UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2019

or

¨	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 May 2, 2019.

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

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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

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PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS 

	March 31, 2019				September 30, 2018
	(Unaudited)
	(In thousands, except share data)
ASSETS
Property, plant and equipment	$	13,272,148			$	12,567,373
Less accumulated depreciation and amortization	2,300,414				2,196,226
Net property, plant and equipment	10,971,734				10,371,147
Current assets
Cash and cash equivalents	108,353				13,771
Accounts receivable, net	419,612				253,295
Gas stored underground	78,148				165,732
Other current assets	65,068				46,055
Total current assets	671,181				478,853
Goodwill	730,419				730,419
Deferred charges and other assets	301,616				294,018
	$	12,674,950			$	11,874,437
CAPITALIZATION AND LIABILITIES
Shareholders’ equity
Common stock, no par value (stated at $0.005 per share); 200,000,000 shares authorized; issued and outstanding: March 31, 2019 — 116,982,903 shares; September 30, 2018 — 111,273,683 shares	$	585			$	556
Additional paid-in capital	3,485,794				2,974,926
Accumulated other comprehensive loss	(116,810		)		(83,647		)
Retained earnings	2,138,532				1,878,116
Shareholders’ equity	5,508,101				4,769,951
Long-term debt	3,528,713				2,493,665
Total capitalization	9,036,814				7,263,616
Current liabilities
Accounts payable and accrued liabilities	244,042				217,283
Other current liabilities	495,097				547,068
Short-term debt	—				575,780
Current maturities of long-term debt	125,000				575,000
Total current liabilities	864,139				1,915,131
Deferred income taxes	1,251,836				1,154,067
Regulatory excess deferred taxes (See Note 13)	712,681				739,670
Regulatory cost of removal obligation	462,249				466,405
Pension and postretirement liabilities	176,593				177,520
Deferred credits and other liabilities	170,638				158,028
	$	12,674,950			$	11,874,437

See accompanying notes to condensed consolidated financial statements.

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ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

	Three Months Ended   March 31
	2019				2018
	(Unaudited) (In thousands, except per share data)
Operating revenues
Distribution segment	$	1,057,889			$	1,199,291
Pipeline and storage segment	135,650				120,955
Intersegment eliminations	(98,894		)		(100,837		)
Total operating revenues	1,094,645				1,219,409
Purchased gas cost
Distribution segment	570,348				727,053
Pipeline and storage segment	(90		)		433
Intersegment eliminations	(98,582		)		(100,526		)
Total purchased gas cost	471,676				626,960
Operation and maintenance expense	149,427				159,159
Depreciation and amortization expense	96,772				89,381
Taxes, other than income	79,093				73,007
Operating income	297,677				270,902
Other non-operating income (expense)	4,232				(2,167		)
Interest charges	26,949				27,304
Income before income taxes	274,960				241,431
Income tax expense	60,072				62,439
Net income	$	214,888			$	178,992
Basic net income per share	$	1.83			$	1.60
Diluted net income per share	$	1.82			$	1.60
Cash dividends per share	$	0.525			$	0.485
Basic weighted average shares outstanding	117,581				111,706
Diluted weighted average shares outstanding	117,756				111,706
Net income	$	214,888			$	178,992
Other comprehensive income (loss), net of tax
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $29 and $(276) (See Note 2)	97				(939		)
Cash flow hedges:
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $(825) and $6,575	(2,792		)		22,244
Total other comprehensive income (loss)	(2,695		)		21,305
Total comprehensive income	$	212,193			$	200,297

See accompanying notes to condensed consolidated financial statements.

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ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Six Months Ended   March 31
	2019				2018
	(Unaudited) (In thousands, except per share data)
Operating revenues
Distribution segment	$	1,896,724			$	2,060,083
Pipeline and storage segment	270,120				247,418
Intersegment eliminations	(194,417		)		(198,900		)
Total operating revenues	1,972,427				2,108,601
Purchased gas cost
Distribution segment	1,008,080				1,190,811
Pipeline and storage segment	(448		)		1,345
Intersegment eliminations	(193,791		)		(198,279		)
Total purchased gas cost	813,841				993,877
Operation and maintenance expense	288,027				288,204
Depreciation and amortization expense	192,837				177,755
Taxes, other than income	143,581				135,780
Operating income	534,141				512,985
Other non-operating expense	(3,491		)		(4,724		)
Interest charges	54,798				58,813
Income before income taxes	475,852				449,448
Income tax expense (benefit)	103,318				(43,676		)
Net income	$	372,534			$	493,124
Basic net income per share	$	3.22			$	4.47
Diluted net income per share	$	3.21			$	4.47
Cash dividends per share	$	1.05			$	0.97
Basic weighted average shares outstanding	115,690				110,135
Diluted weighted average shares outstanding	115,794				110,135
Net income	$	372,534			$	493,124
Other comprehensive income (loss), net of tax
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $29 and $(338) (See Note 2)	97				(1,046		)
Cash flow hedges:
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $(7,405) and $6,026	(25,050		)		21,289
Total other comprehensive income (loss)	(24,953		)		20,243
Total comprehensive income	$	347,581			$	513,367

See accompanying notes to condensed consolidated financial statements.

