EDGAR 10-K Filing

Company CIK: 1587732
Filing Year: 2022
Filename: 1587732_10-K_2022_0001587732-22-000019.json

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ITEM 1. BUSINESS
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 our approximately 2.2 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, 72 percent and 13 percent of the natural gas distribution customers in Oklahoma, Kansas and Texas, respectively.
OUR STRATEGY
Our vision is to be a premier natural gas distribution company, creating exceptional value for all stakeholders. 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 through programs, procedures, policies, guidelines and internal controls designed to mitigate risk and incidents that may harm our employees, contractors, customers, the public or the environment. A significant portion of our capital spending is focused on the safety, integrity, reliability and efficiency of our natural gas distribution system, which also has the benefit of reducing methane emissions from our pipeline system. We also deploy a variety of operational and damage prevention procedures and technologies to monitor and maintain our natural gas distribution system and allow safe delivery of natural gas to our customers. Our Company’s focus on safety also extends to protecting our assets and information systems from physical damage and cyber intrusions through the utilization of robust security solutions, workforce training and crisis drills, among other initiatives.
•A High-performing Workforce - Our employees are the foundation of our Company. Our success begins with a values-driven culture and a commitment to developing an innovative, agile, diverse and engaged workforce where every employee understands that they can and do make a difference.
•Capital Demand Growth - As a result of our commitment to enhance the integrity, reliability and safety of our existing infrastructure, we are making significant investments in our existing system. In addition, as some of our service territories continue to experience accelerating economic growth, our capital investments for main line extensions and service lines to serve new customers, will further contribute to our growth.
•Customer Affordability - We understand the importance of providing reliable, but also affordable, energy to our customers. We are focused on efficiently managing our resources and leveraging innovative technology solutions to enhance operational efficiency. We offer energy efficiency and education programs that 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.
•Energy Transition Solutions - We are committed to environmental stewardship, social responsibility and good corporate governance, all evaluated through the lens of our core values of safety, ethics, diversity and inclusion, service and value. We are focused on continually improving and expanding disclosures of our ESG-related plans, programs, goals and targets. We believe that natural gas assets will continue to play a pivotal role in a cleaner energy future and that we are uniquely positioned to deliver affordable, reliable and renewable energy to customers, now and into the future.
REGULATORY OVERVIEW
We are subject to the regulations 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. Texas Gas Service is subject to regulatory oversight by the various incorporated cities that it serves, which have primary jurisdiction for their respective service areas. Rates in unincorporated areas of our service territory in Texas and all appellate matters are subject to regulatory oversight by the RRC. These regulatory authorities have the responsibility of ensuring that the utilities in their jurisdictions provide safe and reliable service at a reasonable cost, while providing utility companies 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 for specific costs or investments made between rate cases. 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 receive 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 2022 through 2026. Oklahoma Natural Gas is also required to file a rate case on or before June 30, 2027, based on a test year consisting of the twelve months ended 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 this surcharge. Kansas Gas Service expects to file rate adjustments annually for this surcharge until it is required to file a rate case under the GSRS statute.
Texas - Texas Gas Service provides service to customers in five service areas. These service areas are further divided into the incorporated cities and the unincorporated areas. Periodic rate cases are filed with the cities or the RRC, as needed. Between rate cases, Texas Gas Service can adjust rates through annual filings pursuant to the GRIP statute or an annual COSA filing.
Annual filings under the GRIP statute allow Texas Gas Service to recover taxes and depreciation and to earn 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. Texas Gas Service makes annual GRIP filings for the incorporated cities in three of its service areas and for the unincorporated areas in all five service areas, which combined comprise 89 percent of Texas Gas Service’s customers.
COSA tariffs permit Texas Gas Service to recover return, taxes and depreciation on the annual increases in net investment, and adjust 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 regulator but is not required. Texas Gas Service makes an annual COSA filing for the incorporated cities in two of its service areas, comprising 11 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 Return on Equity
Oklahoma Natural Gas (2)
Oklahoma November 2021 $1,726 8.95% 59% 9.40%
Kansas Gas Service (3)
Kansas December 2021 $1,197 8.60% N/A
9.30%
Texas Gas Service (2)
Central-Gulf June 2021 $547 8.95% 59% 9.50%
West Texas July/August 2021 $468 8.80% 60% 9.50%
Rio Grande Valley August 2021 $146 8.89% 61% 9.50%
North Texas August 2021 $68 9.16% 62% 9.75%
Borger / Skellytown December 2020 $10 9.16% 62% 9.75%
Division Jurisdiction Interim Rate Adjustment Mechanism Interim Capital Recovery WNA WNA Effective Dates Energy Efficiency / Conservation Program
Oklahoma Natural Gas Oklahoma PBRC Yes Yes November - April Yes
Kansas Gas Service (3)
Kansas GSRS Yes Yes January - December No
Texas Gas Service Central-Gulf GRIP Yes Yes September - May Yes
West Texas GRIP Yes Yes September - May No
Rio Grande Valley GRIP / COSA
Yes Yes September - May Yes
North Texas GRIP / COSA
Yes Yes September - May No
Borger / Skellytown GRIP Yes Yes September - May No
Division Jurisdiction Purchased Gas Adjustment(4)
Bad Debt Recovery(5)
Expense Trackers(6)
Oklahoma Natural Gas Oklahoma Yes Yes N/A
Kansas Gas Service (3)
Kansas Yes Yes Yes
Texas Gas Service Central-Gulf Yes Yes Yes
West Texas Yes Yes Yes
Rio Grande Valley Yes Yes Yes
North Texas Yes Yes Yes
Borger / Skellytown Yes Yes Yes
(1) Effective date of last approved rate case or interim filing.
(2) The rate base, authorized rate of return, authorized debt/equity ratio and authorized return on equity presented in this table are those from the most recent approved regulatory filing for Oklahoma Natural Gas and Texas Gas Service. These rate bases, rates of return, debt/equity ratios and returns on equity are not necessarily indicative of current or future rate bases, rates of return, debt/equity ratios or returns on equity.
(3) Kansas Gas Service’s most recent rate case, approved in February 2019, settled without a determination of rate base, rate of return, authorized debt/equity ratio and authorized return on equity within the settlement. This reflects Kansas Gas Service’s estimate of rate base from that rate case adjusted for approved GSRS filings and return on equity 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.
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, 2021, approximately 88 percent, 55 percent, and 68 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 164 Bcf and 153 Bcf of natural gas supply in 2021 and 2020, 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 interruption, 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. The consumption patterns for our customers may change from time-to-time in response to a variety of possible 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 electricity.
In each jurisdiction in which we operate, changes in customer-usage profiles are considered in the periodic redesign of our rates.
As of December 31, 2021, we had 51.4 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 1.4 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 assure the reliability of gas deliveries during peak demands for natural gas. Approximately 26 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 discussion 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, and this competition has and may continue to impact revenues. 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 have continued to supply natural gas to CNG fueling stations. Our strategy is to support third-party investment in CNG fueling stations. We deploy capital to connect CNG stations built and operated by third parties to our system. As of December 31, 2021, we supply 145 fueling stations, 33 of which we operate in conjunction with our own fleets. Of the 112 remaining stations, 66 are retail and 46 are private stations. We transported 2.8 million Dth to CNG stations in 2021, which represents an increase of 6 percent compared with 2020.
RNG and Hydrogen - RNG and hydrogen technologies offer potential opportunities to secure new gas supply sources that could be transported on our pipelines. We are making investments in RNG and hydrogen technologies and innovation, including: (1) establishing interconnection guidelines for delivery of RNG to our system, (2) working directly with developers and end-use customers to identify potential RNG 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 develop methodologies regarding hydrogen blending and utilization, and (5) evaluating the opportunity to reduce our greenhouse gas emissions.
ENVIRONMENTAL AND SAFETY MATTERS
See Note 16 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
The foundation of our Company is our employees and our success begins with a culture driven by our core values and a commitment to developing an innovative, agile, diverse and engaged workforce where every employee understands that they can and do make a difference. We believe that advancing a safe, ethical, inclusive and diverse culture creates an environment that attracts and retains the high-performing workforce needed to successfully execute our strategy.
Employees and Employee Engagement - We employed approximately 3,600 people at February 1, 2022, 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, 2022:
Union Approximate Employees Contract Expires
The United Steelworkers 400 May 31, 2022
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 and the foundation of everything we do. A strong safety culture 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 teammates, our customers and communities safe. To reinforce our commitment to the safety and well-being of our employees, customers and communities we include four operational measures, TRIR, DART, PVIR and ERT, in our short-term incentive compensation. By including four operational measures in our short-term incentive compensation, we 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 in these operational measures for the periods indicated:
Years Ended December 31,
Operational measure 2021 2020 2019
TRIR 0.96 1.02 1.04
DART 0.22 0.28 0.25
PVIR 2.10 1.76 1.75
ERT 62.7% 64.5% 62.8%
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 employees, 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 the performance of our diversity statistics about our workforce across roles and seniority levels. Additionally, we make available conscious inclusion training to all employees. We also have an Inclusion and Diversity Council, which is chaired by our Chief Executive Officer, and includes five employees serving as permanent members, with 14 employees serving as rotating members with two-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. We also have employee-led resource groups to provide community and support to our employees based on shared characteristics, interests or experiences. We continue to examine how we can promote inclusion and diversity in our human capital management and may implement additional practices in the future.
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 58 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 60 2019 to present Senior Vice President and Chief Financial Officer
2014 to 2019 Senior Vice President, Commercial
Joseph L. McCormick 62 2014 to present Senior Vice President, General Counsel and Assistant Secretary
Curtis L. Dinan 54 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 57 2015 to present Senior Vice President, Administration and Chief Information Officer
Jeffrey J. Husen 50 2018 to present Vice President, Chief Accounting Officer and Controller
2014 to 2018 Controller
* As of January 1, 2022
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 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 public investors. Information contained on our website and posted on or disseminated through our social media accounts is not incorporated by reference into this report.

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ITEM 1A. RISK FACTORS
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.
RISK FACTORS INHERENT IN OUR BUSINESS
Operational Risks
Pandemics or other health crises could have an adverse effect on our business.
Our business and our customers could be materially and adversely affected by the risks, or the public perception of the risks, related to a pandemic or other health crisis, such as the outbreak of COVID-19. The COVID-19 pandemic has had an unprecedented impact on the U.S. and its economy and continues to create significant uncertainties about the potential adverse effect of the pandemic on the economy, our customers, our employees and supply chain partners.
As an essential business, we implemented business continuity and emergency response plans at the beginning of the pandemic that allowed us to continue to provide natural gas services to customers and support our operations, while taking health and safety measures such as implementing worker distancing measures and using a remote workforce where possible.
To the extent the COVID-19 pandemic adversely affects our business, it may also have the effect of heightening many of the other risks described in Item 1A of this Annual Report.
Our business increasingly relies on technology, the failure of which, or the occurrence of cyber breaches or physical security attacks thereon, or those of third parties, 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 to help run our financial and operations organizations, including an enterprise resource planning system that integrates data and reporting activities across our Company. 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 use of technological programs, systems and tools may subject our business to increased risks.
Our business is dependent upon our operational systems to process a large amount of data and complex transactions. As part of our operations, we come into contact with sensitive information, including personally identifiable information. If any of our financial, operational or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee or third party causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee or third-party tampering or manipulation of those systems will result in losses that are difficult to detect or mitigate.
Additionally, certain portions of our IT, customer service, resource management, pipeline and infrastructure installation and maintenance, engineering, payroll and human resources functions that we rely on are provided by third-party vendors. Services provided by third parties could be disrupted due to events and circumstances beyond our control which could adversely impact our business, financial condition, results of operations and cash flows.
In March 2020, remote working arrangements for our employees increased as a result of the COVID-19 pandemic, requiring enhancements and modifications to our IT infrastructure (e.g. Internet, Virtual Private Network, remote collaboration systems, etc.). Experts have observed an increase in the volume and the sophistication of cyberattacks since the beginning of the COVID-19 pandemic.
Any cyber breaches or physical security attacks, or threats of such attacks, that affect our information technology systems, distribution facilities, our customers, our 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. Physical damage due to a cyber security incident or acts of cyber terrorism could impact services and could lead to material liabilities. 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 are increasingly focused on risks related to physical security and cybersecurity in general and have implemented more stringent security requirements specifically for certain federal contractors and critical infrastructure sectors, including natural gas distribution. In addition, cyber or physical attacks or threats on our suppliers, third-party service providers or our Company, customer and employee data may result in a financial loss and may adversely impact our business, financial condition, results of operations and cash flows. Third-party systems on which we rely could also suffer such attacks or operational system failure.
While we continue to bolster our physical security and cybersecurity practices, including the implementation of certain security measures required by the federal government and the continued evaluation and improvement of existing policies, procedures, protective technologies, and controls to prevent and detect cyber breaches or physical security attacks, there is no guarantee that these efforts (or any similar efforts by third parties on which we rely) will be effective against any particular cyber breach or physical attack or protect us from unauthorized access or damage to our systems. 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.
We are subject to pipeline safety and system integrity laws and regulations that may require significant expenditures, significant increases in operating costs or, in the case of noncompliance, substantial fines or penalties.
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. These requirements are subject to change, either as a result of new statutes or regulations or modifications to the existing statutes or regulations. 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 could expose us to civil or criminal liability, enforcement actions, fines, penalties or injunctive measures that may not be recoverable from customers in rates and could have a material adverse effect on our business, financial condition, results of operations and cash flows, and reputation.
We are subject to strict regulations at many of our facilities and job sites regarding employee safety, and failure to comply with these regulations could adversely affect our financial results or result in significant fines or penalties.
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. The failure to comply with DOT, OSHA and state requirements or general industry standards, including keeping adequate records or preventing occupational exposure to regulated substances, could expose us to civil or criminal liability, enforcement actions, and regulatory fines and penalties that may not be recoverable through our rates and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Although we employ safety procedures in the design and operation of our facilities, there is a risk that an accident or injury to one of our employees could occur in one of our facilities. Any accident or injury to our employees could result in litigation, operational delays and harm to our reputation, which could negatively affect our business, operating results and financial condition.
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 of the risks and hazards typically associated with the natural gas distribution business. Operating risks include, but are not limited to, leaks, 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 (for example, this may occur if a third-party were to perform excavation or construction work near our facilities or vehicles colliding with above-ground pipeline facilities) and catastrophic events, such as severe weather events, hurricanes, thunderstorms, tornadoes, sustained extreme temperatures, earthquakes, floods or other similar events beyond our control. Disruptions to the operations of natural gas producers who supply us with natural gas, including due to the loss of power or extreme temperatures, could disrupt our ability to serve our customers. 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. Lapses in judgement or failure to follow protocols by our employees or service providers could lead to warranty and indemnification liabilities or catastrophic accidents, causing property damage or personal injury. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage caused to or by employees, customers, contractors, vendors and other third parties. The location of pipeline facilities near populated areas, including residential areas, commercial business centers and industrial gathering places, could increase the level of damages resulting from these risks. Liabilities incurred and interruptions to the operations of our pipelines or other facilities caused by such an event could reduce revenues generated by us and increase expenses, which could have a material adverse effect on our financial condition, results of operations and cash flows. Additionally, our regulators may not allow us to recover part or all of the increased cost related to the foregoing events from our customers, which would adversely affect our earnings and cash flows.
Unanticipated events or a combination of events, failure in resources needed to respond to events, or slow or inadequate response to events may have an adverse impact on our financial condition, results of operations and cash flows.
While we have general liability, cyber, and property insurance currently in place in amounts that we consider appropriate based on our assessment of business risk and best practices in our industry and in general business, such policies are subject to certain limits, deductibles and policy exclusions. Further, we are not fully insured against all risks inherent in our business, including certain types of catastrophic events. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and, in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. Consequently, we may not be able to renew existing insurance policies or purchase other desirable insurance on commercially reasonable terms, if at all.
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 paid 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.
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. We must contract for reliable and adequate delivery capacity for our transmission and distribution systems, while considering the dynamics of the interstate and intrastate pipeline capacity markets, our own in-system resources, as well as the characteristics of our customer base. If we are unable to obtain these, our ability to meet our customers’ natural gas requirements could be impaired. A significant disruption to or reduction in natural gas supply, pipeline capacity or storage capacity due to events including, but not limited to, operational failures or disruptions, severe weather events, hurricanes, thunderstorms, tornadoes, sustained extreme temperatures, earthquakes, floods, freeze off of natural gas wells, terrorist or cyber-attacks or other acts of war, or legislative or regulatory actions, could reduce our available supply of natural gas. Such severe events may also cause significant reductions in our natural gas in storage, which will take time to replenish, and cause gas restrictions or curtailment of operations and delivery of natural gas to customers including, for example, restrictions and curtailments imposed by regulators during Winter Storm Uri in February 2021. These types of events and disruptions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We may not be able to complete necessary or desirable expansion or infrastructure development projects, which may delay or prevent us from serving our customers or expanding our business.
In order to serve new customers or expand our service to existing customers, we may need to maintain, expand or upgrade our distribution and/or transmission infrastructure, including laying new distribution lines. Various factors may prevent or delay us from completing such projects or make completion more costly, such as the inability to obtain required approvals from local, state and/or federal regulatory and governmental bodies, public opposition to the project, inability to obtain adequate financing, right-of-way acquisition, competition for labor and materials, construction delays, cost overruns, and inability to negotiate acceptable agreements relating to construction or other material components of an infrastructure development project. As a result, we may not be able to adequately serve existing customers or support customer growth, which would adversely impact our business, stakeholder perception, financial condition, results of operations and cash flows.
Our risk-management policies and procedures may not be effective, and employees may violate our risk-management policies.
We have implemented a set of policies and procedures that involve both our senior management and the Audit Committee of our Board of Directors to assist us in managing risks associated with our business. These risk-management policies and procedures are intended to align strategies, processes, people, IT and business knowledge so that risk is managed throughout the organization. However, as conditions change and become more complex, current risk measures may fail to assess adequately the relevant risks associated with our business and the presence of risks previously unknown to us. Additionally, if employees fail to adhere to our policies and procedures or if our policies and procedures are not effective, potentially because of future conditions or risks outside of our control, we may be exposed to greater risk than we had intended. Ineffective risk-management policies and procedures or violation of risk-management policies and procedures could have a material adverse effect on our earnings, financial condition and cash flows.
Failure to maintain the security of personally identifiable information could adversely affect us.
