ATMOS ENERGY CORP - Annual Report: 2021 (Form 10-K)
Table of Contents
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 | ||||||||
| Part I | ||||||||
| Item 1. | ||||||||
| Item 1A. | ||||||||
| Item 1B. | ||||||||
| Item 2. | ||||||||
| Item 3. | ||||||||
| Item 4. | Mine Safety Disclosures | |||||||
| Part II | ||||||||
| Item 5. | ||||||||
| Item 6. | ||||||||
| Item 7. | ||||||||
| Item 7A. | ||||||||
| Item 8. | ||||||||
| Item 9. | ||||||||
| Item 9A. | ||||||||
| Item 9B. | ||||||||
| Part III | ||||||||
| Item 10. | ||||||||
| Item 11. | ||||||||
| Item 12. | ||||||||
| Item 13. | ||||||||
| Item 14. | ||||||||
| Part IV | ||||||||
| Item 15. | ||||||||
| Item 16. | ||||||||
Table of Contents
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 | ||||
3
Table of Contents
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
4
Table of Contents
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
5
Table of Contents
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.
6
Table of Contents
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 | |||||||||||||||||||||||||||||
7
Table of Contents
(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.
8
Table of Contents
(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 | ||||||||||||||||||||||
9
Table of Contents
| 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.
10
Table of Contents
(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.
11
Table of Contents
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.
12
Table of Contents
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.
13
Table of Contents
| 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
14
Table of Contents
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
15
Table of Contents
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
16
Table of Contents
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.
17
Table of Contents
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.
18
Table of Contents
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
19
Table of Contents
| 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
20
Table of Contents
| 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
21
Table of Contents
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 | ||||||
22
Table of Contents
| 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 | ||||||
23
Table of Contents
| 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 | ||||||
24
Table of Contents
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.
25
Table of Contents
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.
26
Table of Contents
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.
27
Table of Contents
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.
28
Table of Contents
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
29
Table of Contents
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.
The following table summarizes our existing forward starting interest rate swaps as of September 30, 2021.
| Planned Debt Issuance Date | Amount Hedged | Effective Interest Rate | ||||||||||||
| (In thousands) | ||||||||||||||
| Fiscal 2023 | 500,000 | 1.66 | % | |||||||||||
| Fiscal 2024 | 450,000 | 1.80 | % | |||||||||||
| Fiscal 2025 | 600,000 | 1.75 | % | |||||||||||
| Fiscal 2026 | 300,000 | 2.16 | % | |||||||||||
| $ | 1,850,000 | |||||||||||||
The liquidity provided by these sources is expected to be sufficient to fund the Company's working capital needs and capital expenditures program. Additionally, we expect to continue to be able to obtain financing upon reasonable terms as necessary.
The following table presents our capitalization as of September 30, 2021 and 2020:
| September 30 | |||||||||||||||||||||||
| 2021 | 2020 | ||||||||||||||||||||||
| (In thousands, except percentages) | |||||||||||||||||||||||
| Short-term debt | $ | — | — | % | $ | — | — | % | |||||||||||||||
Long-term debt (1) | 7,330,657 | 48.1 | % | 4,531,944 | 40.0 | % | |||||||||||||||||
Shareholders’ equity (2) | 7,906,889 | 51.9 | % | 6,791,203 | 60.0 | % | |||||||||||||||||
| Total capitalization, including short-term debt | $ | 15,237,546 | 100.0 | % | $ | 11,323,147 | 100.0 | % | |||||||||||||||
(1)Inclusive of our finance leases.
(2)Excluding the $2.2 billion of incremental financing issued to pay for the purchased gas costs incurred during Winter Storm Uri, our equity capitalization ratio would have been 60.6%.
Cash Flows
Our internally generated funds may change in the future due to a number of factors, some of which we cannot control. These factors include regulatory changes, the price for our services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks and other factors.
Cash flows from operating, investing and financing activities for the years ended September 30, 2021, 2020 and 2019 are presented below.
30
Table of Contents
| For the Fiscal Year Ended September 30 | |||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | 2021 vs. 2020 | 2020 vs. 2019 | |||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Total cash provided by (used in) | |||||||||||||||||||||||||||||
| Operating activities | $ | (1,084,251) | $ | 1,037,999 | $ | 968,769 | $ | (2,122,250) | $ | 69,230 | |||||||||||||||||||
| Investing activities | (1,963,655) | (1,925,518) | (1,683,660) | (38,137) | (241,858) | ||||||||||||||||||||||||
| Financing activities | 3,143,821 | 883,777 | 725,670 | 2,260,044 | 158,107 | ||||||||||||||||||||||||
| Change in cash and cash equivalents | 95,915 | (3,742) | 10,779 | 99,657 | (14,521) | ||||||||||||||||||||||||
| Cash and cash equivalents at beginning of period | 20,808 | 24,550 | 13,771 | (3,742) | 10,779 | ||||||||||||||||||||||||
| Cash and cash equivalents at end of period | $ | 116,723 | $ | 20,808 | $ | 24,550 | $ | 95,915 | $ | (3,742) | |||||||||||||||||||
Cash flows for the fiscal year ended September 30, 2020 compared with fiscal year ended September 30, 2019 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.
Cash flows from operating activities
For the fiscal year ended September 30, 2021, cash flow used from operating activities was $1.1 billion compared with cash flows generated from operating activities of $1.0 billion in the prior year. The year-over-year decrease in operating cash flows reflects gas costs incurred during Winter Storm Uri and the timing of customer collections partially offset by the positive effects of successful rate case outcomes achieved in fiscal 2020 and 2021.
Cash flows from investing activities
Our capital expenditures are primarily used to improve the safety and reliability of our distribution and transmission system through pipeline replacement and system modernization and to enhance and expand our system to meet customer needs. Over the last three fiscal years, approximately 88 percent of our capital spending has been committed to improving the safety and reliability of our system.
For the fiscal year ended September 30, 2021, we had $1.97 billion in capital expenditures compared with $1.94 billion for the fiscal year ended September 30, 2020. Capital spending increased by $33.8 million, or two percent, as a result of planned increases to modernize our system.
Cash flows from financing activities
Our financing activities provided $3.1 billion and $883.8 million in cash for fiscal years 2021 and 2020.
During the fiscal year ended September 30, 2021, we received $3.4 billion in net proceeds from the issuance of long-term debt and equity. We completed a public offering of $600 million of 1.50% senior notes due 2031, $1.1 billion of 0.625% senior notes due 2023 and $1.1 billion floating rate senior notes due 2023. Net proceeds from the latter two notes were used to pay for gas costs incurred during Winter Storm Uri. Additionally, during the year ended September 30, 2021, we settled 6,130,875 shares that had been sold on a forward basis for net proceeds of $606.7 million. The net proceeds were used primarily to support capital spending and for other general corporate purposes, including the payment of natural gas purchases. Additionally, cash dividends increased due to an 8.7 percent increase in our dividend rate and an increase in shares outstanding.
During the fiscal year ended September 30, 2020, we received $1.6 billion in net proceeds from the issuance of long-term debt and equity. We completed a public offering of $300 million of 2.625% senior notes due 2029 and $500 million of 3.375% senior notes due 2049 and entered into a two year $200 million term loan. We received net proceeds from these offerings, after the underwriting discount and offering expenses, of $791.7 million. Additionally, we settled 6,101,916 shares that had been sold on a forward basis for net proceeds of approximately $624 million. The net proceeds were used primarily to support capital spending, reduce short-term debt and other general corporate purposes. Cash dividends increased due to a 9.5 percent increase in our dividend rate and an increase in shares outstanding.
31
Table of Contents
The following table shows the number of shares issued for the fiscal years ended September 30, 2021, 2020 and 2019:
| For the Fiscal Year Ended September 30 | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| Shares issued: | |||||||||||||||||
| Direct Stock Purchase Plan | 79,921 | 107,989 | 110,063 | ||||||||||||||
| Retirement Savings Plan and Trust | 84,265 | 78,941 | 81,456 | ||||||||||||||
| 1998 Long-Term Incentive Plan (LTIP) | 242,216 | 254,706 | 299,612 | ||||||||||||||
Equity Issuance (1) | 6,130,875 | 6,101,916 | 7,574,111 | ||||||||||||||
| Total shares issued | 6,537,277 | 6,543,552 | 8,065,242 | ||||||||||||||
(1)Share amounts do not include shares issued under forward sale agreements until the shares have been settled.
Credit Ratings
Our credit ratings directly affect our ability to obtain short-term and long-term financing, in addition to the cost of such financing. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including but not limited to, debt to total capitalization, operating cash flow relative to outstanding debt, operating cash flow coverage of interest and operating cash flow less dividends to debt. In addition, the rating agencies consider qualitative factors such as consistency of our earnings over time, the risks associated with our business and the regulatory structures that govern our rates in the states where we operate.
Our debt is rated by two rating agencies: Standard & Poor’s Corporation (S&P) and Moody’s Investors Service (Moody’s). As a result of the impacts of Winter Storm Uri, during the second quarter of fiscal 2021, S&P lowered our long-term and short-term credit ratings by one notch and placed our ratings under negative outlook and Moody's reaffirmed its long-term and short-term credit ratings and placed our ratings under negative outlook.
As of September 30, 2021, our outlook and current debt ratings, which are all considered investment grade are as follows:
| S&P | Moody’s | |||||||||||||||||||||||||
| Senior unsecured long-term debt | A- | A1 | ||||||||||||||||||||||||
| Short-term debt | A-2 | P-1 | ||||||||||||||||||||||||
| Outlook | Negative | Negative | ||||||||||||||||||||||||
A significant degradation in our operating performance or a significant reduction in our liquidity caused by more limited access to the private and public credit markets as a result of deteriorating global or national financial and credit conditions could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by the two credit rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings.
A credit rating is not a recommendation to buy, sell or hold securities. The highest investment grade credit rating is AAA for S&P and Aaa for Moody’s. The lowest investment grade credit rating is BBB- for S&P and Baa3 for Moody’s. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independently of any other rating. There can be no assurance that a rating will remain in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating agency if, in its judgment, circumstances so warrant.
Debt Covenants
We were in compliance with all of our debt covenants as of September 30, 2021. Our debt covenants are described in Note 7 to the consolidated financial statements.
32
Table of Contents
Contractual Obligations and Commercial Commitments
The following table provides information about contractual obligations and commercial commitments at September 30, 2021.
| Payments Due by Period | |||||||||||||||||||||||||||||
| Total | Less than 1 year | 1-3 years | 3-5 years | More than 5 years | |||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Contractual Obligations | |||||||||||||||||||||||||||||
Long-term debt (1) | $ | 7,360,000 | $ | 200,000 | $ | 2,200,000 | $ | 10,000 | $ | 4,950,000 | |||||||||||||||||||
Interest charges (2) | 4,268,559 | 221,325 | 418,664 | 412,654 | 3,215,916 | ||||||||||||||||||||||||
Finance leases (3) | 29,809 | 1,342 | 2,753 | 2,846 | 22,868 | ||||||||||||||||||||||||
Operating leases (4) | 271,074 | 41,822 | 68,043 | 39,359 | 121,850 | ||||||||||||||||||||||||
Financial instrument obligations (5) | 5,269 | 5,269 | — | — | — | ||||||||||||||||||||||||
Pension and postretirement benefit plan contributions (6) | 315,298 | 26,126 | 59,252 | 90,829 | 139,091 | ||||||||||||||||||||||||
Uncertain tax positions (7) | 32,792 | — | 32,792 | — | — | ||||||||||||||||||||||||
Total contractual obligations | $ | 12,282,801 | $ | 495,884 | $ | 2,781,504 | $ | 555,688 | $ | 8,449,725 | |||||||||||||||||||
(1)Long-term debt excludes our finance lease obligations, which are separately reported within this table. The $1.1 billion of 0.625% senior notes and $1.1 billion floating rate senior notes that were issued in March 2021 contractually mature in 2023; however, we intend to repay these after the receipt of securitization funds, which we expect will occur in the next twelve months. As such, we have classified the senior notes as current maturities of long-term debt as of September 30, 2021. See Notes 7 and 9 to the consolidated financial statements for further details.
(2)Interest charges were calculated using the effective rate for each debt issuance through the contractual maturity date.
(3)Finance lease payments shown above include interest totaling $11.1 million. See Note 6 to the consolidated financial statements.
(4)Operating lease payments shown above include interest totaling $38.6 million. See Note 6 to the consolidated financial statements.
(5)Represents liabilities for natural gas commodity financial instruments that were valued as of September 30, 2021. The ultimate settlement amounts of these remaining liabilities are unknown because they are subject to continuing market risk until the financial instruments are settled.
(6)Represents expected contributions to our defined benefit and postretirement benefit plans, which are discussed in Note 10 to the consolidated financial statements.
(7)Represents liabilities associated with uncertain tax positions claimed or expected to be claimed on tax returns. The amount does not include interest and penalties that may be applied to these positions.
We maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of individual contracts. Our Mid-Tex Division also maintains a limited number of long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at market and fixed prices. At September 30, 2021, we were committed to purchase 32.4 Bcf within one year and 12.9 Bcf within two to three years under indexed contracts. At September 30, 2021, we were committed to purchase 11.9 Bcf within one year under fixed price contracts ranging from $1.86 to $7.03 per Mcf.
Risk Management Activities
In our distribution and pipeline and storage segments, we use a combination of physical storage, fixed physical contracts and fixed financial contracts to reduce our exposure to unusually large winter-period gas price increases. Additionally, we manage interest rate risk by entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.
We record our financial instruments as a component of risk management assets and liabilities, which are classified as current or noncurrent based upon the anticipated settlement date of the underlying financial instrument. Substantially all of our financial instruments are valued using external market quotes and indices.
33
Table of Contents
The following table shows the components of the change in fair value of our financial instruments for the fiscal year ended September 30, 2021 (in thousands):
| Fair value of contracts at September 30, 2020 | $ | 78,663 | |||
| Contracts realized/settled | (64,205) | ||||
| Fair value of new contracts | 13,136 | ||||
| Other changes in value | 197,823 | ||||
| Fair value of contracts at September 30, 2021 | 225,417 | ||||
| Netting of cash collateral | — | ||||
| Cash collateral and fair value of contracts at September 30, 2021 | $ | 225,417 | |||
The fair value of our financial instruments at September 30, 2021, is presented below by time period and fair value source:
| Fair Value of Contracts at September 30, 2021 | |||||||||||||||||||||||||||||
| Maturity in years | |||||||||||||||||||||||||||||
| Source of Fair Value | Less than 1 | 1-3 | 4-5 | Greater than 5 | Total Fair Value | ||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Prices actively quoted | $ | 49,804 | $ | 94,522 | $ | 81,091 | $ | — | $ | 225,417 | |||||||||||||||||||
| Prices based on models and other valuation methods | — | — | — | — | — | ||||||||||||||||||||||||
| Total Fair Value | $ | 49,804 | $ | 94,522 | $ | 81,091 | $ | — | $ | 225,417 | |||||||||||||||||||
RECENT ACCOUNTING DEVELOPMENTS
Recent accounting developments and their impact on our financial position, results of operations and cash flows are described in Note 2 to the consolidated financial statements.
| ITEM 7A. | Quantitative and Qualitative Disclosures About Market Risk. | ||||
We are exposed to risks associated with commodity prices and interest rates. Commodity price risk is the potential loss that we may incur as a result of changes in the fair value of a particular instrument or commodity. Interest-rate risk is the potential increased cost we could incur when we issue debt instruments or to provide financing and liquidity for our business activities. Additionally, interest-rate risk could affect our ability to issue cost effective equity instruments.
We conduct risk management activities in our distribution and pipeline and storage segments. In our distribution segment, we use a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season. Our risk management activities and related accounting treatment are described in further detail in Note 15 to the consolidated financial statements. Additionally, our earnings are affected by changes in short-term interest rates as a result of our issuance of short-term commercial paper and our other short-term borrowings.
Commodity Price Risk
We purchase natural gas for our distribution operations. Substantially all of the costs of gas purchased for distribution operations are recovered from our customers through purchased gas cost adjustment mechanisms. Therefore, our distribution operations have limited commodity price risk exposure.
Interest Rate Risk
Our earnings are exposed to changes in short-term interest rates associated with our short-term commercial paper program and other short-term borrowings. We use a sensitivity analysis to estimate our short-term interest rate risk. For purposes of this analysis, we estimate our short-term interest rate risk as the difference between our actual interest expense for the period and estimated interest expense for the period assuming a hypothetical average one percent increase in the interest rates associated with our short-term borrowings. Had interest rates associated with our short-term borrowings increased by an average of one percent, our interest expense would not have materially increased during 2021.
34
Table of Contents
| ITEM 8. | Financial Statements and Supplementary Data. | ||||
Index to financial statements and financial statement schedules:
| Page | |||||
| Financial statements and supplementary data: | |||||
All financial statement schedules are omitted because the required information is not present, or not present in amounts sufficient to require submission of the schedule or because the information required is included in the financial statements and accompanying notes thereto.
35
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Atmos Energy Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Atmos Energy Corporation (the “Company“) as of September 30, 2021 and 2020, the related consolidated statements of comprehensive income, shareholders‘ equity, and cash flows, for each of the three years in the period ended September 30, 2021, and the related notes (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at September 30, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2021, in conformity with US generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of September 30, 2021, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated November 12, 2021 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company‘s management. Our responsibility is to express an opinion on the Company‘s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Determination of Capital Costs | |||||
| Description of the Matter | As more fully described in Note 2 to the financial statements, the Company capitalizes the direct and indirect costs of construction. Once a project is completed, it is placed into service and included in the Company’s rate base. Costs of maintenance and repairs that are not included in the Company’s rate base are charged to expense. For the year ended September 30, 2021, the Company capitalized approximately $2.0 billion of construction-related costs for regulated property, plant and equipment. Auditing management’s identification of capital additions and maintenance and repairs expense involved significant effort and auditor judgment. These amounts have both a higher magnitude and a higher likelihood of potential misstatement. As a cost-based, rate-regulated entity, the rates charged to customers are designed to recover the entity’s costs and provide a rate of return on rate base. Net property, plant and equipment is the most significant component of the Company’s rate base. As a result, inappropriate capitalization of costs could affect the amount, timing and classification of revenues and expenses in the financial statements. | ||||
36
Table of Contents
| How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s controls over the initial determination and approval of expenditures for either capital additions or maintenance and repair. For example, we selected a sample of projects initiated during the year to evaluate the effectiveness of management’s review controls to determine the proper categorization of project expenditures as either capitalizable costs or current-period expense. Our audit procedures included, among others, testing a sample of projects initiated during the year, including the evaluation of the nature of the project, with Company personnel outside of accounting and financial reporting. For example, we evaluated project setup through inspection of each project’s description for compliance with the Company’s capitalization policy as described in Note 2 and a series of inquiries of the project approver to understand how they assessed whether projects should be treated as capital or expense. Other audit procedures included evaluating whether the descriptions and amounts included on third-party invoices either support or contradict the project classification as capital, evaluating the appropriateness of individuals capitalizing direct labor charges to projects by assessing the relevance of their job function to the capital project, and recalculating other overhead costs capitalized to projects. | ||||
/s/ Ernst & Young LLP
We have served as the Company‘s auditor since 1983.
Dallas, Texas
November 12, 2021
37
Table of Contents
ATMOS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
| September 30 | |||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands, except share data) | |||||||||||
| ASSETS | |||||||||||
| Property, plant and equipment | $ | 17,258,547 | $ | 15,539,166 | |||||||
| Construction in progress | 626,551 | 418,055 | |||||||||
| 17,885,098 | 15,957,221 | ||||||||||
| Less accumulated depreciation and amortization | 2,821,128 | 2,601,874 | |||||||||
| Net property, plant and equipment | 15,063,970 | 13,355,347 | |||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | 116,723 | 20,808 | |||||||||
Accounts receivable, less allowance for uncollectible accounts of $64,471 in 2021 and $29,949 in 2020 | 342,967 | 230,595 | |||||||||
| Gas stored underground | 178,116 | 111,950 | |||||||||
Other current assets (See Note 9) | 2,200,909 | 107,905 | |||||||||
| Total current assets | 2,838,715 | 471,258 | |||||||||
| Goodwill | 731,257 | 731,257 | |||||||||
Deferred charges and other assets (See Note 9) | 974,720 | 801,170 | |||||||||
| $ | 19,608,662 | $ | 15,359,032 | ||||||||
| CAPITALIZATION AND LIABILITIES | |||||||||||
| Shareholders’ equity | |||||||||||
Common stock, no par value (stated at $0.005 per share); 200,000,000 shares authorized; issued and outstanding: 2021 — 132,419,754 shares; 2020 — 125,882,477 shares | $ | 662 | $ | 629 | |||||||
| Additional paid-in capital | 5,023,751 | 4,377,149 | |||||||||
| Accumulated other comprehensive income (loss) | 69,803 | (57,589) | |||||||||
| Retained earnings | 2,812,673 | 2,471,014 | |||||||||
| Shareholders’ equity | 7,906,889 | 6,791,203 | |||||||||
| Long-term debt | 4,930,205 | 4,531,779 | |||||||||
| Total capitalization | 12,837,094 | 11,322,982 | |||||||||
Commitments and contingencies (See Note 13) | |||||||||||
| Current liabilities | |||||||||||
| Accounts payable and accrued liabilities | 423,222 | 235,775 | |||||||||
| Other current liabilities | 686,681 | 546,461 | |||||||||
| Current maturities of long-term debt | 2,400,452 | 165 | |||||||||
| Total current liabilities | 3,510,355 | 782,401 | |||||||||
| Deferred income taxes | 1,705,809 | 1,456,569 | |||||||||
Regulatory excess deferred taxes (See Note 14) | 549,227 | 697,764 | |||||||||
| Regulatory cost of removal obligation | 468,688 | 457,188 | |||||||||
| Deferred credits and other liabilities | 537,489 | 642,128 | |||||||||
| $ | 19,608,662 | $ | 15,359,032 | ||||||||
See accompanying notes to consolidated financial statements.
