UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



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



¨☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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)

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 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.~~



Class		Shares Outstanding
Common stock	No Par Value	~~110,967,636~~144,487,306

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~~
Mcf		Thousand cubic feet
MMcf		Million cubic feet
Moody’s		Moody’s Investors Services, Inc.
~~PPA~~		~~Pension Protection Act of 2006~~
PRP		Pipeline Replacement Program
RRC		Railroad Commission of Texas
RRM		Rate Review Mechanism
RSC		Rate Stabilization Clause
S&P		Standard & Poor’s Corporation
SAVE		Steps to Advance Virginia Energy
SEC		United States Securities and Exchange Commission
~~SGR~~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

(In thousands, except

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

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended March 31
	2023		2022
	(Unaudited) (In thousands)
Cash Flows From Operating Activities
Net income	$	629,531	$	574,208
Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization expense	294,337		261,230

Deferred income taxes	59,060		40,122



Other	(27,496)		(12,812)
Net assets / liabilities from risk management activities	(1,482)		(4,172)
Net change in Winter Storm Uri current regulatory asset (See Note 8)	2,021,889		—
Net change in other operating assets and liabilities	(83,123)		(218,092)
Net cash provided by operating activities	2,892,716		640,484
Cash Flows From Investing Activities
Capital expenditures	(1,415,349)		(1,190,029)


Debt and equity securities activities, net	(4,560)		3,758

Other, net	9,519		4,302
Net cash used in investing activities	(1,410,390)		(1,181,969)
Cash Flows From Financing Activities
Net decrease in short-term debt	(184,967)		—
Net proceeds from equity issuances	359,683		594,320
Issuance of common stock through stock purchase and employee retirement plans	7,910		8,010
Proceeds from issuance of long-term debt	797,258		798,802

Proceeds from term loan	2,020,000		—
Repayment of term loan	(2,020,000)		—
Repayment of long-term debt	(2,200,000)		(200,000)

Cash dividends paid	(210,725)		(183,944)
Debt issuance costs	(7,864)		(8,196)
Other	—		(1,735)

Net cash provided by (used in) financing activities	(1,438,705)		1,007,257
Net increase in cash and cash equivalents	43,621		465,772
Cash and cash equivalents at beginning of period	51,554		116,723
Cash and cash equivalents at end of period	$	95,175	$	582,495

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

~~December~~March 31, ~~2017~~2023

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~~3.3 million residential, commercial, public authority and industrial customers through our six regulated distribution divisions, which at ~~December~~March 31, ~~2017,~~2023, covered service areas located in eight states.

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

2. Unaudited Financial Information

These consolidated interim-period financial statements have been prepared in accordance with accounting principles generally accepted in the United States on the same basis 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.~~2022. 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.~~2022. Because of seasonal and other factors, the results of operations for the ~~three-month~~six-month period ended ~~December~~March 31, ~~2017~~2023 are not indicative of our results of operations for the full ~~2018~~2023 fiscal year, which ends September 30, ~~2018.~~2023.

Except ~~for the actions of our regulators regarding tax reform~~ as ~~discussed~~described in Note 6 and ~~the receipt of funds held in escrow related~~Note 12 to the ~~prior year sale of AEM,~~unaudited condensed consolidated financial statements, 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.~~2022.

~~In May 2014,~~During the ~~Financial Accounting Standards Board (FASB) issued~~second quarter of fiscal 2023, we completed our annual goodwill impairment assessment using a ~~comprehensive new revenue recognition standard~~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 ~~will supersede virtually all existing revenue recognition guidance under generally accepted accounting principles in~~would more likely than not reduce the United States. Under the new standard, an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current guidance. The new guidance will become effective for us October 1, 2018 and can be applied either retrospectively to each period presented or as a cumulative-effect adjustment asfair value of the ~~date of adoption.~~

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.

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.~~

Significant regulatory assets and liabilities as of ~~December~~March 31, ~~2017~~2023 and September 30, ~~2017~~2022 included the following:

Pension and postretirement benefit costs⁽¹⁾

Infrastructure mechanisms⁽²⁾

Infrastructure mechanisms (1)

Winter Storm Uri incremental costs (2)

Regulatory excess deferred taxes (3)

Regulatory excess deferred taxes⁽³⁾

Regulatory excess deferred taxes (3)

(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 incurred during Winter Storm Uri and certain related carrying costs. See Note 8 to the unaudited condensed consolidated financial statements for further information.

(3)Regulatory excess deferred taxes represent changes in our net deferred tax liability related to our cost of service ratemaking due to the enactment of Tax Cuts and Jobs Act of 2017 (the "TCJA") and a Kansas legislative change enacted in fiscal 2020. See Note 11 to the unaudited condensed consolidated financial statements for further information.

3. Segment Information

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

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

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

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

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

The accounting policies of the segments are the same as those described in the summary of significant accounting policies found in our Annual Report on Form 10-K for the fiscal year ended September 30, 2017. We evaluate performance based on net income or loss of the respective operating units. We allocate interest and pension expense to the pipeline and storage segment; however, there is no debt or pension liability recorded on the pipeline and storage segment balance sheet. All material intercompany transactions have been eliminated; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process. Income taxes are allocated to each segment as if each segment’s taxes were calculated on a separate return basis.2022.

Income statements and capital expenditures for the three and six months ended ~~December~~March 31, ~~2017~~2023 and ~~2016~~2022 by segment are presented in the following tables:


	Three Months Ended March 31, 2023
	Distribution		Pipeline and Storage		Eliminations		Consolidated
	(In thousands)
Operating revenues from external parties	$	1,499,437	$	41,536	$	—	$	1,540,973
Intersegment revenues	773		142,888		(143,661)		—
Total operating revenues	1,500,210		184,424		(143,661)		1,540,973
Purchased gas cost	809,023		621		(143,433)		666,211
Operation and maintenance expense	151,353		43,591		(228)		194,716
Depreciation and amortization expense	106,310		42,007		—		148,317
Taxes, other than income	98,200		10,891		—		109,091
Operating income	335,324		87,314		—		422,638
Other non-operating income	7,465		9,941		—		17,406
Interest charges	21,420		15,950		—		37,370
Income before income taxes	321,369		81,305		—		402,674
Income tax expense	32,895		12,108		—		45,003
Net income	$	288,474	$	69,197	$	—	$	357,671
Capital expenditures	$	424,989	$	194,700	$	—	$	619,689


	Three Months Ended March 31, 2022
	Distribution		Pipeline and Storage		Eliminations		Consolidated
	(In thousands)
Operating revenues from external parties	$	1,609,667	$	40,152	$	—	$	1,649,819
Intersegment revenues	879		123,595		(124,474)		—
Total operating revenues	1,610,546		163,747		(124,474)		1,649,819
Purchased gas cost	993,854		1,683		(124,159)		871,378
Operation and maintenance expense	121,541		42,126		(315)		163,352
Depreciation and amortization expense	96,612		36,762		—		133,374
Taxes, other than income	87,236		9,347		—		96,583
Operating income	311,303		73,829		—		385,132
Other non-operating income	549		4,664		—		5,213
Interest charges	15,157		13,771		—		28,928
Income before income taxes	296,695		64,722		—		361,417
Income tax expense	27,844		8,574		—		36,418
Net income	$	268,851	$	56,148	$	—	$	324,999
Capital expenditures	$	362,468	$	143,381	$	—	$	505,849



	Six Months Ended March 31, 2022
	Distribution		Pipeline and Storage		Eliminations		Consolidated
	(In thousands)
Operating revenues from external parties	$	2,581,303	$	81,302	$	—	$	2,662,605
Intersegment revenues	1,665		245,363		(247,028)		—
Total operating revenues	2,582,968		326,665		(247,028)		2,662,605
Purchased gas cost	1,490,653		(1,728)		(246,384)		1,242,541
Operation and maintenance expense	244,825		78,281		(644)		322,462
Depreciation and amortization expense	189,409		71,821		—		261,230
Taxes, other than income	156,281		19,098		—		175,379
Operating income	501,800		159,193		—		660,993
Other non-operating income	2,465		11,450		—		13,915
Interest charges	23,705		25,074		—		48,779
Income before income taxes	480,560		145,569		—		626,129
Income tax expense	32,138		19,783		—		51,921
Net income	$	448,422	$	125,786	$	—	$	574,208
Capital expenditures	$	799,850	$	390,179	$	—	$	1,190,029

