Enhanced Investments - Financial Portal

Published: 2023-02-23 16:45:11 ET

<<< go to OGS company page

ogs-20221231

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2022.

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

For the transition period from __________ to __________.

Commission file number 001-36108

ONE Gas, Inc.

(Exact name of registrant as specified in its charter)


Oklahoma		46-3561936
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

15 East Fifth Street
Tulsa,	OK	74103
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code (918) 947-7000

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

Title of each class

Trading Symbol

Name of exchange on which registered

Common Stock, par value $0.01 per share

OGS

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 ☒ 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 ☒

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 ☒ 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 ☒ 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 the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 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. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

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

The aggregate market value of the equity securities held by nonaffiliates based on the closing trade price of the registrant on June 30, 2022, was $4.2 billion.

On February 17, 2023, we had 55,350,277 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the definitive proxy statement to be delivered to shareholders in connection with the Annual Meeting of Shareholders to be held May 25, 2023, are incorporated by reference in Part III.

ONE Gas, Inc.

2022 ANNUAL REPORT


Part I.		Page No.
Item 1.	Business	6
Item 1A.	Risk Factors	12
Item 1B.	Unresolved Staff Comments	16
Item 2.	Properties	16
Item 3.	Legal Proceedings	16
Item 4.	Mine Safety Disclosures	16
Part II.
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	17
Item 6.	[Reserved]	18
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	37
Item 8.	Financial Statements and Supplementary Data	39
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	79
Item 9A.	Controls and Procedures	79
Item 9B.	Other Information	79
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	79
Part III.
Item 10.	Directors, Executive Officers and Corporate Governance	79
Item 11.	Executive Compensation	80
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	80
Item 13.	Certain Relationships and Related Transactions, and Director Independence	81
Item 14.	Principal Accountant Fees and Services	81
Part IV.
Item 15.	Exhibits, Financial Statement Schedules	82
Item 16.	Form 10-K Summary	87
Signatures		88

As used in this Annual Report, references to “we,” “our,” “us” or the “Company” refer to ONE Gas, Inc., an Oklahoma corporation, and its predecessors and subsidiaries, unless the context indicates otherwise.

GLOSSARY

The abbreviations, acronyms and industry terminology used in this Annual Report are defined as follows:


AAO			Accounting Authority Order
ADIT			Accumulated deferred income taxes
AFUDC			Allowance for funds used during construction
Annual Report			Annual Report on Form 10-K for the year ended December 31, 2022
ASC			Accounting Standards Codification
ASU			Accounting Standards Update
Bcf			Billion cubic feet
CAA			Federal Clean Air Act, as amended
CERCLA			Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CFTC			Commodities Futures Trading Commission
CISA			Cybersecurity and Infrastructure Security Agency
Clean Water Act			Federal Water Pollution Control Amendments of 1972, as amended
CNG			Compressed natural gas
Code			Internal Revenue Code of 1986, as amended
COSA			Cost-of-Service Adjustment
COVID-19			Coronavirus Disease 2019
DART			Days Away, Restricted or Transferred Incident Rate; calculated by multiplying the total number of recordable injuries and illnesses, or one or more restricted days that resulted in an employee transferring to a different job within the company by 200,000, and then dividing that number by the total number of hours worked by all employees
DHS			United States Department of Homeland Security
DOT			United States Department of Transportation
Dth			Dekatherm
ECP			The ONE Gas, Inc. Amended and Restated Equity Compensation Plan (2018)
EDIT			Excess accumulated deferred income taxes resulting from a decrease in enacted tax rates
EPA			United States Environmental Protection Agency
EPS			Earnings per share
ERT			Emergency Response Time; calculated as the time between the creation of an emergency order and the arrival of a first company responder to the scene expressed as the percentage of emergency orders with a response time of 30 minutes or less
ESG			Environmental, social and governance
ESPP			The ONE Gas, Inc. Amended and Restated Employee Stock Purchase Plan
Exchange Act			Securities Exchange Act of 1934, as amended
FASB			Financial Accounting Standards Board
FERC			Federal Energy Regulatory Commission
GAAP			Accounting principles generally accepted in the United States of America
GRIP			Texas Gas Reliability Infrastructure Program
GSRS			Gas System Reliability Surcharge
HCA(s)			High consequence area(s)
HDD			Heating degree day is a measure designed to reflect the demand for energy needed for heating based on the extent to which the daily average temperature falls below a reference temperature for which no heating is required, usually 65 degrees Fahrenheit
IRA of 2022			Inflation Reduction Act of 2022
IT			Information technology
KCC			Kansas Corporation Commission
KDHE			Kansas Department of Health and Environment
KGSS-I			Kansas Gas Service Securitization I, L.L.C.
LDC			Local distribution company
LIBOR			London Interbank Offered Rate
MAOP(s)			Maximum allowable operating pressure(s)
MGP			Manufactured gas plant
MMcf			Million cubic feet


Moody’s			Moody’s Investors Service, Inc.
NPRM			Notice of proposed rulemaking
NYSE			New York Stock Exchange
OCC			Oklahoma Corporation Commission
ODFA			Oklahoma Development Finance Authority
ONE Gas			ONE Gas, Inc.
ONE Gas 2021 Term Loan Facility			ONE Gas’ $2.5 billion two-year unsecured term loan facility, dated February 22, 2021, which terminated on March 11, 2021
ONE Gas 364-day Credit Agreement			ONE Gas’ $250 million 364-day revolving credit agreement, dated April 7, 2020, which terminated on March 16, 2021
ONE Gas Credit Agreement			ONE Gas’ $1.0 billion revolving credit agreement, as amended
OSHA			Occupational Safety and Health Administration
PBRC			Performance-Based Rate Change
PHMSA			United States Department of Transportation Pipeline and Hazardous Materials Safety Administration
Pipeline Safety, Regulatory Certainty and Job Creation Act			Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, as amended
PIPES Act			Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020
PPE			Personal protective equipment
PVIR			Preventable Vehicle Incident Rate; calculated by multiplying the number of total preventable vehicle incidents by 1,000,000 and then dividing that number by the total number of business use miles driven
Quarterly Report(s)			Quarterly Report(s) on Form 10-Q
RNG			Renewable natural gas
ROE			Return on equity calculated consistent with utility ratemaking principles in each jurisdiction in which we operate
RRC			Railroad Commission of Texas
S&P			Standard and Poor’s Rating Services
SEC			Securities and Exchange Commission
Securities Act			Securities Act of 1933, as amended
Securitized Utility Tariff Bonds			Series 2022-A Senior Secured Securitized Utility Tariff Bonds, Tranche A
Securitized Utility Tariff Property			Securitized Utility Tariff Property as defined in the financing order issued by the KCC in August 2022
Senior Notes			ONE Gas’ registered notes consisting of $300 million of 3.61 percent senior notes due February 2024, $473 million of 1.10 percent senior notes due March 2024, $300 million of 2.00 percent senior notes due May 2030, $300 million of 4.25 percent senior notes due September 2032, $600 million of 4.66 percent senior notes due February 2044 and $400 million of 4.50 percent senior notes due November 2048
SOFR			Secured Overnight Financing Rate administered by the Federal Reserve Bank of New York
TCEQ			Texas Commission on Environmental Quality
TPFA			Texas Public Finance Authority
TSA			United States Department of Homeland Security’s Transportation Security Administration
TRIR			Total Recordable Incident Rate; calculated by multiplying the number of recordable cases by 200,000, and then dividing that number by the number of hours worked by all employees
WNA			Weather normalization adjustment(s)
XBRL			eXtensible Business Reporting Language

The statements in this Annual Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may include words such as “will,” “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled,” “likely” and other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that such expectations and assumptions will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements are

described under Part I, Item 1A, Risk Factors, and Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation, Forward-Looking Statements, in this Annual Report.

PART I.

ITEM 1. BUSINESS

OUR BUSINESS

ONE Gas, Inc. is incorporated under the laws of the state of Oklahoma. Our common stock is listed on the NYSE under the trading symbol “OGS,” and is included in the S&P MidCap 400 Index. We are a 100-percent regulated natural gas distribution utility, headquartered in Tulsa, Oklahoma, and one of the largest publicly traded natural gas utilities in the United States. We are the successor to the company founded in 1906 as Oklahoma Natural Gas Company, which became ONEOK, Inc. (NYSE: OKE) in 1980. On January 31, 2014, ONE Gas officially separated from ONEOK, Inc.

We provide natural gas distribution services to approximately 2.3 million customers and are the largest natural gas distributor in Oklahoma and Kansas and the third largest in Texas, in terms of customers. We primarily serve residential, commercial and transportation customers in all three states. Our largest natural gas distribution markets in terms of customers are Oklahoma City and Tulsa, Oklahoma; Kansas City, Wichita and Topeka, Kansas; and Austin and El Paso, Texas. Our three divisions, Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, distribute natural gas to approximately 88 percent, 71 percent and 13 percent of the natural gas distribution customers in Oklahoma, Kansas and Texas, respectively.

OUR STRATEGY

Our mission is to deliver natural gas for a better tomorrow. Our business strategy is focused on:

•Safe and Reliable Energy - We are committed, first and foremost, to pursuing a zero-incident safety and 100-percent compliance culture. A significant portion of our capital spending is focused on the safety, integrity and reliability of our natural gas distribution system. We also deploy a variety of operational and damage prevention procedures and technologies to monitor and maintain our natural gas distribution system. Our Company’s focus on safety also extends to protecting our assets and information systems from physical damage and cyber intrusions.

•A High-performing Workforce - Our employees are the foundation of our Company. Our success begins with a values-driven culture and a commitment to engaging people to do their best work in an inclusive environment.

•Capital Demand Growth - Through capital investments, we meet growing customer demand, support economic development, and manage our system investments for the long-term.

•Clean Energy Solutions - Our assets are essential to a clean energy future. We are focused on reducing our emissions and supporting our customers’ emission reduction efforts.

•Serving Customers - We provide reliable and affordable energy to our customers by efficiently managing our resources and leveraging technology solutions to enhance operational efficiency. Our energy efficiency and education programs help our customers invest in higher efficiency appliances and reduce energy usage. For customers needing assistance, we offer payment arrangement options and seek to connect customers to social service agencies that provide financial assistance.

REGULATORY OVERVIEW

We are subject to regulation and oversight of the state and local regulatory authorities of the territories in which we operate. Rates and charges for natural gas distribution services are established by the OCC for Oklahoma Natural Gas and by the KCC for Kansas Gas Service. Rates and charges in the incorporated cities of our service areas in Texas are established by those cities, which have primary jurisdiction for their respective service areas. Rates and charges in the unincorporated areas of our service territory in Texas are established by the RRC. All appellate matters in Texas are subject to regulatory oversight by the RRC. These regulatory authorities have the responsibility of ensuring that the utilities under their jurisdiction provide safe and reliable service at a reasonable cost, while providing utilities the opportunity to earn a fair and reasonable return on their investments.

Generally, our rates and charges are established in rate case proceedings. Regulatory authorities may also approve mechanisms that allow for adjustments between rate cases for investments made or specific costs incurred. Due to the nature of the regulatory process, there is an inherent lag between the time that we make investments or incur additional costs and the setting of new rates and/or charges to recover those investments or costs. Additionally, we are not allowed recovery of certain costs we incur.

The following provides additional detail on the regulatory mechanisms in the jurisdictions we serve.

Oklahoma - Oklahoma Natural Gas currently operates under a PBRC mechanism, which provides for streamlined annual rate reviews between rate cases to adjust rates for incremental capital investment and changes in revenue and allowed expenses. Under this mechanism, we have an authorized ROE of 9.4 percent, with a 100 basis point dead-band of 8.9 to 9.9 percent. If our achieved ROE is below 8.9 percent, our base rates are increased upon OCC approval to an amount necessary to restore the ROE to 9.4 percent. If our achieved ROE exceeds 9.9 percent, the portion of the earnings that exceeds 9.9 percent is shared with our customers, who receive the benefit of 75 percent of those earnings. We retain the benefit of the remaining 25 percent. Oklahoma Natural Gas is required to make filings pursuant to the PBRC mechanism for the 12 months ended December 31 for each of the years 2021 through 2025. Oklahoma Natural Gas is also required to file a rate case on or before June 30, 2027, based on a test year ending December 31, 2026.

Kansas - Kansas Gas Service files periodic rate cases with the KCC as needed. Between rate cases, Kansas Gas Service adjusts rates through provisions of the GSRS statute. The GSRS statute allows Kansas Gas Service to file for a rate adjustment providing a recovery of and return on qualifying infrastructure investments incurred between rate case filings, including safety-related investments to replace, upgrade or modernize obsolete facilities, as well as projects that enhance the integrity of pipeline system components or extend the useful life of such assets. Eligible investments also include expenditures for relocations and physical and cyber security. Filings cannot occur more often than once every 12 months and the rate adjustment cannot increase the monthly charge by more than $0.80 per residential customer per month compared with the most recent GSRS filing. Rate adjustments reflected in the GSRS surcharge may only be collected for 60 months before Kansas Gas Service is required to file a rate case or cease collection of the surcharge. A full rate case may be filed at shorter intervals if desired by either Kansas Gas Service or the KCC.

Texas - Texas Gas Service provides service to customers in various service areas. These service areas are further divided into incorporated cities and unincorporated areas. Periodic rate cases are filed with cities or the RRC, as needed. Between rate cases, Texas Gas Service can adjust rates through annual filings pursuant to the GRIP statute or a COSA filing. In 2022, Texas Gas Service’s customers were aggregated in five service areas. Effective February 2023, three of these service areas were consolidated, reducing the total number of service areas to three.

Annual filings under the GRIP statute allow Texas Gas Service to recover depreciation, taxes, and a return on the annual net increase in investment for a service area. After the fifth anniversary of the effective date of the rate schedules from the first GRIP filing for a service area, Texas Gas Service is required to file a full rate case. A full rate case may be filed at shorter intervals if desired by either Texas Gas Service or the regulator. In 2022, Texas Gas Service made annual GRIP filings for the incorporated cities in two of its service areas and for the unincorporated areas in all five service areas, which combined comprise 91 percent of Texas Gas Service’s customers.

COSA tariffs permit Texas Gas Service to recover depreciation, taxes, and a return on the annual increases in net investment, and adjust rates for annual increases or decreases in certain expenses and revenues. The various COSAs have a cap on the increase in expenses. A full rate case may be filed when desired by Texas Gas Service or the regulatory authority but is not required. Texas Gas Service makes an annual COSA filing for the incorporated cities in one of its service areas, comprising 9 percent of its customers.

Weather normalization - All of our service areas utilize weather normalization mechanisms. These mechanisms are designed to reduce the delivery charge component of customers’ bills for the additional volumes used when actual HDDs exceed normalized HDDs and to increase the delivery charge component of customers’ bills for the reduction in volumes used when actual HDDs are less than normal HDDs. Normal HDDs are established through rate proceedings in each of our jurisdictions.

The following tables provide additional detail on our rate structures and the regulatory mechanisms in each of our jurisdictions:


Division	Jurisdiction	Effective Date of Last Action(1)	Rate Base (millions)	Pre-Tax Rate of Return	Equity Ratio	ROE
Oklahoma Natural Gas (2)	Oklahoma	November 2022	$1,854	8.95%	59%	9.40%
Kansas Gas Service (3)	Kansas	November 2022	$1,261	8.60%	N/A	9.30%
Texas Gas Service (2)	Central-Gulf	June 2022	$617	8.95%	59%	9.50%
	West-North(7)	February 2023	$589	8.91%	60%	9.60%
	Rio Grande Valley	August 2022	$160	8.89%	61%	9.50%

Division

Jurisdiction

Interim Rate Adjustment Mechanism

Interim Capital Recovery

WNA

WNA Effective Dates

Energy Efficiency / Conservation Program

Oklahoma Natural Gas

Oklahoma

PBRC

Yes

November - April

Yes

Kansas Gas Service (3)

Kansas

GSRS

Yes

January - December

Texas Gas Service

Central-Gulf

GRIP

Yes

September - May

Yes

West-North

GRIP

Yes

September - May

Rio Grande Valley

GRIP / COSA

Yes

September - May

Yes

Division

Jurisdiction

Purchased Gas Adjustment(4)

Bad Debt Recovery(5)

Expense Trackers(6)

Oklahoma Natural Gas

Oklahoma

Yes

N/A

Kansas Gas Service (3)

Kansas

Yes

Texas Gas Service

Central-Gulf

Yes

West-North

Yes

Rio Grande Valley

Yes


(1)			Effective date of last approved rate case or interim filing.
(2)			The rate base, authorized ROE, authorized debt/equity ratio and authorized return on equity presented in this table are those from the most recent approved regulatory filing for Oklahoma Natural Gas and Texas Gas Service.
(3)			Kansas Gas Service’s most recent rate case, approved in February 2019, settled without a determination of rate base, ROE, authorized debt/equity ratio and authorized return on equity. This reflects Kansas Gas Service’s estimate of rate base from that rate case adjusted for approved GSRS filings and ROE embedded in the pre-tax carrying charge utilized in its GSRS filing.
(4)			Our purchased gas adjustment mechanisms allow recovery of expenses the Company incurs to purchase, transport, and store natural gas for our customers. These costs are passed on to customers without markup.
(5)			We recover the gas cost portion of bad debts through our various purchased gas adjustment mechanisms.
(6)			Expense trackers include pension and other postemployment benefits costs for Kansas Gas Service and Texas Gas Service, ad-valorem taxes in Kansas and pipeline integrity testing expenses in Texas.
(7)			Effective February 1, 2023, the West Texas, North Texas and Borger/Skellytown service areas were consolidated into the West-North service area.

Our natural gas sales include fixed and variable charges related to the delivery of natural gas and gas costs that are passed through to our customers in accordance with our cost of natural gas regulatory mechanisms. Fixed charges reflect the portion of our natural gas sales attributable to the monthly fixed customer charge component of our rates, which does not fluctuate based on customer usage in each period. Variable charges reflect the portion of our natural gas sales that fluctuate with the volumes delivered and billed and the effects of weather normalization.

For the year ended December 31, 2022, approximately 88 percent, 56 percent, and 69 percent of our revenues from sales customers, excluding the cost of natural gas, were recovered from fixed charges for Oklahoma Natural Gas, Kansas Gas Service, and Texas Gas Service, respectively.

MARKET CONDITIONS AND SEASONALITY

Supply - We purchased 165 Bcf and 164 Bcf of natural gas supply in 2022 and 2021, respectively. Our natural gas supply portfolio consists of contracts with varying terms from a diverse group of suppliers. We award these contracts through competitive-bidding processes to ensure reliable and competitively priced natural gas supply. We acquire our natural gas supply from natural gas processors, marketers and producers.

An objective of our supply-sourcing strategy is to provide value to our customers through reliable, competitively priced and flexible natural gas supply and transportation from multiple production areas and suppliers. This strategy is designed to mitigate

the impact on our supply from physical interruptions, financial difficulties of a single supplier, natural disasters and other unforeseen force majeure events, as well as to ensure that adequate supply is available to meet the variations of customer demand.

We do not anticipate problems with securing natural gas supply to satisfy customer demand; however, if supply shortages were to occur, we have curtailment provisions in our tariffs that allow us to reduce or discontinue natural gas service to large industrial users and to request that residential and commercial customers reduce their natural gas requirements to an amount essential for public health and safety. In addition, during times of critical supply disruptions, curtailments of deliveries to customers with firm contracts may be made in accordance with guidelines established by appropriate federal, state and local regulatory agencies.

Natural gas supply requirements for our sales customers are impacted by weather and economic conditions. Our customers’ usage may also change in response to a variety of factors, including:

•the occurrence of a significant disruption in natural gas supplies, either by itself, or accompanied by higher or lower natural gas prices;

•the availability of more energy-efficient construction methods or home improvements such as installation or replacement of insulated doors and windows, additional or energy efficient insulation and installation or replacement of existing appliances with more efficient appliances; and

•fuel switching from natural gas to other energy alternatives.

In each jurisdiction in which we operate, changes in customer usage are considered in the periodic redesign of our rates.

As of December 31, 2022, we had 57.6 Bcf of natural gas storage capacity under contract with remaining terms ranging from one to ten years and maximum allowable daily withdrawal capacity of approximately 1.7 Bcf. This storage capacity allows us to purchase natural gas during the off-peak season and store it for use in the winter periods. This storage is also needed to support the reliability of gas deliveries during peak demands for natural gas. Approximately 33 percent of our winter natural gas supply needs for our sales customers is expected to be supplied from storage.

In managing our natural gas supply portfolios, we partially mitigate price volatility for our customers using a combination of financial derivatives and natural gas in storage. We have natural gas financial hedging programs that have been authorized by the OCC, KCC and certain jurisdictions in Texas. We do not utilize financial derivatives for speculative purposes, nor do we have trading operations associated with our business.

Demand - See discussions below under Seasonality, Competition and CNG for factors affecting demand for our services.

Seasonality - Natural gas sales to residential and commercial customers are seasonal, as a substantial portion of their natural gas requirements are for heating. Accordingly, the volume of natural gas sales is normally higher during the months of November through March than in other months of the year. The impact on our natural gas sales resulting from weather temperatures that are above or below normal is offset partially through our WNA mechanisms. See the tables above under Regulatory Overview for additional information.

Competition - We encounter competition based on customers’ preference for natural gas, compared with other energy alternatives and their comparative prices. We compete primarily to supply energy for space and water heating, cooking and clothes drying. Significant energy usage competition occurs between natural gas and electricity in the residential and small commercial markets. Customers and builders typically make the decision on the type of equipment, and therefore the energy source, at initial installation, generally locking in the chosen energy source for the life of the equipment. Changes in the competitive position of natural gas relative to electricity and other energy alternatives have the potential to cause a decline in consumption of natural gas or in the number of natural gas customers.

We are subject to competition from other pipelines for our large industrial and commercial customers. Under our transportation tariffs, qualifying industrial and commercial customers are able to purchase their natural gas supply from the provider of their choice and contract with us to transport it for a fee. A portion of the transportation services that we provide are at negotiated rates that are below the maximum approved transportation tariff rates. Reduced-rate transportation service may be negotiated when a competitive pipeline is in close proximity or another viable energy option is available to the customer.

CNG - In meeting demand for CNG for motor vehicle transportation, particularly from fleet operators who value its lower greenhouse gas emissions and operating fuel costs relative to gasoline- or diesel-powered vehicles, we supply natural gas to CNG fueling stations. We deploy capital to connect our system to CNG stations built and operated by third parties. As of December 31, 2022, we supply 147 fueling stations, 36 of which we operate in conjunction with our own fleets. Of the 111 remaining stations, 66 are retail and 45 are private stations. We transported approximately 2.8 million Dth to CNG stations each year in 2022 and 2021.

Alternative Fuels – RNG and hydrogen technologies offer potential opportunities to secure new gas supply sources that could be transported through our pipelines. Our evaluation of these technologies and opportunities includes: (1) establishing interconnection guidelines for delivery of alternative fuels to our system, (2) working directly with developers and end-use customers to identify potential alternative fuel supply projects, (3) analyzing pipeline system integrity and gas supply implications, including sourcing opportunities, related to hydrogen use in our system, (4) partnering with industry groups to identify opportunities for hydrogen blending and utilization, and (5) evaluating the opportunity to reduce greenhouse gas emissions through the use of alternative fuels.

ENVIRONMENTAL AND SAFETY MATTERS

See Note 17 of the Notes to Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report for information regarding environmental and safety matters.

HUMAN CAPITAL

We intentionally foster an inclusive work culture, where all viewpoints are welcome, to develop an engaged and high-performing workforce and an environment where top talent wants to work.

Employment - We employed approximately 3,800 people at February 1, 2023, including approximately 700 people at Kansas Gas Service who are subject to collective bargaining agreements. The following table sets forth our contracts with collective bargaining units at February 1, 2023:

Union

Approximate Employees

Contract Expires

The United Steelworkers

400

May 31, 2025

International Brotherhood of Electrical Workers

300

June 30, 2024

We recognize that employees are a key stakeholder group for the success of our business. Therefore, we perform an annual survey to monitor and assess employee engagement.

Workplace Health and Safety - Safety is our number one core value. We are committed to pursuing a zero-incident safety culture, which can reduce risk, enhance productivity and build a strong reputation in the communities in which we operate. Our success is reliant on training and development, performance management and shared responsibility that focuses on engagement and ensures our employees know what is expected to keep themselves, their co-workers, our customers and communities safe. To reinforce our commitment to the safety and well-being of our co-workers, customers and communities, our short-term incentive compensation program includes four operational measures, TRIR, DART, PVIR and ERT. These measures focus on the importance of personal injury prevention, reducing the severity of injuries, safe driving, and public safety. The following table sets forth our performance for the periods indicated:


	Years Ended December 31,
Operational measure	2022	2021	2020
TRIR	1.37	0.96	1.02
DART	0.22	0.22	0.28
PVIR	1.84	2.10	1.76
ERT	62.7%	62.7%	64.5%

TRIR, DART and PVIR are personal safety metrics tracked by the American Gas Association. We regularly rank in the top quartile for similar-sized LDCs for these metrics.

As part of our culture of safety, we continue to closely monitor the COVID-19 pandemic and have maintained many of the precautions put in place in 2020 to allow us to continue to provide safe, reliable service while protecting our co-workers, customers, and communities.

We also are committed to a supportive culture of physical, financial, emotional and social wellness for employees. We provide health and wellness programs to support and inspire our employees to make healthy personal and professional lifestyle choices.

Inclusion and Diversity - Our core values include inclusion and diversity, and we believe in equity and the value and voice of every employee. As part of our commitment, we have and continue to consider inclusion and diversity implications in our recruiting process, Company training, and Company performance monitoring. For example, we monitor our workforce diversity statistics across roles and seniority levels. Additionally, we make available conscious inclusion training to all employees.

We have an Inclusion and Diversity Council, which is chaired by our Chief Executive Officer, and includes five employees serving as permanent members, and 16 employees serving as rotating members with three-year terms. The Inclusion and Diversity Council provides governance and guidance for implementing our strategy and sharing our vision of an inclusive and diverse workforce. In addition, we have employee-led resource groups to provide community and support to our employees based on shared characteristics, interests or experiences.

INFORMATION ABOUT OUR EXECUTIVE OFFICERS

All executive officers are elected annually by our Board of Directors and each serves until such person resigns, is removed or is otherwise disqualified to serve or until such officer’s successor is duly elected. Our executive officers listed below include the officers who have been designated by our Board of Directors as our Section 16 officers.

Name

Age*

Business Experience in Past Five Years

Robert S. McAnnally

2021 to present

President, Chief Executive Officer and Director

2020 to 2021

Senior Vice President and Chief Operating Officer

2015 to 2020

Senior Vice President, Operations

Caron A. Lawhorn

2019 to present

Senior Vice President and Chief Financial Officer

2014 to 2019

Senior Vice President, Commercial

Joseph L. McCormick

2014 to present

Senior Vice President, General Counsel and Assistant Secretary

Curtis L. Dinan

2021 to present

Senior Vice President and Chief Operating Officer

2020 to 2021

Senior Vice President and Chief Commercial Officer

2019 to 2020

Senior Vice President, Commercial

2018 to 2019

Senior Vice President and Chief Financial Officer

2014 to 2018

Senior Vice President, Chief Financial Officer and Treasurer

Mark A. Bender

2015 to present

Senior Vice President, Administration and Chief Information Officer

W. Kent Shortridge

2022 to present

Senior Vice President, Operations and Customer Service

2018 to 2022

Managing Vice President, Operations

2014 to 2018

Vice President, Operations - Oklahoma Natural Gas

Brian F. Brumfield

2022 to present

Vice President, Chief Accounting Officer and Controller

2017 to 2022

Controller, Tucson Electric Power/UNS Energy

* As of January 1, 2023

No family relationship exists between any of the executive officers, nor is there any arrangement or understanding between any executive officer and any other person pursuant to which the officer was selected.