38
Table of Contents
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
| Year Ended September 30 | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| (In thousands, except per share data) | |||||||||||||||||
| Operating revenues | |||||||||||||||||
| Distribution segment | $ | 3,241,973 | $ | 2,626,993 | $ | 2,745,461 | |||||||||||
| Pipeline and storage segment | 637,347 | 609,339 | 567,024 | ||||||||||||||
| Intersegment eliminations | (471,830) | (415,195) | (410,637) | ||||||||||||||
| Total operating revenues | 3,407,490 | 2,821,137 | 2,901,848 | ||||||||||||||
| Purchased gas cost | |||||||||||||||||
| Distribution segment | 1,501,695 | 1,071,227 | 1,268,591 | ||||||||||||||
| Pipeline and storage segment | 1,582 | 1,548 | (360) | ||||||||||||||
| Intersegment eliminations | (470,560) | (413,921) | (409,394) | ||||||||||||||
| Total purchased gas cost | 1,032,717 | 658,854 | 858,837 | ||||||||||||||
| Operation and maintenance expense | 679,019 | 629,601 | 630,308 | ||||||||||||||
| Depreciation and amortization expense | 477,977 | 429,828 | 391,456 | ||||||||||||||
| Taxes, other than income | 312,779 | 278,755 | 275,189 | ||||||||||||||
| Operating income | 904,998 | 824,099 | 746,058 | ||||||||||||||
Other non-operating income (expense) | (2,145) | 7,171 | 7,404 | ||||||||||||||
| Interest charges | 83,554 | 84,474 | 103,153 | ||||||||||||||
| Income before income taxes | 819,299 | 746,796 | 650,309 | ||||||||||||||
| Income tax expense | 153,736 | 145,353 | 138,903 | ||||||||||||||
| Net Income | $ | 665,563 | $ | 601,443 | $ | 511,406 | |||||||||||
| Basic net income per share | $ | 5.12 | $ | 4.89 | $ | 4.36 | |||||||||||
| Diluted net income per share | $ | 5.12 | $ | 4.89 | $ | 4.35 | |||||||||||
| Weighted average shares outstanding: | |||||||||||||||||
| Basic | 129,779 | 122,788 | 117,200 | ||||||||||||||
| Diluted | 129,834 | 122,872 | 117,461 | ||||||||||||||
| Net income | $ | 665,563 | $ | 601,443 | $ | 511,406 | |||||||||||
| Other comprehensive income (loss), net of tax | |||||||||||||||||
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $(55), $32 and $64 | (191) | 106 | 218 | ||||||||||||||
| Cash flow hedges: | |||||||||||||||||
Amortization and unrealized gains (losses) on interest rate agreements, net of tax of $36,875, $17,198 and $(6,782) | 127,583 | 56,888 | (22,944) | ||||||||||||||
| Total other comprehensive income (loss) | 127,392 | 56,994 | (22,726) | ||||||||||||||
| Total comprehensive income | $ | 792,955 | $ | 658,437 | $ | 488,680 | |||||||||||
See accompanying notes to consolidated financial statements.
39
Table of Contents
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
| Common stock | Additional Paid-in Capital | Accumulated Other Comprehensive Income (Loss) | Retained Earnings | Total | |||||||||||||||||||||||||||||||
| Number of Shares | Stated Value | ||||||||||||||||||||||||||||||||||
| (In thousands, except share and per share data) | |||||||||||||||||||||||||||||||||||
| Balance, September 30, 2018 | 111,273,683 | $ | 556 | $ | 2,974,926 | $ | (83,647) | $ | 1,878,116 | $ | 4,769,951 | ||||||||||||||||||||||||
| Net income | — | — | — | — | 511,406 | 511,406 | |||||||||||||||||||||||||||||
| Other comprehensive loss | — | — | — | (22,726) | — | (22,726) | |||||||||||||||||||||||||||||
Cash dividends ($2.10 per share) | — | — | — | — | (245,717) | (245,717) | |||||||||||||||||||||||||||||
Cumulative effect of accounting change | — | — | — | (8,210) | 8,210 | — | |||||||||||||||||||||||||||||
| Common stock issued: | |||||||||||||||||||||||||||||||||||
| Public offering | 7,574,111 | 38 | 694,065 | — | — | 694,103 | |||||||||||||||||||||||||||||
| Direct stock purchase plan | 110,063 | 1 | 11,070 | — | — | 11,071 | |||||||||||||||||||||||||||||
| Retirement savings plan | 81,456 | — | 8,252 | — | — | 8,252 | |||||||||||||||||||||||||||||
| 1998 Long-term incentive plan | 299,612 | 2 | 2,946 | — | — | 2,948 | |||||||||||||||||||||||||||||
| Employee stock-based compensation | — | — | 20,935 | — | — | 20,935 | |||||||||||||||||||||||||||||
| Balance, September 30, 2019 | 119,338,925 | 597 | 3,712,194 | (114,583) | 2,152,015 | 5,750,223 | |||||||||||||||||||||||||||||
| Net income | — | — | — | — | 601,443 | 601,443 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | 56,994 | — | 56,994 | |||||||||||||||||||||||||||||
Cash dividends ($2.30 per share) | — | — | — | — | (282,444) | (282,444) | |||||||||||||||||||||||||||||
| Common stock issued: | |||||||||||||||||||||||||||||||||||
| Public offering | 6,101,916 | 30 | 624,272 | — | — | 624,302 | |||||||||||||||||||||||||||||
| Direct stock purchase plan | 107,989 | 1 | 11,325 | — | — | 11,326 | |||||||||||||||||||||||||||||
| Retirement savings plan | 78,941 | — | 8,222 | — | — | 8,222 | |||||||||||||||||||||||||||||
| 1998 Long-term incentive plan | 254,706 | 1 | 2,748 | — | — | 2,749 | |||||||||||||||||||||||||||||
| Employee stock-based compensation | — | — | 18,388 | — | — | 18,388 | |||||||||||||||||||||||||||||
| Balance, September 30, 2020 | 125,882,477 | 629 | 4,377,149 | (57,589) | 2,471,014 | 6,791,203 | |||||||||||||||||||||||||||||
| Net income | — | — | — | — | 665,563 | 665,563 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | 127,392 | — | 127,392 | |||||||||||||||||||||||||||||
Cash dividends ($2.50 per share) | — | — | — | — | (323,904) | (323,904) | |||||||||||||||||||||||||||||
| Common stock issued: | |||||||||||||||||||||||||||||||||||
| Public offering | 6,130,875 | 31 | 606,636 | — | — | 606,667 | |||||||||||||||||||||||||||||
| Direct stock purchase plan | 79,921 | — | 7,715 | — | — | 7,715 | |||||||||||||||||||||||||||||
| Retirement savings plan | 84,265 | 1 | 8,125 | — | — | 8,126 | |||||||||||||||||||||||||||||
| 1998 Long-term incentive plan | 242,216 | 1 | 3,091 | — | — | 3,092 | |||||||||||||||||||||||||||||
| Employee stock-based compensation | — | — | 21,035 | — | — | 21,035 | |||||||||||||||||||||||||||||
| Balance, September 30, 2021 | 132,419,754 | $ | 662 | $ | 5,023,751 | $ | 69,803 | $ | 2,812,673 | $ | 7,906,889 | ||||||||||||||||||||||||
See accompanying notes to consolidated financial statements.
40
Table of Contents
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Year Ended September 30 | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||||||||
| Net income | $ | 665,563 | $ | 601,443 | $ | 511,406 | |||||||||||
Adjustments to reconcile net income to net cash provided by (used in) operating activities: | |||||||||||||||||
Depreciation and amortization | 477,977 | 429,828 | 391,456 | ||||||||||||||
| Deferred income taxes | 155,355 | 155,322 | 132,004 | ||||||||||||||
| One-time income tax benefit | — | (20,962) | — | ||||||||||||||
| Stock-based compensation | 11,255 | 9,583 | 11,121 | ||||||||||||||
| Amortization of debt issuance costs | 14,030 | 11,543 | 9,464 | ||||||||||||||
| Equity component of AFUDC | (32,749) | (23,493) | (11,165) | ||||||||||||||
| Other | 3,731 | 8,411 | 1,169 | ||||||||||||||
| Changes in assets and liabilities: | |||||||||||||||||
(Increase) decrease in accounts receivable | (113,665) | 7,167 | 18,724 | ||||||||||||||
(Increase) decrease in gas stored underground | (66,166) | 18,188 | 35,594 | ||||||||||||||
| Increase in Winter Storm Uri current regulatory asset (see Note 9) | (2,003,659) | — | — | ||||||||||||||
Increase in other current assets | (84,705) | (35,878) | (26,590) | ||||||||||||||
| Increase in Winter Storm Uri long-term regulatory asset (see Note 9) | (76,652) | — | — | ||||||||||||||
(Increase) decrease in deferred charges and other assets | 136,809 | (31,935) | (58,403) | ||||||||||||||
Increase in accounts payable and accrued liabilities | 104,242 | 7,359 | 9,908 | ||||||||||||||
Decrease in other current liabilities | (166,268) | (129,543) | (103,895) | ||||||||||||||
Increase (decrease) in deferred credits and other liabilities | (109,349) | 30,966 | 47,976 | ||||||||||||||
Net cash provided by (used in) operating activities | (1,084,251) | 1,037,999 | 968,769 | ||||||||||||||
| CASH FLOWS USED IN INVESTING ACTIVITIES | |||||||||||||||||
| Capital expenditures | (1,969,540) | (1,935,676) | (1,693,477) | ||||||||||||||
| Proceeds from the sale of discontinued operations | — | — | 4,000 | ||||||||||||||
| Purchases of debt and equity securities | (49,879) | (50,517) | (29,153) | ||||||||||||||
| Proceeds from sale of debt and equity securities | 14,957 | 32,339 | 6,070 | ||||||||||||||
| Maturities of debt securities | 28,850 | 18,669 | 20,299 | ||||||||||||||
| Other, net | 11,957 | 9,667 | 8,601 | ||||||||||||||
Net cash used in investing activities | (1,963,655) | (1,925,518) | (1,683,660) | ||||||||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | |||||||||||||||||
Net decrease in short-term debt | — | (464,915) | (110,865) | ||||||||||||||
| Proceeds from issuance of long-term debt, net of premium/discount | 2,797,346 | 999,450 | 1,045,221 | ||||||||||||||
| Net proceeds from equity offering | 606,667 | 624,302 | 694,103 | ||||||||||||||
Issuance of common stock through stock purchase and employee retirement plans | 15,841 | 19,548 | 19,323 | ||||||||||||||
| Settlement of interest rate swaps | 62,159 | (4,426) | (90,141) | ||||||||||||||
| Repayment of long-term debt | — | — | (575,000) | ||||||||||||||
| Cash dividends paid | (323,904) | (282,444) | (245,717) | ||||||||||||||
| Debt issuance costs | (14,288) | (7,738) | (11,254) | ||||||||||||||
Net cash provided by financing activities | 3,143,821 | 883,777 | 725,670 | ||||||||||||||
Net increase (decrease) in cash and cash equivalents | 95,915 | (3,742) | 10,779 | ||||||||||||||
| Cash and cash equivalents at beginning of year | 20,808 | 24,550 | 13,771 | ||||||||||||||
| Cash and cash equivalents at end of year | $ | 116,723 | $ | 20,808 | $ | 24,550 | |||||||||||
See accompanying notes to consolidated financial statements.
41
Table of Contents
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Nature of Business
Atmos Energy Corporation (Atmos Energy or the “Company”) and its subsidiaries are engaged in the regulated natural gas distribution and pipeline and storage businesses. Through our distribution business, we deliver natural gas through sales and transportation arrangements to over three million residential, commercial, public-authority and industrial customers through our six regulated distribution divisions in the service areas described below:
| Division | Service Area | |||||||
| Atmos Energy Colorado-Kansas Division | Colorado, Kansas | |||||||
| Atmos Energy Kentucky/Mid-States Division | Kentucky, Tennessee, Virginia(1) | |||||||
| Atmos Energy Louisiana Division | Louisiana | |||||||
| Atmos Energy Mid-Tex Division | Texas, including the Dallas/Fort Worth metropolitan area | |||||||
| Atmos Energy Mississippi Division | Mississippi | |||||||
| Atmos Energy West Texas Division | West Texas | |||||||
(1)Denotes location where we have more limited service areas.
In addition, we transport natural gas for others through our distribution system. Our distribution business is subject to federal and state regulation and/or regulation by local authorities in each of the states in which our distribution divisions operate. Our corporate headquarters and shared-services function are located in Dallas, Texas, and our customer support centers are located in Amarillo and Waco, Texas.
Our pipeline and storage business, which is also subject to federal and state regulation, consists of the pipeline and storage operations of our Atmos Pipeline–Texas (APT) Division and our natural gas transmission business in Louisiana. The APT division provides transportation and storage services to our Mid-Tex Division, other third-party local distribution companies, industrial and electric generation customers, as well as marketers and producers. As part of its pipeline operations, APT manages five underground storage facilities in Texas. We also provide ancillary services customary to the pipeline industry including parking arrangements, lending and sales of inventory on hand. 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.
2. Summary of Significant Accounting Policies
Principles of consolidation — The accompanying consolidated financial statements include the accounts of Atmos Energy Corporation and its wholly-owned subsidiaries. All material intercompany transactions have been eliminated; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process.
Use of estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The most significant estimates include the allowance for doubtful accounts, unbilled revenues, contingency accruals, pension and postretirement obligations, deferred income taxes, impairment of long-lived assets, risk management and trading activities, fair value measurements and the valuation of goodwill and other long-lived assets. Actual results could differ from those estimates.
Regulation — Our distribution and pipeline and storage operations are subject to regulation with respect to rates, service, maintenance of accounting records and various other matters by the respective regulatory authorities in the states in which we operate. Our accounting policies recognize the financial effects of the ratemaking and accounting practices and policies of the various regulatory commissions. Accounting principles generally accepted in the United States require cost-based, rate-regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are permitted to be capitalized rather than expensed because they can be recovered through rates. We record certain costs as regulatory assets when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. The amounts to be recovered or recognized are based upon historical experience and our understanding of the regulations. Further, regulation may impact the period in which revenues or expenses are recognized.
Substantially all of our regulatory assets are recorded as a component of other current assets and deferred charges and other assets and our regulatory liabilities are recorded as a component of other current liabilities and deferred credits and other
42
liabilities. Deferred gas costs are recorded either in other current assets or liabilities and the long-term portion of regulatory excess deferred taxes and regulatory cost of removal obligation are reported separately. Significant regulatory assets and liabilities as of September 30, 2021 and 2020 included the following:
| September 30 | |||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Regulatory assets: | |||||||||||
| Pension and postretirement benefit costs | $ | 45,922 | $ | 149,089 | |||||||
Infrastructure mechanisms (1) | 222,795 | 183,943 | |||||||||
Winter Storm Uri incremental costs (2) | 2,100,728 | — | |||||||||
| Deferred gas costs | 66,395 | 40,593 | |||||||||
Regulatory excess deferred taxes (3) | 45,370 | — | |||||||||
| Recoverable loss on reacquired debt | 3,789 | 4,894 | |||||||||
| Deferred pipeline record collection costs | 32,099 | 29,839 | |||||||||
| Other | 4,343 | 6,283 | |||||||||
| $ | 2,521,441 | $ | 414,641 | ||||||||
| Regulatory liabilities: | |||||||||||
Regulatory excess deferred taxes (3) | $ | 705,084 | $ | 718,651 | |||||||
| Regulatory cost of removal obligation | 541,511 | 531,096 | |||||||||
| Deferred gas costs | 52,553 | 19,985 | |||||||||
| Asset retirement obligation | 18,373 | 20,348 | |||||||||
| APT annual adjustment mechanism | 31,110 | 57,379 | |||||||||
| Pension and postretirement benefit costs | 56,201 | — | |||||||||
| Other | 19,363 | 19,554 | |||||||||
| $ | 1,424,195 | $ | 1,367,013 | ||||||||
(1)Infrastructure mechanisms in Texas, Louisiana and Tennessee allow for the deferral of all eligible expenses associated with capital expenditures incurred pursuant to these rules, including the recording of interest on the deferred expenses until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recovered through base rates.
(2)Includes extraordinary gas costs incurred during Winter Storm Uri and related carrying costs. See Note 9 to the consolidated financial statements for further information. This amount is recorded within other current assets and deferred charges and other assets on the consolidated balance sheet as of September 30, 2021.
(3)Regulatory excess deferred taxes represent changes in our net deferred tax liability related to our cost of service ratemaking due to the enactment of the Tax Cuts and Jobs Act of 2017 (the "TCJA") and a Kansas legislative change enacted in fiscal 2020. See Notes 12 and 14 to the consolidated financial statements for further information.
Revenue recognition
Distribution Revenues
Distribution revenues represent the delivery of natural gas to residential, commercial, industrial and public authority customers at prices based on tariff rates established by regulatory authorities in the states in which we operate. Revenue is recognized and our performance obligation is satisfied over time when natural gas is delivered and simultaneously consumed by our customers. We have elected to use the invoice practical expedient and recognize revenue for volumes delivered that we have the right to invoice our customers. We read meters and bill our customers on a monthly cycle basis. Accordingly, we estimate volumes from the last meter read to the balance sheet date and accrue revenue for gas delivered but not yet billed.
In our Texas and Mississippi jurisdictions, we pay franchise fees and gross receipt taxes to operate in these service areas. These franchise fees and gross receipts taxes are required to be paid regardless of our ability to collect from our customers. Accordingly, we account for these amounts on a gross basis in revenue and we record the associated tax expense as a component of taxes, other than income.
Pipeline and Storage Revenues
Pipeline and storage revenues primarily represent the transportation and storage of natural gas on our APT system and the transmission of natural gas through our 21-mile pipeline in Louisiana. APT provides transportation and storage services to our
43
Mid-Tex Division, other third party local distribution companies and certain industrial customers under tariff rates approved by the RRC. APT also provides certain transportation and storage services to industrial and electric generation customers, as well as marketers and producers, under negotiated rates. Our pipeline in Louisiana is primarily used to aggregate gas supply for our Louisiana Division under a long-term contract and on a more limited basis to third parties. The demand fee charged to our Louisiana Division is subject to regulatory approval by the Louisiana Public Service Commission. We also manage two asset management plans with distribution affiliates of the Company at terms that have been approved by the applicable state regulatory commissions. The performance obligations for these transportation customers are satisfied by means of transporting customer-supplied gas to the designated location. Revenue is recognized and our performance obligation is satisfied over time when natural gas is delivered to the customer. Management determined that these arrangements qualify for the invoice practical expedient for recognizing revenue. For demand fee arrangements, revenue is recognized and our performance obligation is satisfied by standing ready to transport natural gas over the period of each individual month.
Alternative Revenue Program Revenues
In our distribution segment, we have weather-normalization adjustment mechanisms that serve to minimize the effects of weather on our residential and commercial revenues. Additionally, APT has a regulatory mechanism that requires that we share with its tariffed customers 75% of the difference between the total non-tariffed revenues earned during a test period and a revenue benchmark of $69.4 million that was established in its most recent rate case. Differences between actual revenues and revenues calculated under these mechanisms adjust the amount billed to customers. These mechanisms are considered to be alternative revenue programs under accounting standards generally accepted in the United States as they are deemed to be contracts between us and our regulator. Accordingly, revenue under these mechanisms are excluded from revenue from contracts with customers.
Purchased gas costs — Rates established by regulatory authorities are adjusted for increases and decreases in our purchased gas costs through purchased gas cost adjustment mechanisms. Purchased gas cost adjustment mechanisms provide gas distribution companies a method of recovering purchased gas costs on an ongoing basis without filing a rate case to address all of their non-gas costs. There is no margin generated through purchased gas cost adjustments, but they provide a dollar-for-dollar offset to increases or decreases in our distribution segment’s gas costs. The effects of these purchased gas cost adjustment mechanisms are recorded as deferred gas costs on our consolidated balance sheets.
Cash and cash equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Accounts receivable and allowance for uncollectible accounts — Accounts receivable arise from natural gas sales to residential, commercial, industrial, public authority and other customers. Our accounts receivable balance includes unbilled amounts which represent a customer’s consumption of gas from the date of the last cycle billing through the last day of the month. The receivable balances are short term and generally do not extend beyond one month. To minimize credit risk, we assess the credit worthiness of new customers, require deposits where necessary, assess late fees, pursue collection activities and disconnect service for nonpayment. After disconnection, accounts are written off when deemed uncollectible. At each reporting period, we assess the allowance for uncollectible accounts based on historical experience, current conditions and consideration of expected future conditions. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions.
Gas stored underground — Our gas stored underground is comprised of natural gas injected into storage to support the winter season withdrawals for our distribution operations. The average cost method is used for all of our distribution operations. Gas in storage that is retained as cushion gas to maintain reservoir pressure is classified as property, plant and equipment and is valued at cost.
Property, plant and equipment — Regulated property, plant and equipment is stated at original cost, net of contributions in aid of construction. The cost of additions includes direct construction costs, payroll related costs (taxes, pensions and other benefits), administrative and general costs and an allowance for funds used during construction (AFUDC). AFUDC represents the capitalizable total cost of funds used to finance the construction of major projects.
The following table details amounts capitalized for the fiscal year ended September 30.
44
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Component of AFUDC | Statement of Comprehensive Income Location | (In thousands) | ||||||||||||||||||
| Debt | Interest charges | $ | 11,414 | $ | 8,436 | $ | 7,643 | |||||||||||||
| Equity | Other non-operating income (expense) | 32,749 | 23,493 | 11,165 | ||||||||||||||||
| $ | 44,163 | $ | 31,929 | $ | 18,808 | |||||||||||||||
Major renewals, including replacement pipe, and betterments that are recoverable through our regulatory rate base are capitalized while the costs of maintenance and repairs that are not capitalizable are charged to expense as incurred. The costs of large projects are accumulated in construction in progress until the project is completed. When the project is completed, tested and placed in service, the balance is transferred to the regulated plant in service account included in the rate base and depreciation begins.
Regulated property, plant and equipment is depreciated at various rates on a straight-line basis. These rates are approved by our regulatory commissions and are comprised of two components: one based on average service life and one based on cost of removal. Accordingly, we recognize our cost of removal expense as a component of depreciation expense. The related cost of removal accrual is reflected as a regulatory liability on the consolidated balance sheet. At the time property, plant and equipment is retired, removal expenses less salvage, are charged to the regulatory cost of removal accrual. The composite depreciation rate was 3.0 percent, 3.0 percent and 3.1 percent for the fiscal years ended September 30, 2021, 2020 and 2019.