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

Balance sheet information at ~~December~~March 31, ~~2017~~2023 and September 30, ~~2017~~2022 by segment is presented in the following tables:


	March 31, 2023
	Distribution		Pipeline and Storage		Eliminations		Consolidated
	(In thousands)
Net property, plant and equipment	$	13,495,410	$	4,950,476	$	—	$	18,445,886
Total assets	$	20,565,390	$	5,226,910	$	(4,480,439)	$	21,311,861


	September 30, 2022
	Distribution		Pipeline and Storage		Eliminations		Consolidated
	(In thousands)
Net property, plant and equipment	$	12,723,532	$	4,516,707	$	—	$	17,240,239
Total assets	$	21,424,586	$	4,797,206	$	(4,028,803)	$	22,192,989

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

September 30, 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 six months ended ~~December~~March 31, ~~2017~~2023 and ~~2016~~2022 are calculated as follows:


	Three Months Ended March 31				Six Months Ended March 31
	2023		2022		2023		2022
	(In thousands, except per share amounts)
Basic Earnings Per Share
Net income	$	357,671	$	324,999	$	629,531	$	574,208
Less: Income allocated to participating securities	212		202		381		379
Income available to common shareholders	$	357,459	$	324,797	$	629,150	$	573,829
Basic weighted average shares outstanding	143,941		136,834		142,881		135,259
Net income per share — Basic	$	2.48	$	2.37	$	4.40	$	4.24
Diluted Earnings Per Share
Income available to common shareholders	$	357,459	$	324,797	$	629,150	$	573,829
Effect of dilutive shares	—		—		—		—
Income available to common shareholders	$	357,459	$	324,797	$	629,150	$	573,829
Basic weighted average shares outstanding	143,941		136,834		142,881		135,259
Dilutive shares	46		416		82		211
Diluted weighted average shares outstanding	143,987		137,250		142,963		135,470
Net income per share — Diluted	$	2.48	$	2.37	$	4.40	$	4.24

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

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, 2022. 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 six months ended March 31, 2023 and 2022.


	Three Months Ended March 31, 2023				Three Months Ended March 31, 2022
	Distribution		Pipeline and Storage		Distribution		Pipeline and Storage
	(In thousands)
Gas sales revenues:
Residential	$	943,090	$	—	$	1,090,702	$	—
Commercial	398,812		—		428,330		—
Industrial	45,044		—		54,372		—
Public authority and other	22,686		—		26,396		—
Total gas sales revenues	1,409,632		—		1,599,800		—
Transportation revenues	33,511		190,248		32,801		163,850
Miscellaneous revenues	2,662		1,152		2,680		2,284
Revenues from contracts with customers	1,445,805		191,400		1,635,281		166,134
Alternative revenue program revenues (1)	53,910		(6,976)		(25,246)		(2,387)
Other revenues	495		—		511		—
Total operating revenues	$	1,500,210	$	184,424	$	1,610,546	$	163,747



	Six Months Ended March 31, 2023				Six Months Ended March 31, 2022
	Distribution		Pipeline and Storage		Distribution		Pipeline and Storage
	(In thousands)
Gas sales revenues:
Residential	$	1,896,141	$	—	$	1,666,543	$	—
Commercial	787,479		—		679,091		—
Industrial	104,259		—		103,053		—
Public authority and other	45,512		—		41,588		—
Total gas sales revenues	2,833,391		—		2,490,275		—
Transportation revenues	65,673		385,500		60,670		327,709
Miscellaneous revenues	4,944		3,874		5,279		8,827
Revenues from contracts with customers	2,904,008		389,374		2,556,224		336,536
Alternative revenue program revenues (1)	35,588		(18,321)		25,740		(9,871)
Other revenues	1,040		—		1,004		—
Total operating revenues	$	2,940,636	$	371,053	$	2,582,968	$	326,665

(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 APT shares with its tariffed customers 75% of the difference between the total non-tariffed revenues earned during a test period and a 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. Our policy related to the accounting for our accounts receivable and 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, 2022. During the six months ended March 31, 2023, there were no material changes to this policy. Rollforwards of our allowance for uncollectible accounts for the three and six months ended March 31, 2023 and 2022 are presented in the table below. The allowance excludes the gas cost portion of customers’

bills for approximately 81 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 March 31, 2023
	(In thousands)
Beginning balance, December 31, 2022	$	47,613
Current period provisions	13,009
Write-offs charged against allowance	(8,333)
Recoveries of amounts previously written off	462
Ending balance, March 31, 2023	$	52,751


	Three Months Ended March 31, 2022
	(In thousands)
Beginning balance, December 31, 2021	$	64,934
Current period provisions	5,705
Write-offs charged against allowance	(9,029)
Recoveries of amounts previously written off	603
Ending balance, March 31, 2022	$	62,213



	Six Months Ended March 31, 2023
	(In thousands)
Beginning balance, September 30, 2022	$	49,993
Current period provisions	20,242
Write-offs charged against allowance	(18,754)
Recoveries of amounts previously written off	1,270
Ending balance, March 31, 2023	$	52,751



	Six Months Ended March 31, 2022
	(In thousands)
Beginning balance, September 30, 2021	$	64,471
Current period provisions	12,075
Write-offs charged against allowance	(15,458)
Recoveries of amounts previously written off	1,125
Ending balance, March 31, 2022	$	62,213

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~~2022. Other than as described below, there were no material changes in the terms of our debt instruments during the ~~three~~six months ended ~~December~~March 31, ~~2017.~~2023.

Long-term debt at ~~December~~March 31, ~~2017~~2023 and September 30, ~~2017~~2022 consisted of the following:


	March 31, 2023		September 30, 2022
	(In thousands)
Unsecured 0.625% Senior Notes, due March 2023	$	—	$	1,100,000
Unsecured 3.00% Senior Notes, due June 2027	500,000		500,000
Unsecured 2.625% Senior Notes, due September 2029	500,000		500,000
Unsecured 1.50% Senior Notes, due January 2031	600,000		600,000
Unsecured 5.45% Senior Notes, due October 2032	300,000		—
Unsecured 5.95% Senior Notes, due October 2034	200,000		200,000
Unsecured 5.50% Senior Notes, due June 2041	400,000		400,000
Unsecured 4.15% Senior Notes, due January 2043	500,000		500,000
Unsecured 4.125% Senior Notes, due October 2044	750,000		750,000
Unsecured 4.30% Senior Notes, due October 2048	600,000		600,000
Unsecured 4.125% Senior Notes, due March 2049	450,000		450,000
Unsecured 3.375% Senior Notes, due September 2049	500,000		500,000
Unsecured 2.85% Senior Notes, due February 2052	600,000		600,000
Unsecured 5.75% Senior Notes, due October 2052	500,000		—
Floating-rate Senior Notes, due March 2023	—		1,100,000
Medium-term note Series A, 1995-1, 6.67%, due December 2025	10,000		10,000
Unsecured 6.75% Debentures, due July 2028	150,000		150,000
Finance lease obligations	51,133		51,850
Total long-term debt	6,611,133		8,011,850
Less:
Original issue discount on unsecured senior notes and debentures	6,271		3,704
Debt issuance cost	50,253		46,042
Current maturities of long-term debt	1,512		2,201,457
	$	6,553,097	$	5,760,647

On October 3, 2022, we completed a public offering of $500 million of 5.75% senior notes due October 2052, with an effective interest rate of 4.50%, after giving effect to the offering costs and settlement of our interest rate swaps, and $300 million of 5.45% senior notes due October 2032, with an effective interest rate of 5.57%, after giving effect to the offering costs. The net proceeds from the offering, after the underwriting discount and offering expenses, of $789.4 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


~~(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 ratio between 50% and 60%, inclusive of long–term and short–term debt.~~structure. 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~~four 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 that expires ~~September 25, 2021. The~~on March 31, 2027. This facility 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~~March 31, ~~2017 and~~2023, there were no amounts outstanding under our commercial paper program. At September 30, ~~2017 a total of $336.8~~2022, there was $185.0 million ~~and $447.7 million was~~ outstanding under our commercial paper program.