In connection with our business we and our vendors, suppliers and contractors collect and retain personally identifiable information (e.g., information of our customers, shareholders, suppliers, third-party service providers and employees), and there is an expectation that we and such third parties will adequately protect that information. The U.S. regulatory environment surrounding information security and privacy is increasingly demanding. New laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and could potentially elevate our costs. Any failure by us to comply with these laws and regulations, including as a result of a security or privacy breach, could result in significant penalties and liabilities for us. A significant theft, loss or fraudulent use of the personally identifiable information we maintain or failure of our vendors, suppliers and contractors to use or maintain such data in accordance with contractual provisions could adversely impact our reputation and could result in significant costs, fines and litigation.
Our business could be adversely affected by strikes or work stoppages by our unionized employees, which may impact our operations, cash flows and earnings.
At February 1, 2022, approximately 700 of our estimated 3,600 employees were represented by collective-bargaining units under collective-bargaining agreements. We are involved periodically in discussions with collective-bargaining units representing some of our employees to negotiate or renegotiate labor agreements. We cannot predict the results of these negotiations, including whether any failure to reach new agreements will have a negative effect on our business, financial condition and results of operations or whether we will be able to reach any agreement with the collective-bargaining units. Any failure to reach agreement on new labor contracts might result in a work stoppage. Any future work stoppage could, depending on the operations and the length of the work stoppage, have a material adverse effect on our financial condition, results of operations and cash flows.
A shortage of skilled labor may make it difficult for us to maintain labor productivity and competitive costs, which could adversely affect operations, cash flows and earnings. Further, we may be unable to attract and retain management and professional and technical employees, which could adversely impact our operations, earnings and cash flows.
Our operations require skilled and experienced workers with proficiency in multiple tasks. A shortage of workers trained in various skills associated with the natural gas distribution business could cause us to conduct certain operations without full staff, thus hiring outside resources, which may decrease productivity and increase costs. This shortage of trained workers can result from experienced workers reaching retirement age and increased competition for workers in certain areas, combined with the challenges of attracting new qualified workers to the natural gas distribution industry. A shortage of skilled labor could continue over an extended period. If the shortage of experienced labor continues or worsens, it could have an adverse impact on our productivity and costs and our ability to meet the needs of our customers, which could adversely affect our business 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 talented management and professionals while retaining a skilled, agile, diverse and engaged workforce. We are subject to the risk that we will not be able to effectively replace or transfer the knowledge and expertise of retiring management or employees. Without effective succession, our ability to provide quality service to our customers and satisfy our regulatory requirements will be challenged, and this could adversely impact our business, financial condition, results of operations and cash flows.
We are subject to environmental regulations and failure to comply with these regulations could result in significant fines or penalties and could adversely affect our operations or financial results.
We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local governmental authorities relating to environmental and health and safety matters, including those legal requirements 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, protection of natural and cultural resources, as well as work practices related to employee health and safety. Many of these laws or regulations require us to obtain permits for certain of our operations, and we may not always be able to obtain such permits on terms satisfactory for our operations or planned timelines. 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. Certain laws provide for strict, joint and several liability, without regard to fault or the legality of the original act. 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 that may not be
recoverable through our rates or insurance and could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We also own or retain legal responsibility for certain environmental conditions at certain former MGP sites. A number of environmental issues may exist with respect to these former MGP sites. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation, changing technology and governmental regulations and could be material to our financial condition, results of operations and cash flows.
With the trend toward stricter standards, greater regulation and more extensive permit requirements for the types of assets operated by us that are subject to environmental regulation, 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, which could adversely affect our financial condition, results of operations and cash flows.
We are subject to various risks associated with climate change, which may adversely affect our financial results, growth, cash flows and results of operations.
Our business is subject to both transition and physical risks due to climate change. Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. Climate change is projected to 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. 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. Severe weather impacts our operating territories 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. We may not be able to pass on the higher costs to our customers or recover all the costs related to mitigating these physical risks.
In addition, to the extent climate change adversely impacts the economic health of our operating territory, it could adversely impact customer demand or our customers’ ability to pay. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could adversely affect our ability to access capital markets or cause us to receive less favorable terms and conditions in future financings. Financial institutions are increasingly making commitments to achieve net-zero financed greenhouse gas emissions. As they take steps to implement these commitments, they may adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. The adoption of such policies may be hastened by government actions, including regulations from the Biden Administration to address climate risk in the financial sector and the Federal Reserve’s implementation of recommendations from the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. A material reduction in the capital available or an increase in the cost of capital could make it more difficult for us to finance the investments necessary to maintain the safety and reliability of our distribution system. In addition, increases in the cost of capital or limited availability of capital to the fossil fuel industry could result in decreased supplies of natural gas available for distribution, or otherwise negatively impact our financial performance, growth, cash flows, or results of operations. For more information, see our risk factors titled “Increases in the price of natural gas could reduce our earnings, increase our working capital requirements, and adversely impact our customer base” and “We may be unable to access capital or our cost of capital may increase significantly which may adversely affect our results of operations, cash flows and financial condition.”
Our business could be affected by lawsuits related to climate change. Various parties (including individuals, local governments, and environmental groups) have brought suit in a number of jurisdictions seeking to hold greenhouse gas emitters liable for the impacts of climate change. Although novel legal theories continue to be developed, many of these suits are brought on one of the following themes: (1) oil and gas companies are liable for various asserted damages associated with the production or sale of fuels that contributed to climate change and (2) oil and gas companies have been aware of the adverse effects of climate change for some time but failed to adequately disclose those impacts to investors or consumers. Although we are not currently named in any such suits, the success of such suits could adversely impact our business, results of operations and cash flows.
We are also subject to political, regulatory, and legislative risks. For more information, see our risk factor titled “Carbon neutral, energy-efficiency or other legislation or regulations intended to address climate change could increase our operating costs or restrict our market opportunities, adversely affecting our financial results, growth, cash flows and results of operations.”
Regulatory and Legislative Risks
Regulatory actions 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 regulation by the OCC, KCC, RRC and various municipalities in Texas, who set the rates that we charge our customers for our services. Our ability to obtain timely future rate increases depends on regulatory discretion. Significant events, including severe weather events, such as Winter Storm Uri, may result in us experiencing extraordinary costs, including unforeseeable and unprecedented market pricing for gas costs and financing costs related to the payment of gas costs, all or a part of which may not be recoverable through our tariffs in each state where we operate. As such, there can be no assurance that we will be able to obtain rate increases, fully recover our extraordinary costs or that our authorized rates of return will continue at the current levels.
We monitor and compare the rates of return we achieve with our allowed rates of return and initiate general and specific rate proceedings as needed. If a regulatory agency were to prohibit us from setting rates that allow for the timely recovery of our costs and a reasonable return by significantly lowering our allowed return or adversely altering our cost allocation, rate design or other tariff provisions, modifying or eliminating cost trackers, prohibiting recovery of regulatory assets or disallowing portions of our expenses, then our earnings could be adversely impacted. Regulatory proceedings also involve a risk of rate reduction, because once a proceeding has been filed, it is subject to challenge by various intervenors. Risks and uncertainties relating to delays in obtaining, or failure to obtain, regulatory approvals, conditions imposed in regulatory approvals, and determinations in regulatory proceedings can also impact our financial performance. In particular, the timing and amount of rate relief can materially impact our results of operations, financial condition and cash flows.
Further, accounting principles that govern our Company permit certain assets that result from the regulatory process to be recorded on our consolidated balance sheets that could not be recorded under GAAP for nonregulated entities. We consider factors such as rate orders from regulators, previous rate orders for substantially similar costs, written approval from our regulators and analysis of recoverability by internal and external legal counsel to determine the probability of future recovery of these assets. If we determine future recovery is no longer probable, we would be required to write off the regulatory assets at that time, which would adversely affect our financial condition, results of operations and cash flows. Regulatory authorities also review whether our natural gas costs are prudent and can adjust the amount of our natural gas costs that we pass through to our customers. In certain instances, including in the event of significant and severe weather events, we may apply to regulators seeking authority to timely recover extraordinary costs, and our application may not be approved. If any of our natural gas costs or related expenses were disallowed, our results of operations and cash flows would be adversely affected.
In the normal course of business in the regulatory environment, assets are placed in service before regulatory action is taken, such as filing a rate case or for 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 studying 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.
The profitability of our operations is dependent on our ability to timely recover the costs related to providing natural gas service to our customers. However, we are unable to predict the impact that new regulatory requirements will have on our operating expenses or the level of capital expenditures and we cannot give assurance that our regulators will continue to allow recovery of such expenditures in the future. Changes in the regulatory environment applicable to our business or the imposition of additional regulation could impair our ability to recover costs absorbed historically by our customers, and adversely impact our results of operations, financial condition and cash flows.
A successful challenge to the securitization statute in Oklahoma could adversely affect our financial condition, earnings and cash flows.
There is a legal challenge to the securitization statute in Oklahoma. If successful, this legal challenge is not expected to affect our ability to recover the extraordinary costs associated with Winter Storm Uri. However, we would not be able to finance these costs through a securitization. Instead, Oklahoma Natural Gas would have to seek regulatory approval for an alternate cost recovery method. Under such a scenario, customers would likely see an increase in the charge for the extraordinary costs relative to the charge we would expect with securitization, which could make it more difficult for customers to pay their 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 and could adversely affect our results of operations, financial condition and cash flows.
We are subject to comprehensive energy regulation by governmental agencies, and the recovery of our costs is dependent on regulatory action.
We are subject to comprehensive regulation by several state and municipal utility regulatory agencies, which significantly influences our operating environment and our ability to recover our costs from utility customers. The utility regulatory authorities in Oklahoma, Kansas and Texas regulate many aspects of our utility operations, including organization, safety, financing, affiliate transactions, customer service and the terms of service to customers, including the rates that we can charge customers.
The profitability of our operations is dependent on our ability to recover costs, including income taxes, related to providing natural gas to our customers by filing periodic rate cases or other filings. The regulatory environment applicable to our operations could impair our ability to recover costs historically included in the rates billed to our customers. In addition, as the regulatory environment applicable to our operations increases in complexity, the risk of inadvertent noncompliance could also increase. Our failure to comply with applicable laws and regulations could result in the imposition of fines, penalties or other enforcement actions by the authorities that regulate our operations that may not be recoverable in our rates.
We are unable to predict the impact that the future regulatory activities of these agencies will have on our operations. Changes in regulations or the imposition of additional regulations could have an adverse impact on our business, financial condition and results of operations. Further, the results of our operations could be impacted adversely if our authorized cost-recovery mechanisms do not function as anticipated.
Our business and operations are subject to regulation by a number of federal agencies, including FERC, DOT, OSHA, EPA, CFTC and various regulatory agencies in Oklahoma, Kansas and Texas, and we are subject to numerous federal and state laws and regulations. Future changes to laws, regulations and policies may impair our ability to compete for business or to recover costs and may increase the cost of our operations. Furthermore, because the language in some laws and regulations is not prescriptive, there is a risk that our interpretation of these laws and regulations may not be consistent with expectations of regulators. Any compliance failure related to these laws and regulations may result in fines, penalties or injunctive measures affecting our operating assets. For example, under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act of 1938, as amended, to impose penalties of up to $1 million per day for each violation. In addition, as the regulatory environment for our industry increases in complexity, the risk of inadvertent noncompliance could also increase. 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.
Carbon neutral, energy-efficiency or other legislation or regulations intended to address climate change 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.
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. In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that greenhouse gas emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for greenhouse gas emissions from certain large stationary sources and require the monitoring and annual reporting of greenhouse gas emissions from certain fossil fuel systems (including certain of our operations). The regulation of methane from oil and gas facilities, including systems to transport and distribute natural gas, has been subject to uncertainty in recent years; in September 2020, the Trump Administration revised prior regulations, rescinding certain methane standards and removing the transmission and storage segments from the source category for certain regulations. However, on January 20, 2021, President Biden signed an executive order calling for the suspension, revision, or recission of the September 2020 rule and the establishment of new standards applicable to existing oil and gas operations, including the transmission and storage segments.
President Biden has announced that climate change will be a focus of his administration and has signed several executive orders on the subject. For example, on January 27, 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased production of renewable energy on federal lands and waters, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risk across governmental agencies and economic sectors. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as greenhouse gas cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of 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 provide a cost advantage to 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. For example, as part of the Consolidated Appropriations Act, 2021, Congress has provided extensions for key renewable energy tax credits. Internationally, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emission reduction targets every five years after 2020. Although the United States had withdrawn from the agreement, President Biden has signed executive orders recommitting the United States to the agreement and calling on the federal government to begin formulating the United States’ nationally determined emissions reduction targets under the agreement.
The focus on climate change could adversely impact the reputation of fossil fuel products or services. The occurrence of the foregoing events could put upward pressure on the cost of natural gas relative to other energy sources, increase our costs and the prices we charge to customers, reduce the demand for natural gas or cause fuel switching to other energy sources, and impact the competitive position of natural gas and the ability to serve new or existing customers, adversely affecting our business, results of operations and cash flows.
Certain of our operations occur on lands that may be subject to various indigenous rights.
Parts of our operations cross lands that historically have been held by or within the jurisdiction of various Native American tribes, who may exercise significant jurisdiction and sovereignty over their lands. Our operations may be impacted to the extent these tribal governments are found to have and choose to act upon such jurisdiction over lands where we operate. For example, a U.S. Supreme Court ruling in 2020 found that the Muscogee (Creek) Nation reservation in Eastern Oklahoma has not been disestablished. State courts in Oklahoma, applying the analysis in the U.S. Supreme Court’s ruling regarding the Muscogee (Creek) Nation, have ruled that the Cherokee, Chickasaw, Seminole, Choctaw, and Quapaw reservations likewise have not been disestablished. The U.S. Supreme Court’s ruling and these companion decisions could lead to some confusion as to which agencies have authority to regulate activities in these areas of Oklahoma. Costs associated with compliance with these additional regulatory requirements could be material and could adversely affect our business, results of operations and cash flows.
We are involved in legal or administrative proceedings before various courts and governmental bodies that could adversely affect our financial condition, results of operations and cash flows.
In the normal course of business, we are involved in legal or administrative proceedings before various courts and governmental bodies with respect to general claims, rates, environmental issues, gas cost prudence reviews and other matters. Adverse decisions regarding these matters, to the extent they require us to make payments in excess of amounts provided for in our consolidated financial statements, or to the extent they are not covered by insurance, could adversely affect our financial condition, results of operations and cash flows.
Changes in federal and state fiscal, tax and monetary policy could significantly increase our costs and decrease our cash flows.
Changes in federal and state fiscal, tax and monetary policy may result in increased taxes, interest rates, and inflationary pressures on the costs of goods, services and labor or may result in refunding amounts previously collected for deferred taxes to customers on an accelerated basis. 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. This series of events may cause us to seek increases in the rates we charge customers and thus may adversely impact customer growth. Changes in tax rates could adversely affect our cash flows and may increase the cash we pay for income taxes in the future. Changes in monetary or other policies of the federal or state governments may adversely affect the economic climate for the United States, the regions in which we operate or particular industries, such as ours or those of our customers. Any of these events 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.
Financial, Economic and Market Risks
Unfavorable economic and market conditions could adversely affect our financial condition, earnings and cash flows.
Weakening economic activity in our markets 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, exacerbating impacts on our ability to collect and furthering our increasing 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.
We cannot predict the timing, strength, or duration of any future economic slowdowns. Fluctuations and uncertainties in the economy make it challenging for us to accurately forecast and plan future business activities and to identify risks that may affect our business, financial condition, results of operations and cash flows. The foregoing could adversely affect our business, financial condition, results of operations and cash flows.
Increases in the price of natural gas could reduce our earnings, increase our working capital requirements, and adversely impact our customer base.
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. The increased production in the U.S. of natural gas from shale formations generally has put downward pressure on the wholesale cost of natural gas in recent years; however, other factors could put upward pressure on natural gas prices, including weather-related events, restrictions or regulations on shale natural gas production and waste water disposal, increased demand from natural gas fueled electric power generation and increases in natural gas exports. 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.
Natural gas costs are passed through to our customers based on the actual cost of the natural gas we purchase and a customer’s consumption. Regulatory authorities review whether our natural gas costs are prudent and can adjust the amount of our natural gas costs that we pass through to our customers. The disallowance of or delay in recovery of our natural gas costs could adversely affect our financial condition, results of operations and cash flows. Additionally, an increase in the price of natural gas could cause us to experience a significant increase in short-term debt because we must pay suppliers for natural gas when purchased.
Further, higher and more volatile natural gas prices may adversely impact our customers’ perception of natural gas. Substantial fluctuations in natural gas prices can occur from year to year and sustained periods of high natural gas prices or of pronounced natural gas price volatility may lead to customers selecting other energy alternatives, such as electricity, and to increased scrutiny of the prudence of our natural gas procurement strategies and practices by our regulators. It may also cause new home developers, builders and new customers to select alternative sources of energy. Additionally, high natural gas prices may cause customers to conserve more and may also adversely impact our accounts receivable collections, resulting in higher bad debt expense. The occurrence of any of the foregoing could adversely affect our business, financial condition, results of operations and cash flows, as well as our future growth opportunities.
Our business is subject to competition that could adversely affect our results of operations.
The natural gas distribution business is competitive, and we face competition from other companies that supply energy, including electric companies, private generation, solar energy producers, propane dealers, other renewable energy providers and from other sources of energy for power generation, such as coal or nuclear energy. We also compete with other natural gas providers in certain areas. Significant competitive factors include efficiency, quality and reliability of the services we provide and the price we charge.
The most significant product competition occurs between natural gas and electricity in the residential and small commercial markets. Natural gas competes with electricity for water and space heating, cooking, clothes drying and other general energy needs. Increases in the price of natural gas or decreases in the price of other energy sources could adversely impact our competitive position by decreasing the price benefits of natural gas to the consumer. Customers and builders typically make the decision on the type of equipment at initial installation and use the chosen energy source for the life of the equipment. Changes in the competitive position of natural gas relative to electricity and other energy products have the potential to cause a decline in consumption or in the number of natural gas customers.
Consumer or government-mandated conservation efforts, bans on natural gas infrastructure in new construction, higher natural gas costs or decreases in the price of other energy sources also may encourage decreases in natural gas consumption and allow competition from alternative energy sources for applications that have used natural gas, encouraging some customers to move away from natural gas-powered equipment to equipment fueled by other energy sources. Competition between natural gas and other forms of energy is also based on efficiency, performance, reliability, safety, environmental and other nonprice factors. Technological improvements in other energy sources, energy storage, conservation, efficiency and events that impair the public
perception of the nonprice attributes of natural gas could erode our competitive advantage. These factors in turn could decrease the demand for natural gas, impair our ability to attract new customers, and cause existing customers to switch to other forms of energy or to bypass our systems in favor of alternative competitive sources. This could result in slow or no customer growth and could cause customers to reduce or cease using natural gas, thereby reducing our ability to make capital expenditures and otherwise grow our business and adversely affecting our 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 and weather patterns of these states could adversely impact the growth opportunities available to us and the usage patterns and financial condition of our customers. This could adversely affect our financial condition, results of operations and cash flows.