AVAILABLE INFORMATION

We make available, free of charge, on our website (www.onegas.com) our Annual Reports, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act. Such materials are available as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC, which also makes these materials available on its website (www.sec.gov). Our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Certificate of Incorporation, bylaws, the written charters of our Audit Committee, Executive Compensation Committee, Corporate Governance Committee and Executive Committee and our ESG Report are also available on our website, and copies of these documents are available upon request.

In addition to filings with the SEC and materials posted on our website, we also use social media platforms as channels of information distribution to reach investors and other stakeholders. Information contained on our website and posted on or disseminated through our social media accounts is not incorporated by reference into this report.

ITEM 1A. RISK FACTORS

Our investors should consider the following risks that could affect us and our business. Although we believe we have discussed the key factors, our investors need to be aware that other risks may prove to be important in the future. New risks may emerge at any time, and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors should carefully consider the following discussion of risks and the other information included or incorporated by reference in this Annual Report, including Forward-Looking Statements, which are included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

OPERATIONAL RISKS

Our business is subject to operational hazards and unforeseen interruptions that could materially and adversely affect our business and for which we may not be insured adequately.

We are subject to all the risks and hazards typically associated with the natural gas distribution business that could affect the public safety and reliability of our distribution system. Operating risks include, but are not limited to, leaks, accidents, pipeline ruptures and the breakdown or failure of equipment or processes. Other operational hazards and unforeseen interruptions include adverse weather conditions, accidents, explosions, fires, the collision of equipment or vehicles with our pipeline facilities and catastrophic events, such as severe weather events, hurricanes, thunderstorms, tornadoes, sustained extreme temperatures, earthquakes, floods, acts of terrorism, pandemics and other health crises, or other similar events beyond our control. Climate change could cause these catastrophic events to become more severe or more frequent. It is also possible that our facilities, or those of our counterparties or service providers, could be direct targets or indirect casualties of an act of terrorism, including cyber-attacks. These issues 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.

Our general liability, cyber, and property insurance policies for many of these hazards and risks are subject to certain limits, deductibles, and policy exclusions. The insurance proceeds received for any loss of, or any damage to, any of our systems or facilities or to third parties may not be sufficient to restore the total loss or damage. Further, the proceeds of any such insurance may not be received in a timely manner. The occurrence of any of the foregoing could have a material adverse effect on our financial condition, results of operations and cash flows.

We may be unable to attract and retain management and professional and technical employees, or experience workforce disruptions due to strikes or work stoppages by our unionized employees, which could adversely impact our operations, earnings, and cash flows.

Our ability to implement our business strategy, satisfy our regulatory requirements, and serve our customers is dependent upon our ability to continue to recruit and employ a skilled, agile, diverse, and engaged workforce consisting of talented and experienced managers, professional and technical employees. The competition for talent has become increasingly intense and we may experience increased employee turnover due to a tightening labor market. If we are unable to recruit and retain an appropriately qualified workforce, we could encounter operating challenges primarily due to a loss of institutional knowledge and expertise, 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, increased safety compliance issues, or cost of contract labor. Additionally, approximately 19 percent of our employees are represented by collective-bargaining units under

collective-bargaining agreements. Disputes over the agreements or failure to timely and effectively renegotiate new agreements upon their expiration could have a negative effect on our business, financial condition and results of operations or result in a work stoppage. Any future work stoppage could, depending on the breadth and the length of the work stoppage, have a material adverse effect on our financial condition, results of operations and cash flows.

The availability of adequate natural gas pipeline transportation and storage capacity and natural gas supply may decrease and impair our ability to meet customers’ natural gas requirements and our financial condition may be adversely affected.

In order to meet customers’ natural gas demands, we rely on and must obtain sufficient natural gas supplies, pipeline transportation and storage capacity from third parties. If we are unable to obtain these, our ability to meet our customers’ natural gas requirements could be impaired. If a substantial disruption to or reduction in natural gas supply, pipeline capacity or storage capacity occurred due to operational failures or disruptions, legislative or regulatory actions, hurricanes, tornadoes, floods, earthquakes, extreme cold weather, acts of terrorism, or cyber-attacks or acts of war, our operations or financial results could be adversely affected.

Our business increasingly relies on technology, the failure of which may adversely affect our financial results and cash flows.

Due to increased technology advances, we have become more reliant on technology to effectively operate our business. We use computer programs and applications to help run our business, including an enterprise resource planning system that integrates data and reporting activities across our Company. Additionally, certain portions of our IT systems and infrastructure are provided or maintained by third-party vendors. The failure of these or other similarly important technologies, the lack of alternative technologies, or our inability to have these technologies supported, updated, expanded, or integrated into other technologies, could hinder our operations, and adversely impact our financial condition and results of operations.

The occurrence of cyber breaches or physical security attacks on our business, or those of third parties, may disrupt or adversely affect our operations or result in the loss or misuse of confidential and proprietary information.

Any cyber breaches or physical security attacks, or threats of such attacks, that affect our IT systems, distribution facilities, customers, suppliers and third-party service providers or any financial data could disrupt normal business operations, expose sensitive information, and/or lead to physical damages that may have a material adverse effect on our business. A severe attack or security breach could adversely affect our business reputation, diminish customer confidence, disrupt operations, subject us to financial liability or increased regulation, increase our costs and expose us to material legal claims and liability which may not be fully covered by insurance, and our business, financial condition, results of operations and cash flows could be adversely affected. As cyber or physical security attacks become more frequent and sophisticated, we could be required to incur increased costs to strengthen our systems or to obtain additional insurance coverage against potential losses. Federal and state regulatory agencies, such as DHS and TSA, are increasingly focused on risks related to physical security and cybersecurity in general and have promulgated more stringent security regulations specifically for certain federal contractors and critical infrastructure sectors, including natural gas distribution. Any failure to comply with such government regulations may have a material adverse effect on our results of operations and financial condition.

We are subject to various risks associated with climate change which could increase our operating costs or restrict our opportunities in new or existing markets, adversely affecting our financial results, growth, cash flows and results of operations.

Climate change may increase the likelihood of extreme weather in our service territory, and our customers’ energy use could increase or decrease depending on the duration and magnitude of any changes. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues and cash flows which are not adequately offset by our WNA mechanisms. Extreme weather conditions in general require increased system resiliency, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of our operating territory could also have an impact on our revenues and cash flows by affecting natural gas prices and the availability of our leased transportation and storage capacity. Weather impacts our operations primarily through severe weather events, including hurricanes, thunderstorms, tornadoes, sustained extreme temperatures, snow and ice storms, earthquakes, floods, or other similar events beyond our control. To the extent the frequency of extreme weather events increases, our costs of providing service and our working capital requirements could increase.

REGULATORY AND LEGISLATIVE RISKS

We are subject to federal, state, and local regulation of the safety of our systems and operations, including pipeline safety, system integrity, and the safety of our employees and facilities that may require significant expenditures or, in the case of noncompliance, substantial fines or penalties.

We are subject to regulation under federal pipeline safety statutes promulgated by PHMSA, DOT, OSHA, and any analogous state regulations. These include safety requirements for the design, construction, operation, and maintenance of pipelines, including transmission and distribution pipelines. Additionally, the workplaces associated with our facilities are subject to the requirements of DOT and OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. Compliance with existing or new laws and regulations may result in increased capital, operating and other costs which may not be recoverable in rates from our customers or may impact materially our competitive position relative to other energy providers. The failure to comply with these laws, regulations and other requirements, or an accident or injury to employees could expose us to civil or criminal liability, enforcement actions, fines, penalties, or injunctive measures that may not be recoverable through our rates and could have a material adverse effect on our business, financial condition, results of operations, cash flows, and reputation.

We are subject to federal, state, and local laws, rules and regulations that could impact our ability to earn a reasonable rate of return on our invested capital and to fully recover our invested capital, operating costs, and natural gas costs.

We are subject to regulatory oversight from various federal, state, and local regulatory authorities, including the OCC, KCC, RRC and various municipalities in Texas. Regulatory actions from these authorities relate to allowed rates of return, rate design and construct, and purchased gas and operating cost recovery. Therefore, our returns are continuously monitored and are subject to challenge for their reasonableness by regulatory authorities or third-party intervenors. Our ability to obtain timely future rate increases depends on regulatory discretion and therefore, there can be no assurance that we will be able to obtain rate increases, fully recover our costs or that our authorized rates of return will continue at the current levels, which could adversely impact our results of operations, financial condition, and cash flows.

In the normal course of business, assets are placed in service before regulatory action is taken, such as filing a rate case or seeking interim recovery under a capital tracking mechanism that could result in an adjustment of our returns. Once we make a regulatory filing, regulatory bodies have the authority to suspend implementation of the new rates while evaluating the filing. Because of this process, we may suffer the negative financial effects of having placed assets in service that do not initially earn our authorized rate of return or may not be allowed recovery on such expenditures at all.

We are subject to environmental regulations and legislation, including those intended to address climate change, which could increase our operating costs, adversely affecting our financial results, growth, cash flows and results of operations.

We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local governmental authorities, including the EPA and any analogous state agencies, relating to protection of the environment, 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. The failure to comply with any laws, regulations, permits and other requirements, or the discovery of presently unknown environmental conditions, could expose us to civil or criminal liability, enforcement actions and regulatory fines and penalties and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

International, federal, regional and/or state legislative and/or regulatory initiatives may attempt to regulate greenhouse gas emissions, including carbon dioxide and methane, as a response to the threat of climate change. Various states and municipalities have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on areas such as greenhouse gas cap and trade programs, carbon taxes, reporting and tracking programs, and restrictions on emissions. Such laws or regulations could impose costs tied to carbon emissions, operational requirements or restrictions, or additional charges to fund energy efficiency activities. They could also incentivize alternative energy sources, impose 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.

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

Our business and operations are subject to regulation by a number of federal agencies, including FERC, CFTC, IRS and various state agencies in Oklahoma, Kansas, and Texas, and we are subject to numerous other federal and state laws and regulations. Future changes to laws, regulations and policies may impair our ability to compete for business or recover costs and could

adversely affect our cash flows, restrict our ability to make capital investments and may cause us to increase debt and take other actions to conserve cash. Any compliance failure related to these laws and regulations may result in fines, penalties or injunctive measures affecting our operating assets. The fines or penalties for noncompliance with laws and regulations may not be recoverable through our rates. Our failure to comply with applicable regulations could result in a material adverse effect on our business, financial condition, results of operations and cash flows.

FINANCIAL, ECONOMIC AND MARKET RISKS

Unfavorable economic and market conditions could adversely affect our financial condition, earnings, cash flows and limit our future growth.

Weakening economic activity in our markets and supply chain disruptions could result in a loss of existing customers, fewer new customers, especially in newly constructed homes and other buildings, or a decline in energy consumption, any of which could adversely affect our revenues or restrict our future growth. These conditions may make it more difficult for customers to pay their natural gas bills, leading to slow collections and higher-than-normal levels of accounts receivable, which in turn could increase our financing requirements and bad debt expense. Customers may also experience difficulties paying their natural gas bills in the instance of severe weather events that result in higher usage and higher natural gas prices, reducing our collections and increasing our financing requirements and bad debt expense, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity, and prospects.

Changes in supply and demand within the natural gas markets, as well as other factors, could cause an increase in the price of natural gas. Market conditions can also lead to short-term price spikes in natural gas prices, such as high demand during periods of extreme cold weather or system constraints at specific delivery locations. An increase in the price of natural gas could cause us to experience a significant increase in short-term or long-term debt because we must pay suppliers for natural gas when purchased.

We cannot predict the timing, severity, or duration of any future economic slowdowns or natural gas market disruptions. Fluctuations and uncertainties in the economy may result in higher interest rates and inflationary pressures on the costs of goods, services, and labor. This could increase our expenses and capital spending and decrease our cash flows if we are not able to recover or recover timely such increased costs from our customers. The foregoing could adversely affect our business, financial condition, results of operations and cash flows.

Our business activities are concentrated in three states.

We provide natural gas distribution services to customers in Oklahoma, Kansas, and Texas. Changes in the regional economies, politics, regulations, regulatory decisions by state and local regulatory authorities, and weather patterns of these states could adversely impact our financial condition, results of operations and cash flows.

The inability to access capital or significant increases in the cost of capital could adversely affect our results of operations, cash flows and financial condition.

Our ability to obtain adequate and cost-effective financing is dependent upon the liquidity of the financial markets, as well as our financial condition and credit ratings. Our long-term debt is currently rated as “investment grade” by both of our rating agencies. We rely upon access to both the short-term and long-term credit and capital markets to satisfy our liquidity requirements. If adverse credit conditions or a downgrade in our ratings outlook 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 a reduction in our credit ratings by one or both of our rating agencies. Such a downgrade could further limit our access to private credit and/or public capital markets and increase our costs of borrowing. Additionally, the inability to access adequate capital or an increase in the cost of capital may require us to conserve cash, prevent or delay us from making capital expenditures, and require us to reduce or eliminate our dividend or other discretionary uses of cash.

Our financing arrangements subject us to various restrictions that could limit our operating flexibility, earnings, and cash flows.

The indentures governing our Senior Notes and our ONE Gas Credit Agreement contain customary covenants that restrict our ability to create or permit certain liens, to consolidate or merge, or to convey, transfer or lease substantially all of our properties and assets. Events beyond our control could impair our ability to satisfy these requirements. As long as our indebtedness remains outstanding, these restrictive covenants could impair our ability to expand or pursue our growth strategy.

In addition, the breach of any covenants or any payment obligations in any of these debt agreements will result in an event of default under the applicable debt instrument. If an event of default were to occur, the holders of the defaulted debt may have the ability to cause all amounts outstanding with respect to that debt to be due and payable, subject to applicable grace periods. This could trigger cross-defaults under our other debt agreements, including our Senior Notes. Forced repayment of some or all of our indebtedness could require us to incur new debt at a higher cost, which would have an adverse impact on our financial condition, results of operations and cash flows.

We may pursue acquisitions, divestitures, and other strategic opportunities which, if not successful, may adversely impact our results of operations, cash flows and financial condition.

As part of our strategic objectives, we may pursue acquisitions to complement or expand our business, as well as divestitures and other strategic opportunities. We may not be able to successfully negotiate, finance or receive regulatory approval for future acquisitions or integrate the acquired businesses with our existing business and services. These efforts may also distract our management and employees from day-to-day operations and require substantial commitments of time and resources. Future acquisitions could result in potentially dilutive issuances of equity securities, a decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition, the incurrence of debt, contingent liabilities and amortization expenses and substantial goodwill. The effects of these strategic decisions may have long-term implications that are not likely to be known to us in the short-term. We may be materially and adversely affected if we are unable to successfully integrate businesses that we acquire.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

The following table sets forth the approximate miles of distribution mains and transmission pipelines we own as of December 31, 2022:


Properties (miles)	OK	KS	TX	Total
Distribution	19,400	11,700	11,000	42,100
Transmission	600	1,500	300	2,400
Total properties	20,000	13,200	11,300	44,500

We lease approximately 300 thousand square feet of office space and other facilities for our operations. In addition, we have 57.6 Bcf of natural gas storage capacity under contract, with maximum allowable daily withdrawal capacity of approximately 1.7 Bcf.

ITEM 3. LEGAL PROCEEDINGS

See Note 17 of the Notes to Consolidated Financial Statements in this Annual Report for information regarding legal proceedings.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II.

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

MARKET HOLDERS AND DIVIDENDS

Our common stock is listed on the NYSE under the trading symbol “OGS.”

At February 17, 2023, there were 9,437 registered shareholders of our common stock.

In January 2023, we declared a dividend of $0.65 per share ($2.60 per share on an annualized basis) for shareholders of record on February 24, 2023, payable on March 10, 2023.

Performance Graph

The following performance graph compares the performance of our common stock with the S&P MidCap 400 Utilities Index, the S&P MidCap 400 Index, the Dow Jones Industrial Average and a ONE Gas peer group during the period beginning December 31, 2017 and ending on December 31, 2022. This graph assumes a $100 investment in our common stock and in each of the indices at the beginning of the period and a reinvestment of dividends paid on such investments throughout the period.


	Cumulative Total Return As of Each Year Ended
	Cumulative Total Return As of Each Year Ended
	December 31,
	2018		2019		2020		2021		2022
ONE Gas, Inc.	$	111.40	$	133.99	$	112.91	$	117.83	$	118.53
S&P MidCap 400 Utilities Index	$	106.81	$	122.12	$	105.18	$	125.96	$	125.76
S&P MidCap 400 Index	$	88.90	$	112.17	$	127.48	$	159.01	$	159.01
Dow Jones Industrial Average	$	96.52	$	120.98	$	132.75	$	160.55	$	149.53
ONE Gas Peer Group*	$	104.14	$	123.50	$	109.50	$	128.69	$	133.82
* The ONE Gas peer group used in this graph is the same peer group that will be used in determining our level of performance under our 2022 performance units at the end of the three-year performance period and is comprised of the following companies: Alliant Energy Corporation; Atmos Energy Corporation; Avista Corporation; CenterPoint Energy, Inc.; Chesapeake Utilities Corporation; CMS Energy Corporation; New Jersey Resources Corporation; NiSource Inc.; Northwest Natural Holding Company; NorthWestern Corporation; South Jersey Industries, Inc.; Southwest Gas Holdings, Inc.; and Spire Inc.

ITEM 6. [RESERVED]

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our audited consolidated financial statements and Notes to Consolidated Financial Statements in this Annual Report.

EXECUTIVE SUMMARY

We are a 100-percent regulated natural gas distribution company. As such, our regulators determine the rates we are allowed to charge for our service based on the revenue requirements needed to achieve our authorized rates of return. We earn revenues from the delivery of natural gas, but do not earn a profit on the natural gas that we deliver, as those costs are passed through to our customers at cost. The primary components of our revenue requirements are the amount of capital invested in our business, which is also known as rate base, our allowed rate of return on our capital investments and our recoverable operating expenses, including depreciation, interest expense and income taxes. The variable component of our rates is dependent on the consumption of natural gas, which is impacted primarily by the weather and, to a lesser extent, economic activity. While we have WNA mechanisms that adjust sales customers’ bills when actual HDDs differ from normalized HDDs, these mechanisms are in place for only a portion of the year, except in Kansas, and do not offset all fluctuations in usage resulting from weather variability. Accordingly, the weather can have either a positive or negative impact on our financial performance.

Our financial performance, therefore, is contingent on a number of factors, including: (1) our regulatory construct, including the rates we are allowed to charge for our service, and the authorized rates of return on our investments in rate base; (2) the consumption of natural gas, which impacts the amount of natural gas sales derived from the variable component of our rates; (3) customer growth; (4) our operating performance; and (5) the perceived value of natural gas relative to other energy sources, particularly electricity, which influences our customers’ choice of natural gas to provide a portion of their energy needs.

We are subject to regulatory requirements for pipeline integrity, pipeline and cyber security and environmental compliance. These requirements impact our operating expenses and the level of capital expenditures required for compliance. Historically, our regulators have allowed recovery of these expenditures. However, because integrity and environmental regulations are frequently changing, our capital and operating expenditures to comply are changing as well. Although we believe our regulators will continue to allow recovery of such expenditures in the future, we will continue to make these expenditures with no assurance about if, or over what period, we will be permitted to recover them.

RECENT DEVELOPMENTS

Long-term Debt and Securitization Transactions - On August 8, 2022, we issued $300 million of 4.25 percent senior notes due September 2032. The proceeds from the issuance were used to repay amounts outstanding under our commercial paper program and for general corporate purposes.

In August 2022, Oklahoma Natural Gas received proceeds of approximately $1.3 billion, which represents the amount of the securitization bonds issued by the ODFA, less issuance costs. The receipt of these proceeds represents Oklahoma Natural Gas’ recovery of approximately $1.3 billion of authorized extraordinary natural gas purchase costs and other operational costs incurred during Winter Storm Uri, as well as carrying costs.

In August 2022, we called $750 million of the $1.0 billion of 0.85 percent senior notes due March 2023, $150 million of the $700 million of 1.10 percent senior notes due March 2024 and the remaining $400 million of outstanding floating-rate senior notes due March 2023, using the proceeds received from the securitization transaction for Oklahoma Natural Gas.

See “Regulatory Activities,” “Liquidity and Capital Resources,” and Notes 1 and 10 of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of the securitization transactions.

At-the-Market Equity Program - For the year ended December 31, 2022, we sold and issued 403,792 shares of our common stock for $35.0 million, generating proceeds, net of issuance costs, of $34.7 million. Additionally, for the year ended December 31, 2022, we executed forward sale agreements for 1,451,474 shares of our common stock. On December 30, 2022, we settled forward sales agreements with respect to 1,162,071 shares of our common stock for net proceeds of $93.8 million. Had we settled the remaining 289,403 shares under the outstanding forward sale agreements as of December 31, 2022, we would have generated net proceeds of approximately $21.7 million.

See “Liquidity and Capital Resources” and Note 6 of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of our at-the-market equity program.

ONE Gas Credit Agreement - On March 16, 2022, we entered into the first amendment to the second amended and restated ONE Gas Credit Agreement, which was previously amended and restated on March 16, 2021. The amendment extends the maturity date of the ONE Gas Credit Agreement to March 16, 2027, from March 16, 2026, and amends the ONE Gas Credit Agreement to provide that we may extend the maturity date, subject to the lenders’ consent, by one year two additional times. The amendment also changes the benchmark rate defined in the ONE Gas Credit Agreement to SOFR. All other material terms and conditions of the ONE Gas Credit Agreement remain in full force and effect.

Dividend - In January 2023, we declared a dividend of $0.65 per share ($2.60 per share on an annualized basis) for shareholders of record on February 24, 2023, payable on March 10, 2023.

REGULATORY ACTIVITIES

Oklahoma - In April 2021, Oklahoma Natural Gas submitted an initial application requesting a financing order pursuant to the securitization legislation in Oklahoma. In January 2022, the OCC approved a financing order that reflected the terms of a settlement agreement reached in November 2021, which included an agreement that all extreme gas purchase and extraordinary costs incurred as a result of Winter Storm Uri were reasonable and prudent and a financing order should be issued to recover these costs through securitization. In May 2022, pursuant to the securitization statute in Oklahoma, the Oklahoma Supreme Court validated that the bond issuance proposed by the ODFA complied with the securitization statute and the laws of Oklahoma.

In August 2022, the ODFA completed the issuance of $1.35 billion in ratepayer-backed bonds with varying scheduled final maturities over 30 years, consistent with the OCC financing order. The bonds are limited and special revenue obligations of the ODFA, payable solely from the securitization bond collateral and are not an obligation of Oklahoma Natural Gas or any of its affiliates.

As required, PBRC filings are made annually on or before March 15, until the next general rate case which is required to be filed on or before June 30, 2027. In March 2022, Oklahoma Natural Gas filed its required PBRC application for a calendar year 2021 test year. The filed request included a $19.7 million base rate revenue increase, $2.3 million energy efficiency incentive, and $9.1 million of estimated EDIT to be credited to customers in 2023. In May 2022, the Public Utility Division (“PUD”) of the OCC filed responsive testimony supporting an increase of $19.6 million and the Office of the Attorney General filed a statement of position supporting PUD’s position. Pursuant to its tariff, Oklahoma Natural Gas placed new rates into effect on July 13, 2022, reflecting a base rate revenue increase of $19.6 million. These rates were subject to refund until approved by the OCC. In August 2022, a stipulation was filed reflecting the $19.6 million increase supported by PUD and unopposed by the office of the Attorney General. In September 2022, a hearing was held and the administrative law judge recommended approval of the joint stipulation. In November 2022, the OCC issued an order approving the joint stipulation.

As required by OCC rule, in April 2022, Oklahoma Natural Gas filed a request for approval of a demand portfolio of conservation and energy efficiency programs for calendar years 2023-2025. The request included an annual portfolio of program costs of $17.4 million, with an estimated annual utility incentive of $2.6 million. In September 2022, a joint stipulation

and settlement agreement was entered into with the PUD supporting Oklahoma Natural Gas’ request. A hearing was held in October 2022, and the administrative law judge recommended approval of the joint stipulation and settlement agreement. In December 2022, the OCC issued an order approving the joint stipulation.

In May 2021, Oklahoma Natural Gas filed a general rate case. In October 2021, a joint stipulation and settlement agreement was signed by all parties to the rate case. In November 2021, the OCC issued an order approving the joint stipulation and settlement agreement. Upon approval of the order, Oklahoma Natural Gas’ base rates increased by $15.3 million. Premised on an ROE of 9.4 percent and a common equity ratio of 58.55 percent, the order also includes the continuation of the PBRC tariff that was established in 2009. The approved order allows Oklahoma Natural Gas to recover commodity costs of no more than $5.0 million annually for the purchase of RNG and requires Oklahoma Natural Gas to file an application on or before December 31, 2022, requesting approval of an RNG pilot program including an “opt-in” tariff allowing Oklahoma Natural Gas to allocate costs and benefits of RNG to those customers who choose RNG for their fuel source.

In December 2022, Oklahoma Natural Gas filed the required request for an RNG Pilot Program and Voluntary Tariff pursuant to the requirement in the rate case order. The proposed tariff will allow all residential, small commercial and industrial sales customers to voluntarily purchase the environmental attributes of RNG up to the equivalent of 10 Dth per month. If approved, the tariff will be in effect through 2027. Assessment of the tariff and pilot program will be made in the rate case required to be filed on or before June 30, 2027. An order is expected no earlier than the third quarter of 2023.

In May 2021, a bill amending the Oklahoma state income tax code was signed into law that reduced the state income tax rate to four percent from six percent beginning January 1, 2022. As a result of the enactment of this legislation, we remeasured our ADIT. As a regulated entity, the reduction in ADIT of $29.3 million was recorded as a regulatory liability. The impact of the change in the state income tax rate on Oklahoma Natural Gas’ rates, as well as the timing and amount of the impact on the annual crediting mechanism for the EDIT regulatory liability, was not material and is included in the March 15, 2022 PBRC filing, as approved in November 2022.

Kansas - In March 2021, the KCC issued an order adopting the KCC staff’s recommendation to open company-specific dockets to accept each utility’s filing of financial impact compliance reports and permit the KCC staff to conduct a review of the utility’s compliance report and its actions during Winter Storm Uri. In April 2021, a bill permitting the utilities to pursue securitization to finance extraordinary expenses, such as fuel costs incurred during extreme weather events, was signed into law by the Kansas governor. The law gives the KCC the authority to oversee and authorize the issuance of ratepayer-backed securitized bonds issued by a public utility.

