UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)



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

For the quarterly period ended ~~December 31, 2017~~June 30, 2022



¨☐			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~~

and

Virginia

75-1743247

(State or other jurisdiction of

incorporation or organization)

(IRS employer

identification no.)

1800 Three Lincoln Centre ~~Suite 1800~~

5430 LBJ Freeway ~~Dallas, Texas~~

~~75240~~

~~(Zip code)~~

Dallas

Texas

75240

(Address of principal executive offices)

(Zip code)

(972) 934-9227

(Registrant’s telephone number, including area code)


Title of each class		Trading Symbol	Name of each exchange on which registered
Common stock	No Par Value	ATO	New York Stock Exchange

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. YesþNo¨

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its website, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files). YesþNo¨

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”,~~filer,” “smaller reporting ~~company”,~~company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer

Accelerated ~~Filer~~ þfiler

~~Accelerated Filer~~ ¨

Non-accelerated filer

~~Non-Accelerated Filer~~ ¨

Smaller reporting company

☐

~~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 ¨☐Noþ

Number of shares outstanding of each of the issuer’s classes of common stock, as of ~~February 1, 2018.~~

July 29, 2022.



Class		Shares Outstanding
Common stock	No Par Value	~~110,967,636~~139,891,918

GLOSSARY OF KEY TERMS




~~Adjusted diluted EPS from continuing operations~~		~~Non-GAAP measure defined as diluted earnings per share from continuing operations before the one-time, non-cash income tax benefit~~
~~Adjusted income from continuing operations~~AEC		~~Non-GAAP measure defined as income from continuing operations before the one-time, non-cash income tax benefit~~
~~AEC~~	Atmos Energy Corporation
~~AEH~~AOCI		~~Atmos Energy Holdings, Inc.~~
~~AEM~~	~~Atmos Energy Marketing, LLC~~
~~AOCI~~	Accumulated other comprehensive income
ARM		Annual Rate Mechanism
~~Bcf~~
ASC		Accounting Standards Codification
Bcf		Billion cubic feet
~~DARR~~
DARR		Dallas Annual Rate Review
~~ERISA~~		~~Employee Retirement Income Security Act of 1974~~
FASB		Financial Accounting Standards Board
~~GAAP~~
GAAP		Generally Accepted Accounting Principles
GRIP		Gas Reliability Infrastructure Program
~~Gross Profit~~GSRS		~~Non-GAAP measure defined as operating revenues less purchased gas cost~~
~~GSRS~~	Gas System Reliability Surcharge
~~Mcf~~LIBOR		London Interbank Offered Rate
Mcf		Thousand cubic feet
MMcf		Million cubic feet
Moody’s		Moody’s Investors Services, Inc.
~~PPA~~NTSB		~~Pension Protection Act of 2006~~National Transportation Safety Board
PRP		Pipeline Replacement Program
RRC		Railroad Commission of Texas
RRM		Rate Review Mechanism
RSC		Rate Stabilization Clause
S&P		Standard & Poor’s Corporation
SAVE		Steps to Advance Virginia Energy
SEC		United States Securities and Exchange Commission
~~SGR~~SIP		~~Supplemental Growth Filing~~System Integrity Program
SIR		System Integrity Rider
~~SRF~~SOFR		Secured Overnight Financing Rate
SRF		Stable Rate Filing
SSIR		System Safety and Integrity Rider
TCJA		Tax Cuts and Jobs Act of 2017
WNA		Weather Normalization Adjustment

PART I. FINANCIAL INFORMATION



Item 1.			Financial Statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


	December 31, 2017			September 30, 2017				June 30, 2022		September 30, 2021
	(Unaudited)							(Unaudited)
	(In thousands, except share data)							(In thousands, except share data)
ASSETS							ASSETS
Property, plant and equipment	$	11,609,627		$	11,301,304		Property, plant and equipment	$	19,502,000	$	17,885,098
Less accumulated depreciation and amortization	2,090,835			2,042,122			Less accumulated depreciation and amortization	2,945,397		2,821,128
Net property, plant and equipment	9,518,792			9,259,182			Net property, plant and equipment	16,556,603		15,063,970
Current assets							Current assets
Cash and cash equivalents	54,750			26,409			Cash and cash equivalents	328,075		116,723
Accounts receivable, net	489,217			222,263
Accounts receivable, net (See Note 5)							Accounts receivable, net (See Note 5)	375,257		342,967
Gas stored underground	163,959			184,653			Gas stored underground	223,993		178,116
Other current assets	70,984			106,321
Other current assets (See Note 8)							Other current assets (See Note 8)	2,354,526		2,200,909
Total current assets	778,910			539,646			Total current assets	3,281,851		2,838,715
Goodwill	730,132			730,132			Goodwill	731,257		731,257
Deferred charges and other assets	236,886			220,636
Deferred charges and other assets (See Note 8)							Deferred charges and other assets (See Note 8)	1,085,773		974,720
	$	11,264,720		$	10,749,596			$	21,655,484	$	19,608,662
CAPITALIZATION AND LIABILITIES							CAPITALIZATION AND LIABILITIES
Shareholders’ equity							Shareholders’ equity
Common stock, no par value (stated at $0.005 per share); 200,000,000 shares authorized; issued and outstanding: December 31, 2017 — 110,962,112 shares; September 30, 2017 — 106,104,634 shares	$	555		$	531
Common stock, no par value (stated at $0.005 per share); 200,000,000 shares authorized; issued and outstanding: June 30, 2022 — 139,888,756 shares; September 30, 2021 — 132,419,754 shares							Common stock, no par value (stated at $0.005 per share); 200,000,000 shares authorized; issued and outstanding: June 30, 2022 — 139,888,756 shares; September 30, 2021 — 132,419,754 shares	$	699	$	662
Additional paid-in capital	2,940,062			2,536,365			Additional paid-in capital	5,726,090		5,023,751
Accumulated other comprehensive loss	(106,316		)	(105,254		)
Accumulated other comprehensive income							Accumulated other comprehensive income	305,210		69,803
Retained earnings	1,729,319			1,467,024			Retained earnings	3,236,172		2,812,673
Shareholders’ equity	4,563,620			3,898,666			Shareholders’ equity	9,268,171		7,906,889
Long-term debt	3,067,469			3,067,045			Long-term debt	5,759,164		4,930,205
Total capitalization	7,631,089			6,965,711			Total capitalization	15,027,335		12,837,094
Current liabilities							Current liabilities
Accounts payable and accrued liabilities	285,675			233,050			Accounts payable and accrued liabilities	397,058		423,222
Other current liabilities	336,919			332,648			Other current liabilities	660,629		686,681
Short-term debt	336,816			447,745

Current maturities of long-term debt							Current maturities of long-term debt	2,201,430		2,400,452
Total current liabilities	959,410			1,013,443			Total current liabilities	3,259,117		3,510,355
Deferred income taxes	1,033,206			1,878,699			Deferred income taxes	1,936,658		1,705,809
Regulatory excess deferred taxes (See Note 6)	746,246			—
Regulatory excess deferred taxes							Regulatory excess deferred taxes	425,960		549,227
Regulatory cost of removal obligation	480,086			485,420			Regulatory cost of removal obligation	479,962		468,688
Pension and postretirement liabilities	233,337			230,588

Deferred credits and other liabilities	181,346			175,735			Deferred credits and other liabilities	526,452		537,489
	$	11,264,720		$	10,749,596			$	21,655,484	$	19,608,662

See accompanying notes to condensed consolidated financial statements.

~~ATMOS ENERGY CORPORATION~~

~~CONDENSED CONSOLIDATED STATEMENTS OF INCOME~~

Three Months Ended
December 31
2017 2016

(Unaudited)
(In thousands, except per
share data)
Operating revenues
Distribution segment $ 860,792
$ 754,656
Pipeline and storage segment 126,463
109,952
Intersegment eliminations (98,063 ) (84,440 )
Total operating revenues 889,192
780,168

Purchased gas cost
Distribution segment 463,758
395,346
Pipeline and storage segment 912
355
Intersegment eliminations (97,753 ) (84,396 )
Total purchased gas cost 366,917
311,305
Operation and maintenance expense 129,567
124,938
Depreciation and amortization expense 88,374
76,958
Taxes, other than income 62,773
57,049
Operating income 241,561
209,918
Miscellaneous expense, net (2,035 ) (994 )
Interest charges 31,509
31,030
Income from continuing operations before income taxes 208,017
177,894
Income tax (benefit) expense (106,115 ) 63,856
Income from continuing operations 314,132
114,038
Income from discontinued operations, net of tax ($0 and $6,841) —
10,994
Net income $ 314,132
$ 125,032
Basic and diluted net income per share
Income per share from continuing operations $ 2.89
$ 1.08
Income per share from discontinued operations —
0.11
Net income per share - basic and diluted $ 2.89
$ 1.19
Cash dividends per share $ 0.485
$ 0.450
Basic and diluted weighted average shares outstanding 108,564
105,284

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

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


								Three Months Ended June 30
	Three Months Ended December 31							2022		2021
	2017			2016				(Unaudited) (In thousands, except per share data)
Operating revenues							Operating revenues
Distribution segment							Distribution segment	$	773,311	$	558,750
Pipeline and storage segment							Pipeline and storage segment	183,412		162,987
Intersegment eliminations							Intersegment eliminations	(140,294)		(116,184)
Total operating revenues							Total operating revenues	816,429		605,553

Purchased gas cost							Purchased gas cost
Distribution segment							Distribution segment	390,559		202,050
Pipeline and storage segment							Pipeline and storage segment	(1,347)		691
Intersegment eliminations							Intersegment eliminations	(140,053)		(115,871)
Total purchased gas cost							Total purchased gas cost	249,159		86,870

Operation and maintenance expense							Operation and maintenance expense	182,325		184,470
Depreciation and amortization expense							Depreciation and amortization expense	134,231		119,348
Taxes, other than income							Taxes, other than income	96,127		81,475
Operating income							Operating income	154,587		133,390
Other non-operating income							Other non-operating income	13,263		5,887
Interest charges							Interest charges	26,190		20,962
Income before income taxes							Income before income taxes	141,660		118,315
Income tax expense							Income tax expense	13,113		15,904

Net income							Net income	$	128,547	$	102,411
Basic net income per share							Basic net income per share	$	0.92	$	0.78
Diluted net income per share							Diluted net income per share	$	0.92	$	0.78
Cash dividends per share							Cash dividends per share	$	0.680	$	0.625
Basic weighted average shares outstanding							Basic weighted average shares outstanding	139,881		131,358
Diluted weighted average shares outstanding							Diluted weighted average shares outstanding	140,227		131,486
	(Unaudited) (In thousands)
Net income	$	314,132		$	125,032		Net income	$	128,547	$	102,411
Other comprehensive income (loss), net of tax							Other comprehensive income (loss), net of tax
Net unrealized holding losses on available-for-sale securities, net of tax of $62 and $476	(107		)	(828		)
Net unrealized holding losses on available-for-sale securities, net of tax of $31 and $11							Net unrealized holding losses on available-for-sale securities, net of tax of $31 and $11	(106)		(36)
Cash flow hedges:							Cash flow hedges:
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $(549) and $52,429	(955		)	91,214
Net unrealized gains on commodity cash flow hedges, net of tax of $0 and $3,183	—			4,982
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $46,168 and $(22,890)							Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $46,168 and $(22,890)	159,737		(79,196)
Total other comprehensive income (loss)	(1,062		)	95,368			Total other comprehensive income (loss)	159,631		(79,232)
Total comprehensive income	$	313,070		$	220,400		Total comprehensive income	$	288,178	$	23,179

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Nine Months Ended June 30
	2022		2021
	(Unaudited) (In thousands, except per share data)
Operating revenues
Distribution segment	$	3,356,279	$	2,718,074
Pipeline and storage segment	510,077		476,868
Intersegment eliminations	(387,322)		(355,836)
Total operating revenues	3,479,034		2,839,106

Purchased gas cost
Distribution segment	1,881,212		1,304,269
Pipeline and storage segment	(3,075)		(440)
Intersegment eliminations	(386,437)		(354,890)
Total purchased gas cost	1,491,700		948,939

Operation and maintenance expense	504,787		479,488
Depreciation and amortization expense	395,461		353,269
Taxes, other than income	271,506		243,376
Operating income	815,580		814,034
Other non-operating income	27,178		14,793
Interest charges	74,969		69,068
Income before income taxes	767,789		759,759
Income tax expense	65,034		142,916



Net income	$	702,755	$	616,843
Basic net income per share	$	5.13	$	4.77
Diluted net income per share	$	5.12	$	4.77
Cash dividends per share	$	2.04	$	1.875
Basic weighted average shares outstanding	136,799		129,185
Diluted weighted average shares outstanding	137,055		129,229

Net income	$	702,755	$	616,843
Other comprehensive income (loss), net of tax
Net unrealized holding losses on available-for-sale securities, net of tax of $98 and $48	(336)		(165)
Cash flow hedges:
Amortization and unrealized gain on interest rate agreements, net of tax of $68,136 and $34,392	235,743		118,993
Total other comprehensive income	235,407		118,828
Total comprehensive income	$	938,162	$	735,671

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended June 30
	2022		2021
	(Unaudited) (In thousands)
Cash Flows From Operating Activities
Net income	$	702,755	$	616,843
Adjustments to reconcile net income to net cash provided by (used in) operating activities:

Depreciation and amortization expense	395,461		353,269

Deferred income taxes	40,899		144,195



Other	(15,941)		378
Net assets / liabilities from risk management activities	(7,167)		(99)
Net change in Winter Storm Uri long-term regulatory asset (See Note 8)	—		(2,088,536)
Net change in other operating assets and liabilities	(186,691)		(184,517)
Net cash provided by (used in) operating activities	929,316		(1,158,467)
Cash Flows From Investing Activities
Capital expenditures	(1,726,039)		(1,357,960)


Debt and equity securities activities, net	3,594		(2,363)

Other, net	7,876		8,006
Net cash used in investing activities	(1,714,569)		(1,352,317)
Cash Flows From Financing Activities

Net proceeds from equity issuances	675,320		460,678
Issuance of common stock through stock purchase and employee retirement plans	11,670		12,121
Proceeds from issuance of long-term debt	798,802		2,797,346


Repayment of long-term debt	(200,000)		—
Cash dividends paid	(279,256)		(241,260)
Debt issuance costs	(8,196)		(14,288)
Other	(1,735)		—

Net cash provided by financing activities	996,605		3,014,597
Net increase in cash and cash equivalents	211,352		503,813
Cash and cash equivalents at beginning of period	116,723		20,808
Cash and cash equivalents at end of period	$	328,075	$	524,621

Three Months Ended
December 31
2017 2016

(Unaudited)
(In thousands)
Cash Flows From Operating Activities
Net income $ 314,132
$ 125,032
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense 88,374
77,143
Deferred income taxes 53,149
67,241
One-time income tax benefit (161,884 ) —
Discontinued cash flow hedging for natural gas marketing commodity contracts —
(10,579 )
Other 6,915
4,842
Net assets / liabilities from risk management activities 2,030
3,969
Net change in operating assets and liabilities (129,478 ) (150,685 )
Net cash provided by operating activities 173,238
116,963
Cash Flows From Investing Activities
Capital expenditures (383,238 ) (297,962 )
Acquisition —
(85,714 )
Available-for-sale securities activities, net (135 ) (10,263 )
Other, net 2,001
1,802
Net cash used in investing activities (381,372 ) (392,137 )
Cash Flows From Financing Activities
Net (decrease) increase in short-term debt (110,929 ) 110,936
Net proceeds from equity offering 395,099
49,400
Issuance of common stock through stock purchase and employee retirement plans 5,660
8,998
Proceeds from issuance of long-term debt —
125,000
Interest rate agreements cash collateral —
25,670
Cash dividends paid (51,837 ) (47,740 )
Other (1,518 ) —
Net cash provided by financing activities 236,475
272,264
Net increase (decrease) in cash and cash equivalents 28,341
(2,910 )
Cash and cash equivalents at beginning of period 26,409
47,534
Cash and cash equivalents at end of period $ 54,750
$ 44,624

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

~~December 31, 2017~~June 30, 2022

1. Nature of Business

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

Our distribution business delivers natural gas through sales and transportation arrangements to over ~~three~~3 million residential, commercial, public authority and industrial customers through our ~~six~~6 regulated distribution divisions, which at ~~December 31, 2017,~~June 30, 2022, covered service areas located in ~~eight~~8 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 as those used for the Company’s audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017.~~2021. In the opinion of management, all material adjustments (consisting of normal recurring accruals) necessary for a fair presentation have been made to the unaudited consolidated interim-period financial statements. These consolidated interim-period financial statements are condensed as permitted by the instructions to Form 10-Q and should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation included in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017.~~2021. Because of seasonal and other factors, the results of operations for the ~~three-month~~nine-month period ended ~~December 31, 2017~~June 30, 2022 are not indicative of our results of operations for the full ~~2018~~2022 fiscal year, which ends September 30, ~~2018.~~2022.

~~Except for the actions of our regulators regarding tax reform as discussed in Note 6 and the receipt of funds held in escrow related to the prior year sale of AEM, no~~No events have occurred subsequent to the balance sheet date that would require recognition or disclosure in the unaudited condensed consolidated financial statements.

Significant accounting policies

Our accounting policies are described in Note 2 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017.~~2021.