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ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

	Six Months Ended   March 31
	2019				2018
	(Unaudited) (In thousands)
Cash Flows From Operating Activities
Net income	$	372,534			$	493,124
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	192,837				177,755
Deferred income taxes	96,885				116,023
One-time income tax benefit	—				(165,675		)
Other	5,334				12,252
Net assets / liabilities from risk management activities	(333		)		812
Net change in operating assets and liabilities	(106,428		)		117,076
Net cash provided by operating activities	560,829				751,367
Cash Flows From Investing Activities
Capital expenditures	(777,586		)		(693,978		)
Proceeds from the sale of discontinued operations	4,000				3,000
Debt and equity securities activities, net	777				(1,175		)
Other, net	4,388				4,009
Net cash used in investing activities	(768,421		)		(688,144		)
Cash Flows From Financing Activities
Net decrease in short-term debt	(575,780		)		(318,143		)
Net proceeds from equity offering	494,085				395,092
Issuance of common stock through stock purchase and employee retirement plans	10,344				11,902
Proceeds from issuance of long-term debt	1,045,221				—
Settlement of interest rate swaps	(90,141		)		—
Repayment of long-term debt	(450,000		)		—
Cash dividends paid	(120,328		)		(105,891		)
Debt issuance costs	(11,227		)		—
Other	—				(1,518		)
Net cash provided by (used in) financing activities	302,174				(18,558		)
Net increase in cash and cash equivalents	94,582				44,665
Cash and cash equivalents at beginning of period	13,771				26,409
Cash and cash equivalents at end of period	$	108,353			$	71,074

See accompanying notes to condensed consolidated financial statements.

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

March 31, 2019

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 March 31, 2019, covered service areas located in eight states.

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

2.    Unaudited Financial Information

These consolidated interim-period financial statements have been prepared in accordance with accounting principles generally accepted in the United States on the same basis, aside from accounting policy changes noted below, as those used for the Company’s audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended September 30, 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 six-month period ended March 31, 2019 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.

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

Accounting pronouncements adopted in fiscal 2019

During the first quarter of fiscal 2019, we adopted the following accounting guidance updates, effective October 1, 2018. The adoption of this new guidance, individually and collectively, did not have a material impact on our financial position, results of operations or cash flows.

•	Revenue recognition - Under the new guidance, we are required to recognize revenue when we transfer promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. See Note 5 for our discussion of the effects of implementing this standard.

•

Classification and measurement of financial instruments - The new guidance requires that we recognize changes in the fair value of our equity securities formerly designated as available-for-sale in other non-operating income (expense) in our condensed consolidated statement of comprehensive income on a prospective basis from the date of adoption. 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 (AOCI) 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 AOCI.

•	Presentation of the Components of Net Periodic Benefit Cost - The new guidance requires us to present only the current service cost component of the net benefit cost within operations and maintenance expense in the statement of

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

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

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

•

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

Accounting pronouncements that will be effective after fiscal 2019

In February 2016, the Financial Accounting Standards Board (FASB) issued a comprehensive new leasing standard that will require lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. Subsequently, the FASB issued practical expedients to 1) allow entities to not evaluate existing or expired land easements that were not previously accounted for as leases under the current guidance and 2) allow entities the option to adopt the standard and recognize a cumulative–effect adjustment to the opening balance of retained earnings in the period of adoption rather than applying the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The new standard will be effective for us beginning on October 1, 2019. We are currently evaluating the effect of this standard and amendments on our financial position, results of operations, cash flows and 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.

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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 March 31, 2019 and September 30, 2018 included the following:

	March 31, 2019				September 30, 2018
	(In thousands)
Regulatory assets:
Pension and postretirement benefit costs	$	7,843			$	6,496
Infrastructure mechanisms(1)	107,649				96,739
Deferred gas costs	3,490				1,927
Recoverable loss on reacquired debt	7,450				8,702
Deferred pipeline record collection costs	23,914				20,467
Rate case costs	1,612				2,741
Other	6,691				6,739
	$	158,649			$	143,811
Regulatory liabilities:
Regulatory excess deferred taxes(2)	$	736,634			$	744,895
Regulatory cost of service reserve(3)	6,175				22,508
Regulatory cost of removal obligation	524,067				522,175
Deferred gas costs	124,248				94,705
Asset retirement obligation	12,887				12,887
APT annual adjustment mechanism	48,524				35,228
Pension and postretirement benefit costs	70,328				69,113
Other	16,942				9,486
	$	1,539,805			$	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, $24.0 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.

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

	Three Months Ended March 31, 2019
	Distribution				Pipeline and Storage				Eliminations				Consolidated
	(In thousands)
Operating revenues from external parties	$	1,057,192			$	37,453			$	—			$	1,094,645
Intersegment revenues	697				98,197				(98,894		)		—
Total operating revenues	1,057,889				135,650				(98,894		)		1,094,645
Purchased gas cost	570,348				(90		)		(98,582		)		471,676
Operation and maintenance expense	117,621				32,118				(312		)		149,427
Depreciation and amortization expense	69,904				26,868				—				96,772
Taxes, other than income	71,053				8,040				—				79,093
Operating income	228,963				68,714				—				297,677
Other non-operating income (expense)	5,263				(1,031		)		—				4,232
Interest charges	15,896				11,053				—				26,949
Income before income taxes	218,330				56,630				—				274,960
Income tax expense	46,137				13,935				—				60,072
Net income	$	172,193			$	42,695			$	—			$	214,888
Capital expenditures	$	293,270			$	67,912			$	—			$	361,182

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

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	Six Months Ended March 31, 2019
	Distribution				Pipeline and Storage				Eliminations				Consolidated
	(In thousands)
Operating revenues from external parties	$	1,895,373			$	77,054			$	—			$	1,972,427
Intersegment revenues	1,351				193,066				(194,417		)		—
Total operating revenues	1,896,724				270,120				(194,417		)		1,972,427
Purchased gas cost	1,008,080				(448		)		(193,791		)		813,841
Operation and maintenance expense	223,388				65,265				(626		)		288,027
Depreciation and amortization expense	139,613				53,224				—				192,837
Taxes, other than income	127,243				16,338				—				143,581
Operating income	398,400				135,741				—				534,141
Other non-operating expense	(1,214		)		(2,277		)		—				(3,491		)
Interest charges	34,106				20,692				—				54,798
Income before income taxes	363,080				112,772				—				475,852
Income tax expense	76,502				26,816				—				103,318
Net income	$	286,578			$	85,956			$	—			$	372,534
Capital expenditures	$	595,815			$	181,771			$	—			$	777,586