In May 2021, Kansas Gas Service filed a motion in its company-specific docket opened by the KCC, requesting a limited waiver of the penalty provisions of its tariff to eliminate the multipliers in the penalty calculation when calculating the penalties to assess on marketers and individually-balanced transportation customers for their unauthorized natural gas usage during Winter Storm Uri. In March 2022, the KCC issued an order approving a settlement, which modified the penalty provisions of Kansas Gas Service’s tariffs and included a carrying charge of two percent on amounts due to Kansas Gas Service. Amounts collected from these penalties reduce the regulatory asset for the winter weather event, up to $52.6 million. Through December 31, 2022, we have collected $50.5 million of these penalties.

In July 2021, Kansas Gas Service submitted its financial plan to the KCC as required by the company-specific docket opened by the KCC in March 2021. The plan included a proposal for a newly formed, bankruptcy remote subsidiary of the Company to issue securitized utility tariff bonds to recover the extraordinary costs resulting from Winter Storm Uri from Kansas Gas Service’s customers. In February 2022, the KCC issued an order approving a unanimous settlement agreement that allows Kansas Gas Service to recover extraordinary costs, net of any penalties recovered from marketers and individually-balanced transportation customers, plus carrying costs, by seeking a financing order from the KCC for the issuance of securitized utility tariff bonds.

In March 2022, Kansas Gas Service submitted its application for a financing order to the KCC as contemplated by the unanimous settlement agreement, requesting approval to issue securitized utility tariff bonds to recover extraordinary costs resulting from Winter Storm Uri. In July 2022, Kansas Gas Service, the KCC Staff and the Citizens’ Utility Ratepayer Board reached a settlement agreement for the issuance of a financing order allowing a newly formed, bankruptcy remote subsidiary of the Company to issue securitized utility tariff bonds. In August 2022, the KCC issued an order approving the agreement and also issued a financing order.

As part of the order, we created KGSS-I, a special-purpose, wholly-owned subsidiary of ONE Gas, and filed a registration statement with the SEC, for the purpose of issuing securitized utility tariff bonds. The registration statement was declared effective on November 7, 2022.

In November 2022, KGSS-I issued $336 million of 5.486 percent Securitized Utility Tariff Bonds. KGSS-I used the proceeds from the issuance to purchase the Securitized Utility Tariff Property from Kansas Gas Service, pay for debt issuance costs, and reimburse Kansas Gas Service for upfront securitization costs paid by Kansas Gas Service on behalf of KGSS-I. See Note 4 of the Notes to Consolidated Financial Statements in this Annual Report for additional information about the Securitized Utility Tariff Bonds and Notes 10 and 11 of the Notes to Consolidated Financial Statements in this Annual Report for additional information about the securitization transaction.

In August 2022, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $7.8 million related to its GSRS. The KCC issued an order in November 2022 authorizing an increase of $7.7 million, and the new surcharge became effective on December 1, 2022.

In August 2022, Kansas Gas Service submitted an application to the KCC requesting certain changes to Section 7 of its General Terms and Conditions tariff. These changes would revise the tariff to use Kansas Gas Service’s average embedded cost to determine the cost for service line installations and replacements as well as certain customer requested work. The KCC has 240 days to review the request.

In August 2021, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $7.6 million related to its GSRS. The KCC issued an order in November 2021, and the new surcharge became effective on December 1, 2021.

In May 2020, a bill amending the Kansas state income tax code was signed into law that exempts public utilities regulated by the KCC from paying Kansas state income taxes beginning January 1, 2021, and authorizes the KCC to adjust utility rates for the elimination of Kansas state income tax beginning January 1, 2021. As a result of the enactment of this legislation, we remeasured our ADIT. As a regulated entity, the reduction in ADIT of $84.2 million was recorded as a regulatory liability and will be refunded to our customers. This adjustment had no material impact on our income tax expense and no impact on our cash flows for the years ended December 31, 2022 and 2021. The bill stipulates that, if requested by the utility, this EDIT will be returned to Kansas customers over a period of no less than 30 years, with the exact timing to be determined in our next general rate proceeding. In August 2020, Kansas Gas Service submitted an application to the KCC to reduce its base rates by approximately $4.9 million to reflect the elimination of Kansas state income taxes. In December 2020, the KCC approved the application, effective January 1, 2021.

Texas - Pursuant to securitization legislation enacted in Texas as a result of Winter Storm Uri and a June 2021 RRC Notice to Gas Utilities, Texas Gas Service submitted an application to the RRC in July 2021, for an order authorizing the amount of extraordinary costs for recovery and other such specifications necessary for the issuance of securitized bonds.

In November 2021, the RRC approved a unanimous settlement agreement between Texas Gas Service, the other natural gas utilities in Texas participating in the securitization process, the staff of the RRC and all intervenors. The settlement agreement provides that all costs incurred by Texas Gas Service to purchase natural gas during Winter Storm Uri were reasonable, necessary and prudently incurred.

In February 2022, the RRC issued a single financing order for Texas Gas Service and other natural gas utilities in Texas participating in the securitization process, which included a determination that the approved costs will be collected from customers over a period of not more than 30 years. The TPFA formed the Texas Natural Gas Securitization Finance Corporation, a new independent public authority, that will issue the securitized bonds, which are expected to be issued by April 2023. At December 31, 2022, Texas Gas Service has deferred approximately $243.1 million in extraordinary costs associated with Winter Storm Uri, which includes $43.8 million attributable to the former West Texas service area. Pursuant to the approved settlement order, in January 2022, Texas Gas Service began collecting the extraordinary costs, including carrying costs, associated with Winter Storm Uri attributable to the former West Texas service area from those customers.

West-North Service Area - In June 2022, Texas Gas Service filed a rate case seeking to consolidate its West Texas, North Texas and Borger/Skellytown service areas into a single West-North service area and requesting a rate increase of $13.0 million. In January 2023, the RRC approved the consolidation and a rate increase of $8.8 million premised on a return on equity of 9.6 percent and a common equity ratio of 59.74 percent equity. The new rates were implemented in February 2023.

West Texas Service Area - In March 2022, Texas Gas Service made GRIP filings for all customers in the former West Texas service area, requesting a $5.0 million increase to be effective in July 2022. In June 2022, the city of El Paso denied the requested increase and assessed fees associated with its review of the filing. Texas Gas Service appealed the city’s action to the

RRC. In August 2022, the RRC approved the appealed rates. All other municipalities, and the RRC, approved the new rates or allowed them to take effect with no action. Texas Gas Service implemented the new rates in July 2022.

In March 2021, Texas Gas Service made GRIP filings for all customers in the former West Texas service area, requesting an increase of $9.7 million to be effective in July 2021. In June 2021, the city of El Paso approved a motion which found the GRIP filing to be in compliance with the GRIP statute. The city subsequently denied the requested increase and assessed fees associated with its review of the filing. In July 2021, Texas Gas Service appealed the city’s action to the RRC. The RRC granted and approved the appeal, and new rates became effective in August 2021. All other municipalities, and the RRC, approved the new rates or allowed them to take effect with no action.

Central-Gulf Service Area - In February 2023, Texas Gas Service made GRIP filings for all customers in the Central-Gulf service area, requesting an $11.5 million increase to be effective in June 2023.

In February 2022, Texas Gas Service made GRIP filings for all customers in the Central-Gulf service area, requesting a $9.1 million increase to be effective in June 2022. All municipalities, and the RRC, approved the new rates and new rates became effective in June 2022.

In February 2021, Texas Gas Service made GRIP filings for all customers in the Central-Gulf service area, requesting an increase of $10.7 million to be effective in June 2021. All municipalities, and the RRC, approved the new rates or allowed them to take effect with no action.

Other Texas Service Areas - In April 2022, Texas Gas Service made its annual COSA filings for the incorporated area of the Rio Grande Valley service area, requesting an increase of $2.9 million. In July 2022, the municipalities approved an increase of $2.5 million, and new rates became effective in August 2022.

In April 2021, Texas Gas Service made its annual COSA filings for the incorporated areas of the Rio Grande Valley service area and the North Texas service area. In July 2021, the cities in the Rio Grande Valley and North Texas service areas agreed to increases of $3.5 million and $1.4 million, respectively. New rates became effective in August 2021.

In the normal course of business, Texas Gas Service has filed rate cases and sought GRIP and COSA increases in various other Texas jurisdictions to address investments in rate base and changes in expenses. For the years ended December 31, 2022 and 2021, the impact of these filings was not material.

Winter Storm Uri Deferred Costs - In accordance with regulatory orders associated with the winter weather event, our regulatory asset totaled approximately $258.2 million in extraordinary costs for natural gas purchases, related financing and carrying costs and other operational costs that have not been recovered at December 31, 2022. The amounts deferred include invoiced costs for natural gas purchases that have not been paid as we work with our suppliers to resolve discrepancies in invoiced amounts. The amounts deferred may be adjusted as the differences are resolved. As these amounts are related to the extraordinary gas purchase costs associated with Winter Storm Uri, which are deferred, future adjustments to the amounts deferred are not expected to have a material impact on earnings.

Other - Certain costs to be recovered through the ratemaking process have been capitalized as regulatory assets. Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria for recognition and accordingly, a write-off of regulatory assets and stranded costs may be required. There were no write-offs of regulatory assets resulting from the failure to meet the criteria for capitalization during 2022, 2021 or 2020.

FINANCIAL RESULTS AND OPERATING INFORMATION

Selected Financial Results - Net income was $221.7 million, or $4.08 per diluted share, $206.4 million, or $3.85 per diluted share, and $196.4 million, or $3.68 per diluted share, for the years ended December 31, 2022, 2021 and 2020, respectively. We operate in one reportable business segment: regulated public utilities that deliver natural gas to residential, commercial and transportation customers. We evaluate our financial performance principally on net income.

The following table sets forth certain selected financial results for our operations for the periods indicated:


							Variances				Variances
	Years Ended December 31,						2022 vs. 2021				2021 vs. 2020
Financial Results	2022		2021		2020		Increase (Decrease)				Increase (Decrease)
			(Millions of dollars, except percentages)
Natural gas sales	$	2,418.7	$	1,661.7	$	1,389.2	$	757.0	46	%	$	272.5	20	%
Transportation revenues	126.5		119.0		114.1		7.5		6	%	4.9		4	%
Other revenues	32.8		27.9		27.0		4.9		18	%	0.9		3	%
Total revenues	2,578.0		1,808.6		1,530.3		769.4		43	%	278.3		18	%
Cost of natural gas	1,459.1		775.0		537.4		684.1		88	%	237.6		44	%
Operating costs	540.4		516.1		494.5		24.3		5	%	21.6		4	%
Depreciation and amortization	228.5		207.2		194.9		21.3		10	%	12.3		6	%
Operating income	$	350.0	$	310.3	$	303.5	$	39.7	13	%	$	6.8	2	%
Net income	$	221.7	$	206.4	$	196.4	$	15.3	7	%	$	10.0	5	%
Capital expenditures and asset removal costs	$	656.5	$	544.3	$	512.2	$	112.2	21	%	$	32.1	6	%

Natural gas sales to customers represent revenue from contracts with customers through implied contracts established by our tariffs and rates approved by regulatory authorities, as well as revenues from regulatory mechanisms related to natural gas sales. Additionally, natural gas sales includes recovery of the cost of natural gas.

Transportation revenues represent revenue from contracts with customers through implied contracts established by our tariffs and rates approved by regulatory authorities, as well as tariff-based negotiated contracts.

Other revenues include primarily miscellaneous service charges, which represent implied contracts with customers established by our tariffs and rates approved by regulatory authorities and other revenues from regulatory mechanisms.

Our average cost of gas rate increased to $8.22 per Mcf for the year ended December 31, 2022, compared to $4.87 per Mcf in the prior year. Cost of natural gas includes commodity purchases, fuel, storage, transportation, hedging costs and settlement proceeds for natural gas price volatility mitigation programs approved by our regulators and other gas purchase costs recovered through our cost of natural gas regulatory mechanisms and does not include an allocation of general operating costs or depreciation and amortization. These regulatory mechanisms provide a method of recovering natural gas costs on an ongoing basis without a profit. Therefore, although our revenues will fluctuate with the cost of natural gas that we pass-through to our customers, operating income is not affected by fluctuations in the cost of natural gas.

2022 vs. 2021 - Operating income increased $39.7 million due primarily to the following:

•an increase of $58.7 million from new rates;

•an increase of $7.0 million in residential sales due primarily to net customer growth; and

•a decrease of $3.1 million in bad debt expense.

These increases were offset partially by:

•an increase of $15.4 million in outside service costs;

•an increase of $14.1 million in depreciation expense due to additional capital expenditures being placed in service; and

•an increase of $3.2 million in employee-related costs.

Other Factors Affecting Net Income - Other factors that affect net income for the year ended December 31, 2022, compared with 2021, include an increase of $1.0 million in other expense, net, and an increase of $17.2 million in interest expense. The increase in other expense, net, is due primarily to a $10.9 million decrease in the market value of investments associated with our nonqualified employee benefit plans, offset partially by a $7.7 million decrease in net periodic benefit costs other than service costs. The increase in interest expense is due primarily to interest on our commercial paper, the issuance of $300 million

of 4.25 percent senior notes in August 2022 and $336 million of 5.486 percent Securitized Utility Tariff Bonds in November 2022, compared with the same period last year.

EDIT - The return of EDIT to our customers is not expected to have a material impact on earnings, as any reduction or credit in rates is offset by a reduction in income tax expense. During the years ended December 31, 2022 and 2021, we credited income tax expense $18.0 million and $17.3 million, respectively, for the amortization of the regulatory liability associated with EDIT that was returned to customers.

Capital Expenditures and Asset Removal Costs - Our capital expenditures program includes expenditures for pipeline integrity, extending service to new areas, increasing system capabilities, pipeline replacements, automated meter reading, government-mandated pipeline relocations, fleet, facilities, IT assets and cybersecurity. It is our practice to maintain and upgrade our infrastructure, facilities and systems to ensure safe, reliable and efficient operations. Asset removal costs include expenditures associated with the replacement or retirement of long-lived assets that result from the construction, development and/or normal use of our assets, primarily our pipeline assets.

Capital expenditures and asset removal costs increased $112.2 million for 2022, compared with 2021, due primarily to expenditures for system integrity and extension of service to new areas. Our capital expenditures and asset removal costs are expected to be approximately $675 million for 2023. While we did not experience a significant impact to our capital expenditure program during the year ended December 31, 2022, our future capital expenditure activity is dependent on a number of factors, including economic conditions and our supply chains for contract labor, materials and supplies.

Selected Operating Information - The following tables set forth certain selected operating information for the periods indicated:


	Years Ended								Variances
	December 31,								2022 vs. 2021
(in thousands)	2022				2021				Increase (Decrease)
Average Number of Customers	OK	KS	TX	Total	OK	KS	TX	Total	OK	KS	TX	Total
Residential	831	592	656	2,079	824	591	650	2,065	7	1	6	14
Commercial and industrial	76	50	35	161	75	50	35	160	1	—	—	1
Other	1	—	3	4	—	—	3	3	1	—	—	1
Transportation	5	6	1	12	6	6	1	13	(1)	—	—	(1)
Total customers	913	648	695	2,256	905	647	689	2,241	8	1	6	15


	Years Ended								Variances
	December 31,								2021 vs. 2020
(in thousands)	2021				2020				Increase (Decrease)
Average Number of Customers	OK	KS	TX	Total	OK	KS	TX	Total	OK	KS	TX	Total
Residential	824	591	650	2,065	814	589	641	2,044	10	2	9	21
Commercial and industrial	75	50	35	160	75	50	35	160	—	—	—	—
Other	—	—	3	3	—	—	3	3	—	—	—	—
Transportation	6	6	1	13	6	6	1	13	—	—	—	—
Total customers	905	647	689	2,241	895	645	680	2,220	10	2	9	21

The increase in the average number of customers for 2022, compared with 2021, is due primarily to the connection of new customers resulting from the extension and expansion of our system in our service areas. For 2022, our average customer count includes 27,100 new customer connections compared to 24,900 in 2021.

The following table reflects the total volumes delivered, excluding the effects of WNA mechanisms:


	Years Ended December 31,
Volumes (MMcf)	2022	2021	2020
Natural gas sales
Residential	125,286	117,758	121,967
Commercial and industrial	43,184	37,615	36,169
Other	2,725	2,521	2,427
Total sales volumes delivered	171,195	157,894	160,563
Transportation	230,080	229,935	224,531
Total volumes delivered	401,275	387,829	385,094

Total sales volumes delivered increased for 2022, compared with 2021, due primarily to colder weather in the fourth quarter 2022. The impact of weather on residential and commercial natural gas sales is mitigated by WNA mechanisms in all jurisdictions.

The following table sets forth the HDDs by state for the periods indicated:


	Years Ended
	December 31,
	2022		2021		2022 vs. 2021		2022		2021
HDDs	Actual	Normal	Actual	Normal	Actual Variance		Actual as a percent of Normal
Oklahoma	3,621	3,346	3,224	3,229	12	%	108	%	100	%
Kansas	4,779	4,722	4,251	4,722	12	%	101	%	90	%
Texas	1,950	1,764	1,550	1,766	26	%	111	%	88	%


	Years Ended
	December 31,
	2021		2020		2021 vs. 2020		2021		2020
HDDs	Actual	Normal	Actual	Normal	Actual Variance		Actual as a percent of Normal
Oklahoma	3,224	3,229	3,253	3,264	(1)	%	100	%	100	%
Kansas	4,251	4,722	4,408	4,722	(4)	%	90	%	93	%
Texas	1,550	1,766	1,580	1,779	(2)	%	88	%	89	%

Normal HDDs are established through rate proceedings in each of our rate jurisdictions for use primarily in weather normalization billing calculations. Normal HDDs disclosed above are based on:

•Oklahoma - For years 2021 through the current period, 10-year weighted average HDDs as of June 30, 2021, as calculated using 11 weather stations across Oklahoma and weighted on average customer count. For 2020, 10-year weighted average HDDs as of December 31, 2014, as calculated using 11 weather stations across Oklahoma and weighted on average customer count.

•Kansas - A 30-year rolling average for years 1988-2017 calculated using three weather stations across Kansas and weighted on HDDs by weather station and customers.

•Texas - An average of HDDs authorized in our most recent rate proceeding in each jurisdiction and weighted using a rolling 10-year average of actual natural gas distribution sales volumes by service area.

Actual HDDs are based on year-to-date, weighted average of:

•11 weather stations and customers by month for Oklahoma;

•3 weather stations and customers by month for Kansas; and

•9 weather stations and natural gas distribution sales volumes by service area for Texas.

Selected financial results and operating information for 2021, compared with 2020, is described in Part II, Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the year ended December 31, 2021.

CONTINGENCIES

We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses from such matters, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not have a material adverse effect on our results of operations, financial position or cash flows. See Note 17 of the Notes to Consolidated Financial Statements in this Annual Report for information with respect to legal proceedings.

LIQUIDITY AND CAPITAL RESOURCES

General - We have relied primarily on operating cash flow and commercial paper for our liquidity and capital resource requirements. We fund operating expenses, working capital requirements, including purchases of natural gas, and capital expenditures primarily with cash from operations and commercial paper.

We believe that the combination of the significant residential component of our customer base, the fixed-charge component of our natural gas sales revenues and our rate mechanisms that we have in place result in a stable cash flow profile and historically has generated stable earnings. Additionally, we have rate mechanisms in place in our jurisdictions that reduce the lag in earning a return on our capital expenditures and provide for recovery of certain changes in our cost of service by allowing for adjustments to rates between rate cases. We anticipate that our cash flow generated from operations and our expected short- and long-term financing arrangements will enable us to maintain our current and planned level of operations and provide us flexibility to finance our infrastructure investments. Our ability to access capital markets for debt and equity financing under reasonable terms depends on market conditions, our financial condition and credit ratings.

Short-term Debt - On March 16, 2022, we entered into the first amendment to the second amended and restated ONE Gas Credit Agreement, which was previously amended and restated on March 16, 2021. The amendment extends the maturity date of the ONE Gas Credit Agreement to March 16, 2027, from March 16, 2026, and amends the ONE Gas Credit Agreement to provide that we may extend the maturity date, subject to the lenders’ consent, by one year two additional times. The amendment also changes the benchmark rate defined in the ONE Gas Credit Agreement to SOFR. All other material terms and conditions of the ONE Gas Credit Agreement remain in full force and effect.

The ONE Gas Credit Agreement provides for a $1.0 billion revolving unsecured credit facility and includes a $20 million letter of credit subfacility and a $60 million swingline subfacility. We can request an increase in commitments of up to an additional $500 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement is available to provide liquidity for working capital, capital expenditures, acquisitions and mergers, the issuance of letters of credit and for other general corporate purposes.

The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At December 31, 2022, our total debt-to-capital ratio was 56 percent and we were in compliance with all covenants under the ONE Gas Credit Agreement. We may reduce the unutilized portion of the ONE Gas Credit Agreement in whole or in part without premium or penalty. The ONE Gas Credit Agreement contains customary events of default. Upon the occurrence of certain events of default, the obligations under the ONE Gas Credit Agreement may be accelerated and the commitments may be terminated.

In connection with the second amendment and restatement of the ONE Gas Credit Agreement on March 16, 2021, all commitments under the ONE Gas 364-day Credit Agreement were terminated and all obligations under the ONE Gas 364-day Credit Agreement were paid in full and discharged.

In June 2021, we increased the size of our commercial paper program to permit the issuance of commercial paper to fund short-term borrowing needs in an aggregate principal amount not to exceed $1.0 billion outstanding at any time. Prior to this increase, our commercial paper program permitted us to issue commercial paper in an aggregate principal amount not to exceed $700 million outstanding at any time. The maturities of the commercial paper notes may vary but may not exceed 270 days from the date of issue. Commercial paper is generally sold at par less a discount representing an interest factor. At December 31, 2022 and 2021, we had $552.0 million and $494.0 million of commercial paper outstanding, respectively. The weighted-average interest rate on our commercial paper was 4.75 percent and 0.38 percent at December 31, 2022 and 2021, respectively.

At December 31, 2022, we had $1.2 million in letters of credit issued and no borrowings under the ONE Gas Credit Agreement, with $998.8 million of remaining credit available to repay our commercial paper borrowings.

Long-term Debt - On August 8, 2022, we issued $300 million of 4.25 percent senior notes due September 2032. The proceeds from the issuance were used to repay amounts outstanding under our commercial paper program and for general corporate purposes.

On August 25, 2022, the ODFA completed the issuance of $1.35 billion in ratepayer-backed bonds with varying scheduled final maturities over 30 years, consistent with the OCC financing order. The bonds are limited and special revenue obligations of the ODFA, payable solely from the securitization bond collateral and are not an obligation of Oklahoma Natural Gas or any of its affiliates.

In August 2022, we called $750 million of the $1.0 billion of 0.85 percent senior notes due March 2023, $150 million of the $700 million of 1.10 percent senior notes due March 2024 and the remaining $400 million of outstanding floating-rate senior notes due March 2023, using the proceeds received from Oklahoma Natural Gas’ securitization transaction.

On November 18, 2022, KGSS-I issued $336 million of 5.486 percent Securitized Utility Tariff Bonds. The Securitized Utility Tariff Bonds have an interest rate of 5.486 percent and a term of 10 years with semi-annual principal repayments, which results in an expected weighted average life of the bonds of 5.5 years. The bonds are governed by an indenture between KGSS-I and the indenture trustee. The indenture contains certain covenants that restrict KGSS-I’s ability to sell, transfer, convey, exchange, or otherwise dispose of its assets.

In November 2022, we called the remaining $250 million of the $1.0 billion of 0.85 percent senior notes due March 2023 and $77 million of the $700 million of 1.10 percent senior notes due March 2024, using the proceeds from the securitization transaction for Kansas Gas Service. See Note 10 of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of the securitization transactions.

In March 2021, we issued $1.0 billion of 0.85 percent senior notes due March 2023, $700 million of 1.10 percent senior notes due March 2024, and $800 million of floating-rate senior notes due March 2023. The net proceeds from the issuance were used for payment of gas purchases and related costs resulting from Winter Storm Uri and general corporate purposes.

In September 2021, we called $400 million of the floating-rate senior notes due March 2023 at par, using a combination of cash on hand and commercial paper. We did not have the right to call these senior notes prior to September 11, 2021.

The indenture governing our Senior Notes includes an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding Senior Notes to declare those Senior Notes immediately due and payable in full.

Depending on the series, we may redeem our Senior Notes at par, plus accrued and unpaid interest to the redemption date, starting three months or six months before their maturity dates. Prior to these dates, we may redeem these Senior Notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective Senior Note plus accrued and unpaid interest to the redemption date. Our Senior Notes are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness.

In February 2021, we entered into the ONE Gas 2021 Term Loan Facility as part of the financing of our natural gas purchases in order to provide sufficient liquidity to satisfy our obligations as a result of Winter Storm Uri. The net proceeds of the March 2021 debt issuance reduced the commitments under the ONE Gas 2021 Term Loan Facility on a dollar-for-dollar basis, and as a result no commitments remained outstanding and the facility was terminated concurrently with the closing of the debt issuance.

At December 31, 2022, our long-term debt-to-capital ratio was 51 percent.

Credit Ratings - Our credit ratings at December 31, 2022, were:


Rating Agency	Rating	Outlook
Moody’s	A3	Stable
S&P	A-	Stable

At December 31, 2022, our commercial paper was rated Prime-2 by Moody’s and A-2 by S&P. We intend to maintain credit metrics at a level that supports our balanced approach to capital investment and a return of capital to shareholders via a dividend that we believe will be competitive with our peer group.

At-the-Market Equity Program - In February 2020, we initiated an at-the-market equity program by entering into an equity distribution agreement under which we may issue and sell shares of our common stock with an aggregate offering price up to $250 million (including any shares of common stock that may be sold pursuant to the master forward sale confirmation entered into in connection with the equity distribution agreement and the related supplemental confirmations). Sales of common stock are made by means of ordinary brokers’ transactions on the NYSE, in block transactions or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common stock under the program.

For the years ended December 31, 2022 and 2021, we sold and issued 403,792 and 281,124 shares of our common stock for $35.0 million and $21.4 million, respectively, generating proceeds, net of issuance costs, of $34.7 million and $21.1 million, respectively.

For the year ended December 31, 2022, we also executed forward sale agreements for 1,451,474 shares of our common stock. We did not enter into any forward sale agreements in 2021. On December 30, 2022, we settled forward sales agreements with respect to 1,162,071 shares of our common stock for net proceeds of $93.8 million. Had we settled the remaining 289,403 shares under the outstanding forward sale agreements as of December 31, 2022, we would have generated net proceeds of approximately $21.7 million.

At December 31, 2022, we had $63.1 million of equity available for issuance under the program.

Pension and Other Postemployment Benefit Plans - For the year ended December 31, 2022, we contributed $1.5 million to our defined benefit pension plans and $1.9 million to our other postemployment benefit plans. For the year ended December 31, 2021, we contributed $1.0 million to our defined benefit pension plans and $2.0 million to our other postemployment benefit plans. Additional information about our pension and other postemployment benefits plans, including anticipated contributions, is included under “Estimates and Critical Accounting Policies - Pension and Other Postemployment Benefits” and under Note 14 of the Notes to Consolidated Financial Statements in this Annual Report.

CASH FLOW ANALYSIS

We use the indirect method to prepare our consolidated statements of cash flows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payments and changes in our assets and liabilities not classified as investing or financing activities during the period. Items that impact net income but may not result in actual cash receipts or payments include, but are not limited to, depreciation and amortization, deferred income taxes, share-based compensation expense and provision for doubtful accounts.