During the second quarter of fiscal 2022, we completed our annual goodwill impairment assessment using a qualitative assessment, as permitted under U.S. GAAP. We test for goodwill 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.

Recently issued accounting pronouncements

In ~~May 2014,~~November 2021, the Financial Accounting Standards Board (FASB) issued ~~a comprehensive new revenue recognition standard that~~guidance which will ~~supersede virtually all existing revenue recognition guidance under generally accepted accounting principles~~require disclosure about government assistance in the ~~United States. Under~~notes to the ~~new standard, an entity will recognize revenue when it transfers promised goods~~financial statements. The amendment requires annual disclosures about transactions with a government that are accounted for by applying a grant or ~~services~~contribution accounting model by analogy, including information about the nature of the transactions and the related accounting policy used to ~~customers in an amount~~account for the transactions, the line items on the balance sheet and income statement that ~~reflects~~are affected by the ~~consideration to which~~transactions and the ~~company expects to be entitled in exchange for those goods or services. In doing so, companies may need to use more judgment~~significant terms and ~~make more estimates than under current guidance.~~conditions of the transactions, including commitments and contingencies. The ~~new guidance will become~~amendment is effective for us beginning October 1, ~~2018 and can~~2022; however, we elected to adopt this amendment during the first quarter of fiscal 2022 as permitted by the guidance. As the guidance is related only to disclosures in the notes to the financial statements, there will be ~~applied either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption.~~

~~As of December 31, 2017, we had substantially completed the evaluation of our sources of revenue and the~~no impact ~~that the new guidance will have~~ on our financial position, results of operations or cash flows and business processes. Based on this evaluation, we currently do not believe the implementation of the new guidance will have a material effect on our financial position, results of operations, cash flows or business processes. We expect to apply the new guidance using the modified retrospective method on the date of adoption. We are currently still evaluating the impact on our financial statement presentation and related disclosures.flows.

In ~~January 2016,~~March 2020, the FASB issued optional guidance ~~related to~~which will ease the ~~classification and measurement~~potential burden in accounting for or recognizing the effects of reference rate reform on financial ~~instruments.~~reporting. The amendments ~~modify~~provide optional expedients and exceptions for applying U.S. GAAP to contracts, hedging relationships and other transactions affected by the ~~accounting and presentation for certain financial liabilities and equity investments not consolidated or reported using~~cessation of the ~~equity method.~~London Interbank Offered Rate (LIBOR). The ~~guidance is effective for us beginning October 1, 2018; limited early adoption is permitted.~~amendments can be elected immediately, as of March 12, 2020, through December 31, 2022. We are currently evaluating if we will apply the optional guidance as we assess the impact of the cessation of LIBOR on our current contracts and hedging relationships and the potential impact ~~of this new guidance~~ on our financial position, results of operations and cash flows.

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

earliest comparative period presented in the year of adoption. Additionally, in January 2018, the FASB issued amendments to the standard that provides a practical expedient for entities to not evaluate existing or expired land easements that were not previously accounted for as leases under the current guidance. We are currently evaluating the effect of this standard and amendments on our financial position, results of operations and cash flows.

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

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

In March 2017, the FASB issued new guidance related to the income statement presentation of the components of net periodic benefit cost for an entity’s sponsored defined benefit pension and other postretirement plans. The new guidance requires entities to disaggregate the current service cost component of the net benefit cost from the other components and present it with other current compensation costs for related employees in the statement of income. The other components of net benefit cost will be presented outside of income from operations on the statement of income. In addition, only the service cost component of net benefit cost is eligible for capitalization (e.g., as part of inventory or property, plant, and equipment). However, we believe that we will be allowed to defer the other components of net periodic benefit cost as a regulatory asset and that we will still be allowed to capitalize all components of net periodic benefit cost for ratemaking purposes. The new guidance will be effective for us in the fiscal year beginning on October 1, 2018 and for interim periods within that year. We are currently evaluating the potential impact of this new guidance on our financial position, results of operations and cash flows.

Regulatory assets and liabilities

Accounting principles generally accepted in the United States require cost-based, rate-regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are permitted to be capitalized rather than expensed because they can be recovered through rates. We record certain costs as regulatory assets when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Substantially all of our regulatory assets are recorded as a component of other current assets and deferred charges and other assets and ~~a portion of~~ our regulatory liabilities are recorded as a component of other current liabilities and deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or ~~liabilities and our regulatory excess deferred taxes and regulatory cost of removal obligation is reported separately.~~

liabilities.

Significant regulatory assets and liabilities as of ~~December 31, 2017~~June 30, 2022 and September 30, ~~2017~~2021 included the following:


	December 31, 2017		September 30, 2017			June 30, 2022		September 30, 2021
	(In thousands)					(In thousands)
Regulatory assets:					Regulatory assets:
Pension and postretirement benefit costs⁽¹⁾	$	24,598	$	26,826
Infrastructure mechanisms⁽²⁾	54,571		46,437
Pension and postretirement benefit costs					Pension and postretirement benefit costs	$	34,482	$	45,922
Infrastructure mechanisms (1)					Infrastructure mechanisms (1)	225,279		222,795
Winter Storm Uri incremental costs (2)					Winter Storm Uri incremental costs (2)	2,107,820		2,100,728
Deferred gas costs	18,505		65,714		Deferred gas costs	42,818		66,395
Regulatory excess deferred taxes					Regulatory excess deferred taxes	48,746		45,370
Recoverable loss on reacquired debt	10,580		11,208		Recoverable loss on reacquired debt	3,448		3,789
Deferred pipeline record collection costs	12,942		11,692		Deferred pipeline record collection costs	35,212		32,099
APT annual adjustment mechanism	—		2,160
Rate case costs	3,160		2,629

Other	9,703		10,132		Other	15,552		4,343
	$	134,059	$	176,798		$	2,513,357	$	2,521,441
Regulatory liabilities:					Regulatory liabilities:
Regulatory excess deferred taxes⁽³⁾	$	746,246	$	—
Regulatory excess deferred taxes					Regulatory excess deferred taxes	$	586,149	$	705,084

Regulatory cost of removal obligation	520,483		521,330		Regulatory cost of removal obligation	558,542		541,511
Deferred gas costs	19,739		15,559		Deferred gas costs	45,874		52,553
Asset retirement obligation	12,827		12,827		Asset retirement obligation	18,373		18,373
APT annual adjustment mechanism	1,720		—		APT annual adjustment mechanism	26,689		31,110
Pension and postretirement benefit costs					Pension and postretirement benefit costs	51,954		56,201
Other	7,673		5,941		Other	23,223		19,363
	$	1,308,688	$	555,657		$	1,310,804	$	1,424,195


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


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


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

(1)Infrastructure mechanisms in Texas, Louisiana and Tennessee 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)Includes extraordinary gas costs subject to securitization incurred during Winter Storm Uri and permissible carrying costs. See Note 8 to the unaudited condensed consolidated financial statements for further information. This amount is recorded within other current assets and deferred charges and other assets on the condensed consolidated balance sheet as of June 30, 2022.

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~~8 states.

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

~~The~~ ~~natural gas marketing segment~~ ~~was comprised of our discontinued natural gas marketing business.~~

Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. Although our distribution segment operations are geographically dispersed, they are aggregated and reported as a single segment as each natural gas distribution division has similar economic characteristics. In addition, because the pipeline and storage operations of our Atmos Pipeline-Texas division and our natural gas transmission operations in Louisiana have similar economic characteristics, they have been aggregated and reported as a single segment.

The accounting policies of the segments are the same as those described in the summary of significant accounting policies found in our Annual Report on Form 10-K for the fiscal year ended September 30, 2017. We evaluate performance based on net income or loss of the respective operating units. We allocate interest and pension expense to the pipeline and storage segment; however, there is no debt or pension liability recorded on the pipeline and storage segment balance sheet. All material intercompany transactions have been eliminated; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process. Income taxes are allocated to each segment as if each segment’s taxes were calculated on a separate return basis.2021.

Income statements and capital expenditures for the three and nine months ended ~~December 31, 2017~~June 30, 2022 and ~~2016~~2021 by segment are presented in the following tables:


	Three Months Ended June 30, 2022
	Distribution		Pipeline and Storage		Eliminations		Consolidated
	(In thousands)
Operating revenues from external parties	$	772,497	$	43,932	$	—	$	816,429
Intersegment revenues	814		139,480		(140,294)		—
Total operating revenues	773,311		183,412		(140,294)		816,429
Purchased gas cost	390,559		(1,347)		(140,053)		249,159
Operation and maintenance expense	133,654		48,912		(241)		182,325
Depreciation and amortization expense	97,106		37,125		—		134,231
Taxes, other than income	85,933		10,194		—		96,127
Operating income	66,059		88,528		—		154,587
Other non-operating income	6,708		6,555		—		13,263
Interest charges	12,341		13,849		—		26,190
Income before income taxes	60,426		81,234		—		141,660
Income tax expense	3,025		10,088		—		13,113
Net income	$	57,401	$	71,146	$	—	$	128,547
Capital expenditures	$	417,244	$	118,766	$	—	$	536,010


	Three Months Ended June 30, 2021
	Distribution		Pipeline and Storage		Eliminations		Consolidated
	(In thousands)
Operating revenues from external parties	$	557,931	$	47,622	$	—	$	605,553
Intersegment revenues	819		115,365		(116,184)		—
Total operating revenues	558,750		162,987		(116,184)		605,553
Purchased gas cost	202,050		691		(115,871)		86,870
Operation and maintenance expense	130,454		54,329		(313)		184,470
Depreciation and amortization expense	86,099		33,249		—		119,348
Taxes, other than income	72,024		9,451		—		81,475
Operating income	68,123		65,267		—		133,390
Other non-operating income	1,060		4,827		—		5,887
Interest charges	8,540		12,422		—		20,962
Income before income taxes	60,643		57,672		—		118,315
Income tax expense	7,354		8,550		—		15,904
Net income	$	53,289	$	49,122	$	—	$	102,411
Capital expenditures	$	398,416	$	113,816	$	—	$	512,232


	Three Months Ended December 31, 2017													Nine Months Ended June 30, 2022
	Distribution			Pipeline and Storage			Eliminations			Consolidated				Distribution		Pipeline and Storage		Eliminations		Consolidated
	(In thousands)													(In thousands)
Operating revenues from external parties	$	860,453		$	28,739		$	—		$	889,192		Operating revenues from external parties	$	3,353,800	$	125,234	$	—	$	3,479,034
Intersegment revenues	339			97,724			(98,063		)	—			Intersegment revenues	2,479		384,843		(387,322)		—
Total operating revenues	860,792			126,463			(98,063		)	889,192			Total operating revenues	3,356,279		510,077		(387,322)		3,479,034
Purchased gas cost	463,758			912			(97,753		)	366,917			Purchased gas cost	1,881,212		(3,075)		(386,437)		1,491,700
Operation and maintenance expense	103,737			26,140			(310		)	129,567			Operation and maintenance expense	378,479		127,193		(885)		504,787
Depreciation and amortization expense	65,434			22,940			—			88,374			Depreciation and amortization expense	286,515		108,946		—		395,461
Taxes, other than income	55,107			7,666			—			62,773			Taxes, other than income	242,214		29,292		—		271,506
Operating income	172,756			68,805			—			241,561			Operating income	567,859		247,721		—		815,580
Miscellaneous expense	(1,400		)	(635		)	—			(2,035		)
Other non-operating income													Other non-operating income	9,173		18,005		—		27,178
Interest charges	21,368			10,141			—			31,509			Interest charges	36,046		38,923		—		74,969
Income before income taxes	149,988			58,029			—			208,017			Income before income taxes	540,986		226,803		—		767,789
Income tax benefit	(99,111		)	(7,004		)	—			(106,115		)
Income tax expense													Income tax expense	35,163		29,871		—		65,034
Net income	$	249,099		$	65,033		$	—		$	314,132		Net income	$	505,823	$	196,932	$	—	$	702,755
Capital expenditures	$	241,249		$	141,989		$	—		$	383,238		Capital expenditures	$	1,217,094	$	508,945	$	—	$	1,726,039

Three Months Ended December 31, 2016
Distribution Pipeline and Storage Natural Gas Marketing Eliminations Consolidated
(In thousands)
Operating revenues from external parties $ 754,266
$ 25,902
$ —
$ —
$ 780,168
Intersegment revenues 390
84,050
—
(84,440 ) —
Total operating revenues 754,656
109,952
—
(84,440 ) 780,168
Purchased gas cost 395,346
355
—
(84,396 ) 311,305
Operation and maintenance expense 92,714
32,268
—
(44 ) 124,938
Depreciation and amortization expense 61,157
15,801
—
—
76,958
Taxes, other than income 50,546
6,503
—
—
57,049
Operating income 154,893
55,025
—
—
209,918
Miscellaneous expense (633 ) (361 ) —
—
(994 )
Interest charges 21,118
9,912
—
—
31,030
Income from continuing operations before income taxes 133,142
44,752
—
—
177,894
Income tax expense 47,778
16,078
—
—
63,856
Income from continuing operations 85,364
28,674
—
—
114,038
Income from discontinued operations, net of tax —
—
10,994
—
10,994
Net income $ 85,364
$ 28,674
$ 10,994
$ —
$ 125,032
Capital expenditures $ 222,484
$ 75,478
$ —
$ —
$ 297,962



	Nine Months Ended June 30, 2021
	Distribution		Pipeline and Storage		Eliminations		Consolidated
	(In thousands)
Operating revenues from external parties	$	2,715,644	$	123,462	$	—	$	2,839,106
Intersegment revenues	2,430		353,406		(355,836)		—
Total operating revenues	2,718,074		476,868		(355,836)		2,839,106
Purchased gas cost	1,304,269		(440)		(354,890)		948,939
Operation and maintenance expense	363,246		117,188		(946)		479,488
Depreciation and amortization expense	254,636		98,633		—		353,269
Taxes, other than income	214,991		28,385		—		243,376
Operating income	580,932		233,102		—		814,034
Other non-operating income	1,135		13,658		—		14,793
Interest charges	33,269		35,799		—		69,068
Income before income taxes	548,798		210,961		—		759,759
Income tax expense	109,481		33,435		—		142,916
Net income	$	439,317	$	177,526	$	—	$	616,843
Capital expenditures	$	1,000,616	$	357,344	$	—	$	1,357,960

Balance sheet information at ~~December 31, 2017~~June 30, 2022 and September 30, ~~2017~~2021 by segment is presented in the following tables:


	June 30, 2022
	Distribution		Pipeline and Storage		Eliminations		Consolidated
	(In thousands)
Property, plant and equipment, net	$	12,314,182	$	4,242,421	$	—	$	16,556,603
Total assets	$	20,891,285	$	4,497,125	$	(3,732,926)	$	21,655,484


	December 31, 2017										September 30, 2021
	Distribution		Pipeline and Storage		Eliminations			Consolidated			Distribution		Pipeline and Storage		Eliminations		Consolidated
	(In thousands)										(In thousands)
Property, plant and equipment, net	$	7,010,709	$	2,508,083	$	—		$	9,518,792	Property, plant and equipment, net	$	11,232,649	$	3,831,321	$	—	$	15,063,970
Total assets	$	10,633,234	$	2,729,455	$	(2,097,969	)	$	11,264,720	Total assets	$	18,847,266	$	4,076,844	$	(3,315,448)	$	19,608,662

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

4. Earnings Per Share

We use the two-class method of computing earnings per share because we have participating securities in the form of non-vested restricted stock units with a nonforfeitable right to dividend equivalents, for which vesting is predicated solely on the passage of time. The calculation of earnings per share using the two-class method excludes income attributable to these participating securities from the numerator and excludes the dilutive impact of those shares from the denominator. Basic 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 to the unaudited condensed consolidated financial statements, when the impact is dilutive. Basic and diluted earnings per share for the three and nine months ended ~~December 31, 2017~~June 30, 2022 and ~~2016~~2021 are calculated as follows:


	Three Months Ended June 30				Nine Months Ended June 30
	2022		2021		2022		2021
	(In thousands, except per share amounts)
Basic Earnings Per Share
Net income	$	128,547	$	102,411	$	702,755	$	616,843
Less: Income allocated to participating securities	79		70		465		440
Income available to common shareholders	$	128,468	$	102,341	$	702,290	$	616,403
Basic weighted average shares outstanding	139,881		131,358		136,799		129,185
Net income per share — Basic	$	0.92	$	0.78	$	5.13	$	4.77
Diluted Earnings Per Share
Income available to common shareholders	$	128,468	$	102,341	$	702,290	$	616,403
Effect of dilutive shares	—		—		—		—
Income available to common shareholders	$	128,468	$	102,341	$	702,290	$	616,403
Basic weighted average shares outstanding	139,881		131,358		136,799		129,185
Dilutive shares	346		128		256		44
Diluted weighted average shares outstanding	140,227		131,486		137,055		129,229
Net income per share - Diluted	$	0.92	$	0.78	$	5.12	$	4.77

5. Revenue and Accounts Receivable

Revenue

Our revenue recognition policy is fully described in Note 2 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2021. The following tables disaggregate our revenue from contracts with customers by customer type and segment and provide a reconciliation to total operating revenues, including intersegment revenues, for the three and nine months ended June 30, 2022 and 2021.

