ONE Gas, Inc. (OGS)

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

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

RECENT DEVELOPMENTS

Credit Facility - In October 2024, we entered into an agreement that increased the capacity of the ONE Gas Credit Agreement to $1.35 billion from $1.275 billion with commitments from existing lenders and the addition of a new lender. Other than the increased commitments, the maturity date, March 16, 2028, and all other terms and conditions of the ONE Gas Credit Agreement remain unchanged.

Commercial Paper - In October 2024, we increased the capacity of our commercial paper program to $1.35 billion from $1.275 billion.

Equity issuances - On December 27, 2024, we settled under forward contracts 3,160,465 shares (926,465 shares from forwards related to an at-the-market equity distribution agreement and 2,234,000 from forwards related to underwriting agreements) of our common stock for net proceeds of $245.7 million ($75.2 million from forwards related to an at-the market equity distribution agreement and $170.5 million from forwards related to underwriting agreements).

In December 2024, we amended the two forward sale agreements we entered into in September 2023 to extend the maturity date of 223,000 and 180,000 shares of our common stock, to December 31, 2025 from December 31, 2024. The amended forward sale agreements provide for settlement on a date, or dates, to be specified at our discretion but which will occur no later than December 31, 2025.

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In February 2023, we entered into an at-the-market equity distribution agreement under which we may issue and sell shares of our common stock with an aggregate offering price up to $300 million. This at-the-market equity program replaced our previous at-the-market equity program, which began in February 2020, and expired in February 2023. 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. At December 31, 2024, we had $225.5 million of equity available for issuance under the program.

The following table summarizes all of our outstanding forward sale agreements at December 31, 2024:

See “Liquidity and Capital Resources” and Note 7 of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of our at-the-market equity program.

Dividend - In January 2025, we declared a dividend of $0.67 per share ($2.68 per share on an annualized basis) for shareholders of record as of February 21, 2025, payable on March 7, 2025.

REGULATORY ACTIVITIES

Oklahoma - As required by our tariff, PBRC filings are made annually on or before March 15 until the next general rate case, which is required to be filed on or before June 30, 2027. On February 29, 2024, Oklahoma Natural Gas filed its required PBRC application for the year ended December 2023. The filed request included a $31.8 million base rate revenue increase, $2.4 million energy efficiency incentive, and $12.8 million of estimated EDIT to be credited to customers in 2025. On May 31, 2024, a settlement in the case was filed with a proposed revenue increase of $31.4 million. On June 4, 2024, a hearing was held at the conclusion of which the administrative law judge took the case under advisement. On July 15, 2024, the administrative law judge issued a report to the OCC recommending approval of the settlement agreement. Pursuant to its tariff, Oklahoma Natural Gas placed new rates into effect on June 28, 2024. The OCC issued an order approving the settlement on August 27, 2024.

In March 2023, Oklahoma Natural Gas filed its required PBRC application for the year ended December 2022. The filed request included a $27.6 million base rate revenue increase, $2.5 million energy efficiency incentive, and $11.9 million of estimated EDIT to be credited to customers in 2024. On June 13, 2023, a settlement in the case was filed with a proposed revenue increase of $26.3 million, a $2.5 million energy efficiency incentive, and a $12.6 million EDIT credit. Pursuant to its tariff, Oklahoma Natural Gas placed new rates into effect on June 29, 2023. In July 2023, the OCC issued an order approving the settlement.

Kansas - On March 1, 2024, Kansas Gas Service submitted an application to the KCC requesting an increase to its base rates reflecting investments in its natural gas distribution system. On August 2, 2024, a unanimous settlement agreement was signed by all parties to the rate case and filed with the KCC. A hearing on the unanimous settlement agreement was held on August 13, 2024. On October 3, 2024, the KCC issued an order approving the settlement agreement and new rates became effective on November 1, 2024. Kansas Gas Service’s net base rates will increase by $35 million. Kansas Gas Service was already recovering $35 million from customers through the GSRS; therefore, this settlement represents a total base rate increase of $70 million. The unanimous settlement agreement stipulates a GSRS pre-tax carrying charge of 8.97 percent for subsequent GSRS filings.

In August 2023, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $8.0 million related to its GSRS. The KCC issued an order in November 2023 authorizing the increase, and the new surcharge became effective on December 1, 2023.

Texas

West-North Service Area - In February 2025, Texas Gas Service made a GRIP filing for all customers in the West-North service area, requesting a $8.2 million increase to be effective in June 2025.

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In March 2024, Texas Gas Service made a GRIP filing for all customers in the West-North service area, requesting an $8.6 million increase to be effective in July 2024. In June of 2024, El Paso and Socorro denied the requested increase. Texas Gas Service filed an appeal of these denials to the RRC on July 8, 2024, which was upheld by the RRC. All other municipalities, and the RRC, approved an increase of $8.5 million or allowed it to take effect with no action. Texas Gas Service implemented new rates in July 2024.

Central-Gulf Service Area - In February 2025, Texas Gas Service made a GRIP filing for all customers in the Central-Gulf service area, requesting a $15.4 million increase to be effective in June 2025.

In June 2024, Texas Gas Service filed a rate case for all customers in the Central-Gulf service area, requesting a $25.8 million increase. Texas Gas Service has invested approximately $355 million in its Central-Gulf service area natural gas distribution system since its last Central-Gulf service area rate case was finalized in August 2020. A portion of this investment, approximately $342 million, is currently recovered through GRIP. On September 27, 2024, the parties filed an uncontested settlement agreement for an increase of $19.3 million based on a 9.7 percent return on equity and 59.6 percent common equity ratio. In November 2024, the RRC approved this settlement and new rates took effect in December 2024.

In February 2024, Texas Gas Service made a GRIP filing for all customers in the Central-Gulf service area, requesting a $12.3 million increase to be effective in June 2024. In May 2024, the RRC and municipalities approved an increase of $12.2 million, and new rates became effective in June 2024.

Rio Grande Valley Service Area - In May 2024, Texas Gas Service made a GRIP filing for all customers in the Rio Grande Valley service area, requesting a $3.7 million increase to be effective in August 2024. In August 2024, the RRC and municipalities approved an increase of $3.6 million, and new rates became effective in September 2024.

In June 2023, Texas Gas Service filed a rate case for all customers in the Rio Grande Valley service area, requesting a $9.8 million increase. In November 2023, the parties filed a signed settlement agreement that included a 9.7 percent ROE and an overall revenue increase of $5.9 million. In January 2024, the administrative law judge issued a proposal for decision recommending approval of the settlement. On January 30, 2024, the RRC approved the administrative law judge’s decision and the new rates went into effect.