A downgrade in our credit ratings or placing those ratings on negative outlook or watch could adversely affect our cost of and ability to access capital.
Our ability to obtain adequate and cost-effective financing depends in part on our credit ratings. Our credit ratings are subject to change at any time in the discretion of the applicable rating agencies. Numerous factors, including many of which are not within our control, are considered by the rating agencies in connection with assigning credit ratings. A reduction in our ratings by our rating agencies could adversely affect our costs of borrowing and/or access to sources of liquidity and capital. Such a downgrade could further limit or delay our access to public and private credit markets and increase the costs of borrowing under available credit lines. While the current Moody’s and S&P issuer credit ratings for ONE Gas are investment grade, there is no assurance that these credit ratings will not be downgraded. A downgrade of our credit ratings may materially and adversely affect the market prices of our equity and debt securities, the interest rates at which borrowings are made and debt securities and commercial paper are issued, and the various fees on credit facilities. This could make it significantly more costly for us to borrow money, to issue debt securities and to raise certain other types of capital and/or complete additional financings. Such negative credit rating actions, as well as the reasons for such actions, could materially and adversely affect our cash flows, results of operations and financial condition and the market price of, and our ability to pay the principal of and interest on, our debt securities. Should our credit ratings be downgraded, it could limit or delay our ability to obtain additional financing in the future for working capital, capital expenditures and acquisitions when necessary or desirable. In addition, our pool of investors and prospective creditors would likely decrease. An increase in borrowing costs without the ability to recover these higher costs in the rates charged to our customers could adversely affect our results of operations, financial condition and cash flows by limiting our ability to earn our allowed rate of return.
Moreover, most of our large suppliers and counterparties require an expected level of creditworthiness in order for them to enter into transactions with us. If our credit ratings decline, the costs to operate our business could increase because counterparties could require the posting of collateral in the form of cash-related instruments, or counterparties could decline to do business with us.
Demand for natural gas is highly weather sensitive and seasonal, and weather conditions may cause our earnings to vary from year to year.
Our earnings can vary from year to year, depending in part on weather conditions, which directly influence the volume of natural gas delivered to customers. Natural gas sales to residential and commercial customers are seasonal, as a substantial portion of their natural gas requirements are for heating during the winter months. Warmer-than-normal weather can reduce our revenues as customer consumption declines. We have implemented WNA mechanisms for our sales to customers in Oklahoma, Kansas and Texas, which are designed to reduce our earnings sensitivity to weather. Through these mechanisms, we increase customer billings to offset lower natural gas usage when weather is warmer than normal and decrease customer billings to offset higher natural gas usage when weather is colder than normal. If our rates and tariffs are modified to curtail such weather protection programs, then we would be exposed to additional risk associated with weather. As a result of occurrences of the foregoing, our results of operations, financial condition and cash flows could vary and be impacted adversely.
Emerging technologies may cause disruption in utility services, which may adversely affect our current customer base, our customer growth, earnings and cash flows.
Commercial technologies that advance electrification and increase energy efficiency in some aspects of the economy, such as transportation or heating, could negatively impact the demand for natural gas. We may not be able to quickly adapt to changes resulting from rapidly advancing technologies that may result in a reduction in demand for our services. This could slow
customer growth and even cause customers to reduce or cease using natural gas which could have a material adverse effect on our financial condition, results of operations and cash flows.
An impairment of goodwill and long-lived assets could reduce our earnings.
At December 31, 2021, we had approximately $158 million of goodwill recorded on our Consolidated Balance Sheet. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. GAAP requires us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that impairment is indicated, we would be required to take an immediate noncash charge to earnings with a correlative effect on our equity and balance sheet leverage as measured by debt to total capitalization, which could adversely impact our financial condition and results of operations.
We may be unable to access capital or our cost of capital may increase significantly which may 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, in addition to our financial condition and credit ratings. Disruptions in the capital and credit markets could adversely affect our ability to access short-term and long-term capital. Access to funds under our ONE Gas Credit Agreement and our commercial paper program is dependent on the ability of the participating banks to meet their funding commitments and lenders to continue purchasing our commercial paper. Those banks may not be able to meet their funding commitments if they experience shortages of capital and liquidity. Disruptions and volatility in the global credit markets could cause the interest rate we pay under our ONE Gas Credit Agreement and our commercial paper program to increase. This could result in higher interest rates on future financings and could impact the liquidity of the lenders under our ONE Gas Credit Agreement, potentially impairing their ability to meet their funding commitments to us. Disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation or failures of significant financial institutions could adversely affect our access to capital needed for our business. 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. A significant reduction in our liquidity could cause a negative change in our ratings outlook or a reduction in our credit ratings. This could in turn further limit our access to credit markets and increase our costs of borrowing.
As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy all of our outstanding obligations in the event of a default on our part, which may adversely affect our results of operations, cash flows and financial condition.
The terms of our debt agreements contain cross-default provisions, which provide that we will be in default under such agreements in the event of certain defaults under other debt agreements. Accordingly, should an event of default occur under any of those agreements, we would face the prospect of being in default under many or all of our debt agreements, obliged in such instance to satisfy all of our outstanding indebtedness under many or all such agreements simultaneously. In such an event, we may not have sufficient funds available to satisfy all of our outstanding obligations and may not be able to obtain alternative financing or, if we are able to obtain such financing, we may not be able to obtain it on terms acceptable to us, which would adversely affect our ability to implement our business plan, have flexibility in planning for, or reacting to, changes in our business, make capital expenditures and finance our operations.
The cost of providing pension and other postemployment health care benefits to eligible employees and qualified retirees is subject to changes in pension fund values, changing demographics and other factors and may increase our costs. In addition, the passage of the Patient Protection and Affordable Care Act in 2010 and the Consolidated Appropriations Act in 2021 and the potential revision, repeal and/or replacement of either of these acts could increase the cost of health care benefits for our employees. Further, the costs to us of providing such benefits and related funding requirements are subject to the continued and timely recovery of such costs through our rates which may adversely affect our cash flows and earnings.
We have defined benefit pension plans and other postemployment welfare plans for certain eligible employees. Our defined benefit plans are closed to new participants. Our other postemployment welfare plans subsidize costs for providing postemployment medical benefits and life insurance. The cost of providing these benefits to eligible current and former employees is subject to changes in the market value of our pension and other postemployment benefit plan assets, changing demographics, including longer life expectancy of plan participants and their beneficiaries, current and future legislative
changes, and changes in health care costs, discount rates used to calculate liability, and various actuarial calculations and assumptions.
Any sustained declines in equity markets and reductions in bond values may have a material adverse effect on the value of our pension and other postemployment benefit plan assets. In these circumstances, additional cash contributions to our pension and other postemployment benefit plans may be required, which could have a material adverse impact on our financial condition and cash flows.
In addition, the costs of providing health care benefits to our employees could increase over the next several years due in large part to the Patient Protection and Affordable Care Act of 2010 and the Consolidated Appropriations Act, 2021, and the potential revision, repeal and/or replacement of either of these acts. The future costs of compliance with the provisions are difficult to measure at this time. Also, our costs of providing such benefits and related funding requirements could also materially increase in the future, depending on the timing of the recovery, if any, of such costs through our rates, which could adversely impact our financial condition and cash flows.
Our financing arrangements subject us to various restrictions that could limit our operating flexibility, earnings and cash flows.
The covenants in the indenture governing our Senior Notes and our ONE Gas Credit Agreement 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.
The ONE Gas Credit Agreement includes a requirement that our debt to total capital ratio may not exceed 72.5 percent at the end of any calendar quarter through December 31, 2021, and 70 percent as of the end of any calendar quarter thereafter. Events beyond our control could impair our ability to satisfy this requirement. 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 there were an event of default under one of our debt agreements, 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 would reduce our available cash and have an adverse impact on our financial condition, results of operations and cash flows.
Some of our debt, including borrowings under our ONE Gas Credit Agreement, our floating-rate senior notes, and our commercial paper program, is based on variable rates of interest, which could result in higher interest expenses in the event of an increase in interest rates.
We are exposed to fluctuations in variable interest rates. This increases our exposure to fluctuations in market interest rates. Our floating-rate senior notes, and amounts borrowed under the ONE Gas Credit Agreement and commercial paper program are based on variable rates of interest. If these rates rise, the interest rate on this debt will also increase. Therefore, an increase in these rates will increase our interest payment obligations and have a negative effect on our cash flows and financial position.
Conditions in the financial markets and economic conditions generally may materially adversely affect us.
Our business is capital intensive and we rely significantly on long-term debt to fund a portion of our capital expenditures and repay outstanding debt, and on short-term borrowings to fund a portion of day-to-day business operations.
Limitations on the availability of credit and increases in interest rates or credit spreads may materially adversely affect our businesses, cash flows, results of operations, financial condition and/or prospects, as well as our ability to meet contractual and other commitments. In difficult credit market environments, we may find it necessary to fund our operations and capital expenditures at a higher cost or we may be unable to raise as much funding as we need to support new or ongoing business activities. This could cause us to reduce non-safety related capital expenditures and could increase our cost of servicing debt, both of which could significantly reduce our short-term and long-term profitability.
Other factors can affect the availability and cost of credit for our business, as well as the terms of equity and debt financing, including:
•adverse changes to laws and regulations in the states in which we operate;
•the overall health of the energy industry;
•volatility in natural gas prices;
•changes in tax law;
•credit ratings downgrades;
•general economic and financial market conditions; and
•the availability of capital to the fossil fuel industry.
We are dependent on continued access to the credit and capital markets to execute our business strategy.
Our long-term debt is currently rated as “investment grade” by both of our rating agencies. We rely upon access to both 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.
While we believe we can meet our capital requirements from our operations and the sources of financing available to us, we can provide no assurance that we will continue to be able to do so in the future, especially if the market price of natural gas increases significantly or there are regulatory constraints on our ability to recover gas or financing costs. The future effects on our business, liquidity and financial results of a deterioration of current conditions in the credit and capital markets could be material and adverse to us, both in the ways described above or in other ways that we do not currently anticipate.
RISKS RELATING TO OUR COMMON STOCK
Provisions in our certificate of incorporation, our bylaws and Oklahoma law, as well as regulatory approvals, may prevent or delay an acquisition of our Company, which could decrease the trading price of our common stock.
Our certificate of incorporation, bylaws and Oklahoma law contain provisions that are intended to deter coercive takeover practices and inadequate takeover bids by making such practices or bids unacceptably expensive to the raider and to encourage prospective acquirers to negotiate with our Board of Directors rather than to attempt a hostile takeover. These provisions include, among others:
•rules regarding how shareholders may present proposals or nominate directors for election at shareholder meetings; and
•the right of our Board of Directors to issue preferred stock without shareholder approval.
Oklahoma law also imposes some restrictions on mergers and other business combinations between us and any holder of 15 percent or more of our outstanding common stock.
We believe these provisions protect our shareholders from coercive or otherwise potentially unfair takeover tactics by requiring potential acquirers to negotiate with our Board of Directors and by providing our Board of Directors with more time to assess any acquisition proposal. These provisions are not intended to make our Company immune from takeovers. However, these provisions apply even if the offer may be considered beneficial by some shareholders and could delay or prevent an acquisition that our Board of Directors determines is not in the best interests of our Company and our shareholders.
Additionally, any acquisition of our Company would need to be approved by certain regulatory bodies including the OCC, KCC and various regulators in Texas, which could delay or prevent an acquisition.
Our ability to pay dividends on our common stock will depend on our ability to generate sufficient positive earnings and cash flows.
Our ability to pay dividends in the future will depend upon, among other things, our future earnings, cash flows and restrictive covenants, if any, under future credit agreements to which we may be a party. Our cash available for dividends will principally be generated from our operations. Because the cash we generate from operations will fluctuate from quarter to quarter, we may not be able to maintain future dividends at the levels we expect or at all. Our ability to pay dividends depends primarily on cash flows, including cash flows from changes in working capital, and not solely on profitability, which is affected by noncash items. As a result, we may pay dividends during periods when we record net losses and may be unable to pay cash dividends during periods when we record net income.
GENERAL RISK FACTORS
Federal, state, and local jurisdictions may challenge our tax return positions.
The preparation of our federal and state tax return filings requires significant judgments, use of estimates and the interpretation and application of complex tax laws. Significant judgment also is required in assessing the timing and amounts of deductible and taxable items, and in determining the amount of any reserves for potential adverse outcomes regarding tax positions that have been taken that may be subject to challenge by taxing authorities. Despite management’s expectation that our tax return positions will be fully supportable, certain positions may be challenged successfully by federal, state, and local jurisdictions, which could adversely impact our results of operations, cash flows and financial condition.
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. Changing political climates and public attitudes may adversely affect the ongoing acceptability of strategic decisions that have been made (and, in some cases, previously approved by regulators) to the detriment of the Company. We may be materially and adversely affected if we are unable to successfully integrate businesses that we acquire.
Changes in accounting standards may adversely impact our financial condition, results of operations and cash flows.
We are subject to additional changes in GAAP, SEC regulations and other interpretations of financial reporting requirements for public utilities. We neither have control over the impact these changes may have on our financial condition or results of operations nor the timing of such changes.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES
ITEM 2. PROPERTIES
The following table sets forth the approximate miles of distribution mains and transmission pipelines as of December 31, 2021:
Properties (miles) OK KS TX Total
Distribution 19,200 11,700 10,700 41,600
Transmission 600 1,500 300 2,400
Total properties 19,800 13,200 11,000 44,000
We lease approximately 300 thousand square feet of office space and other facilities for our operations. In addition, we have 51.4 Bcf of natural gas storage capacity under contract, with maximum allowable daily withdrawal capacity of approximately 1.4 Bcf.

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
See Note 16 of the Notes to Consolidated Financial Statements in this Annual Report for information regarding legal proceedings.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II.

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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 21, 2022, there were 9,929 registered shareholders of our common stock.
In January 2022, we declared a dividend of $0.62 per share ($2.48 per share on an annualized basis) for shareholders of record on February 25, 2022, payable on March 11, 2022.
Performance Graph
The following performance graph compares the performance of our common stock with the S&P MidCap 400 Index, the Dow Jones Industrial Average and a ONE Gas peer group during the period beginning December 31, 2016 and ending on December 31, 2021. 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
December 31,
2017 2018 2019 2020 2021
ONE Gas, Inc. $ 117.30 $ 130.67 $ 157.16 $ 132.44 $ 138.22
S&P MidCap 400 Utilities Index $ 111.09 $ 118.66 $ 135.65 $ 116.85 $ 139.92
S&P MidCap 400 Index $ 116.24 $ 103.36 $ 130.44 $ 148.26 $ 184.97
Dow Jones Industrial Average $ 128.11 $ 123.65 $ 154.99 $ 170.06 $ 205.68
ONE Gas Peer Group*
$ 114.88 $ 117.77 $ 138.22 $ 120.04 $ 141.89
* 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 2021 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.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [RESERVED]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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 and outcomes, which determine 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, which impacts our operating expenses; 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 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 regulation is changing constantly, 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
Winter Storm Uri - 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 gas costs 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. See “Regulatory Activities” and Note 10 of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion.
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.
On March 11, 2021, we issued $1.0 billion of 0.85 percent senior notes due 2023, $700 million of 1.10 percent senior notes due 2024, and $800 million of floating-rate senior notes due 2023. The floating-rate senior notes bear interest at a rate equal to three-month LIBOR plus 61 basis points per year reset quarterly for the applicable interest period (0.81 percent at December 31, 2021). The net proceeds from the issuance were used for general corporate purposes, including payment of gas purchase costs resulting from 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.
On September 21, 2021, we called $400 million of the floating-rate senior notes due 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.
Our purchased gas costs are recoverable through the tariffs in each state where we operate. Due to the higher level of gas purchase costs during Winter Storm Uri, related financing costs and other operational response costs, we are working with regulators to extend the recovery periods of such costs in order to lessen the immediate customer impact. In that regard, the OCC, KCC and the RRC each authorized certain utilities, including LDCs, to record regulatory assets to account for the extraordinary costs associated with this winter weather event, including but not limited to gas purchase costs and other costs related to the procurement and transportation of gas supply, carrying costs and other operational costs. As of December 31, 2021, we have deferred approximately $2.0 billion in costs associated with Winter Storm Uri.
In the second quarter of 2021, legislation in Oklahoma, Kansas and Texas was approved that permits utilities to pursue securitization to finance extraordinary expenses, such as fuel costs, incurred during extreme weather events. We have received or are currently seeking approval from our regulators to utilize the securitization legislation in each state to repay or refinance the debt we incurred to finance the extraordinary costs associated with Winter Storm Uri.
See “Regulatory Activities”, “Liquidity and Capital Resources”, Note 10 of the Notes to the Consolidated Financial Statements and Item 1A, “Risk Factors” in this Annual Report for additional discussion of the effects of this winter weather event on us.
ONE Gas Credit Agreement - On March 16, 2021, we entered into the second amended and restated ONE Gas Credit Agreement, which was previously amended and restated on October 5, 2017. 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. In connection with the amendment and restatement of the ONE Gas Credit Agreement, 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.
ONE Gas Commercial Paper Program - On June 22, 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.
COVID-19 - Throughout the COVID-19 pandemic, we have continued to provide essential services to our customers. We have 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 have 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, 2021, we have not requested recovery of any deferrals pursuant to these orders and no regulatory assets have been recorded. In Oklahoma, the test period for our recently completed rate case included the impacts of COVID-19 on our cost of service in determining our new rates that became effective in November 2021. In addition, the annual PBRC filings allow us to include any impacts from COVID-19 in our test period cost of service to determine the impact on our rates. In Kansas and Texas, we continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable.
See “Regulatory Activities,” “Financial Results and Operating Information,” “Capital Expenditures and Asset Removal Costs,” Note 10 and Note 16 of the Notes to Consolidated Financial Statements and Item 1A, “Risk Factors” in this Annual Report for additional discussion of the effects of COVID-19 on us.
Dividend - In January 2022, we declared a dividend of $0.62 per share ($2.48 per share on an annualized basis) for shareholders of record on February 25, 2022, payable on March 11, 2022.