We also have a $900 million three-year unsecured revolving credit facility, which expires March 31, 2025 and is used to provide additional working capital funding. This facility 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 March 31, 2023 and September 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, 2023 and is used to provide working capital funding. There were no borrowings outstanding under this facility as of March 31, 2023 and September 30, 2022.

Finally, we have a ~~$10~~$50 million 364-day unsecured revolving credit facility, which was renewed March 31, 2023 and is used ~~primarily~~ to issue letters of ~~credit.~~credit and to provide working capital funding. At ~~December~~March 31, ~~2017,~~2023, 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~~to $44.4 million.

On March 3, 2023, we entered into a term loan agreement for a $2.02 billion senior unsecured term loan facility that would have matured December 31, 2023. The proceeds from the facility, along with cash on hand, were used to repay at maturity on March 9, 2023 our ~~$10 million~~outstanding $1.1 billion senior notes and $1.1 billion floating-rate senior notes. Under the terms of the facility, we were required to ~~$4.4 million.~~prepay the facility prior to maturity upon receiving proceeds from the issuance of certain securities that were part of a utility recovery securitization transaction authorized by the state of Texas. On March 23, 2023, we received those proceeds (see Note 8), and on March 24, 2023 we prepaid the term loan facility, thus terminating the term loan agreement and all obligations thereunder.

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~~March 31, ~~2017,~~2023, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 4440 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~~March 31, ~~2017.~~2023. 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 six months ended March 31, 2023 and 2022.


	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, 2022	140,896,598	$	704	$	5,838,118	$	369,112	$	3,211,157	$	9,419,091
Net income	—	—		—		—		271,860		271,860
Other comprehensive income	—	—		—		22,218		—		22,218


Cash dividends ($0.74 per share)	—	—		—		—		(104,552)		(104,552)

Common stock issued:
Public and other stock offerings	2,147,210	11		223,768		—		—		223,779
Stock-based compensation plans	111,953	1		3,877		—		—		3,878
Balance, December 31, 2022	143,155,761	716		6,065,763		391,330		3,378,465		9,836,274
Net income	—	—		—		—		357,671		357,671
Other comprehensive loss	—	—		—		(30,333)		—		(30,333)


Cash dividends ($0.74 per share)	—	—		—		—		(106,173)		(106,173)

Common stock issued:
Public and other stock offerings	1,316,930	6		143,808		—		—		143,814
Stock-based compensation plans	11,959	—		3,952		—		—		3,952
Balance, March 31, 2023	144,484,650	$	722	$	6,213,523	$	360,997	$	3,629,963	$	10,205,205


	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

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

On March ~~28, 2016,~~31, 2023, we filed 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.~~31, 2026. This shelf registration statement replaced our previous shelf registration statement which was filed on June 29, 2021. At ~~December~~March 31, ~~2017, approximately $1.2~~2023, $4.0 billion of securities ~~remained~~were available for issuance under ~~the~~this shelf registration statement.

On ~~November 14, 2017,~~March 31, 2023, 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~~$1.0 billion through March ~~28, 2019. During the three months ended December~~ 31, ~~2017, no~~2026 (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 March 23, 2022.

~~On November 30, 2017,~~During the six months ended March 31, 2023, 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 2,177,143 shares of our common ~~stock. We received~~stock at an aggregate ~~gross~~price of $257.0 million. During the six months ended March 31, 2023, we also settled forward sale agreements with respect to 3,394,919 shares that had been borrowed and sold by various forward sellers under the ATM program for net proceeds of ~~$400~~$359.7 million. As of March 31, 2023, $1.0 billion of equity was available for issuance under our existing ATM program. Additionally, we had $673.2 million ~~and received net~~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	1,157,238	$	132,198	$	114.24
December 29, 2023	919,898	105,843		$	115.06
March 28, 2024	2,744,502	319,894		$	116.56
June 28, 2024	927,939	108,491		$	116.92
September 30, 2024	58,807	6,792		$	115.49
Total	5,808,384	$	673,218	$	115.90

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, 2022	$	(495)	$	369,607	$	369,112
Other comprehensive income (loss) before reclassifications	221		(7,276)		(7,055)
Amounts reclassified from accumulated other comprehensive income	—		(1,060)		(1,060)
Net current-period other comprehensive income (loss)	221		(8,336)		(8,115)

March 31, 2023	$	(274)	$	361,271	$	360,997


	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	(230)		74,518		74,288
Amounts reclassified from accumulated other comprehensive income	—		1,488		1,488
Net current-period other comprehensive income (loss)	(230)		76,006		75,776

March 31, 2022	$	(183)	$	145,762	$	145,579

8. Winter Storm Uri

Overview

As described in Note 9 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2022, 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

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 )
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. On March 3, 2023, we entered into a term loan agreement for a $2.02 billion senior unsecured term loan facility and used the proceeds, along with cash on hand, to repay at maturity the outstanding $2.2 billion senior notes that matured on March 9, 2023.

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, we recorded a regulatory asset for incremental costs, including certain carrying costs, incurred in Kansas and Texas. As of March 31, 2023, we have recorded an $89.1 million regulatory asset related to costs incurred in Kansas. The regulatory asset that was recorded related to costs incurred in Texas was relieved in March 2023 as a result of securitization proceedings in Texas as discussed below. Additionally, pursuant to a separate regulatory order issued by the RRC, we have deferred $32.4 million in carrying costs incurred after September 1, 2022, which we anticipate recovering in future regulatory filings. We have recorded the regulatory asset for Texas as a long-term asset in deferred charges and other assets as of March 31, 2023.

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 during fiscal 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, 2022.

Kansas

The ~~following tables detail reclassifications out~~KCC issued a financing order on October 25, 2022, which authorizes us to securitize, through the issuance of ~~AOCI~~bonds, $118.5 million, which includes the carrying costs and estimated interest related to the securitization over a time period not to exceed 12 years. We currently expect the issuance of bonds to take place during fiscal 2023. 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 March 31, 2023.

Texas

On February 8, 2022, the RRC issued a Financing Order that authorizes the Texas Public Financing Authority (TPFA) to issue customer rate relief bonds to securitize the costs that were approved in the Final Determination over a period not to exceed 30 years. The TPFA authorized the creation of the Texas Natural Gas Securitization Finance Corporation (the Finance Corporation) as an issuing financing entity for the ~~three months ended December 31, 2017~~purpose of issuing customer rate relief bonds. On March 23, 2023, the Finance Corporation issued $3.5 billion in customer rate relief bonds with varying scheduled final maturities from 12 to 18 years. The bonds are obligations of the Finance Corporation, payable from the customer rate relief charges and ~~2016. Amounts in parentheses below indicate decreases~~other bond collateral, and are not an obligation of Atmos Energy. When we begin collecting the customer rate relief charges, such property shall be solely owned by the Finance Corporation and not available to ~~net income~~pay creditors of Atmos Energy.

On March 23, 2023, we received proceeds from the Finance Corporation in the ~~statement~~amount of ~~income:~~

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~~$2.02 billion, and we relieved $2.02 billion in regulatory assets related to costs incurred in Texas. U.S. GAAP does not provide comprehensive recognition and measurement guidance for many forms of ~~income~~government assistance received by business entities. Accordingly, we have accounted for the proceeds received from ~~discontinued operations~~the Finance Corporation by analogy to International Accounting Standards No. 20, "Accounting for Government Grants and Disclosure of Government Assistance" consistent with a grant related to income. The proceeds received and the corresponding derecognition of the deferred regulatory asset have been reflected in ~~the~~purchased gas cost and interest charges in our condensed consolidated statements of comprehensive income.

As the proceeds reflect the recovery of the regulatory asset, there was no impact to earnings. The proceeds are reflected in our condensed consolidated statements of cash flow as an increase in operating cash flow. As discussed in Note 6, we used the proceeds from the Finance Corporation to repay a term loan facility.