See “Regulatory Activities,” “Liquidity and Capital Resources,” and Notes 1 and 3 of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of the securitization transactions.

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FINANCIAL RESULTS AND OPERATING INFORMATION

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.

Selected Financial Results - Net income was $222.9 million, or $3.91 per diluted share, $231.2 million, or $4.14 per diluted share, and $221.7 million, or $4.08 per diluted share, for the years ended December 31, 2024, 2023 and 2022, respectively.

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 tariffs and rates approved by regulatory authorities, as well as revenues from regulatory mechanisms related to natural gas sales. Additionally, natural gas sales include recovery of the cost of natural gas.

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

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

Securitization customer charges represent revenue from contracts with customers through implied contracts established by the financing order approved by the KCC, related to the securitization of extraordinary costs incurred during Winter Storm Uri in the state of Kansas. See Note 17 of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of the securitization transaction in Kansas.

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

Our average cost of gas rate decreased to $5.32 per Mcf for the year ended December 31, 2024, compared to $7.08 per Mcf in the prior year. Cost of natural gas includes commodity purchases, fuel, storage, transportation, hedging costs and settlement proceeds for natural gas price volatility mitigation programs approved by our regulators and other gas purchase costs recovered through our cost of natural gas regulatory mechanisms and does not include an allocation of general operating costs or depreciation and amortization. These regulatory mechanisms provide a method of recovering natural gas costs on an ongoing basis without a profit. Therefore, although our revenues will fluctuate with the cost of natural gas that we pass-through to our customers, operating income is not affected by fluctuations in the cost of natural gas.

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2024 vs. 2023 - Operating income increased $21.4 million due primarily to the following:

•an increase of $67.9 million from new rates and

•an increase of $6.3 million in residential sales due to net customer growth in Oklahoma and Texas.

These increases were offset partially by:

•an increase of $22.9 million in employee-related costs;

•an increase of $16.9 million in depreciation expense due to additional capital expenditures being placed in service;

•an increase of $6.9 million in ad-valorem taxes;

•an increase of $2.2 million in fleet expense;

•an increase of $1.9 million in outside services; and

•an increase of $1.7 million in insurance expense.

Revenues for the year ended December 31, 2024, include a decrease of $4.3 million associated with KGSS-I, which is offset by a decrease of $2.5 million in amortization and operating expense and $1.7 million in interest expense, net.

Other Factors Affecting Net Income - Other factors that affect net income for the year ended December 31, 2024, compared with 2023, include an decrease of $2.0 million in other income, net and an increase of $31.9 million in interest expense, net. The decrease in other income, net is due primarily to a $1.2 million decrease in the gain on investments associated with our nonqualified deferred compensation plans. The increase in interest expense is due primarily to the issuance of $300 million of 5.10 percent senior notes due 2029 in December 2023, the reopening of the 5.10 percent senior notes in August 2024 in which we issued an additional $250 million, and repayment of $300 million of 3.61 percent senior notes due February 2024 and $473 million of 1.10 percent senior notes due March 2024 upon maturity with commercial paper.

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, 2024 and 2023, we credited income tax expense $25.7 million and $22.4 million, respectively, for the amortization of the regulatory liability associated with EDIT that was embedded in base rates.

Capital Expenditures and Asset Removal Costs - Our capital expenditures program includes expenditures for pipeline integrity, extending service to new areas, reinforcing and 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 $33.4 million for 2024, compared with 2023, due primarily to expenditures for system integrity and extension of service to new areas. Our capital expenditures and asset removal costs are expected to be approximately $750 million for 2025. While we did not experience a significant impact to our capital expenditure program during the year ended December 31, 2024, our future capital expenditure activity is dependent on a number of factors, including economic conditions and our supply chains for contract labor, materials and supplies.

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

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The increase in the average number of customers for 2024, compared with 2023, is due primarily to the connection of new customers resulting from the extension and expansion of our system in our service areas. For 2024, our average customer count includes 23,000 new customer connections compared to 23,400 in 2023.

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

The impact of weather on residential and commercial natural gas sales is mitigated by WNA mechanisms in all jurisdictions.

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

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

•Oklahoma - A 10-year weighted average as of June 30, 2021, as calculated using 11 weather stations across Oklahoma and weighted on average customer count.

•Kansas - A 30-year rolling average for years 1994-2023 calculated using three weather stations across Kansas and weighted on HDDs by weather station and customers.

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

Actual HDDs are based on the quarter-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.

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 outcome of such matters will not have a material adverse effect on our results of operations, financial position or cash flows. See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report for information with respect to legal proceedings.

LIQUIDITY AND CAPITAL RESOURCES

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

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

Short-term Debt - The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At December 31, 2024, our total debt-to-capital ratio was 51.8 percent and we were in compliance with all covenants under the ONE Gas Credit Agreement. Excluding the debt of KGSS-I, which is non-recourse to us, our total debt-to-capital ratio was 49.5 percent. 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, 2024, we had $1.35 million in letters of credit issued and no borrowings under the ONE Gas Credit Agreement, with approximately $1.349 billion of remaining credit, which is available to repay our commercial paper borrowings.

In June 2024, we entered into an agreement that increased the capacity of the ONE Gas Credit Agreement to $1.275 billion from $1.2 billion with commitments from existing lenders and the addition of a new lender.

In October 2024, we entered into an agreement that increased the capacity of the ONE Gas Credit Agreement to $1.35 billion from $1.275 billion with commitments from existing lenders and the addition of a new lender. The ONE Gas Credit Agreement provides for a $1.35 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 $150 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement is available to provide liquidity for working capital, capital expenditures, acquisitions and mergers, the issuance of letters of credit, and for other general corporate purposes.

In July 2024, we increased the capacity of our commercial paper program to $1.275 billion from $1.2 billion.

In October 2024, we increased the capacity of our commercial paper program to $1.35 billion from $1.275 billion. Under our commercial paper program, we may issue unsecured commercial paper to fund short-term borrowing needs. The maturities of the commercial paper vary but may not exceed 270 days from the date of issue. Commercial paper is generally sold at par less a discount representing an interest factor. At December 31, 2024 and December 31, 2023, we had $914.6 million and $88.5 million of commercial paper outstanding with a weighted-average interest rate of 4.77 percent and 5.60 percent, respectively.

