 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, 2018.

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



	Three Months Ended December 31, 2018
	Distribution			Pipeline and Storage			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	838,181		$	39,601		$	—		$	877,782
Intersegment revenues	654			94,869			(95,523		)	—
Total operating revenues	838,835			134,470			(95,523		)	877,782
Purchased gas cost	437,732			(358		)	(95,209		)	342,165
Operation and maintenance expense	105,767			33,147			(314		)	138,600
Depreciation and amortization expense	69,709			26,356			—			96,065
Taxes, other than income	56,190			8,298			—			64,488
Operating income	169,437			67,027			—			236,464
Other non-operating expense	(6,477		)	(1,246		)	—			(7,723		)
Interest charges	18,210			9,639			—			27,849
Income before income taxes	144,750			56,142			—			200,892
Income tax expense	30,365			12,881			—			43,246
Net income	$	114,385		$	43,261		$	—		$	157,646
Capital expenditures	$	302,545		$	113,859		$	—		$	416,404



	Three Months Ended December 31, 2017
	Distribution			Pipeline and Storage			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	860,453		$	28,739		$	—		$	889,192
Intersegment revenues	339			97,724			(98,063		)	—
Total operating revenues	860,792			126,463			(98,063		)	889,192
Purchased gas cost	463,758			912			(97,753		)	366,917
Operation and maintenance expense	103,215			26,140			(310		)	129,045
Depreciation and amortization expense	65,434			22,940			—			88,374
Taxes, other than income	55,107			7,666			—			62,773
Operating income	173,278			68,805			—			242,083
Other non-operating expense	(1,922		)	(635		)	—			(2,557		)
Interest charges	21,368			10,141			—			31,509
Income before income taxes	149,988			58,029			—			208,017
Income tax benefit	(99,111		)	(7,004		)	—			(106,115		)
Net income	$	249,099		$	65,033		$	—		$	314,132
Capital expenditures	$	241,249		$	141,989		$	—		$	383,238

Balance sheet information at December 31, 2018 and September 30, 2018 by segment is presented in the following tables:



	December 31, 2018
	Distribution		Pipeline and Storage		Eliminations			Consolidated
	(In thousands)
Property, plant and equipment, net	$	7,889,901	$	2,808,328	$	—		$	10,698,229
Total assets	$	11,836,888	$	3,040,831	$	(2,261,930	)	$	12,615,789



	September 30, 2018
	Distribution		Pipeline and Storage		Eliminations			Consolidated
	(In thousands)
Property, plant and equipment, net	$	7,644,693	$	2,726,454	$	—		$	10,371,147
Total assets	$	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. 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 months ended December 31, 2018 and 2017 are calculated as follows:



	Three Months Ended December 31
	2018		2017
	(In thousands, except per share amounts)
Basic Earnings Per Share
Net income	$	157,646	$	314,132
Less: Income allocated to participating securities	135		328
Income available to common shareholders	$	157,511	$	313,804
Basic weighted average shares outstanding	113,800		108,564
Net income per share — Basic	$	1.38	$	2.89
Diluted Earnings Per Share
Income available to common shareholders	$	157,511	$	313,804
Effect of dilutive shares	—		—
Income available to common shareholders	$	157,511	$	313,804
Basic weighted average shares outstanding	113,800		108,564
Dilutive shares ⁽¹⁾	32		—
Diluted weighted average shares outstanding	113,832		108,564
Net income per share - Diluted	$	1.38	$	2.89


(1)	Dilutive shares were the result of the forward sale agreements entered into during fiscal 2019. See Note 7 for further discussion.

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 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 December 31, 2018
	Distribution			Pipeline and Storage
	(In thousands)
Gas sales revenues:
Residential	$	547,928		$	—
Commercial	218,938			—
Industrial	34,537			—
Public authority and other	13,285			—
Total gas sales revenues	814,688			—
Transportation revenues	25,400			147,424
Miscellaneous revenues	6,950			1,682
Revenues from contracts with customers	847,038			149,106
Alternative revenue program revenues	(8,739		)	(14,636		)
Other revenues	536			—
Total operating revenues	$	838,835		$	134,470

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 prices 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. These amounts can be either additional revenue or given back to customers depending on actual results as compared to the weather in our distribution segment or versus the benchmark in our pipeline and storage segment. 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, 2018. Other than as described below, there were no material changes in the terms of our debt instruments during the three months ended December 31, 2018.