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 six months ended ~~December~~March 31, ~~2017~~2023 and ~~2016~~2022 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 March 31
	Pension Benefits				Other Benefits
	2023		2022		2023		2022
	(In thousands)
Components of net periodic pension cost:
Service cost	$	2,908	$	4,324	$	1,546	$	2,558
Interest cost (1)	7,325		5,064		3,478		2,684
Expected return on assets (1)	(7,278)		(7,383)		(2,804)		(3,313)

Amortization of prior service cost (credit) (1)	(30)		(58)		(3,285)		(3,308)
Amortization of actuarial (gain) loss (1)	164		1,951		(1,863)		—

Net periodic pension cost	$	3,089	$	3,898	$	(2,928)	$	(1,379)



	Six Months Ended March 31
	Pension Benefits				Other Benefits
	2023		2022		2023		2022
	(In thousands)
Components of net periodic pension cost:
Service cost	$	5,816	$	8,647	$	3,091	$	5,117
Interest cost (1)	14,650		10,127		6,955		5,367
Expected return on assets (1)	(14,556)		(14,766)		(5,608)		(6,625)

Amortization of prior service cost (credit) (1)	(61)		(116)		(6,571)		(6,617)
Amortization of actuarial (gain) loss (1)	329		3,902		(3,726)		—

Net periodic pension cost	$	6,178	$	7,794	$	(5,859)	$	(2,758)

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

(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~~2022.

For the six months ended March 31, 2023 we contributed $6.2 million to our postretirement medical plans. We anticipate contributing a total of between $15 million and $25 million to our postretirement plans during fiscal 2023.

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 the three months ended December 31, 2017.~~cash flows.

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 under contracts 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~~2022. At March 31, 2023, we were ~~no material changes~~committed to ~~the~~ purchase ~~commitments for the~~81.2 Bcf within one year, 109.2 Bcf within two to three ~~months ended December~~years and 3.1 Bcf beyond three years under indexed contracts. At March 31, ~~2017.~~2023, we were committed to purchase 7.3 Bcf within one year under fixed price contracts with a weighted average price of $2.64 per Mcf.

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~~March 31, ~~2017, formula~~2023, 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 six months ended March 31, 2023.

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, 2023 and 2022, adjusted for tax expense associated with certain discrete items. The effective tax rates for the three months ended March 31, 2023 and 2022 were 11.2% and 10.1% and for the six months ended March 31, 2023 and 2022 were 11.1% and 8.3%. 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.

Regulatory Excess Deferred Taxes

Regulatory excess net deferred taxes represent changes in ~~further detail in Note 6, all jurisdictions are addressing impacts~~our net deferred tax liability related to our cost of service ratemaking due to the enactment of the ~~TCJA.~~Tax Cuts and Jobs Act of 2017 (the "TCJA") and a Kansas legislative change enacted in fiscal 2020. Currently, the regulatory excess net deferred tax liability of $418.9 million is being returned over various periods. Of this amount, $332.2 million is being returned to customers over 35 - 60 months. An additional $71.6 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 March 31, 2023 and September 30, 2022, $151.4 million and $159.8 million is recorded in other current liabilities.

~~10.~~

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.~~2022. During the ~~three~~six months ended ~~December~~March 31, ~~2017,~~2023, 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~~2022-2023 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we ~~anticipate hedging~~hedged approximately 2632 percent, or ~~15.0~~17.7 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,~~In March 2023, we ~~had~~entered into forward starting interest rate swaps to effectively fix the Treasury yield component associated with ~~the anticipated issuance~~$150 million of ~~$450 million~~planned issuances of unsecured senior notes in fiscal ~~2019~~2024. These swaps were designated as cash flow hedges at ~~3.78%, which~~the time the agreements were executed.

The following table summarizes our existing forward starting interest rate swaps as of March 31, 2023.



Planned Debt Issuance Date	Amount Hedged
	(In thousands)


Fiscal 2024	$	600,000
Fiscal 2025	600,000
Fiscal 2026	300,000
	$	1,500,000

Additionally, in April 2023, we entered into a forward starting interest rate swap to effectively fix the Treasury yield component associated with $100 million of planned issuances of unsecured senior notes in fiscal 2024. This swap was designated as a cash flow hedge at the time the ~~swaps were~~agreement was 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~~March 31, ~~2017,~~2023, 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~~March 31, ~~2017,~~2023, we had ~~12,143~~4,123 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~~March 31, ~~2017~~2023 and September 30, ~~2017.~~2022. 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 March 31, 2023 and September 30, 2022, no gross amounts and no cash collateral were netted within our consolidated balance sheet.


									March 31, 2023
								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	$	95,735	$	(272)

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	250,232		—
Total		—		(114,175		)	Total		345,967		(272)
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	1,974		(11,679)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	190		(262		)

Total		646		(3,000		)	Total		1,974		(11,679)
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		$	347,941	$	(11,951)

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, 2022
	Balance Sheet Location	Assets		Liabilities
		(In thousands)

Designated As Hedges:



Interest rate contracts	Deferred charges and other assets / Deferred credits and other liabilities	$	355,075	$	—
Total		355,075		—
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	26,207		(3,000)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	709		(1,129)
Total		26,916		(4,129)
Gross / Net Financial Instruments		$	381,991	$	(4,129)

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

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 (gain) 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~~March 31, ~~2017~~2023 and ~~2016~~2022 was ~~$0.6~~$(0.7) million and ~~$0.1~~$1.0 million and for the six months ended March 31, 2023 and 2022 was $(1.4) million and $1.9 million.

The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three and six months ended ~~December~~March 31, ~~2017~~2023 and ~~2016. The amounts included in the table below exclude gains and losses arising from ineffectiveness because those amounts are immediately recognized in the income statement as incurred.~~2022.


	Three Months Ended March 31				Six Months Ended March 31
	2023		2022		2023		2022
	(In thousands)
Increase (decrease) in fair value:
Interest rate agreements	$	(29,937)	$	121,140	$	(7,276)	$	74,518

Recognition of (gains) losses in earnings due to settlements:
Interest rate agreements	(530)		744		(1,060)		1,488

Total other comprehensive income (loss) from hedging, net of tax	$	(30,467)	$	121,884	$	(8,336)	$	76,006

Three Months Ended
December 31
2017 2016 (1)
(In thousands)
Increase (decrease) in fair value:
Interest rate agreements $ (1,332 ) $ 91,127
Forward commodity contracts⁽²⁾
—
9,847
Recognition of (gains) losses in earnings due to settlements:
Interest rate agreements 377
87
Forward commodity contracts⁽²⁾
—
(4,865 )
Total other comprehensive income (loss) from hedging, net of tax $ (955 ) $ 96,196

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 March 31, 2023, we had $93.1 million of net realized gains in AOCI associated with our interest rate agreements. The following amounts, net of deferred taxes, represent the expected recognition in earnings of the deferred ~~losses~~net gains 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 2053. 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	$	2,120
Thereafter	90,967
Total	$	93,087

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.~~2022. During the ~~three~~six months ended ~~December~~March 31, ~~2017,~~2023, 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.~~2022.

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~~March 31, ~~2017~~2023 and September 30, ~~2017.~~2022. Assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.


	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)(1)		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral		March 31, 2023
	(In thousands)
Assets:
Financial instruments	$	—	$	347,941	$	—	$	—	$	347,941
Debt and equity securities
Registered investment companies	27,596		—		—		—		27,596
Bond mutual funds	33,326		—		—		—		33,326
Bonds (2)	—		34,962		—		—		34,962
Money market funds	—		6,458		—		—		6,458
Total debt and equity securities	60,922		41,420		—		—		102,342
Total assets	$	60,922	$	389,361	$	—	$	—	$	450,283
Liabilities:
Financial instruments	$	—	$	11,951	$	—	$	—	$	11,951

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, 2022
	(In thousands)											(In thousands)
Assets:											Assets:
Financial instruments	$	—	$	3,239	$	—	$	—	$	3,239	Financial instruments	$	—	$	381,991	$	—	$	—	$	381,991
Available-for-sale securities
Debt and equity securities											Debt and equity securities
Registered investment companies	41,097		—		—		—		41,097		Registered investment companies	26,367		—		—		—		26,367
Bond mutual funds	16,371		—		—		—		16,371		Bond mutual funds	32,367		—		—		—		32,367
Bonds	—		29,104		—		—		29,104
Bonds (2)											Bonds (2)	—		33,433		—		—		33,433
Money market funds	—		1,837		—		—		1,837		Money market funds	—		3,845		—		—		3,845
Total available-for-sale securities	57,468		30,941		—		—		88,409
Total debt and equity securities											Total debt and equity securities	58,734		37,278		—		—		96,012
Total assets	$	57,468	$	34,180	$	—	$	—	$	91,648	Total assets	$	58,734	$	419,269	$	—	$	—	$	478,003
Liabilities:											Liabilities:
Financial instruments	$	—	$	112,398	$	—	$	—	$	112,398	Financial instruments	$	—	$	4,129	$	—	$	—	$	4,129

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

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

~~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

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~~March 31, ~~2017~~2023 and September 30, ~~2017:~~2022:


	March 31, 2023		September 30, 2022
	(In thousands)
Carrying Amount	$	6,560,000	$	7,960,000
Fair Value	$	5,879,825	$	6,918,843

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.~~2022. During the ~~three~~six months ended ~~December~~March 31, ~~2017,~~2023, 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
24

~~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.