Three Months Ended
December 31
2017 2016
(In thousands, except per share amounts)
Basic and Diluted Earnings Per Share from continuing operations
Income from continuing operations $ 314,132
$ 114,038
Less: Income from continuing operations allocated to participating securities 328
153
Income from continuing operations available to common shareholders $ 313,804
$ 113,885
Basic and diluted weighted average shares outstanding 108,564
105,284
Income from continuing operations per share — Basic and Diluted $ 2.89
$ 1.08

Basic and Diluted Earnings Per Share from discontinued operations
Income from discontinued operations $ —
$ 10,994
Less: Income from discontinued operations allocated to participating securities —
14
Income from discontinued operations available to common shareholders $ —
$ 10,980
Basic and diluted weighted average shares outstanding 108,564
105,284
Income from discontinued operations per share — Basic and Diluted $ —
$ 0.11
Net income per share — Basic and Diluted $ 2.89
$ 1.19


	Three Months Ended June 30, 2022				Three Months Ended June 30, 2021
	Distribution		Pipeline and Storage		Distribution		Pipeline and Storage
	(In thousands)
Gas sales revenues:
Residential	$	441,806	$	—	$	336,016	$	—
Commercial	231,309		—		157,314		—
Industrial	57,045		—		25,348		—
Public authority and other	13,080		—		8,870		—
Total gas sales revenues	743,240		—		527,548		—
Transportation revenues	27,216		186,405		25,903		164,619
Miscellaneous revenues	2,453		3,104		2,615		3,895
Revenues from contracts with customers	772,909		189,509		556,066		168,514
Alternative revenue program revenues (1)	(77)		(6,097)		2,206		(5,527)
Other revenues	479		—		478		—
Total operating revenues	$	773,311	$	183,412	$	558,750	$	162,987



	Nine Months Ended June 30, 2022				Nine Months Ended June 30, 2021
	Distribution		Pipeline and Storage		Distribution		Pipeline and Storage
	(In thousands)
Gas sales revenues:
Residential	$	2,108,349	$	—	$	1,821,570	$	—
Commercial	910,400		—		692,443		—
Industrial	160,098		—		81,122		—
Public authority and other	54,668		—		42,159		—
Total gas sales revenues	3,233,515		—		2,637,294		—
Transportation revenues	87,886		514,114		84,643		480,945
Miscellaneous revenues	7,732		11,931		8,336		12,921
Revenues from contracts with customers	3,329,133		526,045		2,730,273		493,866
Alternative revenue program revenues (1)	25,663		(15,968)		(13,666)		(16,998)
Other revenues	1,483		—		1,467		—
Total operating revenues	$	3,356,279	$	510,077	$	2,718,074	$	476,868

(1) In our distribution segment, we have weather-normalization adjustment mechanisms that serve to mitigate the effects of weather on our revenue. 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 regulatorily determined revenue benchmark.

Accounts receivable and allowance for uncollectible accounts

Accounts receivable arise from natural gas sales to residential, commercial, industrial, public authority and other customers. Our accounts receivable balance includes unbilled amounts which represent a customer’s consumption of gas from the date of the last cycle billing through the last day of the month. The receivable balances are short term and generally do not extend beyond one month. To minimize credit risk, we assess the credit worthiness of new customers, require deposits where necessary, assess late fees, pursue collection activities and disconnect service for nonpayment. After disconnection, accounts are written off when deemed uncollectible.

Our policy related to the accounting for our allowance for uncollectible accounts is fully described in Note 2 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2021. During the nine months ended June 30, 2022, there were no material changes to this policy. Rollforwards of our allowance for uncollectible accounts for the three and nine months ended June 30, 2022 and 2021 are presented in the table below. The allowance excludes the gas cost portion of customers’ bills for approximately 79 percent of our customers as we have the ability to collect these gas costs through our gas cost recovery mechanisms in most of our jurisdictions.


	Three Months Ended June 30, 2022
	(In thousands)
Beginning balance, March 31, 2022	$	62,213
Current period provisions	5,657
Write-offs charged against allowance	(7,430)
Recoveries of amounts previously written off	328
Ending balance, June 30, 2022	$	60,768


	Three Months Ended June 30, 2021
	(In thousands)
Beginning balance, March 31, 2021	$	44,680
Current period provisions	14,403
Write-offs charged against allowance	(2,875)
Recoveries of amounts previously written off	437
Ending balance, June 30, 2021	$	56,645


	Nine Months Ended June 30, 2022
	(In thousands)
Beginning balance, September 30, 2021	$	64,471
Current period provisions	17,733
Write-offs charged against allowance	(22,888)
Recoveries of amounts previously written off	1,452
Ending balance, June 30, 2022	$	60,768


	Nine Months Ended June 30, 2021
	(In thousands)
Beginning balance, September 30, 2020	$	29,949
Current period provisions	32,872
Write-offs charged against allowance	(7,544)
Recoveries of amounts previously written off	1,368
Ending balance, June 30, 2021	$	56,645

6. Debt

The nature and terms of our debt instruments and credit facilities are described in detail in Note 57 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017. There~~2021. Other than as described below, there were no material changes in the terms of our debt instruments during the ~~three~~nine months ended ~~December 31, 2017.~~June 30, 2022.

Long-term debt at ~~December 31, 2017~~June 30, 2022 and September 30, ~~2017~~2021 consisted of the following:


	June 30, 2022		September 30, 2021
	(In thousands)
Unsecured 0.625% Senior Notes, due March 2023	$	1,100,000	$	1,100,000
Unsecured 3.00% Senior Notes, due 2027	500,000		500,000
Unsecured 2.625% Senior Notes, due 2029	500,000		300,000
Unsecured 1.50% Senior Notes, due 2031	600,000		600,000
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		600,000
Unsecured 4.125% Senior Notes, due 2049	450,000		450,000
Unsecured 3.375% Senior Notes, due 2049	500,000		500,000
Unsecured 2.85% Senior Notes, due 2052	600,000		—
Floating-rate term loan, due April 2022	—		200,000
Floating-rate Senior Notes, due March 2023	1,100,000		1,100,000
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
Finance lease obligations	52,196		18,739
Total long-term debt	8,012,196		7,378,739
Less:
Original issue discount on unsecured senior notes and debentures	3,760		2,811
Debt issuance cost	47,842		45,271
Current maturities	2,201,430		2,400,452
	$	5,759,164	$	4,930,205

On October 1, 2021, we completed a public offering of $600 million of 2.85% senior notes due 2052, with an effective interest rate of 2.58%, after giving effect to the offering costs and settlement of our interest rate swaps. The net proceeds from the offering, after the underwriting discount and offering expenses, of $589.8 million were used for general corporate purposes.

December 31, 2017 September 30, 2017
(In thousands)
Unsecured 8.50% Senior Notes, due March 2019 $ 450,000
$ 450,000
Unsecured 3.00% Senior Notes, due 2027 500,000
500,000
Unsecured 5.95% Senior Notes, due 2034 200,000
200,000
Unsecured 5.50% Senior Notes, due 2041 400,000
400,000
Unsecured 4.15% Senior Notes, due 2043 500,000
500,000
Unsecured 4.125% Senior Notes, due 2044 750,000
750,000
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 3,085,000
3,085,000
Less:
Original issue premium / discount on unsecured senior notes and debentures (4,398 ) (4,384 )
Debt issuance cost 21,929
22,339
$ 3,067,469
$ 3,067,045
On January 14, 2022, we completed a public offering of $200 million of 2.625% senior notes due 2029, with an effective interest rate of 2.54%, after giving effect to the offering costs. The net proceeds from the offering, after the underwriting discount and offering expenses, of $200.8 million were used to repay our $200 million floating-rate term loan on January 18, 2022.


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

Short-term debt

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–capitalization~~equity-to-total-capitalization ratio between 50% and 60%, inclusive of ~~long–term~~long-term and ~~short–term~~short-term debt. Our ~~short–term~~short-term borrowing requirements are ~~affected~~driven primarily by construction work in progress and the seasonal nature of the natural gas business. Changes in the price of natural gas and the amount of natural gas we need to supply our customers’ needs could significantly affect our borrowing requirements. Our short–term borrowings typically reach their highest levels in the winter months.

~~Currently, our~~Our short-term borrowing requirements are satisfied through a combination of a $1.5 billion commercial paper program and ~~three~~4 committed revolving credit facilities with third-party lenders that provide ~~approximately $1.5~~$2.5 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 31, 2022, we amended this agreement to (i) extend the maturity date from March 31, 2026 to March 31, 2027 and (ii) replace the London interbank offered rate (the LIBOR Rate) with the forward-looking term rate based on the secured overnight financing rate (the SOFR Rate) as the interest rate benchmark. This facility ~~that expires September 25, 2021. The facility~~now bears interest at a base rate or at a ~~LIBOR-based~~SOFR-based rate for the applicable interest period, plus a ~~spread~~margin ranging from zero percent to 0.25 percent for base rate advances or a margin ranging from 0.75 percent to 1.25 percent for SOFR-based advances, based on the Company’s credit ratings. Additionally, the facility contains a $250 million accordion feature, which provides the opportunity to increase the total committed loan to $1.75 billion. At ~~December 31, 2017 and September~~June 30, ~~2017 a total of $336.8 million and $447.7 million was~~2022 there were no amounts outstanding under our commercial paper program.

We also have a $900 million three-year unsecured revolving credit facility which is used to provide additional working capital funding. On March 31, 2022, we amended this agreement to (i) extend the maturity date from March 31, 2024 to March 31, 2025 and (ii) replace the LIBOR Rate with the SOFR Rate as the interest rate benchmark. This facility now bears interest at a base rate or at a SOFR-based rate for the applicable interest period, plus a margin ranging from zero percent to 0.25 percent for base rate advances or a margin ranging from 0.75 percent to 1.25 percent for SOFR-based advances, based on the Company's credit ratings. Additionally, the facility contains a $100 million accordion feature, which provides the opportunity to increase the total committed loan to $1.0 billion. At June 30, 2022, there were no borrowings outstanding under this facility.

Additionally, we have a ~~$25~~$50 million 364-day unsecured facility, which was renewed April 1, 2022 and is used to provide working capital funding. There were no borrowings outstanding under this facility as of June 30, 2022.

Finally, we have a ~~$10~~$50 million 364-day unsecured revolving credit facility, which was renewed March 31, 2022 and is used ~~primarily~~ to issue letters of ~~credit.~~credit and to provide working capital funding. At ~~December 31, 2017,~~June 30, 2022, there were no borrowings outstanding under ~~either of these facilities;~~this facility; however, outstanding letters of credit reduced the total amount available to us ~~under our $10 million facility~~ to ~~$4.4~~$44.4 million.

Debt covenants

The availability of funds under these credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total-debt-to-total-capitalization of no greater than 70 percent. At ~~December 31, 2017,~~June 30, 2022, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 4447 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~~$15 million to in excess of ~~$100~~$100 million becomes due by acceleration or isif not paid at maturity. We were in compliance with all of our debt covenants as of ~~December 31, 2017.~~June 30, 2022. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.

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

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the "TCJA") was signed into law. The TCJA introduced several significant changes to corporate income tax laws in the United States. The most significant change that will affect Atmos Energy is the reduction of the federal statutory income tax rate from 35% to 21%. As a rate-regulated entity, the accelerated capital expensing and the limitation on interest deductibility provisions included in the TCJA are not applicable to us.

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

At September 30, 2017, we measured our net deferred tax liability using the enacted federal statutory tax rate of 35%. The enactment of the TCJA on December 22, 2017 required us to remeasure our deferred tax assets and liabilities, including our U.S. federal income tax net operating loss carryforwards, at the newly enacted federal statutory income tax rate. As the Company’s fiscal year end is September 30, the Internal Revenue Code requires the Company to use a blended statutory federal corporate income tax rate of 24.5% for fiscal 2018.

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

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

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

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

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

We are actively working with our regulators in each jurisdiction to address the impact of the TCJA on our cost of service based rates. Accounting orders have been issued for our Colorado, Kansas, Kentucky, Tennessee and Virginia service areas that require us to establish, effective January 1, 2018, a separate regulatory liability for the difference in taxes included in our rates that have been calculated based on a 35% statutory income tax rate and the new 21% statutory income tax rate. The establishment of this regulatory liability relating to our cost of service rates will result in a reduction to our revenues beginning in the second quarter of fiscal 2018. The period and timing of the return of these liabilities to utility customers will be determined by regulators in each of our jurisdictions.

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

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

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

•On January 31, 2018, Louisiana Public Service Commission (LPSC) directed utilities to file reports on February 14, 2018, regarding savings for ratepayers as a result of the new federal tax laws. The LPSC is also considering an accounting order to direct the utilities to track and record the impacts of the TCJA and a rule making docket to address the TCJA.

7. Shareholders' Equity

The following tables present a reconciliation of changes in stockholders' equity for the three and nine months ended June 30, 2022 and 2021.


	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, 2021	132,419,754	$	662	$	5,023,751	$	69,803	$	2,812,673	$	7,906,889
Net income	—	—		—		—		249,209		249,209
Other comprehensive loss	—	—		—		(45,947)		—		(45,947)


Cash dividends ($0.68 per share)	—	—		—		—		(90,411)		(90,411)

Common stock issued:
Public and other stock offerings	2,730,115	13		265,848		—		—		265,861
Stock-based compensation plans	275,212	2		3,942		—		—		3,944
Balance, December 31, 2021	135,425,081	677		5,293,541		23,856		2,971,471		8,289,545
Net income	—	—		—		—		324,999		324,999
Other comprehensive income	—	—		—		121,723		—		121,723


Cash dividends ($0.68 per share)	—	—		—		—		(93,533)		(93,533)

Common stock issued:
Public and other stock offerings	3,509,116	18		336,451		—		—		336,469
Stock-based compensation plans	77,832	—		4,028		—		—		4,028
Balance, March 31, 2022	139,012,029	695		5,634,020		145,579		3,202,937		8,983,231
Net income	—	—		—		—		128,547		128,547
Other comprehensive income	—	—		—		159,631		—		159,631


Cash dividends ($0.68 per share)	—	—		—		—		(95,312)		(95,312)

Common stock issued:
Public and other stock offerings	801,952	4		84,656		—		—		84,660
Stock-based compensation plans	74,775	—		7,414		—		—		7,414
Balance, June 30, 2022	139,888,756	$	699	$	5,726,090	$	305,210	$	3,236,172	$	9,268,171


	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, 2020	125,882,477	$	629	$	4,377,149	$	(57,589)	$	2,471,014	$	6,791,203
Net income	—	—		—		—		217,678		217,678
Other comprehensive income	—	—		—		60,121		—		60,121


Cash dividends ($0.625 per share)	—	—		—		—		(79,023)		(79,023)

Common stock issued:
Public and other stock offerings	2,126,118	11		219,998		—		—		220,009
Stock-based compensation plans	144,366	1		3,167		—		—		3,168
Balance, December 31, 2020	128,152,961	641		4,600,314		2,532		2,609,669		7,213,156
Net income	—	—		—		—		296,754		296,754
Other comprehensive income	—	—		—		137,939		—		137,939


Cash dividends ($0.625 per share)	—	—		—		—		(80,325)		(80,325)

Common stock issued:
Public and other stock offerings	2,498,026	12		248,948		—		—		248,960
Stock-based compensation plans	16,122	—		4,441		—		—		4,441
Balance, March 31, 2021	130,667,109	653		4,853,703		140,471		2,826,098		7,820,925
Net income	—	—		—		—		102,411		102,411
Other comprehensive loss	—	—		—		(79,232)		—		(79,232)


Cash dividends ($0.625 per share)	—	—		—		—		(81,912)		(81,912)

Common stock issued:
Public and other stock offerings	39,078	1		3,829		—		—		3,830
Stock-based compensation plans	80,852	—		7,736		—		—		7,736
Balance, June 30, 2021	130,787,039	$	654	$	4,865,268	$	61,239	$	2,846,597	$	7,773,758

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

~~On March 28, 2016, we filed~~We have a shelf registration statement with the Securities and Exchange Commission (SEC) that ~~originally permitted~~allows us to issue ~~from time to time,~~ up to ~~$2.5~~$5.0 billion in common stock and/or debt securities ~~which expires March 28, 2019. At December 31, 2017, approximately $1.2~~through June 29, 2024. As of the date of this report, $2.2 billion of securities ~~remained~~were available for issuance under ~~the~~this shelf registration statement.

On ~~November 14, 2017,~~March 23, 2022, we filed a prospectus supplement under the shelf 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, which expires March 28, 2019. During the three months ended December 31, 2017, no~~$1.0 billion through June 29, 2024 (including shares of common stock ~~were~~that may be sold ~~under~~pursuant to forward sale agreements entered into concurrently with the ATM ~~program.~~equity sales program). This ATM equity sales program replaced our previous ATM equity sales program, filed on June 29, 2021, which was exhausted during our second fiscal quarter.

~~On November~~During the nine months ended June 30, ~~2017,~~2022, we ~~filed a prospectus supplement~~executed forward sales under ~~the registration statement relating to an underwriting agreement to sell 4,558,404~~our ATM equity sales program with various forward sellers who borrowed and sold 10,308,214 shares of our common ~~stock. We received~~stock at an aggregate ~~gross~~price of $1.1 billion. During the nine months ended June 30, 2022, we also settled forward sale agreements with respect to 6,932,722 shares that had been borrowed and sold by various forward sellers under the ATM program for net proceeds of ~~$400~~$675.3 million. As of June 30, 2022, $663.0 million ~~and received net~~of equity was available for issuance under our existing ATM program. Additionally, we had $700.9 million in available proceeds ~~after expenses, of $395.1 million~~ from ~~the offering.~~outstanding forward sale agreements, as detailed below.