Long-term debt at December 31, 2018 and September 30, 2018 consisted of the following:



	December 31, 2018			September 30, 2018
	(In thousands)
Unsecured 8.50% Senior Notes, due March 2019	$	450,000		$	450,000
Unsecured 3.00% Senior Notes, due 2027	500,000			500,000
Unsecured 5.95% Senior Notes, due 2034	200,000			200,000
Unsecured 5.50% Senior Notes, due 2041	400,000			400,000
Unsecured 4.15% Senior Notes, due 2043	500,000			500,000
Unsecured 4.125% Senior Notes, due 2044	750,000			750,000
Unsecured 4.30% Senior Notes, due 2048	600,000			—
Medium-term note Series A, 1995-1, 6.67%, due 2025	10,000			10,000
Unsecured 6.75% Debentures, due 2028	150,000			150,000
Floating-rate term loan, due September 2019⁽¹⁾	125,000			125,000
Total long-term debt	3,685,000			3,085,000
Less:
Original issue (premium) / discount on unsecured senior notes and debentures	(1,472		)	(4,439		)
Debt issuance cost	26,693			20,774
Current maturities	575,000			575,000
	$	3,084,779		$	2,493,665


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

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 driven 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 that expires on September 25, 2022. The facility bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a spread ranging from zero percent to 1.25 percent, based on the Company’s credit ratings. Additionally, the facility contains a $250 million accordion feature, which provides the opportunity to increase the total committed loan to $1.75 billion. At December 31, 2018, 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 and a $10 million 364-day unsecured revolving credit facility, which is used primarily to issue letters of credit. At December 31, 2018, 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 December 31, 2018, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 42 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 if not paid at maturity. We were in compliance with all of our debt covenants as of December 31, 2018. 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.

7. Shareholders' Equity

The following tables present a reconciliation of changes in stockholders' equity for the three months ended December 31, 2018 and 2017.



	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



	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

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

On November 13, 2018, we filed a registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $3.0 billion in common stock and/or debt securities, which expires November 13, 2021. This registration statement replaced our previous registration statement that was effectively exhausted in October 2018. At December 31, 2018, approximately $1.8 billion of securities remained available for issuance under the shelf registration statement.

On November 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 November 13, 2021. During the three months ended December 31, 2018, no shares of common stock were sold under the ATM equity sales program.

On November 30, 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 the underwriting discount, net proceeds from the offering were $494.7 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. During the three months ended December 31, 2018, no shares of common stock were settled under the forward sale agreements. If we had settled all shares under the forward agreements at December 31, 2018, we would have received approximately $245.2 million, based on a net price of $91.90 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 for $400 million. After expenses, net proceeds from the 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 agreement cash flow hedges. Deferred gains (losses) for our available-for-sale debt securities 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⁽¹⁾			Interest Rate Agreement Cash Flow Hedges			Total
	(In thousands)
September 30, 2018	$	8,124		$	(91,771	)	$	(83,647	)
Other comprehensive loss before reclassifications	—			(22,716		)	(22,716		)
Amounts reclassified from accumulated other comprehensive income	—			458			458
Net current-period other comprehensive loss	—			(22,258		)	(22,258		)
Cumulative effect of accounting change (See Note 2)	(8,210		)	—			(8,210		)
December 31, 2018	$	(86	)	$	(114,029	)	$	(114,115	)



	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 loss before reclassifications	(107		)	(1,332		)	(1,439		)
Amounts reclassified from accumulated other comprehensive income	—			377			377
Net current-period other comprehensive loss	(107		)	(955		)	(1,062		)
December 31, 2017	$	6,941		$	(113,257	)	$	(106,316	)


(1)	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 the 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 months ended December 31, 2018 and 2017 are presented in the following table. Most of these costs are recoverable through our tariff rates. A portion of these costs is capitalized into our rate 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.



	Three Months Ended December 31
	Pension Benefits						Other Benefits
	2018			2017			2018			2017
	(In thousands)
Components of net periodic pension cost:
Service cost	$	4,045		$	4,560		$	2,702		$	3,020
Interest cost⁽¹⁾	6,799			6,430			2,961			2,727
Expected return on assets⁽¹⁾	(7,113		)	(6,917		)	(2,665		)	(2,002		)
Amortization of prior service cost (credit)⁽¹⁾	(58		)	(58		)	43			3
Amortization of actuarial (gain) loss⁽¹⁾	1,608			3,089			(2,045		)	(1,618		)
Net periodic pension cost	$	5,281		$	7,104		$	996		$	2,130

(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.

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. These

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 three months ended December 31, 2018.

Leases

We have entered into operating leases for towers, office and warehouse space, vehicles and heavy equipment used in our operations. During the three months ended December 31, 2018, we executed amendments to some of our lease agreements that impacted terms as well as our future minimum lease payments. As of December 31, 2018, 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 leases. The related future minimum lease payments at December 31, 2018 totaled $194.2 million

Regulatory Matters

Except for routine regulatory proceedings as discussed below, there were no material changes to regulatory matters for the three months ended December 31, 2018.

