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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended September 30, 2021

OR

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

For the transition period from                      to                     

Commission file number 1-10042

Atmos Energy Corporation

(Exact name of registrant as specified in its charter)

    Texas and Virginia    75-1743247

    (State or other jurisdiction of    (IRS employer

    incorporation or organization)    identification no.)

    1800 Three Lincoln Centre

    5430 LBJ Freeway

    Dallas, Texas    75240

    (Address of principal executive offices)    (Zip code)

Registrant’s telephone number, including area code:

(972) 934-9227

Securities registered pursuant to Section 12(b) of the Act:

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

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  þ        No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨        No  þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ        No  ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).    Yes  þ        No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ☑ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ☐       No  þ

The aggregate market value of the common voting stock held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second fiscal quarter, March 31, 2021, was $12,737,499,573.

As of November 5, 2021, the registrant had 132,425,817 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Definitive Proxy Statement to be filed for the Annual Meeting of Shareholders on February 9, 2022 are incorporated by reference into Part III of this report.

Table of Contents

TABLE OF CONTENTS

		Page
Glossary of Key Terms		3
	Part I
Item 1.	Business	4
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	18
Item 2.	Properties	18
Item 3.	Legal Proceedings	19
Item 4.	Mine Safety Disclosures	19
	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	20
Item 6.	Selected Financial Data	21
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	34
Item 8.	Financial Statements and Supplementary Data	35
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	85
Item 9A.	Controls and Procedures	85
Item 9B.	Other Information	87
	Part III
Item 10.	Directors, Executive Officers and Corporate Governance	87
Item 11.	Executive Compensation	88
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	88
Item 13.	Certain Relationships and Related Transactions, and Director Independence	88
Item 14.	Principal Accountant Fees and Services	88
	Part IV
Item 15.	Exhibits and Financial Statement Schedules	88
Item 16.	Form 10-K Summary	92

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GLOSSARY OF KEY TERMS

Adjusted diluted net income per share	Non-GAAP measure defined as diluted net income per share before the one-time, non-cash income tax benefit
Adjusted net income	Non-GAAP measure defined as net income before the one-time, non-cash income tax benefit
AFUDC	Allowance for funds used during construction
AOCI	Accumulated Other Comprehensive Income
ARM	Annual Rate Mechanism
ATO	Trading symbol for Atmos Energy Corporation common stock on the NYSE
Bcf	Billion cubic feet
COSO	Committee of Sponsoring Organizations of the Treadway Commission
DARR	Dallas Annual Rate Review
ERISA	Employee Retirement Income Security Act of 1974
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles
GRIP	Gas Reliability Infrastructure Program
GSRS	Gas System Reliability Surcharge
LIBOR	London Interbank Offered Rate
LTIP	1998 Long-Term Incentive Plan
Mcf	Thousand cubic feet
MDWQ	Maximum daily withdrawal quantity
Mid-Tex ATM Cities	Represents a coalition of 47 incorporated cities or approximately 10 percent of the Mid-Tex Division's customers.
Mid-Tex Cities	Represents all incorporated cities other than Dallas and Mid-Tex ATM Cities, or approximately 72 percent of the Mid-Tex Division’s customers.
MMcf	Million cubic feet
Moody’s	Moody’s Investor Service, Inc.
NGPA	Natural Gas Policy Act of 1978
NTSB	National Transportation Safety Board
NYSE	New York Stock Exchange
PHMSA	Pipeline and Hazardous Materials Safety Administration
PPA	Pension Protection Act of 2006
PRP	Pipeline Replacement Program
RRC	Railroad Commission of Texas
RRM	Rate Review Mechanism
RSC	Rate Stabilization Clause
S&P	Standard & Poor’s Corporation
SAVE	Steps to Advance Virginia Energy
SEC	United States Securities and Exchange Commission
SIR	System Integrity Rider
SRF	Stable Rate Filing
SSIR	System Safety and Integrity Rider
TCJA	Tax Cuts and Jobs Act of 2017
WNA	Weather Normalization Adjustment

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PART I

The terms “we,” “our,” “us,” “Atmos Energy” and the “Company” refer to Atmos Energy Corporation and its subsidiaries, unless the context suggests otherwise.

ITEM 1. Business.

Overview and Strategy

Atmos Energy Corporation, headquartered in Dallas, Texas, and incorporated in Texas and Virginia, is the country’s largest natural-gas-only distributor based on number of customers. We safely deliver reliable, affordable, efficient and abundant natural gas through regulated sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers in eight states located primarily in the South. We also operate one of the largest intrastate pipelines in Texas based on miles of pipe.

Atmos Energy's vision is to be the safest provider of natural gas services. We intend to achieve this vision by:

•operating our business exceptionally well

•investing in safety, innovation and environmental sustainability, and

•achieving superior financial results.

Since 2011, our operating strategy has focused on modernizing our distribution and transmission system while reducing regulatory lag. This operating strategy has allowed us to increase our capital expenditures approximately 13 percent per year to improve safety and reliability and to reduce methane emissions from our system.

Our core values include focusing on our employees and customers while conducting our business with honesty and integrity. We continue to strengthen our culture through ongoing communications with our employees and enhanced employee training.

Operating Segments

As of September 30, 2021, 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.

Distribution Segment Overview

The following table summarizes key information about our six regulated natural gas distribution divisions, presented in order of total rate base.

Division	Service Areas	Communities Served	Customer Meters
Mid-Tex	Texas, including the Dallas/Fort Worth Metroplex	550	1,791,482
Kentucky/Mid-States	Kentucky	230	183,937
	Tennessee		159,461
	Virginia		24,746
Louisiana	Louisiana	270	373,207
West Texas	Amarillo, Lubbock, Midland	80	326,419
Mississippi	Mississippi	110	272,993
Colorado-Kansas	Colorado	170	125,241
	Kansas		139,763

We operate in our service areas under terms of non-exclusive franchise agreements granted by the various cities and towns that we serve. At September 30, 2021, we held 1,025 franchises having terms generally ranging from five to 35 years. A

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significant number of our franchises expire each year, which require renewal prior to the end of their terms. Historically, we have successfully renewed these franchises and believe that we will continue to be able to renew our franchises as they expire.

Revenues in this operating segment are established by regulatory authorities in the states in which we operate. These rates are intended to be sufficient to cover the costs of conducting business, including a reasonable return on invested capital. In addition, we transport natural gas for others through our distribution systems.

Rates established by regulatory authorities often include cost adjustment mechanisms for costs that (i) are subject to significant price fluctuations compared to our other costs, (ii) represent a large component of our cost of service and (iii) are generally outside our control.

Purchased gas cost adjustment mechanisms represent a traditional and common form of cost adjustment mechanism. Purchased gas cost adjustment mechanisms provide a method of recovering purchased gas costs on an ongoing basis without filing a rate case because they provide a dollar-for-dollar offset to increases or decreases in the cost of natural gas. Therefore, although substantially all of our distribution operating revenues fluctuate with the cost of gas that we purchase, distribution operating income is generally not affected by fluctuations in the cost of gas.

Additionally, some jurisdictions have performance-based ratemaking adjustments to provide incentives to minimize purchased gas costs through improved storage management and use of financial instruments to reduce volatility in gas costs. Under the performance-based ratemaking adjustments, purchased gas costs savings are shared between the Company and its customers.

Our supply of natural gas is provided by a variety of suppliers, including independent producers and marketers. The gas is delivered into our systems by various pipeline companies, withdrawals of gas from proprietary and contracted storage assets and base load and peaking arrangements, as needed.

Supply arrangements consist of both base load and peaking quantities and are contracted from our suppliers on a firm basis with various terms at market prices. Base load quantities are those that flow at a constant level throughout the month and peaking quantities provide the flexibility to change daily quantities to match increases or decreases in requirements related to weather conditions.

Except for local production purchases, we select our natural gas suppliers through a competitive bidding process by periodically requesting proposals from suppliers. We select these suppliers based on their ability to reliably deliver gas supply to our designated firm pipeline receipt points at the lowest reasonable cost. Major suppliers during fiscal 2021 were Castleton Commodities Merchant Trading L.P., Cima Energy, LP, Concord Energy LLC, EnLink Gas Marketing LP, ETC Gas Marketing LTD, Hartree Partners, L.P., Kinder Morgan Texas Pipeline LLC, Symmetry Energy Solutions, LLC, Targa Gas Marketing LLC and Twin Eagle Resources Management, LLC.

The combination of base load and peaking agreements, coupled with the withdrawal of gas held in storage, allows us the flexibility to adjust to changes in weather, which minimizes our need to enter into long-term firm commitments. We estimate our peak-day availability of natural gas supply to be approximately 4.4 Bcf. The peak-day demand for our distribution operations in fiscal 2021 was on February 14, 2021, when sales to customers reached approximately 4.3 Bcf.

Currently, our distribution divisions utilize 35 pipeline transportation companies, both interstate and intrastate, to transport our natural gas. The pipeline transportation agreements are firm and many of them have “pipeline no-notice” storage service, which provides for daily balancing between system requirements and nominated flowing supplies. These agreements have been negotiated with the shortest term necessary while still maintaining our right of first refusal. The natural gas supply for our Mid-Tex Division is delivered primarily by our APT Division.

To maintain our deliveries to high priority customers, we have the ability, and have exercised our right, to interrupt or curtail service to certain customers pursuant to contracts and applicable state regulations or statutes. Our customers’ demand on our system is not necessarily indicative of our ability to meet current or anticipated market demands or immediate delivery requirements because of factors such as the physical limitations of gathering, storage and transmission systems, the duration and severity of cold weather, the availability of gas reserves from our suppliers, the ability to purchase additional supplies on a short-term basis and actions by federal and state regulatory authorities. Interruption and curtailment rights provide us the flexibility to meet the human-needs requirements of our customers on a reliable basis. Priority allocations imposed by federal and state regulatory agencies, as well as other factors beyond our control, may affect our ability to meet the demands of some of our customers.