Senior Notes - At December 31, 2024, our long-term debt-to-capital ratio was 43.8 percent. Excluding the debt of KGSS-I, which is non-recourse to us, our long-term debt-to-capital ratio was 40.7 percent. See Note 17 of the Notes to Consolidated Financial Statements in this Annual Report for information with respect to KGSS-I.

At December 31, 2024, we had outstanding $2.2 billion of Senior Notes with none due within the next year. The indenture governing our Senior Notes includes an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding Senior Notes to declare those Senior Notes immediately due and payable in full.

In August, 2024, we reopened our outstanding 5.10 percent senior notes due 2029 and issued an additional $250 million. After the completion of this offering, the aggregate principal amount of the outstanding 5.10 percent senior notes due 2029 is $550 million. The additional $250 million senior notes were issued at a premium of $4 million, creating an effective interest rate of 4.87 percent.

We repaid our $300 million of 3.61 percent senior notes due February 2024 and our $473 million of 1.10 percent senior notes due March 2024 upon maturity with commercial paper.

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Depending on the series, we may redeem our Senior Notes at par, plus accrued and unpaid interest to the redemption date, starting one month, 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.

Credit Ratings - Our credit ratings at December 31, 2024, were:

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.

Securitized Utility Tariff Bonds - At December 31, 2024, we had outstanding $287.3 million of 5.486 percent KGSS-I Securitized Utility Tariff Bonds with $29.0 million due within the next year. The bonds are governed by an indenture between KGSS-I and the indenture trustee. The indenture contains certain covenants that restrict KGSS-I’s ability to sell, transfer, convey, exchange, or otherwise dispose of its assets.

Equity Issuances - On December 27, 2024, we settled under forward contracts 3,160,465 shares (926,465 shares from forwards related to an at-the-market equity distribution agreement and 2,234,000 from forwards related to underwriting agreements) of our common stock for net proceeds of $245.7 million ($75.2 million from forwards related to an at-the market equity distribution agreement and $170.5 million from forwards related to underwriting agreements).

In December 2024, we amended the two forward sale agreements we entered into in September 2023 to extend the maturity date of 223,000 and 180,000 shares of our common stock to December 31, 2025 from December 31, 2024. The amended forward sale agreements provide for settlement on a date, or dates, to be specified at our discretion but which will occur no later than December 31, 2025.

In February 2023, we entered into an at-the-market equity distribution agreement under which we may issue and sell shares of our common stock with an aggregate offering price up to $300 million. This at-the-market equity program replaced our previous at-the-market equity program, which began in February 2020, and expired in February 2023. 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. At December 31, 2024, we had $225.5 million of equity available for issuance under the program.

Pension and Other Postemployment Benefit Plans - For the year ended December 31, 2024, we contributed $1.6 million to our defined benefit pension plans and no contributions were made to our other postemployment benefit plans. For the year ended December 31, 2023, we contributed $1.3 million to our defined benefit pension plans and $2.5 million to our other postemployment benefit plans. Additional information about our pension and other postemployment benefit plans, including anticipated contributions, is included under “Critical Accounting Estimates - Pension and Other Postemployment Benefits” and under Note 11 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 sales revenues, natural gas costs and operating expenses discussed in “Financial Results and Operating Information,” the effects of Winter Storm Uri 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 WNA mechanisms, 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.

Operating cash flows were lower for the year ended December 31, 2024, compared to 2023, due primarily to proceeds from government securitization of winter weather costs for Texas Gas Service in March 2023 and working capital changes related to lower cost of gas rates embedded in accounts receivable and natural gas in storage.

Investing Cash Flows - Cash used in investing activities increased for the year ended December 31, 2024, compared to 2023, due primarily to an increase in capital expenditures for system integrity and extension of service to new areas.

Financing Cash Flows - Cash used in financing activities decreased for the year ended December 31, 2024, compared to 2023, due primarily to commercial paper borrowing in excess of repayments of long-term debt and the additional issuance of long-term debt.

ENVIRONMENTAL, SAFETY AND REGULATORY MATTERS

Environmental Matters - We are subject to multiple laws and regulations regarding protection of the environment and natural and cultural resources, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, plant and wildlife protection, hazardous materials use, storage and transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits or the discovery of presently unknown environmental conditions may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other regulatory or permitting mandates under the CAA and other similar federal and state laws could require unexpected capital expenditures. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during 2024, 2023 and 2022.

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

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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. 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. 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 exceeds $15.0 million, net of any related insurance recoveries, Kansas Gas Service is required to file an application with the KCC for approval to increase the $15.0 million cap. During 2024, we received $1.7 million in insurance proceeds for remediation costs related to these sites. At December 31, 2024 and 2023, we have deferred $31.1 million and $32.0 million, respectively, for accrued investigation and remediation costs pursuant to our AAO. On January 3, 2025, Kansas Gas Service requested to increase the cap on the AAO from $15 million to $32 million. The original $15 million cap approved in 2017 was the result of a unanimous settlement agreement and contained additional reporting requirements and obligations. Kansas Gas Service's request to increase the cap leaves all these additional provisions in place.

We also own or retain legal responsibility for certain environmental conditions at a former MGP site in Texas. At the request of the TCEQ, we began investigating the level and extent of contamination associated with the site under their Texas Risk Reduction Program. A preliminary site investigation revealed that this site contains contaminants generally associated with MGP sites and is subject to control or remediation under various environmental laws and regulations. At December 31, 2024, estimated costs associated with expected remediation activities for this site are not material.

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the years ended December 31, 2024 and 2023. The reserve for remediation of our MGP sites was $14.3 million at December 31, 2024 and 2023.

Environmental Footprint - 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 2024, 2023 or 2022.

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. As part of the Consolidated Appropriations Act, 2021, the PIPES Act 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.

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

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IMPACT OF NEW ACCOUNTING STANDARDS

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

CRITICAL ACCOUNTING ESTIMATES

The preparation of our consolidated financial statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported 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 revenues and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.

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

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

For further discussion of regulatory assets and liabilities, see Note 3 of the Notes to Consolidated Financial Statements in this Annual Report.

Revenue Recognition - For regulated deliveries of natural gas, we read meters and bill customers on a monthly cycle. We recognize revenues upon the delivery of natural gas or services rendered to customers. The billing cycles for customers do not necessarily coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas that has been delivered but not yet billed at the end of an accounting period. Accrued unbilled revenue is based on a percentage estimate of amounts unbilled each month, which is dependent upon a number of factors, some of which require management’s judgment. These factors include customer consumption patterns and the impact of weather on usage. The accrued unbilled natural gas sales revenue at December 31, 2024 and 2023 was $212.0 million and $191.4 million, respectively, and is included in accounts receivable on our consolidated balance sheets.