As of December 31, 2018, regulatory proceedings were in progress in our Colorado, Kansas, Kentucky, Louisiana, Mid-Tex, Tennessee, Virginia and West Texas service areas. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments. Additionally, as discussed in further detail in Note 13, all jurisdictions are addressing impacts of the TCJA.

10. Financial Instruments

We currently use financial instruments to mitigate commodity price risk and interest rate risk. The objectives and strategies for using financial instruments and the related accounting for these financial instruments are fully described in Notes 2 and 13 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2018. During the three months ended December 31, 2018, 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 2018-2019 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we anticipate hedging approximately 33 percent, or 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 interest rate risk by entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.

As of December 31, 2018, we had forward starting interest rate swaps to effectively fix the Treasury yield component associated with the anticipated issuance of $450 million unsecured senior notes in fiscal 2019 at 3.78%, which we designated as a cash flow hedge at the time the swaps were executed. As of December 31, 2018, we had $47.7 million of net realized losses in accumulated other comprehensive income (AOCI) associated with the settlement of financial instruments used to fix the Treasury yield component of the interest cost of financing various issuances of long-term debt and senior notes, which will be recognized as a component of interest expense over the life of the associated notes from the date of settlement. The remaining amortization periods for these settled amounts extend through fiscal 2045.

Quantitative Disclosures Related to Financial Instruments

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

As of December 31, 2018, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of December 31, 2018, we had 14,353 MMcf of net 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 December 31, 2018 and September 30, 2018. The gross amounts of recognized assets and liabilities are netted within our unaudited condensed consolidated balance sheets to the extent that we have netting arrangements with our counterparties. However, for December 31, 2018 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)
December 31, 2018
Designated As Hedges:
Interest rate swap agreements	Other current assets / Other current liabilities	$	—	$	(85,930	)
Total		—		(85,930		)
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	3,241		(1,265		)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	285		—
Total		3,526		(1,265		)
Gross / Net Financial Instruments		$	3,526	$	(87,195	)




	Balance Sheet Location	Assets		Liabilities
		(In thousands)
September 30, 2018
Designated As Hedges:
Interest rate swap agreements	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

Cash Flow Hedges

As discussed above, our distribution segment has interest rate swap agreements, which we designated as a cash flow hedge at the time the swaps 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 December 31, 2018 and 2017 was $0.6 million and $0.6 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 months ended December 31, 2018 and 2017. 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 as incurred.



	Three Months Ended December 31
	2018			2017
	(In thousands)
Increase (decrease) in fair value:
Interest rate agreements	$	(22,716	)	$	(1,332	)
Recognition of losses in earnings due to settlements:
Interest rate agreements	458			377
Total other comprehensive income (loss) from hedging, net of tax	$	(22,258	)	$	(955	)

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 December 31, 2018, 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
	(In thousands)
Next twelve months	$	(1,878	)
Thereafter	(45,827		)
Total	$	(47,705	)

Financial Instruments Not Designated as Hedges

As discussed above, financial instruments used in our distribution segment are not designated as hedges. However, there is no earnings impact on our distribution segment as a result of the use of these financial instruments because the gains and losses arising from the use of these financial instruments are recognized in the consolidated statement of 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, 2018. During the three months ended December 31, 2018, 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, 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 December 31, 2018 and September 30, 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		December 31, 2018
	(In thousands)
Assets:
Financial instruments	$	—	$	3,526	$	—	$	—	$	3,526
Debt and equity securities
Registered investment companies	37,241		—		—		—		37,241
Bond mutual funds	21,523		—		—		—		21,523
Bonds⁽²⁾	—		30,096		—		—		30,096
Money market funds	—		3,319		—		—		3,319
Total debt and equity securities	58,764		33,415		—		—		92,179
Total assets	$	58,764	$	36,941	$	—	$	—	$	95,705
Liabilities:
Financial instruments	$	—	$	87,195	$	—	$	—	$	87,195



	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)
Assets:
Financial instruments	$	—	$	1,619	$	—	$	—	$	1,619
Debt and equity securities
Registered investment companies	42,644		—		—		—		42,644
Bond mutual funds	21,507		—		—		—		21,507
Bonds⁽²⁾	—		31,400		—		—		31,400
Money market funds	—		3,834		—		—		3,834
Total debt and equity securities	64,151		35,234		—		—		99,385
Total assets	$	64,151	$	36,853	$	—	$	—	$	101,004
Liabilities:
Financial instruments	$	—	$	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 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.