The following table sets forth the changes in cash flows by operating, investing and financing activities for the periods indicated:



	Years Ended December 31,						Variances
	2022		2021		2020		2022 vs. 2021		2021 vs. 2020
			(Millions of dollars)
Total cash provided by (used in):
Operating activities	1,570.8		$	(1,535.7)	$	364.5	$	3,106.5	$	(1,900.2)
Investing activities	(614.1)		(501.1)		(470.4)		$	(113.0)	(30.7)
Financing activities	(947.4)		2,037.6		96.0		(2,985.0)		1,941.6
Change in cash, cash equivalents, restricted cash and restricted cash equivalents	9.3		0.8		(9.9)		8.5		10.7
Cash, cash equivalents, restricted cash and restricted cash equivalents at beginning of period	8.8		8.0		17.9		0.8		(9.9)
Cash, cash equivalents, restricted cash and restricted cash equivalents at end of period	$	18.1	$	8.8	$	8.0	$	9.3	$	0.8

Operating Cash Flows - Changes in cash flows from operating activities are due primarily to changes in operating income and expenses discussed in “Financial Results and Operating Information,” the effects of tax reform discussed in “Regulatory Activities” and changes in working capital. Changes in natural gas prices and demand for our services or natural gas, whether because of general economic conditions, variations in weather not mitigated by WNAs, changes in supply or increased competition from other energy providers, could affect our earnings and operating cash flows. Typically, our cash flows from operations are greater in the first half of the year compared with the second half of the year.

2022 vs. 2021 - Cash flows from operating activities were higher in 2022 compared with 2021, due primarily to recovery of regulatory assets associated with Winter Storm Uri, through securitization in Oklahoma compared to increased natural gas purchases and other extraordinary costs in the prior period resulting from Winter Storm Uri, which were deferred and included in regulatory assets. See Notes 10 and 11 of the Notes to Consolidated Financial Statements in this Annual Report for additional information.

Investing Cash Flows - 2022 vs. 2021 - Cash used in investing activities increased for 2022, compared to 2021, due primarily to an increase in capital expenditures for system integrity and extension of service to new areas.

Financing Cash Flows - 2022 vs. 2021 - Cash flows from financing activities were lower in 2022 compared with 2021, due primarily to a net outflow of cash for repayments of long-term debt in 2022 compared to a net inflow of cash from issuances of long-term debt in 2021. See Notes 4 and 11 of the Notes to Consolidated Financial Statements in this Annual Report for additional information.

2021 vs. 2020 - Cash flows in 2021, compared with 2020, are described in Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the year ended December 31, 2021.

ENVIRONMENTAL, SAFETY AND REGULATORY MATTERS

Environmental Matters - We are subject to multiple laws and regulations regarding protection of the environment and natural and cultural resources, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, plant and wildlife protection, hazardous materials use, storage and transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits or the discovery of presently unknown environmental conditions may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other regulatory or permitting mandates under the CAA and other similar federal and state laws could require unexpected capital expenditures. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation and remediation compliance to-date have not been significant in relation to our

financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during 2022, 2021 and 2020.

We own or retain legal responsibility for certain environmental conditions at 12 former MGP sites in Kansas. These sites contain contaminants generally associated with MGP sites and are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE governs all environmental investigation and remediation work at these sites. The terms of the consent agreement require us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater. Regulatory closure has been achieved at five of the 12 sites, but these sites remain subject to potential future requirements that may result in additional costs.

We have an AAO that allows Kansas Gas Service to defer and seek recovery of costs necessary for investigation and remediation at, and nearby, these 12 former MGP sites that are incurred after January 1, 2017, up to a cap of $15.0 million, net of any related insurance recoveries. Costs approved for recovery in a future rate proceeding would then be amortized over a 15-year period. The unamortized amounts will not be included in rate base or accumulate carrying charges. Following a determination that future investigation and remediation work approved by the KDHE is expected to exceed $15.0 million, net of any related insurance recoveries, Kansas Gas Service will be required to file an application with the KCC for approval to increase the $15.0 million cap. At December 31, 2022 and 2021, we have deferred $29.8 million and $29.9 million, respectively, for accrued investigation and remediation costs pursuant to our AAO. Kansas Gas Service expects to file an application as soon as practicable after the KDHE approves the plans we have submitted.

We have completed or are addressing removal of the source of soil contamination at all 12 sites and continue to monitor groundwater at seven of the 12 sites according to plans approved by the KDHE. In 2019, we completed a project to remove a source of contamination and associated contaminated materials at the twelfth site where no active soil remediation had previously occurred. Remediation plans concerning various sites were submitted to the KDHE in 2021 and 2020 and the KDHE has provided comments that we are addressing. We are also working on a remediation plan for another of these sites for submission to the KDHE.

We also own or retain legal responsibility for certain environmental conditions at a former MGP site in Texas. At the request of the TCEQ, we began investigating the level and extent of contamination associated with the site under their Texas Risk Reduction Program. A preliminary site investigation revealed that this site contains contaminants generally associated with MGP sites and is subject to control or remediation under various environmental laws and regulations. Impacts have been identified in the soil and groundwater at the site with limited impacts observed in surrounding areas. In April 2022, we submitted a remediation work plan to address the areas impacted to the TCEQ. At December 31, 2022, estimated costs associated with expected remediation activities for this site are not material.

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the years ended December 31, 2022, 2021 and 2020. The reserve for remediation of our MGP sites was $12.7 million and $22.8 million at December 31, 2022 and December 31, 2021, respectively. Environmental issues may exist with respect to MGP sites that are unknown to us. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation required, changing technology and governmental regulations, and to the extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition, results of operations or cash flows.

We are subject to environmental regulation by federal, state and local authorities. Due to the inherent uncertainties surrounding the development of federal and state environmental laws and regulations, we cannot determine with specificity the impact such laws and regulations may have on our existing and future facilities. With the trend toward stricter standards, greater regulation and more extensive permit requirements for the types of assets operated by us, our environmental expenditures could increase in the future, and such expenditures may not be fully recovered by insurance or recoverable in rates from our customers, and those costs may adversely affect our financial condition, results of operations and cash flows.

Environmental Footprint - Our environmental and climate change strategy focuses on taking steps to minimize the impact of our operations on the environment. These strategies include: (1) developing and maintaining an accurate greenhouse gas emissions inventory according to current rules issued by the EPA; (2) monitoring and improving the integrity of our pipelines; (3) reducing operational emissions through the implementation of advanced leak detection technology and damage prevention programs; (4) promoting end-use conservation through programs that incentivize the use of high-efficiency equipment; and (5) increased utilization of CNG for vehicles. In addition, we are considering potential avenues to incorporate RNG and hydrogen

into our operations. RNG and hydrogen technologies offer potential opportunities to secure lower-carbon supply sources that could be transported on our pipeline system and potentially reduce the carbon intensity of the product we deliver.

We participate in several programs to voluntarily reduce methane emissions including the EPA’s Natural Gas STAR Program, the EPA’s Natural Gas STAR Methane Challenge Program, and Our Nation’s Energy Future (ONE Future). By joining these programs, we committed to: (1) evaluate our methane emission reduction opportunities; (2) implement practices to reduce methane emissions where feasible; and (3) annually report our methane emissions and/or our methane reduction activities. As part of the Methane Challenge Program, we have committed to annually replace or rehabilitate at least two percent of our combined inventory of cast iron and noncathodically-protected steel pipe, which aligns with our planned system integrity expenditures for infrastructure replacements. We exceeded our goal by achieving an overall replacement rate greater than two percent annually every year from 2016 through 2021 and anticipate reporting on our 2022 progress in 2023.

In September 2020, we announced membership in ONE Future, a group of natural gas companies working together to voluntarily reduce methane emissions across the natural gas value chain to one percent or less by 2025. We have submitted our 2020 and 2021 data, which ONE Future aggregates with peer members. In its most recent annual report, ONE Future stated that its members registered a 2021 methane intensity of 0.462 percent, which surpassed the 2025 goal of 1.0 percent. The intensity for the distribution sector, which includes us, was 0.113 percent, beating the 2021 goal of 0.225 percent by 50 percent. Participating distribution companies represented 47 percent of the natural gas delivered in the U.S. in 2021.

Additional information about our environmental matters is included in the section entitled “Environmental Matters” in Note 17 of the Notes to Consolidated Financial Statements in this Annual Report. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation, and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during 2022, 2021 or 2020.

Pipeline Safety - We are subject to regulation under federal pipeline safety statutes and any analogous state regulations. These include safety requirements for the design, construction, operation, and maintenance of pipelines, including transmission and distribution pipelines. At the federal level, we are regulated by PHMSA. PHMSA regulations require the following for certain pipelines: inspection and maintenance plans; integrity management programs, including the determination of pipeline integrity risks and periodic assessments on certain pipeline segments; an operator qualification program, which includes certain trainings; a public awareness program that provides certain information; and a control room management plan.

As part of regulating pipeline safety, PHMSA promulgates various regulations. In April 2016, PHMSA published a NPRM, the Safety of Gas Transmission & Gathering Lines Rule, in the Federal Register to revise pipeline safety regulations applicable to the safety of onshore natural gas transmission and gathering pipelines. Proposals included changes to pipeline integrity management requirements and other safety-related requirements, which were split into three separate rulemakings. At December 31, 2022, all three final rules have been published and the potential capital and operating expenditures associated with compliance were not material or did not apply to us.

Separately, as part of the Consolidated Appropriations Act, 2021, the PIPES Act of 2020 reauthorized PHMSA through 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemakings. Congress has also instructed PHMSA to issue final regulations that will require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations. To the extent such rulemakings impose more stringent requirements on our facilities, we may be required to incur expenditures that may be material.

Air and Water Emissions - The CAA, the Clean Water Act, and analogous state laws and/or regulations promulgated thereunder, impose restrictions and controls regarding the discharge of pollutants into the air and water in the United States. Failure to comply with these requirements may result in substantial fines or other penalties, including (in certain cases) the revocation of necessary permits. Under the CAA, a federally enforceable operating permit is required for sources of significant air emissions. We may be required to incur certain capital expenditures for air-pollution-control equipment in connection with obtaining or maintaining permits and approvals for sources of air emissions. Such expenditures have not had a material impact on our results of operations, financial position or cash flows; however, we cannot predict the impacts of any future requirements. The Clean Water Act imposes substantial potential liability for the discharge of pollutants into waters of the United States, including the potential for fines, civil enforcement, or orders to perform remediation of waters affected by such discharge.

Climate – The threat of climate change continues to attract considerable attention. International, federal, state and/or local statute and/or regulatory initiatives may be proposed in the future to regulate greenhouse gas emissions. We monitor relevant legislation and regulatory initiatives to assess the potential impact on our operations. On August 16, 2022, the IRA of 2022 was signed into law. The IRA of 2022 contains approximately $369 billion in climate funding, largely consisting of tax credits for clean energy. Based upon our review of the legislation, we do not anticipate it to have any material impacts on our future results of operations.

The EPA’s Mandatory Greenhouse Gas Reporting Rule requires annual greenhouse gas emissions reporting as carbon dioxide equivalents from affected facilities and for the natural gas delivered by us to our natural gas distribution customers who are not otherwise required to report their own emissions. The additional cost to gather and report this emission data did not have, and we do not expect it to have, a material impact on our results of operations, financial position or cash flows. In addition, Congress has considered, and may consider in the future, legislation to reduce greenhouse gas emissions, including carbon dioxide and methane. While the IRA of 2022 imposes a charge on methane emissions from certain facilities, the charge does not apply to distribution companies such as ONE Gas. Likewise, the EPA may institute additional regulatory rulemaking associated with greenhouse gas emissions. At this time, no rule or legislation has been enacted for natural gas distribution that assesses any costs, fees or expenses on any of these emissions.

Our operations may also be indirectly impacted by regulations attempting to limit or control climate impacts. For example, there is a risk that financial institutions may be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, President Biden signed an executive order calling for the development of a climate finance plan and, separately, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector.

Waste and Hazardous Substances - During the course of our operations, we may use or generate hazardous substances and wastes, including hazardous wastes. The generation, use, storage, transportation, handling, and disposal of such materials may be subject to federal, state, and local laws. For example, the Resource Conservation and Recovery Act regulates both solid and hazardous wastes, including the imposition of detailed requirements for the handling, storage, treatment, and disposal of hazardous wastes. Separately, CERCLA, also commonly known as Superfund, imposes strict, joint and several liability, without regard to fault or the legality of the original act, on certain classes of “persons” (defined under CERCLA). These persons include, but are not limited to, the owner or operator of a facility where the release occurred and/or companies that disposed or arranged for the disposal of the hazardous substances found at the facility. Under CERCLA, these persons may be liable for the costs of cleaning up the hazardous substances released into the environment, damages to natural resources and the costs of certain health studies.

Pipeline Security - In May and July 2021, TSA issued security directives which included several new cybersecurity requirements for critical pipeline owners and operators. The first security directive requires critical pipeline owners and operators to (1) report confirmed and potential cybersecurity incidents to the CISA; (2) designate a cybersecurity coordinator to be available 24 hours a day, seven days a week; (3) review current practices; and (4) identify any gaps and related remediation measures to address cyber-related risks and report the results to TSA and CISA within 30 days. The second security directive requires owners and operators of TSA-designated critical pipelines to implement specific mitigation measures to protect against ransomware and other known threats to information technology and operational technology systems, develop and implement a cybersecurity contingency and recovery plan, and conduct a cybersecurity architecture design review. Compliance with these measures has not had a material impact on our operations. We continue to evaluate the potential effect of these directives on our operations and facilities, as well as the potential cost of implementation, and will continue to monitor for any clarifications or amendments to these directives.

COVID-19 - Throughout the COVID-19 pandemic, we continued to provide essential services to our customers. We implemented a comprehensive set of policies, procedures and guidelines to protect the safety of our employees, customers and communities. Safety protocols developed during the pandemic include remote work for our office-based employees, limiting direct contact with our customers and requiring the use of PPE and a self-assessment health screening mobile application.

Impacts on our results of operations as a result of COVID-19 include but are not limited to:

•lower late payment, reconnect and collection fees and incremental expenses for bad debts related to the suspension of disconnects for nonpayment until the second quarter of 2021;

•incremental expenses for PPE, cleaning supplies, outside services and other expenses; and

•lower expenses for travel and employee training that have been impacted by the pandemic.

We received accounting orders in each of our jurisdictions authorizing us to accumulate and defer for regulatory purposes certain incremental costs incurred, including bad debt expenses, and certain lost revenues, net of offsetting expense reductions associated with COVID-19. Recovery of any net incremental costs and lost revenue deferred pursuant to these orders will be determined in future rate cases or alternative rate recovery filings in each jurisdiction. At December 31, 2022, we have not requested recovery of any deferrals pursuant to these orders and no regulatory assets have been recorded.

Regulatory - Several regulatory initiatives impacted the earnings and future earnings potential of our business. See additional information regarding our regulatory initiatives in “Regulatory Activities” in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

IMPACT OF NEW ACCOUNTING STANDARDS

Information about the impact of new accounting standards is included in Note 1 of the Notes to Consolidated Financial Statements in this Annual Report.

CRITICAL ESTIMATES AND ACCOUNTING POLICIES

The preparation of our consolidated financial statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates. See our “Risk Factors” and/or “Forward-Looking Statements” in this Annual Report for factors which could impact our estimates.

The following summary sets forth what we consider to be our most critical estimates and accounting policies. Our critical accounting policies are defined as those estimates and policies most important to the portrayal of our financial condition and results of operations and that require management’s most difficult, subjective or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters.

Regulation - Our operations are subject to regulation with respect to rates, service, maintenance of pipeline and accounting records and various other matters by the respective regulatory authorities in the states in which we operate. We account for the financial effects of the ratemaking and accounting practices and policies of the various regulatory authorities in our consolidated financial statements. We record regulatory assets for costs that have been deferred for which future recovery through customer rates is considered probable and regulatory liabilities when it is probable that revenues will be reduced for amounts that will be returned to customers through the ratemaking process. As a result, certain costs that would normally be expensed under GAAP are capitalized or deferred on the balance sheet because it is probable they can be recovered through rates. Discontinuing the application of this method of accounting for regulatory assets and liabilities 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. Further, regulation may impact the period in which revenues or expenses are recognized. The amounts to be recovered or recognized are based upon historical experience and our understanding of the regulations. The impact of regulation on our operations may be affected by decisions of the regulatory authorities or the issuance of new regulations.

For further discussion of regulatory assets and liabilities, see Note 10 of the Notes to Consolidated Financial Statements in this Annual Report.

Revenue Recognition - For regulated deliveries of natural gas, we read meters and bill customers on a monthly cycle. We recognize revenues upon the delivery of natural gas or services rendered to customers. The billing cycles for customers do not necessarily coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas that has been delivered but not yet billed at the end of an accounting period. Accrued unbilled revenue is based on a percentage estimate of amounts unbilled each month, which is dependent upon a number of factors, some of which require management’s judgment. These factors include customer consumption patterns and the impact of weather on usage. The accrued unbilled natural gas sales revenue at December 31, 2022 and 2021 was $269.5 million and $183.2 million, respectively, and is included in accounts receivable on our consolidated balance sheets.

We have determined the majority of our natural gas sales and transportation tariffs to be implied contracts with customers, which are settled over time, where our performance obligation is settled with our customer when natural gas is delivered and simultaneously consumed by the customer. In addition, we use the invoice method practical expedient, where we recognize revenue for volumes delivered for which we have a right to invoice. For our other utility revenue, which are primarily one-time service fees that meet the requirements under ASC 606, the performance obligation is satisfied at a point in time when services

are rendered to the customer. Certain revenues that do not meet the requirements under ASC 606 as revenues from contracts with customers are reflected as other revenues in determining total revenue. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report for additional information regarding our revenues.

Pension and Other Postemployment Benefits - We have defined benefit pension plans covering eligible retirees and full-time employees. We also sponsor welfare plans that provide other postemployment medical and life insurance benefits to eligible retirees and employees who retire with at least five years of service.

To calculate the expense and liabilities related to our plans, we utilize an outside actuarial consultant, which uses statistical and other factors to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and mortality and employment periods. We use tables issued by the Society of Actuaries to estimate mortality rates. In determining the projected benefit costs, assumptions can change from period to period and may result in material changes in the costs and liabilities we recognize.

For the year ended December 31, 2022, we contributed $1.5 million to our defined benefit pension plans and $1.9 million to our other postemployment benefit plans. For the year ended December 31, 2021, we contributed $1.0 million to our defined benefit pension plans and $2.0 million to our other postemployment benefit plans. In 2023, our contributions are expected to be $1.4 million to our defined benefit pension plans, and no contributions are expected to be made to our other postemployment benefit plans.

We recorded net periodic benefit costs for our defined benefit pension plans, prior to regulatory deferrals, of $5.0 million in 2022, and estimate that in 2023, we will record a credit of approximately $7.5 million. Net periodic benefits costs for our postemployment benefit plans, prior to regulatory deferrals, were a credit of $5.2 million in 2022, and we estimate that in 2023, we will record expense of approximately $0.3 million, prior to regulatory deferrals.

The following table sets forth the significant assumptions used to determine our estimated 2023 net periodic benefit cost related to our defined benefit pension and other postemployment benefit plans and sensitivity to changes with respect to these assumptions:


	Rate Used		Cost Sensitivity (a)		Obligation Sensitivity (b)
			(Millions of dollars)
Discount rate for pension	5.60	%	$	2.3	$	20.9
Discount rate for other postemployment benefits	5.70	%	$	(0.1)	$	3.6
Expected long-term return on plan assets for pension	6.75	%	$	2.2	$	—
Expected long-term return on plan assets for other postemployment benefits	5.55	%	$	0.4	$	—

(a) Approximate impact a quarter percentage point decrease in the assumed rate would have on net periodic pension costs.

(b) Approximate impact a quarter percentage point decrease in the assumed rate would have on defined benefit pension obligation.

See Note 14 of the Notes to Consolidated Financial Statements in this Annual Report for additional information regarding our pension and other postretirement benefit plans.

Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated. We expense legal fees as incurred and base our legal liability estimates on currently available facts and our assessments of the ultimate outcome or resolution. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than the completion of a remediation feasibility study. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effect on earnings or cash flows for the years ended December 31, 2022, 2021 and 2020. Environmental issues may exist with respect to these MGP sites that are unknown to us. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation required, changing technology and governmental regulations, and to the extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition, results of operations or cash flows.

See “Environmental Matters” and Note 17 of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of contingencies.

CONTRACTUAL OBLIGATIONS

Long-term debt, commercial paper borrowings and interest payments on debt - Long-term debt includes our Senior Notes and Securitized Utility Tariff Bonds. See Notes 3 and 4 in the Notes to Consolidated Financial Statements in this Annual Report for additional information on our long-term debt, commercial paper borrowings and interest payments on our debt. Interest payments on debt are calculated by multiplying our long-term debt by the respective coupon rates or effective floating rate.

Firm transportation and storage contracts - We are party to fixed-price contracts providing us with firm transportation and storage capacity. The commitments associated with these contracts are recoverable through our purchased-gas cost mechanisms as allowed by the applicable regulatory authority.

Natural gas purchase commitments - We are party to fixed-price and variable-price contracts for the purchase of natural gas. Future variable-price natural gas purchase commitments are estimated based on market price information as of December 31, 2022. Actual future variable-price purchase commitments may vary depending on market prices at the time of delivery. As market information changes daily and is potentially volatile, these values may change significantly. The commitments associated with these contracts are recoverable through our purchased-gas cost mechanisms as allowed by the applicable regulatory authority.

Operating leases - Our operating leases consist primarily of office facilities and IT leases. See Note 5 of the Notes to Consolidated Financial Statements in this Annual Report for discussion of leases.

FORWARD-LOOKING STATEMENTS

Some of the statements contained and incorporated in this Annual Report are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. The forward-looking statements relate to our anticipated financial performance, liquidity, management’s plans and objectives for our future operations, our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this Annual Report identified by words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled,” “likely,” and other words and terms of similar meaning.

One should not place undue reliance on forward-looking statements, which are applicable only as of the date of this Annual Report. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, costs, liquidity, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:

•our ability to recover costs (including operating costs and increased commodity costs related to Winter Storm Uri in February 2021), income taxes and amounts equivalent to the cost of property, plant and equipment, regulatory assets and our allowed rate of return in our regulated rates or other recovery mechanisms;

•cyber-attacks, which, according to experts, have increased in volume and sophistication since the beginning of the COVID-19 pandemic, or breaches of technology systems that could disrupt our operations or result in the loss or exposure of confidential or sensitive customer, employee or Company information; further, increased remote working arrangements as a result of the pandemic have required enhancements and modifications to our IT infrastructure (e.g. Internet, Virtual Private Network, remote collaboration systems, etc.), and any failures of the technologies, including third-party service providers, that facilitate working remotely could limit our ability to conduct ordinary operations or expose us to increased risk or effect of an attack;

•our ability to manage our operations and maintenance costs;

•the concentration of our operations in Oklahoma, Kansas, and Texas;

•changes in regulation of natural gas distribution services, particularly those in Oklahoma, Kansas and Texas;

•the economic climate and, particularly, its effect on the natural gas requirements of our residential and

commercial customers;

•the length and severity of a pandemic or other health crisis, such as the outbreak of COVID-19, including the impact to our operations, customers, contractors, vendors and employees, the effectiveness of vaccine campaigns (including the COVID-19 vaccine campaign) on our workforce and customers and the effect of other measures or mandates that international, federal, state and local governments, agencies, law enforcement and/or health authorities implement to address the pandemic or other health crisis, which could (as with COVID-19) precipitate or exacerbate one or more of the above-mentioned and/or other risks, and significantly disrupt or prevent us from operating our business in the ordinary course for an extended period;

•competition from alternative forms of energy, including, but not limited to, electricity, solar power, wind power, geothermal energy and biofuels;

•adverse weather conditions and variations in weather, including seasonal effects on demand and/or supply, the occurrence of severe storms in the territories in which we operate, and climate change, and the related effects on supply, demand, and costs;

•indebtedness could make us more vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantage compared with competitors;

•our ability to secure reliable, competitively priced and flexible natural gas transportation and supply, including decisions by natural gas producers to reduce production or shut-in producing natural gas wells and expiration of existing supply and transportation and storage arrangements that are not replaced with contracts with similar terms and pricing;

•our ability to complete necessary or desirable expansion or infrastructure development projects, which may delay or prevent us from serving our customers or expanding our business;

•operational and mechanical hazards or interruptions;

•adverse labor relations;

•the effectiveness of our strategies to reduce earnings lag, revenue protection strategies and risk mitigation strategies, which may be affected by risks beyond our control such as commodity price volatility, counterparty performance or creditworthiness and interest rate risk;

•the capital-intensive nature of our business, and the availability of and access to, in general, funds to meet our debt obligations prior to or when they become due and to fund our operations and capital expenditures, either through (i) cash on hand, (ii) operating cash flow, or (iii) access to the capital markets and other sources of liquidity;

•our ability to obtain capital on commercially reasonable terms, or on terms acceptable to us, or at all;

•limitations on our operating flexibility, earnings and cash flows due to restrictions in our financing arrangements;

•cross-default provisions in our borrowing arrangements, which may lead to our inability to satisfy all of our outstanding obligations in the event of a default on our part;

•changes in the financial markets during the periods covered by the forward-looking statements, particularly those affecting the availability of capital and our ability to refinance existing debt and fund investments and acquisitions to execute our business strategy;

•actions of rating agencies, including the ratings of debt, general corporate ratings and changes in the rating agencies’ ratings criteria;

•changes in inflation and interest rates;

•our ability to recover the costs of natural gas purchased for our customers, including those related to Winter Storm Uri and any related financing required to support our purchase of natural gas supply, including the securitized financing currently contemplated in Texas;

•impact of potential impairment charges;

•volatility and changes in markets for natural gas and our ability to secure additional and sufficient liquidity on reasonable commercial terms to cover costs associated with such volatility;

•possible loss of LDC franchises or other adverse effects caused by the actions of municipalities;

•payment and performance by counterparties and customers as contracted and when due, including our counterparties maintaining ordinary course terms of supply and payments;

•changes in existing or the addition of new environmental, safety, tax and other laws to which we and our subsidiaries are subject, including those that may require significant expenditures, significant increases in operating costs or, in the case of noncompliance, substantial fines or penalties;

•the effectiveness of our risk-management policies and procedures, and employees violating our risk-management policies;

•the uncertainty of estimates, including accruals and costs of environmental remediation;

•advances in technology, including technologies that increase efficiency or that improve electricity’s competitive position relative to natural gas;

•population growth rates and changes in the demographic patterns of the markets we serve, and economic conditions in these areas’ housing markets;

•acts of nature and the potential effects of threatened or actual terrorism and war, including recent events in Europe;

•the sufficiency of insurance coverage to cover losses;

•the effects of our strategies to reduce tax payments;

•the effects of litigation and regulatory investigations, proceedings, including our rate cases, or inquiries and the requirements of our regulators as a result of the Tax Cuts and Jobs Act of 2017;

•changes in accounting standards;

•changes in corporate governance standards;

•existence of material weaknesses in our internal controls;

•our ability to comply with all covenants in our indentures and the ONE Gas Credit Agreement, a violation of which, if not cured in a timely manner, could trigger a default of our obligations;

•our ability to attract and retain talented employees, management and directors, and shortage of skilled-labor;

•unexpected increases in the costs of providing health care benefits, along with pension and postemployment health care benefits, as well as declines in the discount rates on, declines in the market value of the debt and equity securities of, and increases in funding requirements for, our defined benefit plans; and

•our ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future results. These and other risks are described in greater detail in Part 1, Item 1A, Risk Factors, in this Annual Report. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to market risk discussed below includes forward-looking statements. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur since actual gains and losses will differ from those estimated based on actual fluctuations in commodity prices or interest rates and the timing of transactions.