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

 

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

	March 31, 2019
	Distribution				Pipeline and Storage				Eliminations				Consolidated
	(In thousands)
Property, plant and equipment, net	$	8,126,906			$	2,844,828			$	—			$	10,971,734
Total assets	$	11,904,290			$	3,071,654			$	(2,300,994	)		$	12,674,950

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

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

5.    Revenue

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

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

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

Distribution Revenues

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

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

Pipeline and Storage Revenues

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

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Alternative Revenue Program Revenues

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

6.    Debt

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

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

 

	March 31, 2019				September 30, 2018
	(In thousands)
Unsecured 8.50% Senior Notes, due March 2019	$	—			$	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				—
Unsecured 4.125% Senior Notes, due 2049	450,000				—
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	263				(4,439		)
Debt issuance cost	31,024				20,774
Current maturities	125,000				575,000
	$	3,528,713			$	2,493,665

    

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

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

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

We utilize short-term debt to provide cost-effective, short-term financing until it can be replaced with a balance of long-term debt and equity financing that achieves the Company’s desired capital structure with an equity-to-total-capitalization ratio between 50% and 60%, inclusive of long-term and short-term debt. Our short-term borrowing requirements are driven primarily by construction work in progress and the seasonal nature of the natural gas business. Changes in the price of natural gas and the

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

Currently, our short-term borrowing requirements are satisfied through a combination of a $1.5 billion commercial paper program and three committed revolving credit facilities with third-party lenders that provide approximately $1.5 billion of total working capital funding. The primary source of our funding is our commercial paper program, which is supported by a five-year unsecured $1.5 billion credit facility. On March 29, 2019, we executed our final one-year extension option which extended the maturity date from September 25, 2022 to September 25, 2023. The facility bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a margin ranging from zero percent to 1.25 percent, based on the Company’s credit ratings. Additionally, the facility contains a $250 million accordion feature, which provides the opportunity to increase the total committed loan to $1.75 billion. At March 31, 2019, there were no amounts outstanding under our commercial paper program. At September 30, 2018, a total of $575.8 million was outstanding.

Additionally, we have a $25 million 364-day unsecured facility, which was renewed effective April 1, 2019 and expires March 31, 2020, and a $10 million 364-day unsecured revolving credit facility, which is used primarily to issue letters of credit. At March 31, 2019, there were no borrowings outstanding under either of these facilities; however, outstanding letters of credit reduced the total amount available to us under our $10 million facility to $4.4 million.

The availability of funds under these credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total-debt-to-total-capitalization of no greater than 70 percent. At March 31, 2019, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 41 percent. In addition, both the interest margin and the fee that we pay on unused amounts under certain of these facilities are subject to adjustment depending upon our credit ratings.

These credit facilities and our public indentures contain usual and customary covenants for our business, including covenants substantially limiting liens, substantial asset sales and mergers. Additionally, our public debt indentures relating to our senior notes and debentures, as well as certain of our revolving credit agreements, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or if not paid at maturity. We were in compliance with all of our debt covenants as of March 31, 2019. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.

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7.    Shareholders' Equity

The following tables present a reconciliation of changes in stockholders' equity for the three and six months ended March 31, 2019 and 2018.

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

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

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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 March 31, 2019, approximately $1.3 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.

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

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

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 expenses, net proceeds from the offering were $494.1 million. Concurrently, we entered into separate forward sale agreements with two underwriters who borrowed and sold 2,668,464 shares of our common stock. Under the agreements we have the ability to settle these shares before March 31, 2020 at a price based on the offering price established on November 28, 2018. As of March 31, 2019, no shares of common stock were settled under the forward sale agreements. If we had settled all shares under the forward agreements at March 31, 2019, we would have received approximately $244.8 million, based on a net price of $91.75 per share.

On November 30, 2017, we filed a prospectus supplement under the previous registration statement relating to an underwriting agreement to sell 4,558,404 shares of our common stock 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 income (loss) before reclassifications	97				(25,966		)		(25,869		)
Amounts reclassified from accumulated other comprehensive income	—				916				916
Net current-period other comprehensive income (loss)	97				(25,050		)		(24,953		)
Cumulative effect of accounting change (See Note 2)	(8,210		)		—				(8,210		)
March 31, 2019	$	11			$	(116,821	)		$	(116,810	)

 

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

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

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

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

 

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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 six months ended March 31, 2019.

Leases

We have entered into operating leases for towers, office and warehouse space, vehicles and heavy equipment used in our operations. During the six months ended March 31, 2019, we executed amendments to some of our lease agreements that impacted terms as well as our future minimum lease payments. As of March 31, 2019, the remaining lease terms range from one to 20 years and generally provide for the payment of taxes, insurance and maintenance by the lessee. Renewal options exist for certain of these leases. The related future minimum lease payments at March 31, 2019 totaled $193.3 million.

Regulatory Matters

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

As of March 31, 2019, regulatory proceedings were in progress in substantially all of our 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 Tax Cuts and Jobs Act of 2017 (the "TCJA").

10.    Financial Instruments

We currently use financial instruments to mitigate commodity price risk and in the past have also used financial instruments to mitigate interest rate risk. The objectives and strategies for using financial instruments and the related accounting for these financial instruments are fully described in Notes 2 and 13 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2018. During the six months ended March 31, 2019, there were no material changes in our objectives, strategies and accounting for using financial instruments. Our financial instruments

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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 hedged 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

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

In fiscal 2014 and 2015, we entered into forward starting interest rate swaps to fix the Treasury yield component associated with $450 million of the then anticipated issuance of $450 million unsecured senior notes in fiscal 2019. These notes were issued as planned in March 2019 and we settled the swaps with the payment of $90.1 million. Because the swaps were effective, the realized loss was recorded as a component of AOCI and is being recognized as a component of interest expense over the 30-year life of the senior notes.