Debt and equity securities are comprised of our available-for-sale debt securities and our equity securities. We regularly evaluate the performance of our available-for-sale debt securities on an investment by investment basis for impairment, taking into consideration the investment’s purpose, volatility and current returns. If a determination is made that a decline in fair value is other than temporary, the related investment is written down to its estimated fair value and the other-than-temporary impairment is recognized in the statement of comprehensive income. At December 31, 2018 and September 30, 2018, our available-for-sale debt securities were recorded at amortized cost of $30.2 million and $31.5 million. At December 31, 2018, we maintained investments in bonds that have contractual maturity dates ranging from January 2019 through December 2021.

Other Fair Value Measures

Our debt is recorded at carrying value. The fair value of our debt is determined using third party market value quotations, which are considered Level 1 fair value measurements for debt instruments with a recent, observable trade or Level 2 fair value measurements for debt instruments where fair value is determined using the most recent available quoted market price. The following table presents the carrying value and fair value of our debt as of December 31, 2018 and September 30, 2018:



	December 31, 2018		September 30, 2018
	(In thousands)
Carrying Amount	$	3,685,000	$	3,085,000
Fair Value	$	3,746,697	$	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, 2018. During the three months ended December 31, 2018, there were no material changes in our concentration of credit risk.

13. Impact 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. As a result of the implementation of the TCJA, we recognized a $161.9 million income tax benefit in our condensed consolidated statement of comprehensive income during the first quarter of fiscal 2018 related to a change in deferred taxes that were not related to 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 will be returned to ratepayers in accordance with regulatory requirements. As of December 31, 2018 and September 30, 2018, this liability totaled $740.9 million and $744.9 million.

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 December 31, 2018, we have 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, Louisiana, Mississippi, Tennessee and Texas service areas. We continue to work with regulators in Virginia to reflect the effects of the lower statutory income tax rate in our cost of service in rates.

Regulators in all of our service areas issued accounting orders that required us to establish, effective January 1, 2018, a separate regulatory liability for the difference in taxes included in our rates that were calculated based on a 35% statutory income tax rate and rates based on the new 21% statutory income tax rate until the new rates could be established. As of December 31, 2018, we received approval from regulators to return these liabilities to customers in Colorado, Kansas, Louisiana and Texas. This regulatory liability totaled $19.3 million and $22.5 million as of December 31, 2018 and September 30, 2018.

As of December 31, 2018, we received approval from regulators to return excess deferred taxes in Colorado, Kentucky, Louisiana, Mississippi, Tennessee and Texas in accordance with regulatory proceedings on a provisional basis over periods ranging from 13 to 51 years. In our remaining jurisdictions, the treatment of the effects of the 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 measurement period in accounting for business combinations. The Company recorded provisional amounts for the income tax effects of 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 on the Company's income tax balances may change following further interpretation of TCJA provisions by issuance of U.S. Treasury regulations or guidance from the Internal Revenue Service. We continue to monitor and assess the accounting implications of the TCJA developments on the consolidated 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 December 31, 2018, the related condensed consolidated statements of comprehensive income and cash flows for the three months ended December 31, 2018 and 2017, and 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 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) (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 December 31, 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 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 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.

/s/ ERNST & YOUNG LLP

Dallas, Texas

February 5, 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, 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; 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; 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; the impact of climate change or related additional legislation or regulation in the future; 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 December 31, 2018 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.

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, 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 three months ended December 31, 2018.

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 statement of comprehensive income as purchased gas cost. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe 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 rather than operating revenues and purchased gas cost individually. Further, the term 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 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 non-cash income tax benefit of $161.9 million for the three months ended December 31, 2017. Due to the non-recurring nature of this benefit, we believe that net income and diluted net income per share before the non-cash income tax benefit provide a more relevant measure to analyze our financial performance than net income and diluted net income per share 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 and adjusted diluted earnings per share, which is calculated as follows:



	Three Months Ended December 31
	2018		2017			Change
	(In thousands, except per share data)
Net income	$	157,646	$	314,132		$	(156,486	)
TCJA non-cash income tax benefit	—		(161,884		)	161,884
Adjusted net income	$	157,646	$	152,248		$	5,398

Diluted net income per share	$	1.38	$	2.89		$	(1.51	)
Diluted EPS from TCJA non-cash income tax benefit	—		(1.49		)	1.49
Adjusted diluted net income per share	$	1.38	$	1.40		$	(0.02	)

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 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 three months ended December 31, 2018, we recorded net income of $157.6 million, or $1.38 per diluted share, compared to net income of $314.1 million, or $2.89 per diluted share for the three months ended December 31, 2017.