Other property, plant and equipment is stated at cost. Depreciation is generally computed on the straight-line method for financial reporting purposes based upon estimated useful lives.
Asset retirement obligations — We record a liability at fair value for an asset retirement obligation when the legal obligation to retire the asset has been incurred with an offsetting increase to the carrying value of the related asset.
As of September 30, 2021 and 2020, we had asset retirement obligations of $18.4 million and $20.3 million. Additionally, we had $12.8 million and $14.4 million of asset retirement costs recorded as a component of property, plant and equipment that will be depreciated over the remaining life of the underlying associated assets.
We believe we have a legal obligation to retire our natural gas storage facilities. However, we have not recognized an asset retirement obligation associated with our storage facilities because we are not able to determine the settlement date of this obligation as we do not anticipate taking our storage facilities out of service permanently. Therefore, we cannot reasonably estimate the fair value of this obligation.
Impairment of long-lived assets — We evaluate whether events or circumstances have occurred that indicate that other long-lived assets may not be recoverable or that the remaining useful life may warrant revision. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset’s carrying value over its fair value is recorded.
Goodwill — We annually evaluate our goodwill balances for impairment during our second fiscal quarter or more frequently as impairment indicators arise. During the second quarter of fiscal 2021, we completed our annual goodwill impairment assessment. We test goodwill for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit. Based on the assessment performed, we determined that our goodwill was not impaired. Although not applicable for the fiscal 2021 analysis, if a qualitative goodwill assessment resulted in impairment indicators, we would then use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. These calculations are dependent on several subjective factors including the timing of future cash flows, future growth rates and the discount rate. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its fair value.
Lease accounting — We adopted the provisions of the new lease accounting standard beginning on October 1, 2019. Results for reporting periods beginning on October 1, 2019 are presented under the new lease accounting standard and prior periods are presented under the former lease accounting standard. Upon adoption, we recorded right of use (ROU) assets and lease liabilities within the consolidated balance sheet.
We determine if an arrangement is a lease at the inception of the agreement based on the terms and conditions in the contract. A contract contains a lease if there is an identified asset and we have the right to control the asset. We are the lessee for substantially all of our leasing activities, which primarily includes operating leases for office and warehouse space, tower space, vehicles and heavy equipment used in our operations. We are also a lessee in finance leases for service centers.
45
We record a lease liability and a corresponding ROU asset for all of our leases with a term greater than 12 months. For lease contracts containing renewal and termination options, we include the option period in the lease term when it is reasonably certain the option will be exercised. We most frequently assume renewal options at the inception of the arrangement for our tower and fleet leases, based on our anticipated use of the assets. Real estate leases that contain a renewal option are evaluated on a lease-by-lease basis to determine if the option period should be included in the lease term. Currently, we have not included material renewal options for real estate leases in our ROU asset or lease liability.
The lease liability represents the present value of all lease payments over the lease term. We do not include short-term leases in the calculation of our lease liabilities. The discount rate used to determine the present value of the lease liability is the rate implicit in the lease unless that rate cannot be readily determined. We use the implicit rate stated in the agreement to determine the lease liability for our fleet leases. We use our corporate collateralized incremental borrowing rate as the discount rate for all other lease agreements. This rate is appropriate because we believe it represents the rate we would have incurred to borrow funds to acquire the leased asset over a similar term. We calculated this rate using a combination of inputs, including our current credit rating, quoted market prices of interest rates for our publicly traded unsecured debt, observable market yield curve data for peer companies with a credit rating one notch higher than our current credit rating and the lease term.
The ROU asset represents the right to use the underlying asset for the lease term, and is equal to the lease liability, adjusted for prepaid or accrued lease payments and any lease incentives that have been paid to us or when we are reasonably certain to incur costs equal to or greater than the allowance defined in the contract. We bundle our lease and non-lease components as a single component for all asset classes.
Variable payments included in our leasing arrangements are expensed in the period in which the obligation for these payments is incurred. Variable payments are dependent on usage, output or may vary for other reasons. Most of our variable lease expense is related to tower leases that have escalating payments based on changes to a stated CPI index, and usage of certain office equipment.
We have not provided material residual value guarantees for our leases, nor do our leases contain material restrictions or covenants.
Marketable securities — As of September 30, 2021, we hold marketable securities classified as either equity or debt securities. Changes in fair value of our equity securities are recorded in net income, while debt securities, which are considered available for sale securities, are reported at market value with unrealized gains and losses shown as a component of accumulated other comprehensive income (loss).
We regularly evaluate the performance of our available for sale debt securities on an investment by investment basis for impairment, taking into consideration the securities’ purpose, volatility and current returns. If a determination is made that a security will likely be sold before the recovery of its cost, the related investment is written down to its estimated fair value.
Financial instruments and hedging activities — We use financial instruments to mitigate commodity price risk in our distribution and pipeline and storage segments and to mitigate interest rate risk. The objectives and strategies for using financial instruments have been tailored to our business and are discussed in Note 15 to the consolidated financial statements.
We record all of our financial instruments on the balance sheet at fair value, with the exception of normal purchases and normal sales that are expected to result in physical delivery, with changes in fair value ultimately recorded in the statement of comprehensive income. These financial instruments are reported as risk management assets and liabilities and are classified as current or noncurrent other assets or liabilities based upon the anticipated settlement date of the underlying financial instrument. We record the cash flow impact of our financial instruments in operating cash flows based upon their balance sheet classification.
The timing of when changes in fair value of our financial instruments are recorded in the statement of comprehensive income depends on whether the financial instrument has been designated and qualifies as a part of a hedging relationship or if regulatory rulings require a different accounting treatment. Changes in fair value for financial instruments that do not meet one of these criteria are recognized in the statement of comprehensive income as they occur.
Financial Instruments Associated with Commodity Price Risk
In our distribution segment, the costs associated with and the realized gains and losses arising from the use of financial instruments to mitigate commodity price risk are included in our purchased gas cost adjustment mechanisms in accordance with regulatory requirements. Therefore, changes in the fair value of these financial instruments are initially recorded as a component of deferred gas costs and recognized in the consolidated statements of comprehensive income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue in accordance with accounting principles generally accepted in the United States. Accordingly, there is no earnings impact on our distribution segment as a result of the use of these financial instruments.
46
Financial Instruments Associated with Interest Rate Risk
In connection with the planned issuance of long-term debt, we may use financial instruments to manage interest rate risk. We currently manage this risk through the use of forward starting interest rate swaps to fix the Treasury yield component of the interest cost associated with anticipated financings. We designate these financial instruments as cash flow hedges at the time the agreements are executed. Unrealized gains and losses associated with the instruments are recorded as a component of accumulated other comprehensive income (loss). When the instruments settle, the realized gain or loss is recorded as a component of accumulated other comprehensive income (loss) and recognized as a component of interest charges over the life of the related financing arrangement. As of September 30, 2021 and 2020, no cash was required to be held in margin accounts.
Fair Value Measurements — We report certain assets and liabilities at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We primarily use quoted market prices and other observable market pricing information in valuing our financial assets and liabilities and minimize the use of unobservable pricing inputs in our measurements.
Fair-value estimates also consider our own creditworthiness and the creditworthiness of the counterparties involved. Our counterparties consist primarily of financial institutions and major energy companies. This concentration of counterparties may materially impact our exposure to credit risk resulting from market, economic or regulatory conditions. We seek to minimize counterparty credit risk through an evaluation of their financial condition and credit ratings and the use of collateral requirements under certain circumstances.
Amounts reported at fair value are subject to potentially significant volatility based upon changes in market prices, including, but not limited to, the valuation of the portfolio of our contracts, maturity and settlement of these contracts and newly originated transactions and interest rates, each of which directly affect the estimated fair value of our financial instruments. We believe the market prices and models used to value these financial instruments represent the best information available with respect to closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts. Values are adjusted to reflect the potential impact of an orderly liquidation of our positions over a reasonable period of time under then current market conditions.
Authoritative accounting literature establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority given to unobservable inputs (Level 3). The levels of the hierarchy are described below:
Level 1 — Represents unadjusted quoted prices in active markets for identical assets or liabilities. An active market for the asset or liability is defined as a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Prices actively quoted on national exchanges are used to determine the fair value of most of our assets and liabilities recorded on our balance sheet at fair value.
Our Level 1 measurements consist primarily of our debt and equity securities. The Level 1 measurements for investments in the Atmos Energy Corporation Master Retirement Trust (the Master Trust), Supplemental Executive Benefit Plan and postretirement benefit plan consist primarily of exchange-traded financial instruments.
Level 2 — Represents pricing inputs other than quoted prices included in Level 1 that are either directly or indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from, or corroborated by, observable market data. Our Level 2 measurements primarily consist of non-exchange-traded financial instruments, such as over-the-counter options and swaps and municipal and corporate bonds where market data for pricing is observable. The Level 2 measurements for investments in our Master Trust, Supplemental Executive Benefit Plan and postretirement benefit plan consist primarily of non-exchange traded financial instruments such as corporate bonds and government securities.
Level 3 — Represents generally unobservable pricing inputs which are developed based on the best information available, including our own internal data, in situations where there is little if any market activity for the asset or liability at the measurement date. The pricing inputs utilized reflect what a market participant would use to determine fair value. We currently do not have any Level 3 investments.
Pension and other postretirement plans — Pension and other postretirement plan costs and liabilities are determined on an actuarial basis 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. Our measurement date is September 30. 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.
47
The discount rate is utilized principally in calculating the actuarial present value of our pension and postretirement obligation and net pension and postretirement cost. 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 the annual pension and postretirement plan cost. 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 when 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 cost is not affected. Rather, this gain or loss is amortized over the expected future working lifetime of the plan participants.
The expected return on plan assets is then calculated by applying the expected long-term rate of return on plan assets to the market-related value of the plan assets. 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 calculation will delay the impact of current market fluctuations on the pension expense for the period.
We use a corridor approach to amortize actuarial gains and losses. Under this approach, net gains or losses in excess of ten percent of the larger of the pension benefit obligation or the market-related value of the assets are amortized on a straight-line basis. The period of amortization is the average remaining service of active participants who are expected to receive benefits under the plan.
We estimate the assumed health care cost trend rate used in determining our annual postretirement net cost 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 the annual review of our participant census information as of the measurement date.
We present only the current service cost component of the net benefit cost within operations and maintenance expense in the consolidated statements of comprehensive income. The remaining components of net benefit cost are recorded in other non-operating income (expense) in our consolidated statements of comprehensive income. Only the service cost component of net benefit cost is eligible for capitalization and we continue to capitalize these costs into property, plant and equipment. Additionally, we defer into a regulatory asset the portion of non-service components of net periodic benefit cost that are capitalizable for regulatory purposes.
Income taxes — Income taxes are determined based on the liability method, which results in income tax assets and liabilities arising from temporary differences. Temporary differences are differences between the tax bases of assets and liabilities and their reported amounts in the financial statements that will result in taxable or deductible amounts in future years. The liability method requires the effect of tax rate changes on accumulated deferred income taxes to be reflected in the period in which the rate change was enacted. The liability method also requires that deferred tax assets be reduced by a valuation allowance unless it is more likely than not that the assets will be realized.
The Company may recognize the tax benefit from uncertain tax positions only if it is at least more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon settlement with the taxing authorities. We recognize accrued interest related to unrecognized tax benefits as a component of interest charges. We recognize penalties related to unrecognized tax benefits as a component of miscellaneous income (expense) in accordance with regulatory requirements.
Tax collections — We are allowed to recover from customers revenue-related taxes that are imposed upon us. We record such taxes as operating expenses and record the corresponding customer charges as operating revenues. However, we do collect and remit various other taxes on behalf of various governmental authorities, and we record these amounts in our consolidated balance sheets on a net basis. We do not collect income taxes from our customers on behalf of governmental authorities.
Contingencies — In the normal course of business, we are confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties or the action of various regulatory agencies. For such matters, we record liabilities when they are considered probable and estimable, based on currently available facts and our estimates of the ultimate outcome or resolution of the liability in the future. We maintain liability insurance for various risks associated with the operation of our natural gas pipelines and facilities, including for property damage and bodily injury. These liability insurance policies generally require us to be responsible for the first $1.0 million (self-insured retention) of each incident. To the extent a loss contingency exceeds the self-insurance retention, we record an insurance receivable when
48
recovery is considered probable. Upon reaching a settlement, the loss contingency is deemed resolved and recorded in accounts payable and accrued liabilities until paid. Loss contingencies and any related insurance recovery receivables reflect our best estimate of these amounts as of the date of this report. Actual results may differ from estimates, depending on actual outcomes or changes in the facts or expectations surrounding each potential exposure.
Subsequent events — Except as noted in Note 6 to the consolidated financial statements regarding the commencement of finance leases, Note 7 to the consolidated financial statements regarding the public offering of senior notes and Note 9 to the consolidated financial statements regarding the most recent update to our securitization filing in the State of Texas, no events occurred subsequent to the balance sheet date that would require recognition or disclosure in the consolidated financial statements.
Recent accounting pronouncements
Accounting pronouncements adopted in fiscal 2021
Effective October 1, 2020, we adopted new accounting guidance that requires credit losses on most financial assets measured at amortized cost and certain other instruments to be measured using an expected credit loss model. Under this model, we estimate credit losses over the entire contractual term of the instrument from the date of initial recognition of that instrument. The new guidance also introduces a new impairment recognition model for available-for-sale debt securities that will require credit losses to be recorded through an allowance account. We adopted the new guidance using a modified retrospective method. The adoption of this standard did not have a material impact on our financial position, results of operations and cash flows and no adjustments were made to October 1, 2020 opening balances as a result of this adoption. As required under the modified retrospective method of adoption, results for the reporting period beginning after October 1, 2020 are presented under Accounting Standards Codification (ASC) 326, while prior period amounts are not adjusted. See Notes 5 and 16 to the consolidated financial statements for further discussion of implementation of the standard.
Accounting pronouncements that will be effective after fiscal 2021
In March 2020, the Financial Accounting Standards Board (FASB) issued optional guidance which will ease the potential burden in accounting for or recognizing the effects of reference rate reform on financial reporting. The amendments provide optional expedients and exceptions for applying U.S. GAAP to contracts, hedging relationships and other transactions affected by the cessation of the London Interbank Offered Rate (LIBOR). The amendments can be elected immediately, as of March 12, 2020, through December 31, 2022. As we implement the cessation of LIBOR into our current contracts and hedging relationships, we expect to elect the optional guidance to ease the potential burden in accounting. We are currently evaluating the potential impact on our financial position, results of operations and cash flows.
3. Segment Information
As of September 30, 2021, we manage and review our consolidated operations through the following two 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.
Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers. Although our distribution segment operations are geographically dispersed, they are aggregated and reported as a single segment as each natural gas distribution division has similar economic characteristics. In addition, because the pipeline and storage operations of our Atmos Pipeline-Texas division and our natural gas transmission operations in Louisiana have similar economic characteristics, they have been aggregated and reported as a single segment.
The accounting policies of the segments are the same as those described in the summary of significant accounting policies. We evaluate performance based on net income or loss of the respective operating units. We allocate interest and pension expense to the pipeline and storage segment; however, there is no debt or pension liability recorded on the pipeline and storage segment balance sheet. All material intercompany transactions have been eliminated; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process. Income taxes are allocated to each segment as if each segment’s income taxes were calculated on a separate return basis.
Income statements and capital expenditures by segment are shown in the following tables.
49
| Year Ended September 30, 2021 | |||||||||||||||||||||||
| Distribution | Pipeline and Storage | Eliminations | Consolidated | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Operating revenues from external parties | $ | 3,238,753 | $ | 168,737 | $ | — | $ | 3,407,490 | |||||||||||||||
| Intersegment revenues | 3,220 | 468,610 | (471,830) | — | |||||||||||||||||||
| Total operating revenues | 3,241,973 | 637,347 | (471,830) | 3,407,490 | |||||||||||||||||||
| Purchased gas cost | 1,501,695 | 1,582 | (470,560) | 1,032,717 | |||||||||||||||||||
| Operation and maintenance expense | 501,209 | 179,080 | (1,270) | 679,019 | |||||||||||||||||||
| Depreciation and amortization expense | 345,481 | 132,496 | — | 477,977 | |||||||||||||||||||
| Taxes, other than income | 275,074 | 37,705 | — | 312,779 | |||||||||||||||||||
| Operating income | 618,514 | 286,484 | — | 904,998 | |||||||||||||||||||
| Other non-operating income (expense) | (20,694) | 18,549 | — | (2,145) | |||||||||||||||||||
| Interest charges | 36,629 | 46,925 | — | 83,554 | |||||||||||||||||||
Income before income taxes | 561,191 | 258,108 | — | 819,299 | |||||||||||||||||||
| Income tax expense | 115,329 | 38,407 | — | 153,736 | |||||||||||||||||||
| Net income | $ | 445,862 | $ | 219,701 | $ | — | $ | 665,563 | |||||||||||||||
| Capital expenditures | $ | 1,454,195 | $ | 515,345 | $ | — | $ | 1,969,540 | |||||||||||||||
| Year Ended September 30, 2020 | |||||||||||||||||||||||
| Distribution | Pipeline and Storage | Eliminations | Consolidated | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Operating revenues from external parties | $ | 2,624,251 | $ | 196,886 | $ | — | $ | 2,821,137 | |||||||||||||||
| Intersegment revenues | 2,742 | 412,453 | (415,195) | — | |||||||||||||||||||
| Total operating revenues | 2,626,993 | 609,339 | (415,195) | 2,821,137 | |||||||||||||||||||
| Purchased gas cost | 1,071,227 | 1,548 | (413,921) | 658,854 | |||||||||||||||||||
| Operation and maintenance expense | 472,760 | 158,115 | (1,274) | 629,601 | |||||||||||||||||||
| Depreciation and amortization expense | 309,582 | 120,246 | — | 429,828 | |||||||||||||||||||
| Taxes, other than income | 245,181 | 33,574 | — | 278,755 | |||||||||||||||||||
| Operating income | 528,243 | 295,856 | — | 824,099 | |||||||||||||||||||
| Other non-operating income (expense) | (1,265) | 8,436 | — | 7,171 | |||||||||||||||||||
| Interest charges | 39,634 | 44,840 | — | 84,474 | |||||||||||||||||||
Income before income taxes | 487,344 | 259,452 | — | 746,796 | |||||||||||||||||||
| Income tax expense | 91,680 | 53,673 | — | 145,353 | |||||||||||||||||||
| Net income | $ | 395,664 | $ | 205,779 | $ | — | $ | 601,443 | |||||||||||||||
| Capital expenditures | $ | 1,466,631 | $ | 469,045 | $ | — | $ | 1,935,676 | |||||||||||||||
50
| Year Ended September 30, 2019 | |||||||||||||||||||||||
| Distribution | Pipeline and Storage | Eliminations | Consolidated | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Operating revenues from external parties | $ | 2,742,824 | $ | 159,024 | $ | — | $ | 2,901,848 | |||||||||||||||
| Intersegment revenues | 2,637 | 408,000 | (410,637) | — | |||||||||||||||||||
| Total operating revenues | 2,745,461 | 567,024 | (410,637) | 2,901,848 | |||||||||||||||||||
| Purchased gas cost | 1,268,591 | (360) | (409,394) | 858,837 | |||||||||||||||||||
| Operation and maintenance expense | 480,222 | 151,329 | (1,243) | 630,308 | |||||||||||||||||||
| Depreciation and amortization expense | 283,697 | 107,759 | — | 391,456 | |||||||||||||||||||
| Taxes, other than income | 242,179 | 33,010 | — | 275,189 | |||||||||||||||||||
| Operating income | 470,772 | 275,286 | — | 746,058 | |||||||||||||||||||
| Other non-operating income | 6,241 | 1,163 | — | 7,404 | |||||||||||||||||||
| Interest charges | 60,031 | 43,122 | — | 103,153 | |||||||||||||||||||
Income before income taxes | 416,982 | 233,327 | — | 650,309 | |||||||||||||||||||
| Income tax expense | 88,168 | 50,735 | — | 138,903 | |||||||||||||||||||
| Net income | $ | 328,814 | $ | 182,592 | $ | — | $ | 511,406 | |||||||||||||||
| Capital expenditures | $ | 1,274,613 | $ | 418,864 | $ | — | $ | 1,693,477 | |||||||||||||||
The following table summarizes our revenues from external parties, excluding intersegment revenues, by products and services for the fiscal years ended September 30.
| 2021 | 2020 | 2019 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Distribution revenues: | |||||||||||||||||
| Gas sales revenues: | |||||||||||||||||
| Residential | $ | 2,117,272 | $ | 1,717,070 | $ | 1,733,548 | |||||||||||
| Commercial | 838,382 | 654,963 | 711,284 | ||||||||||||||
| Industrial | 113,171 | 89,641 | 118,046 | ||||||||||||||
| Public authority and other | 50,369 | 42,007 | 42,613 | ||||||||||||||
| Total gas sales revenues | 3,119,194 | 2,503,681 | 2,605,491 | ||||||||||||||
| Transportation revenues | 105,554 | 97,441 | 95,629 | ||||||||||||||
| Other gas revenues | 14,005 | 23,129 | 41,704 | ||||||||||||||
| Total distribution revenues | 3,238,753 | 2,624,251 | 2,742,824 | ||||||||||||||
| Pipeline and storage revenues | 168,737 | 196,886 | 159,024 | ||||||||||||||
| Total operating revenues | $ | 3,407,490 | $ | 2,821,137 | $ | 2,901,848 | |||||||||||
Balance sheet information at September 30, 2021 and 2020 by segment is presented in the following tables.
| September 30, 2021 | |||||||||||||||||||||||
| Distribution | Pipeline and Storage | Eliminations | Consolidated | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Property, plant and equipment, net | $ | 11,232,649 | $ | 3,831,321 | $ | — | $ | 15,063,970 | |||||||||||||||
| Total assets | $ | 18,847,266 | $ | 4,076,844 | $ | (3,315,448) | $ | 19,608,662 | |||||||||||||||
51
| September 30, 2020 | |||||||||||||||||||||||
| Distribution | Pipeline and Storage | Eliminations | Consolidated | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Property, plant and equipment, net | $ | 9,944,978 | $ | 3,410,369 | $ | — | $ | 13,355,347 | |||||||||||||||
| Total assets | $ | 14,578,176 | $ | 3,647,907 | $ | (2,867,051) | $ | 15,359,032 | |||||||||||||||
4. Earnings Per Share
We use the two-class method of computing earnings per share because we have participating securities in the form of non-vested restricted stock units with a nonforfeitable right to dividend equivalents, for which vesting is predicated solely on the passage of time. The calculation of earnings per share using the two-class method excludes income attributable to these participating securities from the numerator and excludes the dilutive impact of those shares from the denominator. Basic weighted average shares outstanding is calculated based upon the weighted average number of common shares outstanding during the periods presented. Also, this calculation includes fully vested stock awards that have not yet been issued as common stock. Additionally, the weighted average shares outstanding for diluted EPS includes the incremental effects of the forward sale agreements, discussed in Note 8 to the consolidated financial statements,when the impact is dilutive.