We have determined the majority of our natural gas sales and transportation tariffs to be implied contracts with customers, which are settled over time, where our performance obligation is settled with our customer when natural gas is delivered and simultaneously consumed by the customer. In addition, we use the invoice method practical expedient, where we recognize revenue for volumes delivered for which we have a right to invoice. For our other utility revenue, which are primarily one-time service fees that meet the requirements under ASC 606, the performance obligation is satisfied at a point in time when services are rendered to the customer. Certain revenues that do not meet the requirements under ASC 606 as revenues from contracts with customers are reflected as other revenues in determining total revenue. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report for additional information regarding our revenues.

Pension and Other Postemployment Benefits - We have defined benefit pension plans covering eligible retirees and eligible 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

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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, 2024, we contributed $1.6 million to our defined benefit pension plans and no contributions were made to our other postemployment benefit plans. For the year ended December 31, 2023, we contributed $1.3 million to our defined benefit pension plans and $2.5 million to our other postemployment benefit plans. In 2025, our contributions are expected to be $9.8 million to our defined benefit pension plans, and no contributions are expected to be made to our other postemployment benefit plans.

We recorded net periodic benefit credits for our defined benefit pension plans, prior to regulatory deferrals, of $5.5 million in 2024, and estimate that in 2025, we will record net periodic benefit cost of approximately $5.7 million. Net periodic benefits credits for our postemployment benefit plans, prior to regulatory deferrals, were $0.4 million in 2024, and we estimate that in 2025, we will record a credit of approximately $0.2 million, prior to regulatory deferrals.

The following table sets forth the significant assumptions used to determine our estimated 2025 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.

See Note 11 of the Notes to Consolidated Financial Statements in this Annual Report for additional information regarding our pension and other postretirement benefit plans.

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

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effect on earnings or cash flows for the years ended December 31, 2024, 2023 and 2022. Environmental issues may exist with respect to these MGP sites that are unknown to us. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation required, changing technology and governmental regulations, and to the extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition, results of operations or cash flows.

See “Environmental Matters” and Note 15 of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of contingencies.

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

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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 and other statements in this Annual Report regarding our environmental, social and other sustainability plans and goals are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current, and forward-looking environmental, social and sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future.

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

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

•our ability to recover costs, income taxes and amounts equivalent to the cost of property, plant and equipment, regulatory assets and our allowed rate of return in our regulated rates or other recovery mechanisms;

•cyber-attacks, which, continue to increase in volume and sophistication, or breaches of technology systems that could disrupt our operations or result in the loss or exposure of confidential or sensitive customer, employee, vendor, counterparty or Company information; further, increased remote working arrangements 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;

•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 which could significantly disrupt or prevent us from operating our business in the ordinary course for an extended period;

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

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

•indebtedness, which 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;

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

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

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

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

•changes in inflation and interest rates;

•our ability to recover the costs of natural gas purchased for our customers and any related financing required to support our purchase of natural gas supply;

•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, cybersecurity and other laws or regulations 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 in Oklahoma, Kansas and Texas, and economic conditions in these areas;

•acts of nature and naturally occurring disasters;

•political unrest 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;

•changes in accounting standards;

•changes in corporate governance standards;

•existence of material weaknesses in our internal controls;

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

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

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

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

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

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

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

RECENT DEVELOPMENTS

Securitization transactions - In March 2023, the TNG Corporation completed the issuance of the Customer Rate Relief (Winter Storm Uri), Taxable Series 2023 Bonds. On March 23, 2023, we received our portion of the net proceeds, which was approximately $197 million. The proceeds were used to repay debt and for general corporate purposes.

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

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

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Long-Term Debt transactions - In December 2023, we issued $300 million of 5.10 percent senior notes due April 2029. The proceeds from the issuance were used to repay amounts outstanding under our commercial paper program and for general corporate purposes.

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

In August 2022, we called $750 million of the $1.0 billion of 0.85 percent senior notes due March 2023, $150 million of the $700 million of 1.10 percent senior notes due March 2024 and the remaining $400 million of outstanding floating-rate senior notes due March 2023, using the proceeds received from the securitization transaction for Oklahoma Natural Gas. In November 2022, we called the remaining $250 million of the $1.0 billion of 0.85 percent senior notes due March 2023 and $77 million of the $700 million of 1.10 percent senior notes due March 2024, using the proceeds from the securitization transaction for Kansas Gas Service.

See “Regulatory Activities,” “Liquidity and Capital Resources,” and Notes 1 and 3 of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of the securitization transactions.

Equity issuances - On December 28, 2023, we settled under forward contracts 1,032,403 shares (289,403 from forwards related to an at-the-market equity distribution agreement and 743,000 from forwards related to underwriting agreements) of our common stock for net proceeds of $79.0 million, or $76.52 per share.

In December 2023, we amended the forward sale agreement we entered into in March 2023 to extend the maturity date of 657,000 shares to December 31, 2024 from December 29, 2023. The amended forward sale agreement provides for settlement on a date, or dates, to be specified at our discretion, but which will occur no later than December 31, 2024, for 1,257,000 shares of common stock.

In September 2023, we entered into an underwriting agreement and two forward sale agreements for 1.2 million and 180,000 shares of our common stock, respectively. The forward sale agreements provide for settlement on a date, or dates, to be specified at our discretion, but which will occur no later than December 31, 2024.

In June 2023, we executed forward sale agreements under our current at-the-market equity program for 926,465 shares of our common stock.

In March 2023, we entered into an underwriting agreement and a forward sale agreement for 2.0 million shares of our common stock. The forward sale agreement provided for settlement on a date, or dates, to be specified at our discretion, but which will occur no later than December 29, 2023, for 1.4 million shares of common stock and by December 31, 2024, for the remaining balance.

In February 2023, we entered into an at-the-market equity distribution agreement under which we may issue and sell shares of our common stock with an aggregate offering price up to $300 million. This at-the-market equity program replaced our previous at-the-market equity program, which began in February 2020, and expired in February 2023. 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. At December 31, 2023, we had $225.5 million of equity available for issuance under the program.

ONE Gas Credit Agreement - In October 2023, we entered into an agreement that increased the capacity of the ONE Gas Credit Agreement to $1.2 billion from $1.0 billion.