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

~~Fair Value Hedges~~

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

~~Cash Flow Hedges~~

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

Three Months Ended
December 31, 2016

(In thousands)

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

~~Financial Instruments Not Designated as Hedges~~

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~~March 31, ~~2017 and~~2023, the related condensed consolidated statements of ~~income,~~ comprehensive income for the three and six month periods ended March 31, 2023 and 2022, the condensed consolidated statements of cash flows for the ~~three-month~~six month periods ended ~~December~~March 31, ~~2017~~2023 and ~~2016. These~~2022, 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, 2022, 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 14, 2022, 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, 2022, 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

~~February 6, 2018~~



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

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.~~2022.

Cautionary Statement for the Purposes of the Safe Harbor under the Private Securities Litigation Reform Act of 1995

The statements contained in this Quarterly Report on Form 10-Q may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report are forward-looking statements made in good faith by us and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report, or any other of our documents or oral presentations, the words “anticipate”, “believe”, “estimate”, “expect”, “forecast”, “goal”, “intend”, “objective”, “plan”, “projection”, “seek”, “strategy” or similar words are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to our strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties include the following: ~~our ability to continue to access the credit~~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 ~~impact~~safety of ~~adverse economic conditions on~~ our ~~customers;~~operations; 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 of our business; increased costs of providing health care benefits, along with pension and postretirement health care benefits and increased funding requirements; the inabilityfailure to ~~continue to hire, train~~attract and retain ~~operational, technical~~a qualified workforce; natural disasters, terrorist activities or other events and ~~managerial personnel; possible~~other risks and uncertainties discussed herein, all of which are difficult to predict and many of which are beyond our control; 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~~the impact of new cybersecurity compliance requirements; adverse weather conditions; the impact of greenhouse gas emissions or other ~~events~~legislation or regulations intended to address climate change; the impact of climate change; the capital-intensive nature of our business; our ability to continue to access the credit and ~~other~~capital markets to execute our business strategy; market risks ~~and uncertainties discussed herein, all of which are difficult to predict and many of which are~~ beyond our ~~control.~~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; and increased costs of providing health care benefits, along with pension and postretirement health care benefits and increased funding requirements. 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.

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~~3.3 million residential, commercial, public authority and industrial customers throughout our six distribution divisions, which at ~~December~~March 31, ~~2017~~2023 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~~2022 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~~six months ended ~~December~~March 31, ~~2017.~~2023.

~~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~~six months ~~of fiscal 2018,~~ended March 31, 2023, we recorded ~~adjusted~~net income ~~from continuing operations~~ of ~~$152.2~~$629.5 million, or ~~$1.40~~$4.40 per diluted share, compared to ~~adjusted~~net income ~~from continuing operations~~ of ~~$114.0~~$574.2 million, or ~~$1.08~~$4.24 per diluted share for the ~~first three~~six months ~~of fiscal 2017.~~ ended March 31, 2022.

The ~~period-over-period~~10 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, partially offset by increased depreciation and property tax expenses and higher spending on certain operating expenses in both our ~~effective income tax rate.~~ segments.

During the ~~three~~six months ended ~~December~~March 31, ~~2017,~~2023, we ~~completed seven~~implemented ratemaking regulatory ~~proceedings, resulting~~actions which resulted in an increase in annual operating income of ~~$46.1 million and~~$115.1 million. Additionally, as of March 31, 2023, we had ~~seven~~ ratemaking efforts in progress ~~at December 31, 2017~~ seeking a total increase in annual operating income of ~~$13.3~~$298.9 million.

Capital expenditures for the ~~first three~~six months ~~of fiscal 2018~~ended March 31, 2023 were ~~$383.2~~$1,415.3 million. ~~Approximately 82~~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~~six months ended ~~December~~March 31, ~~2017. The net proceeds from the issuance were primarily used to repay short-term~~2023, we completed approximately $1.2 billion of long-term debt and equity financing. As of March 31, 2023, our equity capitalization was 60.9 percent. As of March 31, 2023, we had approximately $3.3 billion in total liquidity, consisting of $95.2 million in cash and cash equivalents, $673.2 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 2022.2023.

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 50 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 81 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~~March 31, ~~2017~~2023 compared with Three Months Ended ~~December~~March 31, ~~2016~~2022

Financial and operational highlights for our distribution segment for the three months ended ~~December~~March 31, ~~2017~~2023 and ~~2016~~2022 are presented below.


	Three Months Ended March 31
	2023		2022		Change
	(In thousands, unless otherwise noted)
Operating revenues	$	1,500,210	$	1,610,546	$	(110,336)
Purchased gas cost	809,023		993,854		(184,831)

Operating expenses	355,863		305,389		50,474
Operating income	335,324		311,303		24,021
Other non-operating income	7,465		549		6,916
Interest charges	21,420		15,157		6,263
Income before income taxes	321,369		296,695		24,674

Income tax expense	32,895		27,844		5,051
Net income	$	288,474	$	268,851	$	19,623
Consolidated distribution sales volumes — MMcf	117,731		142,218		(24,487)
Consolidated distribution transportation volumes — MMcf	43,377		47,080		(3,703)
Total consolidated distribution throughput — MMcf	161,108		189,298		(28,190)

Consolidated distribution average cost of gas per Mcf sold	$	6.87	$	6.99	$	(0.12)

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 to a $37.7 million increase in gross profit, partially offset with a $19.9 million increase~~7.7 percent. Key drivers for the change in operating ~~expenses. The quarter-over-quarter increase in gross profit primarily reflects:~~income include:

•a ~~$25.6~~$52.5 million ~~net~~ increase in rate adjustments, primarily in our Mid-Tex ~~Mississippi, West Texas and Kentucky/Mid-States Divisions.~~Division.

•a ~~$5.7~~$14.9 million increase in consumption, net of WNA, primarily due to the decline in residential ~~and commercial net~~ consumption ~~primarily in our Mid-Tex and Mississippi Divisions.~~during the second quarter of fiscal 2022.

•a ~~$3.5~~$6.1 million increase ~~from~~related to residential customer growth, primarily in our Mid-Tex Division, and ~~Kentucky/Mid-States Divisions.~~increased industrial load.

~~The~~•a $4.5 million decrease in refunds of excess deferred taxes to customers, which is substantially offset in income tax expense.

Partially offset by:

•a $17.7 million increase in ~~operating expenses, which includes~~depreciation expense and property taxes associated with increased capital investments.

•an $11.6 million increase in pipeline system maintenance primarily related to increased line locate spending.

•a $6.9 million increase in bad debt expense primarily due to higher customer bills.

•an $11.3 million increase in 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,~~administrative costs, including the reimbursement of certain costs in the prior year.

Other non-operating income increased ~~depreciation and property tax expense associated with~~$6.9 million primarily due to unrealized gains on equity investments in the current period compared to unrealized losses on equity investments in the prior period. Interest charges increased ~~capital investments.~~

~~The decrease in income tax expense reflects a reduction in our effective tax rate from 35.9%~~$6.3 million primarily due to ~~27.4%, as a result~~the issuance of long-term debt during the ~~TCJA, which is partially offset by an increase in income before income taxes.~~first quarter of fiscal 2023.