Pipeline and Storage Segment Overview

Our pipeline and storage segment consists of the pipeline and storage operations of APT and our natural gas transmission operations in Louisiana. APT is one of the largest intrastate pipeline operations in Texas with a heavy concentration in the established natural gas-producing areas of central, northern and eastern Texas, extending into or near the major producing areas of the Barnett Shale, the Texas Gulf Coast and the Permian Basin of West Texas. Through its system, APT provides transportation and storage services to our Mid-Tex Division, other third party local distribution companies, industrial and

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electric generation customers, marketers and producers. As part of its pipeline operations, APT owns and operates five underground storage reservoirs in Texas.

Revenues earned from transportation and storage services for APT are subject to traditional ratemaking governed by the RRC. Rates are updated through periodic filings made under Texas’ GRIP. GRIP allows us to include in our rate base annually approved capital costs incurred in the prior calendar year provided that we file a complete rate case at least once every five years; the most recent of which was completed in August 2017. APT’s existing regulatory mechanisms allow certain transportation and storage services to be provided under market-based rates.

Our natural gas transmission operations in Louisiana are comprised of a 21-mile pipeline located in the New Orleans, Louisiana area that is primarily used to aggregate gas supply for our distribution division in Louisiana under a long-term contract and, on a more limited basis, to third parties. The demand fee charged to our Louisiana distribution division for these services is subject to regulatory approval by the Louisiana Public Service Commission. We also manage two asset management plans in Louisiana that serve distribution affiliates of the Company, 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.

Ratemaking Activity

Overview

The method of determining regulated rates varies among the states in which our regulated businesses operate. The regulatory authorities have the responsibility of ensuring that utilities in their jurisdictions operate in the best interests of customers while providing utility companies the opportunity to earn a reasonable return on their investment. Generally, each regulatory authority reviews rate requests and establishes a rate structure intended to generate revenue sufficient to cover the costs of conducting business, including a reasonable return on invested capital.

Our rate strategy focuses on reducing or eliminating regulatory lag, obtaining adequate returns and providing stable, predictable margins, which benefit both our customers and the Company. As a result of our ratemaking efforts in recent years, Atmos Energy has:

•Formula rate mechanisms in place in four states that provide for an annual rate review and adjustment to rates.

•Infrastructure programs in place in all of our states that provide for an annual adjustment to rates for qualifying capital expenditures. Through our annual formula rate mechanisms and infrastructure programs, we have the ability to recover approximately 90 percent of our capital expenditures within six months and substantially all of our capital expenditures within twelve months.

•Authorization in tariffs, statute or commission rules that allows us to defer certain elements of our cost of service such as depreciation, ad valorem taxes and pension costs, until they are included in rates.

•WNA mechanisms in seven states that serve to minimize the effects of weather on approximately 96 percent of our distribution residential and commercial revenues.

•The ability to recover the gas cost portion of bad debts in five states.

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The following table provides a jurisdictional rate summary for our regulated operations as of September 30, 2021. This information is for regulatory purposes only and may not be representative of our actual financial position.

Division	Jurisdiction	Effective Date of Last Rate/GRIP Action	Rate Base (thousands)(1)	Authorized Rate of Return(1)	Authorized Debt/ Equity Ratio(1)	Authorized Return on Equity(1)
Atmos Pipeline — Texas	Texas	05/11/2021	$2,924,585	8.87%	47/53	11.50%
Colorado-Kansas	Colorado	05/03/2018	134,726	7.55%	44/56	9.45%
	Colorado SSIR	01/01/2021	78,265	7.55%	44/56	9.45%
	Kansas	04/01/2020	242,314	7.03%	44/56	9.10%
	Kansas GSRS	02/01/2021	16,917	7.03%	44/56	9.10%
Kentucky/Mid-States	Kentucky	05/08/2019	424,929	7.49%	42/58	9.65%
	Kentucky-PRP	10/01/2020	39,368	7.49%	42/58	9.65%
	Tennessee	06/01/2021	421,189	7.62%	40/60	9.80%
	Virginia	04/01/2019	47,827	7.43%	42/58	9.20%
	Virginia-SAVE	10/01/2020	3,509	7.43%	42/58	9.20%
Louisiana	Louisiana	07/01/2021	837,325	7.30%	(4)	(4)
Mid-Tex	Mid-Tex Cities(6)	12/01/2020	3,726,295(5)	7.53%	42/58	9.80%
	Mid-Tex - ATM Cities	06/11/2021	4,307,060(5)	7.97%	40/60	9.80%
	Mid-Tex - Environs	09/01/2021	4,307,060(5)	7.97%	40/60	9.80%
	Dallas	06/09/2021	4,293,195(5)	7.57%	41/59	9.80%
Mississippi	Mississippi(7)	11/01/2020	474,216	7.81%	(4)	(4)
	Mississippi - SIR(7)	11/01/2020	247,414	7.81%	(4)	(4)
West Texas	West Texas Cities(8) (10)	12/01/2020	660,893(9)	7.53%	42/58	9.80%
	West Texas - ALDC	06/01/2021	751,829(9)	7.35%	(4)	(4)
	West Texas - Environs	06/11/2021	765,101(9)	7.97%	40/60	9.80%

Division	Jurisdiction	Bad  Debt Rider(2)	Formula Rate	Infrastructure Mechanism	Performance Based Rate Program(3)	WNA Period
Atmos Pipeline —  Texas	Texas	No	Yes	Yes	N/A	N/A
Colorado-Kansas	Colorado	No	No	Yes	No	N/A
	Kansas	Yes	No	Yes	Yes	October-May
Kentucky/Mid-States	Kentucky	Yes	No	Yes	Yes	November-April
	Tennessee	Yes	Yes	Yes	Yes	October-April
	Virginia	Yes	No	Yes	No	January-December
Louisiana	Louisiana	No	Yes	Yes	No	December-March
Mid-Tex Cities	Texas	Yes	Yes	Yes	No	November-April
Mid-Tex — Dallas	Texas	Yes	Yes	Yes	No	November-April
Mississippi	Mississippi	No	Yes	Yes	No	November-April
West Texas	Texas	Yes	Yes	Yes	No	October-May

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(1)The rate base, authorized rate of return, authorized debt/equity ratio and authorized return on equity presented in this table are those from the most recent regulatory filing for each jurisdiction. These rate bases, rates of return, debt/equity ratios and returns on equity are not necessarily indicative of current or future rate bases, rates of return or returns on equity.

(2)The bad debt rider allows us to recover from customers the gas cost portion of bad debts.

(3)The performance-based rate program provides incentives to distribution companies to minimize purchased gas costs by allowing the companies and their customers to share the purchased gas costs savings.

(4)A rate base, rate of return, return on equity or debt/equity ratio was not included in the respective state commission’s final decision.

(5)The Mid-Tex rate base represents a “system-wide,” or 100 percent, of the Mid-Tex Division’s rate base.

(6)The Mid-Tex Cities approved the Formula Rate Mechanism filing with rates effective December 1, 2021, which included a rate base of $4,394.5 million, an authorized return of 7.36%, a debt/equity ratio of 42/58 and an authorized ROE of 9.80%.

(7)The Mississippi Public Service Commission approved a settlement at its meeting on October 14, 2021, which included a rate base of $797.6 million and an authorized return of 7.81%. New rates were implemented November 1, 2021.

(8)The West Texas Cities includes all West Texas Division cities except Amarillo, Channing, Dalhart and Lubbock (ALDC).

(9)The West Texas rate base represents a "system-wide," or 100 percent, of the West Texas Division's rate base.

(10)The West Texas Cities approved the Formula Rate Mechanism filing with rates effective December 1, 2021, which included a rate base of $759.0 million, an authorized return of 7.36%, a debt/equity ratio of 42/58 and an authorized ROE of 9.80%.

Although substantial progress has been made in recent years to improve rate design and recovery of investment across our service areas, we are continuing to seek improvements in rate design to address cost variations and pursue tariffs that reduce regulatory lag associated with investments. Further, potential changes in federal energy policy, federal safety regulations and changing economic conditions will necessitate continued vigilance by the Company and our regulators in meeting the challenges presented by these external factors.

Recent Ratemaking Activity

The amounts described in the following sections represent the annual 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 the commission's or other governmental authority's final ruling. The following table summarizes the annualized ratemaking outcomes we implemented in each of the last three fiscal years.

	Annual Increase (Decrease) to Operating Income For the Fiscal Year Ended September 30
Rate Action	2021		2020		2019
	(In thousands)
Annual formula rate mechanisms	$	181,459	$	160,857	$	114,810
Rate case filings	5,119		(1,057)		1,656
Other ratemaking activity	(877)		353		214
	$	185,701	$	160,153	$	116,680

Additionally, the ratemaking outcomes for the rate activity in fiscal 2021 include the refund of excess deferred income taxes 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 fiscal 2021 rate outcomes for ratemaking activities were $226.2 million.

The following ratemaking efforts seeking $56.5 million in annual operating income were initiated during fiscal 2021 but had not been completed or implemented as of September 30, 2021:

Division	Rate Action	Jurisdiction	Operating Income Requested
			(In thousands)
Kentucky/Mid-States	Infrastructure Mechanism	Virginia (1)	$	350
Kentucky/Mid-States	Rate Case	Kentucky (2)	14,394
Kentucky/Mid-States	Infrastructure Mechanism	Kentucky	3,506
Mid-Tex	Formula Rate Mechanism	Mid-Tex Cities (3)	29,707
Mississippi	Infrastructure Mechanism	Mississippi (4)	8,354
Mississippi	Formula Rate Mechanism	Mississippi (4)	(730)
West Texas	Formula Rate Mechanism	West Texas Cities (5)	903
			$	56,484

(1)     On August 23, 2021, the State Corporation Commission of Virginia approved a rate increase of $0.3 million effective October 1, 2021.

(2)    The Kentucky rate case filing also includes the $3.5 million related to the annual Kentucky pipeline replacement program.

(3)     The Mid-Tex Cities approved a rate increase of $21.7 million, which includes $33.8 million related to the refund of excess deferred income taxes that will be offset by lower income tax expense. New rates will be implemented on December 1, 2021.