Basic and diluted earnings per share for the fiscal years ended September 30 are calculated as follows:
| 2021 | 2020 | 2019 | |||||||||||||||
| (In thousands, except per share data) | |||||||||||||||||
| Basic Earnings Per Share | |||||||||||||||||
| Net Income | $ | 665,563 | $ | 601,443 | $ | 511,406 | |||||||||||
| Less: Income allocated to participating securities | 465 | 444 | 416 | ||||||||||||||
| Net Income available to common shareholders | $ | 665,098 | $ | 600,999 | $ | 510,990 | |||||||||||
| Basic weighted average shares outstanding | 129,779 | 122,788 | 117,200 | ||||||||||||||
| Net Income per share — Basic | $ | 5.12 | $ | 4.89 | $ | 4.36 | |||||||||||
| Diluted Earnings Per Share | |||||||||||||||||
| Net Income available to common shareholders | $ | 665,098 | $ | 600,999 | $ | 510,990 | |||||||||||
| Effect of dilutive shares | — | — | — | ||||||||||||||
| Net Income available to common shareholders | $ | 665,098 | $ | 600,999 | $ | 510,990 | |||||||||||
| Basic weighted average shares outstanding | 129,779 | 122,788 | 117,200 | ||||||||||||||
| Dilutive shares | 55 | 84 | 261 | ||||||||||||||
| Diluted weighted average shares outstanding | 129,834 | 122,872 | 117,461 | ||||||||||||||
| Net Income per share — Diluted | $ | 5.12 | $ | 4.89 | $ | 4.35 | |||||||||||
5. Revenue and Accounts Receivable
The following tables disaggregates our revenue from contracts with customers by customer type and segment and provides a reconciliation to total operating revenues, including intersegment revenues, for the periods presented.
52
| Year Ended September 30, 2021 | |||||||||||
| Distribution | Pipeline and Storage | ||||||||||
| (In thousands) | |||||||||||
| Gas sales revenues: | |||||||||||
| Residential | $ | 2,129,704 | $ | — | |||||||
| Commercial | 841,145 | — | |||||||||
| Industrial | 113,091 | — | |||||||||
| Public authority and other | 50,565 | — | |||||||||
| Total gas sales revenues | 3,134,505 | — | |||||||||
| Transportation revenues | 107,822 | 646,416 | |||||||||
| Miscellaneous revenues | 10,971 | 14,141 | |||||||||
| Revenues from contracts with customers | 3,253,298 | 660,557 | |||||||||
Alternative revenue program revenues (1) | (13,303) | (23,210) | |||||||||
| Other revenues | 1,978 | — | |||||||||
| Total operating revenues | $ | 3,241,973 | $ | 637,347 | |||||||
| Year Ended September 30, 2020 | |||||||||||
| Distribution | Pipeline and Storage | ||||||||||
| Gas sales revenues: | |||||||||||
| Residential | $ | 1,704,444 | $ | — | |||||||
| Commercial | 650,396 | — | |||||||||
| Industrial | 89,467 | — | |||||||||
| Public authority and other | 41,339 | — | |||||||||
| Total gas sales revenues | 2,485,646 | — | |||||||||
| Transportation revenues | 99,435 | 636,819 | |||||||||
| Miscellaneous revenues | 19,085 | 9,754 | |||||||||
| Revenues from contracts with customers | 2,604,166 | 646,573 | |||||||||
Alternative revenue program revenues (1) | 20,856 | (37,234) | |||||||||
| Other revenues | 1,971 | — | |||||||||
| Total operating revenues | $ | 2,626,993 | $ | 609,339 | |||||||
53
| Year Ended September 30, 2019 | |||||||||||
| Distribution | Pipeline and Storage | ||||||||||
| Gas sales revenues: | |||||||||||
| Residential | $ | 1,755,229 | $ | — | |||||||
| Commercial | 716,757 | — | |||||||||
| Industrial | 118,060 | — | |||||||||
| Public authority and other | 42,796 | — | |||||||||
| Total gas sales revenues | 2,632,842 | — | |||||||||
| Transportation revenues | 97,495 | 623,808 | |||||||||
| Miscellaneous revenues | 26,050 | 8,060 | |||||||||
| Revenues from contracts with customers | 2,756,387 | 631,868 | |||||||||
Alternative revenue program revenues (1) | (12,958) | (64,844) | |||||||||
| Other revenues | 2,032 | — | |||||||||
| Total operating revenues | $ | 2,745,461 | $ | 567,024 | |||||||
(1)In our distribution segment, we have weather-normalization adjustment mechanisms that serve to mitigate the effects of weather on our revenue. Additionally, APT has a regulatory mechanism that requires that we share with its tariffed customers 75% of the difference between the total non-tariffed revenues earned during a test period and a revenue benchmark.
Accounts receivable and allowance for uncollectible accounts
As described in Note 2 to the consolidated financial statements, on October 1, 2020, we adopted new accounting guidance which requires credit losses on our accounts receivable to be measured using an expected credit loss model over the entire contractual term from the date of initial recognition.
Due to the COVID-19 pandemic, in March 2020 we temporarily suspended disconnecting customers for nonpayment and stopped charging late fees. We resumed disconnection activity during the third quarter of fiscal 2021. We are actively working with our customers experiencing financial hardship to offer flexible payment options and directing them to aid agencies for financial assistance. Our allowance for uncollectible accounts reflects the expected impact on our customers’ ability to pay.
Rollforwards of our allowance for uncollectible accounts for the year ended September 30, 2021, 2020 and 2019 are presented in the table below. The allowance excludes the gas cost portion of customers’ bills for approximately 79 percent of our customers as we have the ability to collect these gas costs through our gas cost recovery mechanisms in most of our jurisdictions.
| Allowance for uncollectible accounts | |||||
| (In thousands) | |||||
Balance, September 30, 2018 | $ | 14,795 | |||
| Current period provisions | 18,106 | ||||
| Write-offs charged against allowance | (19,575) | ||||
| Recoveries of amounts previously written off | 2,573 | ||||
Balance, September 30, 2019 | 15,899 | ||||
| Current period provisions | 24,796 | ||||
| Write-offs charged against allowance | (12,698) | ||||
| Recoveries of amounts previously written off | 1,952 | ||||
Balance, September 30, 2020 | 29,949 | ||||
| Current period provisions | 43,807 | ||||
| Write-offs charged against allowance | (11,019) | ||||
| Recoveries of amounts previously written off | 1,734 | ||||
Balance, September 30, 2021 | $ | 64,471 | |||
54
6. Leases
We adopted the provisions of the new lease accounting standard beginning on October 1, 2019, using the optional transition method, which allowed us to apply the provisions of the new standard to all leases that existed as of the date of adoption. Therefore, results for reporting periods beginning on October 1, 2019 are presented under the new lease accounting standard and prior periods are presented under the former lease accounting standard.
We are the lessee for substantially all of our leasing activity, which primarily includes operating leases for office and warehouse space, tower space, vehicles and heavy equipment used in our operations. We are also a lessee in finance leases for service centers.
The following table presents our weighted average remaining lease term for our leases.
| September 30, 2021 | September 30, 2020 | ||||||||||
| Weighted average remaining lease term (years) | |||||||||||
| Finance leases | 19.0 | 19.1 | |||||||||
| Operating leases | 10.2 | 10.6 | |||||||||
The following table represents our weighted average discount rate:
| September 30, 2021 | September 30, 2020 | ||||||||||
| Weighted average discount rate | |||||||||||
| Finance leases | 5.7 | % | 8.0 | % | |||||||
| Operating leases | 2.8 | % | 2.9 | % | |||||||
Lease costs for the year ended September 30, 2021 and 2020 are presented in the table below. These costs include both amounts recognized in expense and amounts capitalized. For the year ended September 30, 2021 and 2020 we did not have material short-term lease costs or variable lease costs.
| September 30, 2021 | September 30, 2020 | ||||||||||
| (In thousands) | |||||||||||
| Finance lease cost | $ | 1,334 | $ | 622 | |||||||
| Operating lease cost | 42,349 | 40,887 | |||||||||
| Total lease cost | $ | 43,683 | $ | 41,509 | |||||||
Our ROU assets and lease liabilities are presented as follows on the consolidated balance sheets:
| Balance Sheet Classification | September 30, 2021 | September 30, 2020 | ||||||||||||
| (In thousands) | ||||||||||||||
| Assets | ||||||||||||||
| Finance leases | $ | 18,252 | $ | 8,480 | ||||||||||
| Operating leases | 222,446 | 227,146 | ||||||||||||
| Total right-of-use assets | $ | 240,698 | $ | 235,626 | ||||||||||
| Liabilities | ||||||||||||||
| Current | ||||||||||||||
| Finance leases | $ | 452 | $ | 165 | ||||||||||
| Operating leases | 37,688 | 35,716 | ||||||||||||
| Noncurrent | ||||||||||||||
| Finance leases | 18,287 | 8,466 | ||||||||||||
| Operating leases | 194,745 | 201,071 | ||||||||||||
| Total lease liabilities | $ | 251,172 | $ | 245,418 | ||||||||||
Finance leases for two service centers are expected to commence in the first quarter of fiscal 2022 that impact our future lease payments. The total future lease payments for these leases are $46.5 million.
55
Other pertinent information related to leases was as follows. During the year ended September 30, 2021 and 2020, amounts paid in cash for our finance leases were not material.
| September 30, 2021 | September 30, 2020 | ||||||||||
| (In thousands) | |||||||||||
| Cash paid amounts included in the measurement of lease liabilities | |||||||||||
| Operating cash flows used for operating leases | $ | 42,013 | $ | 37,758 | |||||||
| Right-of-use assets obtained in exchange for lease obligations | |||||||||||
| Finance leases | $ | 10,333 | $ | 6,083 | |||||||
| Operating leases | $ | 25,690 | $ | 34,169 | |||||||
Maturities of our lease liabilities as of September 30, 2021 were as follows:
| Total | Finance Leases | Operating Leases | |||||||||
| (In thousands) | |||||||||||
| 2022 | $ | 43,164 | $ | 1,342 | $ | 41,822 | |||||
| 2023 | 38,690 | 1,365 | 37,325 | ||||||||
| 2024 | 32,106 | 1,388 | 30,718 | ||||||||
| 2025 | 23,927 | 1,411 | 22,516 | ||||||||
| 2026 | 18,278 | 1,435 | 16,843 | ||||||||
| Thereafter | 144,718 | 22,868 | 121,850 | ||||||||
| Total lease payments | 300,883 | 29,809 | 271,074 | ||||||||
| Less: Imputed interest | 49,711 | 11,070 | 38,641 | ||||||||
| Total | $ | 251,172 | $ | 18,739 | $ | 232,433 | |||||
Reported as of September 30, 2021 | |||||||||||
| Short-term lease liabilities | $ | 38,140 | $ | 452 | $ | 37,688 | |||||
| Long-term lease liabilities | 213,032 | 18,287 | 194,745 | ||||||||
| Total lease liabilities | $ | 251,172 | $ | 18,739 | $ | 232,433 | |||||
Disclosures Related to Periods Prior to Adoption of ASC 842
Consolidated lease and rental expense amounted to $40.4 million for fiscal 2019.
56
7. Debt
Long-term debt
Long-term debt at September 30, 2021 and 2020 consisted of the following:
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
Unsecured 0.625% Senior Notes, due 2023 | $ | 1,100,000 | $ | — | |||||||
Unsecured 3.00% Senior Notes, due 2027 | 500,000 | 500,000 | |||||||||
Unsecured 2.625% Senior Notes, due 2029 | 300,000 | 300,000 | |||||||||
Unsecured 1.50% Senior Notes, due 2031 | 600,000 | — | |||||||||
Unsecured 5.95% Senior Notes, due 2034 | 200,000 | 200,000 | |||||||||
Unsecured 5.50% Senior Notes, due 2041 | 400,000 | 400,000 | |||||||||
Unsecured 4.15% Senior Notes, due 2043 | 500,000 | 500,000 | |||||||||
Unsecured 4.125% Senior Notes, due 2044 | 750,000 | 750,000 | |||||||||
Unsecured 4.30% Senior Notes, due 2048 | 600,000 | 600,000 | |||||||||
Unsecured 4.125% Senior Notes, due 2049 | 450,000 | 450,000 | |||||||||
Unsecured 3.375% Senior Notes, due 2049 | 500,000 | 500,000 | |||||||||
Floating-rate term loan, due April 2022 | 200,000 | 200,000 | |||||||||
Floating-rate Senior Notes, due 2023 | 1,100,000 | — | |||||||||
Medium term Series A notes, 1995-1, 6.67%, due 2025 | 10,000 | 10,000 | |||||||||
Unsecured 6.75% Debentures, due 2028 | 150,000 | 150,000 | |||||||||
Finance lease obligations (see Note 6) | 18,739 | 8,631 | |||||||||
| Total long-term debt | 7,378,739 | 4,568,631 | |||||||||
| Less: | |||||||||||
| Net original issue (premium) / discount on unsecured senior notes and debentures | 2,811 | 583 | |||||||||
| Debt issuance cost | 45,271 | 36,104 | |||||||||
| Current maturities | 2,400,452 | 165 | |||||||||
| $ | 4,930,205 | $ | 4,531,779 | ||||||||
Maturities of long-term debt, excluding our finance lease obligations, at September 30, 2021 were as follows (in thousands):
| 2022 | $ | 2,400,000 | |||
| 2023 | — | ||||
| 2024 | — | ||||
| 2025 | 10,000 | ||||
| 2026 | — | ||||
| Thereafter | 4,950,000 | ||||
| $ | 7,360,000 | ||||
On October 1, 2021, we completed a public offering of $600 million of 2.85% senior notes dues 2052, with an effective interest rate of 2.58%, after giving effect to the offering costs and settlement of our interest rate swaps. The net proceeds from the offering, after the underwriting discount and estimated offering expenses, of $589.6 million, will be used for general corporate purposes.
On March 9, 2021, we completed a public offering of $1.1 billion of 0.625% senior notes due 2023, with an effective interest rate of 0.834%, after giving effect to the offering costs, and $1.1 billion floating rate senior notes due 2023 that bear interest at a rate equal to the Three-Month LIBOR rate plus 0.38%. The net proceeds from the offering, after the underwriting discount and offering expenses, of $2.2 billion were used for the payment of unplanned natural gas costs incurred during Winter Storm Uri. The notes are subject to optional redemption at any time on or after September 9, 2021 at a price equal to 100 percent of the principal amount of the notes being redeemed, plus any accrued and unpaid interest thereon, if any, to, but
57
excluding, the redemption date. As discussed in Note 9 to the consolidated financial statements, we intend to repay these notes in fiscal 2022 after the expected receipt of securitization funds. As such, we have classified the senior notes as current maturities of long-term debt as of September 30, 2021.
On October 1, 2020, we completed a public offering of $600 million of 1.50% senior notes due 2031, with an effective interest rate of 1.71%, after giving effect to the offering costs and settlement of our interest rate swaps. The net proceeds from the offering, after the underwriting discount and offering expenses, of $592.3 million, were used for general corporate purposes, including the repayment of working capital borrowings pursuant to our commercial paper program and the related settlement of our interest rate swaps.
Short-term Debt
We utilize short-term debt to provide cost-effective, short-term financing until it can be replaced with a balance of long-term debt and equity financing that achieves the Company’s desired capital structure with an equity-to-total-capitalization ratio between 50% and 60%, inclusive of long-term and short-term debt. Our short-term borrowing requirements are driven primarily by construction work in progress and the seasonal nature of the natural gas business.
Our short-term borrowing requirements are satisfied through a combination of a $1.5 billion commercial paper program and four committed revolving credit facilities with third-party lenders that provide $2.5 billion of total working capital funding.
The primary source of our funding is our commercial paper program, which is supported by a five-year unsecured $1.5 billion credit facility that was replaced on March 31, 2021, with a new five-year unsecured $1.5 billion credit facility that expires on March 31, 2026. The new facility bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a margin ranging from zero to 0.25 percent for base rate advances or a margin ranging from 0.75 percent to 1.25 percent for LIBOR-based advances, based on the Company’s credit ratings. Additionally, the facility contains a $250 million accordion feature, which provides the opportunity to increase the total committed loan to $1.75 billion. At September 30, 2021 and September 30, 2020, there were no amounts outstanding under our commercial paper program.
We had a $600 million 365-day unsecured revolving credit facility, which was replaced on March 31, 2021, with a new $900 million three-year unsecured revolving credit facility. This new facility will be used primarily to provide additional working capital funding. The new facility bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a margin ranging from zero percent to 0.25 percent for base rate advances or a margin ranging from 0.75 percent to 1.25 percent for LIBOR-based advances, based on the Company's credit ratings. Additionally, the facility contains a $100 million accordion feature, which provides the opportunity to increase the total committed loan to $1.0 billion. At September 30, 2021, there were no borrowings outstanding under this facility.
Additionally, we have a $50 million 364-day unsecured facility, which was renewed April 1, 2021 and is used to provide working capital funding. There were no borrowings outstanding under this facility as of September 30, 2021.
Finally, we have a $50 million 364-day unsecured revolving credit facility, which was renewed April 29, 2021 and is used to issue letters of credit and to provide working capital funding. At September 30, 2021, there were no borrowings outstanding under the new facility; however, outstanding letters of credit reduced the total amount available to us to $44.4 million.
Debt Covenants
The availability of funds under these credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total-debt-to-total-capitalization of no greater than 70 percent. At September 30, 2021, our total-debt-to-total-capitalization ratio, as defined, was 49 percent. In addition, both the interest margin and the fee that we pay on unused amounts under each of these facilities are subject to adjustment depending upon our credit ratings.
These credit facilities and our public indentures contain usual and customary covenants for our business, including covenants substantially limiting liens, substantial asset sales and mergers. Additionally, our public debt indentures relating to our senior notes and debentures, as well as certain of our revolving credit agreements, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is not paid at maturity. We were in compliance with all of our debt covenants as of September 30, 2021. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.
58
8. Shareholders' Equity
Shelf Registration, At-the-Market Equity Sales Program and Equity Issuances
On June 29, 2021, we filed a shelf registration statement with the Securities and Exchange Commission (SEC) that allows us to issue up to $5.0 billion in common stock and/or debt securities, which expires June 29, 2024. This shelf registration statement replaced our previous shelf registration statement which was filed on February 11, 2020. At September 30, 2021, approximately $4.0 billion of securities remained available for issuance under the shelf registration statement. Following the completion of the $600 million senior unsecured notes offering on October 1, 2021 (see Note 7 to the consolidated financial statements), approximately $3.4 billion of securities remained available for issuance under the shelf registration statement.
On June 29, 2021, we filed a prospectus supplement under the shelf registration statement relating to an at-the-market (ATM) equity sales program (June 2021 ATM) under which we may 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 concurrently with the ATM equity sales program). This ATM equity sales program replaced our previous ATM equity sales program, filed on February 12, 2020 (February 2020 ATM).
During the year ended September 30, 2021, we executed forward sales under the February 2020 ATM and June 2021 ATM equity sales programs with various forward sellers who borrowed and sold 5,866,604 shares of our common stock at an aggregate price of $578.4 million. During the year ended September 30, 2021, we also settled forward sale agreements with respect to 6,130,875 shares that had been borrowed and sold by various forward sellers under the February 2020 ATM for net proceeds of $606.7 million. As of September 30, 2021, $760 million of equity was available for issuance under the June 2021 ATM program. Additionally, we had $302.0 million in available proceeds from outstanding forward sale agreements, as detailed below.
| Maturity | Shares Available | Net Proceeds Available (In Thousands) | Forward Price | ||||||||||||||
| June 30, 2022 | 1,681,910 | $ | 166,989 | 99.29 | |||||||||||||
| September 30, 2022 | 1,389,814 | 134,995 | 97.13 | ||||||||||||||
| Total | 3,071,724 | $ | 301,984 | 98.31 | |||||||||||||
Accumulated Other Comprehensive Income (Loss)
We record deferred gains (losses) in accumulated other comprehensive income (AOCI) related to available-for-sale debt securities and interest rate agreement cash flow hedges. Deferred gains (losses) for our available-for-sale debt securities are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate agreement cash flow hedges are recognized in earnings as a component of interest charges, as they are amortized. The following tables provide the components of our accumulated other comprehensive income (loss) balances, net of the related tax effects allocated to each component of other comprehensive income (loss).
| Available- for-Sale Securities | Interest Rate Agreement Cash Flow Hedges | Total | |||||||||||||||
| (In thousands) | |||||||||||||||||
| September 30, 2020 | $ | 238 | $ | (57,827) | $ | (57,589) | |||||||||||
| Other comprehensive income (loss) before reclassifications | (191) | 123,017 | 122,826 | ||||||||||||||
| Amounts reclassified from accumulated other comprehensive income | — | 4,566 | 4,566 | ||||||||||||||
| Net current-period other comprehensive income (loss) | (191) | 127,583 | 127,392 | ||||||||||||||
| September 30, 2021 | $ | 47 | $ | 69,756 | $ | 69,803 | |||||||||||
59
| Available- for-Sale Securities | Interest Rate Agreement Cash Flow Hedges | Total | |||||||||||||||
| (In thousands) | |||||||||||||||||
| September 30, 2019 | $ | 132 | $ | (114,715) | $ | (114,583) | |||||||||||
| Other comprehensive income before reclassifications | 108 | 53,241 | 53,349 | ||||||||||||||
Amounts reclassified from accumulated other comprehensive income | (2) | 3,647 | 3,645 | ||||||||||||||
| Net current-period other comprehensive income | 106 | 56,888 | 56,994 | ||||||||||||||
| September 30, 2020 | $ | 238 | $ | (57,827) | $ | (57,589) | |||||||||||
9. Winter Storm Uri
Overview
A historic winter storm impacted supply, market pricing and demand for natural gas in our service territories in mid-February. During this time, the governors of Kansas and Texas each declared a state of emergency, and certain regulatory agencies issued emergency orders that impacted the utility and natural gas industries, including statewide utilities curtailment programs and orders encouraging or requiring jurisdictional natural gas utilities to work to ensure customers were provided with safe and reliable natural gas service.
