ONE Gas, Inc. (OGS) FY 2021 MD&A

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.

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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.

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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

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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.

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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.

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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.

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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:

Natural gas sales to customers represent revenue from contracts with customers through implied contracts established by our

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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.

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

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:

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.

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The following table sets forth the HDD’s by state for the periods indicated:

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.

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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

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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:

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.

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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.

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

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.

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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.

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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

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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

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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.

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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.

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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:

(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

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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

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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;

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•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.