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(4) The Mississippi Public Service Commission (MPSC) approved an increase in operating income of $8.4 million for the SIR filing, which includes $2.1 million related to the refund of excess deferred income taxes that will be offset by lower income tax expense. The MPSC also approved a reduction in operating income of $5.6 million for the SRF filing, which includes $4.3 million related to the refund of excess deferred income taxes that will be offset by lower income tax expense. New rates for both filings were implemented November 1, 2021.

(5)    The West Texas Cities approved a rate increase of $0.2 million, which includes $3.3 million related to the refund of excess deferred income taxes that will be offset by lower income tax expense. New rates will be implemented on December 1, 2021.

Our recent ratemaking activity is discussed in greater detail below.

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 specific infrastructure programs in substantially all of our distribution divisions with tariffs in place to permit the investment associated with these programs to have their surcharge rate adjusted annually to recover approved capital costs incurred in a prior test-year period. The following table summarizes our annual formula rate mechanisms by state.

	Annual Formula Rate Mechanisms
State	Infrastructure Programs	Formula Rate Mechanisms
Colorado	System Safety and Integrity Rider (SSIR)	—
Kansas	Gas System Reliability Surcharge (GSRS)	—
Kentucky	Pipeline Replacement Program (PRP)	—
Louisiana	(1)	Rate Stabilization Clause (RSC)
Mississippi	System Integrity Rider (SIR)	Stable Rate Filing (SRF)
Tennessee	(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 table summarizes our annual formula rate mechanisms with effective dates during the fiscal years ended September 30, 2021, 2020 and 2019:

Division	Jurisdiction	Test Year Ended	Increase (Decrease) in Annual Operating Income		Effective Date
			(In thousands)
2021 Filings:
Mid-Tex	Environs	12/2020	$	4,632	09/01/2021
Louisiana	Louisiana (1) (4)	12/2020	(2,407)		07/01/2021
Mid-Tex	ATM Cities (2)	12/2020	11,085		06/11/2021
West Texas	Triangle (2)	12/2020	416		06/11/2021
West Texas	Environs (2)	12/2020	1,267		06/11/2021
Mid-Tex	DARR (2) (4)	09/2020	1,708		06/09/2021
Kentucky/Mid-States	Tennessee ARM	09/2020	10,260		06/01/2021
Atmos Pipeline - Texas	Texas	12/2020	43,868		05/11/2021
Colorado-Kansas	Kansas GSRS	09/2020	1,695		02/01/2021
Colorado-Kansas	Colorado SSIR	12/2021	2,366		01/01/2021
Mid-Tex	Mid-Tex Cities RRM	12/2019	82,645		12/01/2020
West Texas	West Texas Cities RRM	12/2019	5,645		12/01/2020
Mississippi	Mississippi - SIR	10/2021	10,556		11/01/2020

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Mississippi	Mississippi - SRF	10/2021	5,856		11/01/2020
Kentucky/Mid-States	Virginia - SAVE	09/2021	305		10/01/2020
Kentucky/Mid-States	Kentucky PRP	09/2021	1,562		10/01/2020
Total 2021 Filings (4)			$	181,459
2020 Filings:
Mid-Tex	DARR	09/2019	$	14,746	09/01/2020
Louisiana	Louisiana (1)	12/2019	14,781		07/01/2020
West Texas	Environs (3)	12/2019	1,031		06/16/2020
Kentucky/Mid-States	Tennessee ARM	05/2019	714		06/15/2020
Mid-Tex	ATM Cities (3)	12/2019	11,148		06/12/2020
Mid-Tex	Environs (3)	12/2019	4,440		05/20/2020
Atmos Pipeline - Texas	Texas	12/2019	49,251		05/20/2020
West Texas	Amarillo, Lubbock, Dalhart and Channing (3)	12/2019	5,937		04/28/2020
Colorado-Kansas	Colorado SSIR	12/2020	2,082		01/01/2020
Mississippi	Mississippi - SIR	10/2020	7,586		11/01/2019
Mississippi	Mississippi - SRF	10/2020	6,886		11/01/2019
Kentucky/Mid-States	Virginia - SAVE	09/2020	84		10/01/2019
Kentucky/Mid-States	Kentucky PRP	09/2020	2,912		10/01/2019
Mid-Tex	Mid-Tex RRM Cities	12/2018	34,380		10/01/2019
West Texas	West Texas Cities RRM	12/2018	4,879		10/01/2019
Total 2020 Filings			$	160,857
2019 Filings:
Mid-Tex	ATM Cities	12/2018	$	6,591	09/26/2019
Louisiana	LGS	12/2018	7,124		07/01/2019
Mid-Tex	Environs	12/2018	2,435		06/04/2019
West Texas	Environs	12/2018	1,005		06/04/2019
Mid-Tex	DARR	09/2018	9,452		06/01/2019
Kentucky/Mid-States	Tennessee ARM	05/2020	2,393		06/01/2019
Atmos Pipeline - Texas	Texas	12/2018	49,225		05/07/2019
West Texas	Amarillo, Lubbock, Dalhart and Channing	12/2018	5,692		05/01/2019
Colorado-Kansas	Kansas GSRS	12/2018	1,562		05/01/2019
Louisiana	Trans La	09/2018	4,719		04/01/2019
Colorado-Kansas	Colorado GIS	12/2019	87		04/01/2019
Colorado-Kansas	Colorado SSIR	12/2019	2,147		01/01/2019
Mississippi	Mississippi - SIR	10/2019	7,135		11/01/2018
Mississippi	Mississippi - SRF	10/2019	(118)		11/01/2018
Kentucky/Mid-States	Tennessee ARM	05/2019	(5,032)		10/15/2018
Mid-Tex	Mid-Tex RRM Cities	12/2017	17,633		10/01/2018
West Texas	West Texas Cities RRM	12/2017	2,760		10/01/2018
Total 2019 Filings			$	114,810

(1)    Beginning in fiscal 2020, our Trans La and LGS filings were combined into one filing, per Commission order.

(2)    The rate increases for these filings were approved based on the effective dates herein; however, the new rates were implemented beginning September 1, 2021.

(3)    The rate increases for our Texas GRIP filings were approved based on the effective date herein; however, the new rates were implemented beginning September 1, 2020.

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(4)    The rate change for the DARR and RSC filings include $15.1 million for the DARR filing and $24.2 million for the RSC filing related to the refund of excess deferred income taxes that will be offset by lower income tax expense. Excluding the amounts related to the refund of excess deferred taxes, our total fiscal 2021 rate outcomes for our formula rate mechanisms were $220.8 million.

Rate Case Filings

A rate case is a formal request from Atmos Energy to a regulatory authority to increase rates that are charged to 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 reasonable rate of return to our shareholders and ensure that we continue to safely deliver reliable, reasonably priced natural gas service to our customers.

The following table summarizes our recent rate cases:

Division	State	Increase (Decrease) in Annual Operating Income		Effective Date
		(In thousands)
2021 Rate Case Filings:
West Texas (ALDC) (1)	Texas	$	5,119	06/01/2021
Total 2021 Rate Case Filings		$	5,119
2020 Rate Case Filings:
West Texas (Triangle)	Texas	$	(808)	04/21/2020
Colorado-Kansas	Kansas	(249)		04/01/2020
Total 2020 Rate Case Filings		$	(1,057)
2019 Rate Case Filings:
Mid-Tex (ATM Cities)	Texas	$	2,113	06/01/2019
Kentucky/Mid-States	Kentucky	3,441		05/08/2019
Kentucky/Mid-States	Virginia	(400)		04/01/2019
Mid-Tex (Environs)	Texas	(2,674)		01/01/2019
West Texas (Environs)	Texas	(824)		01/01/2019
Total 2019 Rate Case Filings		$	1,656

(1)    The rate change for the West Texas (ALDC) filing includes $1.2 million related to the refund of excess deferred income taxes, which will be offset by lower income tax expense. Excluding this amount related to the refund of excess deferred income taxes, the increase to operating income for this filing was $6.3 million.

Other Ratemaking Activity

The following table summarizes other ratemaking activity during the fiscal years ended September 30, 2021, 2020 and 2019:

Division	Jurisdiction	Rate Activity	Increase (Decrease) in Annual Operating Income		Effective Date
			(In thousands)
2021 Other Rate Activity:
Colorado-Kansas	Kansas	Ad Valorem (1)	$	(877)	02/01/2021
Total 2021 Other Rate Activity			$	(877)
2020 Other Rate Activity:
Colorado-Kansas	Kansas	Ad Valorem(1)	$	353	02/01/2020
Total 2020 Other Rate Activity			$	353
2019 Other Rate Activity:
Colorado-Kansas	Kansas	Ad-Valorem(1)	$	214	02/01/2019
Total 2019 Other Rate Activity			$	214

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

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Other Regulation

We are regulated by various state or local public utility authorities. We are also subject to regulation by the United States Department of Transportation with respect to safety requirements in the operation and maintenance of our transmission and distribution facilities. In addition, our operations are also subject to various state and federal laws regulating environmental matters. From time to time, we receive inquiries regarding various environmental matters. We believe that our properties and operations comply with, and are operated in conformity with, applicable safety and environmental statutes and regulations. There are no administrative or judicial proceedings arising under environmental quality statutes pending or known to be contemplated by governmental agencies which would have a material adverse effect on us or our operations. The Pipeline and Hazardous Materials Safety Administration (PHMSA), within the U.S. Department of Transportation, develops and enforces regulations for the safe, reliable and environmentally sound operation of the pipeline transportation system. The PHMSA pipeline safety statutes provide for states to assume safety authority over intrastate natural transmission and distribution gas pipelines. State pipeline safety programs are responsible for adopting and enforcing the federal and state pipeline safety regulations for intrastate natural gas transmission and distribution pipelines.