Due to the historic nature of this winter storm, we experienced unforeseeable and unprecedented market pricing for gas costs, which resulted in aggregated natural gas purchases during the month of February of approximately $2.3 billion. These gas costs were paid by the end of March 2021.
Incremental Financing
As discussed in Note 7 to the consolidated financial statements, on March 9, 2021, we completed a public offering of $2.2 billion in debt securities and the net proceeds from the offering, after the underwriting discount and offering expenses, were used to substantially fund these purchased gas costs. As a result of this unplanned debt issuance, S&P lowered its long-term/short-term credit ratings from A/A-1 to A-/A-2 and placed our ratings under negative outlook. Moody’s reaffirmed its long-term and short-term credit ratings and placed our ratings under negative outlook. These credit rating adjustments and the issuance of unplanned debt did not impact our ability to satisfy our debt covenants.
Regulatory Asset Accounting
Our purchased gas costs are recoverable through purchased gas cost adjustment mechanisms in each state where we operate. Due to the unprecedented level of purchased gas costs incurred during Winter Storm Uri, the Kansas Corporation Commission (KCC) and the Railroad Commission of Texas (RRC) issued orders authorizing natural gas utilities to record a regulatory asset to account for the extraordinary costs associated with the winter storm. Pursuant to these orders, as of September 30, 2021, we have recorded a $2.1 billion regulatory asset for incremental costs, including carrying costs, incurred in Kansas ($89.0 million) and Texas ($2,011.7 million). These costs are subject to review for prudency by each commission and may be adjusted.
Securitization
To minimize the impact on the customer bill by extending the recovery periods for these unprecedented purchased gas costs, the Kansas and Texas State Legislatures each approved securitization legislation during fiscal 2021. The following summarizes the status of the securitization of each state as of the date of this filing.
Kansas
The Kansas securitization legislation, which became effective April 9, 2021, permits a natural gas public utility, in its sole discretion, to apply to the KCC for a financing order for the recovery of qualified extraordinary costs through the issuance of bonds. Within 25 days after a complete application is filed, the KCC shall establish a procedural schedule that requires it to issue a decision on the application within 180 days from the date a complete application was filed. Utilities may apply for a recovery period of up to 32 years.
On September 14, 2021, we filed with the KCC an application to securitize $94.1 million of extraordinary gas costs incurred during Winter Storm Uri. This amount also includes an estimate of penalties, carrying costs and administrative costs
60
that we expect to incur in connection with the resolution of this filing. Included in our filing is an allowed deferral of an equity return as part of the recoverable carrying costs. As of September 30, 2021, approximately $2.8 million is capitalized for ratemaking purposes but is not recorded as a regulatory asset on our consolidated balance sheet. We anticipate proceedings to begin in January 2022. Because we intend to securitize these costs and recover over several years, we have recorded the regulatory asset for Kansas as a long-term asset in deferred charges and other assets as of September 30, 2021.
Texas
On June 16, 2021, House Bill 1520 became effective. House Bill 1520 authorizes the RRC to issue a statewide securitization financing order directing the Texas Public Finance authority to issue bonds (customer rate relief bonds) for gas utilities that choose to participate to recover extraordinary costs incurred to secure gas supply and to provide service during Winter Storm Uri, and to restore gas utility systems after that event, thereby providing rate relief to customers by extending the period during which these extraordinary costs would otherwise be recovered and supporting the financial strength and stability of gas utility companies.
The legislation required natural gas utilities seeking to participate in the securitization program to file an application with the RRC and submit extraordinary gas costs incurred during Winter Storm Uri for a prudency review by July 30, 2021. We filed our application with the RRC on July 30, 2021 to securitize $2.0 billion of extraordinary gas costs incurred during Winter Storm Uri. This amount also included an estimate of carrying costs and administrative costs that we expect to incur in connection with the resolution of this filing.
On November 10, 2021, the RRC issued a Final Determination of the Regulatory Asset (the Final Determination). The Final Determination stipulates that all of our gas and storage costs were prudently incurred. Additionally, the Final Determination permits us to defer, through December 31, 2021 our actual carrying costs associated with the $2.2 billion of incremental financing issued in March 2021 and to recover approximately $0.6 million of our administrative costs.
The statutory deadline for the RRC to issue a Financing Order is March 27, 2022. The Financing Order will be issued to the Texas Public Financing Authority authorizing the issuance of customer rate relief bonds to securitize the aggregated extraordinary costs for all participating utilities within 180 days. The participating utilities, as servicers acting on behalf of the state of the securitization financing, will bill and collect customer rate relief charges from their current and future customers and remit the collections to the state issuer of the securitization financing.
Based on the RRC's procedural schedule, we believe we will receive the securitization funds within twelve months. We will repay the $2.2 billion in public notes issued to finance the incremental gas costs incurred during Winter Storm Uri. Accordingly, we have recorded the regulatory asset for Texas in other current assets and these notes as current maturities of long-term debt as of September 30, 2021.
10. Retirement and Post-Retirement Employee Benefit Plans
We have both funded and unfunded noncontributory defined benefit plans that together cover most of our employees. We also maintain post-retirement plans that provide health care benefits to retired employees. Finally, we sponsor a defined contribution plan that covers substantially all employees. These plans are discussed in further detail below.
As a rate regulated entity, most of our net periodic pension and other postretirement benefits costs are recoverable through our rates over a period of up to 15 years. A portion of these costs is capitalized into our rate base or deferred as a regulatory asset or liability. The remaining costs are recorded as a component of operation and maintenance expense or other non-operating expense. Additionally, the amounts that have not yet been recognized in net periodic pension cost that have been recorded as regulatory assets or liabilities are as follows:
61
| Defined Benefit Plan | Supplemental Executive Retirement Plans | Postretirement Plans | Total | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| September 30, 2021 | |||||||||||||||||||||||
| Unrecognized prior service (credit) cost | $ | (353) | $ | — | $ | (64,313) | $ | (64,666) | |||||||||||||||
| Unrecognized actuarial (gain) loss | (3,060) | 39,666 | (28,141) | 8,465 | |||||||||||||||||||
| $ | (3,413) | $ | 39,666 | $ | (92,454) | $ | (56,201) | ||||||||||||||||
| September 30, 2020 | |||||||||||||||||||||||
| Unrecognized prior service (credit) cost | $ | (584) | $ | — | $ | 951 | $ | 367 | |||||||||||||||
| Unrecognized actuarial loss | 78,082 | 51,045 | 9,110 | 138,237 | |||||||||||||||||||
| $ | 77,498 | $ | 51,045 | $ | 10,061 | $ | 138,604 | ||||||||||||||||
Defined Benefit Plans
Employee Pension Plan
As of September 30, 2021, we maintained one cash balance defined benefit plan, the Atmos Energy Corporation Pension Account Plan (the Plan). The Plan was established effective January 1999 and covers most of the employees of Atmos Energy that were hired on or before September 30, 2010. Effective October 1, 2010, the plan was closed to new participants. The assets of the Plan are held within the Atmos Energy Corporation Master Retirement Trust (the Master Trust).
Opening account balances were established for participants as of January 1999 equal to the present value of their respective accrued benefits under the pension plans which were previously in effect as of December 31, 1998. The Plan credits an allocation to each participant’s account at the end of each year according to a formula based on the participant’s age, service and total pay (excluding incentive pay). In addition, at the end of each year, a participant’s account is credited with interest on the employee’s prior year account balance. Participants are fully vested in their account balances after three years of service and may choose to receive their account balances as a lump sum or an annuity.
Generally, our funding policy is to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974, including the funding requirements under the Pension Protection Act of 2006 (PPA). However, additional voluntary contributions are made from time to time as considered necessary. Contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future.
During fiscal 2021, we contributed $10.0 million in cash to the Plan to achieve a desired level of funding while maximizing the tax deductibility of this payment. During fiscal 2020, we did not make a contribution to the Plan. Based upon market conditions at September 30, 2021, the current funded position of the Plan and the funding requirements under the PPA, we do not anticipate a minimum required contribution for fiscal 2022. However, we may consider whether a voluntary contribution is prudent to maintain certain funding levels.
We make investment decisions and evaluate performance of the assets in the Master Trust on a medium-term horizon of at least to five years. We also consider our current financial status when making recommendations and decisions regarding the Master Trust’s assets. Finally, we strive to ensure the Master Trust’s assets are appropriately invested to maintain an acceptable level of risk and meet the Master Trust’s long-term asset investment policy adopted by the Board of Directors.
To achieve these objectives, we invest the Master Trust’s assets in equity securities, fixed income securities, interests in commingled pension trust funds, other investment assets and cash and cash equivalents. Investments in equity securities are diversified among the market’s various subsectors in an effort to diversify risk and maximize returns. Fixed income securities are invested in investment grade securities. Cash equivalents are invested in securities that either are short term (less than 180 days) or readily convertible to cash with modest risk.
The following table presents asset allocation information for the Master Trust as of September 30, 2021 and 2020.
62
| Targeted Allocation Range | Actual Allocation September 30 | ||||||||||||||||
| Security Class | 2021 | 2020 | |||||||||||||||
| Domestic equities | 35%-55% | 44.5% | 45.3% | ||||||||||||||
| International equities | 10%-20% | 16.9% | 15.6% | ||||||||||||||
| Fixed income | 5%-30% | 16.0% | 17.0% | ||||||||||||||
| Company stock | 0%-15% | 10.6% | 13.0% | ||||||||||||||
| Other assets | 0%-20% | 12.0% | 9.1% | ||||||||||||||
At September 30, 2021 and 2020, the Plan held 716,700 shares of our common stock which represented 10.6 percent and 13.0 percent of total Plan assets. These shares generated dividend income for the Plan of approximately $1.8 million and $1.6 million during fiscal 2021 and 2020.
Our employee pension plan expenses and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected return on plan assets and assumed discount rates and demographic data. We review the estimates and assumptions underlying our employee pension plans annually based upon a September 30 measurement date. The development of our assumptions is fully described in our significant accounting policies in Note 2 to the consolidated financial statements. The actuarial assumptions used to determine the pension liability for the Plan was determined as of September 30, 2021 and 2020 and the actuarial assumptions used to determine the net periodic pension cost for the Plan was determined as of September 30, 2020, 2019 and 2018. In October 2021, the Society of Actuaries released its annually-updated mortality improvement scale for pension plans incorporating new assumptions surrounding life expectancies in the United States. As of September 30, 2021, we updated our assumed mortality rates to incorporate the updated mortality table.
Additional assumptions are presented in the following table:
| Pension Liability | Pension Cost | ||||||||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | 2019 | |||||||||||||||||||||||||
| Discount rate | 2.97 | % | 2.80 | % | 2.80 | % | 3.29 | % | 4.38 | % | |||||||||||||||||||
| Rate of compensation increase | 3.50 | % | 3.50 | % | 3.50 | % | 3.50 | % | 3.50 | % | |||||||||||||||||||
| Expected return on plan assets | 6.25 | % | 6.25 | % | 6.25 | % | 6.50 | % | 6.75 | % | |||||||||||||||||||
| Interest crediting rate | 4.69 | % | 4.69 | % | 4.69 | % | 4.69 | % | 4.69 | % | |||||||||||||||||||
The following table presents the Plan’s accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2021 and 2020:
63
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Accumulated benefit obligation | $ | 558,639 | $ | 565,755 | |||||||
| Change in projected benefit obligation: | |||||||||||
| Benefit obligation at beginning of year | $ | 604,221 | $ | 577,270 | |||||||
| Service cost | 17,369 | 17,551 | |||||||||
| Interest cost | 16,883 | 19,028 | |||||||||
| Actuarial (gain) loss | (7,561) | 22,898 | |||||||||
| Benefits paid | (34,883) | (32,526) | |||||||||
| Benefit obligation at end of year | 596,029 | 604,221 | |||||||||
| Change in plan assets: | |||||||||||
| Fair value of plan assets at beginning of year | 528,881 | 530,109 | |||||||||
| Actual return on plan assets | 92,808 | 31,298 | |||||||||
| Employer contributions | 10,000 | — | |||||||||
| Benefits paid | (34,883) | (32,526) | |||||||||
| Fair value of plan assets at end of year | 596,806 | 528,881 | |||||||||
| Reconciliation: | |||||||||||
| Funded status | 777 | (75,340) | |||||||||
| Unrecognized prior service cost | — | — | |||||||||
| Unrecognized net loss | — | — | |||||||||
| Net amount recognized | $ | 777 | $ | (75,340) | |||||||
Net periodic pension cost for the Plan for fiscal 2021, 2020 and 2019 is presented in the following table.
| Fiscal Year Ended September 30 | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Components of net periodic pension cost: | |||||||||||||||||
| Service cost | $ | 17,369 | $ | 17,551 | $ | 15,311 | |||||||||||
Interest cost (1) | 16,883 | 19,028 | 22,071 | ||||||||||||||
Expected return on assets (1) | (27,913) | (28,316) | (28,451) | ||||||||||||||
Amortization of prior service cost (credit) (1) | 8,686 | (231) | (232) | ||||||||||||||
Recognized actuarial (gain) loss (1) | (231) | 9,025 | 4,201 | ||||||||||||||
| Net periodic pension cost | $ | 14,794 | $ | 17,057 | $ | 12,900 | |||||||||||
(1) The components of net periodic cost other than the service cost component are included in the line item other non-operating income (expense) in the consolidated statements of comprehensive income or are capitalized on the consolidated balance sheets as a regulatory asset or liability, as described in Note 2 to the consolidated financial statements.
64
The following tables set forth by level, within the fair value hierarchy, the Plan's assets at fair value as of September 30, 2021 and 2020. As required by authoritative accounting literature, assets are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement. The methods used to determine fair value for the assets held by the Plan are fully described in Note 2 to the consolidated financial statements. Investments in our common/collective trusts and limited partnerships that are measured at net asset value per share equivalent are not classified in the fair value hierarchy. The net asset value amounts presented are intended to reconcile the fair value hierarchy to the total investments. In addition to the assets shown below, the Plan had net accounts receivable of $2.1 million and $0.7 million at September 30, 2021 and 2020, which materially approximates fair value due to the short-term nature of these assets.
| Assets at Fair Value as of September 30, 2021 | |||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Investments: | |||||||||||||||||||||||
| Common stocks | $ | 239,166 | $ | — | $ | — | $ | 239,166 | |||||||||||||||
| Money market funds | — | 7,060 | — | 7,060 | |||||||||||||||||||
| Registered investment companies | 74,236 | — | — | 74,236 | |||||||||||||||||||
| Government securities: | |||||||||||||||||||||||
| Mortgage-backed securities | — | 14,048 | — | 14,048 | |||||||||||||||||||
| U.S. treasuries | 7,483 | 34 | — | 7,517 | |||||||||||||||||||
| Corporate bonds | — | 30,834 | — | 30,834 | |||||||||||||||||||
| Total investments measured at fair value | $ | 320,885 | $ | 51,976 | $ | — | 372,861 | ||||||||||||||||
| Investments measured at net asset value: | |||||||||||||||||||||||
Common/collective trusts (1) | 121,570 | ||||||||||||||||||||||
Limited partnerships (1) | 100,299 | ||||||||||||||||||||||
| Total investments | $ | 594,730 | |||||||||||||||||||||
| Assets at Fair Value as of September 30, 2020 | |||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Investments: | |||||||||||||||||||||||
| Common stocks | $ | 211,244 | $ | — | $ | — | $ | 211,244 | |||||||||||||||
| Money market funds | — | 6,096 | — | 6,096 | |||||||||||||||||||
| Registered investment companies | 29,762 | — | — | 29,762 | |||||||||||||||||||
| Government securities: | |||||||||||||||||||||||
| Mortgage-backed securities | — | 15,230 | — | 15,230 | |||||||||||||||||||
| U.S. treasuries | 21,755 | 36 | — | 21,791 | |||||||||||||||||||
| Corporate bonds | — | 52,648 | — | 52,648 | |||||||||||||||||||
| Total investments measured at fair value | $ | 262,761 | $ | 74,010 | $ | — | 336,771 | ||||||||||||||||
| Investments measured at net asset value: | |||||||||||||||||||||||
Common/collective trusts (1) | 122,207 | ||||||||||||||||||||||
Limited partnerships (1) | 69,176 | ||||||||||||||||||||||
| Total investments | $ | 528,154 | |||||||||||||||||||||
(1) The fair value of our common/collective trusts and limited partnerships are measured using the net asset value per share practical expedient. There are no redemption restrictions, redemption notice periods or unfunded commitments for these investments. The redemption frequency is daily.
Supplemental Executive Retirement Plans
We have three nonqualified supplemental plans which provide additional pension, disability and death benefits to our officers, division presidents and certain other employees of the Company.
65
The first plan is referred to as the Supplemental Executive Benefits Plan (SEBP) and covers our corporate officers and certain other employees of the Company who were employed on or before August 12, 1998. The SEBP is a defined benefit arrangement which provides a benefit equal to 75 percent of covered compensation under which benefits paid from the underlying qualified defined benefit plan are an offset to the benefits under the SEBP.
In August 1998, we adopted the Supplemental Executive Retirement Plan (SERP) (formerly known as the Performance-Based Supplemental Executive Benefits Plan), which covers all corporate officers selected to participate in the plan between August 12, 1998 and August 5, 2009. The SERP is a defined benefit arrangement which provides a benefit equal to 60 percent of covered compensation under which benefits paid from the underlying qualified defined benefit plan are an offset to the benefits under the SERP.
Effective August 5, 2009, we adopted a new defined benefit Supplemental Executive Retirement Plan (the 2009 SERP), for corporate officers or any other employees selected at the discretion of the Board. Under the 2009 SERP, a nominal account has been established for each participant, to which the Company contributes at the end of each calendar year an amount equal to ten percent (25 percent for members of the Management Committee appointed on or after January 1, 2016) of the total of each participant’s base salary and cash incentive compensation earned during each prior calendar year, beginning December 31, 2009. The benefits vest after three years of service and attainment of age 55 and earn interest credits at the same annual rate as the Company’s Pension Account Plan.
Due to the retirement of certain executives of the company during fiscal 2021, we recognized a settlement charge of $9.2 million and paid a $25.7 million lump sum in relation to the retirements.
Similar to our employee pension plans, we review the estimates and assumptions underlying our supplemental plans annually based upon a September 30 measurement date using the same techniques as our employee pension plans. The actuarial assumptions used to determine the pension liability for the supplemental plans were determined as of September 30, 2021 and 2020 and the actuarial assumptions used to determine the net periodic pension cost for the supplemental plans were determined as of September 30, 2020, 2019 and 2018. These assumptions are presented in the following table:
| Pension Liability | Pension Cost | ||||||||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | 2019 | |||||||||||||||||||||||||
Discount rate (1) | 2.57 | % | 2.80 | % | 2.90 | % | 3.19 | % | 4.38 | % | |||||||||||||||||||
| Rate of compensation increase | 3.50 | % | 3.50 | % | 3.50 | % | 3.50 | % | 3.50 | % | |||||||||||||||||||
| Interest crediting rate | 4.69 | % | 4.69 | % | 4.69 | % | 4.69 | % | 4.69 | % | |||||||||||||||||||
(1) Reflects a weighted average discount rate for pension cost for fiscal 2021 and 2020 due to the settlements during the year.
66
The following table presents the supplemental plans’ accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2021 and 2020:
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Accumulated benefit obligation | $ | 100,981 | $ | 122,207 | |||||||
| Change in projected benefit obligation: | |||||||||||
| Benefit obligation at beginning of year | $ | 129,140 | $ | 143,987 | |||||||
| Service cost | 1,067 | 1,074 | |||||||||
| Interest cost | 3,180 | 4,188 | |||||||||
| Actuarial (gain) loss | 1,332 | 7,386 | |||||||||
| Benefits paid | (4,720) | (4,766) | |||||||||
| Settlements | (25,698) | (22,729) | |||||||||
| Benefit obligation at end of year | 104,301 | 129,140 | |||||||||
| Change in plan assets: | |||||||||||
| Fair value of plan assets at beginning of year | — | — | |||||||||
| Employer contribution | 30,418 | 27,495 | |||||||||
| Benefits paid | (4,720) | (4,766) | |||||||||
| Settlements | (25,698) | (22,729) | |||||||||
| Fair value of plan assets at end of year | — | — | |||||||||
| Reconciliation: | |||||||||||
| Funded status | (104,301) | (129,140) | |||||||||
| Unrecognized prior service cost | — | — | |||||||||
| Unrecognized net loss | — | — | |||||||||
| Accrued pension cost | $ | (104,301) | $ | (129,140) | |||||||
Assets for the supplemental plans are held in separate rabbi trusts. At September 30, 2021 and 2020, assets held in the rabbi trusts consisted of equity securities of $38.1 million and $41.9 million, which are included in our fair value disclosures in Note 16 to the consolidated financial statements.