As of March 31, 2019, we had $116.8 million of net realized losses in 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 2049.

 

Quantitative Disclosures Related to Financial Instruments

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

As of March 31, 2019, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of March 31, 2019, we had 6,065 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 March 31, 2019 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 March 31, 2019 and September 30, 2018, no gross amounts and no cash collateral were netted within our consolidated balance sheet.

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

 

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	Balance Sheet Location		Assets				Liabilities
			(In thousands)
September 30, 2018
Designated As Hedges:
Interest rate swaps	Other current assets / Other current liabilities		$	—			$	(56,499	)
Total			—				(56,499		)
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities		1,369				(235		)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities		250				(103		)
Total			1,619				(338		)
Gross / Net Financial Instruments			$	1,619			$	(56,837	)

 

Impact of Financial Instruments on the Statement of Comprehensive Income

Cash Flow Hedges

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

The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three and six months ended March 31, 2019 and 2018. The amounts included in the table below exclude gains and losses arising from ineffectiveness because those amounts are immediately recognized in the statement of comprehensive income as incurred.

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

Deferred gains (losses) recorded in AOCI associated with our interest rate agreements are recognized in earnings as they are amortized over the terms of the underlying debt instruments. The following amounts, net of deferred taxes, represent the expected recognition in earnings, as of March 31, 2019, of the deferred losses recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments at the date of settlement.

	Interest Rate Agreements
	(In thousands)
Next twelve months	$	(4,212	)
Thereafter	(112,609		)
Total	$	(116,821	)

 

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Financial Instruments Not Designated as Hedges

As discussed above, commodity contracts which are used in our distribution segment are not designated as hedges. However, there is no earnings impact on our distribution segment as a result of the use of these financial instruments because the gains and losses arising from the use of these financial instruments are recognized in the consolidated statement of comprehensive income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue. Accordingly, the impact of these financial instruments is excluded from this presentation.

11.    Fair Value Measurements

We report certain assets and liabilities at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We record cash and cash equivalents, accounts receivable and accounts payable at carrying value, which substantially approximates fair value due to the short-term nature of these assets and liabilities. For other financial assets and liabilities, we primarily use quoted market prices and other observable market pricing information to minimize the use of unobservable pricing inputs in our measurements when determining fair value. The methods used to determine fair value for our assets and liabilities are fully described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2018. During the six months ended March 31, 2019, there were no changes in these methods.

Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about fair value measurements of the assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 7 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2018.

Quantitative Disclosures

Financial Instruments

The classification of our fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. Authoritative accounting literature establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1), with the lowest priority given to unobservable inputs (Level 3). The following tables summarize, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2019 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				March 31, 2019
	(In thousands)
Assets:
Financial instruments	$	—			$	1,611			$	—			$	—			$	1,611
Debt and equity securities
Registered investment companies	42,412				—				—				—				42,412
Bond mutual funds	21,935				—				—				—				21,935
Bonds(2)	—				29,890				—				—				29,890
Money market funds	—				2,440				—				—				2,440
Total debt and equity securities	64,347				32,330				—				—				96,677
Total assets	$	64,347			$	33,941			$	—			$	—			$	98,288
Liabilities:
Financial instruments	$	—			$	38			$	—			$	—			$	38

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	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 March 31, 2019 and September 30, 2018, our available-for-sale debt securities amortized cost was $29.9 million and $31.5 million. At March 31, 2019, we maintained investments in bonds that have contractual maturity dates ranging from April 2019 through February 2022.

Other Fair Value Measures

Our debt is recorded at carrying value. The fair value of our debt is determined using third party market value quotations, which are considered Level 1 fair value measurements for debt instruments with a recent, observable trade or Level 2 fair value measurements for debt instruments where fair value is determined using the most recent available quoted market price. The following table presents the carrying value and fair value of our debt as of March 31, 2019 and September 30, 2018:

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

12.    Concentration of Credit Risk

Information regarding our concentration of credit risk is disclosed in Note 16 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2018. During the six months ended March 31, 2019, 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 $165.7 million income tax benefit in our condensed consolidated statement of comprehensive income during the six months ended March 31, 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 March 31, 2019 and September 30, 2018, this liability totaled $736.6 million and $744.9 million.

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

Regulators in all of our service areas issued accounting orders that required us to establish, effective January 1, 2018, a separate regulatory liability for 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 March 31, 2019, we received approval from regulators to return these liabilities to customers in Colorado, Kansas, Louisiana, Texas and Virginia. This regulatory liability totaled $6.2 million and $22.5 million as of March 31, 2019 and September 30, 2018.

As of March 31, 2019, we received approval from regulators to return excess deferred taxes in Colorado, Kentucky, Louisiana, Mississippi, Tennessee, certain jurisdictions in Texas and Virginia in accordance with regulatory proceedings on a provisional basis over periods ranging from 13 to 51 years. In our remaining jurisdictions, the 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.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Atmos Energy Corporation

Results of Review of Interim Financial Statements

We have reviewed the accompanying condensed consolidated balance sheet of Atmos Energy Corporation as of March 31, 2019, the related condensed consolidated statements of comprehensive income for the three and six month periods ended March 31, 2019 and 2018, the condensed consolidated statements of cash flows for the six month periods ended March 31, 2019 and 2018 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 September 30, 2018, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

These financial statements are the responsibility of the Company's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the SEC and the PCAOB. We conducted our review in accordance with the standards of the PCAOB. A review of interim financial 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

May 7, 2019

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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 March 31, 2019 covered service areas located in eight states. In addition, we transport natural gas for others through our distribution and pipeline systems.