Maturity	Shares Available	Net Proceeds Available (In thousands)		Forward Price

September 29, 2023	5,527,318	$	595,261	$	107.69

December 29, 2023	919,898	105,634		$	114.83
Total	6,447,216	$	700,895	$	108.71

Accumulated Other Comprehensive Income (Loss)

We record deferred gains (losses) in AOCI related to available-for-sale debt securities and interest rate ~~cash flow hedges and prior to the sale of Atmos Energy Marketing on January 3, 2017, commodity contract~~agreement cash flow hedges. Deferred gains (losses) for our available-for-sale debt securities ~~and commodity contract cash flow hedges~~ are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate agreement cash flow hedges are recognized in earnings ~~as they are amortized.~~on a straight-line basis over the life of the related financing. The following tables provide the components of our accumulated other comprehensive income (loss) balances, net of the related tax effects allocated to each component of other comprehensive income (loss):.

Available-
for-Sale
Securities

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


	Available- for-Sale Securities		Interest Rate Agreement Cash Flow Hedges		Total
	(In thousands)
September 30, 2021	$	47	$	69,756	$	69,803
Other comprehensive income (loss) before reclassifications	(336)		233,511		233,175
Amounts reclassified from accumulated other comprehensive income	—		2,232		2,232
Net current-period other comprehensive income (loss)	(336)		235,743		235,407

June 30, 2022	$	(289)	$	305,499	$	305,210


	Available- for-Sale Securities		Interest Rate Agreement Cash Flow Hedges		Total
	(In thousands)
September 30, 2020	$	238	$	(57,827)	$	(57,589)
Other comprehensive income (loss) before reclassifications	(165)		115,568		115,403
Amounts reclassified from accumulated other comprehensive income	—		3,425		3,425
Net current-period other comprehensive income (loss)	(165)		118,993		118,828

June 30, 2021	$	73	$	61,166	$	61,239

Available-
for-Sale
Securities

Interest
Rate
Agreement
Cash Flow
Hedges

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

Overview

~~The following tables detail reclassifications out of AOCI~~As described in Note 9 to the consolidated financial statements in our Annual Report on Form 10-K for the ~~three months~~fiscal year ended September 30, 2021, a historic winter storm impacted supply, market pricing and demand for natural gas in our service territories in mid-February 2021. During this time, the governors of Kansas and Texas each declared a state of emergency, and certain regulatory agencies issued emergency orders that impacted the utility and natural gas industries, including statewide utilities curtailment programs and orders encouraging or requiring jurisdictional natural gas utilities to work to ensure customers were provided with safe and reliable natural gas service.

Due to the historic nature of this winter storm, we experienced unforeseeable and unprecedented market pricing for gas costs, which resulted in aggregated natural gas purchases during the month of February of approximately $2.3 billion. These gas costs were paid using funds received from a public offering of debt securities completed in March 2021 of $2.2 billion.

Regulatory Asset Accounting

Our purchased gas costs are recoverable through purchased gas cost adjustment mechanisms in each state where we operate. Due to the unprecedented level of purchased gas costs incurred during Winter Storm Uri, the Kansas Corporation Commission (KCC) and the Railroad Commission of Texas (RRC) issued orders authorizing natural gas utilities to record a regulatory asset to account for the extraordinary costs associated with the winter storm. Pursuant to these orders, as of June 30, 2022, we have recorded a $2.1 billion regulatory asset for incremental costs, including carrying costs, incurred in Kansas ($88.0 million) and Texas ($2,019.8 million).

Securitization Proceedings

To minimize the impact on the customer bill by extending the recovery periods for these unprecedented purchased gas costs, the Kansas and Texas State Legislatures each enacted securitization legislation in 2021, as described in further detail in Note 9 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2021.

Kansas

On March 24, 2022, the KCC issued an Order Approving Unanimous Settlement Agreement which stipulated that all of our gas and storage costs were prudently incurred. On May 25, 2022, we filed with the KCC an application to securitize $90.2 million in securitized utility tariff costs. Because we intend to recover these costs over several years, we have recorded the regulatory asset for Kansas as a long-term asset in deferred charges and other assets as of June 30, 2022.

Texas

We filed our application with the RRC on July 30, 2021 to securitize $2.0 billion of extraordinary gas costs incurred during Winter Storm Uri. This amount also included an estimate of carrying costs and administrative costs that we expect to incur in connection with the resolution of this filing.

On November 10, 2021, the RRC issued a Final Determination of the Regulatory Asset (the Final Determination). The Final Determination stipulates that all of our gas and storage costs were prudently incurred. Additionally, the Final Determination permits us to defer, through December 31, ~~2017~~2021 our actual carrying costs associated with the $2.2 billion of incremental financing issued in March 2021 and ~~2016. Amounts in parentheses below indicate decreases~~ to ~~net income~~recover approximately $0.6 million of our administrative costs.

On February 8, 2022, the RRC issued a Financing Order that authorizes the Texas Public Financing Authority to issue customer rate relief bonds to securitize the costs that were approved in the ~~statement~~Final Determination over a period not to exceed 30 years. As required by the Financing Order, the Texas Public Financing Authority has 180 days to issue the securitization bonds. Issuance may occur after 180 days if necessary based on bond market conditions, the receipt of ~~income:~~necessary approvals and the timely receipt of necessary financial disclosure information from each participating gas utility. Upon receipt of the securitization funds we will repay the $2.2 billion in public notes issued to finance the incremental gas costs incurred during Winter Storm Uri.

Three Months Ended December 31, 2017
Accumulated Other Comprehensive Income Components
Amount Reclassified from
Accumulated Other
Comprehensive Income

Affected Line Item in the
Statement of Income
(In thousands)
Cash flow hedges
Interest rate agreements $ (594 ) Interest charges
(594 ) Total before tax
217
Tax benefit
Total reclassifications $ (377 ) Net of tax

Three Months Ended December 31, 2016
Accumulated Other Comprehensive Income Components
Amount Reclassified from
Accumulated Other
Comprehensive Income

Affected Line Item in the
Statement of Income
(In thousands)
Cash flow hedges
Interest rate agreements $ (137 ) Interest charges
Commodity contracts 7,967

Purchased gas cost⁽¹⁾
7,830
Total before tax
(3,052 ) Tax expense
Total reclassifications $ 4,778
Net of tax

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

8.9. Interim Pension and Other Postretirement Benefit Plan Information

The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three and nine months ended ~~December 31, 2017~~June 30, 2022 and ~~2016~~2021 are presented in the following ~~table.~~tables. Most of these costs are recoverable through our tariff ~~rates; however, a~~rates. A portion of these costs is capitalized into our rate ~~base.~~base or deferred as a regulatory asset or liability. The remaining costs are recorded as a component of operation and maintenance expense or other non-operating expense.


	Three Months Ended June 30
	Pension Benefits				Other Benefits
	2022		2021		2022		2021
	(In thousands)
Components of net periodic pension cost:
Service cost	$	4,323	$	4,609	$	2,559	$	4,305
Interest cost (1)	5,063		5,016		2,683		2,661
Expected return on assets (1)	(7,383)		(6,978)		(3,312)		(2,613)

Amortization of prior service cost (credit) (1)	(58)		(58)		(3,308)		44
Amortization of actuarial (gain) loss (1)	1,951		3,062		—		—
Settlements(1)	—		8,999		—		—
Net periodic pension cost	$	3,896	$	14,650	$	(1,378)	$	4,397

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



	Nine Months Ended June 30
	Pension Benefits				Other Benefits
	2022		2021		2022		2021
	(In thousands)
Components of net periodic pension cost:
Service cost	$	12,970	$	13,834	$	7,676	$	12,917
Interest cost (1)	15,190		15,072		8,050		7,981
Expected return on assets (1)	(22,149)		(20,934)		(9,937)		(7,841)

Amortization of prior service cost (credit) (1)	(174)		(174)		(9,925)		130
Amortization of actuarial (gain) loss (1)	5,853		9,405		—		—
Settlements(1)	—		8,999		—		—
Net periodic pension cost	$	11,690	$	26,202	$	(4,136)	$	13,187

(1) The ~~assumptions used to develop our~~components of net periodic ~~pension~~ cost ~~for~~other than the ~~three months ended December 31, 2017 and 2016~~service cost component are included in the line item other non-operating expense in the condensed consolidated statements of comprehensive income or are capitalized on the condensed consolidated balance sheets as ~~follows:~~

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

~~The discount rate used to compute the present value of~~ a ~~plan’s liabilities generally is based on rates of high-grade corporate bonds with maturities similar~~regulatory asset or liability, as described in Note 2 to the average period over which the benefits will be paid. Generally, our funding policy has been to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974. In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plan as of January 1, 2017. Based on that determination, we were not required to make a minimum contribution to our defined benefit plan during the first quarter of fiscal 2018.

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

~~9. Commitments and Contingencies~~

~~Litigation and Environmental Matters~~

~~With respect to the litigation and environmental-related matters or claims that were disclosed in Note 11 to the~~consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017, there were no material changes~~2021.

For the nine months ended June 30, 2022 we contributed $11.1 million to our postretirement medical plans. We anticipate contributing a total of between $15 million and $25 million to our postretirement plans during fiscal 2022.

10. 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 ~~status~~future. While the outcome of ~~such litigation~~these proceedings is uncertain and ~~environmental-related matters~~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 ~~claims during~~cash flows.

We maintain liability insurance for various risks associated with the ~~three months ended December 31, 2017.~~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) held a public meeting on January 12, 2021 to determine the probable cause of the incident that occurred at a Dallas, Texas residence on February 23, 2018 that resulted in one fatality and injuries to four other residents. At the meeting, the Board deliberated and voted on proposed findings of fact, a probable cause statement, and safety recommendations. On February 8, 2021, the NTSB issued its final report that included an Executive Summary, Findings, Probable Cause, and Recommendations. Also on February 8, 2021, safety recommendations letters were distributed to recommendation recipients, including Atmos Energy. Atmos Energy timely provided a written response on May 7, 2021. Following the release of the NTSB’s final report, the Railroad Commission of Texas (RRC) completed its safety evaluation related to the same incident finding four alleged violations and initiated an enforcement proceeding to pursue administrative penalties totaling $1.6 million. Atmos Energy is working with the RRC to resolve the alleged violations and satisfy the administrative penalties.

The NTSB is investigating a worksite accident that occurred in Farmersville, Texas on June 28, 2021 that resulted in two fatalities and injuries to two others. Together with the Railroad Commission of Texas and the Pipeline and Hazardous Materials Safety Administration, Atmos Energy is a party to the investigation and in that capacity is working closely with all parties to help determine the cause of this incident. NaN civil actions have been filed in Dallas, Texas against Atmos Energy and one of its contractors in response to the accident.

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.~~hubs or fixed price contracts. These purchase commitment contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017. There~~2021. At June 30, 2022, we were ~~no material changes~~committed to ~~the~~ purchase ~~commitments~~68.3 Bcf within one year and 97.2 Bcf within two to three years under indexed contracts. At June 30, 2022, we were committed to purchase 3.4 Bcf within one year under fixed price contracts with a weighted average price of $5.41 per Mcf.

Future Lease Payments

A finance lease for ~~the three months ended December 31, 2017.~~a service center is expected to commence in fiscal 2023 that impacts our future lease payments. The total future lease payments for this lease are $19.3 million.

Rate Regulatory Proceedings

~~Regulatory Matters~~

Various regulatory agencies, including the SEC and the Commodities Futures Trading Commission, continue to adopt regulations implementing many of the provisions of the Dodd-Frank Act of 2010. We continue to enact new procedures and modify existing business practices and contractual arrangements to comply with such regulations. Additional rulemakings are pending which we believe will result in new reporting and disclosure obligations. The costs associated with hedging certain risks inherent in our business may be further increased when these expected additional regulations are adopted.

As of ~~December 31, 2017, formula~~June 30, 2022, routine rate ~~mechanisms~~regulatory proceedings were ~~pending regulatory approval in our Louisiana and Tennessee service areas, infrastructure mechanisms were pending regulatory approval in our Kansas service area, an ad valorem tax rider filing was~~ in progress in several of our ~~Kansas~~ service ~~area and rate cases were pending regulatory approval in our Colorado, Kentucky and Mid-Tex service areas. These regulatory proceedings~~areas, which are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments. ~~Additionally, as discussed~~Except for these proceedings, there were no material changes to rate regulatory proceedings for the nine months ended June 30, 2022.

11. Income Taxes

Income Tax Expense

Our interim effective tax rates reflect the estimated annual effective tax rates for the fiscal years ended September 30, 2022 and 2021, adjusted for tax expense associated with certain discrete items. The effective tax rates for the three months ended June 30, 2022 and 2021 were 9.3% and 13.4% and for the nine months ended June 30, 2022 and 2021 were 8.5% and 18.8%. These effective tax rates differ from the federal statutory tax rate of 21% primarily due to the amortization of excess deferred federal income tax liabilities, tax credits, state income taxes and other permanent book-to-tax differences. These adjustments have a relative impact on the effective tax rate proportionally to pretax income or loss.

Beginning in ~~further detail in Note 6, all jurisdictions are addressing impacts~~the second quarter of fiscal 2021 and through the end of the ~~TCJA.~~last fiscal year, we reached agreement with regulators in various states to begin refunding excess deferred tax liabilities generally over a three to five year period. This increased the refund of excess deferred tax liabilities to customers in the current year period and significantly reduced the effective tax rate for the three and nine month periods ended June 30, 2022 compared to the prior year periods.

Regulatory Excess Deferred Taxes

~~10.~~Regulatory excess net deferred taxes represent changes in our net deferred tax liability related to our cost of service ratemaking due to the enactment of the Tax Cuts and Jobs Act of 2017 (the "TCJA") and state tax legislative changes in Kansas and Louisiana. Currently, the regulatory excess net deferred tax liability of $537.4 million is being returned over various periods. Of this amount, $444.2 million is being returned to customers over 35 - 60 months. An additional $78.1 million is being returned to customers on a provisional basis over 15 - 69 years until our regulators establish the final refund periods. The refund of the remaining $15.1 million will be addressed in future rate proceedings.

As of June 30, 2022 and September 30, 2021, $160.2 million and $155.9 million is recorded in other current liabilities.

Winter Storm Uri Deferred Tax Assets and Liabilities

We deduct our purchased gas costs for federal income tax purposes in the period they are paid. As a result of impacts from Winter Storm Uri, we recorded a $471.0 million (tax effected) increase in our deferred tax liability and an increase in our net operating loss carryforward as of September 30, 2021. At September 30, 2021, we had $850.2 million (tax effected) of federal net operating loss carryforwards.

As a result of the Financing Order issued by the Texas RRC on February 8, 2022, we reduced the deferred tax liability associated with the Winter Storm Uri regulatory asset and the corresponding deferred tax asset associated with net operating loss carryforwards by $451.1 million during the second quarter of fiscal 2022.

As of June 30, 2022, we had $403.8 million (tax effected) of federal net operating loss carryforwards. The federal net operating loss carryforwards are available to offset future taxable income. These net operating losses can be carried forward indefinitely. The Company also has $28.1 million (tax effected) of state net operating loss carryforwards (net of $7.3 million of federal effects) and $1.7 million of state tax credits carryforwards (net of $0.5 million of federal effects). Depending on the jurisdiction in which the state net operating loss was generated, the carryforwards are subject to expiration as early as 2035.

12. Financial Instruments

We currently use financial instruments to mitigate commodity price risk and interest rate risk. The objectives and strategies for using financial instruments and the related accounting for these financial instruments are fully described in Notes 2 and 1315 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017.~~2021. During the ~~three~~nine months ended ~~December 31, 2017,~~June 30, 2022, there were no material changes in our objectives, strategies and accounting for using financial instruments. Our financial instruments do not contain any credit-risk-related or other contingent features that could cause payments to be accelerated when our financial instruments are in net liability positions. The following summarizes those objectives and strategies.

Commodity Risk Management Activities

Our purchased gas cost adjustment mechanisms essentially insulate our distribution segment from commodity price risk; however, our customers are exposed to the effects of volatile natural gas prices. We manage this exposure through a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season.

We typically seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the ~~2017-2018~~2021-2022 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we ~~anticipate hedging~~hedged approximately 2642 percent, or ~~15.0~~23.9 Bcf, of the winter flowing gas requirements. We have not designated these financial instruments as hedges for accounting purposes.

Interest Rate Risk Management Activities

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

As of December 31, 2017, we had forward starting interest rate swaps to effectively fix the Treasury yield component associated with the anticipated issuance of $450 million unsecured senior notes in fiscal 2019 at 3.78%, which we designated as a cash flow hedge at the time the swaps were executed. As of December 31, 2017, we had $40.8 million of net realized losses in accumulated other comprehensive income (AOCI) associated with the settlement of financial instruments used to fix the Treasury yield component of the interest cost of financing various issuances of long-term debt and senior notes, which will be recognized as a component of interest expense over the life of the associated notes from the date of settlement. The remaining amortization periods for these settled amounts extend through fiscal 2045.

Quantitative Disclosures Related to Financial Instruments

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

As of ~~December 31, 2017,~~June 30, 2022, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of ~~December 31, 2017,~~June 30, 2022, we had ~~12,143~~5,819 MMcf of net ~~short~~long commodity contracts outstanding. These contracts have not been designated as hedges.