Net periodic pension cost for the supplemental plans for fiscal 2021, 2020 and 2019 is presented in the following table.
| Fiscal Year Ended September 30 | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Components of net periodic pension cost: | |||||||||||||||||
| Service cost | $ | 1,067 | $ | 1,074 | $ | 869 | |||||||||||
Interest cost (1) | 3,180 | 4,188 | 5,127 | ||||||||||||||
Recognized actuarial loss (1) | 3,560 | 3,945 | 2,227 | ||||||||||||||
Settlements (1) | 9,151 | 9,180 | — | ||||||||||||||
| Net periodic pension cost | $ | 16,958 | $ | 18,387 | $ | 8,223 | |||||||||||
(1) The components of net periodic cost other than the service cost component are included in the line item other non-operating income (expense) in the consolidated statements of comprehensive income or are capitalized on the consolidated balance sheets as a regulatory asset or liability, as described in Note 2 to the consolidated financial statements.
67
Estimated Future Benefit Payments
The following benefit payments for our defined benefit plans, which reflect expected future service, as appropriate, are expected to be paid in the following fiscal years:
| Pension Plan | Supplemental Plans | ||||||||||
| (In thousands) | |||||||||||
| 2022 | $ | 39,020 | $ | 4,925 | |||||||
| 2023 | 39,624 | 11,384 | |||||||||
| 2024 | 40,314 | 4,496 | |||||||||
| 2025 | 41,085 | 39,769 | |||||||||
| 2026 | 42,053 | 5,665 | |||||||||
| 2027-2031 | 203,461 | 22,079 | |||||||||
Postretirement Benefits
We sponsor the Retiree Medical Plan for Retirees and Disabled Employees of Atmos Energy Corporation (the Atmos Retiree Medical Plan). This plan provides medical and prescription drug protection to all qualified participants based on their date of retirement. The Atmos Retiree Medical Plan provides different levels of benefits depending on the level of coverage chosen by the participants and the terms of predecessor plans; however, we generally pay 80 percent of the projected net claims and administrative costs and participants pay the remaining 20 percent. Effective January 1, 2015, for employees who had not met the participation requirements by September 30, 2009, the contribution rates for the Company are limited to a three percent cost increase in claims and administrative costs each year, with the participant responsible for the additional costs.
Generally, our funding policy is to contribute annually an amount in accordance with the requirements of ERISA. However, additional voluntary contributions are made annually as considered necessary. Contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future. We expect to contribute between $15 million and $25 million to our postretirement benefits plan during fiscal 2022.
We maintain a formal investment policy with respect to the assets in our postretirement benefits plan to ensure the assets funding the postretirement benefit plan are appropriately invested to maintain an acceptable level of risk. We also consider our current financial status when making recommendations and decisions regarding the postretirement benefits plan.
We currently invest the assets funding our postretirement benefit plan in diversified investment funds which consist of common stocks, preferred stocks and fixed income securities. The diversified investment funds may invest up to 75 percent of assets in common stocks and convertible securities. The following table presents asset allocation information for the postretirement benefit plan assets as of September 30, 2021 and 2020.
| Actual Allocation September 30 | |||||||||||
| Security Class | 2021 | 2020 | |||||||||
| Diversified investment funds | 97.9% | 97.4% | |||||||||
| Cash and cash equivalents | 2.1% | 2.6% | |||||||||
Similar to our employee pension and supplemental plans, we review the estimates and assumptions underlying our postretirement benefit plan annually based upon a September 30 measurement date using the same techniques as our employee pension plans. The actuarial assumptions used to determine the pension liability for our postretirement plan were determined as of September 30, 2021 and 2020 and the actuarial assumptions used to determine the net periodic pension cost for the postretirement plan were determined as of September 30, 2020, 2019 and 2018.
Effective January 1, 2022, the Retiree Medical Plan for Retirees and Disabled Employees will be amended. The amendments remove the three percent cost increase limitation and change the post-65 retiree coverage to Via Benefits with an Atmos Energy funded Health Reimbursement Account. Eligible post-65 retirees and post-65 spouses will be eligible to enroll in benefits provided by Via Benefits, including those that previously deferred or declined retiree coverage. The amendments were approved by the Atmos Energy Board of Directors in May 2021 and the changes were communicated to participants beginning on July 31, 2021. These amendments to the Retiree Medical Plan for Retirees and Disabled Employees have been included in the actuarial assumptions used to determine the pension liability and net periodic for the postretirement plan as of September 30, 2020.
68
The assumptions are presented in the following table:
| Postretirement Liability | Postretirement Cost | ||||||||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | 2019 | |||||||||||||||||||||||||
| Discount rate | 3.01 | % | 2.80 | % | 2.80 | % | 3.29 | % | 4.38 | % | |||||||||||||||||||
| Expected return on plan assets | 4.94 | % | 4.94 | % | 4.94 | % | 5.14 | % | 5.33 | % | |||||||||||||||||||
| Initial trend rate | 6.25 | % | 6.25 | % | 6.25 | % | 6.25 | % | 6.50 | % | |||||||||||||||||||
| Ultimate trend rate | 5.00 | % | 5.00 | % | 5.00 | % | 5.00 | % | 5.00 | % | |||||||||||||||||||
| Ultimate trend reached in | 2027 | 2026 | 2026 | 2025 | 2022 | ||||||||||||||||||||||||
The following table presents the postretirement plan’s benefit obligation and funded status as of September 30, 2021 and 2020:
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Change in benefit obligation: | |||||||||||
| Benefit obligation at beginning of year | $ | 370,678 | $ | 316,033 | |||||||
| Service cost | 11,000 | 13,466 | |||||||||
| Interest cost | 15,372 | 10,612 | |||||||||
| Plan participants’ contributions | 5,648 | 5,849 | |||||||||
| Actuarial (gain) loss | 6,800 | 43,412 | |||||||||
| Benefits paid | (19,610) | (18,694) | |||||||||
| Plan amendments | (34,732) | — | |||||||||
| Benefit obligation at end of year | 355,156 | 370,678 | |||||||||
| Change in plan assets: | |||||||||||
| Fair value of plan assets at beginning of year | 208,245 | 201,901 | |||||||||
| Actual return on plan assets | 53,335 | 2,356 | |||||||||
| Employer contributions | 20,581 | 16,833 | |||||||||
| Plan participants’ contributions | 5,648 | 5,849 | |||||||||
| Benefits paid | (19,610) | (18,694) | |||||||||
| Fair value of plan assets at end of year | 268,199 | 208,245 | |||||||||
| Reconciliation: | |||||||||||
| Funded status | (86,957) | (162,433) | |||||||||
| Unrecognized transition obligation | — | — | |||||||||
| Unrecognized prior service cost | — | — | |||||||||
| Unrecognized net loss | — | — | |||||||||
| Accrued postretirement cost | $ | (86,957) | $ | (162,433) | |||||||
69
Net periodic postretirement cost for fiscal 2021, 2020 and 2019 is presented in the following table.
| Fiscal Year Ended September 30 | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Components of net periodic postretirement cost: | |||||||||||||||||
| Service cost | $ | 11,000 | $ | 13,466 | $ | 10,810 | |||||||||||
Interest cost (1) | 15,372 | 10,612 | 11,839 | ||||||||||||||
Expected return on assets (1) | (10,455) | (10,499) | (10,659) | ||||||||||||||
Amortization of transition obligation (1) | — | — | — | ||||||||||||||
Amortization of prior service cost (1) | 30,533 | 173 | 173 | ||||||||||||||
Recognized actuarial gain (1) | 1,172 | (1,337) | (8,178) | ||||||||||||||
| Net periodic postretirement cost | $ | 47,622 | $ | 12,415 | $ | 3,985 | |||||||||||
(1) The components of net periodic cost other than the service cost component are included in the line item other non-operating income (expense) in the consolidated statements of comprehensive income or are capitalized on the consolidated balance sheets as a regulatory asset or liability, as described in Note 2 to the consolidated financial statements.
We are currently recovering other postretirement benefits costs through our regulated rates in substantially all of our service areas under accrual accounting as prescribed by accounting principles generally accepted in the United States. Other postretirement benefits costs have been specifically addressed in rate orders in each jurisdiction served by our Kentucky/Mid-States, West Texas, Mid-Tex and Mississippi Divisions as well as our Kansas jurisdiction and APT or have been included in a rate case and not disallowed. Management believes that this accounting method is appropriate and will continue to seek rate recovery of accrual-based expenses in its ratemaking jurisdictions that have not yet approved the recovery of these expenses.
The following tables set forth by level, within the fair value hierarchy, the Retiree Medical Plan’s assets at fair value as of September 30, 2021 and 2020. The methods used to determine fair value for the assets held by the Retiree Medical Plan are fully described in Note 2 to the consolidated financial statements.
| Assets at Fair Value as of September 30, 2021 | |||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Investments: | |||||||||||||||||||||||
| Money market funds | $ | — | $ | 5,527 | $ | — | $ | 5,527 | |||||||||||||||
| Registered investment companies | 262,672 | — | — | 262,672 | |||||||||||||||||||
| Total investments measured at fair value | $ | 262,672 | $ | 5,527 | $ | — | $ | 268,199 | |||||||||||||||
| Assets at Fair Value as of September 30, 2020 | |||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Investments: | |||||||||||||||||||||||
| Money market funds | $ | — | $ | 5,525 | $ | — | $ | 5,525 | |||||||||||||||
| Registered investment companies | 202,720 | — | — | 202,720 | |||||||||||||||||||
| Total investments measured at fair value | $ | 202,720 | $ | 5,525 | $ | — | $ | 208,245 | |||||||||||||||
70
Estimated Future Benefit Payments
The following benefit payments paid by us, retirees and prescription drug subsidy payments for our postretirement benefit plans, which reflect expected future service, as appropriate, are expected to be paid in the following fiscal years. Company payments for fiscal 2021 include contributions to our postretirement plan trusts.
| Company Payments | Retiree Payments | Subsidy Payments | Total Postretirement Benefits | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| 2022 | $ | 17,701 | $ | 2,490 | $ | — | $ | 20,191 | |||||||||||||||
| 2023 | 18,031 | 2,465 | — | 20,496 | |||||||||||||||||||
| 2024 | 18,341 | 2,404 | — | 20,745 | |||||||||||||||||||
| 2025 | 18,981 | 2,425 | — | 21,406 | |||||||||||||||||||
| 2026 | 19,414 | 2,395 | — | 21,809 | |||||||||||||||||||
| 2027-2031 | 100,312 | 10,641 | — | 110,953 | |||||||||||||||||||
Defined Contribution Plan
The Atmos Energy Corporation Retirement Savings Plan and Trust (the Retirement Savings Plan) covers substantially all employees and is subject to the provisions of Section 401(k) of the Internal Revenue Code. Effective January 1, 2007, employees automatically become participants of the Retirement Savings Plan on the date of employment. Participants may elect a salary reduction up to a maximum of 65 percent of eligible compensation, as defined by the Plan, not to exceed the maximum allowed by the Internal Revenue Service. New participants are automatically enrolled in the Plan at a contribution rate of four percent of eligible compensation, from which they may opt out. We match 100 percent of a participant’s contributions, limited to four percent of the participant’s salary. Prior to January 1, 2021, participants were eligible to receive matching contributions after completing one year of service, in which they are immediately vested. Effective January 1, 2021, participants are eligible to receive matching contributions immediately upon enrollment in the Retirement Savings Plan. This matching contribution vests after completing one year of service. Participants are also permitted to take out a loan against their accounts subject to certain restrictions. Employees hired on or after October 1, 2010 participate in the enhanced plan in which participants receive a fixed annual contribution of four percent of eligible earnings to their Retirement Savings Plan account. Participants will continue to be eligible for company matching contributions of up to four percent of their eligible earnings and will be fully vested in the fixed annual contribution after three years of service.
Matching and fixed annual contributions to the Retirement Savings Plan are expensed as incurred and amounted to $20.6 million, $17.9 million and $16.7 million for fiscal years 2021, 2020 and 2019. At September 30, 2021 and 2020, the Retirement Savings Plan held 1.9 percent and 2.2 percent of our outstanding common stock.
11. Stock and Other Compensation Plans
Stock-Based Compensation Plans
Total stock-based compensation cost was $24.1 million, $21.1 million and $23.9 million for the fiscal years ended September 30, 2021, 2020 and 2019. Of this amount, $12.9 million, $11.6 million and $12.8 million was capitalized.
1998 Long-Term Incentive Plan
We have the 1998 Long-Term Incentive Plan (LTIP), which provides a comprehensive, long-term incentive compensation plan providing for discretionary awards of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, time-lapse restricted stock, time-lapse restricted stock units, performance-based restricted stock units and stock units to certain employees and non-employee directors of the Company and our subsidiaries. The objectives of this plan include attracting and retaining the best available personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire common stock.
We are authorized to grant awards up to a maximum cumulative amount of 11.2 million shares of common stock under this plan subject to certain adjustment provisions. As of September 30, 2021, non-qualified stock options, bonus stock, time-lapse restricted stock, time-lapse restricted stock units, performance-based restricted stock units and stock units had been issued under this plan, and 1.1 million shares are available for future issuance.
71
Restricted Stock Units Award Grants
As noted above, the LTIP provides for discretionary awards of restricted stock units to help attract, retain and reward employees of Atmos Energy and its subsidiaries. Certain of these awards vest based upon the passage of time and other awards vest based upon the passage of time and the achievement of specified performance targets. The fair value of the awards granted is based on the market price of our stock at the date of grant. We estimate forfeitures using our historical forfeiture rate. The associated expense is recognized ratably over the vesting period. We use authorized and unissued shares to meet share requirements for the vesting of restricted stock units.
Employees who are granted time-lapse restricted stock units under our LTIP have a nonforfeitable right to dividend equivalents that are paid at the same rate and at the same time at which they are paid on shares of stock without restrictions. Time-lapse restricted stock units contain only a service condition that the employee recipients render continuous services to the Company for a period of three years from the date of grant, except for accelerated vesting in the event of death, disability, change of control of the Company or termination without cause (with certain exceptions). There are no performance conditions required to be met for employees to be vested in time-lapse restricted stock units.
Employees who are granted performance-based restricted stock units under our LTIP have a forfeitable right to dividend equivalents that accrue at the same rate at which they are paid on shares of stock without restrictions. Dividend equivalents on the performance-based restricted stock units are paid either in cash or in the form of shares upon the vesting of the award. Performance-based restricted stock units contain a service condition that the employee recipients render continuous services to the Company for a period of three years from the beginning of the applicable three-year performance period, except for accelerated vesting in the event of death, disability, change of control of the Company or termination without cause (with certain exceptions) and a performance condition based on a cumulative earnings per share target amount.
The following summarizes information regarding the restricted stock units granted under the plan during the fiscal years ended September 30, 2021, 2020 and 2019:
| 2021 | 2020 | 2019 | |||||||||||||||||||||||||||||||||
| Number of Restricted Units | Weighted Average Grant-Date Fair Value | Number of Restricted Units | Weighted Average Grant-Date Fair Value | Number of Restricted Units | Weighted Average Grant-Date Fair Value | ||||||||||||||||||||||||||||||
| Nonvested at beginning of year | 443,279 | $ | 99.28 | 503,072 | $ | 91.66 | 538,592 | $ | 80.91 | ||||||||||||||||||||||||||
| Granted | 223,954 | 102.68 | 199,985 | 102.34 | 241,472 | 98.25 | |||||||||||||||||||||||||||||
| Vested | (271,435) | 97.44 | (242,975) | 85.66 | (269,347) | 76.71 | |||||||||||||||||||||||||||||
| Forfeited | (17,671) | 101.48 | (16,803) | 96.87 | (7,645) | 86.37 | |||||||||||||||||||||||||||||
| Nonvested at end of year | 378,127 | $ | 102.45 | 443,279 | $ | 99.28 | 503,072 | $ | 91.66 | ||||||||||||||||||||||||||
As of September 30, 2021, there was $13.8 million of total unrecognized compensation cost related to nonvested restricted stock units granted under the LTIP. That cost is expected to be recognized over a weighted average period of 1.7 years. The fair value of restricted stock vested during the fiscal years ended September 30, 2021, 2020 and 2019 was $26.3 million, $20.7 million and $20.5 million.
Other Plans
Direct Stock Purchase Plan
We maintain a Direct Stock Purchase Plan, open to all investors, which allows participants to have all or part of their cash dividends paid quarterly in additional shares of our common stock. The minimum initial investment required to join the plan is $1,250. Direct Stock Purchase Plan participants may purchase additional shares of our common stock as often as weekly with voluntary cash payments of at least $25, up to an annual maximum of $100,000.
Equity Incentive and Deferred Compensation Plan for Non-Employee Directors
We have an Equity Incentive and Deferred Compensation Plan for Non–Employee Directors, which provides non-employee directors of Atmos Energy with the opportunity to defer receipt, until retirement, of compensation for services rendered to the Company and invest deferred compensation into either a cash account or a stock account.
Other Discretionary Compensation Plans
We have an annual incentive program covering substantially all employees to give each employee an opportunity to share in our financial success based on the achievement of key performance measures considered critical to achieving business
72
objectives for a given year with minimum and maximum thresholds. The Company must meet the minimum threshold for the plan to be funded and distributed to employees. These performance measures may include earnings growth objectives, improved cash flow objectives or crucial customer satisfaction and safety results. We monitor progress towards the achievement of the performance measures throughout the year and record accruals based upon the expected payout using the best estimates available at the time the accrual is recorded. During the last several fiscal years, we have used earnings per share as our sole performance measure.
12. Details of Selected Financial Statement Captions
The following tables provide additional information regarding the composition of certain financial statement captions.
Balance Sheet
Accounts receivable
Accounts receivable was comprised of the following at September 30, 2021 and 2020:
| September 30 | |||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Billed accounts receivable | $ | 218,219 | $ | 140,259 | |||||||
| Unbilled revenue | 97,417 | 80,699 | |||||||||
| Contributions in aid of construction receivable | 18,984 | 19,821 | |||||||||
| Insurance receivable | 53,779 | 4,731 | |||||||||
| Other accounts receivable | 19,039 | 15,034 | |||||||||
| Total accounts receivable | 407,438 | 260,544 | |||||||||
| Less: allowance for uncollectible accounts | (64,471) | (29,949) | |||||||||
| Net accounts receivable | $ | 342,967 | $ | 230,595 | |||||||
Other current assets
Other current assets as of September 30, 2021 and 2020 were comprised of the following accounts.
| September 30 | |||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Deferred gas costs | $ | 66,395 | $ | 40,593 | |||||||
Winter Storm Uri incremental costs (1) | 2,011,719 | — | |||||||||
| Prepaid expenses | 48,766 | 40,340 | |||||||||
| Materials and supplies | 15,581 | 6,829 | |||||||||
| Assets from risk management activities | 55,073 | 5,687 | |||||||||
| Other | 3,375 | 14,456 | |||||||||
| Total | $ | 2,200,909 | $ | 107,905 | |||||||
(1) Includes $2,003.7 million of gas purchases and $8.0 million of carrying costs that were deferred pursuant to regulatory orders. See Note 9 to the consolidated financial statements for additional details.
73
Property, plant and equipment
Property, plant and equipment was comprised of the following as of September 30, 2021 and 2020:
| September 30 | |||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Storage plant | $ | 539,972 | $ | 530,985 | |||||||
| Transmission plant | 3,725,347 | 3,459,765 | |||||||||
| Distribution plant | 12,085,654 | 10,680,495 | |||||||||
| General plant | 868,962 | 829,624 | |||||||||
| Intangible plant | 38,612 | 38,297 | |||||||||
| 17,258,547 | 15,539,166 | ||||||||||
| Construction in progress | 626,551 | 418,055 | |||||||||
| 17,885,098 | 15,957,221 | ||||||||||
| Less: accumulated depreciation and amortization | (2,821,128) | (2,601,874) | |||||||||
Net property, plant and equipment (1) | $ | 15,063,970 | $ | 13,355,347 | |||||||
(1) Net property, plant and equipment includes plant acquisition adjustments of $(28.5) million and $(37.8) million at September 30, 2021 and 2020.
Deferred charges and other assets
Deferred charges and other assets as of September 30, 2021 and 2020 were comprised of the following accounts.
| September 30 | |||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Marketable securities | $ | 108,071 | $ | 103,952 | |||||||
| Regulatory assets (See Note 2) | 351,843 | 371,707 | |||||||||
| Operating lease right of use assets (See Note 6) | 222,446 | 227,146 | |||||||||
Winter Storm Uri incremental costs (1) | 89,009 | — | |||||||||
| Assets from risk management activities | 175,613 | 74,991 | |||||||||
| Other | 27,738 | 23,374 | |||||||||
| Total | $ | 974,720 | $ | 801,170 | |||||||
(1) Includes $76.7 million of gas purchases and $12.3 million of carrying costs that were deferred pursuant to regulatory orders. See Note 9 to the consolidated financial statements for additional details.