The Federal Energy Regulatory Commission (FERC) allows, pursuant to Section 311 of the Natural Gas Policy Act (NGPA), gas transportation services through our APT assets “on behalf of” interstate pipelines or local distribution companies served by interstate pipelines, without subjecting these assets to the jurisdiction of the FERC under the NGPA. Additionally, the FERC has regulatory authority over the use and release of interstate pipeline and storage capacity. The FERC also has authority to detect and prevent market manipulation and to enforce compliance with FERC’s other rules, policies and orders by companies engaged in the sale, purchase, transportation or storage of natural gas in interstate commerce. We have taken what we believe are the necessary and appropriate steps to comply with these regulations.

The SEC and the Commodities Futures Trading Commission, pursuant to the Dodd–Frank Act, established numerous regulations relating to U.S. financial markets. We enacted procedures and modified existing business practices and contractual arrangements to comply with such regulations. There are, however, some rulemaking proceedings that have not yet been finalized, including those relating to capital and margin rules for (non–cleared) swaps. We do not expect these rules to directly impact our business practices or collateral requirements. However, depending on the substance of these final rules, in addition to certain international regulatory requirements still under development that are similar to Dodd–Frank, our swap counterparties could be subject to additional and potentially significant capitalization requirements. These regulations could motivate counterparties to increase our collateral requirements or cash postings.

Competition

Although our regulated distribution operations are not currently in significant direct competition with any other distributors of natural gas to residential and commercial customers within our service areas, we do compete with other natural gas suppliers and suppliers of alternative fuels for sales to industrial customers. We compete in all aspects of our business with alternative energy sources, including, in particular, electricity. Electric utilities offer electricity as a rival energy source and compete for the space heating, water heating and cooking markets. Promotional incentives, improved equipment efficiencies and promotional rates all contribute to the acceptability of electrical equipment. The principal means to compete against alternative fuels is lower prices, and natural gas historically has maintained its price advantage in the residential, commercial and industrial markets.

Our pipeline and storage operations have historically faced competition from other existing intrastate pipelines seeking to provide or arrange transportation, storage and other services for customers. In the last few years, several new pipelines have been completed, which has increased the level of competition in this segment of our business.

Employees

The Corporate Responsibility, Sustainability, and Safety Committee of the Board of Directors oversees matters relating to equal employment opportunities, diversity, and inclusion; human workplace rights; employee health and safety; and the Company’s vision, values, and culture. It also assists management in integrating responsibility and sustainability into strategic business activities to create long-term shareholder value.

Our culture respects and appreciates inclusion and diversity. Thus, we strive to have a workforce that reflects the unique 1,400 communities that we serve. At September 30, 2021, we had 4,684 employees, substantially unchanged from last year. We monitor our workforce data on a calendar year basis. As of December 31, 2020, 61 percent of our employees worked in field roles and 39 percent worked in support/shared services roles. No employees are subject to a collective bargaining agreement.

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To recruit and hire individuals with a variety of skills, talents, backgrounds and experiences, we value and cultivate our strong relationships with hundreds of community and diversity outreach sources. We also target jobs fairs including those focused on minority, veteran and women candidates and partner with local colleges and universities to identify and recruit qualified applicants in each of the cities and towns we serve. Over the last five calendar years, we hired over 2,000 employees. Our culture is also reflected in our employee benefits. The physical, mental and financial health of our employees and their families is a top priority for the Company, which is why we have a strong, competitive benefits program to help employees and their families manage and protect their health, wealth and time.

We perform succession planning annually to ensure that we develop and sustain a strong bench of talent capable of performing at the highest levels. Not only is talent identified, but potential paths of development are discussed to ensure that employees have an opportunity to build their skills and are well-prepared for future roles. The strength of our succession planning process is evident through our long history of promoting our leaders from within the organization.

Available Information

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports, and amendments to those reports, and other forms that we file with or furnish to the Securities and Exchange Commission (SEC) at their website, www.sec.gov, are also available free of charge at our website, www.atmosenergy.com, under “Publications and SEC Filings” under the “Investors” tab under "Our Company", as soon as reasonably practicable, after we electronically file these reports with, or furnish these reports to, the SEC. We will also provide copies of these reports free of charge upon request to Shareholder Relations at the address and telephone number appearing below:

Shareholder Relations

Atmos Energy Corporation

P.O. Box 650205

Dallas, Texas 75265-0205

972-855-3729

Corporate Governance

In accordance with and pursuant to relevant related rules and regulations of the SEC as well as corporate governance-related listing standards of the New York Stock Exchange (NYSE), the Board of Directors of the Company has established and periodically updated our Corporate Governance Guidelines and Code of Conduct, which is applicable to all directors, officers and employees of the Company. In addition, in accordance with and pursuant to such NYSE listing standards, our Chief Executive Officer during fiscal 2021, John K. Akers, certified to the New York Stock Exchange that he was not aware of any violations by the Company of NYSE corporate governance listing standards. The Board of Directors also annually reviews and updates, if necessary, the charters for each of its Audit, Human Resources, Nominating and Corporate Governance and Corporate Responsibility, Sustainability and Safety Committees. All of the foregoing documents are posted on our website, www.atmosenergy.com, on the "Reports" page under "Corporate Responsibility." We will also provide copies of all corporate governance documents free of charge upon request to Shareholder Relations at the address listed above.

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ITEM 1A. Risk Factors.

Our financial and operating results are subject to a number of risk factors, many of which are not within our control. Investors should carefully consider the following discussion of risk factors as well as other information appearing in this report. These factors include the following, which are organized by category:

Regulatory and Legislative Risks

We are subject to federal, state and local regulations that affect our operations and financial results.

We are subject to regulatory oversight from various federal, state and local regulatory authorities in the eight states that we serve. Therefore, our returns are continuously monitored and are subject to challenge for their reasonableness by the appropriate regulatory authorities or other third-party intervenors. In the normal course of business, as a regulated entity, we often need to place assets in service and establish historical test periods before rate cases that seek to adjust our allowed returns to recover that investment can be filed. Further, the regulatory review process can be lengthy in the context of traditional ratemaking. Because of this process, we suffer the negative financial effects of having placed assets in service without the benefit of rate relief, which is commonly referred to as “regulatory lag.”

However, in the last several years, a number of regulatory authorities in the states we serve have approved rate mechanisms that provide for annual adjustments to rates that allow us to recover the cost of investments made to replace existing infrastructure or reflect changes in our cost of service. These mechanisms work to effectively reduce the regulatory lag inherent in the ratemaking process. However, regulatory lag could significantly increase if the regulatory authorities modify or terminate these rate mechanisms. The regulatory process also involves the risk that regulatory authorities may (i) review our purchases of natural gas and adjust the amount of our gas costs that we pass through to our customers or (ii) limit the costs we may have incurred from our cost of service that can be recovered from customers.

We are also subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local governmental authorities relating to protection of the environment and health and safety matters, including those that govern discharges of substances into the air and water, the management and disposal of hazardous substances and waste, the clean-up of contaminated sites, groundwater quality and availability, plant and wildlife protection, as well as work practices related to employee health and safety. Environmental legislation also requires that our facilities, sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties or interruptions in our operations that could be significant to our financial results. In addition, existing environmental regulations may be revised or our operations may become subject to new regulations.

Some of our operations are subject to increased federal regulatory oversight that could affect our operations and financial results.

FERC has regulatory authority over some of our operations, including the use and release of interstate pipeline and storage capacity. FERC has adopted rules designed to prevent market power abuse and market manipulation and to promote compliance with FERC’s other rules, policies and orders by companies engaged in the sale, purchase, transportation or storage of natural gas in interstate commerce. These rules carry increased penalties for violations. Although we have taken steps to structure current and future transactions to comply with applicable current FERC regulations, changes in FERC regulations or their interpretation by FERC or additional regulations issued by FERC in the future could also adversely affect our business, financial condition or financial results.

We may experience increased federal, state and local regulation of the safety of our operations.

The safety and protection of the public, our customers and our employees is our top priority. We constantly monitor and maintain our pipeline and distribution systems to ensure that natural gas is delivered safely, reliably and efficiently through our network of more than 75,000 miles of distribution and transmission lines. As in recent years, natural gas distribution and pipeline companies are continuing to encounter increasing federal, state and local oversight of the safety of their operations. Although we believe these are costs ultimately recoverable through our rates, the costs of complying with new laws and regulations may have at least a short-term adverse impact on our operating costs and financial results.

Greenhouse gas emissions or other legislation or regulations intended to address climate change could increase our operating costs, adversely affecting our financial results, growth, cash flows and results of operations.

Six of the eight states in which we operate have passed legislation to block attempts by local governments to limit the types of energy available to customers. However, federal, regional and/or state legislative and/or regulatory initiatives may attempt to control or limit the causes of climate change, including greenhouse gas emissions, such as carbon dioxide and methane. Such laws or regulations could impose costs tied to greenhouse gas emissions, operational requirements or restrictions, or additional charges to fund energy efficiency activities. They could also provide a cost advantage to alternative energy sources, impose

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costs or restrictions on end users of natural gas, or result in other costs or requirements, such as costs associated with the adoption of new infrastructure and technology to respond to new mandates. The focus on climate change could adversely impact the reputation of fossil fuel products or services. The occurrence of the foregoing events could put upward pressure on the cost of natural gas relative to other energy sources, increase our costs and the prices we charge to customers, reduce the demand for natural gas or cause fuel switching to other energy sources, and impact the competitive position of natural gas and the ability to serve new or existing customers, adversely affecting our business, results of operations and cash flows.

Operational Risks

We may incur significant costs and liabilities resulting from pipeline integrity and other similar programs and related repairs.

PHMSA requires pipeline operators to develop integrity management programs to comprehensively evaluate certain areas along their pipelines and to take additional measures to protect pipeline segments located in “high consequence areas” where a leak or rupture could potentially do the most harm. As a pipeline operator, the Company is required to:

•perform ongoing assessments of pipeline integrity;

•identify and characterize applicable threats to pipeline segments that could impact a “high consequence area”;

•improve data collection, integration and analysis;

•repair and remediate the pipeline as necessary; and

•implement preventative and mitigating actions.