The following table shows our operating income by distribution division, in order of total rate base, for the three months ended ~~December~~March 31, ~~2017~~2023 and ~~2016.~~2022. 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 March 31
	2017		2016		Change			2023		2022		Change
	(In thousands)							(In thousands)
Mid-Tex	$	72,925	$	72,743	$	182	Mid-Tex	$	163,604	$	155,275	$	8,329
Kentucky/Mid-States	28,129		22,738		5,391		Kentucky/Mid-States	37,303		36,288		1,015
Louisiana	23,268		19,863		3,405		Louisiana	33,329		29,796		3,533
West Texas	15,761		14,928		833		West Texas	35,543		31,157		4,386
Mississippi	18,275		11,958		6,317		Mississippi	42,556		37,087		5,469
Colorado-Kansas	12,931		11,705		1,226		Colorado-Kansas	23,852		22,037		1,815
Other	1,467		958		509		Other	(863)		(337)		(526)
Total	$	172,756	$	154,893	$	17,863	Total	$	335,324	$	311,303	$	24,021

Six Months Ended March 31, 2023 compared with Six Months Ended March 31, 2022

Financial and operational highlights for our distribution segment for the six months ended March 31, 2023 and 2022 are presented below.



	Six Months Ended March 31
	2023		2022		Change
	(In thousands, unless otherwise noted)
Operating revenues	$	2,940,636	$	2,582,968	$	357,668
Purchased gas cost	1,690,938		1,490,653		200,285

Operating expenses	682,618		590,515		92,103
Operating income	567,080		501,800		65,280
Other non-operating income	14,239		2,465		11,774
Interest charges	44,259		23,705		20,554
Income before income taxes	537,060		480,560		56,500

Income tax expense	54,118		32,138		21,980
Net income	$	482,942	$	448,422	$	34,520
Consolidated distribution sales volumes — MMcf	217,809		211,763		6,046
Consolidated distribution transportation volumes — MMcf	83,977		85,677		(1,700)
Total consolidated distribution throughput — MMcf	301,786		297,440		4,346

Consolidated distribution average cost of gas per Mcf sold	$	7.76	$	7.04	$	0.72

Operating income for our distribution segment increased 13.0 percent. Key drivers for the change in operating income include:

•a $109.8 million increase in rate adjustments, primarily in our Mid-Tex Division.

•a $14.1 million increase in consumption, net of WNA, primarily due to the decline in residential consumption during the second quarter of fiscal 2022.

•an $11.5 million increase related to residential customer growth, primarily in our Mid-Tex Division, and increased industrial load.

•a $10.5 million decrease in refunds of excess deferred taxes to customers, which is substantially offset in income tax expense.

Partially offset by:

•a $33.7 million increase in depreciation expense and property taxes associated with increased capital investments.

•an $18.9 million increase in pipeline system maintenance primarily related to increased line locate spending.

•a $7.0 million increase in bad debt expense primarily due to higher customer bills.

•a $5.7 million increase in employee-related costs primarily due to higher overtime incurred.

•an $11.4 million increase in other operation and maintenance expense primarily due to administrative costs, including the reimbursement of certain costs in the prior year.

Other non-operating income increased $11.8 million primarily due to unrealized gains on equity investments in the current period compared to unrealized losses on equity investments in the prior period. Interest charges increased $20.6 million primarily due to the issuance of long-term debt during the first quarter of fiscal 2023.

The following table shows our operating income by distribution division, in order of total rate base, for the six months ended March 31, 2023 and 2022. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.


	Six Months Ended March 31
	2023		2022		Change
	(In thousands)
Mid-Tex	$	277,532	$	261,633	$	15,899
Kentucky/Mid-States	65,488		61,826		3,662
Louisiana	58,677		50,950		7,727
West Texas	56,749		52,031		4,718
Mississippi	69,605		61,787		7,818
Colorado-Kansas	38,819		24,852		13,967
Other	210		(11,279)		11,489
Total	$	567,080	$	501,800	$	65,280

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~~six months of fiscal ~~2018,~~2023, we ~~completed six~~implemented, or received approval to implement, regulatory proceedings, resulting in a ~~$17.1~~$115.1 million increase in annual operating income as summarized below. Our ratemaking outcomes include the refund (return) 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 six months ended March 31, 2023 were $115.5 million.


Rate Action	Annual Increase in Operating Income		EDIT Impact		Annual Increase in Operating Income Excluding EDIT
	(In thousands)
Annual formula rate mechanisms	$	113,817	$	342	$	114,159
Rate case filings	—		—		—
Other rate activity	1,320		—		1,320
	$	115,137	$	342	$	115,479

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

The following ratemaking efforts seeking ~~$13.3~~$213.9 million in increased annual operating income were in progress as of ~~December~~March 31, ~~2017:~~2023:

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)

Colorado-Kansas

Rate Case

Colorado

7,554

Colorado-Kansas

Rate Case

Kansas

7,989

Colorado-Kansas

Infrastructure Mechanism

Kansas (1)

772

~~(2)~~

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

~~(3)~~Kentucky/Mid-States

~~The Company extended the deadline for the~~

Formula Rate Mechanism

Tennessee

Louisiana

Formula Rate Mechanism

Louisiana

16,454

Mid-Tex

Formula Rate Mechanism

City of Dallas ~~to act until February 15, 2018.~~

19,651

Mid-Tex

Infrastructure Mechanism

ATM Cities

12,825

Mid-Tex

Infrastructure Mechanism

Environs

5,983

Mid-Tex

Formula Rate Mechanism

Mid-Tex Cities

113,768

Mississippi

Infrastructure Mechanism

Mississippi

9,843

West Texas

Infrastructure Mechanism

Environs

1,332

West Texas

Formula Rate Mechanism

West Texas Cities

10,085

West Texas

Infrastructure Mechanism

Amarillo, Lubbock, Dalhart and Channing

6,938

West Texas

Infrastructure Mechanism

WTX Triangle

718

213,939

(1) The Kansas Corporation Commission approved the SIP filing on March 21, 2023, with rates effective April 1, 2023.

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) Infrastructure mechanisms in Texas, 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~~six months ended ~~December~~March 31, ~~2017:~~2023:


Division	Jurisdiction	Test Year Ended	Increase in Annual Operating Income		EDIT Impact		Increase in Annual Operating Income Excluding EDIT		Effective Date
			(In thousands)
2023 Filings:













Colorado-Kansas	Colorado SSIR	12/31/2023	$	1,971	$	—	$	1,971	01/01/2023


Mississippi	Mississippi - SIR	10/31/2023	8,560		—		8,560		11/01/2022
Mississippi	Mississippi - SRF	10/31/2023	12,188		778		12,966		11/01/2022
Kentucky/Mid-States	Kentucky PRP (1)	09/30/2023	1,904		—		1,904		10/02/2022
Mid-Tex	Mid-Tex Cities RRM	12/31/2021	81,402		(395)		81,007		10/01/2022
West Texas	West Texas Cities RRM	12/31/2021	7,315		(41)		7,274		10/01/2022
Kentucky/Mid-States	Virginia - SAVE	09/30/2023	477		—		477		10/01/2022

Total 2023 Filings			$	113,817	$	342	$	114,159

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) Rates were implemented on October 2, 2022, subject to refund.

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

There was no rate case activity completed during the ~~three~~six months ended ~~December~~March 31, ~~2017.~~

Other Ratemaking Activity

The ~~Company had no~~following table summarizes other ratemaking activity during the ~~three~~six months ended ~~December~~March 31, ~~2017.~~

2023.

Division

Jurisdiction

Rate Activity

Increase in
Annual
Operating
Income

Effective
Date

(In thousands)

2023 Other Rate Activity:

Colorado-Kansas

Kansas

Ad Valorem (1)

1,320

02/01/2023

Total 2023 Other Rate Activity

1,320

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 APT 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 10, 2023, APT made a GRIP filing that covered changes in net ~~investment~~property, plant and equipment investments from ~~October~~January 1, ~~2016~~2022 through December 31, ~~2016~~2022 with a requested increase in operating income of ~~$29.0~~$84.9 million. ~~On December 5, 2017, the filing was approved.~~

~~On December 21, 2016,~~The demand fee our Louisiana natural gas transmission pipeline charges to our Louisiana distribution division increases five percent annually and has been approved by the Louisiana Public Service Commission ~~approved an annual increase of five percent to the demand fee charged by our natural gas transmission pipeline for each of the next 10 years, effective October 1, 2017.~~until September 30, 2027.