Commodity Price Risk

Our commodity price risk, driven primarily by fluctuations in the price of natural gas, is mitigated by our purchased-gas cost adjustment mechanisms through which we pass-through natural gas costs to our customers without profit. We may use derivative instruments to hedge the cost of a portion of our anticipated natural gas purchases during the winter heating months to reduce the impact on our customers of upward market price volatility of natural gas. Additionally, we inject natural gas into storage during the summer months, when natural gas prices are typically lower, and withdraw the natural gas during the winter heating season. Gains or losses associated with these derivative instruments and storage activities are included in, and recoverable through our purchased-gas cost adjustment mechanisms, which are subject to review by regulatory authorities.

Interest-Rate Risk

We are exposed to interest-rate risk primarily associated with commercial paper borrowings, borrowings under our credit agreement, and new debt financing needed to fund capital requirements, including future contractual obligations and maturities of long-term and short-term debt. We may manage interest-rate risk on future borrowings through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps. Fixed-rate swaps may be used to reduce our risk of increased interest costs during periods of rising interest rates. Floating-rate swaps may be used to convert the fixed rates of long-term borrowings into short-term variable rates.

Counterparty Credit Risk

We assess the creditworthiness of our customers. Those customers who do not meet minimum standards are required to provide security, including deposits or other forms of collateral, when appropriate and allowed by tariff. With approximately 2.3 million customers across three states, we are not exposed materially to a concentration of credit risk. We maintain a provision for doubtful accounts based upon factors surrounding the credit risk of customers, historical trends, consideration of the current

credit environment and other information. We are able to recover the fuel-related portion of bad debts through our purchased-gas cost adjustment mechanisms.

ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of ONE Gas, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of ONE Gas, Inc. and its subsidiaries (the “Company”) as of December 31, 2022 and 2021, and the related consolidated statements of income, of comprehensive income, of equity and of cash flows for each of the three years in the period ended December 31, 2022, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (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 audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated 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 consolidated 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 consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters 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.

Accounting for the Effects of Regulatory Matters

As described in Notes 1 and 10 to the consolidated financial statements, the Company is subject to rate regulation and accounting requirements of regulatory authorities in the states in which it operates, and it follows the accounting and reporting guidance for regulated operations, including evaluating regulatory decisions to determine appropriate revenue recognition, cost deferrals, recoverability for regulatory assets and refund requirements for regulatory liabilities. As disclosed by management, regulatory assets are recorded for costs that have been deferred for which future recovery through customer rates is considered probable and 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. As a result, certain costs that would normally be expensed under accounting principles generally accepted in the United States of America for non-regulated entities are capitalized or deferred on the balance sheet because it is probable they can be recovered through rates. The amounts to be recovered or recognized are based upon historical experience and management’s understanding of regulations and may be affected by decisions of the regulatory authorities or the issuance of new regulations. Should recovery cease due to regulatory actions, certain regulatory assets may no longer meet the criteria for recognition, and accordingly, the Company may be required to write off the regulatory assets at that time. As described in Note 10, in August 2022, the proceeds received related to the securitization of the costs related to the winter weather event reflected the recovery of the related regulatory asset. As of December 31, 2022, there were $606 million of deferred costs included in regulatory assets and $577 million of regulatory liabilities awaiting cash outflow or potential refund.

The principal considerations for our determination that performing procedures relating to the Company’s accounting for the effects of regulatory matters is a critical audit matter are (i) the significant judgment by management in evaluating the impact of regulatory orders and accounting guidance on relevant transactions and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to management’s evaluation of revenue recognition, cost deferrals, and recoverability of regulatory assets, including the securitization of the costs related to the winter weather event and the recovery of the related regulatory assets, and refund requirements for regulatory liabilities.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the impact of regulatory orders and accounting guidance on relevant transactions, including controls over management’s process for evaluating and recording (i) deferred costs, including the amounts to be deferred and the future recovery, resulting in regulatory assets or (ii) a reduction to revenues for amounts that will be credited to customers, resulting in regulatory liabilities. These procedures also included, among others, (i) evaluating management’s process for identifying relevant transactions which require application of regulatory accounting guidance; (ii) evaluating the reasonableness of management’s assessment regarding revenue recognition, probability of recovery and establishment of regulatory assets, including the securitization of the costs related to the winter weather event and the recovery of the related regulatory assets, and the establishment of regulatory liabilities; and (iii) testing the regulatory assets and regulatory liabilities considering the provisions and formulas outlined in rate orders and other regulatory correspondence.

/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma

February 23, 2023

We have served as the Company’s auditor since 2013.

This page intentionally left blank.


ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31,
	2022		2021		2020
	(Thousands of dollars, except per share amounts)

Total revenues	$	2,578,005	$	1,808,597	$	1,530,268

Cost of natural gas	1,459,087		775,006		537,445

Operating expenses
Operations and maintenance	472,265		449,676		431,115
Depreciation and amortization	228,479		207,233		194,881
General taxes	68,217		66,424		63,311
Total operating expenses	768,961		723,333		689,307
Operating income	349,957		310,258		303,516
Other expense, net	(4,183)		(3,207)		(3,020)
Interest expense, net	(77,506)		(60,301)		(62,505)
Income before income taxes	268,268		246,750		237,991
Income taxes	(46,526)		(40,316)		(41,579)
Net income	$	221,742	$	206,434	$	196,412

Earnings per share
Basic	$	4.09	$	3.85	$	3.70
Diluted	$	4.08	$	3.85	$	3.68

Average shares (thousands)
Basic	54,207		53,575		53,133
Diluted	54,338		53,674		53,370
Dividends declared per share of stock	$	2.48	$	2.32	$	2.16

See accompanying Notes to Consolidated Financial Statements.


ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Years Ended December 31,
	2022		2021		2020
	(Thousands of dollars)
Net income	$	221,742	$	206,434	$	196,412
Other comprehensive income (loss), net of tax
Change in pension and other postemployment benefit plans liability, net of tax of $(1,705), $(379), and $289, respectively	5,823		1,250		(1,038)

Total other comprehensive income (loss), net of tax	5,823		1,250		(1,038)
Comprehensive income	$	227,565	$	207,684	$	195,374

See accompanying Notes to Consolidated Financial Statements.


ONE Gas, Inc.
CONSOLIDATED BALANCE SHEETS

	December 31,		December 31,
	2022		2021
Assets	(Thousands of dollars)
Property, plant and equipment
Property, plant and equipment	$	7,834,557	$	7,274,268
Accumulated depreciation and amortization	2,205,717		2,083,433
Net property, plant and equipment	5,628,840		5,190,835
Current assets
Cash and cash equivalents	9,681		8,852
Restricted cash and cash equivalents	8,446		—
Total cash, cash equivalents and restricted cash and cash equivalents	18,127		8,852
Accounts receivable, net	553,834		341,756
Materials and supplies	70,873		54,892

Natural gas in storage	269,205		179,646
Regulatory assets	275,572		1,611,676

Other current assets	29,997		27,742
Total current assets	1,217,608		2,224,564
Goodwill and other assets
Regulatory assets	330,831		724,862
Securitized intangible asset, net	323,838		—
Goodwill	157,953		157,953

Other assets	117,326		103,906
Total goodwill and other assets	929,948		986,721
Total assets	$	7,776,396	$	8,402,120

See accompanying Notes to Consolidated Financial Statements.


ONE Gas, Inc.
CONSOLIDATED BALANCE SHEETS
(Continued)
	December 31,		December 31,
	2022		2021
Equity and Liabilities	(Thousands of dollars)
Equity and long-term debt
Common stock, $0.01 par value: authorized 250,000,000 shares; issued and outstanding 55,349,954 shares at December 31, 2022; issued and outstanding 53,633,210 shares at December 31, 2021	$	553	$	536
Paid-in capital	1,932,714		1,790,362
Retained earnings	651,863		565,161
Accumulated other comprehensive loss	(704)		(6,527)

Total equity	2,584,426		2,349,532
Other long-term debt, excluding current maturities, net of issuance costs	2,352,400		3,683,378
Securitized utility tariff bonds, excluding current maturities, net of issuance costs	309,343		—
Total-long term debt, excluding current maturities, net of issuance costs	2,661,743		3,683,378
Total equity and long-term debt	5,246,169		6,032,910
Current liabilities

Current maturities of securitized utility tariff bonds	20,716		—
Notes payable	552,000		494,000
Accounts payable	360,493		258,554

Accrued taxes other than income	78,352		67,035

Regulatory liabilities	47,867		8,090
Customer deposits	57,854		62,454
Other current liabilities	72,137		90,360
Total current liabilities	1,189,419		980,493
Deferred credits and other liabilities
Deferred income taxes	698,456		695,284
Regulatory liabilities	529,441		552,928
Employee benefit obligations	19,587		35,226

Other deferred credits	93,324		105,279
Total deferred credits and other liabilities	1,340,808		1,388,717
Commitments and contingencies
Total liabilities and equity	$	7,776,396	$	8,402,120

See accompanying Notes to Consolidated Financial Statements.


ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Years Ended December 31,
	2022		2021		2020
	(Thousands of dollars)
Operating activities
Net income	$	221,742	$	206,434	$	196,412
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	228,479		207,233		194,881
Deferred income taxes	(22,034)		43,449		18,485
Share-based compensation expense	10,741		10,498		9,803
Provision for doubtful accounts	6,003		9,131		15,450
Proceeds from government securitization of winter weather event costs	1,330,582		—		—
Changes in assets and liabilities:
Accounts receivable	(213,656)		(57,902)		(58,423)
Materials and supplies	(15,981)		(2,126)		2,966

Natural gas in storage	(89,559)		(85,700)		10,313
Asset removal costs	(47,032)		(49,029)		(40,833)
Accounts payable	85,915		107,207		28,376

Accrued taxes other than income	11,317		3,235		15,844

Customer deposits	(4,600)		(5,574)		10,041
Regulatory assets and liabilities - current	52,417		(1,562,574)		(38,773)
Regulatory assets and liabilities - noncurrent	53,992		(367,210)		23,648
Employee benefit obligation	—		—		(3,109)
Other assets and liabilities - current	(23,377)		18,461		(12,877)
Other assets and liabilities - noncurrent	(14,107)		(11,190)		(7,704)
Cash provided by (used in) operating activities	1,570,842		(1,535,657)		364,500
Investing activities
Capital expenditures	(609,486)		(495,246)		(471,345)
Other investing expenditures	(8,632)		(7,554)		(2,804)
Other investing receipts	4,008		1,717		3,777
Cash used in investing activities	(614,110)		(501,083)		(470,372)
Financing activities
Borrowings (repayment) on notes payable, net	58,000		75,775		(98,275)

Issuance of other long-term debt, net of discounts	297,591		2,498,895		298,428
Issuance of securitized utility tariff bonds, net of discounts	335,931		—		—
Long-term debt financing costs	(8,567)		(35,110)		(2,885)
Issuance of common stock	133,711		26,662		19,383
Repayment of other long-term debt	(1,627,000)		(400,000)		—
Dividends paid	(133,954)		(123,912)		(114,372)
Tax withholdings related to net share settlements of stock compensation	(3,169)		(4,711)		(6,267)
Cash provided by (used in) financing activities	(947,457)		2,037,599		96,012
Change in cash, cash equivalents, restricted cash and restricted cash equivalents	9,275		859		(9,860)
Cash, cash equivalents, restricted cash and restricted cash equivalents at beginning of period	8,852		7,993		17,853
Cash, cash equivalents, restricted cash and restricted cash equivalents at end of period	$	18,127	$	8,852	$	7,993
Supplemental cash flow information:
Cash paid for interest, net of amounts capitalized	$	84,871	$	70,066	$	60,126
Cash paid (received) for income taxes, net	$	67,421	$	(10,809)	$	30,361

See accompanying Notes to Consolidated Financial Statements.


ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF EQUITY

	Common Stock Issued	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income/(Loss)		Total Equity
	(Shares)	(Thousands of dollars)

January 1, 2020	52,771,749	$	528	$	1,733,092	$	402,509	$	(6,739)	$	2,129,390
Net income	—	—		—		196,412		—		196,412
Other comprehensive loss	—	—		—		—		(1,038)		(1,038)
Common stock issued and other	394,984	4		22,915		—		—		22,919
Common stock dividends - $2.16 per share	—	—		914		(115,286)		—		(114,372)
December 31, 2020	53,166,733	532		1,756,921		483,635		(7,777)		2,233,311
Net income	—	—		—		206,434		—		206,434
Other comprehensive income	—	—		—		—		1,250		1,250
Common stock issued and other	466,477	4		32,445		—		—		32,449
Common stock dividends - $2.32 per share	—	—		996		(124,908)		—		(123,912)
December 31, 2021	53,633,210	536		1,790,362		565,161		(6,527)		2,349,532
Net income	—	—		—		221,742		—		221,742
Other comprehensive income	—	—		—		—		5,823		5,823
Common stock issued and other	1,716,744	17		141,266		—		—		141,283
Common stock dividends - $2.48 per share	—	—		1,086		(135,040)		—		(133,954)
December 31, 2022	55,349,954	$	553	$	1,932,714	$	651,863	$	(704)	$	2,584,426
See accompanying Notes to Consolidated Financial Statements.

ONE Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Nature of Operations - We provide natural gas distribution services to approximately 2.3 million customers in Oklahoma, Kansas and Texas through our three divisions, Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. We primarily serve residential, commercial and transportation customers in all three states. We are a corporation incorporated under the laws of the state of Oklahoma, and our common stock is listed on the NYSE under the trading symbol “OGS.”

Basis of Presentation - The consolidated financial statements include the accounts of our natural gas distribution business as set forth in “Organization and Nature of Operations” above. All significant balances and transactions between our subsidiaries have been eliminated.

Use of Estimates - The preparation of our consolidated financial statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, provisions for doubtful accounts receivable, unbilled revenues for natural gas delivered but for which meters have not been read, natural gas purchased but for which no invoice has been received, provision for income taxes, including any deferred income tax valuation allowances, the results of litigation and various other recorded or disclosed amounts.

We evaluate these estimates on an ongoing basis using historical experience and other methods we consider reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on our financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known.

Revenues - We recognize revenue from contracts with customers to depict the transfers of goods and services to customers at an amount that we expect to be entitled to receive in exchange for these goods and services. Our sources of revenue are disaggregated by natural gas sales, transportation revenues, and miscellaneous revenues, which are primarily one-time service fees, that meet the requirements of ASC 606. Certain revenues that do not meet the requirements of ASC 606 are classified as other revenues in our Notes to Consolidated Financial Statements in this Annual Report.

Our natural gas sales to customers and transportation revenues represent revenues from contracts with customers through implied contracts established by our tariffs approved by regulatory authorities. Our customers receive the benefits of our performance when the commodity is delivered to the customer. The performance obligation is satisfied over time as the customer receives the natural gas.

For deliveries of natural gas, we read meters and bill customers on a monthly cycle. We recognize revenues upon the delivery of natural gas or services rendered to customers. The billing cycles for customers do not necessarily coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas that has been delivered but not yet billed at the end of an accounting period. We use the invoice method practical expedient, where we recognize revenue for volumes delivered for which we have a right to invoice. Our estimate of accrued unbilled revenue is based on a percentage estimate of amounts unbilled each month, which is dependent upon a number of factors, some of which require management’s judgment. These factors include customer consumption patterns and the impact of weather on usage. The accrued unbilled natural gas sales revenue at December 31, 2022 and 2021 was $269.5 million and $183.2 million, respectively, and is included in accounts receivable on our consolidated balance sheets.

Our miscellaneous revenues from contracts with customers represent implied contracts established by our tariff rates approved by the regulatory authorities and include miscellaneous utility services with the performance obligation satisfied at a point in time when services are rendered to the customer.

Total other revenues consist of revenues associated with regulatory mechanisms that do not meet the requirements of ASC 606 as revenue from contracts with customers, but authorize us to accrue revenues earned based on tariffs approved by regulatory authorities. Other revenues - natural gas sales primarily relate to the WNA mechanism in Kansas. This mechanism adjusts our revenues earned for the variance between actual and normal HDDs. This mechanism can have either positive

(warmer than normal) or negative (colder than normal) effects on revenues.

We collect and remit other taxes on behalf of governmental authorities, and we record these amounts in accrued taxes other than income in our consolidated balance sheets. See Note 2 for additional discussion of revenues.

Cost of Natural Gas - Cost of natural gas includes commodity purchases, fuel, storage, transportation and other gas purchase costs recovered through our cost of natural gas regulatory mechanisms and does not include an allocation of general operating costs or depreciation and amortization. These cost of natural gas regulatory mechanisms provide a method of recovering natural gas costs on an ongoing basis without a profit. See Note 10 for additional discussion of purchased gas cost recoveries.

Cash, Cash Equivalents and Restricted Cash and Cash Equivalents - Cash and cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less. Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our consolidated balance sheets. Restricted cash and cash equivalents accounts were established for payment of Securitized Utility Tariff Bond issuance costs and payment of debt service on those bonds.

Accounts Receivable - Accounts receivable represent valid claims against nonaffiliated customers for natural gas sold or services rendered, net of an allowance for doubtful accounts. We assess the creditworthiness of our customers. Those customers who do not meet minimum standards may be required to provide security, including deposits and other forms of collateral, when appropriate and allowed by our tariffs. With approximately 2.3 million customers across three states, we are not exposed materially to a concentration of credit risk. We maintain an allowance for doubtful accounts based upon factors surrounding the credit risk of customers, historical trends, consideration of the current credit environment and other information. We are able to recover natural gas costs related to uncollectible accounts through purchased-gas cost adjustment mechanisms. At December 31, 2022 and 2021, our allowance for doubtful accounts was $16.7 million and $18.7 million, respectively.

Inventories - Natural gas in storage is accounted for on the basis of weighted-average cost. Materials and supplies inventories are stated at the lower of weighted-average cost or net realizable value.

Leases - We determine if an arrangement is a lease at inception if the contract conveys the right to control the use and obtain substantially all the economic benefits from the use of an identified asset for a period of time in exchange for consideration. We identify a lease as a finance lease if the agreement includes any of the following criteria: transfer of ownership by the end of the lease term; an option to purchase the underlying asset that the lessee is reasonably certain to exercise; a lease term that represents 75 percent or more of the remaining economic life of the underlying asset; a present value of lease payments and any residual value guaranteed by the lessee that equals or exceeds 90 percent of the fair value of the underlying asset; or an underlying asset that is so specialized in nature that there is no expected alternative use to the lessor at the end of the lease term. A lease that does not meet any of these criteria is considered an operating lease.

Lease right-of-use assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Right-of-use assets and liabilities are recognized at the commencement date of a lease based on the present value of lease payments over the lease term. Our lease terms may include options to extend or terminate the lease. We include these extension or termination options in the determination of the lease term when it is reasonably certain that we will exercise that option. We have lease agreements with lease and non-lease components, which are accounted for separately. Additionally, for certain office equipment leases, we apply a portfolio approach to effectively account for the operating lease right-of-use assets and liabilities. We do not recognize leases having a term of less than one year in our consolidated balance sheets.

For purposes of determining the present value of the lease payments, we use a lease’s implicit interest rate when readily determinable. As most of our leases do not provide an implicit interest rate, we use an incremental borrowing rate based on available information at the commencement of the lease. Lease cost for operating leases is recognized on a straight-line basis over the lease term. See Note 5 for additional information regarding our leases.

Derivatives and Risk Management Activities - We record all derivative instruments at fair value, with the exception of normal purchases and normal sales that are expected to result in physical delivery. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it, or if regulatory requirements impose a different accounting treatment.

If certain conditions are met, we may elect to designate a derivative instrument as a hedge of exposure to changes in fair values or cash flows. We have not elected to designate any of our derivative instruments as hedges.

The table below summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements:

Recognition and Measurement

Accounting Treatment

Balance Sheet

Income Statement

Normal purchases and
normal sales

Fair value not recorded

Change in fair value not recognized in earnings

Mark-to-market

Recorded at fair value

Change in fair value recognized in, and
recoverable through, the purchased-gas cost adjustment mechanisms

See Note 9 for additional information regarding our economic hedging activities using derivatives.

Fair Value Measurements - We define fair value as the price that would be received from the sale of an asset or the transfer of a liability in an orderly transaction between market participants at the measurement date. We use the market and income approaches to determine the fair value of our assets and liabilities and consider the markets in which the transactions are executed. We measure the fair value of a group of financial assets and liabilities consistent with how a market participant would price the net risk exposure at the measurement date.

Fair Value Hierarchy - At each balance sheet date, we utilize a fair value hierarchy to classify fair value amounts recognized or disclosed in our consolidated financial statements based on the observability of inputs used to estimate such fair value. The levels of the hierarchy are described below:

•Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities;

•Level 2 - Significant observable pricing inputs other than quoted prices included within Level 1 that are, either directly or indirectly, observable as of the reporting date. Essentially, this represents inputs that are derived principally from or corroborated by observable market data; and

•Level 3 - May include one or more unobservable inputs that are significant in establishing a fair value estimate. These unobservable inputs are developed based on the best information available and may include our own internal data.

We recognize transfers into and out of the levels as of the end of each reporting period.

Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data. We categorize derivatives for which fair value is determined using multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety. See Note 9 for additional information regarding our fair value measurements.

Property, Plant and Equipment - Our properties are stated at cost, which includes direct construction costs such as direct labor, materials, burden and AFUDC. Generally, the cost of our property retired or sold, plus removal costs, less salvage, is charged to accumulated depreciation. Gains and losses from sales or retirement of an entire operating unit or system of our properties are recognized in income. Maintenance and repairs are charged directly to expense.

AFUDC represents the cost of borrowed funds used to finance construction activities. We capitalize interest costs during the construction or upgrade of qualifying assets. Capitalized interest is recorded as a reduction to interest expense.

Our properties are depreciated using the straight-line method over their estimated useful lives. Generally, we apply composite depreciation rates to functional groups of property having similar economic circumstances. We periodically conduct depreciation studies to assess the economic lives of our assets. These depreciation studies are completed as a part of our regulatory proceedings, and the changes in economic lives, if applicable, are implemented prospectively when the new rates are approved by our regulators and become effective. Changes in the estimated economic lives of our property, plant and equipment could have a material effect on our financial position, results of operations or cash flows.

Property, plant and equipment on our consolidated balance sheets includes construction work in process for capital projects that have not yet been placed in service and therefore are not being depreciated. Assets are transferred out of construction work in process when they are substantially complete and ready for their intended use.

See Note 12 for additional information regarding our property, plant and equipment.

Impairment of Goodwill and Long-Lived Assets - We assess our goodwill for impairment at least annually as of July 1, unless events or a change in circumstances indicate an impairment may have occurred before that time. As part of our goodwill impairment test, we first assess qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance) to determine whether it is more likely than not that our fair value is less than the carrying amount of our net assets. If further testing is necessary or a quantitative test is elected to refresh our recurring qualitative assessment, we perform a quantitative impairment test for goodwill.

Our impairment assessment is performed by comparing our fair value with our book value, including goodwill. If the fair value is less than the book value, an impairment is measured by the amount of our carrying value that exceeds fair value, not to exceed the carrying amount of our goodwill.

To estimate fair value, we use two generally accepted valuation approaches, an income approach and a market approach, using assumptions consistent with a market participant’s perspective. Under the income approach, we use anticipated cash flows over a period of years plus a terminal value and discount these amounts to their present value using appropriate discount rates. Under the market approach, we apply acquisition multiples to forecasted cash flows. The acquisition multiples used are consistent with historical market transactions. The forecasted cash flows are based on average forecasted cash flows over a period of years.

Our goodwill impairment analysis performed in 2022 and 2021 utilized a qualitative assessment and did not result in any impairment indicators, nor did our analysis reflect our reporting unit at risk. Subsequent to July 1, 2022, no event has occurred indicating that it is more likely than not that our fair value is less than the carrying value of our net assets.

We assess our long-lived assets for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. An impairment is indicated if the carrying amount of a long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If an impairment is indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset. We determined that there were no material asset impairments in 2022, 2021 or 2020.

Securitized Intangible Asset - On November 18, 2022, KGSS-I acquired the Securitized Utility Tariff Property from Kansas Gas Service for $327.4 million. The Securitized Utility Tariff Property is classified as a securitized intangible asset on our consolidated balance sheets. This securitized intangible asset will be amortized over 10 years, the estimated period needed to collect the required amounts from Kansas Gas Service’s customers to service the Securitized Utility Tariff Bonds. The amortization expense related to the securitized intangible asset will be included in depreciation and amortization expense in our consolidated statements of income. For the year ended December 31, 2022, we recorded $3.5 million of amortization expense related to the securitized intangible asset. At the end of its life, this securitized intangible asset will have no residual value. See Note 4 for additional information about the Securitized Utility Tariff Bonds and Notes 10 and 11 for additional information about the securitization transaction.

Finite-lived intangible assets are stated at cost, net of accumulated amortization, which is recorded on a straight-line or accelerated basis over the life of the asset. We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value.

Regulation - We are subject to the rate regulation and accounting requirements of the OCC, KCC, RRC and various municipalities in Texas. We follow the accounting and reporting guidance for regulated operations, including evaluating regulatory decisions to determine appropriate revenue recognition, cost deferrals and recoverability for regulatory assets and refund requirements for regulatory liabilities. During the ratemaking process, regulatory authorities set the framework for what we can charge customers for our services and establish the manner that our costs are accounted for, including allowing us to defer recognition of certain costs and permitting recovery of the amounts through rates over time, as opposed to expensing such costs as incurred. Examples include weather normalization, unrecovered purchased-gas costs, extraordinary costs associated with Winter Storm Uri, pension and postemployment benefit costs and ad-valorem taxes. This allows us to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. Actions by regulatory authorities could have an effect on the amount recovered from customers. Any difference in the amount recoverable and the amount deferred is recorded as income or expense at the time of the regulatory action. A write-off of regulatory assets and costs not recovered may be required if all or a portion of the regulated operations have rates that are no longer:

•established by independent regulators;

•designed to recover our costs of providing regulated services; and

•set at levels that will recover our costs when considering the demand and competition for our services.

Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria for recognition and accordingly, a write-off of regulatory assets and stranded costs may be required. There were no write-offs of regulatory assets resulting from the failure to meet the criteria for capitalization during 2022, 2021 and 2020.

See Note 10 for additional information regarding our regulatory assets and liabilities.

Pension and Other Postemployment Employee Benefits - We have defined benefit pension plans covering eligible employees. We also sponsor welfare plans that provide other postemployment medical and life insurance benefits to eligible employees who retire with at least five years of service. To calculate the costs and liabilities related to our plans, we utilize an outside actuarial consultant, which uses statistical and other factors to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and mortality and employment periods. We use tables issued by the Society of Actuaries to estimate mortality rates. In determining the projected benefit obligations and costs, assumptions can change from period to period and may result in material changes in the cost and liabilities we recognize.