The Company incurs significant costs associated with its compliance with existing PHMSA and comparable state regulations. Although we believe these are costs ultimately recoverable through our rates, the costs of complying with new laws and regulations may have at least a short-term adverse impact on our operating costs and financial results. For example, the adoption of new regulations requiring more comprehensive or stringent safety standards could require installation of new or modified safety controls, new capital projects, or accelerated maintenance programs, all of which could require a potentially significant increase in operating costs.

Distributing, transporting and storing natural gas involve risks that may result in accidents and additional operating costs.

Our operations involve a number of hazards and operating risks inherent in storing and transporting natural gas that could affect the public safety and reliability of our distribution system. While Atmos Energy, with the support from each of its regulatory commissions, is accelerating the replacement of pipeline infrastructure, operating issues such as leaks, accidents, equipment problems and incidents, including explosions and fire, could result in legal liability, repair and remediation costs, increased operating costs, significant increased capital expenditures, regulatory fines and penalties and other costs and a loss of customer confidence. We maintain liability and property insurance coverage in place for many of these hazards and risks. However, because some of our transmission pipeline and storage facilities are near or are in populated areas, any loss of human life or adverse financial results resulting from such events could be large. If these events were not fully covered by our general liability and property insurance, which policies are subject to certain limits and deductibles, our operations or financial results could be adversely affected.

If contracted gas supplies, interstate pipeline and/or storage services are not available or delivered in a timely manner, our ability to meet our customers’ natural gas requirements may be impaired and our financial condition may be adversely affected.

In order to meet our customers’ annual and seasonal natural gas demands, we must obtain a sufficient supply of natural gas, interstate pipeline capacity and storage capacity. If we are unable to obtain these, either from our suppliers’ inability to deliver the contracted commodity or the inability to secure replacement quantities, our financial condition and results of operations may be adversely affected. If a substantial disruption to or reduction in interstate natural gas pipelines’ transmission and storage capacity occurred due to operational failures or disruptions, legislative or regulatory actions, hurricanes, tornadoes, floods, extreme cold weather, terrorist or cyber-attacks or acts of war, our operations or financial results could be adversely affected.

Our operations are subject to increased competition.

In residential and commercial customer markets, our distribution operations compete with other energy products, such as electricity and propane. Our primary product competition is with electricity for heating, water heating and cooking. Increases in the price of natural gas could negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This could adversely impact our business if our customer growth slows or if our customers further conserve their use of gas, resulting in reduced gas purchases and customer billings.

In the case of industrial customers, such as manufacturing plants, adverse economic conditions, including higher gas costs, could cause these customers to use alternative sources of energy, such as electricity, or bypass our systems in favor of special

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competitive contracts with lower per-unit costs. Our pipeline and storage operations historically have faced limited competition from other existing intrastate pipelines and gas marketers seeking to provide or arrange transportation, storage and other services for customers. However, in the last few years, several new pipelines have been completed, which has increased the level of competition in this segment of our business.

Adverse weather conditions could affect our operations or financial results.

We have weather-normalized rates for approximately 96 percent of our residential and commercial revenues in our distribution operations, which substantially mitigates the adverse effects of warmer-than-normal weather for meters in those service areas. However, there is no assurance that we will continue to receive such regulatory protection from adverse weather in our rates in the future. The loss of such weather-normalized rates could have an adverse effect on our operations and financial results. In addition, our operating results may continue to vary somewhat with the actual temperatures during the winter heating season. Additionally, sustained cold weather could challenge our ability to adequately meet customer demand in our operations.

The operations and financial results of the Company could be adversely impacted as a result of climate change.

As climate change occurs, our businesses could be adversely impacted, although we believe it is likely that any such resulting impacts would occur very gradually over a long period of time and thus would be difficult to quantify with any degree of specificity. To the extent climate change results in temperatures that differ materially from temperatures we are currently experiencing, financial results could be adversely affected through lower gas volumes and revenues. Climate change could also cause shifts in population, including customers moving away from our service territories.

It could also result in more frequent and more severe weather events, such as hurricanes and tornadoes, which could increase our costs to repair damaged facilities and restore service to our customers or impact the cost of gas. If we were unable to deliver natural gas to our customers, our financial results would be impacted by lost revenues, and we generally would have to seek approval from regulators to recover restoration costs. To the extent we would be unable to recover those costs, or if higher rates resulting from our recovery of such costs would result in reduced demand for our services, our future business, financial condition or financial results could be adversely impacted.

The inability to continue to hire, train and retain operational, technical and managerial personnel could adversely affect our results of operations.

Although the average age of the employee base of Atmos Energy is not significantly changing year over year, there are still a number of employees who will become eligible to retire within the next five to 10 years. If we were unable to hire appropriate personnel or contractors to fill future needs, the Company could encounter operating challenges and increased costs, primarily due to a loss of knowledge, errors due to inexperience or the lengthy time period typically required to adequately train replacement personnel. In addition, higher costs could result from loss of productivity or increased safety compliance issues. The inability to hire, train and retain new operational, technical and managerial personnel adequately and to transfer institutional knowledge and expertise could adversely affect our ability to manage and operate our business. If we were unable to hire, train and retain appropriately qualified personnel, our results of operations could be adversely affected.

Increased dependence on technology may hinder the Company’s business operations and adversely affect its financial condition and results of operations if such technologies fail.

Over the last several years, the Company has implemented or acquired a variety of technological tools including both Company-owned information technology and technological services provided by outside parties. These tools and systems support critical functions including, scheduling and dispatching of service technicians, automated meter reading systems, customer care and billing, operational plant logistics, management reporting, and external financial reporting. The failure of these or other similarly important technologies, or the Company’s inability to have these technologies supported, updated, expanded, or integrated into other technologies, could hinder its business operations and adversely impact its financial condition and results of operations.

Although the Company has, when possible, developed alternative sources of technology and built redundancy into its computer networks and tools, there can be no assurance that these efforts would protect against all potential issues related to the loss of any such technologies.

Cyber-attacks or acts of cyber-terrorism 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.

Our business operations and information technology systems may be vulnerable to an attack by individuals or organizations intending to disrupt our business operations and information technology systems, even though the Company has implemented policies, procedures and controls to prevent and detect these activities. We use our information technology systems to manage our distribution and intrastate pipeline and storage operations and other business processes. Disruption of those systems could adversely impact our ability to safely deliver natural gas to our customers, operate our pipeline and storage

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systems or serve our customers timely. Accordingly, if such an attack or act of terrorism were to occur, our operations and financial results could be adversely affected.

In addition, we use our information technology systems to protect confidential or sensitive customer, employee and Company information developed and maintained in the normal course of our business. Any attack on such systems that would result in the unauthorized release of customer, employee or other confidential or sensitive data could have a material adverse effect on our business reputation, increase our costs and expose us to additional material legal claims and liability. Even though we have insurance coverage in place for many of these cyber-related risks, if such an attack or act of terrorism were to occur, our operations and financial results could be adversely affected to the extent not fully covered by such insurance coverage.

Natural disasters, terrorist activities or other significant events could adversely affect our operations or financial results.

Natural disasters are always a threat to our assets and operations. In addition, the threat of terrorist activities could lead to increased economic instability and volatility in the price of natural gas that could affect our operations. Also, companies in our industry may face a heightened risk of exposure to actual acts of terrorism, which could subject our operations to increased risks. As a result, the availability of insurance covering such risks may become more limited, which could increase the risk that an event could adversely affect our operations or financial results.

Financial, Economic and Market Risks

Our growth in the future may be limited by the nature of our business, which requires extensive capital spending.

Our operations are capital-intensive. We must make significant capital expenditures on a long-term basis to modernize our distribution and transmission system and to comply with the safety rules and regulations issued by the regulatory authorities responsible for the service areas we operate. In addition, we must continually build new capacity to serve the growing needs of the communities we serve. The magnitude of these expenditures may be affected by a number of factors, including new regulations, the general state of the economy and weather.

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. The cost and availability of borrowing funds from third party lenders or issuing equity is dependent on the liquidity of the credit markets, interest rates and other market conditions. This in turn may limit the amount of funds we can invest in our infrastructure.

The Company is dependent on continued access to the credit and capital markets to execute our business strategy.

Our long-term debt is currently rated as “investment grade” by Standard & Poor’s Corporation and Moody’s Investors Service, Inc. Similar to most companies, we rely upon access to both short-term and long-term credit and capital markets to satisfy our liquidity requirements. If adverse credit conditions were to cause a significant limitation on our access to the private credit and public capital markets, we could see a reduction in our liquidity. A significant reduction in our liquidity could in turn trigger a negative change in our ratings outlook or even a reduction in our credit ratings by one or more of the credit rating agencies. Such a downgrade could further limit our access to private credit and/or public capital markets and increase our costs of borrowing.

While we believe we can meet our capital requirements from our operations and the sources of financing available to us, we can provide no assurance that we will continue to be able to do so in the future, especially if the market price of natural gas increases significantly. The future effects on our business, liquidity and financial results of a deterioration of current conditions in the credit and capital markets could be material and adverse to us, both in the ways described above or in other ways that we do not currently anticipate.

We are exposed to market risks that are beyond our control, which could adversely affect our financial results.

We are subject to market risks beyond our control, including (i) commodity price volatility caused by market supply and demand dynamics, counterparty performance or counterparty creditworthiness, and (ii) interest rate risk. We are generally insulated from commodity price risk through our purchased gas cost mechanisms. With respect to interest rate risk, we have been operating in a relatively low interest-rate environment in recent years compared to historical norms for both short and long-term interest rates. However, increases in interest rates could adversely affect our future financial results to the extent that we do not recover our actual interest expense in our rates.

The concentration of our operations in the State of Texas exposes our operations and financial results to economic conditions, weather patterns and regulatory decisions in Texas.

Approximately 70 percent of our consolidated operations are located in the State of Texas. This concentration of our business in Texas means that our operations and financial results may be significantly affected by changes in the Texas economy in general, weather patterns and regulatory decisions by state and local regulatory authorities in Texas.

A deterioration in economic conditions could adversely affect our customers and negatively impact our financial results.