Financial Instruments on the Balance Sheet

The following tables present the fair value and balance sheet classification of our financial instruments as of ~~December 31, 2017~~June 30, 2022 and September 30, ~~2017.~~2021. The gross amounts of recognized assets and liabilities are netted within our unaudited ~~Condensed Consolidated Balance Sheets~~condensed consolidated balance sheets to the extent that we have netting arrangements with our counterparties.

However, as of June 30, 2022 and September 30, 2021, no gross amounts and no cash collateral were netted within our consolidated balance sheet.


									June 30, 2022
								Balance Sheet Location	Assets		Liabilities
	Balance Sheet Location	Assets		Liabilities					(In thousands)
		(In thousands)
December 31, 2017
Designated As Hedges:							Designated As Hedges:

Interest rate contracts							Interest rate contracts	Other current assets / Other current liabilities	$	169,318	$	—

Interest rate contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		(114,175		)	Interest rate contracts	Deferred charges and other assets / Deferred credits and other liabilities	301,152		—
Total		—		(114,175		)	Total		470,470		—
Not Designated As Hedges:							Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	456		(2,738		)	Commodity contracts	Other current assets / Other current liabilities	17,518		(193)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	190		(262		)	Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	169		(5)
Total		646		(3,000		)	Total		17,687		(198)
Gross Financial Instruments		646		(117,175		)
Gross Amounts Offset on Consolidated Balance Sheet:
Contract netting		—		—
Net Financial Instruments		646		(117,175		)
Cash collateral		—		—
Net Assets/Liabilities from Risk Management Activities		$	646	$	(117,175	)
Gross / Net Financial Instruments							Gross / Net Financial Instruments		$	488,157	$	(198)

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


		September 30, 2021
	Balance Sheet Location	Assets		Liabilities
		(In thousands)

Designated As Hedges:



Interest rate contracts	Deferred charges and other assets / Deferred credits and other liabilities	$	169,469	$	—
Total		169,469		—
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	55,073		(5,269)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	6,144		—
Total		61,217		(5,269)
Gross / Net Financial Instruments		$	230,686	$	(5,269)

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

Cash Flow Hedges

As discussed above, our distribution segment has interest rate ~~swap~~ agreements, which we designated as a cash flow ~~hedge~~hedges at the time the ~~swaps~~agreements were executed. The net loss on settled interest rate agreements reclassified from AOCI into interest charges on our condensed consolidated statements of comprehensive income for the three months ended ~~December 31, 2017~~June 30, 2022 and ~~2016~~2021 was ~~$0.6~~$1.0 million and ~~$0.1~~$1.5 million and for the nine months ended June 30, 2022 and 2021 was $2.9 million and $4.4 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 nine months ended ~~December 31, 2017~~June 30, 2022 and ~~2016.~~2021. The amounts included in the table below exclude gains and losses arising from ineffectiveness because those amounts are immediately recognized in the statement of comprehensive income ~~statement~~ as incurred.


	Three Months Ended December 31							Three Months Ended June 30				Nine Months Ended June 30
	2017			2016 (1)				2022		2021		2022		2021
	(In thousands)							(In thousands)
Increase (decrease) in fair value:							Increase (decrease) in fair value:
Interest rate agreements	$	(1,332	)	$	91,127		Interest rate agreements	$	158,993	$	(80,338)	$	233,511	$	115,568
Forward commodity contracts⁽²⁾	—			9,847
Recognition of (gains) losses in earnings due to settlements:

Recognition of losses in earnings due to settlements:							Recognition of losses in earnings due to settlements:
Interest rate agreements	377			87			Interest rate agreements	744		1,142		2,232		3,425
Forward commodity contracts⁽²⁾	—			(4,865		)

Total other comprehensive income (loss) from hedging, net of tax	$	(955	)	$	96,196		Total other comprehensive income (loss) from hedging, net of tax	$	159,737	$	(79,196)	$	235,743	$	118,993


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


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

Deferred gains (losses) recorded in AOCI associated with our interest rate agreements are recognized in earnings as they are amortized over the terms of the underlying debt instruments. As of June 30, 2022, we had $59.5 million of net realized losses in AOCI associated with our interest rate agreements. The following amounts, net of deferred taxes, represent the expected recognition in earnings of the deferred net losses recorded in AOCI associated with our ~~financial instruments,~~interest rate agreements, based upon the fair values of these ~~financial instruments as~~agreements at the date of ~~December 31, 2017.~~settlement. The remaining amortization periods for these settled amounts extend through fiscal 2052. However, the table below does not include the expected recognition in earnings of our outstanding interest rate ~~agreements~~swaps as those instruments have not yet settled.


	Interest Rate Agreements
	(In thousands)
Next twelve months	$	(2,976)
Thereafter	(56,506)
Total	$	(59,482)

Interest Rate
Agreements
(In thousands)
Next twelve months $ (1,508 )
Thereafter (39,248 )
Total $ (40,756 )

Financial Instruments Not Designated as Hedges

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

~~11.~~

13. 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 consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017.~~2021. During the ~~three~~nine months ended ~~December 31, 2017,~~June 30, 2022, 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 710 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017.~~2021.

Quantitative Disclosures

Financial Instruments

The classification of our fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. Authoritative accounting literature establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1), with the lowest priority given to unobservable inputs (Level 3). The following tables summarize, by level

within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of ~~December 31, 2017~~June 30, 2022 and September 30, ~~2017.~~2021. Assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.


	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)(1)		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral		June 30, 2022
	(In thousands)
Assets:
Financial instruments	$	—	$	488,157	$	—	$	—	$	488,157
Debt and equity securities
Registered investment companies	28,370		—		—		—		28,370
Bond mutual funds	32,667		—		—		—		32,667
Bonds (2)	—		33,729		—		—		33,729
Money market funds	—		3,590		—		—		3,590
Total debt and equity securities	61,037		37,319		—		—		98,356
Total assets	$	61,037	$	525,476	$	—	$	—	$	586,513
Liabilities:
Financial instruments	$	—	$	198	$	—	$	—	$	198

Quoted
Prices in
Active
Markets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)⁽¹⁾

Significant
Other
Unobservable
Inputs
(Level 3)

Netting and
Cash
Collateral
December 31, 2017
(In thousands)
Assets:
Financial instruments $ —
$ 646
$ —
$ —
$ 646
Available-for-sale securities
Registered investment companies 43,065
—
—
—
43,065
Bond mutual funds 16,359
—
—
—
16,359
Bonds —
30,861
—
—
30,861
Money market funds —
614
—
—
614
Total available-for-sale securities 59,424
31,475
—
—
90,899
Total assets $ 59,424
$ 32,121
$ —
$ —
$ 91,545
Liabilities:
Financial instruments $ —
$ 117,175
$ —
$ —
$ 117,175


	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)⁽¹⁾		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral		September 30, 2017			Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)(1)		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral		September 30, 2021
	(In thousands)											(In thousands)
Assets:											Assets:
Financial instruments	$	—	$	3,239	$	—	$	—	$	3,239	Financial instruments	$	—	$	230,686	$	—	$	—	$	230,686
Available-for-sale securities
Debt and equity securities											Debt and equity securities
Registered investment companies	41,097		—		—		—		41,097		Registered investment companies	35,175		—		—		—		35,175
Bond mutual funds	16,371		—		—		—		16,371		Bond mutual funds	34,298		—		—		—		34,298
Bonds	—		29,104		—		—		29,104
Bonds (2)											Bonds (2)	—		35,655		—		—		35,655
Money market funds	—		1,837		—		—		1,837		Money market funds	—		2,943		—		—		2,943
Total available-for-sale securities	57,468		30,941		—		—		88,409
Total debt and equity securities											Total debt and equity securities	69,473		38,598		—		—		108,071
Total assets	$	57,468	$	34,180	$	—	$	—	$	91,648	Total assets	$	69,473	$	269,284	$	—	$	—	$	338,757
Liabilities:											Liabilities:
Financial instruments	$	—	$	112,398	$	—	$	—	$	112,398	Financial instruments	$	—	$	5,269	$	—	$	—	$	5,269

(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.

~~(1)~~

Our Level 2 measurements consist of over-the-counter options and swaps which are valued using a market-based approach in which observable market prices are adjusted for criteria specific to each instrument, such as the strike price, notional amount or basis differences, municipal and corporate bonds which are valued based on the most recent available quoted market prices and money market funds which are valued at cost.

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

~~Available-for-sale~~Debt and equity securities are comprised of our available-for-sale debt securities and our equity securities. As described in Note 2 to the ~~following:~~

Amortized
Cost

Gross
Unrealized
Gain

Gross
Unrealized
Loss

Fair
Value
(In thousands)
As of December 31, 2017
Domestic equity mutual funds $ 27,171
$ 8,850
$ (14 ) $ 36,007
Foreign equity mutual funds 4,725
2,333
—
7,058
Bond mutual funds 16,461
—
(102 ) 16,359
Bonds 30,936
6
(81 ) 30,861
Money market funds 614
—
—
614
$ 79,907
$ 11,189
$ (197 ) $ 90,899
As of September 30, 2017
Domestic equity mutual funds $ 25,361
$ 8,920
$ —
$ 34,281
Foreign equity mutual funds 4,581
2,235
—
6,816
Bond mutual funds 16,391
2
(22 ) 16,371
Bonds 29,074
46
(16 ) 29,104
Money market funds 1,837
—
—
1,837
$ 77,244
$ 11,203
$ (38 ) $ 88,409

consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2021, we 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, current returns and any intent to sell the security. As of June 30, 2022, no allowance for credit losses was recorded for our available-for-sale debt securities. At ~~December 31, 2017~~June 30, 2022 and September 30, ~~2017,~~2021, the amortized cost of our available-for-sale debt securities ~~included $43.7~~was $34.1 million and ~~$42.9 million related to assets held in separate rabbi trusts for our supplemental executive benefit plans.~~$35.6 million. At ~~December 31, 2017,~~June 30, 2022, we maintained investments in bonds that have contractual maturity dates ranging from ~~January 2018~~July 2022 through ~~December 2020.~~June 2025.

These securities are reported at market value with unrealized gains and losses shown as a component of accumulated other comprehensive income (loss). We regularly evaluate the performance of these investments on a fund by fund basis for impairment, taking into consideration the fund’s purpose, volatility and current returns. If a determination is made that a decline in fair value is other than temporary, the related fund is written down to its estimated fair value and the other-than-temporary impairment is recognized in the income statement.

Other Fair Value Measures

Our long-term debt is recorded at carrying value. The fair value of our long-term debt, excluding finance leases, 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 carrying value of our finance leases materially approximates fair value. The following table presents the carrying value and fair value of our long-term debt, excluding finance leases, debt issuance costs and original issue premium or discount, as of ~~December 31, 2017~~June 30, 2022 and September 30, ~~2017:~~2021:


	June 30, 2022		September 30, 2021
	(In thousands)
Carrying Amount	$	7,960,000	$	7,360,000
Fair Value	$	7,340,176	$	8,086,136

December 31, 2017 September 30, 2017
(In thousands)
Carrying Amount $ 3,085,000
$ 3,085,000
Fair Value $ 3,305,656
$ 3,382,272

~~12.~~14. Concentration of Credit Risk

Information regarding our concentration of credit risk is disclosed in Note 1617 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017.~~2021. During the ~~three~~nine months ended ~~December 31, 2017,~~June 30, 2022, there were no material changes in our concentration of credit risk.

~~13. Discontinued Operations~~

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

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

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

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

Three Months Ended
December 31, 2016
(In thousands)

Operating revenues $ 303,474
Purchased gas cost 277,554
Operating expenses 7,874
Operating income 18,046
Other nonoperating expense (211 )
Income from discontinued operations before income taxes 17,835
Income tax expense 6,841
Net income from discontinued operations $ 10,994
26

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

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

~~Natural Gas Marketing Commodity Risk Management Activities~~

Our discontinued natural gas marketing segment was exposed to risks associated with changes in the market price of natural gas through the purchase, sale and delivery of natural gas to its customers at competitive prices. Through December 31, 2016, we managed our exposure to such risks through a combination of physical storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Effective January 1, 2017, as a result of the sale of AEM, these activities were discontinued.

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

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

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

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

~~Fair Value Hedges~~

The impact of our natural gas marketing segment commodity contracts designated as fair value hedges and the related hedged item on the results of discontinued operations on our condensed consolidated income statement for the three months ended December 31, 2016 is presented below.

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

Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity.

~~Cash Flow Hedges~~

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

Three Months Ended
December 31, 2016

(In thousands)

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

~~Financial Instruments Not Designated as Hedges~~

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of

Atmos Energy Corporation

Results of Review of Interim Financial Statements

We have reviewed the accompanying condensed consolidated balance sheet of Atmos Energy Corporation ~~and subsidiaries~~(the Company) as of ~~December 31, 2017 and~~June 30, 2022, the related condensed consolidated statements of ~~income,~~ comprehensive income for the three and nine month periods ended June 30, 2022 and 2021, the condensed consolidated statements of cash flows for the ~~three-month~~nine month periods ended ~~December 31, 2017~~June 30, 2022 and ~~2016. These~~2021, 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 ~~are the responsibility of the Company’s management.~~for them to be in conformity with U.S. generally accepted accounting principles.

We ~~conducted our review~~have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States). (PCAOB), the consolidated balance sheet of the Company as of September 30, 2021, the related consolidated statements of comprehensive income, shareholders’ equity and cash flows for the year then ended, and the related notes (not presented herein); and in our report dated November 12, 2021, we expressed an unqualified audit opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of September 30, 2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

These financial statements are the responsibility of the Company's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the SEC and the PCAOB. We conducted our review in accordance with the standards of the PCAOB. A review of interim financial ~~information~~statements consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the ~~Public Company Accounting Oversight Board,~~PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Atmos Energy Corporation and subsidiaries as of September 30, 2017, and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended, not presented herein, and in our report dated November 13, 2017, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of September 30, 2017, is fairly stated, in all material respects, in relation to the consolidated balance sheets from which it has been derived.

/s/ ERNST & YOUNG LLP

Dallas, Texas

~~February 6, 2018~~

August 3, 2022



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

INTRODUCTION

The following discussion should be read in conjunction with the condensed consolidated financial statements in this Quarterly Report on Form 10-Q and Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended September 30, ~~2017.~~2021.

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”~~“forecast��, “goal”, “intend”, “objective”, “plan”, “projection”, “seek”, “strategy” or similar words are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to our strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties include the following: ~~our ability to continue to access the credit~~federal, state and ~~capital markets to execute our business strategy;~~local regulatory and political 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 impact of ~~adverse economic conditions on our customers;~~greenhouse gas emissions or other legislation or regulations intended to address climate change; possible significant costs and liabilities resulting from pipeline integrity and other similar programs and related repairs; the ~~effects of inflation~~inherent hazards and ~~changes~~risks involved in ~~the availability~~distributing, transporting and ~~price of~~storing natural gas; the availability and accessibility of contracted gas supplies, interstate pipeline and/or storage services; market risks beyond our control affecting our risk management activities, including commodity price volatility, counterparty performance or creditworthiness and interest rate risk; the concentration of our operations in Texas; increased competition from energy suppliers and alternative forms of energy; adverse weather conditions; the ~~capital-intensive nature~~impact of ~~our business; increased costs of providing health care benefits, along with pension and postretirement health care benefits and increased funding requirements;~~climate change; the inability to continue to hire, train and retain operational, technical and managerial personnel; ~~possible~~ increased ~~federal, state and local regulation of~~dependence on technology that may hinder the safety of our operations; increased federal regulatory oversight and potential penalties; the impact of environmental regulations on our business; the impact of climate change or related additional legislation or regulation in the future; the inherent hazards and risks involved in distributing, transporting and storing natural gas;Company's business if such technologies fail; 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.~~control; 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; increased costs of providing health care benefits, along with pension and postretirement health care benefits and increased funding requirements; and the outbreak of COVID-19 and its impact on business and economic conditions. Accordingly, while we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, we undertake no obligation to update or revise any of our forward-looking statements whether as a result of new information, future events or otherwise.

OVERVIEW

Atmos Energy and our subsidiaries are engaged in the regulated natural gas distribution and pipeline and storage businesses. We distribute natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers throughout our six distribution divisions, which at ~~December 31, 2017~~June 30, 2022 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 and storage assets located in Kentucky and Tennessee.~~

states.

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

~~The~~ ~~natural gas marketing segment~~ ~~was comprised of our discontinued natural gas marketing business.~~

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

Our condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates, including those related to ~~risk management and trading activities,~~ the allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes and the valuation of goodwill ~~indefinite-lived intangible assets~~ and other long-lived assets. Actual results may differ from such estimates.

Our critical accounting policies used in the preparation of our consolidated financial statements are described in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017~~2021 and include the following:

•Regulation

•Unbilled revenue

•Pension and other postretirement plans

•Impairment assessments

Our critical accounting policies are reviewed periodically by the Audit Committee of our Board of Directors. There were no significant changes to these critical accounting policies during the ~~three~~nine months ended ~~December 31, 2017.~~June 30, 2022.

~~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 income statement as purchased gas cost. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe Gross Profit, 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 gross profit rather than operating revenues and purchased gas cost individually.