REGULATORY ACTIVITIES
Oklahoma - On February 12, 2021, the governor of Oklahoma declared a state of emergency for all 77 counties in the state of Oklahoma in light of expected severe weather and freezing temperatures associated with a winter weather event. The declaration cited anticipated damage to private and public properties and utilities, including electric, gas, and water systems, within the state of Oklahoma.
On February 16, 2021, the OCC approved an emergency order (i) directing natural gas and electric utilities to prioritize deliveries of natural gas and electricity for services necessary for life, health, and public safety, and of natural gas to electric generation facilities that serve human needs customers, and (ii) directing local utilities to communicate with their customers in order to reduce all non-essential energy consumption, and to reduce load in a safe and reasonable manner. The OCC order recognized that the severe weather conditions resulted in increased commodity prices for both gas and electric utilities, along with issues relating to commodity acquisition, line pressure, and supply shortages. The OCC order expired on February 20, 2021.
In response to a motion filed by Oklahoma Natural Gas on March 2, 2021, the OCC issued an order stating that Oklahoma Natural Gas shall defer to a regulatory asset the extraordinary costs associated with this unprecedented winter weather event, including commodity costs, operational costs and carrying costs. The order further states that after all deferred costs have been accumulated and recorded, Oklahoma Natural Gas shall file a compliance report detailing the extent of such costs incurred. The order also provides that recovery of the deferred costs will be addressed in a future proceeding that will include a prudence review.
In April 2021, a bill permitting the state 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 by the Oklahoma governor. This bill gives the OCC the authority to approve amounts to be recovered from the issuance of ratepayer-backed securitized bonds by the ODFA.
On April 29, 2021, Oklahoma Natural Gas submitted an initial application requesting a financing order pursuant to this legislation. On July 30, 2021, Oklahoma Natural Gas filed a supplemental motion with its compliance report pursuant to the March 2, 2021 order from the OCC detailing the extent of extraordinary costs incurred and all required components pursuant to the legislation for the issuance of a financing order, which includes a proposed period of 20 years over which these costs will be collected from customers. On October 4, 2021, the Public Utility Division of the OCC filed responsive testimony recommending that a financing order for securitization be approved. A joint stipulation and settlement was filed on November 18, 2021 ahead of the hearing before the administrative law judge on November 22, 2021. The joint stipulation and settlement agreement includes an agreement that a financing order should be issued to recover through securitization all extreme gas purchase and extraordinary costs over a 25-year period. At the hearing on November 22, 2021, the administrative law judge recommended approval of the joint stipulation and settlement agreement. On January 25, 2022, the OCC approved a financing order, which reflected the terms of the settlement agreement. Following the issuance of the financing order, there is a 30-day period during which parties to our application may appeal the financing order to the Oklahoma Supreme Court. The securitization legislation allows the ODFA 24 months to complete the process to issue the securitized bonds; however, the financing order requests the ODFA to issue bonds and provide the net proceeds to Oklahoma Natural Gas as soon as feasible, but no later than December 31, 2022. At December 31, 2021, Oklahoma Natural Gas has deferred approximately $1.3 billion in extraordinary costs attributable to Winter Storm Uri. See “Liquidity and Capital Resources” in this Annual Report for additional discussion.
As required, PBRC filings are made annually on or before March 15, until the next general rate case, which was required to be filed on or before June 30, 2021, based on a calendar 2020 test year. On May 28, 2021, Oklahoma Natural Gas filed its general rate case. In October 2021, a joint stipulation and settlement agreement was signed by all parties to the rate case. On November 30, 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 a return on equity 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. Oklahoma Natural Gas is required to file a rate case on or before June 30, 2027, based on a 12-month test year ending December 31, 2026. The approved order also states that Oklahoma Natural Gas may recover commodity costs of no more than $5.0 million annually for the purchase of RNG and that Oklahoma Natural Gas shall 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 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 was included in the general rate case previously discussed. The impact on the annual crediting mechanism for the EDIT regulatory liability will be addressed during the processing of the March 15, 2022 PBRC filing.
In June 2020, the OCC issued an order permitting the creation of regulatory assets and deferrals related to COVID-19. Each utility is authorized under the OCC’s order to record as a regulatory asset increased bad debt expenses, costs associated with expanded payment plans, waived fees, and incremental expenses that are directly related to the suspension of or delay in disconnection of service (or the reconnection of service) beginning March 15, 2020, as a result of the governor’s executive order declaring a state of emergency through April 2021. As of December 31, 2021, no regulatory assets have been recorded. In our May 2021 general rate case application, the test year included the impact of COVID-19 on our revenues and expenses through December 31, 2020, and future impacts will be included as part of the annual PBRC mechanism.
In February 2020, Oklahoma Natural Gas filed its fourth annual PBRC application following the general rate case that was approved in January 2016. A settlement was reached, and the OCC approved a joint stipulation in July 2020. This stipulation included a base rate increase of $9.7 million and an energy efficiency incentive of $2.2 million, with new rates reflecting these changes effective in June 2020. This stipulation also included a credit of $12.2 million associated with EDIT issued through a bill credit to Oklahoma customers in the first quarter of 2021.
Kansas - On February 14, 2021, the governor of Kansas issued a State of Disaster Emergency due to wind chill warnings and stress on utility and natural gas providers expected from the significantly colder than normal weather forecasted throughout Kansas. The executive order also urged Kansas citizens to conserve energy to help ensure a continued supply of natural gas and electricity and keep their energy costs down. The declaration also noted that due to increased energy demand and natural gas supply constraints caused by sub-zero temperatures, utilities at the time were experiencing wholesale natural gas prices anywhere from 10 to 100 times higher than normal.
On February 15, 2021, the KCC issued an emergency order (i) directing all jurisdictional natural gas and electric utilities to coordinate efforts and take all reasonably feasible, lawful, and appropriate actions to ensure adequate delivery of natural gas and electricity to interconnected, non-jurisdictional utilities in Kansas, (ii) 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 in Kansas, and (iii) allowing those electric and natural gas distribution utilities who incur extraordinary costs to ensure their customers and other interconnected customers continued to receive utility service during this unprecedented cold weather event to defer those costs and carrying costs to a regulatory asset account. Each jurisdictional utility was required to file a compliance report detailing the extent of such costs incurred and presenting a plan to minimize the financial impacts of this event on ratepayers over a reasonable time frame. These costs were subject to review for reasonableness and accuracy in future regulatory proceedings.
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 the winter weather event. In April 2021, a bill permitting utilities to pursue securitization to finance extraordinary expenses incurred during extreme weather events, was signed into law by the Kansas governor. This bill 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 October 2021, a nonunanimous settlement agreement was filed with the KCC to reach a resolution on these penalties. Prior to a hearing on the amended settlement in January 2022, all parties reached a unanimous settlement, which was filed with a motion requesting approval of the unanimous settlement. Under the terms of the amended unanimous settlement, if approved, the carrying charge on assessed penalties was reduced to two percent, consistent with the nonunanimous agreement in the financial docket. Any amounts collected from these penalties would reduce the regulatory asset for the winter weather event by no more than $52.4 million. A hearing on the settlement was held on February 4, 2022. The KCC has until March 7, 2022, to issue an order on the motion.
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 to issue securitized bonds to recover the extraordinary costs resulting from Winter Storm Uri from its customers over a period of either 5, 7, or 10 years. In November 2021, a nonunanimous settlement agreement was filed with the KCC that would allow Kansas Gas Service to recover extraordinary costs as of October 31, 2021, net of any penalties recovered from marketers and individually-balanced transportation customers, plus carrying costs calculated at two percent. Subsequently, all parties reached agreement on the settlement’s terms which resulted in the nonunanimous agreement becoming a unanimous settlement agreement. The extraordinary costs, other than purchased gas costs, will be trued-up and validated. The settlement agreement supports Kansas Gas Service seeking a financing order from the KCC for the issuance of securitized utility tariff bonds. The KCC issued an order approving the unanimous settlement agreement on February 8, 2022. Kansas Gas Service expects to file an application, in a separate proceeding, requesting a financing order in the first quarter of 2022. The KCC will have 180 days from the date of the filing to consider Kansas Gas Service’s application. If the KCC approves the financing order, we can begin the process to issue the securitized bonds. At December 31, 2021, Kansas Gas Service has deferred approximately $388.3 million in extraordinary costs associated with Winter Storm Uri and has not collected any penalties from marketers or individually-balanced transportation customers.
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, 2021 and 2020. 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 to reflect the elimination of Kansas state income taxes by approximately $4.9 million. In December 2020, the KCC approved the reduction, effective January 1, 2021. See Note 10 of the Notes to Consolidated Financial Statements in this Annual Report for additional information.
In April 2020, Kansas Gas Service filed an application with the KCC for an AAO to accumulate and defer certain incremental costs incurred, including bad debt expenses and lost revenues, as well as associated carrying costs, related to COVID-19 beginning March 1, 2020, for recovery in Kansas Gas Service’s next rate case filing. In July 2020, the KCC approved the request for an AAO subject to the recommendations set forth in its Staff Report and Recommendation and clarifications sought by Kansas Gas Service. The AAO provides notice that Kansas Gas Service may identify, track, document, accumulate, and defer in a regulatory asset extraordinary costs (net of any cost decreases) and lost revenue, plus carrying costs, associated with the COVID-19 pandemic. The KCC states that approval of the AAO is not a finding that tracked costs and lost revenue will be included in future rates; rather, any determination regarding recoverability will occur in a future rate proceeding. In a separate order applicable to all regulated utilities, the KCC approved the deferral of bad debt expense and late payment fees associated with the KCC’s suspension of disconnection activity and customer protection provisions. The recovery, the carrying charges and amortization period will be determined in Kansas Gas Service’s next rate case or alternative rate recovery filing. At December 31, 2021, no regulatory assets have been recorded. We continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial statement purposes at such time as recovery is deemed probable.
In November 2018, Kansas Gas Service submitted an application to the KCC requesting approval of its contract to operate and maintain the natural gas distribution system at Fort Riley, a United States Army installation. The KCC approved the Company’s application in May 2019. The transition period ended in June 2021, after which Kansas Gas Service assumed operation of the system.
Texas - On February 12, 2021, the governor of Texas issued a state of disaster for all 254 counties in Texas in response to the then-forecasted weather conditions. The declaration certified that severe winter weather posed an imminent threat due to prolonged freezing temperatures, heavy snow, and freezing rain statewide.
Also, on February 12, 2021, the RRC issued an emergency order to temporarily implement a statewide utility curtailment program intended to protect residences, hospitals, schools, churches, and other human needs customers. On February 17, 2021, the RRC extended its emergency order issued on February 12, 2021, to February 23, 2021.
On February 13, 2021, the RRC issued a Notice to Local Distribution Companies acknowledging that due to the demand for natural gas expected during the upcoming winter weather event, natural gas utility LDCs may be required to pay extraordinarily high prices in the market for natural gas and may be subjected to other extraordinary costs when responding to the event. The RRC also encouraged natural gas utilities to continue to work to ensure that the citizens of the State of Texas were provided with safe and reliable natural gas service. To partially defer and reduce the impact on customers for these costs that ultimately are reflected in customer bills, the RRC authorized LDCs to record a regulatory asset to account for the extraordinary costs associated with this winter weather event, including but not limited to gas cost and other costs related to the procurement and transportation of gas supply. These costs will be subject to review for reasonableness and accuracy in future regulatory proceedings.
In June 2021, a bill permitting the state to pursue securitized financing of extraordinary expenses, such as fuel costs, financing costs and other operational costs incurred by utilities during Winter Storm Uri, was signed into law by the Texas governor. This bill gives the RRC the authority to approve amounts to be recovered from the issuance of ratepayer-backed securitized bonds by the TPFA. Pursuant to this legislation and a June 17, 2021 RRC Notice to Gas Utilities, Texas Gas Service submitted an application to the RRC on July 30, 2021, for an order authorizing the amount of extraordinary costs for recovery and other such specifications necessary for the issuance of securitized bonds.
In October 2021, Texas Gas Service, the other natural gas utilities in Texas participating in the securitization process, the staff of the RRC and all intervenors filed a unanimous settlement agreement with the RRC. The settlement agreement provides that all costs to purchase natural gas during Winter Storm Uri by Texas Gas Service were reasonable, necessary and prudently incurred. Texas Gas Service agreed to reduce its regulatory asset amount to be securitized by the amount of extraordinary costs attributable to the West Texas service area, which will be recovered through a separate surcharge over a three-year period. The unanimous settlement agreement was approved by the RRC in November 2021.
On February 8, 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, for purposes of issuing the securitized bonds and has begun the process to issue the securitized bonds. At December 31, 2021, Texas Gas Service has deferred approximately $256.6 million in extraordinary costs associated with Winter Storm Uri, which includes $59.5 million attributable to the West Texas service area. Pursuant to the approved settlement order, Texas Gas Service began collecting the extraordinary costs, including carrying costs, associated with Winter Storm Uri attributable to the West Texas service area from those customers in January 2022. See “Liquidity and Capital Resources” in this Annual Report for additional discussion.
In April 2020, the RRC issued an order authorizing utilities to use a regulatory accounting mechanism and a subsequent process through which Texas Gas Service may seek future recovery of incremental expenses resulting from the effects of COVID-19, including bad debt and associated credit and collections costs, and other reasonable and necessary incremental costs to address the impact of COVID-19. The timing of any recovery will be determined as we work with our regulators. At December 31, 2021, no regulatory assets have been recorded. We continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial statement purposes at such time as recovery is deemed probable.
West Texas Service Area - In March 2021, Texas Gas Service made GRIP filings for all customers in the 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.
In March 2020, Texas Gas Service made GRIP filings for all customers in the West Texas service area. In June 2020, the RRC and the cities in the West Texas service area agreed to an increase of $4.7 million, and new rates became effective in June 2020.
Central-Gulf Service Area - 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.
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.
In 2019, Texas Gas Service filed a rate case for all customers in the Central Texas and Gulf Coast service areas, seeking a rate increase of $15.6 million and a $1.3 million credit to customers associated with EDIT, and requesting to consolidate the two service areas into one. In August 2020, the RRC approved all terms of a $10.3 million settlement, as well as consolidation of the Central Texas service area and the Gulf Coast service area into a new Central-Gulf service area. The RRC also approved an $8.5 million credit to customers associated with EDIT. The settlement included a ROE of 9.5 percent and a capital structure with equity of 59 percent and debt of 41 percent, and new rates became effective in August 2020.
Other Texas Service Areas - In April 2021, Texas Gas Service filed annual COSA 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. Annual rate increases associated with these filings that were approved totaled $0.4 million and $0.3 million for the years ended December 31, 2021 and 2020, respectively.
Winter Storm Uri Deferred Costs - The amounts deferred at December 31, 2021, 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 these discrepancies are resolved. In addition, as a result of Winter Storm Uri, we were assessed penalties as a result of over- or under-deliveries of natural gas during periods that operational flow orders were imposed on us. Regarding Kansas Gas Service’s motion requesting a limited waiver of penalty provisions of its tariff, if the current unanimous settlement agreement filed with the KCC is approved, we anticipate assessing penalties on the marketers and individually-balanced transport customers we serve or their agents. Amounts recorded reflect management’s best estimate and may be adjusted in future periods as the disposition of such penalties is determined. As these amounts are related to the extraordinary gas purchase costs associated with Winter Storm Uri, which are deferred, future adjustments to the amounts we have 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 2021, 2020 or 2019.
FINANCIAL RESULTS AND OPERATING INFORMATION
Selected Financial Results - Net income was $206.4 million, or $3.85 per diluted share, $196.4 million, or $3.68 per diluted share, and $186.7 million, or $3.51 per diluted share, for the years ended December 31, 2021, 2020 and 2019, 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, 2021 vs. 2020 2020 vs. 2019
Financial Results 2021 2020 2019 Increase (Decrease) Increase (Decrease)
(Millions of dollars, except percentages)
Natural gas sales $ 1,661.7 $ 1,389.2 $ 1,508.1 $ 272.5 20 % $ (118.9) (8) %
Transportation revenues 119.0 114.1 114.1 4.9 4 % - - %
Other revenues 27.9 27.0 30.5 0.9 3 % (3.5) (11) %
Total revenues 1,808.6 1,530.3 1,652.7 278.3 18 % (122.4) (7) %
Cost of natural gas 775.0 537.4 687.9 237.6 44 % (150.5) (22) %
Operating costs 516.1 494.5 489.1 21.6 4 % 5.4 1 %
Depreciation and amortization 207.2 194.9 180.4 12.3 6 % 14.5 8 %
Operating income $ 310.3 $ 303.5 $ 295.3 $ 6.8 2 % $ 8.2 3 %
Net income $ 206.4 $ 196.4 $ 186.7 $ 10.0 5 % $ 9.7 5 %
Capital expenditures and asset removal costs $ 544.3 $ 512.2 $ 465.1 $ 32.1 6 % $ 47.1 10 %
Natural gas sales to customers represent revenue from contracts with customers through implied contracts established by our
tariffs and rates approved by the regulatory authorities, as well as revenues from regulatory mechanisms related to natural gas sales. Additionally, natural gas sales includes the recovery of our cost of natural gas.
Transportation revenues represent revenue from contracts with customers through implied contracts established by our tariffs and rates approved by the 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 the regulatory authorities and other revenues from regulatory mechanisms.
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.
2021 vs. 2020 - Operating income increased $6.8 million due primarily to the following:
•an increase of $32.0 million from new rates;
•an increase of $8.5 million in residential sales due primarily to net customer growth;
•a decrease of $6.3 million in bad debt expense; and
•a decrease of $2.0 million in COVID-19 related expenses.
These increases were offset partially by:
•an increase of $12.8 million in outside service costs;
•an increase of $12.7 million in employee-related costs;
•an increase of $10.6 million in depreciation expense due to additional capital expenditures being placed in service;
•a decrease of $4.0 million due to lower residential sales volumes, net of weather normalization, primarily in Kansas and Oklahoma; and
•an increase of $2.7 million in fleet expenses.
Other Factors Affecting Net Income - Other factors that affect net income include a $2.2 million increase in 2021, compared with 2020, due to lower interest expense.
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, 2021, 2020 and 2019, we credited income tax expense $17.3 million, $17.4 million and $12.8 million, respectively, for the amortization of the regulatory liability associated with EDIT that was returned to customers. See “Liquidity and Capital Resources” for additional discussion of the Tax Cuts and Jobs Act of 2017.