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Any adverse changes in economic conditions in the United States, especially in the states in which we operate, could adversely affect the financial resources of many domestic households. As a result, our customers could seek to use less gas and it may be more difficult for them to pay their gas bills. This would likely lead to slower collections and higher than normal levels of accounts receivable. This, in turn, could increase our financing requirements. Additionally, should economic conditions deteriorate, our industrial customers could seek alternative energy sources, which could result in lower transportation volumes.

Increased gas costs could adversely impact our customer base and customer collections and increase our level of indebtedness.

Rapid increases in the costs of purchased gas would cause us to experience a significant increase in short-term or long-term debt. We must pay suppliers for gas when it is purchased, which can be significantly in advance of when these costs may be recovered through the collection of monthly customer bills for gas delivered. Increases in purchased gas costs also slow our natural gas distribution collection efforts as customers are more likely to delay the payment of their gas bills, leading to higher than normal accounts receivable. This could result in higher short-term debt levels, greater collection efforts and increased bad debt expense.

The costs of providing health care benefits, pension and postretirement health care benefits and related funding requirements may increase substantially.

We provide health care benefits, a cash-balance pension plan and postretirement health care benefits to eligible full-time employees. The costs of providing health care benefits to our employees could significantly increase over time due to rapidly increasing health care inflation, and any future legislative changes related to the provision of health care benefits. The impact of additional costs which are likely to be passed on to the Company is difficult to measure at this time.

The costs of providing a cash-balance pension plan to eligible full-time employees prior to 2011 and postretirement health care benefits to eligible full-time employees and related funding requirements could be influenced by changes in the market value of the assets funding our pension and postretirement health care plans. Any significant declines in the value of these investments due to sustained declines in equity markets or a reduction in bond yields could increase the costs of our pension and postretirement health care plans and related funding requirements in the future. Further, our costs of providing such benefits and related funding requirements are also subject to a number of factors, including (i) changing demographics, including longer life expectancy of beneficiaries and an expected increase in the number of eligible former employees over the next five to ten years; (ii) various actuarial calculations and assumptions which may differ materially from actual results due primarily to changing market and economic conditions, including changes in interest rates, and higher or lower withdrawal rates; and (iii) future government regulation.

The costs to the Company of providing these benefits and related funding requirements could also increase materially in the future, should there be a material reduction in the amount of the recovery of these costs through our rates or should significant delays develop in the timing of the recovery of such costs, which could adversely affect our financial results.

The outbreak of COVID-19 or any other pandemic and their impact on business and economic conditions could negatively affect our business, results of operations and financial condition.

The scale and scope of the COVID-19 outbreak, the resulting pandemic, any other future pandemic, and their impact on the economy and financial markets could adversely affect the Company’s business, results of operations and financial condition. Regarding COVID-19, as an essential business, the Company continues to provide natural gas services and has implemented business continuity and emergency response plans to continue to provide natural gas services to customers and support the Company’s operations, while taking health and safety measures such as implementing worker distancing measures and using a remote workforce where possible. However, there is no assurance that the continued spread of COVID-19 and efforts to contain the virus will not materially impact our business, results of operations and financial condition.

ITEM 1B. Unresolved Staff Comments.

Not applicable.

ITEM 2. Properties.

Distribution, transmission and related assets

At September 30, 2021, in our distribution segment, we owned an aggregate of 71,921 miles of underground distribution and transmission mains throughout our distribution systems. These mains are located on easements or rights-of-way. We maintain our mains through a program of continuous inspection and repair and believe that our system of mains is in good condition. Through our pipeline and storage segment we also owned 5,699 miles of gas transmission lines.

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Storage Assets

We own underground gas storage facilities in several states to supplement the supply of natural gas in periods of peak demand. The following table summarizes certain information regarding our underground gas storage facilities at September 30, 2021:

State	Usable Capacity (Mcf)	Cushion Gas (Mcf)(1)	Total Capacity (Mcf)	Maximum Daily Delivery Capability (Mcf)
Distribution Segment
Kentucky	7,956,991	9,562,283	17,519,274	146,660
Kansas	3,239,000	2,300,000	5,539,000	32,000
Mississippi	1,907,571	2,442,917	4,350,488	29,136
Total	13,103,562	14,305,200	27,408,762	207,796
Pipeline and Storage Segment
Texas	46,083,549	15,878,025	61,961,574	1,710,000
Louisiana	411,040	256,900	667,940	56,000
Total	46,494,589	16,134,925	62,629,514	1,766,000
Total	59,598,151	30,440,125	90,038,276	1,973,796

(1)Cushion gas represents the volume of gas that must be retained in a facility to maintain reservoir pressure.

Additionally, we contract for storage service in underground storage facilities on many of the interstate and intrastate pipelines serving us to supplement our proprietary storage capacity. The following table summarizes our contracted storage capacity at September 30, 2021:

Segment	Division/Company	Maximum Storage Quantity (MMBtu)	Maximum Daily Withdrawal Quantity (MDWQ)(1)
Distribution Segment
	Colorado-Kansas Division	6,343,728	147,965
	Kentucky/Mid-States Division	8,175,103	226,320
	Louisiana Division	2,594,875	177,765
	Mid-Tex Division	5,000,000	190,000
	Mississippi Division	5,099,536	164,764
	West Texas Division	5,500,000	176,000
Total		32,713,242	1,082,814
Pipeline and Storage Segment
	Trans Louisiana Gas Pipeline, Inc.	1,000,000	47,500
Total Contracted Storage Capacity		33,713,242	1,130,314

(1)Maximum daily withdrawal quantity (MDWQ) amounts will fluctuate depending upon the season and the month. Unless otherwise noted, MDWQ amounts represent the MDWQ amounts as of November 1, which is the beginning of the winter heating season.

ITEM 3. Legal Proceedings.

See Note 13 to the consolidated financial statements, which is incorporated in this Item 3 by reference.

ITEM 4. Mine Safety Disclosures.

Not applicable.

PART II

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ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Our stock trades on the New York Stock Exchange under the trading symbol “ATO.” The dividends paid per share of our common stock for fiscal 2021 and 2020 are listed below.

	Fiscal 2021		Fiscal 2020
Quarter ended:
December 31	$	0.625	$	0.575
March 31	0.625		0.575
June 30	0.625		0.575
September 30	0.625		0.575
	$	2.50	$	2.30

Dividends are payable at the discretion of our Board of Directors out of legally available funds. The Board of Directors typically declares dividends in the same fiscal quarter in which they are paid. As of October 31, 2021, there were 10,590 holders of record of our common stock. Future payments of dividends, and the amounts of these dividends, will depend on our financial condition, results of operations, capital requirements and other factors. We sold no securities during fiscal 2021 that were not registered under the Securities Act of 1933, as amended.

Performance Graph

The performance graph and table below compares the yearly percentage change in our total return to shareholders for the last five fiscal years with the total return of the S&P 500 Stock Index (S&P 500) and the total return of the S&P 500 Utilities Industry Index. The graph and table below assume that $100.00 was invested on September 30, 2016 in our common stock, the S&P 500 and the S&P 500 Utilities Industry Index ax, as well as a reinvestment of dividends paid on such investments throughout the period.

Comparison of Five-Year Cumulative Total Return

among Atmos Energy Corporation, S&P 500 Index and

S&P 500 Utilities Industry Index

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	Cumulative Total Return
	9/30/2016	9/30/2017	9/30/2018	9/30/2019	9/30/2020	9/30/2021
Atmos Energy Corporation	100.00	115.17	131.91	163.30	140.06	132.61
S&P 500 Stock Index	100.00	118.61	139.85	145.80	167.89	218.27
S&P 500 Utilities Stock Index	100.00	112.03	115.31	146.56	139.28	154.61

The following table sets forth the number of securities authorized for issuance under our equity compensation plans at September 30, 2021.

	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)		(b)		(c)
Equity compensation plans approved by security holders:
1998 Long-Term Incentive Plan	944,962	(1)	$	—	1,054,190
Total equity compensation plans approved by security holders	944,962		—		1,054,190
Equity compensation plans not approved by security holders	—		—		—
Total	944,962		$	—	1,054,190

(1)Comprised of a total of 328,369 time-lapse restricted stock units, 377,385 director share units and 239,208 performance-based restricted stock units at the target level of performance granted under our 1998 Long-Term Incentive Plan.

ITEM 6. Selected Financial Data.

No disclosure required by Regulation S-K.

ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

INTRODUCTION

This section provides management’s discussion of the financial condition, changes in financial condition and results of operations of Atmos Energy Corporation and its consolidated subsidiaries with specific information on results of operations and liquidity and capital resources. It includes management’s interpretation of our financial results, the factors affecting these results, the major factors expected to affect future operating results and future investment and financing plans. This discussion should be read in conjunction with our consolidated financial statements and notes thereto.

Several factors exist that could influence our future financial performance, some of which are described in Item 1A above, “Risk Factors”. They should be considered in connection with evaluating forward-looking statements contained in this report or otherwise made by or on behalf of us since these factors could cause actual results and conditions to differ materially from those set out in such forward-looking statements.

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

The statements contained in this Annual Report on Form 10-K 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: federal, state and local regulatory and political trends and decisions, including the impact of rate proceedings before

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various state regulatory commissions; increased federal regulatory oversight and potential penalties; possible increased federal, state and local regulation of the safety of our operations; the impact of greenhouse gas emissions or other legislation or regulations intended to address climate change; possible significant costs and liabilities resulting from pipeline integrity and other similar programs and related repairs; the inherent hazards and risks involved in distributing, transporting and storing natural gas; the availability and accessibility of contracted gas supplies, interstate pipeline and/or storage services; increased competition from energy suppliers and alternative forms of energy; adverse weather conditions; the impact of climate change; the inability to continue to hire, train and retain operational, technical and managerial personnel; increased dependence on technology that may hinder the Company's business if such technologies fail; the threat of cyber-attacks or acts of cyber-terrorism that could disrupt our business operations and information technology systems or result in the loss or exposure of confidential or sensitive customer, employee or Company information; natural disasters, terrorist activities or other events and other risks and uncertainties discussed herein, all of which are difficult to predict and many of which are beyond our control; the capital-intensive nature of our business; our ability to continue to access the credit and capital markets to execute our business strategy; market risks beyond our control affecting our risk management activities, including commodity price volatility, counterparty performance or creditworthiness and interest rate risk; the concentration of our operations in Texas; the impact of adverse economic conditions on our customers; changes in the availability and price of natural gas; increased costs of providing health care benefits, along with pension and postretirement health care benefits and increased funding requirements; and the outbreak of COVID-19 and its impact on business and economic conditions. Accordingly, while we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, we undertake no obligation to update or revise any of our forward-looking statements whether as a result of new information, future events or otherwise.