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

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

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

RESULTS OF OPERATIONS

Executive Summary

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

During the ~~first three~~nine months ~~of fiscal 2018,~~ended June 30, 2022, we recorded ~~adjusted~~net income ~~from continuing operations~~ of ~~$152.2~~$702.8 million, or ~~$1.40~~$5.12 per diluted share, compared to ~~adjusted~~net income ~~from continuing operations~~ of ~~$114.0~~$616.8 million, or ~~$1.08~~$4.77 per diluted share for the ~~first three~~nine months ~~of fiscal 2017.~~ ended June 30, 2021.

The ~~period-over-period~~14 percent year-over-year increase ~~of $38.2 million, or 33.5%,~~in net income largely reflects positive rate outcomes driven by safety and ~~the impact of the TCJA~~reliability spending and customer growth in our distribution segment, offset by higher spending on certain operating and maintenance expenses in both our ~~effective income tax rate.~~ segments.

During the ~~three~~nine months ended ~~December 31, 2017,~~June 30, 2022, we ~~completed seven~~implemented ratemaking regulatory ~~proceedings, resulting~~actions which resulted in an increase in annual operating income of ~~$46.1~~$154.9 million. Excluding the impact of the refund of excess deferred income taxes resulting from previously enacted tax reform legislation, our total rate outcomes were $205.9 million ~~and~~for the nine months ended June 30, 2022. Additionally, as of June 30, 2022, we had ~~seven~~ ratemaking efforts in progress ~~at December 31, 2017~~ seeking a total increase in annual operating income of ~~$13.3~~$132.6 million.

Capital expenditures for the ~~first three~~nine months ~~of fiscal 2018~~ended June 30, 2022 were ~~$383.2 million. Approximately 82~~$1.7 billion. Over 85 percent was invested to improve the safety and reliability of our distribution and transportation systems, with a significant portion of this investment incurred under regulatory mechanisms that reduce lag to six months or less. We expect our capital expenditures to range between $1.3 billion and $1.4 billion for fiscal 2018. We funded our capital expenditures program primarily through operating cash flows of $173.2 million. Additionally, we issued $400 million of common stock during

During the ~~three~~nine months ended ~~December 31, 2017. The net proceeds from~~June 30, 2022, we completed approximately $1.5 billion of long-term debt and equity financing. As of June 30, 2022, our equity capitalization was 53.8 percent. Excluding the ~~issuance were primarily used to repay short-term debt~~$2.2 billion of incremental financing issued in conjunction with Winter Storm Uri, our equity capitalization was 61.7 percent. As of June 30, 2022, we had approximately $3.5 billion in total liquidity, consisting of $328.1 million in cash and cash equivalents, $700.9 million in funds available through equity forward sales agreements and $2,494.4 million in undrawn capacity under our ~~commercial paper program, to fund capital spending and for general corporate purposes.~~credit facilities.

As a result of our sustained financial performance, ~~improved cash flows and capital structure,~~ our Board of Directors increased the quarterly dividend by ~~7.8~~8.8 percent for fiscal ~~2018.~~

~~TCJA Impact~~

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

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

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

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

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

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

Distribution Segment

The distribution segment is primarily comprised of our regulated natural gas distribution and related sales operations in eight states. The primary factors that impact the results of this segment are our ability to earn our authorized rates of return, ~~the cost of natural gas,~~ competitive factors in the energy industry and economic conditions in our service areas.

Our ability to earn our authorized rates of return is based primarily on our ability to improve the rate design in our various ratemaking jurisdictions ~~by reducing or eliminating~~to minimize regulatory lag and, ultimately, ~~separating~~separate the recovery of our approved ~~margins~~rates from customer usage patterns. Improving rate design is a long-term process and is further complicated by the fact that we operate in multiple rate jurisdictions. Under our current rate design, approximately 70 percent of our distribution segment revenues are earned through the first six months of the fiscal year. Additionally, we currently recover approximately 60 percent of our distribution segment revenue, excluding gas costs, through the base customer charge, which partially separates the recovery of our approved rate from customer usage patterns.

Seasonal weather patterns can also affect our distribution operations. However, the effect of weather that is above or below normal is substantially offset through weather normalization adjustments, known as WNA, which ~~has~~have been approved by state regulatory commissions for approximately 9796 percent of our residential and commercial ~~meters~~revenues in the following states for the following time periods:




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

Our distribution operations are also affected by the cost of natural gas. ~~The~~We are generally able to pass the cost of gas ~~is passed~~ through to our customers without ~~markup. Therefore,~~markup under purchased gas cost adjustment mechanisms; therefore, increases in the cost of gas are offset by a corresponding increase in revenues. ~~Gross profit~~Revenues in our Texas and Mississippi service areas ~~includes~~include franchise fees and gross receipts taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenues is influenced by the cost of gas and the level of gas sales volumes. We record the associated tax expense as a component of taxes, other than income. ~~Although changes in these revenue-related taxes arising from changes in gas costs affect gross profit, over time the impact is offset within operating income.~~

~~As discussed above, the~~The cost of gas typically does not have a direct impact on our ~~gross profit.~~operating income because these costs are recovered through our purchased gas cost adjustment mechanisms. However, higher gas costs ~~mean higher bills for our customers, which~~ may adversely impact our accounts receivable collections, resulting in higher bad debt expense. This risk is currently mitigated by rate design that allows us to collect from our customers the gas cost portion of our bad debt expense on approximately 79 percent of our residential and commercial revenues. Additionally, higher gas costs may require us to increase borrowings under our credit facilities, resulting in higher interest expense. ~~In addition,~~Finally, higher gas costs, as well as competitive factors in the industry and general economic conditions may cause customers to conserve or, in the case of industrial consumers, to use alternative energy sources. However, gas cost risk has been mitigated in recent years through improvements in rate design that allow us to collect from our customers the gas cost portion of our bad debt expense on approximately 76 percent of our residential and commercial margins.

Three Months Ended ~~December 31, 2017~~June 30, 2022 compared with Three Months Ended ~~December 31, 2016~~June 30, 2021

Financial and operational highlights for our distribution segment for the three months ended ~~December 31, 2017~~June 30, 2022 and ~~2016~~2021 are presented below.


	Three Months Ended June 30
	2022		2021		Change
	(In thousands, unless otherwise noted)
Operating revenues	$	773,311	$	558,750	$	214,561
Purchased gas cost	390,559		202,050		188,509

Operating expenses	316,693		288,577		28,116
Operating income	66,059		68,123		(2,064)
Other non-operating income	6,708		1,060		5,648
Interest charges	12,341		8,540		3,801
Income before income taxes	60,426		60,643		(217)

Income tax expense	3,025		7,354		(4,329)
Net income	$	57,401	$	53,289	$	4,112
Consolidated distribution sales volumes — MMcf	44,954		41,352		3,602
Consolidated distribution transportation volumes — MMcf	34,360		34,776		(416)
Total consolidated distribution throughput — MMcf	79,314		76,128		3,186

Consolidated distribution average cost of gas per Mcf sold	$	8.69	$	4.89	$	3.80

Three Months Ended December 31
2017 2016 Change
(In thousands, unless otherwise noted)
Operating revenues $ 860,792
$ 754,656
$ 106,136
Purchased gas cost 463,758
395,346
68,412
Gross profit 397,034
359,310
37,724
Operating expenses 224,278
204,417
19,861
Operating income 172,756
154,893
17,863
Miscellaneous expense (1,400 ) (633 ) (767 )
Interest charges 21,368
21,118
250
Income before income taxes 149,988
133,142
16,846
One-time, non-cash income tax benefit (140,151 ) —
(140,151 )
Income tax expense 41,040
47,778
(6,738 )
Net income $ 249,099
$ 85,364
$ 163,735
Consolidated distribution sales volumes — MMcf 86,307
74,430
11,877
Consolidated distribution transportation volumes — MMcf 38,050
36,175
1,875
Total consolidated distribution throughput — MMcf 124,357
110,605
13,752
Consolidated distribution average cost of gas per Mcf sold $ 5.37
$ 5.31
$ 0.06

~~Income before~~Operating income ~~taxes~~ for our distribution segment ~~increased 13 percent, primarily due~~decreased three percent. Increased refunds of excess deferred taxes to ~~a $37.7~~customers decreased period-over-period operating income by $20.8 million ~~increase~~and reduced the interim effective income tax rate for this segment to 5.0% compared to 12.1% in ~~gross profit, partially offset with a $19.9 million increase~~the prior year period. Additional key drivers for the change in operating ~~expenses. The quarter-over-quarter increase in gross profit primarily reflects:~~income include:

•a ~~$25.6~~$30.5 million ~~net~~ increase in rate adjustments, primarily in our Mid-Tex ~~Mississippi, West Texas~~ and ~~Kentucky/Mid-States~~Louisiana Divisions.

•a ~~$5.7~~$3.3 million increase in ~~residential and commercial~~consumption, net ~~consumption,~~of our weather normalization adjustments (WNA)

•a $2.6 million increase in customers, primarily in our Mid-Tex ~~and Mississippi Divisions.~~Division.

•a ~~$3.5~~$1.8 million ~~increase from customer growth, primarily~~decrease in ~~our Mid-Tex and Kentucky/Mid-States Divisions.~~

~~The increase in operating expenses, which includes~~other operation and maintenance expense, ~~provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, was~~ primarily due to ~~incremental system integrity activities, increased~~lower bad debt expense and other administrative costs in the current-year quarter.

Partially offset by:

•a $13.7 million increase in depreciation expense and property ~~tax expense~~taxes associated with increased capital investments.

~~The decrease in income tax expense reflects~~ •a ~~reduction in our effective tax rate from 35.9% to 27.4%, as a result of the TCJA, which is partially offset by an~~$5.0 million increase in ~~income before income taxes.~~system maintenance and related activities.

The following table shows our operating income by distribution division, in order of total rate base, for the three months ended ~~December 31, 2017~~June 30, 2022 and ~~2016.~~2021. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.


	Three Months Ended December 31							Three Months Ended June 30
	2017		2016		Change			2022		2021		Change
	(In thousands)							(In thousands)
Mid-Tex	$	72,925	$	72,743	$	182	Mid-Tex	$	30,574	$	33,135	$	(2,561)
Kentucky/Mid-States	28,129		22,738		5,391		Kentucky/Mid-States	13,715		11,773		1,942
Louisiana	23,268		19,863		3,405		Louisiana	10,892		11,027		(135)
West Texas	15,761		14,928		833		West Texas	1,876		5,118		(3,242)
Mississippi	18,275		11,958		6,317		Mississippi	4,932		5,365		(433)
Colorado-Kansas	12,931		11,705		1,226		Colorado-Kansas	3,335		2,517		818
Other	1,467		958		509		Other	735		(812)		1,547
Total	$	172,756	$	154,893	$	17,863	Total	$	66,059	$	68,123	$	(2,064)

Nine Months Ended June 30, 2022compared with Nine Months Ended June 30, 2021

Financial and operational highlights for our distribution segment for the nine months ended June 30, 2022 and 2021 are presented below.



	Nine Months Ended June 30
	2022		2021		Change
	(In thousands, unless otherwise noted)
Operating revenues	$	3,356,279	$	2,718,074	$	638,205
Purchased gas cost	1,881,212		1,304,269		576,943

Operating expenses	907,208		832,873		74,335
Operating income	567,859		580,932		(13,073)
Other non-operating income	9,173		1,135		8,038
Interest charges	36,046		33,269		2,777
Income before income taxes	540,986		548,798		(7,812)

Income tax expense	35,163		109,481		(74,318)
Net income	$	505,823	$	439,317	$	66,506
Consolidated distribution sales volumes — MMcf	256,717		275,691		(18,974)
Consolidated distribution transportation volumes — MMcf	120,037		120,150		(113)
Total consolidated distribution throughput — MMcf	376,754		395,841		(19,087)

Consolidated distribution average cost of gas per Mcf sold	$	7.33	$	4.73	$	2.60

Operating income for our distribution segment decreased two percent. Increased refunds of excess deferred taxes to customers decreased period-over-period operating income by $89.5 million and reduced the interim effective income tax rate for this segment to 6.5% compared to 19.9% in the prior year period. Additional key drivers for the change in operating income include:

•a $122.6 million increase in rate adjustments, primarily in our Mid-Tex, West Texas and Louisiana Divisions.

•a $13.2 million increase in customers, primarily in our Mid-Tex Division.

Partially offset by:

•a $34.8 million increase in depreciation expense and property taxes associated with increased capital investments.

•a $13.1 million decrease in consumption, net of WNA, primarily due to the decline in residential consumption during the second fiscal quarter.

•a $12.3 million increase in system maintenance and related activities.

•a $2.9 million increase in other operation and maintenance expense, primarily due to employee related costs, insurance premiums and other administrative costs, partially offset by lower bad debt expense in the current year.

The following table shows our operating income by distribution division, in order of total rate base, for the nine months ended June 30, 2022 and 2021. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.



	Nine Months Ended June 30
	2022		2021		Change
	(In thousands)
Mid-Tex	$	292,207	$	284,104	$	8,103
Kentucky/Mid-States	75,541		69,127		6,414
Louisiana	61,842		66,718		(4,876)
West Texas	53,907		51,364		2,543
Mississippi	66,719		68,142		(1,423)
Colorado-Kansas	28,187		36,610		(8,423)
Other	(10,544)		4,867		(15,411)
Total	$	567,859	$	580,932	$	(13,073)

Recent Ratemaking Developments

The amounts described in the following sections represent the operating income that was requested or received in each rate filing, which may not necessarily reflect the stated amount referenced in the final order, as certain operating costs may have changed as a result of a commission’s or other governmental authority’s final ruling. During the first ~~three~~nine months of fiscal ~~2018,~~2022, we ~~completed six~~implemented, or received approval to implement, regulatory proceedings, resulting in a ~~$17.1~~$76.1 million increase in annual operating income as summarized below. Our ratemaking outcomes include the refund of excess deferred income taxes (EDIT) resulting from previously enacted tax reform legislation and do not reflect the true economic benefit of the outcomes because they do not include the corresponding income tax benefit. Excluding these amounts, our total rate outcomes for ratemaking activities for the nine months ended June 30, 2022 were $127.1 million.


Rate Action	Annual Increase in Operating Income		Rate Action	Annual Increase (Decrease) in Operating Income		EDIT Impact		Annual Increase (Decrease) in Operating Income Excluding EDIT
	(In thousands)			(In thousands)
Annual formula rate mechanisms	$	17,077	Annual formula rate mechanisms	$	70,488	$	43,638	$	114,126
Rate case filings	—		Rate case filings	5,938		7,379		13,317
Other rate activity	—		Other rate activity	(370)		—		(370)
	$	17,077		$	76,056	$	51,017	$	127,073

The following ratemaking efforts seeking ~~$13.3~~$132.6 million in increased annual operating income were in progress as of ~~December 31, 2017:~~June 30, 2022:

Division Rate Action Jurisdiction
Operating Income
Requested
(In thousands)
Colorado-Kansas
Rate Case ⁽¹⁾
Colorado $ 2,916
GSRS Kansas 821
Ad Valorem Kansas 457
Kentucky/Mid-States Rate Case Kentucky 4,778

ARM True-Up ⁽²⁾
Tennessee 850
Louisiana RSC Trans La 1,195
Mid-Tex
Rate Case ⁽³⁾
City of Dallas 2,247
$ 13,264

~~(1)~~Division

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

Rate Action

Jurisdiction

Operating Income Requested

(In thousands)

~~(2)~~

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

~~(3)~~

~~The Company extended the deadline for the City of Dallas to act until February 15, 2018.~~

Kentucky/Mid-States

Infrastructure Mechanism

Virginia

477

Kentucky/Mid-States

Formula Rate Mechanism

Tennessee (1)

3,662

Louisiana

Formula Rate Mechanism

Louisiana (2)

17,650

Mid-Tex

Formula Rate Mechanism

Mid-Tex Cities

92,615

Mississippi

Infrastructure Mechanism

Mississippi

10,006

West Texas

Formula Rate Mechanism

West Texas Cities

8,208

132,618

(1) The Tennessee Public Utility Commission approved the ARM filing on June 20, 2022 for an increase in operating income of $2.5 million with rates effective July 1, 2022.

(2) The Company implemented the requested amount, subject to refund, on July 1, 2022 and anticipates resolving the RSC filing during the fourth quarter of fiscal 2022.