74
Accounts payable and accrued liabilities
Accounts payable and accrued liabilities as of September 30, 2021 and 2020 were comprised of the following accounts.
| September 30 | |||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Trade accounts payable | $ | 224,873 | $ | 141,075 | |||||||
| Accrued gas payable | 100,699 | 42,054 | |||||||||
| Accrued liabilities | 97,650 | 52,646 | |||||||||
| Total | $ | 423,222 | $ | 235,775 | |||||||
Other current liabilities
Other current liabilities as of September 30, 2021 and 2020 were comprised of the following accounts.
| September 30 | |||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Customer credit balances and deposits | $ | 49,722 | $ | 56,485 | |||||||
| Accrued employee costs | 50,517 | 48,057 | |||||||||
| Deferred gas costs | 52,553 | 19,985 | |||||||||
| Operating lease liabilities (See Note 6) | 37,688 | 35,716 | |||||||||
| Accrued interest | 55,164 | 53,554 | |||||||||
| Liabilities from risk management activities | 5,269 | 2,015 | |||||||||
| Taxes payable | 160,986 | 148,292 | |||||||||
| Pension and postretirement liabilities | 4,863 | 29,609 | |||||||||
| Regulatory cost of removal obligation | 72,823 | 73,908 | |||||||||
| APT annual adjustment mechanism | 22,694 | 43,893 | |||||||||
| Regulatory excess deferred taxes (See Note 14) | 155,857 | 20,887 | |||||||||
| Other | 18,545 | 14,060 | |||||||||
| Total | $ | 686,681 | $ | 546,461 | |||||||
Deferred credits and other liabilities
Deferred credits and other liabilities as of September 30, 2021 and 2020 were comprised of the following accounts.
| September 30 | |||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Pension and post retirement liabilities | $ | 185,617 | $ | 337,303 | |||||||
| Operating lease liabilities (See Note 6) | 194,745 | 201,071 | |||||||||
| Customer advances for construction | 9,879 | 10,060 | |||||||||
| Other regulatory liabilities (See Note 2) | 75,506 | 17,838 | |||||||||
| Asset retirement obligation | 18,373 | 20,348 | |||||||||
| APT annual adjustment mechanism | 8,416 | 13,486 | |||||||||
| Unrecognized tax benefits | 32,792 | 30,921 | |||||||||
| Other | 12,161 | 11,101 | |||||||||
| Total | $ | 537,489 | $ | 642,128 | |||||||
75
Statement of Comprehensive Income
Other non-operating income (expense)
Other non-operating income (expense) for the fiscal years ended September 30, 2021, 2020 and 2019 were comprised of the following accounts.
| Year Ended September 30 | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Equity component of AFUDC | $ | 32,749 | $ | 23,493 | $ | 11,165 | |||||||||||
| Performance-based rate program | 6,362 | 6,771 | 6,737 | ||||||||||||||
| Pension and other postretirement non-service credit (cost) | (19,238) | (3,189) | 3,016 | ||||||||||||||
| Interest income | 2,144 | 2,932 | 4,160 | ||||||||||||||
| Community support spending | (14,460) | (11,728) | (4,771) | ||||||||||||||
| Miscellaneous | (9,702) | (11,108) | (12,903) | ||||||||||||||
| Total | $ | (2,145) | $ | 7,171 | $ | 7,404 | |||||||||||
Statement of Cash Flows
Supplemental disclosures of cash flow information for the fiscal years ended September 30, 2021, 2020 and 2019 were as follows:
| Year Ended September 30 | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| (In thousands) | |||||||||||||||||
Cash Paid (Received) During The Period For: | |||||||||||||||||
Interest (1) | $ | 207,555 | $ | 194,993 | $ | 184,852 | |||||||||||
| Income taxes | $ | 8,199 | $ | (3,071) | $ | 11,467 | |||||||||||
Non-Cash Transactions: | |||||||||||||||||
| Capital expenditures included in current liabilities | $ | 184,786 | $ | 113,365 | $ | 149,993 | |||||||||||
(1) Cash paid during the period for interest, net of amounts capitalized was $81.9 million, $82.3 million and $91.3 million for the fiscal years ended September 30, 2021, 2020 and 2019.
13. Commitments and Contingencies
Litigation and Environmental Matters
In the normal course of business, we are subject to various legal and regulatory proceedings. For such matters, we record liabilities when they are considered probable and estimable, based on currently available facts, our historical experience and our estimates of the ultimate outcome or resolution of the liability in the future. While the outcome of these proceedings is uncertain and a loss in excess of the amount we have accrued is possible though not reasonably estimable, it is the opinion of management that any amounts exceeding the accruals will not have a material adverse impact on our financial position, results of operations or cash flows.
The National Transportation Safety Board (NTSB) held a public meeting on January 12, 2021 to determine the probable cause of the incident that occurred at a Dallas, Texas residence on February 23, 2018 that resulted in one fatality and injuries to four other residents. At the meeting, the Board deliberated and voted on proposed findings of fact, a probable cause statement, and safety recommendations. On February 8, 2021, the NTSB issued its final report that included an Executive Summary, Findings, Probable Cause, and Recommendations. Also on February 8, 2021, safety recommendations letters were distributed to recommendation recipients, including Atmos Energy. Atmos Energy timely provided a written response on May 7, 2021. Following the release of the NTSB’s final report, the Railroad Commission of Texas (RRC) completed its safety evaluation related to the same incident finding four alleged violations and initiated an enforcement proceeding to pursue administrative penalties totaling $1.6 million. Atmos Energy is working with the RRC to resolve the alleged violations and satisfy the administrative penalties.
76
The NTSB is investigating a worksite accident that occurred in Farmersville, Texas on June 28, 2021 that resulted in two fatalities and injuries to two others. Together with the Railroad Commission of Texas and the Pipeline and Hazardous Materials Safety Administration, Atmos Energy is a party to the investigation and in that capacity is working closely with all parties to help determine the cause of this incident. On July 16, 2021 and July 28, 2021, two civil actions were filed in Dallas, Texas against Atmos Energy and one of its contractors in response to the accident.
We are a party to various other litigation and environmental-related matters or claims that have arisen in the ordinary course of our business. While the results of such litigation and response actions to such environmental-related matters or claims cannot be predicted with certainty, we continue to believe the final outcome of such litigation and matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.
Purchase Commitments
Our distribution divisions maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract.
Our Mid-Tex Division also maintains a limited number of long-term supply contracts to ensure a reliable source of gas for our customers in its service area, which obligate it to purchase specified volumes at prices under contracts indexed to natural gas trading hubs or fixed price contracts. At September 30, 2021, we were committed to purchase 32.4 Bcf within one year and 12.9 Bcf within to three years under indexed contracts. At September 30, 2021, we were committed to purchase 11.9 Bcf within one year under fixed price contracts ranging from $1.86 to $7.03 per Mcf. Purchases under these contracts totaled $149.4 million, $58.5 million and $50.8 million for 2021, 2020 and 2019.
Rate Regulatory Proceedings
As of September 30, 2021, routine rate regulatory proceedings were in progress in some of our service areas, which are discussed in further detail above in the Business — Ratemaking Activity section.
14. Income Taxes
Income Tax Expense
The components of income tax expense from continuing operations for 2021, 2020 and 2019 were as follows:
| 2021 | 2020 | 2019 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Current | |||||||||||||||||
| Federal | $ | — | $ | — | $ | — | |||||||||||
| State | 252 | 14,193 | 8,412 | ||||||||||||||
| Deferred | |||||||||||||||||
| Federal | 128,867 | 143,039 | 113,331 | ||||||||||||||
State (1) | 24,617 | (11,879) | 17,160 | ||||||||||||||
| Income tax expense | $ | 153,736 | $ | 145,353 | $ | 138,903 | |||||||||||
(1) Includes a non-cash income tax benefit of $21.0 million in fiscal 2020 resulting from the remeasurement of the rate at which state deferred taxes will reverse in the future as discussed below.
Reconciliations of the provision for income taxes computed at the statutory rate to the reported provisions for income taxes from continuing operations for 2021, 2020 and 2019 are set forth below:
77
| 2021 | 2020 | 2019 | |||||||||||||||
| (In thousands) | |||||||||||||||||
Tax at statutory rate (1) | $ | 172,053 | $ | 156,827 | $ | 136,565 | |||||||||||
| Common stock dividends deductible for tax reporting | (1,372) | (1,419) | (1,460) | ||||||||||||||
| State taxes (net of federal benefit) | 19,647 | 22,791 | 20,202 | ||||||||||||||
| Amortization of excess deferred taxes | (45,382) | (16,125) | (14,085) | ||||||||||||||
| Remeasurement due to state deferred tax rate change | — | (20,962) | — | ||||||||||||||
| Other, net | 8,790 | 4,241 | (2,319) | ||||||||||||||
| Income tax expense | $ | 153,736 | $ | 145,353 | $ | 138,903 | |||||||||||
(1) Tax expense is calculated at the statutory federal income tax rate of 21.0% for the years ended September 30, 2021, 2020 and 2019.
Deferred income taxes reflect the tax effect of differences between the basis of assets and liabilities for book and tax purposes. The tax effect of temporary differences that gave rise to significant components of the deferred tax liabilities and deferred tax assets at September 30, 2021 and 2020 are presented below:
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Deferred tax assets: | |||||||||||
| Employee benefit plans | $ | 64,316 | $ | 66,991 | |||||||
| Interest rate swaps | — | 16,719 | |||||||||
| Net operating loss carryforwards | 911,424 | 476,507 | |||||||||
| Charitable and other credit carryforwards | 7,712 | 8,712 | |||||||||
| Regulatory excess deferred tax | 148,200 | 161,565 | |||||||||
| Lease asset | 52,138 | 53,118 | |||||||||
| Other | 33,591 | 20,424 | |||||||||
| Total deferred tax assets | 1,217,381 | 804,036 | |||||||||
| Valuation allowance | (663) | (1,102) | |||||||||
| Net deferred tax assets | 1,216,718 | 802,934 | |||||||||
| Deferred tax liabilities: | |||||||||||
Difference in net book value and net tax value of assets (1) | (2,258,264) | (2,138,966) | |||||||||
| Gas cost adjustments | (26,413) | (23,209) | |||||||||
| Winter Storm Uri regulatory asset | (471,025) | — | |||||||||
| Lease liability | (52,138) | (53,118) | |||||||||
| Rate deferral adjustment | (47,445) | (21,945) | |||||||||
| Interest rate agreements | (20,156) | — | |||||||||
| Other | (47,086) | (22,265) | |||||||||
| Total deferred tax liabilities | (2,922,527) | (2,259,503) | |||||||||
| Net deferred tax liabilities | $ | (1,705,809) | $ | (1,456,569) | |||||||
| Deferred credits for rate regulated entities | $ | 4,181 | $ | 2,537 | |||||||
(1) Includes $129.0 million of deferred tax liability related to goodwill as of September 30, 2021 and 2020.
We deduct our purchased gas costs for federal income tax purposes in the period they are paid. As a result of impacts from Winter Storm Uri, we recorded a $471.0 million (tax effected) increase in our deferred tax liability and an increase in our net operating loss carryforward as of September 30, 2021. At September 30, 2021, we had $850.2 million (tax effected) of federal net operating loss carryforwards. The federal net operating loss carryforwards are available to offset future taxable income. Net operating loss carryforwards incurred prior to December 22, 2017 will begin to expire in 2029. The Company also has $6.0 million in charitable contribution carryforwards to offset future taxable income. The Company’s charitable contribution carryforwards expiration period begins in fiscal 2022.
78
The Company also has $61.2 million (tax effected) of state net operating loss carryforwards (net of $16.2 million of federal effects) and $1.7 million of state tax credits carryforwards (net of $0.5 million of federal effects). Depending on the jurisdiction in which the state net operating loss was generated, the carryforwards expiration period begins in fiscal 2023.
We believe it is more likely than not that the benefit from certain state net operating loss carryforwards and state credit carryforwards will not be realized. Due to the uncertainty of realizing a benefit from the deferred tax asset recorded for the carryforwards, a valuation allowance of $0.7 million was established for the year ended September 30, 2021.
At September 30, 2021, we had recorded liabilities associated with unrecognized tax benefits totaling $32.8 million. The following table reconciles the beginning and ending balance of our unrecognized tax benefits:
| 2021 | 2020 | 2019 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Unrecognized tax benefits - beginning balance | $ | 30,921 | $ | 27,716 | $ | 26,203 | |||||||||||
| Increase (decrease) resulting from prior period tax positions | 671 | (26) | (923) | ||||||||||||||
| Increase resulting from current period tax positions | 1,200 | 3,231 | 2,436 | ||||||||||||||
| Unrecognized tax benefits - ending balance | 32,792 | 30,921 | 27,716 | ||||||||||||||
| Less: deferred federal and state income tax benefits | (6,886) | (6,493) | (5,820) | ||||||||||||||
Total unrecognized tax benefits that, if recognized, would impact the effective income tax rate as of the end of the year | $ | 25,906 | $ | 24,428 | $ | 21,896 | |||||||||||
The Company recognizes interest accrued related to unrecognized tax benefits in interest expense and penalties included within interest charges in our consolidated statements of comprehensive income. During the years ended September 30, 2021, 2020 and 2019, the Company recognized approximately $1.4 million, $0.7 million and $2.2 million in interest and penalties. The Company had approximately $10.4 million, $8.2 million and $7.9 million for the payment of interest and penalties accrued at September 30, 2021, 2020 and 2019.
We file income tax returns in the U.S. federal jurisdiction as well as in various states where we have operations. We have concluded substantially all U.S. federal income tax matters through fiscal year 2009 and concluded substantially all Texas income tax matters through fiscal year 2010.
Regulatory Excess Deferred Taxes
Regulatory excess net deferred taxes represent changes in our net deferred tax liability related to our cost of service ratemaking due to the enactment of the Tax Cuts and Jobs Act of 2017 (the TCJA) and a Kansas legislative change enacted in fiscal 2020. As of September 30, 2021 and September 30, 2020, $155.9 million and $20.9 million is recorded in other current liabilities. This amount has increased during fiscal 2021 due to regulatory approvals received during the fiscal year that shortened the refund period in certain of our jurisdictions. As a result, our effective income tax rate decreased to 18.8% for the fiscal year ended September 30, 2021. Our effective income tax rate in the prior year period was 19.5%, which reflected the income tax benefit recognized upon enactment of the new Kansas legislation.
Currently, the regulatory excess net deferred tax liability is being returned over various periods. Of this amount, $532.3 million, is being returned to customers over 35 - 60 months. An additional $115.3 million is being returned to customers on a provisional basis over 15 - 69 years until our regulators establish the final refund periods. The refund of the remaining $12.1 million will be addressed in our next rate proceeding.
15. Financial Instruments
We currently use financial instruments to mitigate commodity price risk and interest rate risk. Our financial instruments do not contain any credit-risk-related or other contingent features that could cause accelerated payments when our financial instruments are in net liability positions.
Commodity Risk Management Activities
Our purchased gas cost adjustment mechanisms essentially insulate our distribution segment from commodity price risk; however, our customers are exposed to the effects of volatile natural gas prices. We manage this exposure through a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season.
79
In jurisdictions where we are permitted to mitigate commodity price risk through financial instruments, the relevant regulatory authorities may establish the level of heating season gas purchases that can be hedged. Our distribution gas supply department is responsible for executing this segment’s commodity risk management activities in conformity with regulatory requirements. Historically, if the regulatory authority does not establish this level, we seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2020-2021 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 39 percent, or approximately 15.8 Bcf of the winter flowing gas requirements at a weighted average cost of approximately $2.86 per Mcf. We have not designated these financial instruments as hedges for accounting purposes.
Interest Rate Risk Management Activities
We manage interest rate risk by periodically entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.
In 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 senior unsecured notes. These swaps were designated as cash flow hedges at the time the agreements were executed.
In September 2021, we settled forward starting interest rate swaps with a notional amount of $600 million and received $62.2 million. On October 1, 2021, the notes were issued as planned.
Quantitative Disclosures Related to Financial Instruments
The following tables present detailed information concerning the impact of financial instruments on our consolidated balance sheet and statements of comprehensive income.
As of September 30, 2021, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of September 30, 2021, we had 23,737 MMcf of net long commodity contracts outstanding. These contracts have not been designated as hedges.
Financial Instruments on the Balance Sheet
The following tables present the fair value and balance sheet classification of our financial instruments as of September 30, 2021 and 2020. As discussed in Note 2 to the consolidated financial statements, we report our financial instruments as risk management assets and liabilities, each of which is classified as current or noncurrent based upon the anticipated settlement date of the underlying financial instrument. The gross amounts of recognized assets and liabilities are netted within our consolidated balance sheets to the extent that we have netting arrangements with the counterparties. However, as of September 30, 2021 and 2020, no gross amounts and no cash collateral were netted within our consolidated balance sheet.
| Balance Sheet Location | Assets | Liabilities | |||||||||||||||
| (In thousands) | |||||||||||||||||
| September 30, 2021 | |||||||||||||||||
| Designated As Hedges: | |||||||||||||||||
| Interest rate contracts | Deferred charges and other assets / Deferred credits and other liabilities | $ | 169,469 | $ | — | ||||||||||||
| Total | 169,469 | — | |||||||||||||||
| Not Designated As Hedges: | |||||||||||||||||
| Commodity contracts | Other current assets / Other current liabilities | 55,073 | (5,269) | ||||||||||||||
| Commodity contracts | Deferred charges and other assets / Deferred credits and other liabilities | 6,144 | — | ||||||||||||||
| Total | 61,217 | (5,269) | |||||||||||||||
| Gross / Net Financial Instruments | $ | 230,686 | $ | (5,269) | |||||||||||||
80
| Balance Sheet Location | Assets | Liabilities | |||||||||||||||
| (In thousands) | |||||||||||||||||
| September 30, 2020 | |||||||||||||||||
| Designated As Hedges: | |||||||||||||||||
| Interest rate contracts | Deferred charges and other assets / Deferred credits and other liabilities | $ | 73,055 | $ | — | ||||||||||||
| Total | 73,055 | — | |||||||||||||||
| Not Designated As Hedges: | |||||||||||||||||
| Commodity contracts | Other current assets / Other current liabilities | 5,687 | (2,015) | ||||||||||||||
| Commodity contracts | Deferred charges and other assets / Deferred credits and other liabilities | 1,936 | — | ||||||||||||||
| Total | 7,623 | (2,015) | |||||||||||||||
| Gross / Net Financial Instruments | $ | 80,678 | $ | (2,015) | |||||||||||||
Impact of Financial Instruments on the Statement of Comprehensive Income
Cash Flow Hedges
As discussed above, our distribution segment has interest rate agreements, which we designate as cash flow hedges at the time the agreements were executed. The net loss on settled interest rate agreements reclassified from AOCI into interest charges on our consolidated statements of comprehensive income for the years ended September 30, 2021, 2020 and 2019 was $5.9 million, $5.5 million and $3.9 million.
The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the years ended September 30, 2021 and 2020.
| Fiscal Year Ended September 30 | |||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Increase in fair value: | |||||||||||
| Interest rate agreements | $ | 123,017 | $ | 53,241 | |||||||
| Recognition of losses in earnings due to settlements: | |||||||||||
| Interest rate agreements | 4,566 | 3,647 | |||||||||
| Total other comprehensive income from hedging, net of tax | $ | 127,583 | $ | 56,888 | |||||||
Deferred gains (losses) recorded in AOCI associated with our interest rate agreements are recognized in earnings as they are amortized over the terms of the underlying debt instruments. As of September 30, 2021, we had $61.7 million of net realized losses in AOCI associated with our interest rate agreements. The following amounts, net of deferred taxes, represent the expected recognition in earnings of the deferred net losses recorded in AOCI associated with our interest rate agreements, based upon the fair values of these agreements at the date of settlement. The remaining amortization periods for these settled amounts extend through fiscal 2052. However, the table below does not include the expected recognition in earnings of our outstanding interest rate agreements as those financial instruments have not yet settled.
81
| Interest Rate Agreements | |||||
| (In thousands) | |||||
| 2022 | $ | (2,959) | |||
| 2023 | (2,959) | ||||
| 2024 | (2,959) | ||||
| 2025 | (2,959) | ||||
| 2026 | (2,959) | ||||
| Thereafter | (46,919) | ||||
| Total | $ | (61,714) | |||
Financial Instruments Not Designated as Hedges
As discussed above, commodity contracts which are used in our distribution segment are not designated as hedges. However, there is no earnings impact on our distribution segment as a result of the use of these financial instruments because the gains and losses arising from the use of these financial instruments are recognized in the consolidated statements of comprehensive income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue. Accordingly, the impact of these financial instruments is excluded from this presentation.
16. Fair Value Measurements
We report certain assets and liabilities at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We record cash and cash equivalents, accounts receivable and accounts payable at carrying value, which substantially approximates fair value due to the short-term nature of these assets and liabilities. For other financial assets and liabilities, we primarily use quoted market prices and other observable market pricing information to minimize the use of unobservable pricing inputs in our measurements when determining fair value. The methods used to determine fair value for our assets and liabilities are fully described in Note 2 to the consolidated financial statements.
Fair value measurements also apply to the valuation of our pension and post-retirement plan assets. The fair value of these assets is presented in Note 10 to the consolidated financial statements.
82
Quantitative Disclosures
Financial Instruments
The classification of our fair value measurements requires judgment regarding the degree to which market data are observable or corroborated by observable market data. The following tables summarize, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2021 and 2020. As required under authoritative accounting literature, assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.
| Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2)(1) | Significant Other Unobservable Inputs (Level 3) | Netting and Cash Collateral | September 30, 2021 | |||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Financial instruments | $ | — | $ | 230,686 | $ | — | $ | — | $ | 230,686 | |||||||||||||||||||
| Debt and equity securities | |||||||||||||||||||||||||||||
| Registered investment companies | 35,175 | — | — | — | 35,175 | ||||||||||||||||||||||||
| Bond mutual funds | 34,298 | — | — | — | 34,298 | ||||||||||||||||||||||||
Bonds (2) | — | 35,655 | — | — | 35,655 | ||||||||||||||||||||||||
| Money market funds | — | 2,943 | — | — | 2,943 | ||||||||||||||||||||||||
| Total debt and equity securities | 69,473 | 38,598 | — | — | 108,071 | ||||||||||||||||||||||||
| Total assets | $ | 69,473 | $ | 269,284 | $ | — | $ | — | $ | 338,757 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Financial instruments | $ | — | $ | 5,269 | $ | — | $ | — | $ | 5,269 | |||||||||||||||||||
| Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2)(1) | Significant Other Unobservable Inputs (Level 3) | Netting and Cash Collateral | September 30, 2020 | |||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Financial instruments | $ | — | $ | 80,678 | $ | — | $ | — | $ | 80,678 | |||||||||||||||||||
| Debt and equity securities | |||||||||||||||||||||||||||||
| Registered investment companies | 37,831 | — | — | — | 37,831 | ||||||||||||||||||||||||
| Bond mutual funds | 29,166 | — | — | — | 29,166 | ||||||||||||||||||||||||
Bonds (2) | — | 32,900 | — | — | 32,900 | ||||||||||||||||||||||||
| Money market funds | — | 4,055 | — | — | 4,055 | ||||||||||||||||||||||||
| Total debt and equity securities | 66,997 | 36,955 | — | — | 103,952 | ||||||||||||||||||||||||
| Total assets | $ | 66,997 | $ | 117,633 | $ | — | $ | — | $ | 184,630 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Financial instruments | $ | — | $ | 2,015 | $ | — | $ | — | $ | 2,015 | |||||||||||||||||||
(1)Our Level 2 measurements consist of over-the-counter options and swaps, which are valued using a market-based approach in which observable market prices are adjusted for criteria specific to each instrument, such as the strike price, notional amount or basis differences, municipal and corporate bonds, which are valued based on the most recent available quoted market prices and money market funds which are valued at cost.