After adjusting for the nonrecurring benefit recognized after implementing the TCJA in fiscal 2018, we recorded adjusted net income of $152.2 million, or $1.40 per diluted share for the three months ended December 31, 2017. The period-over-period increase in adjusted net income of $5.4 million, or four percent largely reflects weather that was 20 percent colder than the prior year, positive rate outcomes in our pipeline and storage business and the impact of the TCJA on our effective income tax rate, partially offset by reduced revenues as a result of implementing the TCJA. Additionally, the period-over-period decrease in adjusted diluted earning per share reflects increases in our common stock outstanding due to common stock issuances in 2017 and 2018. During the three months ended December 31, 2018, we implemented regulatory actions which resulted in an increase in annual operating income of $22.4 million and had ten ratemaking efforts in progress at December 31, 2018, seeking a total increase in annual operating income of $20.9 million.

Capital expenditures for the three months ended December 31, 2018 increased nine percent period-over-period, to $416.4 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 range from $1.65 billion to $1.75 billion for fiscal 2019. We funded our capital expenditures program primarily through operating cash flows of $164.7 million. Additionally, we completed $1.35 billion in external financing during the three months ended December 31, 2018 with the issuance of $600 million in 30-year senior notes and approximately $750 million of common stock. Approximately $245 million of the net proceeds from the equity offering were allocated to the forward sale agreements that expire in March 2020. The net proceeds from these issuances were used 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 8.2 percent for fiscal 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, 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 to minimize regulatory lag and, ultimately, separate the recovery of our approved 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 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. We are generally able to pass the cost of gas through to our customers without markup under purchased gas cost adjustment mechanisms; therefore, increases in the cost of

gas are offset by a corresponding increase in revenues. Contribution 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 revenue-related taxes arising from changes in gas costs affect Contribution Margin, over time the impact is offset within operating income.

Although the cost of gas typically does not have a direct impact on our Contribution Margin, higher gas costs 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. Currently, gas cost risk has been mitigated by rate design that 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 December 31, 2018 compared with Three Months Ended December 31, 2017

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



	Three Months Ended December 31
	2018			2017			Change
	(In thousands, unless otherwise noted)
Operating revenues	$	838,835		$	860,792		$	(21,957	)
Purchased gas cost	437,732			463,758			(26,026		)
Contribution Margin	401,103			397,034			4,069
Operating expenses	231,666			223,756			7,910
Operating income	169,437			173,278			(3,841		)
Other non-operating expense	(6,477		)	(1,922		)	(4,555		)
Interest charges	18,210			21,368			(3,158		)
Income before income taxes	144,750			149,988			(5,238		)
TCJA non-cash income tax benefit	—			(140,151		)	140,151
Income tax expense	30,365			41,040			(10,675		)
Net income	$	114,385		$	249,099		$	(134,714	)
Consolidated distribution sales volumes — MMcf	101,698			86,307			15,391
Consolidated distribution transportation volumes — MMcf	41,048			38,050			2,998
Total consolidated distribution throughput — MMcf	142,746			124,357			18,389
Consolidated distribution average cost of gas per Mcf sold	$	4.30		$	5.37		$	(1.07	)

Income before income taxes for our distribution segment decreased four percent, primarily due to a $7.9 million increase in operating expenses, partially offset by a $4.1 million increase in Contribution Margin. The quarter-over-quarter increase in Contribution Margin primarily reflects:


•	a $7.7 million increase in residential and commercial net consumption, primarily in our Mid-Tex and Mississippi Divisions.


•	a $3.7 million increase from customer growth primarily in our Mid-Tex Division.


•	a $7.3 million net decrease in rate adjustments, after the effect of the TCJA, primarily in our Mid-Tex and Kentucky/Mid-States Divisions.

The increase in operating expenses, which includes operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, is primarily attributable to an increase in depreciation expense and property taxes associated with increased capital investments.

The decrease in income tax expense reflects a reduction in our effective tax rate from 27.4% to 21.0%, 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 December 31, 2018 and 2017. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.



	Three Months Ended December 31
	2018		2017		Change
	(In thousands)
Mid-Tex	$	72,406	$	72,925	$	(519	)
Kentucky/Mid-States	24,452		28,129		(3,677		)
Louisiana	22,153		23,268		(1,115		)
West Texas	15,823		15,761		62
Mississippi	19,588		18,275		1,313
Colorado-Kansas	13,789		12,931		858
Other	1,226		1,989		(763		)
Total	$	169,437	$	173,278	$	(3,841	)

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 three months of fiscal 2019, we implemented five regulatory proceedings, resulting in a $22.4 million increase in annual operating income as summarized below. The ratemaking outcomes for 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 (Decrease) in Operating Income
	(In thousands)
Annual formula rate mechanisms	$	22,378
Rate case filings	—
Other rate activity	—
	$	22,378

The following ratemaking efforts, which reflect a 21% federal income tax rate resulting from the TCJA, seeking $20.9 million in increased annual operating income were in progress as of December 31, 2018:



Division	Rate Action	Jurisdiction	Operating Income Requested
			(In thousands)
Colorado-Kansas	SSIR	Colorado ⁽¹⁾	$	2,147
Colorado-Kansas	SSIR/GIS	Colorado ⁽²⁾	87
Colorado-Kansas	Ad Valorem	Kansas ⁽³⁾	214
Louisiana	RSC	Trans La	4,719
Mid-Tex	Rate Case	ATM Cities	4,252
Mid-Tex	Rate Case	Environs ⁽⁴⁾	(1,875		)
Kentucky/Mid-States	Formula Rate Mechanism True-Up	Tennessee ⁽⁵⁾	(3,220		)
Kentucky/Mid-States	Rate Case	Kentucky	14,424
Kentucky/Mid-States	Rate Case	Virginia	605
West Texas	Rate Case	Environs ⁽⁴⁾	(485		)
			$	20,868


(1)	The Colorado Public Utilities Commission approved the SSIR implementation at their December 19, 2018 meeting with rates effective January 1, 2019.


(2)	The Company has filed a request to recover Geographic Information System projects in a manner similar to its current SSIR program.


(3)	The Kansas Corporation Commission approved the Ad Valorem filing on January 8, 2019.


(4)	The Texas Railroad Commission approved these filings on December 11, 2018 with an operating income decrease of $2.7 million for Mid-Tex and $0.8 million for West Texas effective January 1, 2019.


(5)	The Tennessee Formula Mechanism True-up (True-up filing) test period ended May 2018 reflects the impact of the lower federal income tax rate between January 1, 2018 and May 31, 2018. The True-up filing was included in the Tennessee ARM filing made on February 1, 2019 with the Tennessee Public Utility Commission, which requested an operating income increase of $3.2 million.

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) (2)	—
Louisiana	(1)	Rate Stabilization Clause (RSC)
Mississippi	System Integrity Rider (SIR)	Stable Rate Filing (SRF)
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.


(2)	The Company has proposed removal of the PRP tariff in a pending Kentucky Public Service Commission case and anticipates recovery of this program investment through annual forward-looking rate case filings.

The following annual formula rate mechanisms, which reflect a 21% federal income tax rate resulting from the TCJA, were approved during the three months ended December 31, 2018:



Division	Jurisdiction	Test Year Ended	Increase (Decrease) in Annual Operating Income			Effective Date
		(In thousands)
2019 Filings:
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			$	22,378

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. There was no rate case activity completed during the three months ended December 31, 2018.

Other Ratemaking Activity

The Company had no other ratemaking activity during the three months ended December 31, 2018.

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 and 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 owns and operates five underground storage facilities in Texas.

Our natural gas transmission operations in Louisiana are comprised of a 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 supply areas that we serve, which may influence the level of throughput we may be able to transport on our 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 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.

Three Months Ended December 31, 2018 compared with Three Months Ended December 31, 2017

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



	Three Months Ended December 31
	2018			2017			Change
	(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue	$	88,432		$	93,898		$	(5,466	)
Third-party transportation revenue	43,288			28,931			14,357
Other revenue	2,750			3,634			(884		)
Total operating revenues	134,470			126,463			8,007
Total purchased gas cost	(358		)	912			(1,270		)
Contribution Margin	134,828			125,551			9,277
Operating expenses	67,801			56,746			11,055
Operating income	67,027			68,805			(1,778		)
Other non-operating expense	(1,246		)	(635		)	(611		)
Interest charges	9,639			10,141			(502		)
Income before income taxes	56,142			58,029			(1,887		)
TCJA non-cash income tax benefit	—			(21,733		)	21,733
Income tax expense	12,881			14,729			(1,848		)
Net income	$	43,261		$	65,033		$	(21,772	)
Gross pipeline transportation volumes — MMcf	238,855			213,137			25,718
Consolidated pipeline transportation volumes — MMcf	170,527			155,105			15,422

Income before income taxes for our pipeline and storage segment decreased three percent, primarily due to an $11.1 million increase in operating expenses, partially offset by a $9.3 million increase in Contribution Margin. The increase in Contribution Margin primarily reflects:


•	a $6.1 million increase in rates from the approved GRIP filings approved in December 2017 and May 2018. The increase in rates was driven primarily by increased safety and reliability spending.


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

Operating expenses increased $11.1 million, primarily due to higher depreciation expense associated with increased capital investments and higher system maintenance expense.

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 2019 and beyond.