In March 2023, we entered into an extension agreement related to the ONE Gas Credit Agreement that extended the maturity date to March 16, 2028, from March 16, 2027.

Other than the increased commitments and term extension, all other terms and conditions of the ONE Gas Credit Agreement remain in full force and effect.

Commercial paper program - In November 2023, we increased the capacity of our commercial paper program to $1.2 billion from $1.0 billion. Other than the increased capacity, all other terms and conditions of the commercial paper program remain in full force and effect.

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Dividend - In January 2024, we declared a dividend of $0.66 per share ($2.64 per share on an annualized basis) for shareholders of record as of February 23, 2024, payable on March 8, 2024.

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REGULATORY ACTIVITIES

Oklahoma - As required by our tariff, PBRC filings are made annually on or before March 15 until the next general rate case, which is required to be filed on or before June 30, 2027. In March 2023, Oklahoma Natural Gas filed its required PBRC application for the year ended December 2022. The filed request included a $27.6 million base rate revenue increase, $2.5 million energy efficiency incentive, and $11.9 million of estimated EDIT to be credited to customers in 2024. On June 13, 2023, a settlement in the case was filed with a proposed revenue increase of $26.3 million, a $2.5 million energy efficiency incentive, and a $12.6 million EDIT credit. Pursuant to its tariff, Oklahoma Natural Gas placed new rates into effect on June 29, 2023. In July 2023, the OCC issued an order approving the settlement.

In December 2022, Oklahoma Natural Gas filed a request for an RNG Pilot Program and Voluntary Tariff pursuant to the requirement in the rate case order approved in 2021. The tariff will allow all residential, small commercial and industrial sales customers to voluntarily purchase the environmental attributes of RNG up to the equivalent of 10 Dth per month. In September 2023, responsive testimony was filed by the Public Utility Division of the OCC and the Attorney General’s office supporting Oklahoma Natural Gas’ request. On October 6, 2023, a unanimous settlement recommending approval of the tariff was filed. On October 19, 2023, a hearing before an administrative law judge was held. At the conclusion of the hearing, the administrative law judge recommended approval of the tariff. On November 21, 2023 the OCC issued an order approving the RNG Pilot Program and Voluntary tariff and customer enrollment began on December 1, 2023. Approximately $2.4 million of RNG credits were purchased in December to support the program. Assessment of the tariff and pilot program will be made in the rate case required to be filed on or before June 30, 2027.

Kansas - In August 2023, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $8.0 million related to its GSRS. The KCC issued an order in November 2023 authorizing the increase, and the new surcharge became effective on December 1, 2023.

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

In February 2022, the RRC issued a single financing order for Texas Gas Service and other natural gas utilities in Texas participating in the securitization process, which included a determination that the approved costs will be collected from customers over a period of not more than 30 years. The TPFA formed the TNG Corporation, a new independent public authority, to issue the securitized bonds.

In March 2023, the TNG Corporation completed the issuance of the Customer Rate Relief (Winter Storm Uri), Taxable Series 2023 Bonds and we received our portion of the net proceeds, which was approximately $197 million. The proceeds were used to repay certain indebtedness and for general corporate purposes. Interest costs that exceeded the amount securitized have been deferred and will be addressed in the next general rate proceeding in each applicable jurisdiction in Texas. In October 2023, Texas Gas Service began acting as a collection agent, with responsibility for collecting the securitization charges from customers that are then submitted to the TNG Corporation to repay the securitization bonds.

Central-Gulf Service Area - In February 2024, Texas Gas Service made GRIP filings for all customers in the Central-Gulf service area, requesting a $12.3 million increase to be effective in June 2024.

In February 2023, Texas Gas Service made GRIP filings for all customers in the Central-Gulf service area, requesting an $11.5 million increase to be effective in June 2023. All municipalities, and the RRC, approved the increase or allowed it to take effect with no action, in June 2023.

West-North Service Area - In March 2023, Texas Gas Service made GRIP filings for all customers in the West-North service area, requesting a $7.4 million increase to be effective in July 2023. In June 2023, El Paso, Socorro and Anthony denied the requested increase. Texas Gas Service appealed the municipalities’ actions to the RRC. All other municipalities, and the RRC, approved an increase of $7.3 million or allowed it to take effect with no action. Texas Gas Service implemented the new rates in June 2023, subject to adjustment depending upon the outcome of the appeal. In August 2023, the RRC granted the appeal and approved the increase.

In June 2022, Texas Gas Service filed a rate case seeking to consolidate its West Texas, North Texas and Borger/Skellytown service areas into a single West-North service area and requesting a rate increase of $13.0 million. In January 2023, the RRC

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approved the consolidation and a rate increase of $8.8 million premised on a return on equity of 9.6 percent and a common equity ratio of 59.74 percent equity. The new rates were implemented in February 2023.

Rio Grande Valley Service Area - In June 2023, Texas Gas Service filed a rate case for all customers in the Rio Grande Valley service area, requesting a $9.8 million increase. In November 2023, the parties filed a signed settlement agreement that included a 9.7 percent ROE and an overall revenue increase of $5.9 million. In January 2024, the administrative law judge issued a proposal for decision recommending approval of the settlement. On January 30, 2024, the RRC approved the administrative law judge’s decision and the new rates went into effect.

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FINANCIAL RESULTS AND OPERATING INFORMATION

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.

Selected Financial Results - Net income was $231.2 million, or $4.14 per diluted share, $221.7 million, or $4.08 per diluted share, and $206.4 million, or $3.85 per diluted share, for the years ended December 31, 2023, 2022 and 2021, respectively.

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 tariffs and rates approved by regulatory authorities, as well as revenues from regulatory mechanisms related to natural gas sales. Additionally, natural gas sales include recovery of the cost of natural gas.

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

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

Securitization customer charges represent revenue from contracts with customers through implied contracts established by the financing order approved by the KCC, related to the securitization of extraordinary costs incurred during Winter Storm Uri in the state of Kansas. See Note 17 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion of the securitization transaction in Kansas.

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

Our average cost of gas rate decreased to $7.08 per Mcf for the year ended December 31, 2023, compared to $8.22 per Mcf in the prior year. Cost of natural gas includes commodity purchases, fuel, storage, transportation, hedging costs and settlement proceeds for natural gas price volatility mitigation programs approved by our regulators and other gas purchase costs recovered through our cost of natural gas regulatory mechanisms and does not include an allocation of general operating costs or depreciation and amortization. These regulatory mechanisms provide a method of recovering natural gas costs on an ongoing basis without a profit. Therefore, although our revenues will fluctuate with the cost of natural gas that we pass-through to our customers, operating income is not affected by fluctuations in the cost of natural gas.