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 $32.1 million for 2021, compared with 2020, due primarily to increased system integrity activities and extension of service to new areas. Our capital expenditures and asset removal costs are expected to be approximately $650 million for 2022. While we did not experience a significant impact to our capital expenditures program for the year ended December 31, 2021, we could experience delays in 2022 if conditions associated with COVID-19 worsen, impacting employee absences or our supply chain 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, 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
Years Ended Variances
December 31, 2020 vs. 2019
(in thousands) 2020 2019 Increase (Decrease)
Average Number of Customers OK KS TX Total OK KS TX Total OK KS TX Total
Residential 814 589 641 2,044 804 584 631 2,019 10 5 10 25
Commercial and industrial 75 50 35 160 74 50 35 159 1 - - 1
Other - - 3 3 - - 3 3 - - - -
Transportation 6 6 1 13 6 6 1 13 - - - -
Total customers 895 645 680 2,220 884 640 670 2,194 11 5 10 26
The increase in the average number of customers for 2021, compared with 2020, is due primarily to the connection of new customers resulting from the extension and expansion of our system in our service areas. For 2021, our average customer count includes 24,900 new customer connections compared to 26,400 in 2020. Also contributing to the increase is a reduction in disconnects for nonpayment in the first half of 2021 and other collection activities in response to the COVID-19 pandemic that have allowed customers to continue to receive service.
The following table reflects the total volumes delivered, excluding the effects of WNA mechanisms on sales volumes:
Years Ended December 31,
Volumes (MMcf)
2021 2020 2019
Natural gas sales
Residential 117,758 121,967 128,723
Commercial and industrial 37,615 36,169 40,690
Other 2,521 2,427 2,688
Total sales volumes delivered 157,894 160,563 172,101
Transportation 229,935 224,531 224,304
Total volumes delivered 387,829 385,094 396,405
Total sales volumes delivered decreased for 2021, compared with 2020, due primarily to warmer weather in the fourth quarter 2021. 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 HDD’s by state for the periods indicated:
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 %
Years Ended
December 31,
2020 2019 2020 vs. 2019 2020 2019
HDDs Actual Normal Actual Normal Actual Variance Actual as a percent of Normal
Oklahoma 3,253 3,264 3,716 3,264 (12) % 100 % 114 %
Kansas 4,408 4,722 4,971 4,791 (11) % 93 % 104 %
Texas 1,580 1,779 1,803 1,773 (12) % 89 % 102 %
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 2016 through 2021, 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 - For April 2019 and forward, 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. For 2017 to March 2019, 30-year average for years 1981-2010 published by the National Oceanic and Atmospheric Administration, as calculated using four 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 2020, compared with 2019, 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, 2020.
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 16 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 and our rate mechanisms, including our cost of gas recovery 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. By maintaining a conservative financial profile and stable revenue base, we expect to maintain credit ratings at a level that supports our access to diverse sources of capital at favorable rates for capital investments and expenses.
Short-term Financing - On March 16, 2021, we entered into the second amended and restated ONE Gas Credit Agreement, which was previously amended and restated on October 5, 2017.
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. We can extend the maturity date by one year, subject to the lenders’ consent, up to two times. The ONE Gas Credit Agreement expires in March 2026, and 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 utilizes LIBOR as the reference rate for determining interest to accrue on the borrowings. In the event LIBOR is not available, and such circumstances are unlikely to be temporary, our lenders may establish an alternative interest rate for borrowings under the ONE Gas Credit Agreement by replacing LIBOR with one or more secured overnight financing-based rates or another alternate benchmark rate.
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 72.5 percent at the end of any calendar quarter through December 31, 2021, and 70 percent at the end of any calendar quarter thereafter. At December 31, 2021, our total debt-to-capital ratio was 64 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.
At December 31, 2021, 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.
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.
On June 22, 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. The maturities of the commercial paper notes may vary, but may not exceed 270 days from the date of issue. The commercial paper notes are sold generally at par less a discount representing an interest factor. At December 31, 2021 and 2020, we had $494.0 million and $418.2 million of commercial paper outstanding, respectively. The weighted-average interest rate on our commercial paper was 0.38 percent and 0.18 percent at December 31, 2021 and 2020, respectively.
Long-Term Debt - In March 2021, we issued $1.0 billion of 0.85 percent senior notes due 2023, $700 million of 1.10 percent senior notes due 2024, and $800 million of floating-rate senior notes due 2023. The floating-rate senior notes bear interest at a rate equal to three-month LIBOR plus 61 basis points per year reset quarterly for the applicable interest period (0.81 percent at
December 31, 2021). The net proceeds from the issuance were used for general corporate purposes, including payment of gas purchase costs resulting from Winter Storm Uri.
In the event LIBOR is not available, and such circumstances are unlikely to be temporary, we or our designee may establish an alternative interest rate for our floating-rate senior notes due 2023 by replacing LIBOR with one or more secured financing-based rates or another alternate benchmark rate.
On September 21, 2021, we called $400 million of the floating-rate senior notes due 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.
In April 2020, ONE Gas issued $300 million of 2.00 percent senior notes due 2030. The proceeds from the issuance were used to reduce the amount of outstanding commercial paper and for general corporate purposes.
Our long-term debt includes $1.0 billion of 0.85 percent senior notes due 2023, $400 million of floating-rate senior notes due 2023, $300 million of 3.61 percent senior notes due in 2024, $700 million of 1.10 percent senior notes due 2024, $300 million of 2.00 percent senior notes due 2030, $600 million of 4.658 percent senior notes due 2044, and $400 million of 4.50 percent senior notes due 2048. 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 the 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.
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.
In April 2021, legislation in Oklahoma and Kansas was approved and in June 2021, legislation in Texas was approved that permits utilities to pursue securitization to finance extraordinary expenses, such as fuel costs, incurred during extreme weather events. We are currently seeking approval from our regulators to utilize the securitization legislation in each state to repay or refinance the debt we incurred to finance the extraordinary costs associated with Winter Storm Uri. The OCC issued a financing order on January 25, 2022, and the RCC issued a financing order on February 8, 2022. We expect the bonds to be issued no later than December 31, 2022. See “Regulatory Activities” for Oklahoma, Kansas and Texas in this Annual Report for additional discussion of the securitization legislation in each state.
At December 31, 2021, our long-term debt-to-capital ratio was 61 percent.
Credit Ratings - Our credit ratings at December 31, 2021, were:
Rating Agency Rating Outlook
Moody’s A3 Negative
S&P BBB+ Negative
At December 31, 2021, our commercial paper was rated Prime-2 by Moody’s and A-2 by S&P.
On February 15, 2022, Moody’s revised our outlook to stable from negative and reaffirmed our A3 senior secured rating and Prime-2 commercial paper rating.
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, 2021 and 2020, we issued and sold 281,124 and 179,514 shares of our common stock for $21.4 million and $13.6 million, respectively, generating proceeds, net of issuance costs, of $21.1 million and $13.5 million, respectively. At December 31, 2021, we had $215.0 million of equity available for issuance under the program. Proceeds from the program are available for general corporate purposes, which may include repaying or refinancing a portion of our outstanding indebtedness and funding working capital and capital expenditures.
Tax Reform - We have addressed the regulatory liability for EDIT resulting from the Tax Cuts and Jobs Act of 2017 in each of our jurisdictions. Our 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 other regulatory liabilities resulting from the effect of the changes in income taxes on our rates.
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, will be addressed during the processing of the March 15, 2022 PBRC filing.
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. 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 an EDIT 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 year ended December 31, 2020. 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 to reflect the elimination of Kansas state income taxes by approximately $4.9 million. In December 2020, the KCC approved the reduction, effective January 1, 2021.
Cash flows for years ended December 31, 2021, 2020 and 2019 were reduced by approximately $17.3 million, $17.4 million and $12.8 million, respectively, for EDIT returned to customers.
Pension and Other Postemployment Benefit Plans - For the year ended December 31, 2021, we contributed $1.0 million to our defined benefit pension plan and $2.0 million to our other postemployment benefit plans. For the year ended December 31, 2020, we contributed $1.0 million to our defined benefit pension plan and $2.1 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 13 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
2021 2020 2019 2021 vs. 2020 2020 vs. 2019
(Millions of dollars)
Total cash provided by (used in):
Operating activities $ (1,535.7) $ 364.5 $ 310.4 $ (1,900.2) $ 54.1
Investing activities (501.1) (470.4) (422.9) (30.7) (47.5)
Financing activities 2,037.6 96.0 109.1 1,941.6 (13.1)
Change in cash and cash equivalents 0.8 (9.9) (3.4) 10.7 (6.5)
Cash and cash equivalents at beginning of period 8.0 17.9 21.3 (9.9) (3.4)
Cash and cash equivalents at end of period $ 8.8 $ 8.0 $ 17.9 $ 0.8 $ (9.9)
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 service 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.
2021 vs. 2020 - Cash flows from operating activities were lower in 2021 compared with 2020, due primarily to the extraordinary costs resulting from Winter Storm Uri, which were deferred and included in regulatory assets. See Note 10 of the Notes to Consolidated Financial Statements in this Annual Report for additional information.
Investing Cash Flows - 2021 vs. 2020 - Cash used in investing activities increased for 2021, compared to 2020, due primarily to capital expenditures for increased system integrity activities and extending service to new areas.
Financing Cash Flows - 2021 vs. 2020 - Cash provided by financing activities for 2021 increased, compared with 2020, due primarily to borrowings to finance the extraordinary costs resulting from Winter Storm Uri.
2020 vs. 2019 - Cash flows in 2020, compared with 2019, 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, 2020.
ENVIRONMENTAL, SAFETY AND REGULATORY MATTERS
COVID-19 - See “Regulatory Activities,” “Financial Results and Operating Information,” and “Capital Expenditures and Asset Removal Costs,” as well as Notes 10 and 16 of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion regarding the effects of COVID-19 on us.
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 2021, 2020, or 2019.
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, 2021 and 2020, we have deferred $29.9 million and $18.8 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 and anticipates that filing will occur in 2022.
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. A remediation plan was submitted to the KDHE concerning this site in 2020 and the KDHE has provided comments that we are addressing. We are also working on a remediation plan that we expect to submit to the KDHE in 2022 for an additional site. During the year ended December 31, 2021, we increased the estimates for contractor costs due to increased demand for the types of resources needed to conduct work contemplated in our remediation plans, resulting in an increase in our reserves of $11.2 million. At December 31, 2021 and 2020, the reserve for remediation of our MGP sites was $22.8 million and $14.5 million, respectively.
We also own or retain legal responsibility for certain environmental conditions at a former MGP site in Texas. At the request of the Texas Commission on Environmental Quality, 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. Until the investigation is complete, we are unable to determine what, if any, active remediation will be required. A reliable estimate of potential remediation costs is not feasible at this point due to the amount of uncertainty as to the levels and extent of contamination.
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, 2021, 2020 and 2019. 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. We do not expect expenditures for these matters to have a material adverse effect on our financial condition, results of operations or cash flows.
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. For example, 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. Subsequently, PHMSA announced they would split this NPRM into three separate final rulemakings:
•the first final rule addresses the legislative mandates from the Pipeline Safety, Regulatory Certainty and Job Creation Act and is called the Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments;
•the second final rule will be called the Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments and will cover all remaining elements of the NPRM (except for gas gathering pipelines); and
•the third final rule will be called the Safety of Gas Gathering Pipelines and will address gas gathering pipelines.
On October 1, 2019, PHMSA published the first of the three final rules referenced above, which addressed the 2011 congressional mandates. This final rule expands integrity management principles beyond HCAs and requires operators to collect traceable, verifiable and complete records moving forward, retain existing and new records for the life of the pipeline, and reconfirm pipeline MAOP in populated areas. The final rule also outlines methods for reconfirming a pipeline’s MAOP within 15 years. The first final rule became effective July 1, 2020. Our estimated capital and operating expenditures associated with compliance with the first final rule were not material.
PHMSA has not yet issued the second final rule. The potential capital and operating expenditures associated with compliance with this rule are currently being evaluated and could be significant depending on the final regulations. We do not expect to be impacted by the third final rule, as we do not own gas gathering pipelines.
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, 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 respective 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, regional and/or state legislative and/or regulatory initiatives may be proposed in the future to regulate greenhouse gas emissions. For example, President Biden has announced that climate change will be a focus of his administration and has signed several executive orders on the subject. For more information, see our risk factor titled “Carbon neutral, energy-efficiency or other legislation or regulations intended to address climate change could increase our operating costs or restrict our market opportunities, adversely affecting our financial results, growth, cash flows and results of operations.” We monitor relevant legislation and regulatory initiatives to assess the potential impact on our 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. 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.
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) following developing technologies for emission control; (4) promoting end-use conservation through programs that incentivize the use of high-efficiency equipment; and (5) reducing the loss of methane from our facilities. In addition, we are considering potential avenues to incorporate RNG and hydrogen into our operations. RNG and hydrogen technologies offer potential opportunities to secure new natural gas supply sources that could be transported on our pipeline system and potentially reduce greenhouse gas emissions.
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. We continue to focus on maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices to limit the release of natural gas during pipeline and facility maintenance and operations. 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 in 2016, 2017, 2018, 2019 and 2020 and anticipate reporting on our 2021 progress in 2022.
We continue to assess various opportunities for emission reductions and other potential improvements to our environmental footprint. However, we cannot guarantee that we will be able to implement any of the opportunities that we may review or
explore. For any such opportunities that we do choose to implement, we cannot guarantee that we will be able to implement them within a specific timeframe or across all operational assets.
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. In its most recent reports, ONE Future reported that its members registered a 2020 methane intensity of 0.424 percent, which surpassed the 2025 goal of 1.0 percent. We have submitted our 2020 data, which is aggregated with peer members. The distribution sector intensity was 0.118 percent, beating the goal of 0.225 percent by 46 percent. Participating distribution companies represented 40 percent of the natural gas delivered in the U.S. in 2020.
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 2021, 2020, or 2019.
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.
ESTIMATES AND CRITICAL 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 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 commissions 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 commodity 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, 2021 and 2020 was $183.2 million and $144.9 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 used the invoice method practical expedient, where we recognized 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, 2021, we contributed $1.0 million to our defined benefit pension plan and $2.0 million to our other postemployment benefit plans. For the year ended December 31, 2020, we contributed $1.0 million to our defined benefit pension plan and $2.1 million to our other postemployment benefit plans. In 2022, our contributions are expected to be $1.5 million to our defined benefit pension plans, and no contributions are expected to be made to our other postemployment benefit plans. In 2020, we paid $12.5 million of lump-sum settlements to certain terminated-vested participants in our defined benefit pension plan.
We recorded net periodic benefit costs for our defined benefit pension plans, prior to regulatory deferrals, of $26.4 million in 2021, and estimate that in 2022, we will record expenses of approximately $17.7 million. Net periodic benefits costs for our postemployment benefit plans, prior to regulatory deferrals, were a credit of $8.9 million in 2021, and we estimate that in 2022, we will record a credit of approximately $5.2 million, prior to regulatory deferrals.
The following table sets forth the significant assumptions used to determine our estimated 2022 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 3.05 % $ 3.2 $ 34.8
Discount rate for other postemployment benefits 3.00 % $ (0.2) $ 5.9
Expected long-term return on plan assets (c) 6.40%/5.85% $ 2.9 $ -
(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.
(c) Expected long-term return on plan assets for pension and other postemployment benefits are 6.40 percent and 5.85 percent, respectively.
Impairment of Goodwill - 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. Goodwill impairment reviews are performed at a reporting unit level, which we equate to our single business segment. Our goodwill impairment analyses, performed in 2021 and 2020, utilized a qualitative assessment and did not result in any impairment indicators, nor did our analyses reflect our reporting unit at risk. Additionally, we performed a quantitative analysis in 2019 which did not result in any impairment indicators. Subsequent to July 1, 2021, no event has occurred indicating that our fair value is less than the carrying value of our net assets.
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 an impairment test for goodwill. Our impairment test is made 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 our fair value, not to exceed the carrying amount of our goodwill.
To estimate our 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 impairment tests require the use of assumptions and estimates, such as industry economic factors and the profitability of future business strategies. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to future impairment charges.
See Note 1 of the Notes to Consolidated Financial Statements in this Annual Report for further discussion of goodwill.
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. In 2020, we submitted a remediation plan to the KDHE for one of our sites and the KDHE has provided comments that we are addressing. We are also working on a remediation plan that we expect to submit to the KDHE in 2022 for an additional site. At December 31, 2021 and 2020, the reserve for remediation of our MGP sites was $22.8 million and $14.5 million, respectively.
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, 2021 and 2020, we have deferred $29.9 million and $18.8 million, respectively, for accrued investigation and remediation costs pursuant to our AAO.
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, 2021, 2020 and 2019. 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 Note 16 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 seven debt issuances at their due dates. 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.
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 ONE Gas 2021 Term Loan Facility was terminated in March 2021 with the issuance of our $1.0 billion of 0.85 percent senior notes due 2023, $700 million of 1.10 percent senior notes due 2024, and $800 million of floating-rate senior notes due 2023. On September 21, 2021, we called $400 million of the floating-rate senior notes due 2023 at par.
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, 2021. 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;
•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 Kansas, Oklahoma, 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;
•conservation and energy efficiency efforts of our customers;
•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 financings currently contemplated in each of our jurisdictions;
•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 conditions in these areas’ housing markets;
•acts of nature and the potential effects of threatened or actual terrorism and war;
•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;
•discovery 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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 economically 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 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, our floating-rate senior notes that mature in 2023, 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 and other forms of collateral, when appropriate and allowed by tariff. With approximately 2.2 million customers across three states, we are not exposed materially to a concentration of credit risk. As a result of regulatory orders and safety considerations, customer disconnects for nonpayment were generally suspended beginning mid-March 2020 through April 2021, when disconnects were resumed in all service areas, except Texas, where disconnects were resumed in June 2021. We have 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. See “Recent Developments” in this Annual Report for additional discussion of the effects of COVID-19 on us. 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.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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, 2021 and 2020, 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, 2021, 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, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 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, 2021, 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 New, or Changes in Existing, Rate Regulation
As described in Notes 1 and 10 to the consolidated financial statements, total regulatory assets and total regulatory liabilities were approximately $2.3 billion and $561 million, respectively, as of December 31, 2021. 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. 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.
The principal considerations for our determination that performing procedures relating to the Company’s accounting for the effects of rate regulation is a critical audit matter are the significant judgment by management when assessing the impact of regulation on accounting for new and existing regulatory assets and liabilities, which in turn led to significant auditor judgment and subjectivity in performing procedures and evaluating audit evidence related to the accounting for the impact of regulatory proceedings on new and existing regulatory assets and 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 assessment of new rate regulation or changes to existing regulation, 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) obtaining and evaluating regulatory rate orders, including correspondence between the Company and regulators, (ii) assessing the reasonableness of management’s judgments regarding new or updated regulatory guidance and proceedings and the related accounting implications, and (iii) testing regulatory assets and liabilities based on provisions and formulas outlined in regulatory orders and other correspondence.