To continue to support our capital market activities, we filed a registration statement with the SEC on November 13, 2018 that permits us to issue a total of $3.0 billion in common stock and/or debt securities. This registration statement replaced our previous registration statement that was effectively exhausted after the completion of our public offering of $600 million of 4.30% senior notes on October 4, 2018. On November 19, 2018, we entered into an at-the-market (ATM) equity distribution program under the new shelf registration statement, under which we may issue and sell shares of our common stock (including shares of common stock that may be sold pursuant to the forward sale agreement) up to an aggregate offering price of $500 million. During the three months ended December 31, 2018, no shares of common stock were sold under the ATM program.

On November 30, 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 the underwriting discount, net proceeds from the offering were $494.7 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. At December 31, 2018, approximately $1.8 billion of securities remained available for issuance under the shelf registration statement.

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



	December 31, 2018				September 30, 2018				December 31, 2017
	(In thousands, except percentages)
Short-term debt	$	—	—	%	$	575,780	6.8	%	$	336,816	4.2	%
Long-term debt⁽¹⁾	3,659,779		40.6	%	3,068,665		36.5	%	3,067,469		38.5	%
Shareholders’ equity	5,348,195		59.4	%	4,769,951		56.7	%	4,563,620		57.3	%
Total	$	9,007,974	100.0	%	$	8,414,396	100.0	%	$	7,967,905	100.0	%


(1)	In March 2019, $450 million of long-term debt will mature. 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%. In September 2019, our $125 million term loan will mature, which we plan to refinance.

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, the price for our services, demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks and other factors.

Cash flows from operating, investing and financing activities for the three months ended December 31, 2018 and 2017 are presented below.



	Three Months Ended December 31
	2018			2017			Change
	(In thousands)
Total cash provided by (used in)
Operating activities	$	164,684		$	173,238		$	(8,554	)
Investing activities	(415,293		)	(381,372		)	(33,921		)
Financing activities	455,035			236,475			218,560
Change in cash and cash equivalents	204,426			28,341			176,085
Cash and cash equivalents at beginning of period	13,771			26,409			(12,638		)
Cash and cash equivalents at end of period	$	218,197		$	54,750		$	163,447

Cash flows from operating activities

Period-over-period changes in our operating cash flows are primarily attributable to changes in net income and working capital changes, particularly within our distribution segment resulting from changes in the price of natural gas and the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries.

For the three months ended December 31, 2018, we generated cash flow from operating activities of $164.7 million compared with $173.2 million for the three months ended December 31, 2017. The $8.6 million decrease in operating cash flows reflects unfavorable changes in the price of natural gas purchased, the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries.

Cash flows from investing activities

Our capital expenditures are primarily used to improve the safety and reliability of our distribution and transmission system through pipeline replacement and system modernization and to enhance and expand our system to meet customer needs. Over the last three fiscal years, approximately 82 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 to earn an adequate return timely on our investment without compromising safety or reliability.

For the three months ended December 31, 2018, cash used for investing activities was $415.3 million compared to $381.4 million for the three months ended December 31, 2017. Capital spending increased by $33.2 million, or nine 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.

Cash flows from financing activities

For the three months ended December 31, 2018, our financing activities provided $455.0 million of cash compared with $236.5 million in the prior-year period. Our significant financing activities for the three months ended December 21, 2018 and 2017 are summarized as follows:

In the three months ended December 31, 2018, we used $590.6 million in net proceeds, after expenses, from debt financing and $494.7 million in net proceeds, after the underwriting discount, from equity financing 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 three months ended December 31, 2017, 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.

The following table summarizes our share issuances for the three months ended December 31, 2018 and 2017:



	Three Months Ended December 31
	2018	2017
Shares issued:
Direct Stock Purchase Plan	20,559	38,209
1998 Long-Term Incentive Plan	184,464	235,960
Retirement Savings Plan and Trust	23,417	24,905
Equity Issuance	5,390,836	4,558,404
Total shares issued	5,619,276	4,857,478

Credit Ratings

Our credit ratings directly affect our ability to obtain short-term and long-term financing, in addition to the cost of such financing. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including debt to total capitalization, operating cash flow relative to outstanding debt, operating cash flow coverage of interest and pension liabilities and funding status. In addition, the rating agencies consider qualitative factors such as consistency of our earnings over time, the quality of our management and business strategy, the risks associated with our businesses and the regulatory structures that govern our rates in the states where we operate.

Our debt is rated by two rating agencies: Standard & Poor’s Corporation (S&P) and Moody’s Investors Service (Moody’s). 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 December 31, 2018, 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 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 December 31, 2018. Our debt covenants are described in greater detail in Note 6 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 three months ended December 31, 2018.

Risk Management Activities

In our distribution and pipeline and storage segments, we use a combination of physical storage, fixed physical contracts and fixed financial contracts to reduce our exposure to unusually large winter-period gas price increases. Additionally, we manage interest rate risk by entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.