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2023 vs. 2022 - Operating income increased $27.6 million due primarily to the following:

•an increase of $61.6 million from new rates;

•an increase of $6.3 million in residential sales due primarily to net customer growth; and

•an increase of $4.9 million in ad valorem recoveries.

These increases were offset partially by:

•an increase of $26.5 million in employee-related costs; and

•an increase of $19.3 million in depreciation expense due to additional capital expenditures being placed in service.

Revenues for the year ended December 31, 2023, include an increase of $42.9 million associated with KGSS-I, which is offset by an increase of $27.1 million in amortization and operating expense and $15.7 million in net interest expense.

Other Factors Affecting Net Income - Other factors that affect net income for the year ended December 31, 2023, compared with 2022, include an increase of $13.7 million in other income, net, and an increase of $37.8 million in interest expense. The increase in other income, net, is due primarily to a $12.0 million increase in the market value of investments associated with our nonqualified employee benefit plans. The increase in interest expense is due primarily to interest on our commercial paper, the issuance of $300 million of 4.250 percent senior notes in August 2022 and $336 million of 5.486 percent Securitized Utility Tariff Bonds in November 2022, compared with the same period last year.

EDIT - The return of EDIT to our customers is not expected to have a material impact on earnings, as any reduction or credit in rates is offset by a reduction in income tax expense. During the years ended December 31, 2023 and 2022, we credited income tax expense $22.4 million and $18.0 million, respectively, for the amortization of the regulatory liability associated with EDIT that was returned to customers.

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

Capital expenditures and asset removal costs increased $72.2 million for 2023, compared with 2022, due primarily to expenditures for system integrity and extension of service to new areas. Our capital expenditures and asset removal costs are expected to be approximately $750 million for 2024. While we did not experience a significant impact to our capital expenditure program during the year ended December 31, 2023, our future capital expenditure activity is dependent on a number of factors, including economic conditions and our supply chains for contract labor, materials and supplies.

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

The increase in the average number of customers for 2023, compared with 2022, is due primarily to the connection of new customers resulting from the extension and expansion of our system in our service areas. For 2023, our average customer count includes 23,400 new customer connections compared to 27,100 in 2022.

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

The impact of weather on residential and commercial natural gas sales is mitigated by WNA mechanisms in all jurisdictions.

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

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

•Oklahoma - A 10-year weighted average as of June 30, 2021, as calculated using 11 weather stations across Oklahoma and weighted on average customer count.

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

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

Actual HDDs are based on the quarter-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.

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 outcome of such matters will not have a material adverse effect on our results of operations, financial position or cash flows. See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report for information with respect to legal proceedings.

LIQUIDITY AND CAPITAL RESOURCES

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

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

Short-term Debt - In October 2023, we entered into an agreement that increased the capacity of the ONE Gas Credit Agreement to $1.2 billion from $1.0 billion.

In March 2023, we entered into an extension agreement related to the ONE Gas Credit Agreement that extended the maturity date to March 16, 2028, from March 16, 2027.

Other than the increased commitments and term extension, all other terms and conditions of the ONE Gas Credit Agreement remain in full force and effect.

The ONE Gas Credit Agreement provides for a $1.2 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 $300 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement is available to provide liquidity for working capital, capital expenditures, acquisitions and mergers, the issuance of letters of credit, and for other general corporate purposes.

The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At December 31, 2023, our total debt-to-capital ratio was 52 percent and we were in compliance with all covenants under the ONE Gas Credit Agreement. Excluding the debt of KGSS-I, which is non-recourse to us, our total debt-to-capital ratio was 50 percent. We may reduce the unutilized portion of the ONE Gas Credit Agreement in whole or in part without premium or penalty. The ONE Gas Credit Agreement contains customary events of default. Upon the occurrence of certain events of default, the obligations under the ONE Gas Credit Agreement may be accelerated and the commitments may be terminated.

In November 2023, we increased the capacity of our commercial paper program to $1.2 billion from $1.0 billion.

Under our commercial paper program, we may issue unsecured commercial paper up to a maximum amount of $1.2 billion to fund short-term borrowing needs. The maturities of the commercial paper vary but may not exceed 270 days from the date of issue. Commercial paper is generally sold at par less a discount representing an interest factor. At December 31, 2023 and 2022, we had $88.5 million and $552.0 million of commercial paper outstanding with a weighted-average interest rate of 5.60 percent and 4.75 percent, respectively.

At December 31, 2023, we had $1.4 million in letters of credit issued and no borrowings under the ONE Gas Credit Agreement, with approximately $1.2 billion of remaining credit, which is available to repay our commercial paper borrowings.

Senior Notes - In December 2023, we issued $300 million of 5.10 percent senior notes due April 2029. The proceeds from the issuance were used to repay amounts outstanding under our commercial paper program and for general corporate purposes.

At December 31, 2023, we had outstanding $2.7 billion of Senior Notes with $773.0 million due within the next year. The indenture governing our Senior Notes includes an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding Senior Notes to declare those Senior Notes immediately due and payable in full.

Depending on the series, we may redeem our Senior Notes at par, plus accrued and unpaid interest to the redemption date, starting three months or six months before their maturity dates. Prior to these dates, we may redeem these Senior Notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective Senior Note plus accrued and unpaid interest to the redemption date. The remaining $473 million of outstanding principal of our 1.10 percent senior notes due March 2024 can be called at par with a 30-day notice. Our Senior Notes are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness.

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Securitized Utility Tariff Bonds - At December 31, 2023, we had outstanding $315.3 million of 5.486 percent KGSS-I Securitized Utility Tariff Bonds with $27.4 million due within the next year. The bonds are governed by an indenture between KGSS-I and the indenture trustee. The indenture contains certain covenants that restrict KGSS-I’s ability to sell, transfer, convey, exchange, or otherwise dispose of its assets.

At December 31, 2023, our long-term debt-to-capital ratio was 52 percent. Excluding the debt of KGSS-I, which is non-recourse to us, our long-term debt-to-capital ratio was 49 percent. See Note 17 of the Notes to Consolidated Financial Statements in this Annual Report for information with respect to KGSS-I.

Credit Ratings - Our credit ratings at December 31, 2023, were:

At December 31, 2023, our commercial paper was rated Prime-2 by Moody’s and A-2 by S&P. We intend to maintain credit metrics at a level that supports our balanced approach to capital investment and a return of capital to shareholders via a dividend that we believe will be competitive with our peer group.