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

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

•	The pipeline and storage segment is comprised primarily of the pipeline and storage operations of our Atmos Pipeline-Texas division and our natural gas transmission operations in Louisiana.

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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 six months ended March 31, 2019.

Non-GAAP Financial Measures

Our operations are affected by the cost of natural gas, which is passed through to our customers without markup and includes commodity price, transportation, storage, injection and withdrawal fees and settlements of financial instruments used to mitigate commodity price risk. These costs are reflected in the condensed consolidated statements of comprehensive income 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 $3.8 million and $165.7 million for the three and six months ended March 31, 2018. 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 March 31
	2019				2018				Change
	(In thousands, except per share data)
Net income	$	214,888			$	178,992			$	35,896
TCJA non-cash income tax benefit	—				(3,791		)		3,791
Adjusted net income	$	214,888			$	175,201			$	39,687
Diluted net income per share	$	1.82			$	1.60			$	0.22
Diluted EPS from TCJA non-cash income tax benefit	—				(0.03		)		0.03
Adjusted diluted net income per share	$	1.82			$	1.57			$	0.25

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	Six Months Ended March 31
	2019				2018				Change
	(In thousands, except per share data)
Net income	$	372,534			$	493,124			$	(120,590	)
TCJA non-cash income tax benefit	—				(165,675		)		165,675
Adjusted net income	$	372,534			$	327,449			$	45,085
Diluted net income per share	$	3.21			$	4.47			$	(1.26	)
Diluted EPS from TCJA non-cash income tax benefit	—				(1.50		)		1.50
Adjusted diluted net income per share	$	3.21			$	2.97			$	0.24

RESULTS OF OPERATIONS

Executive Summary

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

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

After adjusting for the nonrecurring benefit recognized after implementing the TCJA in fiscal 2018, we recorded adjusted net income of $327.4 million, or $2.97 per diluted share for the six months ended March 31, 2018. The period-over-period increase in adjusted net income of $45.1 million, or 14 percent, largely reflects positive rate outcomes, customer growth in our distribution business, positive Contribution Margins in our pipeline and storage business due to wider spreads and positive supply and demand dynamics affecting the Permian Basin and the impact of the TCJA on our effective income tax rate. During the six months ended March 31, 2019, we implemented regulatory actions which resulted in an increase in annual operating income of $20.9 million and had thirteen ratemaking efforts in progress at March 31, 2019, seeking a total increase in annual operating income of $159.3 million.

Capital expenditures for the six months ended March 31, 2019 increased 12 percent period-over-period, to $777.6 million. Over 80 percent was invested to improve the safety and reliability of our distribution and transportation systems, with a significant portion of this investment incurred under regulatory mechanisms that reduce lag to six months or less. We expect our capital expenditures to range from $1.65 billion to $1.75 billion for fiscal 2019. We funded our capital expenditures program primarily through operating cash flows of $560.8 million. Additionally, we completed approximately $2 billion in external financing during the six months ended March 31, 2019 with the issuance of $1.1 billion in 30-year senior notes and approximately $908 million of common stock, of which proceeds of approximately $408 million were allocated to forward sale agreements. The net proceeds from these issuances, together with available cash, were used to repay at maturity our $450 million 8.50% unsecured senior notes, to repay short-term debt under our commercial paper program, to fund capital spending and for general corporate purposes.

As a result of our sustained financial performance, improved cash flows and capital structure, our Board of Directors increased the quarterly dividend by 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.

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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 have been approved by state regulatory commissions for approximately 97 percent of our residential and commercial meters in the following states for the following time periods:

Kansas, West Texas	October — May
Tennessee	October — April
Kentucky, Mississippi, Mid-Tex	November — April
Louisiana	December — March
Virginia	January — December

Our distribution operations are also affected by the cost of natural gas. 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 March 31, 2019 compared with Three Months Ended March 31, 2018

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

	Three Months Ended March 31
	2019				2018				Change
	(In thousands, unless otherwise noted)
Operating revenues	$	1,057,889			$	1,199,291			$	(141,402	)
Purchased gas cost	570,348				727,053				(156,705		)
Contribution Margin	487,541				472,238				15,303
Operating expenses	258,578				260,418				(1,840		)
Operating income	228,963				211,820				17,143
Other non-operating income (expense)	5,263				(1,521		)		6,784
Interest charges	15,896				16,898				(1,002		)
Income before income taxes	218,330				193,401				24,929
TCJA non-cash income tax benefit	—				(3,791		)		3,791
Income tax expense	46,137				51,949				(5,812		)
Net income	$	172,193			$	145,243			$	26,950
Consolidated distribution sales volumes — MMcf	139,242				134,046				5,196
Consolidated distribution transportation volumes — MMcf	46,190				45,932				258
Total consolidated distribution throughput — MMcf	185,432				179,978				5,454
Consolidated distribution average cost of gas per Mcf sold	$	4.10			$	5.42			$	(1.32	)

Income before income taxes for our distribution segment increased thirteen percent, primarily due to a $15.3 million increase in Contribution Margin as well as a $1.8 million decrease in operating expenses. The quarter-over-quarter increase in Contribution Margin primarily reflects:

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

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

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•	an $8.5 million decrease in residential and commercial net consumption, primarily due to inconsistent weather patterns experienced during the quarter compared to the prior-year quarter.

•	a $2.8 million decrease in revenue-related taxes primarily in our Mid-Tex Division.