Three Months Ended ~~December~~March 31, ~~2017~~2023 compared with Three Months Ended ~~December~~March 31, ~~2016~~2022

Financial and operational highlights for our pipeline and storage segment for the three months ended ~~December~~March 31, ~~2017~~2023 and ~~2016~~2022 are presented below.


	Three Months Ended March 31
	2023		2022		Change
	(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue	$	146,774	$	129,162	$	17,612
Third-party transportation revenue	36,868		32,132		4,736

Other revenue	782		2,453		(1,671)
Total operating revenues	184,424		163,747		20,677
Total purchased gas cost	621		1,683		(1,062)

Operating expenses	96,489		88,235		8,254
Operating income	87,314		73,829		13,485
Other non-operating income	9,941		4,664		5,277
Interest charges	15,950		13,771		2,179
Income before income taxes	81,305		64,722		16,583

Income tax expense	12,108		8,574		3,534
Net income	$	69,197	$	56,148	$	13,049
Gross pipeline transportation volumes — MMcf	202,667		224,960		(22,293)
Consolidated pipeline transportation volumes — MMcf	125,673		129,395		(3,722)

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

Partially offset by:

Other non-operating income increased $5.3 million primarily due to a higher allowance for funds used during construction (AFUDC) largely as a result of ~~higher basis spreads creating~~ increased capital spending.

Financial and operational highlights for our pipeline and storage segment for the six months ended March 31, 2023 and 2022 are presented below.



	Six Months Ended March 31
	2023		2022		Change
	(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue	$	293,005	$	256,485	$	36,520
Third-party transportation revenue	74,947		62,757		12,190
Other revenue	3,101		7,423		(4,322)
Total operating revenues	371,053		326,665		44,388
Total purchased gas cost	(237)		(1,728)		1,491

Operating expenses	194,546		169,200		25,346
Operating income	176,744		159,193		17,551
Other non-operating income	24,358		11,450		12,908
Interest charges	29,871		25,074		4,797
Income before income taxes	171,231		145,569		25,662

Income tax expense	24,642		19,783		4,859
Net income	$	146,589	$	125,786	$	20,803
Gross pipeline transportation volumes — MMcf	408,911		406,428		2,483
Consolidated pipeline transportation volumes — MMcf	267,749		265,462		2,287

Operating income for our pipeline and storage segment increased 11.0 percent. Key drivers for the change in operating income include:

Partially offset by:

Other non-operating income increased ~~$2.2~~$12.9 million primarily due to a higher ~~depreciation expense partially offset by lower system maintenance expense.~~

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 ratio between 50% and 60%, inclusive of long-term and short-term debt.~~structure. Additionally, we have various uncommitted trade credit lines with our gas suppliers that we utilize to purchase natural gas on a monthly basis.

On March 31, 2023, we filed a shelf registration statement with the Securities and Exchange Commission (SEC) that allows us to issue up to $5.0 billion in common stock and/or debt securities, which expires March 31, 2026. This shelf registration statement replaced our previous shelf registration statement which was filed on June 29, 2021. As of March 31, 2023, $4.0 billion of securities were available for issuance under this shelf registration statement.

On March 31, 2023, we filed a prospectus supplement under the shelf registrations 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 $1.0 billion through March 31, 2026 (including shares of common stock that may be sold pursuant to forward sale agreements entered into in connection with the ATM equity sales program). This ATM equity sales program replaced our previous ATM equity sales program, filed on March 23, 2022. As of March 31, 2023, $1.0 billion of equity was available for

issuance under our existing ATM equity sales program. Additionally, as of March 31, 2023, we had $673.2 million in available proceeds from outstanding forward sale agreements. Additional details are summarized in Note 7 to the unaudited condensed consolidated financial statements.

The following table summarizes our existing forward starting interest rate swaps as of the date of this report.

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~~2023. 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~~March 31, ~~2017,~~2023, September 30, ~~2017~~2022 and ~~December~~March 31, ~~2016:~~2022:


	March 31, 2023				September 30, 2022				March 31, 2022
	(In thousands, except percentages)
Short-term debt	$	—	—	%	$	184,967	1.1	%	$	—	—	%
Long-term debt (1)	6,554,609		39.1	%	7,962,104		45.3	%	7,958,999		47.0	%
Shareholders’ equity (2)	10,205,205		60.9	%	9,419,091		53.6	%	8,983,231		53.0	%
Total	$	16,759,814	100.0	%	$	17,566,162	100.0	%	$	16,942,230	100.0	%

(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 61.3% at September 30, 2022 and 60.9% at March 31, 2022.

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~~six months ended ~~December~~March 31, ~~2017~~2023 and ~~2016~~2022 are presented below.


	Six Months Ended March 31
	2023		2022		Change
	(In thousands)
Total cash provided by (used in)
Operating activities	$	2,892,716	$	640,484	$	2,252,232
Investing activities	(1,410,390)		(1,181,969)		(228,421)
Financing activities	(1,438,705)		1,007,257		(2,445,962)
Change in cash and cash equivalents	43,621		465,772		(422,151)
Cash and cash equivalents at beginning of period	51,554		116,723		(65,169)
Cash and cash equivalents at end of period	$	95,175	$	582,495	$	(487,320)

Three Months Ended December 31
2017 2016 Change
(In thousands)
Total cash provided by (used in)
Operating activities $ 173,238
$ 116,963
$ 56,275
Investing activities (381,372 ) (392,137 ) 10,765
Financing activities 236,475
272,264
(35,789 )
Change in cash and cash equivalents 28,341
(2,910 ) 31,251
Cash and cash equivalents at beginning of period 26,409
47,534
(21,125 )
Cash and cash equivalents at end of period $ 54,750
$ 44,624
$ 10,126

Cash flows from operating activities

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

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~~six months ended ~~December~~March 31, ~~2017,~~2023, cash used for investing activities was ~~$381.4~~$1,410.4 million compared to ~~$392.1~~$1,182.0 million infor the ~~prior-year period.~~six months ended March 31, 2022. Capital spending increased ~~by $85.3~~$225.3 million, ~~or 29 percent, as a~~which was primarily the result of ~~planned increases in our distribution segment to repair and replace vintage pipe, and increases in spending~~a $156.6 million increase in our pipeline and storage segment 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~~six months ended ~~December~~March 31, ~~2017,~~2023, our financing activities ~~provided $236.5~~used $1,438.7 million of cash compared with ~~$272.3~~$1,007.3 million ~~in the prior-year period. The $35.8 million decrease in~~of cash provided by financing activities ~~is primarily due to increased operating cash flow~~in the prior-year period.

In the six months ended March 31, 2023, we repaid $2.2 billion in long-term debt, and ~~lower cash used in investing activities.~~

~~During the first quarter,~~ we ~~used $395.1 million~~received approximately $1.2 billion in net proceeds from ~~equity financing~~the issuance of long-term debt and equity. We completed a public offering of $500 million of 5.75% senior notes due October 2052 and $300 million of 5.45% senior notes due October 2032, and received net proceeds from the offering, after the underwriting discount and offering expenses, of $789.4 million. Additionally, during the six months ended March 31, 2023, we settled 3,394,919 shares that had been sold on a forward basis for net proceeds of $359.7 million. The net proceeds were used primarily to ~~reduce short-term debt, to~~ support ~~our~~ capital spending and for other general corporate purposes. Cash dividends increased due to ~~a 7.8%~~an 8.8 percent increase in our dividend rate and an increase in shares outstanding.