/s/ PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 24, 2022
We have served as the Company’s auditor since 2013.
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ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31,
2021 2020 2019
(Thousands of dollars, except per share amounts)
Total revenues $ 1,808,597 $ 1,530,268 $ 1,652,730
Cost of natural gas 775,006 537,445 687,974
Operating expenses
Operations and maintenance 449,676 431,115 429,126
Depreciation and amortization 207,233 194,881 180,395
General taxes 66,424 63,311 59,977
Total operating expenses 723,333 689,307 669,498
Operating income 310,258 303,516 295,258
Other expense, net (3,207) (3,020) (2,976)
Interest expense, net (60,301) (62,505) (62,681)
Income before income taxes 246,750 237,991 229,601
Income taxes (40,316) (41,579) (42,852)
Net income $ 206,434 $ 196,412 $ 186,749
Earnings per share
Basic $ 3.85 $ 3.70 $ 3.53
Diluted $ 3.85 $ 3.68 $ 3.51
Average shares (thousands)
Basic 53,575 53,133 52,895
Diluted 53,674 53,370 53,240
Dividends declared per share of stock $ 2.32 $ 2.16 $ 2.00
See accompanying Notes to Consolidated Financial Statements.
ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Years Ended December 31,
2021 2020 2019
(Thousands of dollars)
Net income $ 206,434 $ 196,412 $ 186,749
Other comprehensive income (loss), net of tax
Change in pension and other postemployment benefit plans liability, net of tax of $(379), $289, and $479, respectively
1,250 (1,038) (1,435)
Total other comprehensive income (loss), net of tax 1,250 (1,038) (1,435)
Comprehensive income $ 207,684 $ 195,374 $ 185,314
See accompanying Notes to Consolidated Financial Statements.
ONE Gas, Inc.
CONSOLIDATED BALANCE SHEETS
December 31, December 31,
2021 2020
Assets (Thousands of dollars)
Property, plant and equipment
Property, plant and equipment $ 7,274,268 $ 6,838,603
Accumulated depreciation and amortization 2,083,433 1,971,546
Net property, plant and equipment 5,190,835 4,867,057
Current assets
Cash and cash equivalents 8,852 7,993
Accounts receivable, net 341,756 292,985
Materials and supplies 54,892 52,766
Natural gas in storage 179,646 93,946
Regulatory assets 1,611,676 56,773
Other current assets 27,742 35,406
Total current assets 2,224,564 539,869
Goodwill and other assets
Regulatory assets 724,862 366,956
Goodwill 157,953 157,953
Other assets 103,906 96,877
Total goodwill and other assets 986,721 621,786
Total assets $ 8,402,120 $ 6,028,712
See accompanying Notes to Consolidated Financial Statements.
ONE Gas, Inc.
CONSOLIDATED BALANCE SHEETS
(Continued)
December 31, December 31,
2021 2020
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 53,633,210 shares at
December 31, 2021; issued and outstanding 53,166,733 shares at December 31, 2020
$ 536 $ 532
Paid-in capital 1,790,362 1,756,921
Retained earnings 565,161 483,635
Accumulated other comprehensive loss (6,527) (7,777)
Total equity 2,349,532 2,233,311
Long-term debt, excluding current maturities, and net of issuance costs of $12,418 and $13,159, respectively
3,683,378 1,582,428
Total equity and long-term debt 6,032,910 3,815,739
Current liabilities
Notes payable 494,000 418,225
Accounts payable 258,554 152,313
Accrued taxes other than income 67,035 63,800
Regulatory liabilities 8,090 15,761
Customer deposits 62,454 68,028
Other current liabilities 90,360 78,952
Total current liabilities 980,493 797,079
Deferred credits and other liabilities
Deferred income taxes 695,284 656,806
Regulatory liabilities 552,928 547,563
Employee benefit obligations 35,226 97,637
Other deferred credits 105,279 113,888
Total deferred credits and other liabilities 1,388,717 1,415,894
Commitments and contingencies
Total liabilities and equity $ 8,402,120 $ 6,028,712
See accompanying Notes to Consolidated Financial Statements.
ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31,
2021 2020 2019
(Thousands of dollars)
Operating activities
Net income $ 206,434 $ 196,412 $ 186,749
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 207,233 194,881 180,395
Deferred income taxes 43,449 18,485 13,307
Share-based compensation expense 10,498 9,803 9,314
Provision for doubtful accounts 9,131 15,450 8,994
Changes in assets and liabilities:
Accounts receivable (57,902) (58,423) 30,415
Materials and supplies (2,126) 2,966 (11,399)
Natural gas in storage (85,700) 10,313 3,036
Asset removal costs (49,029) (40,833) (47,784)
Accounts payable 107,207 28,376 (59,293)
Accrued taxes other than income 3,235 15,844 316
Customer deposits (5,574) 10,041 (3,196)
Regulatory assets and liabilities - current (1,562,574) (38,773) 3,787
Regulatory assets and liabilities - non-current (367,210) 23,648 24,416
Employee benefit obligation - (3,109) (35,401)
Other assets and liabilities - current 18,461 (12,877) 7,173
Other assets and liabilities - non-current (11,190) (7,704) (484)
Cash provided by (used in) operating activities (1,535,657) 364,500 310,345
Investing activities
Capital expenditures (495,246) (471,345) (417,322)
Other investing expenditures (7,554) (2,804) (7,009)
Other investing receipts 1,717 3,777 1,399
Cash used in investing activities (501,083) (470,372) (422,932)
Financing activities
Borrowings (repayment) on notes payable, net 75,775 (98,275) 217,000
Issuance of debt, net of discounts 2,498,895 298,428 -
Long-term debt financing costs (35,110) (2,885) -
Issuance of common stock 26,662 19,383 5,116
Repayment of long-term debt (400,000) - -
Dividends paid (123,912) (114,372) (105,424)
Tax withholdings related to net share settlements of stock compensation (4,711) (6,267) (7,575)
Cash provided by financing activities 2,037,599 96,012 109,117
Change in cash and cash equivalents 859 (9,860) (3,470)
Cash and cash equivalents at beginning of period 7,993 17,853 21,323
Cash and cash equivalents at end of period $ 8,852 $ 7,993 $ 17,853
Supplemental cash flow information:
Cash paid for interest, net of amounts capitalized $ 70,066 $ 60,126 $ 61,160
Cash paid (received) for income taxes, net $ (10,809) $ 30,361 $ 30,152
See accompanying Notes to Consolidated Financial Statements.
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ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF EQUITY
Common Stock Issued Common Stock Paid-in Capital
(Shares) (Thousands of dollars)
January 1, 2019 52,598,005 $ 526 $ 1,727,492
Net income - - -
Other comprehensive loss - - -
Reclassification of stranded tax effects - - -
Common stock issued and other 173,744 2 4,697
Common stock dividends - $2.00 per share
- - 903
December 31, 2019 52,771,749 528 1,733,092
Net income - - -
Other comprehensive loss - - -
Common stock issued and other 394,984 4 22,915
Common stock dividends - $2.16 per share
- - 914
December 31, 2020 53,166,733 532 1,756,921
Net income - - -
Other comprehensive income - - -
Common stock issued and other 466,477 4 32,445
Common stock dividends - $2.32 per share
- - 996
December 31, 2021 53,633,210 $ 536 $ 1,790,362
See accompanying Notes to Consolidated Financial Statements.
ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF EQUITY
(Continued)
Retained Earnings Treasury Stock Accumulated Other Comprehensive Loss Total Equity
(Thousands of dollars)
January 1, 2019 $ 320,869 $ (2,145) $ (4,086) $ 2,042,656
Net income 186,749 - - 186,749
Other comprehensive loss - - (1,435) (1,435)
Reclassification of stranded tax effects 1,218 - (1,218) -
Common stock issued and other - 2,145 - 6,844
Common stock dividends - $2.00 per share
(106,327) - - (105,424)
December 31, 2019 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 - - - 22,919
Common stock dividends - $2.16 per share
(115,286) - - (114,372)
December 31, 2020 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 - - - 32,449
Common stock dividends - $2.32 per share
(124,908) - - (123,912)
December 31, 2021 $ 565,161 $ - $ (6,527) $ 2,349,532
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 our approximately 2.2 million customers through our divisions in Oklahoma, Kansas and Texas through 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 the 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 commodity 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, 2021 and 2020 was $183.2 million and $144.9 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 the 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 and Cash Equivalents - Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less.
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 2.2 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, 2021 and 2020, our allowance for doubtful accounts was $18.7 million and $16.6 million, respectively.
Inventories - Natural gas in storage is accounted for on the basis of weighted-average cost. Natural gas inventories that are injected into storage are recorded in inventory based on actual purchase costs, including storage and transportation costs. Natural gas inventories that are withdrawn from storage are accounted for in our purchased-gas cost adjustment mechanisms at the weighted-average inventory 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 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 11 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 test is made 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.
We performed a quantitative analysis in 2019, which did not result in any impairment indicators, nor did our analysis reflect our reporting unit at risk. Our goodwill impairment analysis performed in 2021 and 2020 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, 2021, 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 2021, 2020 or 2019.
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. 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.
See Note 10 for additional information regarding our regulatory assets and liabilities disclosures.
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, 2021 and 2020.
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, 2021 and 2020.
Changes in tax laws or tax rates are recognized in the financial reporting period that includes the enactment date.
See Note 14 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, 2021 and 2020, 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 16 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 based on net income and is calculated based upon 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, 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 2021, 2020 and 2019, we had no single external customer from which we received 10 percent or more of our gross revenues.
Treasury Stock - We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in equity in our consolidated balance sheets. We record the reissuance of treasury stock at our weighted average cost of treasury shares recorded in equity in our consolidated balance sheets.
Reclassifications - Certain reclassifications have been made in the prior-year financial statements to conform to the current-year presentation. We have updated our 2020 and 2019 Statements of Cash Flows to disaggregate “regulatory assets and liabilities” and “other assets and liabilities” into current and non-current components that are presented on our balance sheet to conform to our current year presentation.
Recently Issued Accounting Standards Update - 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. Our revolving line of credit under the ONE Gas Credit Agreement and our floating-rate senior notes utilize LIBOR as the reference rate. If modified, we may elect the optional practical expedients to account for the modifications prospectively. Our adoption did not result in a material impact to our consolidated financial statements.
In December 2019, the FASB issued ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes,” which removes certain exceptions for recognizing deferred taxes for investments, performing intra-period allocation and calculating income taxes in interim periods. ASU 2019-12 also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. This standard is effective for interim and annual periods in fiscal years beginning after December 15, 2020. We adopted this new guidance in the first quarter of 2021 and our adoption did not result in a material impact to our financial position or results of operations or to our consolidated financial statements.
In August 2018, the FASB issued ASU 2018-15, “Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (a consensus of the FASB Emerging Issues Task Force).” Under this guidance, a company should defer implementation costs that it incurs if a company would capitalize those same costs under the internal-use software guidance for an arrangement that is a software license. The deferred implementation costs should be amortized over the term of the hosting arrangement, including any probable renewals. We are party to hosting arrangements identified as service contracts for various information systems used in our operations. We adopted this new guidance using the prospective transition approach for implementation costs incurred in hosting arrangement service contracts beginning January 1, 2020. In certain jurisdictions, we have orders from our regulators allowing us to amortize deferred implementation costs for hosting arrangements entered into after January 1, 2020, over the life approved by our regulators for our internal-use software systems rather than the term of the hosting arrangement. The difference in amortization calculated between the term of the hosting arrangement and internal-use software life approved
by our regulators is deferred as a regulatory asset and amortized over the remaining internal-use software life that exceeds the term of the hosting arrangement. Our adoption did not result in a material impact to our consolidated financial statements.
In August 2018, the FASB issued ASU No. 2018-14, an amendment to ASC 715, “Compensation - Retirement Benefits.” This guidance eliminates requirements for certain disclosures such as the amount and timing of plan assets expected to be returned to the employer and the amount of future annual benefits covered by insurance contracts. The standard is effective for periods ending after December 15, 2020, and we adopted this guidance in the first quarter 2020. The guidance added new disclosure requirements for sponsors of the defined benefit plans to provide information relating to the weighted-average interest crediting rate for cash balance plans and other plans with promised interest crediting rates and an explanation for significant gains or losses related to changes in the benefit obligations for the period. We have reflected these changes as presented in Note 13 to our consolidated financial statements.
In August 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement,” which removes, modifies and adds to certain disclosure requirements of fair value measurements. The guidance was effective for the Company beginning January 1, 2020, and we adopted this guidance in the first quarter 2020. Disclosure requirements removed include the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, the policy for timing of transfers between levels and the valuation processes for Level 3 fair value measurements. Modifications include considerations around the requirement to disclose the timing of liquidation of an investee’s assets and the date when restrictions from redemption might lapse. The additions include the requirement to disclose changes in unrealized gains and losses for the period in other comprehensive income for recurring Level 3 fair value measurements held and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. The guidance did not have a material impact on the Company’s fair value disclosure, and we have reflected these changes as presented in Note 13 to our consolidated financial statements.
In February 2018, the FASB issued ASU 2018-02, “Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income,” which allows a reclassification from accumulated other comprehensive income (loss) to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. We adopted this new guidance in the first quarter 2019 and our adoption did not result in a material impact to our consolidated financial statements. This change is reflected in our consolidated statements of equity.
In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses: Measurement of Credit Losses on Financial Instruments,” which introduces new guidance to the accounting for credit losses on instruments within its scope, including trade receivables. We adopted this new guidance in the first quarter 2020 using the modified retrospective method. Our financial assets within scope of this guidance primarily include our trade receivables from customers. Our policy for measuring our allowance for doubtful accounts is disclosed in the aforementioned policy for accounts receivable. We did not create any new accounting policies, nor did we modify any of our existing policies, as a result of adopting this guidance. Our adoption did not result in a cumulative adjustment to our opening retained earnings or have 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,
2021 2020 2019
(Thousands of dollars)
Natural gas sales to customers $ 1,652,566 $ 1,381,141 $ 1,512,886
Transportation revenues 118,492 113,855 114,014
Miscellaneous revenues 16,757 15,505 20,579
Total revenues from contracts with customers 1,787,815 1,510,501 1,647,479
Other revenues - natural gas sales related 9,650 8,299 (4,699)
Other revenues 11,132 11,468 9,950
Total other revenues 20,782 19,767 5,251
Total revenues $ 1,808,597 $ 1,530,268 $ 1,652,730
3.CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE
On March 16, 2021, we entered into the second amended and restated ONE Gas Credit Agreement, which was previously amended and restated on October 5, 2017.
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. We will be able to extend the maturity date by one year, subject to the lenders’ consent, up to two times. The ONE Gas Credit Agreement expires in March 2026, and 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 utilizes LIBOR as the reference rate for determining interest to accrue on the borrowings. In the event LIBOR is not available, and such circumstances are unlikely to be temporary, our lenders may establish an alternative interest rate for the senior notes by replacing LIBOR with one or more secured overnight financing-based rates or another alternate benchmark rate.
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 72.5 percent at the end of any calendar quarter through December 31, 2021, and 70 percent at the end of any calendar quarter thereafter. At December 31, 2021, our total debt-to-capital ratio was 64 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.
At December 31, 2021, 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.
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 discharged.
On June 22, 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. The maturities of the commercial paper notes may vary, but may not exceed 270 days from the date of issue. The commercial paper notes are sold generally at par less a discount representing an interest factor. At December 31, 2021 and 2020, we had $494.0 million and $418.2 million of commercial paper outstanding, respectively. The weighted-average interest rate on our commercial paper was 0.38 percent and 0.18 percent at December 31, 2021 and 2020, respectively.
4.LONG-TERM DEBT
Senior Notes - In March 2021, we issued $1.0 billion of 0.85 percent senior notes due 2023, $700 million of 1.10 percent senior notes due 2024, and $800 million of floating-rate senior notes due 2023. The floating-rate senior notes bear interest at a rate equal to three-month LIBOR plus 61 basis points per year reset quarterly for the applicable interest period (0.81 percent at December 31, 2021). The net proceeds from the issuance were used for general corporate purposes, including payment of gas purchase costs resulting from Winter Storm Uri.
In the event LIBOR is not available, and such circumstances are unlikely to be temporary, we or our designee may establish an alternative interest rate for our floating-rate senior notes due 2023 by replacing LIBOR with one or more secured financing-based rates or another alternate benchmark rate.
On September 21, 2021, we called $400 million of the floating-rate senior notes due 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.
In April 2020, ONE Gas issued $300 million of 2.00 percent senior notes due 2030. The proceeds from the issuance were used to reduce the amount of outstanding commercial paper and for general corporate purposes.
Our long-term debt includes $1.0 billion of 0.85 percent senior notes due 2023, $400 million of floating-rate senior notes due 2023, $300 million of 3.61 percent senior notes due in 2024, $700 million of 1.10 percent senior notes due 2024, $300 million
of 2.00 percent senior notes due 2030, $600 million of 4.658 percent senior notes due 2044, and $400 million of 4.50 percent senior notes due 2048. 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 the 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.
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 eight 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 $30.9 million and $37.2 million as of December 31, 2021 and 2020, 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 $8.2 million, $8.4 million, and $8.5 million in 2021, 2020 and 2019, respectively.
In 2021, we reassessed certain operating leases for office facilities and IT which were extended or modified, resulting in an increase in our right-of-use asset and operating lease liability of $0.4 million and $0.4 million, respectively.
Years Ended
December 31,
Other information related to operating leases 2021 2020 2019
(Millions of dollars)
Weighted-average remaining lease term 6 years 7 years 7 years
Weighted-average discount rate 2.78 % 2.81 % 3.62 %
Supplemental cash flows information
Lease payments $ (8.0) $ (8.0) $ (8.4)
Right-of-use assets obtained in exchange for lease obligations $ 0.4 $ 9.8 $ 9.5
December 31,
Future minimum lease payments under non-cancellable operating leases 2021
(Millions of dollars)
2022 $ 7.5
2023 6.3
2024 4.8
2025 4.1
2026 3.3
Thereafter 7.7
Total future minimum lease payments $ 33.7
Imputed interest (2.5)
Total operating lease liability $ 31.2
Consolidated balance sheets as of December 31, 2021
Current operating lease liability $ 6.8
Long-term operating lease liability 24.4
Total operating lease liability $ 31.2
6.EQUITY
Preferred Stock - At December 31, 2021, 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, 2021, we had approximately 196.4 million shares of authorized common stock available for issuance.