(2)Our investments in bonds are considered available-for-sale debt securities in accordance with current accounting guidance.
Debt and equity securities are comprised of our available-for-sale debt securities and our equity securities. As described further in Note 2 to the consolidated financial statements, we adopted ASC 326 effective October 1, 2020. In accordance with the new guidance, we evaluate the performance of our available-for-sale debt securities on an investment by investment basis for impairment, taking into consideration the investment’s purpose, volatility, current returns and any intent to sell the security. As of September 30, 2021, no allowance for credit losses was recorded for our available-for-sale debt securities. At
83
September 30, 2021 and 2020, the amortized cost of our available-for-sale debt securities was $35.6 million and $32.6 million. At September 30, 2021 we maintained investments in bonds that have contractual maturity dates ranging from October 2021 through September 2024.
Other Fair Value Measures
In addition to the financial instruments above, we have several financial and nonfinancial assets and liabilities subject to fair value measures. These financial assets and liabilities include cash and cash equivalents, accounts receivable, accounts payable, finance leases and debt, which are recorded at carrying value. The nonfinancial assets and liabilities include asset retirement obligations and pension and post-retirement plan assets. For cash and cash equivalents, accounts receivable, accounts payable and finance leases we consider carrying value to materially approximate fair value due to the short-term nature of these assets and liabilities.
Our long-term debt is recorded at carrying value. The fair value of our long-term debt, excluding finance leases, is determined using third party market value quotations, which are considered Level 1 fair value measurements for debt instruments with a recent, observable trade or Level 2 fair value measurements for debt instruments where fair value is determined using the most recent available quoted market price. The following table presents the carrying value and fair value of our long-term debt, excluding finances leases, debt issuance costs and original issue premium or discount, as of September 30, 2021:
| September 30, 2021 | |||||
| (In thousands) | |||||
| Carrying Amount | $ | 7,360,000 | |||
| Fair Value | $ | 8,086,136 | |||
17. Concentration of Credit Risk
Credit risk is the risk of financial loss to us if a customer fails to perform its contractual obligations. We engage in transactions for the purchase and sale of products and services with major companies in the energy industry and with industrial, commercial, residential and municipal energy consumers. These transactions principally occur in the southern and midwestern regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable for the distribution segment is mitigated by the large number of individual customers and the diversity in our customer base. The credit risk for our pipeline and storage segment is not significant.
84
| ITEM 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure. | ||||
None.
| ITEM 9A. | Controls and Procedures. | ||||
Management’s Evaluation of Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the Company’s disclosure controls and procedures, as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act). Based on this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2021 to provide reasonable assurance that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified by the SEC’s rules and forms, including a reasonable level of assurance that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f), in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we evaluated the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (COSO). Based on our evaluation under the framework in Internal Control-Integrated Framework issued by COSO and applicable Securities and Exchange Commission rules, our management concluded that our internal control over financial reporting was effective as of September 30, 2021, in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Ernst & Young LLP has issued its report on the effectiveness of the Company’s internal control over financial reporting. That report appears below.
| /s/ JOHN K. AKERS | /s/ CHRISTOPHER T. FORSYTHE | |||||||
| John K. Akers | Christopher T. Forsythe | |||||||
| President, Chief Executive Officer and Director | Senior Vice President and Chief Financial Officer | |||||||
| November 12, 2021 | ||||||||
85
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Atmos Energy Corporation
Opinion on Internal Control Over Financial Reporting
We have audited Atmos Energy Corporation’s internal control over financial reporting as of September 30, 2021, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Atmos Energy Corporation (the Company) maintained, in all material respects, effective internal control over financial reporting as of September 30, 2021, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2021 consolidated financial statements of the Company and our report dated November 12, 2021 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Dallas, Texas
November 12, 2021
86
Changes in Internal Control over Financial Reporting
We did not make any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Act) during the fourth quarter of the fiscal year ended September 30, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
| ITEM 9B. | Other Information. | ||||
Not applicable.
PART III
| ITEM 10. | Directors, Executive Officers and Corporate Governance. | ||||
Information regarding directors is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 9, 2022. Information regarding executive officers is reported below:
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
The following table sets forth certain information as of September 30, 2021, regarding the executive officers of the Company. It is followed by a brief description of the business experience of each executive officer.
| Name | Age | Years of Service | Office Currently Held | |||||||||||||||||
| John K. Akers | 58 | 30 | President, Chief Executive Officer and Director | |||||||||||||||||
| Christopher T. Forsythe | 50 | 18 | Senior Vice President and Chief Financial Officer | |||||||||||||||||
| David J. Park | 50 | 27 | Senior Vice President, Utility Operations | |||||||||||||||||
| Karen E. Hartsfield | 51 | 6 | Senior Vice President, General Counsel and Corporate Secretary | |||||||||||||||||
| John M. Robbins | 51 | 8 | Senior Vice President, Human Resources | |||||||||||||||||
John K. (Kevin) Akers was named President and Chief Executive Officer and was appointed to the Board of Directors effective October 1, 2019. Mr. Akers joined the company in 1991. Mr. Akers assumed increased responsibilities over time and was named President of the Mississippi Division in 2002. He was later named President of the Kentucky/Mid-States Division in May 2007, a position he held until December 2016. Effective January 1, 2017, Mr. Akers was named Senior Vice President, Safety and Enterprise Services and was responsible for customer service, facilities management, safety and supply chain management. In November 2018, Mr. Akers was named Executive Vice President and assumed oversight responsibility for APT.
Christopher T. Forsythe was named Senior Vice President and Chief Financial Officer effective February 1, 2017. Mr. Forsythe joined the Company in June 2003 and prior to this promotion, served as the Company's Vice President and Controller from May 2009 through January 2017. Prior to joining Atmos Energy, Mr. Forsythe worked in public accounting for 10 years.
David J. Park was named Senior Vice President of Utility Operations, effective January 1, 2017. In this role, Mr. Park is responsible for the operations of Atmos Energy’s six utility divisions as well as gas supply. Prior to this promotion, Mr. Park served as the President of the West Texas Division from July 2012 to December 2016. Mr. Park also served as Vice President of Rates and Regulatory Affairs in the Mid-Tex Division and previously held positions in Engineering and Public Affairs. Mr. Park's years of service include 10 years at a company acquired by Atmos Energy in 2004.
Karen E. Hartsfield was named Senior Vice President, General Counsel and Corporate Secretary of Atmos Energy, effective August 7, 2017. Ms. Hartsfield joined the Company in June 2015, after having served in private practice for 19 years, most recently as Managing Partner of Jackson Lewis LLP in its Dallas office from July 2013 to June 2015. Prior to joining Jackson Lewis as a partner in January 2009, Ms. Hartsfield was a partner with Baker Botts LLP in Dallas.
John M. (Matt) Robbins was named Senior Vice President, Human Resources, effective January 1, 2017. Mr. Robbins joined the Company in May 2013 and prior to this promotion served as Vice President, Human Resources from February 2015 to December 2016. Before joining Atmos Energy, Mr. Robbins had over 20 years of experience in human resources.
Identification of the members of the Audit Committee of the Board of Directors as well as the Board of Directors’ determination as to whether one or more audit committee financial experts are serving on the Audit Committee of the Board of
87
Directors is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 9, 2022.
The Company has adopted a code of ethics for its principal executive officer, principal financial officer and principal accounting officer. Such code of ethics is represented by the Company’s Code of Conduct, which is applicable to all directors, officers and employees of the Company, including the Company’s principal executive officer, principal financial officer and principal accounting officer. A copy of the Company's Code of Conduct is posted on the Company's website at www.atmosenergy.com on the "Reports" page under "Corporate Responsibility." In addition, any amendment to or waiver granted from a provision of the Company's Code of Conduct will be posted on the Company's website also on the "Reports" page under "Corporate Responsibility."
| ITEM 11. | Executive Compensation. | ||||
Information on executive compensation is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 9, 2022, under the captions "Director Compensation," "Compensation Discussion and Analysis," "Other Executive Compensation Matters" and "Named Executive Officer Compensation."
| ITEM 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. | ||||
Security ownership of certain beneficial owners and of management is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 9, 2022, under the heading "Beneficial Ownership of Common Stock." Information concerning our equity compensation plans is provided in Part II, Item 5, “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities”, of this Annual Report on Form 10-K.
| ITEM 13. | Certain Relationships and Related Transactions, and Director Independence. | ||||
Information on certain relationships and related transactions as well as director independence is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 9, 2022, under the heading "Corporate Governance and Other Board Matters," and "Proposal One – Election of Directors."
| ITEM 14. | Principal Accountant Fees and Services. | ||||
Information on our principal accountant’s fees and services is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 9, 2022, under the heading "Proposal Two – Ratification of Appointment of Independent Registered Public Accounting Firm."
PART IV
| ITEM 15. | Exhibits and Financial Statement Schedules. | ||||
(a) 1. and 2. Financial statements and financial statement schedules.
The financial statements listed in the Index to Financial Statements in Part II, Item 8 are filed as part of this Form 10-K. All financial statement schedules are omitted because the required information is not present, or not present in amounts sufficient to require submission of the schedule or because the information required is included in the financial statements and accompanying notes thereto.
3. Exhibits
| Exhibit Number | Description | Page Number or Incorporation by Reference to | ||||||||||||
| Articles of Incorporation and Bylaws | ||||||||||||||
| 3.1 | Restated Articles of Incorporation of Atmos Energy Corporation - Texas (As Amended Effective February 3, 2010) | |||||||||||||
88
| 3.2 | Restated Articles of Incorporation of Atmos Energy Corporation - Virginia (As Amended Effective February 3, 2010) | |||||||||||||
| 3.3 | Amended and Restated Bylaws of Atmos Energy Corporation (as of February 5, 2019) | |||||||||||||
| Instruments Defining Rights of Security Holders, Including Indentures | ||||||||||||||
| 4.1(a) | Specimen Common Stock Certificate (Atmos Energy Corporation) | |||||||||||||
| 4.1(b) | ||||||||||||||
| 4.2 | Indenture dated as of November 15, 1995 between United Cities Gas Company and Bank of America Illinois, Trustee | |||||||||||||
| 4.3 | Indenture dated as of July 15, 1998 between Atmos Energy Corporation and U.S. Bank Trust National Association, Trustee | |||||||||||||
| 4.4 | Indenture dated as of May 22, 2001 between Atmos Energy Corporation and SunTrust Bank, Trustee | |||||||||||||
| 4.5 | Indenture dated as of March 26, 2009 between Atmos Energy Corporation and U.S. Bank National Corporation, Trustee | |||||||||||||
| 4.6(a) | Debenture Certificate for the 6 3/4% Debentures due 2028 | |||||||||||||
| 4.6(b) | Global Security for the 5.95% Senior Notes due 2034 | |||||||||||||
| 4.6(c) | Officers' Certificate dated June 10, 2011 | |||||||||||||
| 4.6(d) | Global Security for the 5.5% Senior Notes due 2041 | |||||||||||||
| 4.6(e) | Officers' Certificate dated January 11, 2013 | |||||||||||||
| 4.6(f) | Global Security for the 4.15% Senior Notes due 2043 | |||||||||||||
| 4.6(g) | Officers' Certificate dated October 15, 2014 | |||||||||||||
| 4.6(h) | Global Security for the 4.125% Senior Notes due 2044 | |||||||||||||
| 4.6(i) | Officers' Certificate dated June 8, 2017 | |||||||||||||
| 4.6(j) | Officers' Certificate dated October 4, 2018 | |||||||||||||
| 4.6(k) | Global Security for the 4.300% Senior Notes due 2048 | |||||||||||||
| 4.6(l) | Global Security for the 4.300% Senior Notes due 2048 | |||||||||||||
| 4.6(m) | Officers' Certificate dated March 4, 2019 | |||||||||||||
| 4.6(n) | Global Security for the 4.125% Senior Notes due 2049 | |||||||||||||
89
| 4.6(o) | Officers' Certificate dated October 2, 2019 | |||||||||||||
| 4.6(p) | Global Security for the 2.625% Senior Notes due 2029 | |||||||||||||
| 4.6(q) | Global Security for the 3.375% Senior Notes due 2049 | |||||||||||||
| 4.6(r) | Officers' Certificate dated October 1, 2020 | |||||||||||||
| 4.6(s) | Global Security for the 1.500% Senior Notes due 2031 | |||||||||||||
| 4.6(t) | Global Security for the 1.500% Senior Notes due 2031 | |||||||||||||
| 4.6(u) | Fixed Rate Notes Officers' Certificate dated March 9, 2021 | |||||||||||||
| 4.6(v) | Floating Rate Notes Officers' Certificate dated March 9, 2021 | |||||||||||||
| 4.6(w) | Global Security for the 0.625% Senior Notes due 2023 | |||||||||||||
| 4.6(x) | Global Security for the 0.625% Senior Notes due 2023 | |||||||||||||
| 4.6(y) | Global Security for the 0.625% Senior Notes due 2023 | |||||||||||||
| 4.6(z) | Global Security for the Floating Rate Senior Notes due 2023 | |||||||||||||
| 4.6(aa) | Global Security for the Floating Rate Senior Notes due 2023 | |||||||||||||
| 4.6(bb) | Global Security for the Floating Rate Senior Notes due 2023 | |||||||||||||
| 4.6(cc) | Officers' Certificate dated October 1, 2021 | |||||||||||||
| 4.6(dd) | Global Security for the 2.850% Senior Notes due 2052 | |||||||||||||
| 4.6(ee) | Global Security for the 2.850% Senior Notes due 2052 | |||||||||||||
| Material Contracts | ||||||||||||||
| 10.1 | Revolving Credit Agreement, dated as of March 31, 2021, among Atmos Energy Corporation, Crédit Agricole Corporate and Investment Bank, as the Administrative Agent, the agents, arrangers and bookrunners named therein, and the lenders named therein | |||||||||||||
| 10.2 | Revolving Credit Agreement, dated as of March 31, 2021, among Atmos Energy Corporation, Crédit Agricole Corporate and Investment Bank, as the Administrative Agent, the agents, arrangers and bookrunners named therein, and the lenders named therein | |||||||||||||
| 10.3 | Term Loan Agreement, dated as of April 9, 2020, among Atmos Energy Corporation, Credit Agricole Corporate and Investment Bank, as the Administrative Agent, Canadian Imperial Bank of Commerce, New York Branch, as Syndication Agent, Credit Agricole Corporate and Investment Bank and Canadian Imperial Bank of Commerce, New York Branch, as Joint Lead Arrangers and Joint-Bookrunners, and the lenders named therein | |||||||||||||
90
| 10.4(a) | Equity Distribution Agreement, dated as of February 12, 2020, among Atmos Energy Corporation and the Managers and Forward Purchasers named in Schedule A thereto | |||||||||||||
| 10.4(b) | Form of Master Forward Sale Confirmation | |||||||||||||
| 10.5(a) | Equity Distribution Agreement, dated as of June 29, 2021, among Atmos Energy Corporation and the Managers and Forward Purchasers named in Schedule A thereto | |||||||||||||
| 10.5(b) | Form of Master Forward Sale Confirmation | |||||||||||||
| Executive Compensation Plans and Arrangements | ||||||||||||||
| 10.6(a)* | Form of Atmos Energy Corporation Change in Control Severance Agreement - Tier I | |||||||||||||
| 10.6(b)* | Form of Atmos Energy Corporation Change in Control Severance Agreement - Tier II | |||||||||||||
| 10.7(a)* | Atmos Energy Corporation Executive Retiree Life Plan | |||||||||||||
| 10.7(b)* | Amendment No. 1 to the Atmos Energy Corporation Executive Retiree Life Plan | |||||||||||||
| 10.8* | Atmos Energy Corporation Annual Incentive Plan for Management (as amended and restated August 3, 2021) | |||||||||||||
| 10.9(a)* | Atmos Energy Corporation Supplemental Executive Benefits Plan, Amended and Restated in its Entirety August 7, 2007 | |||||||||||||
| 10.9(b)* | Form of Individual Trust Agreement for the Supplemental Executive Benefits Plan | |||||||||||||
| 10.10(a)* | Atmos Energy Corporation Supplemental Executive Retirement Plan (As Amended and Restated, Effective as of January 1, 2016) | |||||||||||||
| 10.10(b)* | Atmos Energy Corporation Performance-Based Supplemental Executive Benefits Plan Trust Agreement, Effective Date December 1, 2000 | |||||||||||||
| 10.11* | Atmos Energy Corporation Account Balance Supplemental Executive Retirement Plan (As Amended and Restated, Effective as of January 1, 2016) | |||||||||||||
| 10.12(a)* | Mini-Med/Dental Benefit Extension Agreement dated October 1, 1994 | |||||||||||||
| 10.12(b)* | Amendment No. 1 to Mini-Med/Dental Benefit Extension Agreement dated August 14, 2001 | |||||||||||||
| 10.12(c)* | Amendment No. 2 to Mini-Med/Dental Benefit Extension Agreement dated December 31, 2002 | |||||||||||||
| 10.13* | Atmos Energy Corporation Equity Incentive and Deferred Compensation Plan for Non-Employee Directors, Amended and Restated as of January 1, 2012 | |||||||||||||
91
| 10.14(a)* | Atmos Energy Corporation 1998 Long-Term Incentive Plan (as amended and restated November 6, 2019) | |||||||||||||
| 10.14(b)* | Form of Award Agreement of Time-Lapse Restricted Stock Units under the Atmos Energy Corporation 1998 Long-Term Incentive Plan | |||||||||||||
| 10.14(c)* | Form of Award Agreement of Performance-Based Restricted Stock Units under the Atmos Energy Corporation 1998 Long-Term Incentive Plan | |||||||||||||
| 10.14(d)* | Form of Non-Employee Director Award Agreement of Time-Lapse Restricted Stock Units Under the Atmos Energy Corporation 1998 Long-Term Incentive Plan | |||||||||||||
| 10.14(e)* | Form of Non-Employee Director Award Agreement of Stock Unit Awards Under The Atmos Energy Corporation 1998 Long-Term Incentive Plan | |||||||||||||
| Other Exhibits, as indicated | ||||||||||||||
| 21 | ||||||||||||||
| 23.1 | ||||||||||||||
| 24 | Power of Attorney | Signature page of Form 10-K for fiscal year ended September 30, 2021 | ||||||||||||
| 31 | ||||||||||||||
| 32 | ||||||||||||||
| Interactive Data File | ||||||||||||||
| 101.INS | XBRL Instance Document - the Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document | |||||||||||||
| 101.SCH | Inline XBRL Taxonomy Extension Schema | |||||||||||||
| 101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase | |||||||||||||
| 101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase | |||||||||||||
| 101.LAB | Inline XBRL Taxonomy Extension Labels Linkbase | |||||||||||||
| 101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase | |||||||||||||
| 104 | Cover Page Interactive Data File - the cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the Inline XBRL document | |||||||||||||
| * | This exhibit constitutes a "management contract or compensatory plan, contract, or arrangement." | ||||
| ** | These certifications pursuant to 18 U.S.C. Section 1350 by the Company’s Chief Executive Officer and Chief Financial Officer, furnished as Exhibit 32 to this Annual Report on Form 10-K, will not be deemed to be filed with the Securities and Exchange Commission or incorporated by reference into any filing by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates such certifications by reference. | ||||
| ITEM 16. | Form 10-K Summary. | ||||
Not applicable.
92
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| ATMOS ENERGY CORPORATION | ||||||||||||||
| (Registrant) | ||||||||||||||
| By: | /s/ CHRISTOPHER T. FORSYTHE | |||||||||||||
Christopher T. Forsythe Senior Vice President and Chief Financial Officer | ||||||||||||||
Date: November 12, 2021
93
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints John K. Akers and Christopher T. Forsythe, or either of them acting alone or together, as his true and lawful attorney-in-fact and agent with full power to act alone, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
94
| /s/ KIM R. COCKLIN | Chairman of the Board | November 12, 2021 | ||||||||||||
| Kim R. Cocklin | ||||||||||||||
| /s/ JOHN K. AKERS | President, Chief Executive Officer and Director | November 12, 2021 | ||||||||||||
| John K. Akers | ||||||||||||||
| /s/ CHRISTOPHER T. FORSYTHE | Senior Vice President and Chief Financial Officer | November 12, 2021 | ||||||||||||
| Christopher T. Forsythe | ||||||||||||||
| /s/ RICHARD M. THOMAS | Vice President and Controller (Principal Accounting Officer) | November 12, 2021 | ||||||||||||
| Richard M. Thomas | ||||||||||||||
| /s/ ROBERT W. BEST | Director | November 12, 2021 | ||||||||||||
| Robert W. Best | ||||||||||||||
| /s/ KELLY H. COMPTON | Director | November 12, 2021 | ||||||||||||
| Kelly H. Compton | ||||||||||||||
| /s/ SEAN DONOHUE | Director | November 12, 2021 | ||||||||||||
| Sean Donohue | ||||||||||||||
| /s/ RAFAEL G. GARZA | Director | November 12, 2021 | ||||||||||||
| Rafael G. Garza | ||||||||||||||
| /s/ RICHARD K. GORDON | Director | November 12, 2021 | ||||||||||||
| Richard K. Gordon | ||||||||||||||
| /s/ ROBERT C. GRABLE | Director | November 12, 2021 | ||||||||||||
| Robert C. Grable | ||||||||||||||
| /s/ NANCY K. QUINN | Director | November 12, 2021 | ||||||||||||
| Nancy K. Quinn | ||||||||||||||
| /s/ RICHARD A. SAMPSON | Director | November 12, 2021 | ||||||||||||
| Richard A. Sampson | ||||||||||||||
| /s/ STEPHEN R. SPRINGER | Director | November 12, 2021 | ||||||||||||
| Stephen R. Springer | ||||||||||||||
| /s/ DIANA J. WALTERS | Director | November 12, 2021 | ||||||||||||
| Diana J. Walters | ||||||||||||||
| /s/ RICHARD WARE II | Director | November 12, 2021 | ||||||||||||
| Richard Ware II | ||||||||||||||
| /s/ FRANK YOHO | Director | November 12, 2021 | ||||||||||||
| Frank Yoho | ||||||||||||||
95