The quarter-over-quarter decrease in operating expenses, which includes operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, primarily reflects a $23 million decrease in nonrecurring expenses related to the planned outage of our natural gas distribution system in Northwest Dallas in March 2018. These decreases were partially offset by higher system integrity and maintenance spending, higher employee costs and an increase in depreciation expense and property taxes of $8.8 million associated with increased capital investments.

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

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

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

	Three Months Ended March 31
	2019				2018				Change
	(In thousands)
Mid-Tex	$	93,131			$	78,190			$	14,941
Kentucky/Mid-States	35,022				36,529				(1,507		)
Louisiana	32,901				30,760				2,141
West Texas	20,921				21,430				(509		)
Mississippi	27,110				25,096				2,014
Colorado-Kansas	19,704				17,474				2,230
Other	174				2,341				(2,167		)
Total	$	228,963			$	211,820			$	17,143

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

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

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

Income before income taxes for our distribution segment increased six percent, primarily due to a $19.4 million increase in Contribution Margin, partially offset by a $6.1 million increase in operating expenses. The year-over-year increase in Contribution Margin primarily reflects:

•	a $16.7 million net increase in rate adjustments, after the effect of the TCJA, primarily in our Mid-Tex and Mississippi Divisions.

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

•	a $4.1 million decrease in revenue-related taxes primarily in our Mid-Tex Division.

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

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

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

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	Six Months Ended March 31
	2019				2018				Change
	(In thousands)
Mid-Tex	$	165,537			$	151,115			$	14,422
Kentucky/Mid-States	59,474				64,658				(5,184		)
Louisiana	55,054				54,028				1,026
West Texas	36,744				37,191				(447		)
Mississippi	46,698				43,371				3,327
Colorado-Kansas	33,493				30,405				3,088
Other	1,400				4,330				(2,930		)
Total	$	398,400			$	385,098			$	13,302

Recent Ratemaking Developments

The amounts described in the following sections represent the operating income that was requested or received in each rate filing, which may not necessarily reflect the stated amount referenced in the final order, as certain operating costs may have changed as a result of a commission’s or other governmental authority’s final ruling. During the first six months of fiscal 2019, we implemented eleven regulatory proceedings, resulting in a $20.9 million increase in annual operating income as summarized below. The ratemaking outcomes for rate case activity in fiscal 2019 include the effect of tax reform legislation enacted effective January 1, 2018 and do not reflect the true economic benefit of the outcomes because they do not include the corresponding income tax benefit we will receive due to the decrease in our statutory tax rate.

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

The following ratemaking efforts seeking $110.1 million in increased annual operating income were in progress as of March 31, 2019:

Division		Rate Action		Jurisdiction		Operating Income Requested
						(In thousands)
Colorado-Kansas		Infrastructure Mechanism		Kansas (1)		$	1,562
Louisiana		Formula Rate Mechanism		Trans La (2)		4,719
Louisiana		Formula Rate Mechanism		LGS		7,124
Mid-Tex		Rate Case		ATM Cities (3)		4,252
Mid-Tex		Formula Rate Mechanism		City of Dallas		9,452
Mid-Tex		Infrastructure Mechanism		Environs		2,435
Mid-Tex		Formula Rate Mechanism		Mid-Tex Cities		47,733
Mississippi		Infrastructure Mechanism		Mississippi		8,433
Kentucky/Mid-States		Formula Rate Mechanism		Tennessee (4)		3,230
Kentucky/Mid-States		Rate Case		Kentucky (5)		14,424
West Texas		Infrastructure Mechanism		Cities of Amarillo, Lubbock, Dalhart and Channing (6)		5,692
West Texas		Infrastructure Mechanism		Environs		1,006
						$	110,062

(1)	On April 23, 2019, the Kansas Corporation Commission approved this filing with rates to be implemented beginning May 1, 2019.

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

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

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

(5)	On May 7, 2019, the Kentucky Public Service Commission (KPSC) approved a final order that resulted in an increase in operating income of $3.5 million with rates to be effective May 8, 2019. Additionally, the KPSC reinstated the Pipeline Replacement Program (PRP) on a forward-looking basis, to be filed in August 2019 with rates to be effective in October 2019.

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

Annual Formula Rate Mechanisms

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

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

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

    

The following annual formula rate mechanisms, which reflect a 21% federal income tax rate resulting from the TCJA, were approved during the six months ended March 31, 2019:

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

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Rate Case Filings

A rate case is a formal request from Atmos Energy to a regulatory authority to increase rates that are charged to our customers. Rate cases may also be initiated when the regulatory authorities request us to justify our rates. This process is referred to as a “show cause” action. Adequate rates are intended to provide for recovery of the Company’s costs as well as a fair rate of return and ensure that we continue to deliver reliable, reasonably priced natural gas service safely to our customers. The following table summarizes the rate cases, which reflect a 21% federal income tax rate resulting from the TCJA, that were completed during the six months ended March 31, 2019.

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

Other Ratemaking Activity

The following table summarizes other ratemaking activity during the six months ended March 31, 2019.

Division		Jurisdiction		Rate Activity		Increase in Annual Operating Income				Effective Date
						(In thousands)
2019 Other Rate Activity:
Colorado-Kansas		Kansas		Ad Valorem (1)		$	214			02/01/2019
Total 2019 Other Rate Activity						$	214

(1)	The Ad Valorem filing relates to property taxes that are either over or undercollected compared to the amount included in our Kansas service area's base rates.

Pipeline and Storage Segment

Our pipeline and storage segment consists of the pipeline and storage operations of our Atmos Pipeline–Texas Division (APT) and our natural gas transmission operations in Louisiana. APT is one of the largest intrastate pipeline operations in Texas with a heavy concentration in the established natural gas producing areas of central, northern 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.