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

~~Annual Formula Rate Mechanisms~~

~~State~~

~~Infrastructure Programs~~

~~Formula Rate Mechanisms~~

~~Colorado~~

System Safety and Integrity Rider (SSIR)

—

Kansas

Gas System Reliability Surcharge (GSRS), System Integrity Program (SIP)

—

Kentucky

Pipeline Replacement Program (PRP)

—

Louisiana

(1)

Rate Stabilization Clause (RSC)

Mississippi

System Integrity Rider (SIR)

Stable Rate Filing (SRF)~~, Supplemental Growth Filing (SGR)~~

Tennessee

—(1)

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)~~

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

The following annual formula rate mechanisms were approved during the ~~three~~nine months ended ~~December 31, 2017:~~June 30, 2022:


Division	Jurisdiction	Test Year Ended	Increase (Decrease) in Annual Operating Income		EDIT Impact		Increase (Decrease) in Annual Operating Income Excluding EDIT		Effective Date
			(In thousands)
2022 Filings:




West Texas	Amarillo, Lubbock, Dalhart and Channing	12/31/2021	$	6,122	$	—	$	6,122	06/11/2022
West Texas	Triangle	12/31/2021	1,549		—		1,549		06/11/2022
West Texas	Environs	12/31/2021	1,221		—		1,221		06/11/2022
Mid-Tex	ATM Cities	12/31/2021	12,815		—		12,815		06/10/2022
Mid-Tex	Environs	12/31/2021	5,646		—		5,646		06/10/2022
Mid-Tex	DARR (1)	09/30/2021	13,201		—		13,201		05/25/2022

Colorado-Kansas	Kansas SIP	12/31/2021	623		—		623		04/01/2022
Colorado-Kansas	Kansas GSRS	09/30/2021	1,820		—		1,820		02/01/2022
Colorado-Kansas	Colorado SSIR	12/31/2022	2,610		—		2,610		01/01/2022
Mid-Tex	Mid-Tex Cities RRM	12/31/2020	21,673		33,851		55,524		12/01/2021
West Texas	West Texas Cities RRM	12/31/2020	151		3,347		3,498		12/01/2021
Mississippi	Mississippi - SIR	10/31/2022	8,354		2,123		10,477		11/01/2021
Mississippi	Mississippi - SRF	10/31/2022	(5,624)		4,317		(1,307)		11/01/2021
Kentucky/Mid-States	Virginia - SAVE	09/30/2022	327		—		327		10/01/2021

Total 2022 Filings			$	70,488	$	43,638	$	114,126

Division Jurisdiction
Test Year
Ended

Increase in
Annual
Operating
Income

Effective
Date
(In thousands)
2018 Filings:
Colorado-Kansas Colorado SSIR 12/31/2018 $ 2,228
12/20/2017
Mississippi Mississippi - SIR 10/31/2018 7,658
12/05/2017
Mississippi
Mississippi - SGR ⁽¹⁾
10/31/2018 1,245
12/05/2017
Mississippi
Mississippi - SRF ⁽¹⁾
10/31/2018 —
12/05/2017
Kentucky/Mid-States Kentucky - PRP 09/30/2018 5,638
10/27/2017
Kentucky/Mid-States
Virginia - SAVE ⁽²⁾
09/30/2017 308
10/01/2017
Total 2018 Filings $ 17,077

(1) The rate increase for this filing was approved based on the effective date herein; however, the new rates will be implemented beginning September 1, 2022.


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


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

Rate Case Filings

A rate case is a formal request from Atmos Energy to a regulatory authority to increase rates that are charged to our customers. Rate cases may also be initiated when the regulatory authorities request us to justify our rates. This process is referred to as a “show cause” action. Adequate rates are intended to provide for recovery of the Company’s costs as well as a fair rate of return and ensure that we continue to deliver reliable, reasonably priced natural gas service safely to our customers.

~~There was no~~

The following table summarizes the rate ~~case activity~~cases that were completed during the ~~three~~nine months ended ~~December 31, 2017.~~

June 30, 2022.



Division	State	Increase in Annual Operating Income		EDIT Impact		Increase in Annual Operating Income Excluding EDIT		Effective Date
		(In thousands)
2022 Rate Case Filings:


Kentucky/Mid-States	Kentucky (1)	$	5,938	$	7,379	$	13,317	05/20/2022


Total 2022 Rate Case Filings		$	5,938	$	7,379	$	13,317

(1) The rate case outcome for Kentucky is inclusive of the fiscal 2022 pipeline replacement program.

Other Ratemaking Activity

The following table summarizes other ratemaking activity during the nine months ended June 30, 2022.

~~Other Ratemaking Activity~~

~~The Company had no other ratemaking activity during the three months ended December 31, 2017.~~

Division

Jurisdiction

Rate Activity

Decrease in
Annual
Operating
Income

Effective
Date

(In thousands)

2022 Other Rate Activity:

Colorado-Kansas

Kansas

Ad Valorem (1)

(370)

02/01/2022

Total 2022 Other Rate Activity

(370)

(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 rate.

Pipeline and Storage Segment

Our pipeline and storage segment consists of the pipeline and storage operations of our Atmos Pipeline–Texas Division (APT) and our natural gas transmission operations in Louisiana. APT is one of the largest intrastate pipeline operations in Texas

with a heavy concentration in the established natural gas producing areas of central, northern ~~eastern~~ and ~~western~~eastern Texas, extending into or near the major producing areas of the Barnett Shale, the Texas Gulf Coast and the ~~Delaware and Midland Basins~~Permian Basin 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. Over 80 percent of this segment’s revenues are derived from these services. As part of its pipeline operations, APT ~~manages~~owns and operates five underground storage facilities in Texas.

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

Our pipeline and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our Texas and Louisiana service areas. Natural gas prices do not directly impact the results of this segment as revenues are derived from the transportation and storage of natural gas. However, natural gas prices and demand for natural gas could influence the level of drilling activity in the ~~markets~~supply areas that we serve, which may influence the level of throughput we may be able to transport on our ~~pipeline.~~pipelines. Further, natural gas price differences between the various hubs that we serve in Texas could influence the volumes of gas transported for shippers through our Texas pipeline system and ~~the~~ rates for such transportation.

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

APT annually uses GRIP to recover capital costs incurred in the prior calendar year. ~~Following the conclusion of its rate case in August 2017,~~On February 11, 2022, APT made a GRIP filing that covered changes in net ~~investment~~property, plant and equipment investments from ~~October~~January 1, ~~2016~~2021 through December 31, ~~2016~~2021 with a requested increase in operating income of ~~$29.0~~$78.8 million. On ~~December 5, 2017,~~May 18, 2022, the ~~filing was approved.~~

~~On December 21, 2016, the Louisiana Public Service~~Texas Railroad Commission approved ~~an annual increase of five percent to~~ the ~~demand fee charged by our natural gas transmission pipeline for each of the next 10 years, effective October 1, 2017.~~Company's GRIP filing.

Three Months Ended ~~December 31, 2017~~June 30, 2022 compared with Three Months Ended ~~December 31, 2016~~June 30, 2021

Financial and operational highlights for our pipeline and storage segment for the three months ended ~~December 31, 2017~~June 30, 2022 and ~~2016~~2021 are presented below.


	Three Months Ended June 30
	2022		2021		Change
	(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue	$	144,970	$	126,022	$	18,948
Third-party transportation revenue	35,939		33,565		2,374

Other revenue	2,503		3,400		(897)
Total operating revenues	183,412		162,987		20,425
Total purchased gas cost	(1,347)		691		(2,038)

Operating expenses	96,231		97,029		(798)
Operating income	88,528		65,267		23,261
Other non-operating income	6,555		4,827		1,728
Interest charges	13,849		12,422		1,427
Income before income taxes	81,234		57,672		23,562

Income tax expense	10,088		8,550		1,538
Net income	$	71,146	$	49,122	$	22,024
Gross pipeline transportation volumes — MMcf	175,117		187,408		(12,291)
Consolidated pipeline transportation volumes — MMcf	146,422		153,166		(6,744)

Three Months Ended December 31
2017 2016 Change
(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue $ 93,898
$ 82,468
$ 11,430
Third-party transportation revenue 28,931
22,220
6,711
Other revenue 3,634
5,264
(1,630 )
Total operating revenues 126,463
109,952
16,511
Total purchased gas cost 912
355
557
Gross profit 125,551
109,597
15,954
Operating expenses 56,746
54,572
2,174
Operating income 68,805
55,025
13,780
Miscellaneous expense (635 ) (361 ) (274 )
Interest charges 10,141
9,912
229
Income before income taxes 58,029
44,752
13,277
One-time, non-cash income tax benefit

(21,733 ) —
(21,733 )
Income tax expense 14,729
16,078
(1,349 )
Net income $ 65,033
$ 28,674
$ 36,359
Gross pipeline transportation volumes — MMcf 213,137
186,780
26,357
Consolidated pipeline transportation volumes — MMcf 155,105
134,976
20,129

~~Income before~~Operating income ~~taxes~~ for our pipeline and storage segment increased ~~30 percent,~~36 percent. Significant drivers for the change in operating income include:

•a $21.0 million increase due to rate adjustments from the GRIP filings approved in May 2021 and 2022. The increase in rates was driven by increased safety and reliability spending.

•a $6.1 million decrease in system maintenance expense primarily due to timing of spending.

Partially offset by:

•a ~~$16.0~~$4.5 million increase in ~~gross profit,~~depreciation and property tax expenses associated with increased capital investments.

Nine Months Ended June 30, 2022compared with Nine Months Ended June 30, 2021

Financial and operational highlights for our pipeline and storage segment for the nine months ended June 30, 2022 and 2021 are presented below.



	Nine Months Ended June 30
	2022		2021		Change
	(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue	$	401,455	$	371,871	$	29,584
Third-party transportation revenue	98,696		93,894		4,802
Other revenue	9,926		11,103		(1,177)
Total operating revenues	510,077		476,868		33,209
Total purchased gas cost	(3,075)		(440)		(2,635)

Operating expenses	265,431		244,206		21,225
Operating income	247,721		233,102		14,619
Other non-operating income	18,005		13,658		4,347
Interest charges	38,923		35,799		3,124
Income before income taxes	226,803		210,961		15,842

Income tax expense	29,871		33,435		(3,564)
Net income	$	196,932	$	177,526	$	19,406
Gross pipeline transportation volumes — MMcf	581,545		614,594		(33,049)
Consolidated pipeline transportation volumes — MMcf	411,884		428,331		(16,447)

Operating income for our pipeline and storage segment increased six percent. Increased refunds of excess deferred taxes to customers decreased period-over-period operating income by $13.3 million and reduced the interim effective income tax rate for this segment to 13.2% compared to 15.8% in the prior year period. Additional drivers for the change in operating income include:

•a $49.4 million increase due to rate adjustments from the GRIP filings approved in May 2021 and 2022. The increase in rates was driven by increased safety and reliability spending.

Partially offset by by:

•a ~~$2.2~~$7.3 million increase in ~~operating expenses. The increase~~system maintenance expense primarily due to spending on hydrostatic testing.

•a $2.4 million net decrease in ~~gross profit~~APT's thru-system activities primarily ~~reflects a $13.9~~associated with lower volumes driven by increased competing takeaway capacity in the Permian Basin and tighter regional spreads.

•an $11.1 million increase in rates from the approved APT rate case and the GRIP filing approved in December 2017. Additionally, average transportation fees increased as a result of higher basis spreads creating a $4.1 million increase in gross profit and transport volumes increased due to incremental throughput on the North Texas pipeline, which was acquired on December 20, 2016.

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

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

~~Natural Gas Marketing Segment~~

Through December 31, 2016, we were engaged in an unregulated natural gas marketing business, which was conducted by Atmos Energy Marketing (AEM). AEM’s primary business was to aggregate and purchase gas supply, arrange transportation and storage logistics and ultimately deliver gas to customers at competitive prices. Additionally, AEM utilized proprietary and customer–owned transportation and storage assets to provide various services its customers requested.

As more fully described in Note 13, effective January 1, 2017, we sold all of the equity interests of AEM to CenterPoint Energy Services, Inc. (CES), a subsidiary of CenterPoint Energy Inc. As a result of the sale, Atmos Energy has fully exited the nonregulated natural gas marketing business. Accordingly, net income of $11.0 million for AEM is reported as discontinued operations for the three months ended December 31, 2016.

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,~~Additionally, we have a $1.5 billion commercial paper program and ~~three~~four committed revolving credit facilities with a$2.5 billion in total availability from third-party ~~lenders of approximately $1.5 billion.~~lenders. The commercial paper program and credit facilities provide cost-effective, short-term financing until it can be replaced with a balance of long-term debt and equity financing that achieves the Company's desired capital structure with an ~~equity-to-capitalization~~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.

We have a shelf registration statement on file with the Securities and Exchange Commission (SEC) that allows us to issue up to $5.0 billion in common stock and/or debt securities. As of the date of this report, $2.2 billion of securities were available for issuance under the shelf registration statement, which expires June 29, 2024.

We also have an at-the-market (ATM) equity sales program that allows us to issue and sell shares of our common stock up to an aggregate offering price of $1.0 billion (including shares of common stock that may be sold pursuant to forward sale agreements entered into in connection with the ATM equity sales program), which expires June 29, 2024. As of June 30, 2022, $663.0 million of equity was available for issuance under this ATM equity sales program. Additionally, as of June 30, 2022, we had $700.9 million in proceeds from executed forward sale agreements available through December 29, 2023. Additional details are summarized in Note 7 to the unaudited condensed consolidated financial statements.

The liquidity provided by these sources is expected to be sufficient to fund the Company's working capital needs and capital expenditure program for the remainder of fiscal year ~~2018 and beyond. Refer~~2022. Additionally, we expect to ~~the TCJA impact section above regarding anticipated impacts on our liquidity, capital resources and cash flows.~~

~~To support our capital market activities, we have a registration statement on file with the SEC that permits us~~continue to issue a total of $2.5 billion in common stock and/or debt securities. Under the shelf registration statement, we recently filed a prospectus supplement for an at–the-market (ATM) equity distribution program under which we may issue and sell, shares of our common stock, upbe able to ~~an aggregate offering price of $500 million. At December 31, 2017, approximately $1.2 billion of securities remained available for issuance under the shelf registration statement.~~obtain financing upon reasonable terms as necessary.

The following table presents our capitalization inclusive of short-term debt and the current portion of long-term debt as of ~~December 31, 2017,~~June 30, 2022, September 30, ~~2017~~2021 and ~~December 31, 2016:~~June 30, 2021:


	June 30, 2022				September 30, 2021				June 30, 2021
	(In thousands, except percentages)
Short-term debt	$	—	—	%	$	—	—	%	$	—	—	%
Long-term debt (1)	7,960,594		46.2	%	7,330,657		48.1	%	7,328,947		48.5	%
Shareholders’ equity (2)	9,268,171		53.8	%	7,906,889		51.9	%	7,773,758		51.5	%
Total	$	17,228,765	100.0	%	$	15,237,546	100.0	%	$	15,102,705	100.0	%

December 31, 2017 September 30, 2017 December 31, 2016
(In thousands, except percentages)
Short-term debt $ 336,816
4.2 % $ 447,745
6.0 % $ 940,747
13.1 %
Long-term debt 3,067,469
38.5 % 3,067,045
41.4 % 2,564,199
35.6 %
Shareholders’ equity 4,563,620
57.3 % 3,898,666
52.6 % 3,698,975
51.3 %
Total $ 7,967,905
100.0 % $ 7,413,456
100.0 % $ 7,203,921
100.0 %
(1) Inclusive of our finance leases.

(2) Excluding the $2.2 billion of incremental financing issued to pay for the purchased gas costs incurred during Winter Storm Uri, our equity capitalization ratio was 61.7% at June 30, 2022 and 60.6% at September 30, 2021.

Cash Flows

Our internally generated funds may change in the future due to a number of factors, some of which we cannot control. These factors include regulatory changes, ~~prices~~the price for our ~~products and~~ services, demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks and other factors.

Cash flows from operating, investing and financing activities for the ~~three~~nine months ended ~~December 31, 2017~~June 30, 2022 and ~~2016~~2021 are presented below.


	Three Months Ended December 31										Nine Months Ended June 30
	2017			2016			Change				2022		2021		Change
	(In thousands)										(In thousands)
Total cash provided by (used in)										Total cash provided by (used in)
Operating activities	$	173,238		$	116,963		$	56,275		Operating activities	$	929,316	$	(1,158,467)	$	2,087,783
Investing activities	(381,372		)	(392,137		)	10,765			Investing activities	(1,714,569)		(1,352,317)		(362,252)
Financing activities	236,475			272,264			(35,789		)	Financing activities	996,605		3,014,597		(2,017,992)
Change in cash and cash equivalents	28,341			(2,910		)	31,251			Change in cash and cash equivalents	211,352		503,813		(292,461)
Cash and cash equivalents at beginning of period	26,409			47,534			(21,125		)	Cash and cash equivalents at beginning of period	116,723		20,808		95,915
Cash and cash equivalents at end of period	$	54,750		$	44,624		$	10,126		Cash and cash equivalents at end of period	$	328,075	$	524,621	$	(196,546)

Cash flows from operating activities

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

For the ~~three~~nine months ended ~~December 31, 2017,~~June 30, 2022, we generated cash flow ~~of $173.2 million~~ from operating activities of $929.3 million compared with ~~$117.0 million~~$1.2 billion of cash flows used from operating activities for the ~~three~~nine months ended ~~December 31, 2016. The $56.2 million increase~~June 30, 2021. Excluding the $2.1 billion incurred in the prior-year period for gas costs incurred during Winter Storm Uri, operating cash ~~flows reflects~~flow decreased $0.8 million primarily due to a $102.8 million refund of excess deferred tax liabilities, mostly offset by the timing of gas cost recoveries and the positive ~~cash~~ effects of successful rate case outcomes achieved in fiscal ~~2017 and changes in working capital, primarily as a result of higher recoveries of deferred gas cost due to higher distribution sales volumes in the current quarter compared to the prior-year quarter.~~2021.

Cash flows from investing activities

~~In recent years, we have incurred~~Our capital expenditures are primarily used to ~~support~~improve the safety and reliability of our distribution and transmission system through pipeline replacement and system modernization and ~~integrity enhancement efforts, expand our natural gas distribution services~~to enhance and expand our ~~intrastate pipeline network.~~system to meet customer needs. Over the last three fiscal years, approximately 8088 percent of our capital spending has been committed to improving the safety and reliability of our system.