Equity Issuances - On December 28, 2023, we settled under forward contracts 1,032,403 shares (289,403 from forwards related to an at-the-market equity distribution agreement and 743,000 from forwards related to underwriting agreements) of our common stock for net proceeds of $79.0 million.

In December 2023, we amended the forward sale agreement we entered into in March 2023 to extend the maturity date of 657,000 shares to December 31, 2024 from December 29, 2023. The amended forward sale agreement provides for settlement on a date, or dates, to be specified at our discretion, but which will occur no later than December 31, 2024, for 1,257,000 shares of common stock.

In September 2023, we entered into an underwriting agreement and two forward sale agreements for 1.2 million and 180,000 shares of our common stock, respectively. The forward sale agreements provide for settlement on a date, or dates, to be specified at our discretion, but which will occur no later than December 31, 2024.

In June 2023, we executed forward sale agreements under our current at-the-market equity program for 926,465 shares of our common stock.

In March 2023, we entered into an underwriting agreement and a forward sale agreement for 2.0 million shares of our common stock. The forward sale agreement provided for settlement on a date, or dates, to be specified at our discretion, but which will occur no later than December 29, 2023, for 1.4 million shares of common stock and by December 31, 2024, for the remaining balance.

In February 2023, we entered into an at-the-market equity distribution agreement under which we may issue and sell shares of our common stock with an aggregate offering price up to $300 million. This at-the-market equity program replaced our previous at-the-market equity program, which began in February 2020, and expired in February 2023. 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. At December 31, 2023, we had $225.5 million of equity available for issuance under the program.

The following table summarizes all of our outstanding forward sale agreements at December 31, 2023:

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For the year ended December 31, 2022, under our at-the-market equity distribution agreement we sold and issued 403,792 shares of our common stock for $35.0 million, generating proceeds, net of issuance costs, of $34.7 million.

For the year ended December 31, 2022, we executed forward sale agreements under our previous at-the-market equity distribution agreement for 1,451,474 shares of our common stock. On December 30, 2022, we settled forward sales agreements with respect to 1,162,071 shares of our common stock for net proceeds of $93.8 million.

Pension and Other Postemployment Benefit Plans - For the year ended December 31,2023, we contributed $1.3 million to our defined benefit pension plans and $2.5 million to our other postemployment benefit plans. For the year ended December 31, 2022, we contributed $1.5 million to our defined benefit pension plans and $1.9 million to our other postemployment benefit plans. Additional information about our pension and other postemployment benefit plans, including anticipated contributions, is included under “Estimates and Critical Accounting Policies - Pension and Other Postemployment Benefits” and under Note 11 of the Notes to Consolidated Financial Statements in this Annual Report.

CASH FLOW ANALYSIS

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

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

Operating Cash Flows - Changes in cash flows from operating activities are due primarily to changes in sales revenues, natural gas costs and operating expenses discussed in “Financial Results and Operating Information,” the effects of Winter Storm Uri 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.

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Operating cash flows were lower in 2023, compared to 2022, due primarily to recovery of the winter weather event regulatory asset for Oklahoma Natural Gas through securitization beginning in August 2022, offset by the recovery of the winter weather event regulatory asset for Texas Gas Service through securitization in March 2023, and working capital changes related to accounts receivable which were impacted by new rates in 2023 compared with 2022.

Investing Cash Flows - Cash used in investing activities increased in 2023, compared to 2022, due primarily to an increase in capital expenditures for system integrity and extension of service to new areas.

Financing Cash Flows - Cash used in financing activities decreased in 2023, compared to 2022, due primarily to the repayment in August 2022 of long-term debt related to Winter Storm Uri.

ENVIRONMENTAL, SAFETY AND REGULATORY MATTERS

Environmental Matters - We are subject to multiple laws and regulations regarding protection of the environment and natural and cultural resources, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, plant and wildlife protection, hazardous materials use, storage and transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits or the discovery of presently unknown environmental conditions may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other regulatory or permitting mandates under the CAA and other similar federal and state laws could require unexpected capital expenditures. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during 2023, 2022 and 2021.

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 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. In 2022, we completed a remediation project to remove a source of contamination and contaminated materials at one of the MGP sites. In June 2023, we submitted a revised draft remediation plan to the KDHE for review following receipt of agency comments and public feedback. In August 2023, the KDHE approved the remediation plan without comment. We submitted a site investigation work plan for another site and on August 27, 2023 the KDHE approved the document without comment.

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, 2023 and 2022, we have deferred $32.0 million and $29.8 million, respectively, for accrued investigation and remediation costs pursuant to our AAO. Kansas Gas Service expects to file an application for amounts deferred in excess of the cap as soon as practicable after the KDHE approves the remediation plans we have submitted.

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We also own or retain legal responsibility for certain environmental conditions at a former MGP site in Texas. At the request of the TCEQ, we began investigating the level and extent of contamination associated with the site under their Texas Risk Reduction Program. A preliminary site investigation revealed that this site contains contaminants generally associated with MGP sites and is subject to control or remediation under various environmental laws and regulations. Impacts have been identified in the soil and groundwater at the site with limited impacts observed in surrounding areas. In April 2022, we submitted a remediation work plan to address the areas impacted to the TCEQ. In August 2023, remediation activities were conducted to address the impacted area in accordance with the remediation work plan. During the third quarter 2023, the TCEQ requested acceptable financial assurance for the projected costs on post-response action care activities at the site. At December 31, 2023, estimated costs associated with expected remediation activities for this site are not material.

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the years ended December 31, 2023 and 2022. The reserve for remediation of our MGP sites was $14.3 million and $12.7 million at December 31, 2023 and 2022, respectively.

Environmental Footprint - 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 2023, 2022 or 2021.

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 the Consolidated Appropriations Act, 2021, the PIPES Act 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.

Regulatory - Several regulatory initiatives impacted the earnings and future earnings potential of our business. See additional information regarding our regulatory initiatives in the “Regulatory Activities” section of 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, if any, is included in Note 1 of the Notes to Consolidated Financial Statements in this Annual Report.

CRITICAL ESTIMATES AND ACCOUNTING POLICIES

The preparation of our consolidated financial statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements. These estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.

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

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

For further discussion of regulatory assets and liabilities, see Note 3 of the Notes to Consolidated Financial Statements in this Annual Report.