CRITICAL ACCOUNTING POLICIES

Our 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 base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from estimates.

Our significant accounting policies are discussed in Note 2 to our consolidated financial statements. The accounting policies discussed below are both important to the presentation of our financial condition and results of operations and require management to make difficult, subjective or complex accounting estimates. Accordingly, these critical accounting policies are reviewed periodically by the Audit Committee of the Board of Directors.

Critical Accounting Policy	Summary of Policy	Factors Influencing Application of the Policy
Regulation	Our distribution and pipeline operations meet the criteria of a cost-based, rate-regulated entity under accounting principles generally accepted in the United States. Accordingly, the financial results for these operations reflect the effects of the ratemaking and accounting practices and policies of the various regulatory commissions to which we are subject. As a result, certain costs that would normally be expensed under accounting principles generally accepted in the United States are permitted to be capitalized or deferred on the balance sheet because it is probable they can be recovered through rates. Further, regulation may impact the period in which revenues or expenses are recognized. The amounts expected to be recovered or recognized are based upon historical experience and our understanding of the regulations. Discontinuing the application of this method of accounting for regulatory assets and liabilities or changes in the accounting for our various regulatory mechanisms could significantly increase our operating expenses as fewer costs would likely be capitalized or deferred on the balance sheet, which could reduce our net income.	Decisions of regulatory authorities Issuance of new regulations or regulatory mechanisms Assessing the probability of the recoverability of deferred costs Continuing to meet the criteria of a cost-based, rate regulated entity for accounting purposes

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Critical Accounting Policy	Summary of Policy	Factors Influencing Application of the Policy
Unbilled Revenue	We follow the revenue accrual method of accounting for distribution segment revenues whereby revenues attributable to gas delivered to customers, but not yet billed under the cycle billing method, are estimated and accrued and the related costs are charged to expense. When permitted, we implement rates that have not been formally approved by our regulatory authorities, subject to refund.We recognize this revenue and establish a reserve for amounts that could be refunded based on our experience for the jurisdiction in which the rates were implemented.	Estimates of delivered sales volumes based on actual tariff information and weather information and estimates of customer consumption and/or behavior Estimates of purchased gas costs related to estimated deliveries Estimates of amounts billed subject to refund

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Critical Accounting Policy	Summary of Policy	Factors Influencing Application of the Policy
Pension and other postretirement plans	Pension and other postretirement plan costs and liabilities are determined on an actuarial basis using a September 30 measurement date and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and current demographic and actuarial mortality data. The assumed discount rate and the expected return are the assumptions that generally have the most significant impact on our pension costs and liabilities. The assumed discount rate, the assumed health care cost trend rate and assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities. The discount rate is utilized principally in calculating the actuarial present value of our pension and postretirement obligations and net periodic pension and postretirement benefit plan costs. When establishing our discount rate, we consider high quality corporate bond rates based on bonds available in the marketplace that are suitable for settling the obligations, changes in those rates from the prior year and the implied discount rate that is derived from matching our projected benefit disbursements with currently available high quality corporate bonds. The expected long-term rate of return on assets is utilized in calculating the expected return on plan assets component of our annual pension and postretirement plan costs. We estimate the expected return on plan assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater than or less than the assumed rate, that year’s annual pension or postretirement plan costs are not affected. Rather, this gain or loss reduces or increases future pension or postretirement plan costs over a period of approximately ten to twelve years. The market-related value of our plan assets represents the fair market value of the plan assets, adjusted to smooth out short-term market fluctuations over a five-year period. The use of this methodology will delay the impact of current market fluctuations on the pension expense for the period. We estimate the assumed health care cost trend rate used in determining our postretirement net expense based upon our actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon our annual review of our participant census information as of the measurement date.	General economic and market conditions Assumed investment returns by asset class Assumed future salary increases Assumed discount rate Projected timing of future cash disbursements Health care cost experience trends Participant demographic information Actuarial mortality assumptions Impact of legislation Impact of regulation
Impairment assessments	We review the carrying value of our long-lived assets, including goodwill and identifiable intangibles, whenever events or changes in circumstance indicate that such carrying values may not be recoverable, and at least annually for goodwill, as required by U.S. accounting standards. The evaluation of our goodwill balances and other long-lived assets or identifiable assets for which uncertainty exists regarding the recoverability of the carrying value of such assets involves the assessment of future cash flows and external market conditions and other subjective factors that could impact the estimation of future cash flows including, but not limited to the commodity prices, the amount and timing of future cash flows, future growth rates and the discount rate. Unforeseen events and changes in circumstances or market conditions could adversely affect these estimates, which could result in an impairment charge.	General economic and market conditions Projected timing and amount of future discounted cash flows Judgment in the evaluation of relevant data

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Non-GAAP Financial Measures

As described further in Note 14 to the consolidated financial statements, due to the passage of Kansas House Bill 2585, we remeasured our deferred tax liability and updated our state deferred tax rate. As a result, we recorded a non-cash income tax benefit of $21.0 million for the fiscal year ended September 30, 2020. Due to the non-recurring nature of this benefit, we believe that net income and diluted net income per share before the non-cash income tax benefit provide a more relevant measure to analyze our financial performance than net income and diluted net income per share in order to allow investors to better analyze our core results and allow the information to be presented on a comparative basis. Accordingly, the following discussion and analysis of our financial performance will reference adjusted net income and adjusted diluted earnings per share, non-GAAP measures, which are calculated as follows:

	For the Fiscal Year Ended September 30
	2021		2020		2019		2021 vs. 2020		2020 vs. 2019
	(In thousands, except per share data)
Net income	$	665,563	$	601,443	$	511,406	$	64,120	$	90,037
Non-cash income tax benefits	—		(20,962)		—		20,962		(20,962)
Adjusted net income	$	665,563	$	580,481	$	511,406	$	85,082	$	69,075
Diluted net income per share	$	5.12	$	4.89	$	4.35	$	0.23	$	0.54
Diluted EPS from non-cash income tax benefits	—		(0.17)		—		0.17		(0.17)
Adjusted diluted net income per share	$	5.12	$	4.72	$	4.35	$	0.40	$	0.37

RESULTS OF OPERATIONS

Overview

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

The following table details our consolidated net income by segment during the last three fiscal years:

	For the Fiscal Year Ended September 30
	2021		2020		2019
	(In thousands)
Distribution segment	$	445,862	$	395,664	$	328,814
Pipeline and storage segment	219,701		205,779		182,592
Net income	$	665,563	$	601,443	$	511,406

During fiscal 2021, we recorded net income of $665.6 million, or $5.12 per diluted share, compared to net income of $601.4 million, or $4.89 per diluted share in the prior year. After adjusting for a nonrecurring income tax benefit recognized during fiscal 2020, adjusted net income was $580.5 million, or $4.72 per diluted share in the prior year. The year-over-year increase in adjusted net income of $85.1 million largely reflects positive rate outcomes driven by safety and reliability spending and distribution customer growth, partially offset by lower service order revenues and higher bad debt expense in our distribution segment due to the temporary suspension of collection activities during the pandemic and increased spending on system maintenance activities.

During the year ended September 30, 2021, we implemented ratemaking regulatory actions which resulted in an increase in annual operating income of $185.7 million. Excluding the impact of the refund of excess deferred income taxes resulting from previously enacted tax reform legislation, our total fiscal 2021 rate outcomes were $226.2 million. Additionally, we had ratemaking efforts in progress at September 30, 2021, seeking a total increase in annual operating income of $56.5 million. As of the date of this report, we have received approval to implement $25.0 million of this amount in the first quarter of fiscal 2022. Excluding the impact of the refund of excess deferred income taxes resulting from previously enacted tax reform legislation, we have received approval to implement $68.5 million during the first quarter of fiscal 2022.

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During fiscal year 2021, we refunded $55.9 million in excess deferred tax liabilities to customers. The refunds reduced operating income and reduced our annual effective income tax rate to 18.8% in fiscal 2021 compared with 19.5% in fiscal 2020.

Capital expenditures for fiscal 2021 increased 2 percent period-over-period, to $2.0 billion. Over 85 percent was invested to improve the safety and reliability of our distribution and transportation systems, with a significant portion of this investment incurred under regulatory mechanisms that reduce regulatory lag to six months or less.

During fiscal 2021, we completed over $3.4 billion of long-term debt and equity financing, including $2.2 billion of incremental financing issued to pay for the purchased gas costs incurred during Winter Storm Uri. As of September 30, 2021, our equity capitalization was 51.9 percent. Excluding the $2.2 billion of incremental financing, our equity capitalization was 60.6 percent. As of September 30, 2021, we had approximately $2.9 billion in total liquidity, including cash and cash equivalents and funds available through equity forward sales agreements.

As a result of the continued stability of our earnings, cash flows and capital structure, our Board of Directors increased the quarterly dividend by 8.8% percent for fiscal 2022.

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 our distribution operations are our ability to earn our authorized rates of return, competitive factors in the energy industry and economic conditions in our service areas.

Our ability to earn our authorized rates is based primarily on our ability to improve the rate design in our various ratemaking jurisdictions to minimize regulatory lag and, ultimately, separate the recovery of our approved rates from customer usage patterns. Improving rate design is a long-term process and is further complicated by the fact that we operate in multiple rate jurisdictions. The “Ratemaking Activity” section of this Form 10-K describes our current rate strategy, progress towards implementing that strategy and recent ratemaking initiatives in more detail. During fiscal 2021, we completed regulatory proceedings in our distribution segment resulting in a $141.8 million increase in annual operating income. Excluding the impact of the refund of excess deferred income taxes resulting from previously enacted tax reform legislation, our total fiscal 2021 annualized rate outcomes in our distribution segment were $182.3 million.