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APT annually uses GRIP to recover capital costs incurred in the prior calendar year. On February 15, 2019, APT made a GRIP filing that covered changes in net investment from January 1, 2018 through December 31, 2018 with a requested increase in operating income of $49.2 million. On May 7, 2019, the Texas Railroad Commission approved the Company's GRIP filing.

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

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

	Three Months Ended March 31
	2019				2018				Change
	(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue	$	94,291			$	89,631			$	4,660
Third-party transportation revenue	37,534				28,414				9,120
Other revenue	3,825				2,910				915
Total operating revenues	135,650				120,955				14,695
Total purchased gas cost	(90		)		433				(523		)
Contribution Margin	135,740				120,522				15,218
Operating expenses	67,026				61,440				5,586
Operating income	68,714				59,082				9,632
Other non-operating expense	(1,031		)		(646		)		(385		)
Interest charges	11,053				10,406				647
Income before income taxes	56,630				48,030				8,600
Income tax expense	13,935				14,281				(346		)
Net income	$	42,695			$	33,749			$	8,946
Gross pipeline transportation volumes — MMcf	254,833				237,167				17,666
Consolidated pipeline transportation volumes — MMcf	165,369				148,980				16,389

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

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

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

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

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

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

	Six Months Ended March 31
	2019				2018				Change
	(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue	$	182,723			$	183,529			$	(806	)
Third-party transportation revenue	80,822				57,345				23,477
Other revenue	6,575				6,544				31
Total operating revenues	270,120				247,418				22,702
Total purchased gas cost	(448		)		1,345				(1,793		)
Contribution Margin	270,568				246,073				24,495
Operating expenses	134,827				118,186				16,641
Operating income	135,741				127,887				7,854
Other non-operating expense	(2,277		)		(1,281		)		(996		)
Interest charges	20,692				20,547				145
Income before income taxes	112,772				106,059				6,713
TCJA non-cash income tax benefit	—				(21,733		)		21,733
Income tax expense	26,816				29,010				(2,194		)
Net income	$	85,956			$	98,782			$	(12,826	)
Gross pipeline transportation volumes — MMcf	493,688				450,304				43,384
Consolidated pipeline transportation volumes — MMcf	335,896				304,085				31,811

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

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

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

Operating expenses increased $16.6 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 in October 2018. At March 31, 2019, approximately $1.3 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

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

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

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

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

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

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

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

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

 

	March 31, 2019							September 30, 2018							March 31, 2018
	(In thousands, except percentages)
Short-term debt	$	—			—	%		$	575,780			6.8	%		$	129,602			1.6	%
Long-term debt(1)	3,653,713				39.9	%		3,068,665				36.5	%		3,067,892				38.8	%
Shareholders’ equity	5,508,101				60.1	%		4,769,951				56.7	%		4,721,346				59.6	%
Total	$	9,161,814			100.0	%		$	8,414,396			100.0	%		$	7,918,840			100.0	%

(1)	In September 2019, our $125 million term loan, which we plan to refinance, will mature.

Cash Flows

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

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	Six Months Ended March 31
	2019				2018				Change
	(In thousands)
Total cash provided by (used in)
Operating activities	$	560,829			$	751,367			$	(190,538	)
Investing activities	(768,421		)		(688,144		)		(80,277		)
Financing activities	302,174				(18,558		)		320,732
Change in cash and cash equivalents	94,582				44,665				49,917
Cash and cash equivalents at beginning of period	13,771				26,409				(12,638		)
Cash and cash equivalents at end of period	$	108,353			$	71,074			$	37,279

Cash flows from operating activities

For the six months ended March 31, 2019, we generated cash flow from operating activities of $560.8 million compared with $751.4 million for the six months ended March 31, 2018. The $190.5 million decrease in operating cash flows is primarily attributable to the change in net income and working capital changes, particularly in our distribution segment resulting from the timing of 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 a reasonable opportunity to earn a fair return on our investment without compromising safety or reliability.

For the six months ended March 31, 2019, cash used for investing activities was $768.4 million compared to $688.1 million for the six months ended March 31, 2018. Capital spending increased by $83.6 million, or 12 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 six months ended March 31, 2019, our financing activities provided $302.2 million of cash compared with $18.6 million of cash used for financing activities in the prior-year period.

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

In the six months ended March 31, 2018, we used $395.1 million in net proceeds from equity financing to reduce short-term debt, to support our capital spending and for other general corporate purposes.

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

	Six Months Ended   March 31
	2019			2018
Shares issued:
Direct Stock Purchase Plan	61,237			90,042
1998 Long-Term Incentive Plan	213,402			257,400
Retirement Savings Plan and Trust	43,745			49,848
Equity Issuance	5,390,836			4,558,404
Total shares issued	5,709,220			4,955,694

Credit Ratings

Our credit ratings directly affect our ability to obtain short-term and long-term financing, in addition to the cost of such financing. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including but not limited to, debt to total capitalization, operating cash flow relative to outstanding debt, operating cash flow coverage of interest and pension liabilities. In addition, the rating agencies consider qualitative factors such as consistency of our earnings over time, the quality of our management and business strategy, the risks associated with our businesses and the regulatory structures that govern our rates in the states where we operate.

Our debt is rated by two rating agencies: Standard & Poor’s Corporation (S&P) and Moody’s Investors Service (Moody’s). On December 14, 2018, Moody's affirmed our debt ratings and improved their outlook from stable to positive, citing improvements to our regulatory construct that reduces investment recovery lag and our balanced fiscal policy. As of March 31, 2019, S&P maintained a stable outlook. Our current debt ratings are all considered investment grade and are as follows:

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

A significant degradation in our operating performance or a significant reduction in our liquidity caused by more limited access to the private and public credit markets as a result of deteriorating global or national financial and credit conditions could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by the two credit rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings.