Income Taxes - Deferred income taxes are recorded for the difference between the financial statement and income tax basis of assets and liabilities and carryforward items, based on income tax laws and rates existing at the time the temporary differences are expected to reverse. The effect on deferred income taxes of a change in tax rates is deferred and amortized for operations regulated by the OCC, KCC, RRC and various municipalities in Texas, if, as a result of an action by a regulator, it is probable that the effect of the change in tax rates will be recovered from or returned to customers through future rates. We continue to amortize previously deferred investment tax credits for ratemaking purposes over the periods prescribed by our regulators.

A valuation allowance for deferred income tax assets is recognized when it is more likely than not that some or all of the benefit from the deferred income tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred income tax liabilities, as well as the current and forecasted business economics of our industry. We had no valuation allowance at December 31, 2022 and 2021.

We utilize a more-likely-than-not recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position that is taken or expected to be taken in a tax return. We reflect penalties and interest as part of income tax expense as they become applicable for tax provisions that do not meet the more-likely-than-not recognition threshold and measurement attribute. There were no material uncertain tax positions at December 31, 2022 and 2021.

Changes in tax laws or tax rates are recognized in the financial reporting period that includes the enactment date.

See Note 15 for additional information regarding income taxes.

Asset Retirement Obligations - Asset retirement obligations represent legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. Certain long-lived assets that comprise our natural gas distribution systems, primarily our pipeline assets, are subject to agreements or regulations that give rise to an asset retirement obligation for removal or other disposition costs associated with retiring the assets in place upon the discontinued use of the natural gas distribution system. We recognize the fair value of a liability for an asset retirement obligation in the period when it is incurred if a reasonable estimate of the fair value can be made. We are not able to estimate reasonably the fair value of the asset retirement obligations for portions of our assets because the settlement dates are indeterminable given our expected continued use of the assets with proper maintenance. We expect our natural gas distribution systems will continue in operation for the foreseeable future. Based on our proximity to significant natural gas reserves and infrastructure and the widespread use of natural gas for heating and cooking activities by residential and commercial customers in our service areas, we expect supply and demand to exist for the foreseeable future.

In accordance with long-standing regulatory treatment, we collect through rates the estimated costs of removal on certain regulated properties through depreciation expense as a portion of the net salvage value component of our composite deprecation rates, with a corresponding credit to accumulated depreciation and amortization. These removal costs collected through our rates include costs attributable to legal and nonlegal removal obligations. These costs are addressed prospectively in depreciation rates, rather than as a regulatory liability, in each general rate order.

For financial reporting purposes, if the removal costs collected have exceeded our removal costs incurred, we estimate a regulatory liability using current rates since the last general rate order in each of our jurisdictions. At December 31, 2022 and

2021, we have not recorded a regulatory liability, as our removal costs incurred have exceeded amounts collected through our depreciation rates. Significant uncertainty exists regarding the recording of these regulatory liabilities, pending, among other issues, clarification of regulatory intent. We continue to monitor the regulatory requirements, and any future regulatory liabilities incurred may be adjusted as more information is obtained. To the extent these estimated liabilities are adjusted, such amounts will be reclassified between accumulated depreciation and amortization and regulatory liabilities on our balance sheet and therefore will not have an impact on earnings.

Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be estimated reasonably. We expense legal fees as incurred and base our legal liability estimates on currently available facts and our estimates of the ultimate outcome or resolution. Accruals for the estimated cost of environmental remediation obligations generally are recognized no later than the completion of a remediation feasibility study. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings.

See Note 17 for additional information regarding contingencies.

Share-Based Payments - We expense the fair value of share-based payments net of estimated forfeitures. We estimate forfeiture rates based on historical forfeitures under our share-based payment plans.

Earnings per share - Basic EPS is calculated by dividing net income by the daily 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. Diluted EPS includes the above, plus unvested stock awards granted under our compensation plans and equity forward sale agreements, but only to the extent these instruments dilute earnings per share.

Segments - We operate in one reportable business segment: regulated public utilities that deliver natural gas primarily to residential, commercial and transportation customers. We define reportable business segments as components of an organization for which discrete financial information is available and operating results are evaluated on a regular basis by the chief operating decision maker (“CODM”) in order to assess performance and allocate resources. Our CODM is our Chief Executive Officer. Characteristics of our organization that were relied upon in making this determination include the similar nature of services we provide, the functional alignment of our organizational structure, and the reports that are regularly reviewed by the CODM for the purpose of assessing performance and allocating resources. Our management is functionally aligned and centralized, with performance evaluated based upon results of the entire distribution business. Capital allocation decisions are driven by asset integrity management, operating efficiency, growth opportunities and government-requested pipeline relocations, not geographic location or regulatory jurisdiction.

In 2022, 2021 and 2020, we had no single external customer from which we received 10 percent or more of our gross revenues.

Recently Issued Accounting Standards Update - In November 2021, the FASB issued ASU 2021-10, “Government Assistance (Topic 832): Disclosures by Business Entities about Government Assistance,” which will require disclosure about government assistance in the notes to the financial statements. The amendment requires annual disclosures about transactions with a government that are accounted for by applying a grant or contribution accounting model by analogy, including information about the nature of the transactions and the related accounting policy used to account for the transactions, the line items on the balance sheet and income statement that are affected by the transactions and the significant terms and conditions of the transactions, including commitments and contingencies. The amendment became effective for us beginning January 1, 2022. As the guidance is related only to disclosures in the notes to the financial statements, we do not anticipate any impact on our financial position, results of operations or cash flows. See Note 10 for additional discussion regarding our securitization transaction with the Oklahoma government that is accounted for by applying a grant accounting model by analogy.

In March 2020, the FASB issued ASU 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting,” which provides relief from the accounting analysis and impacts that may otherwise be required for modifications to agreements (e.g., loans, debt securities, derivatives, borrowings) necessitated by reference rate reform. It also provides optional expedients to enable companies to continue to apply hedge accounting to certain hedging relationships impacted by reference rate reform. In the first quarter 2020, we adopted this new guidance effective for contracts modified between March 12, 2020 and December 31, 2022. In March 2022, we amended the ONE Gas Credit Agreement to change the defined benchmark rate to SOFR from LIBOR. Our adoption and subsequent amendment of the ONE Gas Credit Agreement did not result in a material impact to our consolidated financial statements.

2.REVENUE

The following table sets forth our revenues disaggregated by source for the periods indicated:


	Year Ended December 31,
	2022		2021		2020
	(Thousands of dollars)
Natural gas sales to customers	$	2,410,048	$	1,652,566	$	1,381,141
Transportation revenues	125,951		118,492		113,855
Securitization customer charges (Note 11)	5,769		—		—
Miscellaneous revenues	19,850		16,757		15,505
Total revenues from contracts with customers	2,561,618		1,787,815		1,510,501
Other revenues - natural gas sales related	3,403		9,650		8,299
Other revenues	12,984		11,132		11,468
Total other revenues	16,387		20,782		19,767
Total revenues	$	2,578,005	$	1,808,597	$	1,530,268

3.CREDIT FACILITY AND SHORT-TERM DEBT

On March 16, 2022, we entered into the first amendment to the second amended and restated ONE Gas Credit Agreement, which was previously amended and restated on March 16, 2021. The amendment extends the maturity date of the ONE Gas Credit Agreement to March 16, 2027, from March 16, 2026, and amends the ONE Gas Credit Agreement to provide that we may extend the maturity date, subject to the lenders’ consent, by one year two additional times. The amendment also changed the benchmark rate defined in the ONE Gas Credit Agreement to SOFR. All other material terms and conditions of the ONE Gas Credit Agreement remain in full force and effect.

In June 2021, we increased the size of our commercial paper program to permit the issuance of commercial paper to fund short-term borrowing needs in an aggregate principal amount not to exceed $1.0 billion outstanding at any time. Prior to this increase, our commercial paper program permitted us to issue commercial paper in an aggregate principal amount not to exceed $700 million outstanding at any time. The maturities of the commercial paper notes may vary, but may not exceed 270 days from the date of issue. Commercial paper is generally sold at par less a discount representing an interest factor. At December 31, 2022 and 2021, we had $552.0 million and $494.0 million of commercial paper outstanding, respectively. The weighted-average interest rate on our commercial paper was 4.75 percent and 0.38 percent at December 31, 2022 and 2021, respectively.

4.LONG-TERM DEBT

The table below presents a summary of our long-term debt outstanding for the periods indicated:


	Interest rate at December 31, 2022	December 31, 2022		December 31, 2021
		(Thousands of dollars)
Senior unsecured notes:
Senior unsecured notes due March 2023		$	—	$	1,000,000
Senior unsecured floating rate notes due March 2023		—		400,000
Senior unsecured notes due February 2024	3.610%	300,000		300,000
Senior unsecured notes due March 2024	1.100%	473,000		700,000
Senior unsecured notes due May 2030	2.000%	300,000		300,000
Senior unsecured notes due September 2032	4.250%	300,000		—
Senior unsecured notes due February 2044	4.658%	600,000		600,000
Senior unsecured notes due November 2048	4.500%	400,000		400,000
Total senior unsecured notes		2,373,000		3,700,000
KGSS-I Securitized Utility Tariff Bonds	5.486%	336,000		—
Other	8.000%	1,250		1,261
Unamortized discounts on long-term debt		(7,636)		(5,454)
Debt issuance costs		(20,143)		(12,418)
Total long-term debt, net		2,682,471		3,683,389
Less: current maturities of securitized utility tariff bonds		20,716		—
Less: current maturities of long-term debt		12		11
Noncurrent portion of long-term debt, net		$	2,661,743	$	3,683,378

Senior Notes - In August 2022, we issued $300 million of 4.25 percent senior notes due September 2032. The proceeds from the issuance were used to repay amounts outstanding under our commercial paper program and for general corporate purposes.

In August 2022, we called $750 million of the $1.0 billion of 0.85 percent senior notes due March 2023, $150 million of the $700 million of 1.10 percent senior notes due March 2024 and the remaining $400 million of outstanding floating-rate senior notes due March 2023, using the proceeds received from the Oklahoma government in our securitization transaction for Oklahoma Natural Gas.

whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective Senior Note plus accrued and unpaid interest to the redemption date. Our Senior Notes are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness.

ONE Gas 2021 Term Loan Facility - On February 22, 2021, we entered into the ONE Gas 2021 Term Loan Facility as part of the financing of our natural gas purchases in order to provide sufficient liquidity to satisfy our obligations as a result of Winter Storm Uri. The net proceeds of the March 2021 debt issuance reduced the commitments under the ONE Gas 2021 Term Loan Facility on a dollar-for-dollar basis, and as a result no commitments remained outstanding and the facility was terminated concurrently with the closing of the debt issuance.

5.LEASES

We have operating leases for office facilities, gas storage facilities, IT equipment and right-of-way contracts. Our leases have remaining lease terms of one year to seven years, some of which include options to extend the leases for up to 10 years, and some of which include options to terminate the leases within specified time frames. We have not entered into any finance leases.

Our right-of-use asset is $23.3 million and $30.9 million as of December 31, 2022 and 2021, respectively, and is reported within other assets in our consolidated balance sheets. Operating lease liabilities are reported within our other current liabilities and other liabilities in our consolidated balance sheets. Total operating lease cost including immaterial amounts attributable to short-term operating leases was $7.8 million, $8.2 million, and $8.4 million in 2022, 2021 and 2020, respectively.

In 2022, we reassessed certain operating leases for office facilities and IT which were extended or modified, resulting in an decrease in our right-of-use asset and operating lease liability of $1.3 million and $1.3 million, respectively.


	Years Ended
	December 31,
Other information related to operating leases	2022			2021			2020
				(Millions of dollars)
Weighted-average remaining lease term	5 years			6 years			7 years
Weighted-average discount rate	4.04		%	2.78		%	2.81		%
Supplemental cash flows information
Lease payments	$	(8.2)		$	(8.0)		$	(8.0)
Right-of-use assets obtained in exchange for lease obligations	$	0.3		$	0.4		$	9.8



	December 31,
Future minimum lease payments under non-cancellable operating leases	2022
	(Millions of dollars)
2023	$	6.5
2024	4.7
2025	4.0
2026	3.2
2027	3.0
Thereafter	4.3
Total future minimum lease payments	$	25.7
Imputed interest	(2.6)
Total operating lease liability	$	23.1

Consolidated balance sheets as of December 31, 2022
Current operating lease liability	$	5.7
Long-term operating lease liability	17.4
Total operating lease liability	$	23.1

6.EQUITY

Preferred Stock - At December 31, 2022, we had 50 million, $0.01 par value, authorized shares of preferred stock available. We have not issued or established any classes or series of shares of preferred stock.

Common Stock - At December 31, 2022, we had approximately 194.7 million shares of authorized common stock available for issuance.

At December 31, 2022, we had $63.1 million of equity available for issuance under the program.

Dividends Declared - For the years ended December 31, 2022 and 2021, we declared and paid dividends of $2.48 per share ($0.62 per share quarterly) and $2.32 per share ($0.58 per share quarterly), respectively. In January 2023, we declared a dividend of $0.65 per share ($2.60 per share on an annualized basis) for shareholders of record on February 24, 2023, payable on March 10, 2023.

7.ACCUMULATED OTHER COMPREHENSIVE LOSS

The following table sets forth the balance in accumulated other comprehensive loss for the periods indicated:


	Accumulated Other Comprehensive Income (Loss)
	(Thousands of dollars)
January 1, 2021	$	(7,777)
Pension and other postemployment benefit plans obligations
Other comprehensive income before reclassification, net of tax of $11	78
Amounts reclassified from accumulated other comprehensive income (loss), net of tax of $(390)	1,172
Other comprehensive income	1,250
December 31, 2021	(6,527)
Pension and other postemployment benefit plans obligations
Other comprehensive income before reclassification, net of tax of $(1,669)	5,701
Amounts reclassified from accumulated other comprehensive income (loss), net of tax of $(36)	122
Other comprehensive income	5,823
December 31, 2022	$	(704)

The following table sets forth the effect of reclassifications from accumulated other comprehensive loss on our consolidated statements of income for the periods indicated:


Details about Accumulated Other Comprehensive Income (Loss) Components							Affected Line Item in the Consolidated Statements of Income
	Years Ended December 31,
	2022		2021		2020
	(Thousands of dollars)
Pension and other postemployment benefit plan obligations (a)
Amortization of net loss	$	17,010	$	45,896	$	42,492
Amortization of unrecognized prior service cost (credit)	289		(279)		(117)
	17,299		45,617		42,375
Regulatory adjustments (b)	(17,141)		(44,055)		(41,183)
	158		1,562		1,192		Income before income taxes
	(36)		(390)		(298)		Income tax expense
Total reclassifications for the period	$	122	$	1,172	$	894	Net income

(a) These components of accumulated other comprehensive loss are included in the computation of net periodic benefit cost. See Note 14 for additional information regarding our net periodic benefit cost.

(b) Regulatory adjustments represent pension and other postemployment benefit costs expected to be recovered through rates and are deferred as part of our regulatory assets. See Note 10 for additional information regarding our regulatory assets and liabilities.

8.EARNINGS PER SHARE

Basic EPS is calculated by dividing net income by the daily weighted-average number of common shares outstanding during the periods presented, which includes fully vested stock awards that have not yet been issued as common stock. Diluted EPS is based on shares outstanding for the calculation of basic EPS, plus unvested stock awards granted under our compensation plans and equity forward sale agreements, but only to the extent these instruments dilute earnings per share.

The following tables set forth the computation of basic and diluted EPS from continuing operations for the periods indicated:


	Year Ended December 31, 2022
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	221,742	54,207	$	4.09
Diluted EPS Calculation
Effect of dilutive securities	—		131
Net income available for common stock and common stock equivalents	$	221,742	54,338	$	4.08


	Year Ended December 31, 2021
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	206,434	53,575	$	3.85
Diluted EPS Calculation
Effect of dilutive securities	—		99
Net income available for common stock and common stock equivalents	$	206,434	53,674	$	3.85


	Year Ended December 31, 2020
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	196,412	53,133	$	3.70
Diluted EPS Calculation
Effect of dilutive securities	—		237
Net income available for common stock and common stock equivalents	$	196,412	53,370	$	3.68

9.DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS

Derivative Instruments - At December 31, 2022, we held purchased natural gas call options for the heating season ending March 2023, with total notional amounts of 19.4 Bcf, for which we paid premiums of $14.1 million, and which had no fair value. At December 31, 2021, we held purchased natural gas call options for the heating season ended March 2022, with total notional amounts of 13.2 Bcf, for which we paid premiums of $9.5 million, and which had a fair value of $3.6 million. These contracts are included in, and recoverable through, our purchased-gas cost adjustment mechanisms. Additionally, premiums paid, changes in fair value and any settlements received associated with these contracts are deferred as part of our unrecovered purchased-gas costs in our consolidated balance sheets. Our natural gas call options are classified as Level 1, as fair value amounts are based on unadjusted quoted prices in active markets including settled prices on the New York Mercantile Exchange. There were no transfers between levels for the periods presented.

Other Financial Instruments - The approximate fair value of cash and cash equivalents, restricted cash and cash equivalents, accounts receivable and accounts payable is equal to book value, due to the short-term nature of these items. Our cash and cash equivalents and restricted cash and cash equivalents are comprised of cash and money market accounts, which we consider to be Level 1. At December 31, 2022, other current and noncurrent assets included $9.7 million of corporate bonds and $4.7 million of United States treasury notes, for which the fair value approximates our cost, and are classified as Level 2 and Level 1, respectively. At December 31, 2021, other current and noncurrent assets included $6.9 million of corporate bonds and $3.5 million of United States treasury notes, for which the fair value approximates our cost, and are classified as Level 2 and Level 1, respectively.

Short-term notes payable and commercial paper are due upon demand and, therefore, the carrying amounts approximate fair value and are classified as Level 1. The book value of our long-term debt, including current maturities, was $2.7 billion and $3.7 billion at December 31, 2022 and 2021, respectively. The estimated fair value of our long-term debt, including current maturities, was $2.5 billion and $3.9 billion at December 31, 2022 and 2021, respectively. The estimated fair value of our long-term debt was determined using quoted market prices, and is considered Level 2.

10.REGULATORY ASSETS AND LIABILITIES

The tables below present a summary of regulatory assets, net of amortization, and liabilities for the periods indicated:


		December 31, 2022
	Remaining Recovery Period	Current		Noncurrent		Total
		(Thousands of dollars)
Winter weather event costs	(a)	$	221,926	$	36,291	$	258,217
Under-recovered purchased-gas costs	1 year	19,755		—		19,755
Pension and other postemployment benefit costs	See Note 14	—		258,257		258,257
Reacquired debt costs	6 years	812		3,347		4,159
MGP remediation costs	15 years	98		29,743		29,841
Ad-valorem tax	1 year	13,359		—		13,359
WNA	1 year	8,474		—		8,474
Customer credit deferrals	1 year	9,504		—		9,504
Other	1 to 18 years	1,644		3,193		4,837
Total regulatory assets, net of amortization		275,572		330,831		606,403
Pension and other postemployment benefit costs	See Note 14	(8,228)		—		(8,228)
Income tax rate changes	(a)	—		(529,441)		(529,441)
Over-recovered purchased-gas costs	1 year	(39,639)		—		(39,639)
Total regulatory liabilities		(47,867)		(529,441)		(577,308)
Net regulatory assets and liabilities		$	227,705	$	(198,610)	$	29,095

(a) Recovery period varies by jurisdiction. See discussion below for additional information regarding our regulatory assets related to winter weather event costs and regulatory liabilities related to federal income tax rate changes.


		December 31, 2021
	Remaining Recovery Period	Current		Noncurrent		Total
		(Thousands of dollars)
Winter weather event costs	(a)	$	1,536,054	$	428,023	$	1,964,077
Under-recovered purchased-gas costs	1 year	31,863		—		31,863
Pension and other postemployment benefit costs	See Note 14	11,507		260,559		272,066
Reacquired debt costs	6 years	812		4,070		4,882
MGP remediation costs	15 years	98		29,841		29,939
Ad-valorem tax	1 year	8,561		—		8,561
WNA	1 year	10,044		—		10,044
Customer credit deferrals	1 year	10,685		—		10,685
Other	1 to 18 years	2,052		2,369		4,421
Total regulatory assets, net of amortization		1,611,676		724,862		2,336,538
Income tax rate changes	(a)	—		(552,928)		(552,928)
Over-recovered purchased-gas costs	1 year	(8,090)		—		(8,090)
Total regulatory liabilities		(8,090)		(552,928)		(561,018)
Net regulatory assets and liabilities		$	1,603,586	$	171,934	$	1,775,520

(a) Recovery period varies by jurisdiction. See discussion below for additional information regarding our regulatory liabilities related to federal income tax rate changes.

Regulatory assets in our consolidated balance sheets, as authorized by various regulatory authorities, are probable of recovery. Base rates and certain riders are designed to provide a recovery of costs during the period such rates are in effect, but do not generally provide for a return on investment for amounts we have deferred as regulatory assets. All of our regulatory assets are subject to review by the respective regulatory authorities during future regulatory proceedings. We are not aware of any evidence that these costs will not be recoverable through either riders, base rates, or securitization.

Winter weather event costs - In February 2021, the U.S. experienced Winter Storm Uri, a historic winter weather event impacting supply, market pricing and demand for natural gas in a number of states, including our service territories of Oklahoma, Kansas, and Texas. During this time, the governors of Oklahoma, 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 utility curtailment programs and orders requiring jurisdictional natural gas and electric utilities to do all things possible and necessary to ensure that natural gas and electricity utility services continued to be provided to their customers. Due to the historic nature of this winter weather event, we experienced unforeseeable and unprecedented market pricing for natural gas in our Oklahoma, Kansas, and Texas jurisdictions, which resulted in aggregated natural gas purchases for the month of February 2021 of approximately $2.1 billion.

Oklahoma - Beginning in the first quarter 2021, Oklahoma Natural Gas began deferring to a regulatory asset the extraordinary costs associated with this unprecedented winter weather event, including commodity costs, operational costs and carrying costs, in accordance with an order issued by the OCC in March 2021. In April 2021, a bill permitting the state of Oklahoma to pursue securitized financing of extraordinary expenses, such as fuel costs, financing costs and other operational costs incurred by regulated utilities during extreme weather events, was signed into law. This law gives the OCC the authority to approve amounts to be recovered from the issuance of ratepayer-backed securitized bonds by the ODFA.

In April 2021, Oklahoma Natural Gas submitted an initial application requesting a financing order pursuant to the securitization legislation in Oklahoma. In January 2022, the OCC approved the financing order that reflected the terms of a settlement agreement, which included an agreement that all extreme gas purchase and extraordinary costs incurred as a result of Winter Storm Uri were reasonable and prudent and a financing order should be issued to recover these costs through securitization. Pursuant to the securitization statute in Oklahoma, the Oklahoma Supreme Court validated that the bond issuance proposed by the ODFA complied with the securitization statute and the laws of Oklahoma in May 2022.

The proceeds received by Oklahoma Natural Gas were approximately $1.3 billion, which represents the amount of the securitization bonds issued by the ODFA less issuance costs. The receipt of these proceeds represents Oklahoma Natural Gas’ recovery of the approximately $1.3 billion of authorized extraordinary natural gas purchase costs and other operational costs incurred during Winter Storm Uri, as well as carrying costs. GAAP does not provide comprehensive recognition and measurement guidance for many forms of government assistance received by business entities. Accordingly, we have accounted for the proceeds received from the ODFA by analogy to International Accounting Standards No. 20, “Accounting for Government Grants and Disclosure of Government Assistance” consistent with a grant related to income. The proceeds received and the corresponding recognition of the deferred regulatory asset have been reflected in cost of natural gas in our consolidated statements of income. As the proceeds reflect the recovery of our winter weather event regulatory asset, there was no material impact to earnings. Beginning September 1, 2022, Oklahoma Natural Gas acts as a servicer, with responsibility for collecting the securitization charges from Oklahoma customers that are then submitted to the ODFA to repay the securitization bonds. The collection and remittance of these funds on behalf of the ODFA are recorded in other current liabilities in our consolidated balance sheets.

In May 2021, Kansas Gas Service filed a motion in its company-specific docket opened by the KCC, requesting a limited waiver of the penalty provisions of its tariff to eliminate the multipliers in the penalty calculation when calculating the penalties to assess on marketers and individually-balanced transportation customers for their unauthorized natural gas usage during Winter Storm Uri. In March 2022, the KCC issued an order approving a settlement which modified the penalty provisions of Kansas Gas Service’s tariffs and included a carrying charge of two percent on amounts due to Kansas Gas Service. Amounts collected from these penalties will reduce the regulatory asset for the winter weather event, up to $52.6 million. Through December 31, 2022, we have collected $50.5 million of these penalties.

In July 2021, Kansas Gas Service submitted its financial plan to the KCC as required by the company-specific docket opened by the KCC in March 2021. The plan includes a proposal for a newly formed, bankruptcy remote subsidiary of the Company to issue securitized utility tariff bonds to recover the extraordinary costs resulting from Winter Storm Uri from Kansas Gas Service’s customers. In February 2022, the KCC issued an order approving a unanimous settlement agreement that allows

Kansas Gas Service to recover extraordinary costs, net of any penalties recovered from marketers and individually-balanced transportation customers, plus carrying costs, by seeking a financing order from the KCC for the issuance of securitized utility tariff bonds.

In March 2022, Kansas Gas Service submitted its application for a financing order to the KCC as contemplated by the unanimous settlement agreement, requesting approval to issue securitized utility tariff bonds to recover extraordinary costs resulting from Winter Storm Uri and flexibility to recover the costs. In July 2022, Kansas Gas Service, the KCC Staff and the Citizens’ Utility Ratepayer Board reached a settlement agreement for the issuance of a financing order allowing a newly formed, bankruptcy remote subsidiary of the Company to issue securitized utility tariff bonds. In August 2022, the KCC issued an order approving the agreement and also issued a financing order.

In November 2022, KGSS-I issued $336 million of 5.486 percent Securitized Utility Tariff Bonds. KGSS-I used the proceeds from the issuance to purchase the Securitized Utility Tariff Property from Kansas Gas Service, pay for debt issuance costs, and reimburse Kansas Gas Service for upfront securitization costs paid by Kansas Gas Service on behalf of KGSS-I. See Notes 1 and 4 for additional information about the Securitized Utility Tariff Bonds and Note 11 for additional information about the securitization transaction.

In November 2021, the RRC approved a unanimous settlement agreement among Texas Gas Service, the other natural gas utilities in Texas participating in the securitization process, the staff of the RRC and all intervenors. The settlement agreement provides that all costs incurred by Texas Gas Service to purchase natural gas during Winter Storm Uri were reasonable, necessary and prudently incurred.

In February 2022, the RRC issued a single financing order for Texas Gas Service and other natural gas utilities in Texas participating in the securitization process, which included a determination that the approved costs will be collected from customers over a period of not more than 30 years. The TPFA formed the Texas Natural Gas Securitization Finance Corporation, a new independent public authority, that will issue the securitized bonds, which are expected to be issued by April 2023. At December 31, 2022, Texas Gas Service has deferred approximately $243.1 million in extraordinary costs associated with Winter Storm Uri, which includes $43.8 million attributable to the former West Texas service area. Pursuant to the approved settlement order, Texas Gas Service is collecting the extraordinary costs, including carrying costs, associated with Winter Storm Uri attributable to the former West Texas service area from those customers over a period of three years that began in January 2022.