Treasury Shares - In 2019, we were authorized to purchase treasury shares to be used to offset shares issued under our equity compensation plan and the ESPP. Our Board of Directors established an annual limit of $20 million of treasury stock purchases, exclusive of funds received through the dividend reinvestment and the ESPP. Stock purchases could have been made in the open market or in private transactions at times, and in amounts that we deemed appropriate. There was no guarantee as to the exact number of shares that we would have purchased, and we terminated the program in 2019.
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, 2021 and 2020, we issued and sold 281,124 and 179,514 shares of our common stock for $21.4 million and $13.6 million, respectively, generating proceeds, net of issuance costs, of $21.1 million and $13.5 million, respectively. At December 31, 2021, we had $215.0 million of equity available for issuance under the program.
Dividends Declared - For the years ended December 31, 2021 and 2020, we declared and paid dividends of 2.32 per share (0.58 per share quarterly) and 2.16 per share (0.54 per share quarterly), respectively. In January 2022, we declared a dividend of $0.62 per share ($2.48 per share on an annualized basis) for shareholders of record on February 25, 2022, payable on March 11, 2022.
7.ACCUMULATED OTHER COMPREHENSIVE LOSS
The following table sets forth the balance in accumulated other comprehensive loss for the periods indicated:
Accumulated Other Comprehensive Loss
(Thousands of dollars)
January 1, 2020 $ (6,739)
Pension and other postemployment benefit plans obligations
Other comprehensive income before reclassification, net of tax of $587
(1,932)
Amounts reclassified from accumulated other comprehensive loss, net of tax of $(298)
Other comprehensive loss (1,038)
December 31, 2020 (7,777)
Pension and other postemployment benefit plans obligations
Other comprehensive loss before reclassification, net of tax of $11
Amounts reclassified from accumulated other comprehensive loss, net of tax of $(390)
1,172
Other comprehensive income 1,250
December 31, 2021 (6,527)
The following table sets forth the effect of reclassifications from accumulated other comprehensive loss on our Consolidated Statements of Income for the periods indicated:
Affected Line Item in the
Details about Accumulated Other Comprehensive Years Ended December 31, Consolidated Statements of
Loss Components 2021 2020 2019 Income
(Thousands of dollars)
Pension and other postemployment benefit plan obligations (a)
Amortization of net loss
$ 45,896 $ 42,492 $ 35,283
Amortization of unrecognized prior service cost
(279) (117) (673)
45,617 42,375 34,610
Regulatory adjustments (b) (44,055) (41,183) (33,758)
1,562 1,192 852 Income before income taxes
(390) (298) (213) Income tax expense
Total reclassifications for the period $ 1,172 $ 894 $ 639 Net income
(a) These components of accumulated other comprehensive loss are included in the computation of net periodic benefit cost. See Note 13 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
The following tables set forth the computation of basic and diluted EPS from continuing operations for the periods indicated:
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
Year Ended December 31, 2019
Income Shares Per Share
Amount
(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock
$ 186,749 52,895 $ 3.53
Diluted EPS Calculation
Effect of dilutive securities - 345
Net income available for common stock and common stock equivalents $ 186,749 53,240 $ 3.51
9.DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS
Derivative Instruments - At December 31, 2021, we held purchased natural gas call options for the heating season ending 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 $2.3 million. At December 31, 2020, we held purchased natural gas call options for the heating season ended March 2021, with total notional amounts of 14.7 Bcf, for which we paid premiums of $6.7 million, and which had a fair value of $0.8 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, accounts receivable and accounts payable is equal to book value, due to the short-term nature of these items. Our cash and cash equivalents are comprised of cash and money market accounts, which we consider to be Level 1. 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. At December 31, 2020, other current and noncurrent assets included $1.6 million of corporate bonds and $3.2 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 $3.7 billion and $1.6 billion at December 31, 2021 and 2020, respectively. The estimated fair value of our long-term debt, including current maturities, was $3.9 billion and $2.0 billion at December 31, 2021 and 2020, 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, 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 13 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 assets related to winter weather event costs and regulatory liabilities related to federal income tax rate changes.
December 31, 2020
Remaining Recovery Period Current Noncurrent Total
(Thousands of dollars)
Under-recovered purchased-gas costs 1 year $ 16,502 $ - $ 16,502
Pension and other postemployment benefit costs See Note 13 16,541 341,266 357,807
Reacquired debt costs 7 years 812 4,866 5,678
MGP remediation costs 15 years 98 18,711 18,809
Ad-valorem tax 1 year 5,558 - 5,558
WNA 1 year 4,806 - 4,806
Customer credit deferrals 1 year 10,267 - 10,267
Other 1 to 18 years 2,189 2,113 4,302
Total regulatory assets, net of amortization 56,773 366,956 423,729
Income tax rate changes (a) - (547,563) (547,563)
Over-recovered purchased-gas costs 1 year (15,761) - (15,761)
Total regulatory liabilities (15,761) (547,563) (563,324)
Net regulatory assets and liabilities $ 41,012 $ (180,607) $ (139,595)
(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 or base rates, and we believe that we will be able to recover such costs consistent with our historical recoveries.
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 Kansas, Oklahoma, and Texas. During this time, the governors of Kansas, Oklahoma, 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 Kansas, Oklahoma, and Texas jurisdictions, which resulted in aggregated natural gas purchases for the month of February 2021 of approximately $2.1 billion.
On February 16, 2021, the OCC approved an emergency order (i) directing natural gas and electric utilities to prioritize deliveries of natural gas and electricity for services necessary for life, health, and public safety, and of natural gas to electric generation facilities that serve human needs customers, and (ii) directing local utilities to communicate with their customers in order to reduce all non-essential energy consumption, and to reduce load in a safe and reasonable manner. The OCC order recognized that the severe weather conditions resulted in increased commodity prices for both gas and electric utilities, along with issues relating to commodity acquisition, line pressure, and supply shortages. The OCC order expired on February 20, 2021.
In response to a motion filed by Oklahoma Natural Gas, on March 2, 2021, the OCC issued an order stating that Oklahoma Natural Gas shall defer to a regulatory asset the extraordinary costs associated with this unprecedented winter weather event, including commodity costs, operational costs and carrying costs. The order further states that after all deferred costs have been accumulated and recorded, Oklahoma Natural Gas shall file a compliance report detailing the extent of such costs incurred. The order also provided that recovery of the deferred costs will be addressed in a future proceeding that will include a prudence review.
In April 2021, a bill permitting the state 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 by the Oklahoma governor. This bill gives the OCC the authority to approve amounts to be recovered from the issuance of ratepayer-backed securitized bonds by the ODFA.
On April 29, 2021, Oklahoma Natural Gas submitted an initial application requesting a financing order pursuant to this legislation. On July 30, 2021, Oklahoma Natural Gas filed a supplemental motion with its compliance report pursuant to the March 2, 2021 order from the OCC detailing the extent of extraordinary costs incurred and all required components pursuant to the legislation for the issuance of a financing order, which includes a proposed period of 20 years over which these costs will be collected from customers. On October 4, 2021, the Public Utility Division of the OCC filed responsive testimony recommending that a financing order for securitization be approved. A joint stipulation and settlement was filed on November 18, 2021, ahead of the hearing before the administrative law judge on November 22, 2021. The joint stipulation and settlement agreement includes an agreement that a financing order should be issued to recover through securitization all extreme gas purchase and extraordinary costs over a 25-year period. At the hearing on November 22, 2021, the administrative law judge recommended approval of the joint stipulation and settlement agreement. On January 25, 2022, the OCC approved a financing order, which reflected the terms of the settlement agreement. Following the issuance of the financing order, there is a 30-day period during which parties to our application may appeal the financing order to the Oklahoma Supreme Court. The securitization legislation allows the ODFA 24 months to complete the process to issue the securitized bonds; however, the financing order requests the ODFA to issue bonds and provide the net proceeds to Oklahoma Natural Gas as soon as feasible, but no later than December 31, 2022. At December 31, 2021, Oklahoma Natural Gas has deferred approximately $1.3 billion in extraordinary costs attributable to Winter Storm Uri.
On February 15, 2021, the KCC issued an emergency order (i) directing all jurisdictional natural gas and electric utilities to coordinate efforts and take all reasonably feasible, lawful, and appropriate actions to ensure adequate delivery of natural gas and electricity to interconnected, non-jurisdictional utilities in Kansas, (ii) 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 in Kansas, and (iii) allowing those electric and natural gas distribution utilities who incur extraordinary costs to ensure their customers and other interconnected customers continued to receive utility service during this unprecedented cold weather event to defer those costs and carrying costs to a regulatory asset account. Each jurisdictional utility was required to file a compliance report detailing the extent of such costs incurred and presenting a plan to minimize the financial impacts of this event on ratepayers over a reasonable time frame. These costs were subject to review for reasonableness and accuracy in future regulatory proceedings. 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 the winter weather event. In April 2021, a bill permitting the utilities to pursue securitization to finance extraordinary expenses incurred during extreme weather events, was signed into law by the Kansas governor. The bill 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 October 2021, a nonunanimous settlement agreement was filed with the KCC to reach a resolution on these penalties. Prior to a hearing on the amended settlement in January 2022, all parties reached a unanimous settlement, which was filed with a motion requesting approval of the unanimous settlement. Under the terms of the amended unanimous settlement, if approved, the carrying charge on assessed penalties was reduced to two percent, consistent with the nonunanimous agreement in the financial docket. Any amounts collected from these penalties would reduce the regulatory asset for the winter weather event by no more than $52.4 million. A hearing on the settlement was held on February 4, 2022. The KCC has until March 7, 2022, to issue an order on the motion.
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 to issue securitized bonds to recover the extraordinary costs resulting from Winter Storm Uri from its customers over a period of either 5, 7, or 10 years. In November 2021, a nonunanimous settlement agreement was filed with the KCC that would allow Kansas Gas Service to recover extraordinary costs as of October 31, 2021, net of any penalties recovered from marketers and individually-balanced transportation customers, plus carrying costs calculated at two percent. Subsequently, all parties reached agreement on the settlement’s terms which resulted in the nonunanimous agreement becoming a unanimous settlement agreement. The extraordinary costs, other than purchased gas costs, will be trued-up and validated. The settlement agreement supports Kansas Gas Service seeking a financing order from the KCC for the issuance of securitized utility tariff bonds. The KCC issued an order approving the unanimous settlement agreement on February 8, 2022. Kansas Gas Service expects to file an application, in a separate proceeding, requesting a financing order in the first quarter of 2022. The KCC will have 180 days from the date of the filing to consider Kansas Gas Service’s application. If the KCC approves the financing order, we can begin the process to issue the securitized bonds. At December 31, 2021, Kansas Gas Service has deferred approximately $388.3 million in extraordinary costs associated with Winter Storm Uri and has not collected any penalties from marketers or individually-balanced transportation customers.
On February 13, 2021, the RRC issued a Notice to Local Distribution Companies acknowledging that due to the demand for natural gas expected during the upcoming winter weather event, natural gas utility LDCs may be required to pay extraordinarily high prices in the market for natural gas and may be subjected to other extraordinary costs when responding to the event. The RRC also encouraged natural gas utilities to continue to work to ensure that the citizens of the State of Texas were provided with safe and reliable natural gas service. To partially defer and reduce the impact on customers for these costs that ultimately are reflected in customer bills, the RRC authorized LDCs to record a regulatory asset to account for the extraordinary costs associated with this winter weather event, including but not limited to gas cost and other costs related to the procurement and transportation of gas supply. These costs will be subject to review for reasonableness and accuracy in future regulatory proceedings.
In June 2021, a bill permitting the state to pursue securitized financing of extraordinary expenses, such as fuel costs, financing costs and other operational costs incurred by utilities during Winter Storm Uri, was signed into law by the Texas governor. This bill gives the RRC the authority to approve amounts to be recovered from the issuance of ratepayer-backed securitized bonds by the TPFA. Pursuant to this legislation and a June 17, 2021 RRC Notice to Gas Utilities, Texas Gas Service submitted an application to the RRC on July 30, 2021, for an order authorizing the amount of extraordinary costs for recovery and other such specifications necessary for the issuance of securitized bonds.
In October 2021, Texas Gas Service, the other natural gas utilities in Texas participating in the securitization process, the staff of the RRC and all intervenors filed a unanimous settlement agreement with the RRC. The settlement agreement provides that all costs to purchase natural gas during Winter Storm Uri by Texas Gas Service were reasonable, necessary and prudently incurred. Texas Gas Service agreed to reduce its regulatory asset amount to be securitized by the amount of extraordinary costs attributable to the West Texas service area, which will be recovered through a separate surcharge over a three-year period. The unanimous settlement agreement was approved by the RRC in November 2021.
On February 8, 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, for purposes of issuing the securitized bonds and has begun the process to issue the securitized bonds. At December 31, 2021, Texas Gas Service has deferred approximately $256.6 million in extraordinary costs associated with Winter Storm Uri, which includes $59.5 million attributable to the West Texas service area. Pursuant to the approved settlement order, Texas Gas Service began collecting the extraordinary costs, including carrying costs, associated with Winter Storm Uri attributable to the West Texas service area from those customers in January 2022.
We intend to use the proceeds of these securitized bonds to satisfy our senior notes coming due in March 2023.
In accordance with these regulatory orders associated with the winter weather event, we have deferred approximately $2.0 billion in extraordinary costs for natural gas purchases, related financing and carrying costs and other operational costs, which includes $1.3 billion of costs attributable to Oklahoma Natural Gas customers, $388.3 million of costs attributable to Kansas Gas Service customers and $256.6 million of costs attributable to Texas Gas Service customers, including $59.5 million attributable to the West Texas service area that will be recovered over a three year period beginning January 1, 2022. The amounts deferred at December 31, 2021, 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. In addition, as a result of Winter Storm Uri, we were assessed penalties as a result of over- or under-deliveries of natural gas during periods that operational flow orders were imposed on us. Regarding Kansas Gas Service’s motion requesting a limited waiver of penalty provisions of its tariff, if the nonunanimous settlement agreement filed with the KCC is approved, we anticipate assessing penalties on the marketers and individually-balanced transport customers we serve or their agents. Amounts recorded reflect management’s best estimate of the amounts we may pay or receive and may be adjusted in future periods as the disposition of such penalties is determined. As these amounts are related to the extraordinary gas purchase costs associated with Winter Storm Uri, which are deferred, future adjustments to the amounts we have 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.
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.
Ad-valorem tax represents an increase or decrease in Kansas Gas Service’s taxes above or below the amount approved in base rates. 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 noncurrent 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. At December 31, 2021, the noncurrent regulatory liability for income tax rate changes includes the reclassification of $29.3 million of deferred taxes related to the reduction of the state income tax rate in Oklahoma. Additionally, it includes the reclassification of $84.2 million of deferred taxes related to the elimination of state income tax for utilities in Kansas at December 31, 2021 and 2020. See Note 14 for additional information regarding the impact of income tax rate changes during the year ended December 31, 2021.
See Note 16 for additional information regarding our regulatory assets for MGP remediation costs.
We have 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. Pursuant to these orders, the recovery of any net incremental costs and lost revenues will be determined in future rate cases or alternative rate recovery filings in each jurisdiction. For financial reporting purposes, any amounts deferred as a regulatory asset for future recovery under these accounting orders must be probable of recovery. At December 31, 2021, no regulatory assets have been recorded. We continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable.
Recovery through rates resulted in amortization of regulatory assets of approximately $5.5 million, $3.2 million and $2.5 million for the years ended December 31, 2021, 2020 and 2019, respectively.
11.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,
2021 2020
(Thousands of dollars)
Natural gas distribution pipelines and related equipment $ 5,836,066 $ 5,517,488
Natural gas transmission pipelines and related equipment 624,528 586,360
General plant and other 712,659 657,037
Construction work in process 101,015 77,718
Property, plant and equipment 7,274,268 6,838,603
Accumulated depreciation and amortization (2,083,433) (1,971,546)
Net property, plant and equipment $ 5,190,835 $ 4,867,057
We compute depreciation expense by applying composite, straight-line rates of approximately 2.5 percent to 3.5 percent that were approved by various regulatory authorities.
We recorded capitalized interest of $4.2 million, $4.2 million and $4.6 million for the years ended December 31, 2021, 2020 and 2019, respectively. We incurred liabilities for construction work in process that had not been paid at December 31, 2021, 2020 and 2019 of $25.6 million, $24.3 million and $20.9 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.
12.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 nonemployee directors. At December 31, 2021, we have 4.3 million shares of common stock reserved for issuance under the ECP. At December 31, 2021, we had approximately 1.8 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 $7.5 million, net of tax benefits of $2.5 million, for 2021, $7.0 million, net of tax benefits of $2.3 million, for 2020, and $6.8 million, net of tax benefits of $2.2 million, for 2019.
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, 2021, there was $3.6 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 1.7 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, 2020
99,800 $ 82.29
Granted 50,353 $ 72.69
Vested (42,821) $ 71.67
Forfeited (13,058) $ 81.07
Nonvested at December 31, 2021
94,274 $ 82.16
2021 2020 2019
Weighted-average grant date fair value (per share) $ 72.69 $ 96.21 $ 83.94
Fair value of shares granted (thousands of dollars) $ 3,660 $ 3,005 $ 3,001
For the years ended December 31, 2021, 2020 and 2019, the fair value of restricted stock vested was $3.4 million, $3.3 million, and $3.3 million, respectively.
Performance Stock Unit Award Activity
As of December 31, 2021, there was $6.6 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 1.7 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 2021, 2020 and 2019 grants at the grant date:
Number of
Units Weighted-
Average Grant Date Fair Value
Nonvested at December 31, 2020
208,520 $ 87.97
Granted 107,381 $ 82.51
Vested (76,483) $ 74.04
Forfeited (40,819) $ 89.19
Nonvested at December 31, 2021
198,599 $ 90.13
2021 2020 2019
Volatility (a) 32.70% 16.40% 18.70%
Dividend yield 3.19% 2.25% 2.38%
Risk-free interest rate (b) 0.20% 1.40% 2.50%
(a) - Volatility based on historical volatility over three years using daily stock price observations of our peer utilities.
(b) - Using 3-year treasury.