A credit rating is not a recommendation to buy, sell or hold securities. The highest investment grade credit rating is AAA for S&P and Aaa for Moody’s. The lowest investment grade credit rating is BBB- for S&P and Baa3 for Moody’s. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independently of any other rating. There can be no assurance that a rating will remain in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating agency if, in its judgment, circumstances so warrant.

Debt Covenants

We were in compliance with all of our debt covenants as of March 31, 2019. 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 six months ended March 31, 2019.

Risk Management Activities

In our distribution and pipeline and storage segments, we use a combination of physical storage, fixed physical contracts and fixed financial contracts to reduce our exposure to unusually large winter-period gas price increases. In the past we managed 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 and six months ended March 31, 2019 and 2018:

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

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

	Fair Value of Contracts at March 31, 2019
	Maturity in Years
Source of Fair Value	Less Than 1				1-3				4-5				Greater Than 5				Total Fair Value
	(In thousands)
Prices actively quoted	$	1,573			$	—			$	—			$	—			$	1,573
Prices based on models and other valuation methods	—				—				—				—				—
Total Fair Value	$	1,573			$	—			$	—			$	—			$	1,573

Pension and Postretirement Benefits Obligations

For the six months ended March 31, 2019 and 2018, our total net periodic pension and other postretirement benefits costs were $12.6 million and $20.9 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, 2019, we were not required to make a minimum contribution to our defined benefit plan during fiscal 2019. However, we may consider whether a voluntary contribution is prudent to maintain certain funding levels.

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

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OPERATING STATISTICS AND OTHER INFORMATION

The following tables present certain operating statistics for our distribution and pipeline and storage segments for the three and six month periods ended March 31, 2019 and 2018.

Distribution Sales and Statistical Data

	Three Months Ended   March 31								Six Months Ended   March 31
	2019				2018				2019				2018
METERS IN SERVICE, end of period
Residential	2,995,438				2,964,137				2,995,438				2,964,137
Commercial	273,533				270,795				273,533				270,795
Industrial	1,669				1,673				1,669				1,673
Public authority and other	8,365				8,407				8,365				8,407
Total meters	3,279,005				3,245,012				3,279,005				3,245,012
INVENTORY STORAGE BALANCE — Bcf	30.3				29.7				30.3				29.7
SALES VOLUMES — MMcf(1)
Gas sales volumes
Residential	84,757				80,525				144,621				129,473
Commercial	42,974				40,956				74,557				67,905
Industrial	8,727				9,708				16,901				18,166
Public authority and other	2,784				2,857				4,861				4,809
Total gas sales volumes	139,242				134,046				240,940				220,353
Transportation volumes	48,235				47,843				91,086				87,702
Total throughput	187,477				181,889				332,026				308,055
OPERATING REVENUES (000’s)(1)(2)
Gas sales revenues
Residential	$	681,367			$	805,134			$	1,221,806			$	1,361,654
Commercial	275,031				318,312				492,091				541,892
Industrial	35,979				39,604				70,451				73,017
Public authority and other	17,023				19,008				30,130				32,569
Total gas sales revenues	1,009,400				1,182,058				1,814,478				2,009,132
Transportation revenues	27,532				29,939				52,882				55,301
Other gas revenues(3)	20,957				(12,706		)		29,364				(4,350		)
Total operating revenues	$	1,057,889			$	1,199,291			$	1,896,724			$	2,060,083
Average cost of gas per Mcf sold	$	4.10			$	5.42			$	4.18			$	5.40

See footnote following these tables.

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Pipeline and Storage Operations Sales and Statistical Data

	Three Months Ended   March 31								Six Months Ended   March 31
	2019				2018				2019				2018
CUSTOMERS, end of period
Industrial	93				92				93				92
Other	230				231				230				231
Total	323				323				323				323
INVENTORY STORAGE BALANCE — Bcf	0.2				0.4				0.2				0.4
PIPELINE TRANSPORTATION VOLUMES — MMcf(1)	254,833				237,167				493,688				450,304
OPERATING REVENUES (000’s)(1)(2)	$	135,650			$	120,955			$	270,120			$	247,418

Note to preceding tables:

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

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

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

RECENT ACCOUNTING DEVELOPMENTS

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

 

Item 3.	Quantitative and Qualitative Disclosures About Market Risk

Information regarding our quantitative and qualitative disclosures about market risk are disclosed in Item 7A in our Annual Report on Form 10-K for the fiscal year ended September 30, 2018. During the six months ended March 31, 2019, there were no material changes in our quantitative and qualitative disclosures about market risk.

Item 4.	Controls and Procedures

Management’s Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the Company’s disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act). Based on this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2019 to provide reasonable assurance that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified by the SEC’s rules and forms, including a reasonable level of assurance that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

    

We did not make any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the second quarter of the fiscal year ended September 30, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1.	Legal Proceedings

During the six months ended March 31, 2019, except as noted in Note 9 to the unaudited condensed consolidated financial statements, there were no material changes in the status of the litigation and other matters that were disclosed in Note 11 to our Annual Report on Form 10-K for the fiscal year ended September 30, 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
3.1		Amended and Restated Bylaws of Atmos Energy Corporation (as of February 5, 2019)	Exhibit 3.1 to Form 8-K dated February 5, 2019 (File No. 1-10042)
4.1		Global Security for the 4.125% Senior Notes due 2049	Exhibit 4.2 to Form 8-K dated March 4, 2019 (File No 1-10042)
10		Equity Distribution Agreement, dated as of November 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.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

			ATMOS ENERGY CORPORATION                (Registrant)
			By: /s/    CHRISTOPHER T. FORSYTHE
			Christopher T. Forsythe Senior Vice President and Chief Financial Officer (Duly authorized signatory)

Date: May 7, 2019

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