~~During~~In the ~~first three~~six months ~~of fiscal 2017,~~ended March 31, 2022, we ~~issued $125 million of long-term debt under our three year, $200 million term loan agreement and~~ received ~~$49.4 million~~approximately $1.4 billion in net proceeds from the issuance of ~~common stock under~~long-term debt and equity. We completed a public offering of $600 million of 2.85% senior notes due February 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 September 2029, and received net proceeds of $200.8 million that were used to repay our ~~ATM program.~~$200 million floating-rate term loan. Additionally, during the six months ended March 31, 2022, we settled 6,162,269 shares that had been sold on a forward basis for net proceeds of $594.3 million. The net proceeds ~~from these debt and equity issuances~~ 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 ~~capital expenditures program. Short-term debt increased a net $110.9 million to temporarily finance the acquisition of the North Texas pipeline~~dividend rate and an increase in ~~December 2016.~~


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


	December 31, 2017			September 30, 2017				March 31, 2023		September 30, 2022
	(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	$	21,582,327	$	20,238,139
Less accumulated depreciation and amortization	2,090,835			2,042,122			Less accumulated depreciation and amortization	3,136,441		2,997,900
Net property, plant and equipment	9,518,792			9,259,182			Net property, plant and equipment	18,445,886		17,240,239
Current assets							Current assets
Cash and cash equivalents	54,750			26,409			Cash and cash equivalents	95,175		51,554
Accounts receivable, net	489,217			222,263
Accounts receivable, net (See Note 5)							Accounts receivable, net (See Note 5)	523,741		363,708
Gas stored underground	163,959			184,653			Gas stored underground	183,467		357,941
Other current assets	70,984			106,321
Other current assets (See Note 8)							Other current assets (See Note 8)	270,723		2,274,490
Total current assets	778,910			539,646			Total current assets	1,073,106		3,047,693
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)	1,061,612		1,173,800
	$	11,264,720		$	10,749,596			$	21,311,861	$	22,192,989
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: March 31, 2023 — 144,484,650 shares; September 30, 2022 — 140,896,598 shares							Common stock, no par value (stated at $0.005 per share); 200,000,000 shares authorized; issued and outstanding: March 31, 2023 — 144,484,650 shares; September 30, 2022 — 140,896,598 shares	$	722	$	704
Additional paid-in capital	2,940,062			2,536,365			Additional paid-in capital	6,213,523		5,838,118
Accumulated other comprehensive loss	(106,316		)	(105,254		)
Accumulated other comprehensive income							Accumulated other comprehensive income	360,997		369,112
Retained earnings	1,729,319			1,467,024			Retained earnings	3,629,963		3,211,157
Shareholders’ equity	4,563,620			3,898,666			Shareholders’ equity	10,205,205		9,419,091
Long-term debt	3,067,469			3,067,045			Long-term debt	6,553,097		5,760,647
Total capitalization	7,631,089			6,965,711			Total capitalization	16,758,302		15,179,738
Current liabilities							Current liabilities
Accounts payable and accrued liabilities	285,675			233,050			Accounts payable and accrued liabilities	364,973		496,019
Other current liabilities	336,919			332,648			Other current liabilities	746,512		720,157
Short-term debt	336,816			447,745			Short-term debt	—		184,967
Current maturities of long-term debt							Current maturities of long-term debt	1,512		2,201,457
Total current liabilities	959,410			1,013,443			Total current liabilities	1,112,997		3,602,600
Deferred income taxes	1,033,206			1,878,699			Deferred income taxes	2,135,738		1,999,505
Regulatory excess deferred taxes (See Note 6)	746,246			—
Regulatory excess deferred taxes							Regulatory excess deferred taxes	315,071		385,213
Regulatory cost of removal obligation	480,086			485,420			Regulatory cost of removal obligation	481,723		487,631
Pension and postretirement liabilities	233,337			230,588

Deferred credits and other liabilities	181,346			175,735			Deferred credits and other liabilities	508,030		538,302
	$	11,264,720		$	10,749,596			$	21,311,861	$	22,192,989


	December 31, 2017		September 30, 2017			March 31, 2023		September 30, 2022
	(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	$	24,096	$	31,122
Infrastructure mechanisms (1)					Infrastructure mechanisms (1)	203,010		235,972
Winter Storm Uri incremental costs (2)					Winter Storm Uri incremental costs (2)	121,493		2,109,454

Deferred gas costs	18,505		65,714		Deferred gas costs	49,156		119,742
Regulatory excess deferred taxes (3)					Regulatory excess deferred taxes (3)	47,656		47,311
Recoverable loss on reacquired debt	10,580		11,208		Recoverable loss on reacquired debt	3,322		3,406
Deferred pipeline record collection costs	12,942		11,692		Deferred pipeline record collection costs	51,967		36,898
APT annual adjustment mechanism	—		2,160
Rate case costs	3,160		2,629

Other	9,703		10,132		Other	13,231		21,467
	$	134,059	$	176,798		$	513,931	$	2,605,372
Regulatory liabilities:					Regulatory liabilities:
Regulatory excess deferred taxes⁽³⁾	$	746,246	$	—	Regulatory excess deferred taxes (3)	$	466,496	$	545,021

Regulatory cost of removal obligation	520,483		521,330		Regulatory cost of removal obligation	568,778		568,307
Deferred gas costs	19,739		15,559		Deferred gas costs	97,407		28,834
Asset retirement obligation	12,827		12,827		Asset retirement obligation	5,737		5,737
APT annual adjustment mechanism	1,720		—		APT annual adjustment mechanism	39,360		31,138
Pension and postretirement benefit costs					Pension and postretirement benefit costs	146,829		156,857
Other	7,673		5,941		Other	30,703		23,013
	$	1,308,688	$	555,657		$	1,355,310	$	1,358,907



	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


~~(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.


	Three Months Ended December 31, 2017													Six Months Ended March 31, 2023
	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	$	2,939,130	$	85,852	$	—	$	3,024,982
Intersegment revenues	339			97,724			(98,063		)	—			Intersegment revenues	1,506		285,201		(286,707)		—
Total operating revenues	860,792			126,463			(98,063		)	889,192			Total operating revenues	2,940,636		371,053		(286,707)		3,024,982
Purchased gas cost	463,758			912			(97,753		)	366,917			Purchased gas cost	1,690,938		(237)		(286,241)		1,404,460
Operation and maintenance expense	103,737			26,140			(310		)	129,567			Operation and maintenance expense	287,822		92,376		(466)		379,732
Depreciation and amortization expense	65,434			22,940			—			88,374			Depreciation and amortization expense	211,974		82,363		—		294,337
Taxes, other than income	55,107			7,666			—			62,773			Taxes, other than income	182,822		19,807		—		202,629
Operating income	172,756			68,805			—			241,561			Operating income	567,080		176,744		—		743,824
Miscellaneous expense	(1,400		)	(635		)	—			(2,035		)
Other non-operating income													Other non-operating income	14,239		24,358		—		38,597
Interest charges	21,368			10,141			—			31,509			Interest charges	44,259		29,871		—		74,130
Income before income taxes	149,988			58,029			—			208,017			Income before income taxes	537,060		171,231		—		708,291
Income tax benefit	(99,111		)	(7,004		)	—			(106,115		)
Income tax expense													Income tax expense	54,118		24,642		—		78,760
Net income	$	249,099		$	65,033		$	—		$	314,132		Net income	$	482,942	$	146,589	$	—	$	629,531
Capital expenditures	$	241,249		$	141,989		$	—		$	383,238		Capital expenditures	$	868,533	$	546,816	$	—	$	1,415,349



	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



	Three Months Ended December 31
	2017			2016 (1)
	(In thousands)
Increase (decrease) in fair value:
Interest rate agreements	$	(1,332	)	$	91,127
Forward commodity contracts⁽²⁾	—			9,847
Recognition of (gains) losses in earnings due to settlements:
Interest rate agreements	377			87
Forward commodity contracts⁽²⁾	—			(4,865		)
Total other comprehensive income (loss) from hedging, net of tax	$	(955	)	$	96,196


~~(1)~~	~~Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing jurisdiction 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.~~



	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


~~(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.~~



Planned Debt Issuance Date	Amount Hedged		Effective Interest Rate
	(In thousands)
Fiscal 2024	$	700,000	2.38	%
Fiscal 2025	600,000		1.75	%
Fiscal 2026	300,000		2.16	%
	$	1,600,000


	Fair Value of Contracts at March 31, 2023
	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	$	85,758	$	250,232	$	—	$	—	$	335,990
Prices based on models and other valuation methods	—		—		—		—		—
Total Fair Value	$	85,758	$	250,232	$	—	$	—	$	335,990



	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	)


(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.~~



Item 3.			Quantitative and Qualitative Disclosures About Market Risk



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)~~



*			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.


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