The following table shows the components of the change in fair value of our financial instruments for the three months ended December 31, 2018 and 2017:



	Three Months Ended December 31
	2018			2017
	(In thousands)
Fair value of contracts at beginning of period	$	(55,218	)	$	(109,159	)
Contracts realized/settled	6,458			1,160
Fair value of new contracts	484			(569		)
Other changes in value	(35,393		)	(7,961		)
Fair value of contracts at end of period	(83,669		)	(116,529		)
Netting of cash collateral	—			—
Cash collateral and fair value of contracts at period end	$	(83,669	)	$	(116,529	)

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



	Fair Value of Contracts at December 31, 2018
	Maturity in Years
Source of Fair Value	Less Than 1			1-3		4-5		Greater Than 5		Total Fair Value
	(In thousands)
Prices actively quoted	$	(83,954	)	$	285	$	—	$	—	$	(83,669	)
Prices based on models and other valuation methods	—			—		—		—		—
Total Fair Value	$	(83,954	)	$	285	$	—	$	—	$	(83,669	)

Pension and Postretirement Benefits Obligations

For the three months ended December 31, 2018 and 2017, our total net periodic pension and other postretirement benefits costs were $6.3 million and $9.2 million. These costs are recoverable through our rates. A portion of these costs is capitalized into our rate 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 as discussed in Note 8.

Our fiscal 2019 costs were determined using a September 30, 2018 measurement date. As of September 30, 2018, interest and corporate bond rates were higher than the rates as of September 30, 2017. Therefore, we increased the discount rate used to measure our fiscal 2019 net periodic cost from 3.89 percent to 4.38 percent. The expected return on plan assets remained consistent with prior year at 6.75 percent in the determination of our fiscal 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 2019 net periodic pension cost to be lower than fiscal 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, 2018, we were not required to make a minimum contribution to our defined benefit plan during the first quarter of fiscal 2019.

For the three months ended December 31, 2018 we contributed $4.3 million to our postretirement medical plans. We anticipate contributing a total of between $10 million and $20 million to our postretirement plans during fiscal 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-month periods ended December 31, 2018 and 2017.

Distribution Sales and Statistical Data



	Three Months Ended December 31
	2018		2017
METERS IN SERVICE, end of period
Residential	2,988,920		2,956,247
Commercial	273,032		270,184
Industrial	1,682		1,675
Public authority and other	8,386		8,418
Total meters	3,272,020		3,236,524

INVENTORY STORAGE BALANCE — Bcf	56.7		55.6
SALES VOLUMES — MMcf⁽¹⁾
Gas sales volumes
Residential	59,864		48,948
Commercial	31,583		26,949
Industrial	8,174		8,458
Public authority and other	2,077		1,952
Total gas sales volumes	101,698		86,307
Transportation volumes	42,851		39,859
Total throughput	144,549		126,166
OPERATING REVENUES (000’s)⁽¹⁾⁽²⁾
Gas sales revenues
Residential	$	540,439	$	556,520
Commercial	217,060		223,580
Industrial	34,472		33,413
Public authority and other	13,107		13,561
Total gas sales revenues	805,078		827,074
Transportation revenues	25,350		25,362
Other gas revenues	8,407		8,356
Total operating revenues	$	838,835	$	860,792
Average cost of gas per Mcf sold	$	4.30	$	5.37

See footnote following these tables.

Pipeline and Storage Operations Sales and Statistical Data



	Three Months Ended December 31
	2018		2017
CUSTOMERS, end of period
Industrial	93		93
Other	242		240
Total	335		333

INVENTORY STORAGE BALANCE — Bcf	1.0		1.1
PIPELINE TRANSPORTATION VOLUMES — MMcf⁽¹⁾	238,855		213,137
OPERATING REVENUES (000’s)⁽¹⁾⁽²⁾	$	134,470	$	126,463

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.

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, 2018. During the three months ended December 31, 2018, there were no material changes in our quantitative and qualitative disclosures about market risk.



Item 4.	Controls and Procedures

Management’s Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the Company’s disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act). Based on this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2018 to provide reasonable assurance that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified by the SEC’s rules and forms, including a reasonable level of assurance that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

We did not make any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the first quarter of the fiscal year ended September 30, 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 three months ended December 31, 2018, 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, 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
10	Equity Distribution Agreement, dated as of November 16, 2018, among Atmos Energy Corporation and the Managers and Forward Purchasers named in Schedule A thereto	Exhibit 1.1 to Form 8-K dated November 16, 2018 (File No. 1-10042)
10.1	Form of Master Forward Sale Confirmation	Exhibit 1.2 to 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: February 5, 2019

Atmos Energy - 10-Q quarterly report FY2019 Q1

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