General - In accordance with these regulatory orders associated with the winter weather event, our regulatory asset totaled approximately $258.2 million in extraordinary costs for natural gas purchases, related financing and carrying costs and other operational costs that have not been recovered at December 31, 2022. The amounts deferred include invoiced costs for natural gas purchases that have not been paid as we work with our suppliers to resolve discrepancies in invoiced amounts. The amounts deferred may be adjusted as the differences are resolved. As these amounts are related to the gas purchase costs associated with Winter Storm Uri, which are deferred, future adjustments to the amounts deferred are not expected to have a material impact on earnings.

Other regulatory assets and liabilities - Purchased-gas costs represent the natural gas costs that have been over- or under- recovered from customers through the purchased-gas cost adjustment mechanisms, and includes natural gas utilized in our operations and premiums paid and any cash settlements received from our purchased natural gas call options.

The OCC, KCC and regulatory authorities in Texas have approved the recovery of pension costs and other postemployment benefits costs through rates for Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. The costs recovered through rates are based on the net periodic benefit cost for defined benefit pension and other postemployment costs. Differences, if any, between the net periodic benefit cost, net of deferrals, and the amount recovered through rates are reflected in earnings. We historically have recovered defined benefit pension and other postemployment benefit costs through rates. We believe it is probable that regulators will continue to include the net periodic pension and other postemployment benefit costs in our cost of service.

We amortize reacquired debt costs in accordance with the accounting guidelines prescribed by the OCC and KCC.

See Note 17 for additional information regarding our regulatory assets for MGP remediation costs.

Ad-valorem tax represents the difference in Kansas Gas Service’s taxes incurred each year above or below the amount approved in base rates. This difference is deferred as a regulatory asset or liability for a 12-month period. Kansas Gas Service then applies an adjustment to customers’ bills to refund the over-collected revenue or bill the under-collected revenue over the subsequent 12 months.

Weather normalization represents revenue over- or under- recovered through the WNA rider in Kansas. This amount is deferred as a regulatory asset or liability for a 12-month period. Kansas Gas Service then applies an adjustment to the customers’ bills for 12 months to refund the over-collected revenue or bill the under-collected revenue.

The customer credit deferrals and the regulatory liability for income tax rate changes represents deferral of the effects of enacted federal and state income tax rate changes on our ADIT and the effects of these changes on our rates. See Note 15 for additional information regarding the impact of income tax rate changes during the year ended December 31, 2022.

Recovery through rates resulted in amortization of regulatory assets of approximately $9.4 million, $5.5 million and $3.2 million for the years ended December 31, 2022, 2021 and 2020, respectively.

11.VARIABLE INTEREST ENTITY

KGSS-I is a special-purpose, wholly owned subsidiary of ONE Gas that was formed for the purpose of issuing securitized utility tariff bonds to recover extraordinary costs incurred by Kansas Gas Service resulting from Winter Storm Uri. On November 18, 2022, the securitized financing was complete. KGSS-I’s assets cannot be used to settle ONE Gas’ obligations and the holders of the Securitized Utility Tariff Bonds have no recourse against ONE Gas. See Notes 1, 4 and 10 for additional information about the securitization financing.

Because KGSS-I’s equity at risk is less than 1 percent of its total assets, it is considered to be a variable interest entity. Through its equity ownership interest and role as servicer, ONE Gas has the power to direct the most significant financial and operating activities of KGSS-I, including billing, collections, and remittance of customer cash receipts to enable KGSS-I to service the principal and interest payments due under the Securitized Utility Tariff Bonds. Therefore, ONE Gas is the primary beneficiary of KGSS-I, and as a result, KGSS-I is included in the consolidated financial statements of ONE Gas. No gain or loss was recognized upon initial consolidation.

The following table summarizes the impact of KGSS-I on our consolidated balance sheets:


	December 31,
	2022
	(Thousands of dollars)
Restricted cash and cash equivalents	$	8,446
Accounts receivable	4,862
Securitized intangible asset, net	323,838
Current maturities of securitized utility tariff bonds	20,716
Accounts payable	3,204
Accrued interest	2,202
Securitized utility tariff bonds, excluding current maturities, net of issuance costs	309,343
Equity	$	1,681

The following table summarizes the impact of KGSS-I on our consolidated statements of income:


	Year ended December 31,
	2022
	(Thousands of dollars)
Operating revenues	$	5,769
Operating expense	(52)
Amortization expense	(3,521)
Interest income	6
Interest expense	(2,202)
Income before income taxes	$	—

The following table summarizes the amortization expense related to the securitized intangible asset expected to be recognized in our consolidated statements of income:


For the year ending:	(Thousands of dollars)
2023	$	27,851
2024	$	27,843
2025	$	29,391
2026	$	31,025
2027	$	32,751

12.PROPERTY, PLANT AND EQUIPMENT

The following table sets forth our property, plant and equipment by property type, for the periods indicated:


	December 31,		December 31,
	2022		2021
	(Thousands of dollars)
Natural gas distribution pipelines and related equipment	$	6,240,236	$	5,836,066
Natural gas transmission pipelines and related equipment	661,379		624,528
General plant and other	782,870		712,659
Construction work in process	150,072		101,015
Property, plant and equipment	7,834,557		7,274,268
Accumulated depreciation and amortization	(2,205,717)		(2,083,433)
Net property, plant and equipment	$	5,628,840	$	5,190,835

We compute depreciation expense by applying composite, straight-line rates of approximately 2.5 percent to 3.5 percent as approved by various regulatory authorities.

We recorded capitalized interest of $4.5 million, $4.2 million and $4.2 million for the years ended December 31, 2022, 2021 and 2020, respectively. We incurred liabilities for construction work in process that had not been paid at December 31, 2022, 2021 and 2020 of $28.6 million, $25.6 million and $24.3 million, respectively. Such amounts are not included in capital expenditures or in the change of working capital items on our consolidated statements of cash flows.

13.SHARE-BASED PAYMENTS

The ECP provides for the granting of stock-based compensation, including incentive stock options, nonstatutory stock options, stock bonus awards, restricted stock awards, restricted stock unit awards, performance stock awards and performance unit awards to eligible employees and the granting of stock awards to non-employee directors. At December 31, 2022, we have 4.3 million shares of common stock reserved for issuance under the ECP. At December 31, 2022, we had approximately 1.4 million shares available for issuance under the ECP, which reflect shares issued and estimated shares expected to be issued upon vesting of outstanding awards granted under the plan, less forfeitures. The plan allows for the deferral of awards granted in stock or cash, in accordance with the Code section 409A requirements.

Compensation expense for our ECP share-based payment plans was $6.8 million, net of tax benefits of $2.3 million, for 2022, $7.5 million, net of tax benefits of $2.5 million, for 2021, and $7.0 million, net of tax benefits of $2.3 million, for 2020.

Restricted Stock Unit Awards - We have granted restricted stock unit awards to key employees that vest over a service period of generally three years and entitle the grantee to receive shares of our common stock. Restricted stock unit awards granted accrue dividend equivalents in the form of additional restricted stock units prior to vesting. Restricted stock unit awards are measured at fair value as if they were vested and issued on the grant date and adjusted for estimated forfeitures. Compensation expense is recognized on a straight-line basis over the vesting period of the award. A forfeiture rate of 3 percent per year based on historical forfeitures under our share-based payment plans is used.

Performance Stock Unit Awards - We have granted performance stock unit awards to key employees. The shares of common stock underlying the performance stock units vest at the expiration of a service period of generally three years if certain performance criteria are met by us as determined by the Executive Compensation Committee of the Board of Directors. Upon vesting, a holder of performance stock units is entitled to receive a number of shares of common stock equal to a percentage (0 percent to 200 percent) of the performance stock units granted, based on our total shareholder return over the vesting period, compared with the total shareholder return of a peer group of other utilities over the same period.

If paid, the outstanding performance stock unit awards entitle the grantee to receive shares of our common stock. The outstanding performance stock unit awards are equity awards with a market-based condition, which results in the compensation expense for these awards being recognized on a straight-line basis over the requisite service period, provided that the requisite service period is fulfilled, regardless of when, if ever, the market condition is satisfied. The performance stock unit awards granted accrue dividend equivalents in the form of additional performance stock units prior to vesting. The fair value of these performance stock units was estimated on the grant date based on a Monte Carlo model. The compensation expense on these awards will only be adjusted for forfeitures. A forfeiture rate of 3 percent per year based on historical forfeitures under our share-based payment plans is used.

Restricted Stock Unit Award Activity

As of December 31, 2022, there was $3.7 million of total unrecognized compensation expense related to the nonvested restricted stock unit awards, which is expected to be recognized over a weighted-average period of 1.8 years. The following tables set forth activity and various statistics for restricted stock unit awards outstanding under the respective plans for the period indicated:


	Number of Units	Weighted- Average Grant Date Fair Value
Nonvested at December 31, 2021	94,274	$	82.16
Granted	56,420	$	76.96
Vested	(28,830)	$	78.91
Forfeited	(5,231)	$	84.06
Nonvested at December 31, 2022	116,633	$	79.32


	2022		2021		2020
Weighted-average grant date fair value (per share)	$	76.96	$	72.69	$	96.21
Fair value of shares granted (thousands of dollars)	$	4,342	$	3,660	$	3,005

For the years ended December 31, 2022, 2021 and 2020, the fair value of restricted stock vested was $2.9 million, $3.4 million, and $3.3 million, respectively.

Performance Stock Unit Award Activity

As of December 31, 2022, there was $8.0 million of total unrecognized compensation expense related to the nonvested performance stock unit awards, which is expected to be recognized over a weighted-average period of 1.8 years. The following tables set forth activity and various statistics related to our performance stock unit awards and the assumptions used by us in the valuations of the 2022, 2021 and 2020 grants at the grant date:


	Number of Units	Weighted- Average Grant Date Fair Value
Nonvested at December 31, 2021	198,599	$	90.13
Granted	87,266	$	95.80
Vested	(63,389)	$	89.86
Forfeited	(7,939)	$	91.41
Nonvested at December 31, 2022	214,537	$	92.47


	2022	2021	2020
Volatility (a)	34.00%	32.70%	16.40%
Dividend yield	3.22%	3.19%	2.25%
Risk-free interest rate (b)	1.65%	0.20%	1.40%

(a) - Volatility based on historical volatility over three years using daily stock price observations of our peer utilities.

(b) - Using 3-year treasury rate.


	2022		2021		2020
Weighted-average grant date fair value (per share)	$	95.80	$	82.51	$	102.77
Fair value of shares granted (thousands of dollars)	$	8,360	$	8,860	$	6,502

For the years ended December 31, 2022, 2021 and 2020, the fair value of performance stock vested was $5.2 million, $7.2 million, and $10.2 million, respectively.

Employee Stock Purchase Plan

We have reserved a total of 1.25 million shares of common stock for issuance under our ESPP. Employees can choose to have up to 10 percent of their annual base pay withheld to purchase our common stock, subject to terms and limitations of the plan. The purchase price of the stock is 85 percent of the lower of the average market price of our common stock on the grant date or exercise date. Approximately 42 percent, 44 percent and 50 percent of employees participated in the plan in 2022, 2021 and 2020, respectively. For the years ended December 31, 2022, 2021 and 2020, employees purchased 86,657, 89,240, and 92,507 shares, respectively, at an average price of $65.21, $63.41 and $64.77, respectively.

Compensation expense related to our ESPP, before taxes, was $1.1 million for each of the years ended December 31, 2022, 2021 and 2020.

14.EMPLOYEE BENEFIT PLANS

Defined Benefit Pension and Other Postemployment Benefit Plans

Defined Benefit Pension Plans - We have a defined benefit pension plan and a supplemental executive retirement plan, both of which are closed to new participants. Certain employees of the Texas Gas Service division are entitled to benefits under a frozen cash-balance pension plan. We fund our defined benefit pension costs at a level needed to maintain or exceed the minimum funding levels required by the Employee Retirement Income Security Act of 1974, as amended, and the Pension Protection Act of 2006.

Other Postemployment Benefit Plans - We sponsor health and welfare plans that provide postemployment medical and life insurance benefits to certain employees who retire with at least five years of service. The postemployment medical plan is contributory based on hire date, age and years of service, with retiree contributions adjusted periodically, and contains other cost-sharing features such as deductibles and coinsurance.

Actuarial Assumptions - The following table sets forth the weighted-average assumptions used to determine benefit obligations for pension and postemployment benefits for the periods indicated:


	December 31,
	2022	2021
Discount rate - pension plans	5.60%	3.05%
Discount rate - other postemployment plans	5.70%	3.00%
Compensation increase rate	3.60% - 5.00%	3.10% - 5.00%

The following table sets forth the weighted-average assumptions used by us to determine the periodic benefit costs for pension and postemployment benefits for the periods indicated:


	Years Ended December 31,
	2022	2021	2020
Discount rate - pension plans	3.05%/4.55% (a)	2.80%	3.50%
Discount rate - other postemployment plans	3.00%	2.70%	3.40%
Expected long-term return on plan assets - pension plans	6.40%	7.15%	7.20%
Expected long-term return on plan assets - other postemployment plans	5.85%	7.50%	7.65%
Compensation increase rate	3.10% - 5.00%	3.10% - 3.90%	3.10% - 4.00%

(a) Pension plans were remeasured as of April 30, 2022.

We determine our discount rates annually. We estimate our discount rate based upon a comparison of the expected cash flows associated with our future payments under our defined benefit pension and other postemployment obligations to a hypothetical bond portfolio created using high-quality bonds that closely match expected cash flows. Bond portfolios are developed by selecting a bond for each of the next 60 years based on the maturity dates of the bonds. Bonds selected to be included in the portfolios are only those rated by Moody’s as AA- or better and exclude callable bonds, bonds with less than a minimum issue size, yield outliers and other filtering criteria to remove unsuitable bonds.

We determine our overall expected long-term rate of return on plan assets based on our review of historical returns and economic growth models. We update our assumed mortality rates to incorporate new tables issued by the Society of Actuaries as needed.

Regulatory Treatment - The OCC, KCC and regulatory authorities in Texas have approved the recovery of pension and other postemployment benefits costs through rates for Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. The costs recovered through rates are based on current funding requirements and the net periodic benefit cost for defined benefit pension and other postemployment costs. Differences, if any, between the net periodic benefit cost, net of deferrals, and the amount recovered through rates are reflected in earnings.

We historically have recovered defined benefit pension and other postemployment benefit costs through rates. We believe it is probable that regulators will continue to include the net periodic pension and other postemployment benefit costs in our cost of service.

We capitalize all eligible service cost and non-service cost components pursuant to the accounting requirements of ASC Topic 980 (Regulated Operations) for rate-regulated entities, as these costs are authorized by our regulators to be included in capitalized costs. Noncurrent regulatory assets in our consolidated balance sheets reflect the capitalized non-service cost components of $2.8 million and $6.1 million as of December 31, 2022 and December 31, 2021, respectively. See Note 10 for additional information.

Obligations and Funded Status - The following table sets forth our defined benefit pension and other postemployment benefit plans, benefit obligations and fair value of plan assets for the periods indicated:


	Pension Benefits				Other Postemployment Benefits
	December 31,				December 31,
	2022		2021		2022		2021
Changes in Benefit Obligation	(Thousands of dollars)
Benefit obligation, beginning of period	$	1,049,990	$	1,077,641	$	222,806	$	239,530
Service cost	10,369		13,811		1,274		1,587
Interest cost	36,150		29,458		6,448		6,251
Plan participants’ contributions	—		—		3,035		3,226
Actuarial loss (gain)	(259,261)		(19,587)		(48,609)		(8,894)
Benefits paid	(55,326)		(51,333)		(16,612)		(18,894)

Plan amendments	2,711		—		—		—

Benefit obligation, end of period	784,633		1,049,990		168,342		222,806

Change in Plan Assets
Fair value of plan assets, beginning of period	1,013,244		987,583		231,994		230,895
Actual return (loss) on plan assets	(190,484)		75,999		(38,432)		14,786
Employer contributions	1,527		995		1,892		1,981
Plan participants’ contributions	—		—		3,035		3,226
Benefits paid	(55,326)		(51,333)		(16,612)		(18,894)

Fair value of assets, end of period	768,961		1,013,244		181,877		231,994
Benefit Asset (Obligation), net at December 31	$	(15,672)	$	(36,746)	13,535		$	9,188

Other noncurrent assets	5,267		—		13,535		9,188
Current liabilities	(1,352)		(1,521)		—		—
Noncurrent liabilities	(19,587)		(35,225)		—		—
Benefit Asset (Obligation), net at December 31	$	(15,672)	$	(36,746)	$	13,535	$	9,188

The accumulated benefit obligation for our defined benefit pension plans was $746.8 million and $1.0 billion at December 31, 2022 and 2021, respectively.

For the years ended December 31, 2022 and 2021, the pension benefit obligations experienced actuarial gains of $259.3 million and $19.6 million, respectively, primarily due to the impact of increases in the discount rates used to calculate the benefit obligations.

In 2023, our contributions are expected to be $1.4 million to our defined benefit pension plans, and no contributions are expected to be made to our other postemployment benefit plans.

Components of Net Periodic Benefit Cost - The following tables set forth the components of net periodic benefit cost, prior to regulatory deferrals, for our defined benefit pension and other postemployment benefit plans for the period indicated:


	Pension Benefits
	Year Ended December 31,
	2022		2021		2020
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	10,369	$	13,811	$	12,869
Interest cost (a)	36,150		29,458		34,179
Expected return on assets (a)	(58,528)		(62,382)		(61,119)
Amortization of unrecognized prior service cost (a)	248		—		—
Amortization of net loss (a)	16,793		45,523		42,319
Net periodic benefit cost	$	5,032	$	26,410	$	28,248

(a) These amounts, net of any amounts capitalized as a regulatory asset since adoption of ASU 2017-07 on January 1, 2018, have been recognized as other income (expense), net in the consolidated statements of income. See Note 16 for additional detail of our other income (expense), net.


	Other Postemployment Benefits
	Year Ended December 31,
	2022		2021		2020
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	1,274	$	1,587	$	1,692
Interest cost (a)	6,448		6,251		7,557
Expected return on assets (a)	(13,181)		(16,807)		(15,469)
Amortization of unrecognized prior service cost (credit) (a)	41		(279)		(117)
Amortization of net loss (a)	217		373		173

Net periodic benefit cost (credit)	$	(5,201)	$	(8,875)	$	(6,164)

We use a December 31 measurement date for our plans. On April 30, 2022, we amended our defined benefit pension plans to change the variable cost of living adjustment for eligible participants to a fixed rate. Accordingly, we remeasured our net benefit obligations as of April 30, 2022, resulting in an adjustment of approximately $7.2 million to our pension expense, net of capitalization and regulatory deferrals, for the year ended December 31, 2022.

Other Comprehensive Income (Loss) - The following table sets forth the amounts recognized in other comprehensive income (loss), net of regulatory deferrals, related to our defined benefit pension benefits for the period indicated:


	Pension Benefits
	Year Ended December 31,
	2022		2021		2020
	(Thousands of dollars)
Net gain (loss) arising during the period	$	7,369	$	67	$	(2,519)
Amortization of loss	159		1,562		1,192
Deferred income taxes	(1,705)		(379)		289
Total recognized in other comprehensive income (loss)	$	5,823	$	1,250	$	(1,038)

Due to our regulatory deferrals, there were no amounts recognized in other comprehensive income (loss) related to our other

postemployment benefits for the periods presented.

The tables below set forth the amounts in accumulated other comprehensive loss that had not yet been recognized as components of net periodic benefit expense for the periods indicated:


	Pension Benefits
	December 31,
	2022		2021
	(Thousands of dollars)
Prior service cost	$	(2,463)	$	—
Accumulated loss	(245,290)		(272,332)
Accumulated other comprehensive loss before regulatory assets	(247,753)		(272,332)
Regulatory asset for regulated entities	246,975		264,027
Accumulated other comprehensive loss after regulatory assets	(778)		(8,305)
Deferred income taxes	74		1,778
Accumulated other comprehensive loss, net of tax	$	(704)	$	(6,527)


	Other Postemployment Benefits
	December 31,
	2022		2021
	(Thousands of dollars)
Prior service cost	$	(153)	$	(194)
Accumulated loss	(8,557)		(5,887)
Accumulated other comprehensive loss before regulatory assets	(8,710)		(6,081)
Regulatory asset for regulated entities	8,710		6,081
Accumulated other comprehensive loss after regulatory assets	$	—	$	—

Health Care Cost Trend Rates - The following table sets forth the assumed health care cost-trend rates for the periods indicated:


	2022	2021
Health care cost-trend rate assumed for next year	6.50%	6.00%
Rate to which the cost-trend rate is assumed to decline (the ultimate trend rate)	4.50%	4.50%
Year that the rate reaches the ultimate trend rate	2030	2028

Plan Assets - Our investment strategy is to invest plan assets in accordance with sound investment practices that emphasize long-term fundamentals. The goal of this strategy is to maximize investment returns while managing risk in order to meet the plan’s current and projected financial obligations. To achieve this strategy, we have established a liability-driven investment strategy to change the allocations as the funded status of the defined benefit pension plan increases. The plan’s investments include a diverse blend of various domestic and international equities, investment-grade debt securities which mirror the cash flows of our liability, insurance contracts and alternative investments. The current target allocation for the assets of our defined benefit pension plan is as follows:



Investment-grade bonds	60.0	%
U.S. large-cap equities	14.0	%
Alternative investments	10.0	%
Developed foreign large-cap equities	7.0	%
Mid-cap equities	5.0	%
Emerging markets equities	1.0	%
Small-cap equities	3.0	%
Total	100	%

As part of our risk management for the plans, minimums and maximums have been set for each of the asset classes listed above. All investment managers for the plan are subject to certain restrictions on the securities they purchase and, with the exception of indexing purposes, are prohibited from owning our stock.

The current target allocation for the assets of our other postemployment benefits plan is 90 percent fixed income securities and 10 percent equity securities.

The following tables set forth our pension and other postemployment benefits plan assets by fair value category as of the measurement date:


	Pension Benefits
	December 31, 2022
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Investments:
Equity securities (a)	$	150,027	$	—	$	—	$	150,027
Government obligations	—		160,799		—		160,799
Corporate obligations (b)	—		329,973		—		329,973
Cash and money market funds (c)	4,466		22,185		—		26,651
Insurance contracts and group annuity contracts	—		—		14,480		14,480
Other investments (d)	—		—		87,031		87,031
Total assets	$	154,493	$	512,957	$	101,511	$	768,961

(a) - This category represents securities of the various market sectors from diverse industries.

(b) - This category represents bonds from diverse industries.

(d) - This category represents alternative investments such as hedge funds and other financial instruments.


	Pension Benefits
	December 31, 2021
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Investments:
Equity securities (a)	$	223,871	$	—	$	—	$	223,871
Government obligations	—		205,741		—		205,741
Corporate obligations (b)	—		440,445		—		440,445
Cash and money market funds (c)	3,864		30,546		—		34,410
Insurance contracts and group annuity contracts	—		—		17,301		17,301
Other investments (d)	—		20		91,456		91,476
Total assets	$	227,735	$	676,752	$	108,757	$	1,013,244

(a) - This category represents securities of the various market sectors from diverse industries.

(b) - This category represents bonds from diverse industries.

(d) - This category represents alternative investments such as hedge funds and other financial instruments.


	Other Postemployment Benefits
	December 31, 2022
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Investments:
Equity securities (a)	$	5,983	$	—	$	—	$	5,983
Government obligations	—		43,291		—		43,291
Corporate obligations (b)	—		38,095		—		38,095
Cash and money market funds (c)	750		7,621		—		8,371
Insurance contracts and group annuity contracts (d)	—		86,137		—		86,137
Total assets	$	6,733	$	175,144	$	—	$	181,877

(a) - This category represents securities of the various market sectors from diverse industries.

(b) - This category represents bonds from diverse industries.

(d) - This category includes equity securities and bonds held in a captive insurance product.


	Other Postemployment Benefits
	December 31, 2021
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Investments:
Equity securities (a)	$	25,577	$	—	$	—	$	25,577
Government obligations	—		41,366		—		41,366
Corporate obligations (b)	—		41,601		—		41,601
Cash and money market funds (c)	542		12,990		—		13,532
Insurance contracts and group annuity contracts (d)	—		109,918		—		109,918
Total assets	$	26,119	$	205,875	$	—	$	231,994

(a) - This category represents securities of the various market sectors from diverse industries.

(b) - This category represents bonds from diverse industries.

(d) - This category includes equity securities and bonds held in a captive insurance product.

Insurance contracts and group annuity contracts include investments in the Immediate Participation Guarantee Fund (“IPG Fund”) with John Hancock and are valued at fair value. John Hancock invests the IPG Fund in its general fund portfolio. The contract value of the IPG Fund at the end of the year, which approximates fair value, is estimated. The difference between this estimated balance and the actual balance, as subsequently determined by John Hancock, is charged or credited to the net assets of the plans.

Certain investments that are categorized as money market funds in Level 2 and “Other investments” in Level 3 represent alternative investments such as hedge funds and other financial instruments measured using the net asset value per share (or its equivalent) practical expedient.

The following tables set forth additional information regarding commitments and redemption limitations of these other investments at the periods indicated:


	December 31, 2022
	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in thousands)					(in days)
Grosvenor Registered Multi Limited Partnership	$	40,160	$	—	quarterly	65
K2 Institutional Investors II Limited Partnership	$	46,871	$	—	quarterly	91


	December 31, 2021
	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in thousands)					(in days)
Grosvenor Registered Multi Limited Partnership	$	44,818	$	—	quarterly	65
K2 Institutional Investors II Limited Partnership	$	46,638	$	—	quarterly	91

The following table sets forth the reconciliation of Level 3 fair value measurements of our pension plans for the periods indicated:


	Pension Benefits
	Insurance Contracts		Other Investments		Total
	(Thousands of dollars)
January 1, 2021	$	24,603	$	87,634	$	112,237
Unrealized gains	—		1,625		1,625
Unrealized losses	(3,368)		—		(3,368)
Purchases	—		2,197		2,197
Settlements	(3,934)		—		(3,934)
December 31, 2021	$	17,301	$	91,456	$	108,757
Unrealized gains	1,467		—		1,467
Unrealized losses	—		(7,458)		(7,458)
Purchases	182		3,033		3,215
Settlements	(4,470)		—		(4,470)
December 31, 2022	$	14,480	$	87,031	$	101,511

Pension and Other Postemployment Benefit Payments - Benefit payments for our defined benefit pension and other postemployment benefit plans for the year ended December 31, 2022 were $55.3 million and $16.6 million, respectively. The following table sets forth the pension benefits and other postemployment benefits payments expected to be paid in 2023-2032:


	Pension Benefits		Other Postemployment Benefits
Benefits to be paid in:	(Thousands of dollars)
2023	$	53,970	$	15,502
2024	$	54,807	$	15,150
2025	$	55,446	$	14,878
2026	$	56,241	$	14,488
2027	$	56,546	$	14,199
2028 through 2032	$	287,424	$	65,748

The expected benefits to be paid are based on the same assumptions used to measure our benefit obligations at December 31, 2022, and include estimated future employee service.