For the ~~three~~nine months ended ~~December 31, 2017,~~June 30, 2022, cash used for investing activities was ~~$381.4~~$1,714.6 million compared to ~~$392.1~~$1,352.3 million infor the ~~prior-year period.~~nine months ended June 30, 2021. Capital spending increased ~~by $85.3~~$368.1 million. Capital spending in our distribution segment increased $216.5 million, ~~or 29 percent,~~primarily as a result of ~~planned increases in our distribution segment to repair~~increased system modernization and ~~replace vintage pipe, and increases in~~customer growth spending. Capital spending in our pipeline and storage segment increased $151.6 million primarily due to ~~improve the~~increased spending for pipeline system safety and reliability ~~of gas service to our local distribution company customers. These increases were offset by cash outflows from investing activities~~ in ~~the three months ended December 31, 2016, for the purchase of the North Texas Pipeline for $85.7 million and $10.3 million related to the purchase of available-for-sale securities.~~Texas.

Cash flows from financing activities

For the ~~three~~nine months ended ~~December 31, 2017,~~June 30, 2022, our financing activities provided ~~$236.5 million~~$1.0 billion of cash compared with ~~$272.3 million in the prior-year period. The $35.8 million decrease in~~$3.0 billion of cash provided by financing activities ~~is primarily due to increased operating cash flow and lower cash used~~ in ~~investing activities.~~the prior-year period.

~~During~~In the ~~first quarter,~~nine months ended June 30, 2022, we ~~used $395.1 million~~received $1.5 billion in net proceeds from ~~equity financing~~the issuance of long-term debt and equity. We completed a public offering of $600 million of 2.85% senior notes due 2052 and received net proceeds from the offering, after the underwriting discount and offering expenses, of $589.8 million. We also completed a public offering of $200 million of 2.625% senior notes due 2029, and received net proceeds of $200.8 million that were used to ~~reduce short-term debt,~~repay our $200 million floating-rate term loan. Additionally, during the nine months ended June 30, 2022, we settled 6,932,722 shares that had been sold on a forward basis for net proceeds of $675.3 million. The net proceeds were used primarily to support capital spending and for other general corporate purposes.

Cash dividends increased due to an 8.8 percent increase in our dividend rate and an increase in shares outstanding.

In the nine months ended June 30, 2021, we received $3.3 billion in net proceeds from the issuance of long-term debt and equity. The net proceeds were used primarily for the payment of natural gas costs incurred during Winter Storm Uri, to support capital spending and for other general corporate purposes. Cash dividends increased due to ~~a 7.8%~~an 8.7 percent increase in our dividend rate and an increase in shares outstanding.

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

The following table summarizes our share issuances for the ~~three~~nine months ended ~~December 31, 2017~~June 30, 2022 and ~~2016:~~2021:


	Three Months Ended December 31			Nine Months Ended June 30
	2017	2016		2022	2021
Shares issued:			Shares issued:
Direct Stock Purchase Plan	38,209	27,071	Direct Stock Purchase Plan	52,907	61,561
1998 Long-Term Incentive Plan	235,960	365,471	1998 Long-Term Incentive Plan	427,819	241,340
Retirement Savings Plan and Trust	24,905	95,991	Retirement Savings Plan and Trust	55,554	63,992
At-the-Market (ATM) Equity Distribution Program	—	690,812

Equity Issuance	4,558,404	—	Equity Issuance	6,932,722	4,537,669
Total shares issued	4,857,478	1,179,345	Total shares issued	7,469,002	4,904,562

Credit Ratings

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

Our debt is rated by two rating agencies: Standard & Poor’s Corporation (S&P) and Moody’s Investors Service (Moody’s). As of ~~December 31, 2017, both rating agencies maintained a stable outlook. Our~~June 30, 2022, our outlook and current debt ratings, which are all considered investment grade ~~and~~ are as follows:

S&P

Moody’s

Senior unsecured long-term debt

AA-

A2A1

Short-term debt

~~A-1~~A-2

P-1

Outlook

Negative

Stable

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

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

Debt Covenants

We were in compliance with all of our debt covenants as of ~~December 31, 2017.~~June 30, 2022. Our debt covenants are described in greater detail in Note 56 to the unaudited condensed consolidated financial statements.

Contractual Obligations and Commercial Commitments

Except as noted in Note 910 to the unaudited condensed consolidated financial statements, there were no significant changes in our contractual obligations and commercial commitments during the ~~three~~nine months ended ~~December 31, 2017.~~

June 30, 2022.

Risk Management Activities

In our distribution and pipeline and storage segments, we use a combination of physical storage, fixed physical contracts and fixed financial contracts to reduce our exposure to unusually large winter-period gas price increases. Additionally, we manage interest rate risk by periodically entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings. Through December 31, 2016, we managed our exposure to the risk of natural gas price changes in our natural gas marketing segment by locking in our gross profit margin through a combination of storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties.

The following table shows the components of the change in fair value of our financial instruments for the three and nine months ended ~~December 31, 2017~~June 30, 2022 and ~~2016:~~2021:


	Three Months Ended December 31							Three Months Ended June 30				Nine Months Ended June 30
	2017			2016				2022		2021		2022		2021
	(In thousands)							(In thousands)
Fair value of contracts at beginning of period	$	(109,159	)	$	(279,543	)	Fair value of contracts at beginning of period	$	282,400	$	327,096	$	225,417	$	78,663
Contracts realized/settled	1,160			9,963			Contracts realized/settled	(260)		13		31,224		980
Fair value of new contracts	(569		)	963			Fair value of new contracts	1,834		4,030		3,550		4,356
Other changes in value	(7,961		)	146,895			Other changes in value	203,985		(97,622)		227,768		149,518
Fair value of contracts at end of period	(116,529		)	(121,722		)	Fair value of contracts at end of period	487,959		233,517		487,959		233,517
Netting of cash collateral	—			13,697			Netting of cash collateral	—		—		—		—
Cash collateral and fair value of contracts at period end	$	(116,529	)	$	(108,025	)	Cash collateral and fair value of contracts at period end	$	487,959	$	233,517	$	487,959	$	233,517

The fair value of our financial instruments at ~~December 31, 2017~~June 30, 2022 is presented below by time period and fair value source:


	Fair Value of Contracts at June 30, 2022
	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	$	186,643	$	246,826	$	54,490	$	—	$	487,959
Prices based on models and other valuation methods	—		—		—		—		—
Total Fair Value	$	186,643	$	246,826	$	54,490	$	—	$	487,959

Fair Value of Contracts at December 31, 2017
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 $ (2,282 ) $ (114,247 ) $ —
$ —
$ (116,529 )
Prices based on models and other valuation methods —
—
—
—
—
Total Fair Value $ (2,282 ) $ (114,247 ) $ —
$ —
$ (116,529 )

~~Pension and Postretirement Benefits Obligations~~

For the three months ended December 31, 2017 and 2016, our total net periodic pension and other benefits costs were $9.2 million and $11.6 million. A substantial portion of those costs is recoverable through our rates; however, a portion of these costs is capitalized into our rate base. The remaining costs are recorded as a component of operation and maintenance expense.

Our fiscal 2018 costs were determined using a September 30, 2017 measurement date. As of September 30, 2017, interest and corporate bond rates were higher than the rates as of September 30, 2016. Therefore, we increased the discount rate used to measure our fiscal 2018 net periodic cost from 3.73 percent to 3.89 percent. We lowered the expected return on plan assets to 6.75 percent in the determination of our fiscal 2018 net periodic pension cost based upon expected market returns for our targeted asset allocation. As a result of the net impact of changes in these and other assumptions, we expect our fiscal 2018 net periodic pension cost to be approximately 25 percent lower than fiscal 2017.

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

For the three months ended December 31, 2017 we contributed $3.9 million to our postretirement medical plans. We anticipate contributing a total of between $10 million and $20 million to our postretirement plans during fiscal 2018.

The projected pension liability, future funding requirements and the amount of pension expense or income recognized for the plans are subject to change, depending upon the actuarial value of plan assets in the plans and the determination of future benefit obligations as of each subsequent actuarial calculation date. These amounts will be determined by actual investment returns, changes in interest rates, values of assets in the plans and changes in the demographic composition of the participants in the plans.

OPERATING STATISTICS AND OTHER INFORMATION

The following tables present certain operating statistics for our distribution and pipeline and storage segments for the ~~three-month periods~~three and nine months ended ~~December 31, 2017~~June 30, 2022 and ~~2016.~~2021.

Distribution Sales and Statistical Data

Three Months Ended
December 31
2017 2016
METERS IN SERVICE, end of period
Residential 2,956,247
2,923,480
Commercial 270,184
268,574
Industrial 1,675
1,693
Public authority and other 8,418
8,359
Total meters 3,236,524
3,202,106

INVENTORY STORAGE BALANCE — Bcf 55.6
56.7
SALES VOLUMES — MMcf⁽¹⁾

Gas sales volumes
Residential 48,948
41,500
Commercial 26,949
23,736
Industrial 8,458
7,432
Public authority and other 1,952
1,762
Total gas sales volumes 86,307
74,430
Transportation volumes 39,859
39,065
Total throughput 126,166
113,495
OPERATING REVENUES (000’s)⁽¹⁾

Gas sales revenues
Residential $ 556,520
$ 481,673
Commercial 223,580
200,488
Industrial 33,413
30,031
Public authority and other 13,561
12,109
Total gas sales revenues 827,074
724,301
Transportation revenues 25,362
22,481
Other gas revenues 8,356
7,874
Total operating revenues $ 860,792
$ 754,656
Average cost of gas per Mcf sold $ 5.37
$ 5.31

~~See footnote following these tables.~~


	Three Months Ended June 30		Nine Months Ended June 30
	2022	2021	2022	2021
METERS IN SERVICE, end of period
Residential	3,138,790	3,095,895	3,138,790	3,095,895
Commercial	281,839	281,628	281,839	281,628
Industrial	1,643	1,664	1,643	1,664
Public authority and other	8,204	8,264	8,204	8,264
Total meters	3,430,476	3,387,451	3,430,476	3,387,451

INVENTORY STORAGE BALANCE — Bcf	49.4	46.4	49.4	46.4
SALES VOLUMES — MMcf (1)
Gas sales volumes
Residential	19,760	17,590	144,695	162,154
Commercial	17,012	16,233	83,307	86,559
Industrial	6,988	6,260	22,848	20,650
Public authority and other	1,194	1,269	5,867	6,328
Total gas sales volumes	44,954	41,352	256,717	275,691
Transportation volumes	36,503	36,679	125,993	125,704
Total throughput	81,457	78,031	382,710	401,395

Pipeline and Storage Operations Sales and Statistical Data


	Three Months Ended December 31					Three Months Ended June 30		Nine Months Ended June 30
	2017		2016			2022	2021	2022	2021
CUSTOMERS, end of period					CUSTOMERS, end of period
Industrial	93		90		Industrial	96	95	96	95
Other	240		222		Other	197	202	197	202
Total	333		312		Total	293	297	293	297

INVENTORY STORAGE BALANCE — Bcf	1.1		1.7		INVENTORY STORAGE BALANCE — Bcf	0.7	0.4	0.7	0.4
PIPELINE TRANSPORTATION VOLUMES — MMcf⁽¹⁾	213,137		186,780		PIPELINE TRANSPORTATION VOLUMES — MMcf (1)	175,117	187,408	581,545	614,594
OPERATING REVENUES (000’s)⁽¹⁾	$	126,463	$	109,952

Note to preceding tables:


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

RECENT ACCOUNTING DEVELOPMENTS

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



Item 3.			Quantitative and Qualitative Disclosures About Market Risk

Information regarding our quantitative and qualitative disclosures about market risk are disclosed in Item 7A in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017.~~2021. During the ~~three~~nine months ended ~~December 31, 2017,~~June 30, 2022, there were no material changes in our quantitative and qualitative disclosures about market risk.



Item 4.			Controls and Procedures

Management’s Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the Company’s disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act). Based on this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective as of ~~December 31, 2017~~June 30, 2022 to provide reasonable assurance that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified by the SEC’s rules and forms, including a reasonable level of assurance that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

We did not make any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the ~~first~~third quarter of the fiscal year ended September 30, ~~2018~~2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION



Item 1.			Legal Proceedings

During the ~~three~~nine months ended ~~December 31, 2017,~~June 30, 2022, except as noted in Note 10 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 1113 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017.~~2021. 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 1A.			Risk Factors

There were no material changes from the risk factors disclosed under the heading “Risk Factors” in Item 1A in the Annual Report on Form 10-K for the year ended September 30, 2021.



Item 6.			Exhibits

~~A list of~~The following exhibits ~~required by Item 601 of Regulation S-K and~~are filed as part of this ~~report is set forth in the Exhibits Index, which immediately precedes such exhibits.~~

Quarterly Report.

~~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.~~



Exhibit Number		Description	Page Number or Incorporation by Reference to
3.1		Restated Articles of Incorporation of Atmos Energy Corporation - Texas (As Amended Effective February 3, 2010)	A~~TMOS~~ E~~NERGY~~ C~~ORPORATION~~ ~~(Registrant)~~Exhibit 3.1 to Form 10-Q dated March 31, 2010 (File No. 1-10042)
3.2		Restated Articles of Incorporation of Atmos Energy Corporation - Virginia (As Amended Effective February 3, 2010)	~~By:~~ ~~/s/ CHRISTOPHER T. FORSYTHE~~Exhibit 3.2 to Form 10-Q dated March 31, 2010 (File No. 1-10042)
	~~Christopher T. Forsythe~~ ~~Senior Vice President and Chief Financial Officer~~ ~~(Duly authorized signatory)~~

~~Date: February 6, 2018~~

~~EXHIBITS INDEX~~

~~Item 6~~

3.3

~~Exhibit~~

~~Number~~

~~Description~~

~~Page Number or~~

~~Incorporation by~~

~~Reference to~~

~~2.1~~

~~Membership Interest Purchase Agreement by~~Amended and ~~between~~Restated Bylaws of Atmos Energy ~~Holdings, Inc. as Seller and CenterPoint Energy Services, Inc. as Buyer, dated as~~Corporation (as of ~~October 29, 2016~~

February 5, 2019)

Exhibit ~~2.1~~3.1 to Form 8-K dated ~~October 29, 2016~~February 5, 2019 (File No. 1-10042)

1015

Equity Distribution Agreement, dated as of November 14, 2017, among Atmos Energy Corporation, Goldman Sachs & Co. LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley & Co. LLC, and J.P. Morgan Securities LLC

~~Exhibit 1.1 to Form 8-K dated November 14, 2017 (File No. 1-10042)~~

~~Computation of ratio of earnings to fixed charges~~

Letter regarding unaudited interim financial information

Rule 13a-14(a)/15d-14(a) Certifications

Section 1350 Certifications*

101.INS

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101.SCH

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101.CAL

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101.DEF

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104

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*			These certifications, which were made pursuant to 18 U.S.C. Section 1350 by the Company’s Chief Executive Officer and Chief Financial Officer, furnished as Exhibit 32 to this Quarterly Report on Form 10-Q, will not be deemed to be filed with the Commission or incorporated by reference into any filing by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates such certifications by reference.

SIGNATURE

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


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

Date: August 3, 2022



	Three Months Ended December 31, 2016
	Distribution			Pipeline and Storage			Natural Gas Marketing		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	754,266		$	25,902		$	—	$	—		$	780,168
Intersegment revenues	390			84,050			—		(84,440		)	—
Total operating revenues	754,656			109,952			—		(84,440		)	780,168
Purchased gas cost	395,346			355			—		(84,396		)	311,305
Operation and maintenance expense	92,714			32,268			—		(44		)	124,938
Depreciation and amortization expense	61,157			15,801			—		—			76,958
Taxes, other than income	50,546			6,503			—		—			57,049
Operating income	154,893			55,025			—		—			209,918
Miscellaneous expense	(633		)	(361		)	—		—			(994		)
Interest charges	21,118			9,912			—		—			31,030
Income from continuing operations before income taxes	133,142			44,752			—		—			177,894
Income tax expense	47,778			16,078			—		—			63,856
Income from continuing operations	85,364			28,674			—		—			114,038
Income from discontinued operations, net of tax	—			—			10,994		—			10,994
Net income	$	85,364		$	28,674		$	10,994	$	—		$	125,032
Capital expenditures	$	222,484		$	75,478		$	—	$	—		$	297,962



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



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



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



	Amortized Cost		Gross Unrealized Gain		Gross Unrealized Loss			Fair Value
	(In thousands)
As of December 31, 2017
Domestic equity mutual funds	$	27,171	$	8,850	$	(14	)	$	36,007
Foreign equity mutual funds	4,725		2,333		—			7,058
Bond mutual funds	16,461		—		(102		)	16,359
Bonds	30,936		6		(81		)	30,861
Money market funds	614		—		—			614
	$	79,907	$	11,189	$	(197	)	$	90,899
As of September 30, 2017
Domestic equity mutual funds	$	25,361	$	8,920	$	—		$	34,281
Foreign equity mutual funds	4,581		2,235		—			6,816
Bond mutual funds	16,391		2		(22		)	16,371
Bonds	29,074		46		(16		)	29,104
Money market funds	1,837		—		—			1,837
	$	77,244	$	11,203	$	(38	)	$	88,409




	Three Months Ended December 31, 2016
	(In thousands)

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



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