2021 2020 2019
Weighted-average grant date fair value (per share) $ 82.51 $ 102.77 $ 89.86
Fair value of shares granted (thousands of dollars) $ 8,860 $ 6,502 $ 6,401
For the years ended December 31, 2021, 2020 and 2019, the fair value of performance stock vested was $7.2 million, $10.2 million, and $12.7 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 44 percent, 50 percent and 44 percent of employees participated in the plan in 2021, 2020 and 2019, respectively. For the years ended December 31, 2021, 2020 and 2019, employees purchased 89,240, 92,507, and 71,613 shares, respectively, at an average price of $63.41, $64.77 and $71.42, respectively.
Compensation expense, before taxes, was $1.1 million, $1.1 million and $1.5 million in 2021, 2020 and 2019, respectively.
13.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,
2021 2020
Discount rate - pension plans 3.05% 2.80%
Discount rate - other postemployment plans 3.00% 2.70%
Compensation increase rate 3.10% - 5.00%
3.10% - 3.90%
The following table sets forth the weighted-average assumptions used by us to determine the periodic benefit costs for the periods indicated:
Years Ended December 31,
2021 2020 2019
Discount rate - pension plans 2.80% 3.50% 4.40%
Discount rate - other postemployment plans 2.70% 3.40% 4.40%
Expected long-term return on plan assets - pension plans 7.15% 7.20% 7.20%
Expected long-term return on plan assets - other postemployment plans 7.50% 7.65% 7.35%
Compensation increase rate 3.10% - 3.90%
3.10% - 4.00%
3.20% - 4.00%
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 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 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. Our consolidated balance sheets reflect the capitalized non-service cost components as a regulatory asset. We have recognized a regulatory asset of $6.1 million and $6.0 million as of December 31, 2021 and December 31, 2020, 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,
2021 2020 2021 2020
Changes in Benefit Obligation (Thousands of dollars)
Benefit obligation, beginning of period $ 1,077,641 $ 1,001,368 $ 239,530 $ 230,490
Service cost 13,811 12,869 1,587 1,692
Interest cost 29,458 34,179 6,251 7,557
Plan participants’ contributions - - 3,226 3,500
Actuarial loss (gain) (19,587) 91,566 (8,894) 14,013
Benefits paid (51,333) (62,341) (18,894) (17,722)
Benefit obligation, end of period 1,049,990 1,077,641 222,806 239,530
Change in Plan Assets
Fair value of plan assets, beginning of period 987,583 907,974 230,895 207,182
Actual return (loss) on plan assets 75,999 140,939 14,786 35,837
Employer contributions 995 1,011 1,981 2,098
Plan participants’ contributions - - 3,226 3,500
Benefits paid (51,333) (62,341) (18,894) (17,722)
Settlements - - - -
Fair value of assets, end of period 1,013,244 987,583 231,994 230,895
Benefit Asset (Obligation), net at December 31 $ (36,746) $ (90,058) $ 9,188 $ (8,635)
Other noncurrent assets - - 9,188 -
Current liabilities (1,521) (1,056) - -
Noncurrent liabilities (35,225) (89,002) - (8,635)
Benefit Asset (Obligation), net at December 31 $ (36,746) $ (90,058) $ 9,188 $ (8,635)
The accumulated benefit obligation for our defined benefit pension plans was $1.0 billion and $1.0 billion at December 31, 2021 and 2020, respectively. At December 31, 2021 and 2020, the accumulated benefit obligations of each of our plans exceeded the fair value of the related plan’s assets.
For the year ended December 31, 2021, the pension benefit obligations experienced an actuarial gain of $19.6 million primarily due to the impact of increases in the discount rates used to calculate the benefit obligations. For the year ended December 31, 2020, the pension benefit obligations experienced an actuarial loss of $91.6 million primarily due to the impact of decreases in the discount rates used to calculate the benefit obligations. Benefits paid for 2020 reflects $12.5 million of lump sum payments to certain terminated-vested participants.
In 2022, our contributions are expected to be $1.5 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,
2021 2020 2019
(Thousands of dollars)
Components of net periodic benefit cost
Service cost $ 13,811 $ 12,869 $ 12,030
Interest cost (a) 29,458 34,179 40,670
Expected return on assets (a) (62,382) (61,119) (61,939)
Amortization of net loss (a) 45,523 42,319 33,039
Net periodic benefit cost $ 26,410 $ 28,248 $ 23,800
(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 15 for additional detail of our other income (expense), net.
Other Postemployment Benefits
Year Ended December 31,
2021 2020 2019
(Thousands of dollars)
Components of net periodic benefit cost
Service cost $ 1,587 $ 1,692 $ 1,734
Interest cost (a) 6,251 7,557 9,318
Expected return on assets (a) (16,807) (15,469) (12,586)
Amortization of unrecognized prior service cost (a) (279) (117) (673)
Amortization of net loss (a) 373 173 2,244
Net periodic benefit cost (credit) $ (8,875) $ (6,164) $ 37
(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 15 for additional detail of our other income (expense), net.
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,
2021 2020 2019
(Thousands of dollars)
Net gain (loss) arising during the period $ 67 $ (2,519) $ (2,766)
Amortization of loss 1,562 1,192 852
Deferred income taxes (379) 289 479
Total recognized in other comprehensive income (loss) $ 1,250 $ (1,038) $ (1,435)
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,
2021 2020
(Thousands of dollars)
Accumulated loss $ (272,332) $ (351,059)
Accumulated other comprehensive loss
before regulatory assets (272,332) (351,059)
Regulatory asset for regulated entities 264,027 341,125
Accumulated other comprehensive loss
after regulatory assets (8,305) (9,934)
Deferred income taxes 1,778 2,157
Accumulated other comprehensive loss,
net of tax $ (6,527) $ (7,777)
Other Postemployment Benefits
December 31,
2021 2020
(Thousands of dollars)
Prior service credit $ (194) $ 85
Accumulated loss (5,887) (13,134)
Accumulated other comprehensive loss
before regulatory assets $ (6,081) $ (13,049)
Regulatory asset for regulated entities 6,081 13,049
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:
2021 2020
Health care cost-trend rate assumed for next year 6.00% 6.25%
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 2028 2026
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 65 percent fixed income securities and 35 percent equity securities.
The following tables set forth our pension benefits and other postemployment benefits plan assets by fair value category as of the measurement date:
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.
(c) - This category primarily represents money market funds.
(d) - This category represents alternative investments such as hedge funds and other financial instruments.
Pension Benefits
December 31, 2020
Asset Category Level 1 Level 2 Level 3 Total
(Thousands of dollars)
Investments:
Equity securities (a) $ 392,639 $ 35,454 $ - $ 428,093
Government obligations - 78,080 - 78,080
Corporate obligations (b) - 343,118 - 343,118
Cash and money market funds (c) 1,589 23,311 - 24,900
Insurance contracts and group annuity contracts - - 24,603 24,603
Other investments (d) - 1,155 87,634 88,789
Total assets $ 394,228 $ 481,118 $ 112,237 $ 987,583
(a) - This category represents securities of the various market sectors from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category primarily represents money market funds.
(d) - This category represents alternative investments such as hedge funds and other financial instruments.
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.
(c) - This category primarily represents money market funds.
(d) - This category includes equity securities and bonds held in a captive insurance product.
Other Postemployment Benefits
December 31, 2020
Asset Category Level 1 Level 2 Level 3 Total
(Thousands of dollars)
Investments:
Equity securities (a) $ 73,578 $ - $ - $ 73,578
Government obligations - - - -
Corporate obligations (b) - 39,115 - 39,115
Cash and money market funds (c) 52 8,071 - 8,123
Insurance contracts and group annuity contracts (d) - 110,079 - 110,079
Total assets $ 73,630 $ 157,265 $ - $ 230,895
(a) - This category represents securities of the various market sectors from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category primarily represents money market funds.
(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, 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
December 31, 2020
Fair Value Unfunded Commitments Redemption Frequency Redemption Notice Period
(in thousands) (in days)
Grosvenor Registered Multi Limited Partnership $ 42,632 $ - quarterly 65
K2 Institutional Investors II Limited Partnership $ 45,002 $ - 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, 2020 $ 25,988 $ 81,793 $ 107,781
Unrealized gains 1,764 4,849 6,613
Purchases - 992 992
Settlements (3,149) - (3,149)
December 31, 2020 $ 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
Pension and Other Postemployment Benefit Payments - Benefit payments for our defined benefit pension and other postemployment benefit plans for the year ended December 31, 2021 were $51.3 million and $18.9 million, respectively. The following table sets forth the pension benefits and other postemployment benefits payments expected to be paid in 2022-2031:
Pension
Benefits Other Postemployment
Benefits
Benefits to be paid in: (Thousands of dollars)
2022 $ 52,936 $ 15,744
2023 $ 53,745 $ 15,571
2024 $ 54,440 $ 15,184
2025 $ 55,075 $ 14,940
2026 $ 55,852 $ 14,580
2027 through 2031 $ 283,344 $ 67,566
The expected benefits to be paid are based on the same assumptions used to measure our benefit obligation at December 31, 2021, 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, and employee contributions are discretionary. 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 $14.3 million, $13.8 million and $12.8 million in 2021, 2020 and 2019, respectively.
Profit-Sharing Plan - We have a profit-sharing plan for all employees who do not participate in our defined benefit pension plan. We plan to make a contribution to the profit-sharing plan each quarter equal to 1 percent of each participant’s eligible compensation during the quarter. Additional discretionary employer contributions may be made at the end of each year.
Employee contributions are not allowed under the plan. Our contributions to the plan were $9.9 million, $9.4 million and $8.5 million in 2021, 2020 and 2019, respectively. Effective December 30, 2021, our profit sharing plan was merged with and into our 401(k) Plan.
14.INCOME TAXES
The following table sets forth our provision for income taxes for the periods indicated:
Years Ended December 31,
2021 2020 2019
(Thousands of dollars)
Current income tax provision (benefit)
Federal $ (1,568) $ 20,129 $ 24,537
State (1,565) 2,965 5,008
Total current income tax provision (benefit) (3,133) 23,094 29,545
Deferred income tax provision
Federal 37,810 10,757 8,375
State 5,639 7,728 4,932
Total deferred income tax provision 43,449 18,485 13,307
Total provision for income taxes $ 40,316 $ 41,579 $ 42,852
The following table is a reconciliation of our income tax provision for the periods indicated:
Years Ended December 31,
2021 2020 2019
(Thousands of dollars)
Income before income taxes $ 246,750 $ 237,991 $ 229,601
Federal statutory income tax rate 21 % 21 % 21 %
Provision for federal income taxes 51,817 49,978 48,215
State income taxes, net of federal tax benefit 4,074 10,693 9,758
Amortization of EDIT regulatory liability (17,289) (17,031) (12,828)
Tax benefit of employee share-based compensation (469) (1,489) (2,116)
Other, net 2,183 (572) (177)
Total provision for income taxes $ 40,316 $ 41,579 $ 42,852
As of December 31, 2021, 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 change 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, will be addressed during the processing of the March 15, 2022 PBRC filing.
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. 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 an EDIT 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, 2021 and 2020. 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 to reflect the elimination of Kansas state income taxes by approximately $4.9 million. In December 2020, the KCC approved the reduction, effective January 1, 2021.
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,
2021 2020
(Thousands of dollars)
Deferred tax assets
Employee benefits and other accrued liabilities $ 11,126 $ 28,127
Regulatory adjustments for enacted tax rate changes 120,051 121,738
Net operating loss 424,861 -
Lease obligation basis 6,906 9,319
Other 12,597 4,790
Total deferred tax assets 575,541 163,974
Deferred tax liabilities
Excess of tax over book depreciation 734,051 717,492
Winter weather event costs 421,070 -
Purchased-gas cost adjustment - other 37,433 5,240
Other regulatory assets and liabilities, net 71,541 88,260
Right-of-use asset basis 6,730 9,788
Total deferred tax liabilities 1,270,825 820,780
Net deferred tax liabilities $ 695,284 $ 656,806
We deduct our purchased gas costs for federal income tax purposes in the period they are paid. As a result of the impacts from Winter Storm Uri, we recorded a $421.1 million (tax effected) increase in our deferred tax liability and an increase in our net operating loss carryforward as of December 31, 2021. At December 31, 2021, we had $386.0 million (tax effected) of federal net operating loss carryforwards and $38.9 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 2018, 2019 and 2020. We are no longer subject to income tax examination for years prior to 2018.
15.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,
2021 2020 2019
(Thousands of dollars)
Net periodic benefit cost other than service cost $ (3,930) $ (5,071) $ (5,895)
Earnings on investments associated with nonqualified employee benefit plans 3,699 4,616 5,268
Other, net (2,976) (2,565) (2,349)
Total other expense, net $ (3,207) $ (3,020) $ (2,976)
16.COMMITMENTS AND CONTINGENCIES
Commitments - See Note 5 of the Notes to Consolidated Financial Statements in this Annual Report for discussion of operating leases.
COVID-19 - Throughout the COVID-19 pandemic, we have continued to provide essential services to our customers. We have 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 have 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, 2021, we have not requested recovery of any deferrals pursuant to these orders and no regulatory assets have been recorded. We continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable.
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 2021, 2020, or 2019.
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, 2021 and 2020, we have deferred $29.9 million and $18.8 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 and anticipates that filing will occur in 2022.
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. A remediation plan was submitted to the KDHE concerning this site in 2020 and the KDHE has provided comments that we are addressing. We are also working on a remediation plan that we expect to submit to the KDHE in 2022 for an additional site. During the year ended December 31, 2021, we increased the estimates for contractor costs due to increased demand for the types of resources needed to conduct work contemplated in our remediation plans, resulting in an increase in our reserves of $11.2 million. At December 31, 2021 and 2020, the reserve for remediation of our MGP sites was $22.8 million and $14.5 million, respectively.
We also own or retain legal responsibility for certain environmental conditions at a former MGP site in Texas. At the request of the Texas Commission on Environmental Quality, 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. Until the investigation is complete, we are unable to determine what, if any, active remediation will be required. A reliable estimate of potential remediation costs is not feasible at this point due to the amount of uncertainty as to the levels and extent of contamination.
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, 2021, 2020 and 2019. 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.
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. For example, 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. Subsequently, PHMSA announced they would split this NPRM into three separate final rulemakings:
•the first final rule addresses the legislative mandates from the Pipeline Safety, Regulatory Certainty and Job Creation Act and is called the Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments;
•the second final rule will be called the Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments and will cover all remaining elements of the NPRM (except for gas gathering pipelines); and
•the third final rule will be called the Safety of Gas Gathering Pipelines and will address gas gathering pipelines.
On October 1, 2019, PHMSA published the first of the three final rules referenced above, which addressed the 2011 congressional mandates. This final rule expands integrity management principles beyond HCAs and requires operators to collect traceable, verifiable and complete records moving forward, retain existing and new records for the life of the pipeline, and reconfirm pipeline MAOP in populated areas. The final rule also outlines methods for reconfirming a pipeline’s MAOP within 15 years. The first final rule became effective July 1, 2020. Our estimated capital and operating expenditures associated with compliance with the first final rulemaking were not material.
PHMSA has not yet issued the second final rule. The potential capital and operating expenditures associated with compliance with this rule are currently being evaluated and could be significant depending on the final regulation. We do not expect to be impacted by the third final rule, as we do not own gas gathering pipelines.
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.
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 final outcome of such matters will not have a material adverse effect on our results of operations, financial position or cash flows.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (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, 2021.
The effectiveness of our internal control over financial reporting as of December 31, 2021, 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, 2021, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
Not applicable.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Directors of the Registrant
Information concerning our directors is set forth in our 2022 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 2022 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 2022 definitive Proxy Statement and is incorporated herein by this reference.
Nominating Procedures
Information concerning the nominating procedures is set forth in our 2022 definitive Proxy Statement and is incorporated herein by this reference.
The Audit Committee
Information concerning the Audit Committee is set forth in our 2022 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 2022 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 2022 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 2022 definitive Proxy Statement and is incorporated herein by this reference.
The Executive Committee
Information concerning the Executive Committee is set forth in our 2022 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.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
Information on executive compensation is set forth in our 2022 definitive Proxy Statement and is incorporated herein by this reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
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 2022 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 2022 definitive Proxy Statement and is incorporated herein by this reference.
Equity Compensation Plan Information
Information on equity compensation plans is set forth in our 2022 definitive Proxy Statement and is incorporated herein by this reference.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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 2022 definitive Proxy Statement and is incorporated herein by this reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information on the principal accountant’s fees and services is set forth in our 2022 definitive Proxy Statement and is incorporated herein by this reference.
PART IV.

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(1) Consolidated Financial Statements Page No.
(a)
Report of Independent Registered Public Accounting Firm (PCAOB ID: 238)
51-52
(b)
Consolidated Statements of Income for the years ended December 31, 2021, 2020 and 2019
(c)
Consolidated Statements of Comprehensive Income for the years ended December 31, 2021, 2020 and 2019
(d)
Consolidated Balance Sheets as of December 31, 2021 and 2020
56-57
(e)
Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019
(f)
Consolidated Statements of Equity for the years ended December 31, 2021, 2020 and 2019
60-61
(g)
Notes to Consolidated Financial Statements
62-92
(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 November 17, 2021 (incorporated by reference to Exhibit 3.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on November 23, 2021 (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)).
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 2018 Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.14 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 22, 2018 (File No. 1-36108)).
10.11* Form of 2018 Performance Unit Award Agreement (incorporated by reference to Exhibit 10.15 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 22, 2018 (File No. 1-36108)).
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* ONE Gas, Inc. Deferred Compensation Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.19 to ONE Gas, Inc.’s Annual Report on Form 10-K filed on February 23, 2017 (File No. 1-36108)).
10.15 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)).
10.16 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)).
10.17* 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)).
10.18* 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)).
10.19 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)).
10.20 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)).
10.21* 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)).
10.22* 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)).
10.23 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)).
10.24* 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)).
10.25 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)).
10.26* 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)).
10.27* 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)).
10.28* Form of 2022 Restricted Unit Award Agreement.
10.29* Form of 2022 Performance Unit Award Agreement.
10.30* Form of 2021 Restricted Unit Award Agreement dated June 2021.
10.31* Form of 2021 Performance Unit Award Agreement dated June 2021.
10.32* Form of 2021 Restricted Unit Award Agreement dated September 2021.
10.33* Form of 2021 Performance Unit Award Agreement dated September 2021.
10.34* 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)).
10.35* 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)).
10.36 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)).
10.37 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)).
10.38* 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)).
10.39* 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)).
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, 2021, 2020 and 2019; (iii) Consolidated Statements of Comprehensive Income for the years ended December 31, 2021, 2020 and 2019; (iv) Consolidated Balance Sheets as of December 31, 2021 and 2020; (v) Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019; (vi) Consolidated Statements of Equity for the years ended December 31, 2021, 2020 and 2019; 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.