Revenue Recognition - For regulated deliveries of natural gas, we read meters and bill customers on a monthly cycle. We recognize revenues upon the delivery of natural gas or services rendered to customers. The billing cycles for customers do not necessarily coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas that has been delivered but not yet billed at the end of an accounting period. Accrued unbilled revenue is based on a percentage estimate of amounts unbilled each month, which is dependent upon a number of factors, some of which require management’s judgment. These factors include customer consumption patterns and the impact of weather on usage. The accrued unbilled natural gas sales revenue at December 31, 2023 and 2022 was $191.4 million and $269.5 million, respectively, and is included in accounts receivable on our consolidated balance sheets.

We have determined the majority of our natural gas sales and transportation tariffs to be implied contracts with customers, which are settled over time, where our performance obligation is settled with our customer when natural gas is delivered and simultaneously consumed by the customer. In addition, we use the invoice method practical expedient, where we recognize revenue for volumes delivered for which we have a right to invoice. For our other utility revenue, which are primarily one-time service fees that meet the requirements under ASC 606, the performance obligation is satisfied at a point in time when services are rendered to the customer. Certain revenues that do not meet the requirements under ASC 606 as revenues from contracts with customers are reflected as other revenues in determining total revenue. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report for additional information regarding our revenues.

Pension and Other Postemployment Benefits - We have defined benefit pension plans covering eligible retirees and eligible 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, 2023, we contributed $1.3 million to our defined benefit pension plans and $2.5 million to our other postemployment benefit plans. For the year ended December 31, 2022, we contributed $1.5 million to our defined benefit pension plans and $1.9 million to our other postemployment benefit plans. In 2024, our contributions are expected to be $1.4 million to our defined benefit pension plans, and no contributions are expected to be made to our other postemployment benefit plans.

We recorded net periodic benefit credits for our defined benefit pension plans, prior to regulatory deferrals, of $7.5 million in 2023, and estimate that in 2024, we will record a credit of approximately $5.5 million. Net periodic benefits costs for our postemployment benefit plans, prior to regulatory deferrals, were $0.3 million in 2023, and we estimate that in 2024, we will record a credit of approximately $0.4 million, prior to regulatory deferrals.

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The following table sets forth the significant assumptions used to determine our estimated 2024 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.

See Note 11 of the Notes to Consolidated Financial Statements in this Annual Report for additional information regarding our pension and other postretirement benefit plans.

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

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effect on earnings or cash flows for the years ended December 31, 2023, 2022 and 2021. Environmental issues may exist with respect to these MGP sites that are unknown to us. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation required, changing technology and governmental regulations, and to the extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition, results of operations or cash flows.

See “Environmental Matters” and Note 15 of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of contingencies.

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 and other statements in this Annual Report regarding our environmental, social and other sustainability plans and goals are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current, and forward-looking environmental, social and sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future.

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.

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

•our ability to recover costs, income taxes and amounts equivalent to the cost of property, plant and equipment, regulatory assets and our allowed rate of return in our regulated rates or other recovery mechanisms;

•cyber-attacks, which, according to experts, continue to increase in volume and sophistication, or breaches of technology systems that could disrupt our operations or result in the loss or exposure of confidential or sensitive customer, employee, vendor, counterparty or Company information; further, increased remote working arrangements 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;

•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 which could significantly disrupt or prevent us from operating our business in the ordinary course for an extended period;

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

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

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

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

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

•operational and mechanical hazards or interruptions;

•adverse labor relations;

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

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

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

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

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

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

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

•changes in inflation and interest rates;

•our ability to recover the costs of natural gas purchased for our customers and any related financing required to support our purchase of natural gas supply;

•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;

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•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, cybersecurity and other laws or regulations 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 in Oklahoma, Kansas and Texas, and economic conditions in these areas;

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

•the sufficiency of insurance coverage to cover losses;

•the effects of our strategies to reduce tax payments;

•changes in accounting standards;

•changes in corporate governance standards;

•existence of material weaknesses in our internal controls;

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

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

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

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

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

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

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

EXECUTIVE SUMMARY

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

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

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

RECENT DEVELOPMENTS

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

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

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

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

In November 2022, we called the remaining $250 million of the $1.0 billion of 0.85 percent senior notes due March 2023 and $77 million of the $700 million of 1.10 percent senior notes due March 2024, using the proceeds from the securitization transaction for Kansas Gas Service.

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

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

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

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

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

REGULATORY ACTIVITIES

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

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

The proceeds received by Oklahoma Natural Gas were approximately $1.3 billion, which represents the amount of the securitization bonds issued by the ODFA less issuance costs. The receipt of these proceeds represents Oklahoma Natural Gas’ recovery of the approximately $1.3 billion of authorized extraordinary natural gas purchase costs and other operational costs incurred during Winter Storm Uri, as well as carrying costs. Beginning September 1, 2022, Oklahoma Natural Gas acts as a servicer, with responsibility for collecting the securitization charges from Oklahoma customers that are then submitted to the ODFA to repay the securitization bonds.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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FINANCIAL RESULTS AND OPERATING INFORMATION

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

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

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

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

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

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

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

•an increase of $58.7 million from new rates;

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

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

These increases were offset partially by:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

•11 weather stations and customers by month for Oklahoma;

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

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

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

CONTINGENCIES

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

LIQUIDITY AND CAPITAL RESOURCES

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

CASH FLOW ANALYSIS

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

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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 energy providers, could affect our earnings and operating cash flows. Typically, our cash flows from operations are greater in the first half of the year compared with the second half of the year.

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

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

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

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

ENVIRONMENTAL, SAFETY AND REGULATORY MATTERS

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

IMPACT OF NEW ACCOUNTING STANDARDS

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

CRITICAL ESTIMATES AND ACCOUNTING POLICIES

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

CONTRACTUAL OBLIGATIONS

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

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

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

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

FORWARD-LOOKING STATEMENTS

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

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

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

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

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

•our ability to manage our operations and maintenance costs;

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

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

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

commercial customers;

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

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

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

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

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

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

•operational and mechanical hazards or interruptions;

•adverse labor relations;

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

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

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

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

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

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

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

•changes in inflation and interest rates;

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

•impact of potential impairment charges;

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

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

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

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

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

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

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

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

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

•the sufficiency of insurance coverage to cover losses;

•the effects of our strategies to reduce tax payments;

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

•changes in accounting standards;

•changes in corporate governance standards;

•existence of material weaknesses in our internal controls;

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

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

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

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

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

ITEM 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.