Other Employee Benefit Plans

401(k) Plan - We have a 401(k) plan which covers all full-time employees. Employee contributions are discretionary and we match 100 percent of each participant’s eligible contribution up to 6 percent of eligible compensation, subject to certain limits. Our contributions to the plan were $15.3 million, $14.3 million and $13.8 million in 2022, 2021 and 2020, respectively.

Effective December 30, 2021, our profit sharing-plan was merged with and into our 401(k) Plan. We plan to make a profit-sharing contribution to the 401(k) Plan each quarter equal to 1 percent of each participant’s eligible compensation during the quarter. Additional discretionary profit-sharing contributions may be made at the end of each year. Our profit-sharing contributions made to the plan were $10.9 million, $9.9 million and $9.4 million in 2022, 2021 and 2020, respectively.

15.INCOME TAXES

The following table sets forth our provision for income taxes for the periods indicated:


	Years Ended December 31,
	2022		2021		2020
	(Thousands of dollars)
Current income tax provision (benefit)
Federal	$	61,745	$	(1,568)	$	20,129
State	6,815		(1,565)		2,965
Total current income tax provision (benefit)	68,560		(3,133)		23,094
Deferred income tax provision (benefit)
Federal	(22,234)		37,810		10,757
State	200		5,639		7,728
Total deferred income tax provision (benefit)	(22,034)		43,449		18,485
Total provision for income taxes	$	46,526	$	40,316	$	41,579

The following table is a reconciliation of our income tax provision for the periods indicated:


	Years Ended December 31,
	2022			2021			2020
	(Thousands of dollars)
Income before income taxes	$	268,268		$	246,750		$	237,991
Federal statutory income tax rate	21		%	21		%	21		%
Provision for federal income taxes	56,335			51,817			49,978
State income taxes, net of federal tax benefit	7,016			4,074			10,693
Amortization of EDIT regulatory liability	(17,986)			(17,289)			(17,031)
Tax (expense) benefit for employee share-based compensation	350			(469)			(1,489)
Other, net	811			2,183			(572)
Total provision for income taxes	$	46,526		$	40,316		$	41,579

As of December 31, 2022, we have no uncertain tax positions. Changes in tax laws or tax rates are recognized in the financial reporting period that includes the enactment date. As a regulated entity, the decrease in ADIT resulting from a change in tax laws or tax rates is recorded as a regulatory liability and is subject to refund to our customers.

In May 2021, a bill amending the Oklahoma state income tax code was signed into law that reduced the state income tax rate to four percent from six percent beginning January 1, 2022. As a result of the enactment of this legislation, we remeasured our ADIT. As a regulated entity, the reduction in ADIT of $29.3 million was recorded as a regulatory liability. The impact of the change in the state income tax rate on Oklahoma Natural Gas’ rates, as well as the timing and amount of the impact on the annual crediting mechanism for the EDIT regulatory liability, was included in the March 15, 2022 PBRC filing, as approved in November 2022, and was not material.

Income tax expense reflects credits for the amortization of the regulatory liability associated with EDIT that was returned to customers of $18.0 million and $17.3 million for the years ending December 31, 2022, and 2021, respectively.

The following table sets forth the tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities for the periods indicated:


	December 31,
	2022		2021
	(Thousands of dollars)
Deferred tax assets
Employee benefits and other accrued liabilities	$	4,256	$	11,126
Regulatory adjustments for enacted tax rate changes	114,551		120,051
Net operating loss	161,320		424,861
Lease obligation basis	9,158		6,906
Purchased-gas cost adjustment	3,384		—
Other	3,014		12,597
Total deferred tax assets	295,683		575,541
Deferred tax liabilities
Excess of tax over book depreciation	792,570		734,051
Winter weather event costs	121,347		421,070
Purchased-gas cost adjustment	—		37,433
Other regulatory assets and liabilities, net	71,180		71,541
Right-of-use asset basis	9,042		6,730
Total deferred tax liabilities	994,139		1,270,825
Net deferred tax liabilities	$	698,456	$	695,284

We deduct our purchased gas costs for federal income tax purposes in the period they are paid. As a result of the impacts from government securitization of Winter Storm Uri, we recorded a $299.7 million decrease in our deferred tax liability for the year ended December 31, 2022. At December 31, 2022, we had $152.2 million (tax effected) of federal net operating loss carryforwards and $9.1 million (tax effected) of state net operating loss carryforwards available to offset future taxable income.

We have filed our consolidated federal and state income tax returns for years 2019, 2020 and 2021. We are no longer subject to income tax examination for years prior to 2019.

16.OTHER INCOME AND OTHER EXPENSE

The following table sets forth the components of other income and other expense for the periods indicated:


	Years Ended December 31,
	2022		2021		2020
	(Thousands of dollars)
Net periodic benefit (cost) other than service cost	$	3,766	$	(3,930)	$	(5,071)
Earnings (losses) on investments associated with nonqualified employee benefit plans	(7,197)		3,699		4,616
Other, net	(752)		(2,976)		(2,565)
Total other expense, net	$	(4,183)	$	(3,207)	$	(3,020)

17.COMMITMENTS AND CONTINGENCIES

Leases - See Note 5 of the Notes to Consolidated Financial Statements in this Annual Report for discussion of operating leases.

We also own or retain legal responsibility for certain environmental conditions at a former MGP site in Texas. At the request of the TCEQ, we began investigating the level and extent of contamination associated with the site under their Texas Risk Reduction Program. A preliminary site investigation revealed that this site contains contaminants generally associated with MGP sites and is subject to control or remediation under various environmental laws and regulations. Impacts have been identified in the soil and groundwater at the site with limited impacts observed in surrounding areas. On April 14, 2022, we submitted a remediation work plan to address the areas impacted to the TCEQ. At December 31, 2022, estimated costs associated with expected remediation activities for this site are not material.

the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation required, changing technology and governmental regulations, and to the extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition, results of operations or cash flows.

Legal Proceedings - We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses from such matters, individually and in the aggregate, are not material. Additionally, we believe the probable outcome of such matters will not have a material adverse effect on our results of operations, financial position or cash flows.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (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 Exchange Act. Based on this evaluation, the Company’s Principal Executive Officer and Principal Financial Officer have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this Annual Report based on the evaluation of the controls and procedures required by Rule 13a-15(b) of the Exchange Act.

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). 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 (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Because of 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. Based on our evaluation under that framework and applicable SEC rules, our management concluded that our internal control over financial reporting was effective as of December 31, 2022.

The effectiveness of our internal control over financial reporting as of December 31, 2022, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein (Item 8).

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the quarter ended December 31, 2022, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Not applicable.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

PART III.

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors of the Registrant

Information concerning our directors is set forth in our 2023 definitive Proxy Statement and is incorporated herein by this reference.

Executive Officers of the Registrant

Information concerning our executive officers is included in Part I, Item 1, Business, of this Annual Report.

Compliance with Section 16(a) of the Exchange Act

Information on compliance with Section 16(a) of the Exchange Act is set forth in our 2023 definitive Proxy Statement and is incorporated herein by this reference.

Code of Ethics

Information concerning the code of ethics, or code of business conduct, is set forth in our 2023 definitive Proxy Statement and is incorporated herein by this reference.

Nominating Procedures

Information concerning the nominating procedures is set forth in our 2023 definitive Proxy Statement and is incorporated herein by this reference.

The Audit Committee

Information concerning the Audit Committee is set forth in our 2023 definitive Proxy Statement and is incorporated herein by this reference.

The Audit Committee Financial Experts

Information concerning the Audit Committee Financial Experts is set forth in our 2023 definitive Proxy Statement and is incorporated herein by this reference.

The Executive Compensation Committee

Information concerning the Executive Compensation Committee is set forth in our 2023 definitive Proxy Statement and is incorporated herein by this reference.

The Corporate Governance Committee

Information concerning the Corporate Governance Committee is set forth in our 2023 definitive Proxy Statement and is incorporated herein by this reference.

The Executive Committee

Information concerning the Executive Committee is set forth in our 2023 definitive Proxy Statement and is incorporated herein by this reference.

Committee Charters

The full text of our Audit Committee charter, Executive Compensation Committee charter, Corporate Governance Committee charter and Executive Committee charter are published on and may be printed from our website at www.onegas.com and are also available from our corporate secretary upon request.

ITEM 11. EXECUTIVE COMPENSATION

Information on executive compensation is set forth in our 2023 definitive Proxy Statement and is incorporated herein by this reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Security Ownership of Certain Beneficial Owners

Information concerning the ownership of certain beneficial owners is set forth in our 2023 definitive Proxy Statement and is incorporated herein by this reference.

Security Ownership of Management

Information on security ownership of directors and officers is set forth in our 2023 definitive Proxy Statement and is incorporated herein by this reference.

Equity Compensation Plan Information

Information on equity compensation plans is set forth in our 2023 definitive Proxy Statement and is incorporated herein by this reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information on certain relationships and related transactions and director independence is set forth in our 2023 definitive Proxy Statement and is incorporated herein by this reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information on the principal accountant’s fees and services is set forth in our 2023 definitive Proxy Statement and is incorporated herein by this reference.

PART IV.

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES


(1) Consolidated Financial Statements			Page No.

	(a)	Report of Independent Registered Public Accounting Firm (PCAOB ID: 238)	39-40

	(b)	Consolidated Statements of Income for the years ended December 31, 2022, 2021 and 2020	42

	(c)	Consolidated Statements of Comprehensive Income for the years ended December 31, 2022, 2021 and 2020	43

	(d)	Consolidated Balance Sheets as of December 31, 202 2 and 202 1	44-45

	(e)	Consolidated Statements of Cash Flows for the years ended December 31, 202 2 , 202 1 and 20 20	46

	(f)	Consolidated Statements of Equity for the years ended December 31, 202 2 , 202 1 and 20 20	47

	(g)	Notes to Consolidated Financial Statements	48-78

(2) Consolidated Financial Statements Schedules

All schedules have been omitted because of the absence of conditions under which they are required.


(3) Exhibits

	3.1	Amended and Restated Certificate of Incorporation of ONE Gas, Inc., dated May 24, 2018 (incorporated by reference to Exhibit 3.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on May 30, 2018 (File No. 1-36108)).

	3.2	Amended and Restated By-Laws of ONE Gas, Inc. dated February 21, 2023 (incorporated by reference to Exhibit 3.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on February 21, 2023 (File No. 1-36108)).

	3.3	Amended and Restated Limited Liability Company Agreement of Kansas Gas Service Securitization I, L.L.C., dated as of November 16, 2022 (incorporated by reference to Exhibit 3.3 to ONE Gas, Inc.’s Current Report on Form 8-K filed on November 18, 2022 (File No. 1-36108)).

	4.1	Form of Common Stock Certificate (incorporated by reference to Exhibit 4.2 to ONE Gas, Inc.’s Registration Statement on Form 10, Amendment No. 2 filed on December 23, 2013 (File No. 1-36108)).

	4.2	Indenture, dated January 27, 2014, between ONE Gas, Inc. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on January 30, 2014 (File No. 1-36108)).

	4.3	Supplemental Indenture No. 1, dated January 27, 2014, between ONE Gas, Inc. and U.S. Bank National Association, as trustee, with respect to the 2.070% Senior Notes due 2019, the 3.610% Senior Notes due 2024 and the 4.685% Senior Notes due 2044-(incorporated by reference to Exhibit 10.2 to ONE Gas, Inc.’s Current Report on Form 8-K filed on January 30, 2014 (File No. 1-36108)).

	4.4	Supplemental Indenture No. 2, dated November 5, 2018, among ONE Gas, Inc. and U.S. Bank National Bank Association, as trustee, with respect to the 4.50% Senior Notes due 2048 (incorporated by reference to Exhibit 4.2 to ONE Gas, Inc.’s Current Report on Form 8-K filed on November 6, 2018 (File No. 1-36108)).


			4.5			Supplemental Indenture No. 3, dated May 4, 2020, among ONE Gas, Inc. and U.S. Bank National Bank Association, as trustee, with respect to the 2.00% Senior Notes due 2030 (incorporated by reference to Exhibit 4.2 to ONE Gas, Inc.’s Current Report on Form 8-K filed on May 4, 2020 (File No. 1-36108)).

			4.6			Fourth Supplemental Indenture, dated as of March 11, 2021, between ONE Gas, Inc. and U.S. Bank National Association, as trustee, with respect to the 0.85% Senior Notes due 2023 and 1.10% Senior Notes due 2024 (incorporated by reference to Exhibit 4.2 to ONE Gas, Inc.’s Current Report on Form 8-K filed on March 11, 2021 (File No. 1-36108)).

			4.7			Fifth Supplemental Indenture, dated as of March 11, 2021, between ONE Gas, Inc. and U.S. Bank National Association, as trustee, with respect to the Floating Rate Senior Notes due 2023 (incorporated by reference to Exhibit 4.3 to ONE Gas, Inc.’s Current Report on Form 8-K filed on March 11, 2021 (File No. 1-36108)).

			4.8			Description of the Registrant’s securities registered pursuant to Section 12 of the Securities Act of 1934 (incorporated by reference to Exhibit 4.6 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 26, 2021 (File No. 1-36108)).

			4.9			Sixth Supplemental Indenture, dated as of August 8, 2022, between ONE Gas, Inc. and U.S. Bank Trust Company, National Association, as trustee, with respect to the 4.25% Notes due 2032 (incorporated by reference to Exhibit 4.2 of ONE Gas Inc.’s Current Report on Form 8-K filed on August 8, 2022 (File No. 1-36108)).

			4.10			Indenture by and among Kansas Gas Service Securitization I, L.L.C., U.S. Bank Trust Company, National Association, as Indenture Trustee, and U.S. Bank National Association, as Securities Intermediary (including the form of the Securitized Utility Tariff Bonds and the Series Supplement), dated as of November 18, 2022 (incorporated by reference to Exhibit 4.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on November 18, 2022 (File No. 1-36108)).

			4.11			Series Supplement by and among Kansas Gas Service Securitization I, L.L.C. and U.S. Bank Trust Company, National Association, as Indenture Trustee, dated as of November 18, 2022 (incorporated by reference to Exhibit 4.2 to ONE Gas, Inc.’s Current Report on Form 8-K filed on November 18, 2022 (File No. 1-36108)).

			10.1*			Form of ONE Gas, Inc. Indemnification Agreement between ONE Gas, Inc. and ONE Gas, Inc. officers and directors (incorporated by reference to Exhibit 10.5 to ONE Gas, Inc.’s Registration Statement on Form 10 filed on October 1, 2013 (File No. 1-36108)).

			10.2*			ONE Gas, Inc. Pre-2005 Nonqualified Deferred Compensation Plan (incorporated by reference to Exhibit 10.7 to ONE Gas, Inc.’s Registration Statement on Form 10, Amendment No. 2 filed on December 23, 2013 (File No. 1-36108)).

			10.3*			ONE Gas, Inc. Nonqualified Deferred Compensation Plan (incorporated by reference to Exhibit 10.8 to ONE Gas, Inc.’s Registration Statement on Form 10, Amendment No. 2 filed on December 23, 2013 (File No. 1-36108)).

			10.4*			ONE Gas, Inc. Pre-2005 Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.9 to ONE Gas, Inc.’s Registration Statement on Form 10, Amendment No. 2 filed on December 23, 2013 (File No. 1-36108)).

			10.5*			ONE Gas, Inc. Supplemental Executive Retirement Plan, as amended and restated effective December 1, 2017 (incorporated by reference to Exhibit 10.8 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 22, 2018 (File No. 1-36108)).

			10.6*			ONE Gas, Inc. Officer Change in Control Severance Plan (incorporated by reference to Exhibit 10.12 to ONE Gas, Inc.’s Registration Statement filed on Form 10, Amendment No. 2 filed on December 23, 2013 (File No. 1-36108)).


			10.7*			ONE Gas, Inc. Equity Compensation Plan, as amended and restated effective December 1, 2017 (incorporated by reference to Exhibit 10.11 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 22, 2018 (File No. 1-36108)).

			10.8*			Form of 2019 Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.12 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 20, 2019 (File No. 1-36108)).

			10.9*			Form of 2019 Performance Unit Award Agreement (incorporated by reference to Exhibit 10.13 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 20, 2019 (File No. 1-36108)).

			10.10*			Form of 2023 Restricted Unit Award Agreement.

			10.11*			Form of 2023 Performance Unit Award Agreement.

			10.12			Extension Agreement dated as of October 5, 2018, among ONE Gas, Inc., Bank of America, N.A., as administrative agent, swing line lender, a letter of credit issuer and a lender, and the other lenders and letter of credit issuers parties thereto (incorporated by reference to Exhibit 10.1 to ONE Gas Inc’s Current Report on Form 8-K filed on October 5, 2018 (File No. 1-36108)).

			10.13*			ONE Gas, Inc. Amended and Restated Employee Stock Purchase Plan (incorporated by reference to Exhibit 10.16 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 20, 2020 (File No. 1-36108)).

			10.14			Credit Agreement, dated as of April 7, 2020, among ONE Gas, Inc., Bank of America, N.A., as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on April 7, 2020 (File No. 1-36108)).

			10.15			Form of Commercial Paper Dealer Agreement (incorporated by reference to Exhibit 10.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on September 10, 2014 (File No. 1-36108)).

			10.16*			Form of 2020 Performance Unit Award Agreement (incorporated by reference to Exhibit 10.20 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 20, 2020 (File No. 1-36108)).

			10.17*			Form of 2020 Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.21 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 20, 2020 (File No. 1-36108)).

			10.18			Equity Distribution Agreement, dated as of February 26, 2020, among ONE Gas, Inc. and Morgan Stanley & Co. LLC, BofA Securities, Inc., and Mizuho Securities USA LLC, acting as managers; Morgan Stanley & Co. LLC, Bank of America, N.A. and Mizuho Securities Americas LLC, acting as forward purchasers; and Morgan Stanley & Co. LLC, BofA Securities, Inc. and Mizuho Securities USA LLC, acting as forward sellers (incorporated by reference to Exhibit 1.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on February 26, 2020 (File No. 1-36108)).

			10.19			Form of Master Forward Sale Confirmation (incorporated by reference to Exhibit 1.2 to ONE Gas, Inc.’s Current Report on Form 8-K filed on February 26, 2020 (File No. 1-36108)).

			10.20*			Form of 2021 Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.28 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 26, 2021 (File No. 1-36108)).

			10.21*			Form of 2021 Performance Unit Award Agreement (incorporated by reference to Exhibit 10.29 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 26, 2021 (File No. 1-36108)).

			10.22			Amended and Restated Credit Agreement, dated as of October 5, 2017, among ONE Gas, Inc., Bank of America, N.A., as administrative agent, swingline lender and a letter of credit issuer, and the other lenders and letter of credit issuers parties thereto (incorporated by reference to Exhibit 10.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on October 6, 2017 (File No. 1-36108)).


			10.23*			ONE Gas, Inc. Nonqualified Deferred Compensation Plan, as amended and restated effective January 1, 2018 (incorporated by reference to Exhibit 10.28 to ONE Gas, Inc.’s Annual Report on Form 10-K filed February 22, 2018 (File No. 1-36108)).

			10.24			First Amendment and Extension Agreement, dated as of October 4, 2019, among ONE Gas, Inc., Bank of America, N.A., as administrative agent, swing line lender, a letter of credit issuer and a lender, and the other lenders and letter of credit issuers parties thereto (incorporated by reference to Exhibit 10.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on October 4, 2019 (File No. 1-36108)).

			10.25*			ONE Gas, Inc. Amended and Restated Equity Compensation Plan (2018) (incorporated by reference to Appendix A to ONE Gas, Inc.’s Definitive Proxy Statement on Schedule 14A filed on April 4, 2018 (File No. 1-36108)).

			10.26*			ONE Gas, Inc. Amended and Restated Annual Officer Incentive Plan, effective January 1, 2020 (incorporated by reference to Exhibit 10.31 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 20, 2020 (File No. 1-36108)).

			10.27*			Form of 2022 Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.28 to ONE Gas, Inc’s Annual Report on Form 10-K filed on February 24, 2022 (File No. 1-36108)).

			10.28*			Form of 2022 Performance Unit Award Agreement (incorporated by reference to Exhibit 10.29 to ONE Gas, Inc’s Annual Report on Form 10-K filed on February 24, 2022 (File No. 1-36108)).

			10.29*			Form of 2021 Restricted Unit Award Agreement dated June 2021 (incorporated by reference to Exhibit 10.30 to ONE Gas, Inc’s Annual Report on Form 10-K filed on February 24, 2022 (File No. 1-36108)).

			10.30*			Form of 2021 Performance Unit Award Agreement dated June 2021 (incorporated by reference to Exhibit 10.31 to ONE Gas, Inc’s Annual Report on Form 10-K filed on February 24, 2022 (File No. 1-36108)).

			10.31*			Form of 2021 Restricted Unit Award Agreement dated September 2021 (incorporated by reference to Exhibit 10.32 to ONE Gas, Inc’s Annual Report on Form 10-K filed on February 24, 2022 (File No. 1-36108)).

			10.32*			Form of 2021 Performance Unit Award Agreement dated September 2021 (incorporated by reference to Exhibit 10.33 to ONE Gas, Inc’s Annual Report on Form 10-K filed on February 24, 2022 (File No. 1-36108)).

			10.33*			Form of 2020 Restricted Unit Award Agreement dated July 2020 (incorporated by reference to Exhibit 10.30 to ONE Gas, Inc.'s Annual Report on Form 10-K filed February 26, 2021 (File No. 1-36108)).

			10.34*			ONE Gas Inc. Annual Officer Incentive Plan, effective January 1, 2019 (incorporated by reference to Exhibit 10.30 to ONE Gas, Inc.’s Annual Report on Form 10-K filed February 20, 2019 (File No. 1-36108)).

			10.35			Credit Agreement, dated as of February 22, 2021, among ONE Gas, Inc., the lenders from time to time party thereto and Bank of America, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to ONE Gas Inc.’s Current Report on Form 8-K filed on February 22, 2021 (File No. 1-36108)).

			10.36			Credit Agreement, dated as of March 16, 2021, among ONE Gas, Inc., the lenders from time to time party thereto and Bank of America, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on March 16, 2021 (File No. 1-36108)).

			10.37*			ONE Gas, Inc. Nonqualified Deferred Compensation Plan, as amended and restated effective January 1, 2022 (incorporated by reference to Exhibit 10.1 to ONE Gas, Inc.’s Quarterly Report on Form 10-Q filed on November 2, 2021 (File No. 1-36108)).

			10.38*			ONE Gas, Inc. Amended and Restated Employee Stock Purchase Plan (incorporated by reference to Appendix A to ONE Gas, Inc.’s Definitive Proxy Statement on Schedule 14A filed on April 7, 2021 (File No. 1-36108)).



			10.39			First Amendment to Second Amended and Restated Credit Agreement, dated as of March 16, 2022, among ONE Gas, Inc., Bank of America, N.A., as administrative agent, swing line lender and letter of credit issuer, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on March 17, 2022 (File No. 1-36108)).

			10.40			Securitization Property Purchase and Sale Agreement dated as of August 25, 2022 by and between the Oklahoma Development Finance Authority, as Issuer, and Oklahoma Natural Gas Company, a division of ONE Gas, Inc., as Seller (incorporated by reference to Exhibit 10.1 of ONE Gas, Inc.’s Current Report on Form 8-K filed on August 26, 2022 (File No. 1-36108)).

			10.41			ONE Gas, Inc. Deferred Compensation Plan for Non-Employee Directors, amended and restated effective July 18, 2022 (incorporated by reference to Exhibit 10.3 of ONE Gas, Inc.’s Quarterly Report on Form 10-Q filed on November 1, 2022 (File No. 1-36108)).

			10.42			Securitized Utility Tariff Property Servicing Agreement between Kansas Gas Service Securitization I, L.L.C. and Kansas Gas Service, a Division of ONE Gas, Inc., as Servicer, dated as of November 18, 2022 (incorporated by reference to Exhibit 10.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on November 18, 2022 (File No. 1-36108)).

			10.43			Securitized Utility Tariff Property Purchase and Sale Agreement between Kansas Gas Service Securitization I, L.L.C. and Kansas Gas Service, a Division of ONE Gas, Inc., as Seller, dated as of November 18, 2022 (incorporated by reference to Exhibit 10.2 to ONE Gas, Inc.’s Current Report on Form 8-K filed on November 18, 2022 (File No. 1-36108)).

			10.44			Administration Agreement between Kansas Gas Service Securitization I, L.L.C. and Kansas Gas Service, a Division of ONE Gas, Inc., as Administrator, dated as of November 18, 2022 (incorporated by reference to Exhibit 10.3 to ONE Gas, Inc.’s Current Report on Form 8-K filed on November 18, 2022 (File No. 1-36108)).

			21.1			Subsidiaries of ONE Gas, Inc.

			23.1			Consent of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP.

			31.1			Certification of Robert S. McAnnally pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

			31.2			Certification of Caron A. Lawhorn pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

			32.1			Certification of Robert S. McAnnally pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).

			32.2			Certification of Caron A. Lawhorn pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).


			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			XBRL Schema Document.

			101.CAL			XBRL Calculation Linkbase Document.

			101.LAB			XBRL Label Linkbase Document.

			101. PRE			XBRL Presentation Linkbase Document.

			101.DEF			XBRL Extension Definition Linkbase Document.

			104			Cover Page Interactive Data File (embedded within the Inline XBRL document and contained in Exhibit 101).

* Management contract or compensatory plan or arrangement

Attached as Exhibit 101 to this Annual Report are the following XBRL-related documents: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the years ended December 31, 2022, 2021 and 2020; (iii) Consolidated Statements of Comprehensive Income for the years ended December 31, 2022, 2021 and 2020; (iv) Consolidated Balance Sheets as of December 31, 2022 and 2021; (v) Consolidated Statements of Cash Flows for the years ended December 31, 2022, 2021 and 2020; (vi) Consolidated Statements of Equity for the years ended December 31, 2022, 2021 and 2020; and (vii) Notes to Consolidated Financial Statements.

We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Annual Report.

ITEM 16. FORM 10-K SUMMARY

None.

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


Date:	February 23, 2023		ONE Gas, Inc.
			Registrant

		By:	/s/ Caron A. Lawhorn
			Caron A. Lawhorn
			Senior Vice President and
			Chief Financial Officer

Pursuant to the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on this 23rd day of February 2023.


			/s/ John W. Gibson						/s/ Robert S. McAnnally
			John W. Gibson						Robert S. McAnnally
			Chairman of the Board						President, Chief Executive Officer
									and Director

			/s/ Caron A. Lawhorn						/s/ Brian F. Brumfield
			Caron A. Lawhorn						Brian F. Brumfield
			Senior Vice President and						Vice President, Chief Accounting Officer
			Chief Financial Officer						and Controller
									(Principal Accounting Officer)

			/s/ Robert B. Evans						/s/ Tracy E. Hart
			Robert B. Evans						Tracy E. Hart
			Director						Director

			/s/ Michael G. Hutchinson						/s/ Pattye L. Moore
			Michael G. Hutchinson						Pattye L. Moore
			Director						Director

			/s/ Eduardo A. Rodriguez						/s/ Douglas H. Yaeger
			Eduardo A. Rodriguez						Douglas H. Yaeger
			Director						Director