Our distribution operations are also affected by the cost of natural gas. We are generally able to pass the cost of gas through to our customers without markup under purchased gas cost adjustment mechanisms; therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Revenues in our Texas and Mississippi service areas 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.

The cost of gas typically does not have a direct impact on our operating income because these costs are recovered through our purchased gas cost adjustment mechanisms. However, higher gas costs may adversely impact our accounts receivable collections, resulting in higher bad debt expense. This risk is currently mitigated by rate design that allows us to collect from our customers the gas cost portion of our bad debt expense on approximately 79 percent of our residential and commercial revenues. Additionally, higher gas costs may require us to increase borrowings under our credit facilities, resulting in higher interest expense. 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.

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Review of Financial and Operating Results

Financial and operational highlights for our distribution segment for the fiscal years ended September 30, 2021, 2020 and 2019 are presented below.

	For the Fiscal Year Ended September 30
	2021		2020		2019		2021 vs. 2020		2020 vs. 2019
	(In thousands, unless otherwise noted)
Operating revenues	$	3,241,973	$	2,626,993	$	2,745,461	$	614,980	$	(118,468)
Purchased gas cost	1,501,695		1,071,227		1,268,591		430,468		(197,364)
Operating expenses	1,121,764		1,027,523		1,006,098		94,241		21,425
Operating income	618,514		528,243		470,772		90,271		57,471
Other non-operating income (expense)	(20,694)		(1,265)		6,241		(19,429)		(7,506)
Interest charges	36,629		39,634		60,031		(3,005)		(20,397)
Income before income taxes	561,191		487,344		416,982		73,847		70,362
Income tax expense	115,329		105,147		88,168		10,182		16,979
Non-cash income tax benefit (1)	—		(13,467)		—		13,467		(13,467)
Net income	$	445,862	$	395,664	$	328,814	$	50,198	$	66,850
Consolidated distribution sales volumes — MMcf	308,833		291,650		315,476		17,183		(23,826)
Consolidated distribution transportation volumes — MMcf	152,513		147,387		155,078		5,126		(7,691)
Total consolidated distribution throughput — MMcf	461,346		439,037		470,554		22,309		(31,517)
Consolidated distribution average cost of gas per Mcf sold	$	4.86	$	3.67	$	4.02	$	1.19	$	(0.35)

(1)See Note 14 to the consolidated financial statements for further information.

Fiscal year ended September 30, 2021 compared with fiscal year ended September 30, 2020

Operating income for our distribution segment increased 17 percent, which primarily reflects:

•a $150.6 million increase in rate adjustments, primarily in our Mid-Tex, Mississippi, Louisiana and West Texas Divisions.

•a $19.2 million increase from customer growth primarily in our Mid-Tex Division.

•a $3.8 million decrease in employee related costs.

•a $5.0 million decrease in travel and entertainment expense.

Partially offset by:

•a $43.6 million increase in depreciation expense and property taxes associated with increased capital investments.

•an $18.2 million increase in bad debt expense primarily due to the temporary suspension of collection activities.

•a $12.8 million increase in pipeline maintenance and related activities.

•a $5.1 million increase in insurance expense.

•an $8.4 million decrease in service order revenues primarily due to the temporary suspension of collection activities.

The year-over- year change in other non-operating expense and interest charges of $22.4 million primarily reflects increased amortization of prior service cost associated with our Retiree Medical Plan, as presented in Note 12 to the consolidated financial statements.

During fiscal 2021, we refunded $29.4 million in excess deferred taxes in the distribution segment, which reduced operating income year over year and reduced the annual effective income tax rate for this segment to 20.6% compared with 21.6% in the prior year.

The fiscal year ended September 30, 2020 compared with fiscal year ended September 30, 2019 for our distribution segment is described in Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year ended September 30, 2020.

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The following table shows our operating income by distribution division, in order of total rate base, for the fiscal years ended September 30, 2021, 2020 and 2019. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.

	For the Fiscal Year Ended September 30
	2021		2020		2019		2021 vs. 2020		2020 vs. 2019
	(In thousands)
Mid-Tex	$	310,293	$	236,066	$	202,050	$	74,227	$	34,016
Kentucky/Mid-States	73,259		76,745		73,965		(3,486)		2,780
Louisiana	72,388		71,892		70,440		496		1,452
West Texas	51,104		52,493		44,902		(1,389)		7,591
Mississippi	65,337		55,938		46,229		9,399		9,709
Colorado-Kansas	32,778		34,039		34,362		(1,261)		(323)
Other	13,355		1,070		(1,176)		12,285		2,246
Total	$	618,514	$	528,243	$	470,772	$	90,271	$	57,471

Pipeline and Storage Segment

Our pipeline and storage segment consists of the pipeline and storage operations of our Atmos Pipeline–Texas Division (APT) and our natural gas transmission operations in Louisiana. APT is one of the largest intrastate pipeline operations in Texas with a heavy concentration in the established natural gas producing areas of central, northern and eastern Texas, extending into or near the major producing areas of the Barnett Shale, the Texas Gulf Coast and the Permian Basin of West Texas. APT provides transportation and storage services to our Mid-Tex Division, other third-party local distribution companies, industrial and electric generation customers, as well as marketers and producers. Over 80 percent of this segment's revenues are derived from these services. As part of its pipeline operations, APT owns and operates five underground storage facilities in Texas.

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

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

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

APT annually uses GRIP to recover capital costs incurred in the prior calendar year. On February 12, 2021, APT made a GRIP filing that covered changes in net property, plant and equipment investment from January 1, 2020 through December 31, 2020 with a requested increase in operating income of $44.0 million. On May 11, 2021, the Texas Railroad Commission approved an increase in operating income of $43.9 million. In February 2021, the RRC approved a reduction in revenue of $106.6 million to refund excess deferred tax liabilities to customers over 35 months.

On December 21, 2016, 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.

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Review of Financial and Operating Results

Financial and operational highlights for our pipeline and storage segment for the fiscal years ended September 30, 2021, 2020 and 2019 are presented below.

	For the Fiscal Year Ended September 30
	2021		2020		2019		2021 vs. 2020		2020 vs. 2019
	(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue	$	497,730	$	474,077	$	428,586	$	23,653	$	45,491
Third-party transportation revenue	127,874		127,444		129,930		430		(2,486)
Other revenue	11,743		7,818		8,508		3,925		(690)
Total operating revenues	637,347		609,339		567,024		28,008		42,315
Total purchased gas cost	1,582		1,548		(360)		34		1,908
Operating expenses	349,281		311,935		292,098		37,346		19,837
Operating income	286,484		295,856		275,286		(9,372)		20,570
Other non-operating income	18,549		8,436		1,163		10,113		7,273
Interest charges	46,925		44,840		43,122		2,085		1,718
Income before income taxes	258,108		259,452		233,327		(1,344)		26,125
Income tax expense	38,407		61,168		50,735		(22,761)		10,433
Non-cash income tax benefit (1)	—		(7,495)		—		7,495		(7,495)
Net income	$	219,701	$	205,779	$	182,592	$	13,922	$	23,187
Gross pipeline transportation volumes — MMcf	799,724		822,499		939,376		(22,775)		(116,877)
Consolidated pipeline transportation volumes — MMcf	585,857		621,371		721,998		(35,514)		(100,627)

(1)See Note 14 to the consolidated financial statements for further information.

Fiscal year ended September 30, 2021 compared with fiscal year ended September 30, 2020

Operating income for our pipeline and storage segment decreased three percent, which primarily reflects:

•an $8.2 million net decrease in APT's thru-system activities primarily associated with the tightening of regional spreads driven by increased competing takeaway capacity in the Permian Basin.

•a $17.1 million increase in system maintenance expense primarily due to spending on hydro testing and in-line inspections.

•a $17.0 million increase in depreciation expense and property taxes associated with increased capital investments.

Partially offset by:

•a $56.2 million increase due to rate adjustments from the GRIP filings approved in May 2020 and 2021. The increase in rates was driven by increased safety and reliability spending.

The year-over- year change in other non-operating income and interest charges of $8.0 million reflects increased allowance for funds used during construction (AFUDC) primarily due to increased capital spending, partially offset by an increase in interest expense due to the issuance of long-term debt during fiscal 2021.

During fiscal 2021 we refunded $26.5 million in excess deferred taxes in our pipeline and storage segment, which reduced operating income year over year and reduced the annual effective tax rate for this segment to 14.9% compared with 23.6% in the prior year.

The fiscal year ended September 30, 2020 compared with fiscal year ended September 30, 2019 for our pipeline and storage segment is described in Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year ended September 30, 2020.

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. Additionally, we have a $1.5 billion commercial paper program and four committed revolving credit facilities with $2.5 billion in total availability from third-party

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

We have a shelf registration statement on file with the Securities and Exchange Commission (SEC) that allows us to issue up to $5.0 billion in common stock and/or debt securities. As of the date of this report, approximately $3.4 billion of securities remained available for issuance under the shelf registration statement, which expires June 29, 2024.

We also have an at-the-market (ATM) equity sales program that allows us to issue and sell shares of our common stock up to an aggregate offering price of $1.0 billion (including shares of common stock that may be sold pursuant to forward sale agreements entered into in connection with the ATM equity sales program), which expires June 29, 2024. At September 30, 2021, approximately $760 million of equity is available for issuance under this ATM equity sales program. Additionally, as of September 30, 2021, we had $302.0 million in available proceeds from outstanding forward sale agreements that must be settled during fiscal 2022.

During fiscal 2021, we entered into forward starting interest rate swaps to effectively fix the Treasury yield component associated with $1.4 billion of planned issuances of unsecured senior notes. During fiscal 2021, we settled swaps of $600 million with a net receipt of $62.2 million. On October 1, 2021, the notes were issued as planned.