Published: 2022-11-01 00:00:00 ET

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Our accompanying unaudited consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. These statements also have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair statement of the results for the interim periods presented. All such adjustments are of a normal recurring nature. The 2021 year-end consolidated balance sheet data was derived from audited consolidated financial statements but does not include all disclosures required by GAAP. These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and footnotes in our Annual Report. Our significant accounting policies are described in Note 1 of our Notes to Consolidated Financial Statements in our Annual Report. Due to the seasonal nature of our business, the results of operations for the nine months ended September 30, 2022, are not necessarily indicative of the results that may be expected for a 12-month period.

We provide natural gas distribution services to our approximately 2.3 million customers through our divisions in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. We primarily serve residential, commercial and transportation customers in all three states.

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

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

Segments - We operate in one reportable business segment: regulated public utilities that deliver natural gas primarily to residential, commercial and transportation customers. The accounting policies for our segment are the same as those described in Note 1 of our Notes to Consolidated Financial Statements in our Annual Report. We evaluate our financial performance principally on net income. For the three and nine months ended September 30, 2022 and 2021, we had no single external customer from which we received 10 percent or more of our gross revenues.

Property, Plant and Equipment and Asset Removal Costs - Accounts payable for construction work in process and asset removal costs decreased by approximately $4.0 million and $7.5 million for the nine months ended September 30, 2022 and 2021, respectively. Such amounts are not included in capital expenditures or asset removal costs in our consolidated statements of cash flows.

Goodwill Impairment Test – We assess our goodwill for impairment at least annually on July 1, unless events or changes in circumstances indicate an impairment may have occurred before that time. As part of our goodwill impairment test, we may first assess qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance) to determine whether it is more likely than not that the fair value of our reporting unit is less than its carrying amount. If further testing is necessary or a quantitative test is elected to refresh our recurring qualitative assessments, we perform a quantitative impairment test for goodwill. We did not identify any impairment indicators for our goodwill and determined that no further testing was necessary.

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

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gas costs related to accounts written off when they are deemed uncollectible through the purchased-gas cost adjustment mechanisms in each of our jurisdictions. At September 30, 2022 and December 31, 2021, our allowance for doubtful accounts was $15.6 million and $18.7 million, respectively.

Recently Issued Accounting Standards Update - In November 2021, the FASB issued ASU 2021-10, “Government Assistance (Topic 832): Disclosures by Business Entities about Government Assistance,” which will require disclosure about government assistance in the notes to the financial statements. The amendment requires annual disclosures about transactions with a government that are accounted for by applying a grant or contribution accounting model by analogy, including information about the nature of the transactions and the related accounting policy used to account for the transactions, the line items on the balance sheet and income statement that are affected by the transactions and the significant terms and conditions of the transactions, including commitments and contingencies. The amendment became effective for us beginning January 1, 2022. As the guidance is related only to disclosures in the notes to the financial statements, we do not anticipate any impact on our financial position, results of operations or cash flows. See Note 3 for additional discussion regarding our transaction in Oklahoma with the government that is accounted for by applying a grant accounting model by analogy.

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

						Three Months Ended												Nine Months Ended
						September 30,												September 30,
						2022						2021						2022						2021
						(Thousands of dollars)
Natural gas sales to customers						$	322,444					$	240,591					$	1,640,893					$	1,105,835
Transportation revenues						28,035						25,342						92,350						87,760
Miscellaneous revenues						4,991						4,363						14,615						12,091
Total revenues from contracts with customers						355,470						270,296						1,747,858						1,205,686
Other revenues - natural gas sales related						427						545						2,658						849
Other revenues						3,466						3,082						9,281						8,327
Total other revenues						3,893						3,627						11,939						9,176
Total revenues						$	359,363					$	273,923					$	1,759,797					$	1,214,862

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

						September 30, 2022
						Current						Noncurrent						Total
						(Thousands of dollars)
Winter weather event costs						$	243,232					$	342,997					$	586,229
Under-recovered purchased-gas costs						28,193						—						28,193
Pension and postemployment benefit costs						4,010						245,637						249,647
Reacquired debt costs						811						3,528						4,339
MGP remediation costs						98						29,767						29,865
Ad-valorem tax						12,779						—						12,779
WNA						10,555						—						10,555
Customer credit deferrals						14,595						—						14,595
Other						1,858						2,555						4,413
Total regulatory assets, net of amortization						316,131						624,484						940,615
Income tax rate changes						—						(536,612)						(536,612)
Over-recovered purchased-gas costs						(38,171)						—						(38,171)
Total regulatory liabilities						(38,171)						(536,612)						(574,783)
Net regulatory assets and liabilities						$	277,960					$	87,872					$	365,832

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

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

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

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

In April 2021, Oklahoma Natural Gas submitted an initial application requesting a financing order pursuant to the securitization legislation in Oklahoma. On January 25, 2022, the OCC approved the financing order that reflected the terms of a settlement agreement reached in November 2021, which includes an agreement that all extreme gas purchase and extraordinary costs incurred as a result of Winter Storm Uri were reasonable and prudent and a financing order should be issued to recover these costs through securitization. Pursuant to the securitization statute in Oklahoma, the Oklahoma Supreme Court validated that the bond issuance proposed by the ODFA complied with the securitization statute and the laws of Oklahoma in May 2022.

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 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 from the ODFA were approximately $1.3 billion, which represents the amount of the securitization bonds issued less issuance costs. The receipt of these proceeds represents Oklahoma Natural Gas’ recovery of the approximately $1.3 billion of authorized extraordinary natural gas purchase costs and other operational costs incurred during Winter Storm Uri, as well as carrying costs. GAAP does not provide comprehensive recognition and

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measurement guidance for many forms of government assistance received by business entities. Accordingly, we have accounted for the proceeds received from the ODFA by analogy to International Accounting Standards No. 20, “Accounting for Government Grants and Disclosure of Government Assistance” consistent with a grant related to income. The proceeds received and the corresponding recognition of the deferred regulatory asset have been reflected in cost of natural gas in our Consolidated Statements of Income. As the proceeds reflect the recovery of our winter weather event regulatory asset, there was no material impact to earnings. Beginning September 1, 2022, Oklahoma Natural Gas will act as a servicer, with responsibility for collecting the securitization charges from Oklahoma customers that are then submitted to the ODFA to repay the securitization bonds. The collection and remittance of these funds on behalf of the ODFA are recorded in other current liabilities in our consolidated balance sheets.

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 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 unanimous settlement, the carrying charge on assessed penalties was reduced to two percent, consistent with the nonunanimous agreement in the financial docket. On March 3, 2022, the KCC issued an order approving the settlement which modified the penalty provisions of Kansas Gas Service’s tariffs and included a carrying charge of two percent on amounts due to Kansas Gas Service. Amounts collected from these penalties will reduce the regulatory asset for the winter weather event, up to $52.6 million. Through September 30, 2022, we have collected $49.4 million of these penalties.

In July 2021, Kansas Gas Service submitted its financial plan to the KCC as required by the company-specific docket opened by the KCC in March 2021. The plan includes a proposal for a newly formed, bankruptcy remote subsidiary of the Company to issue securitized bonds to recover the extraordinary costs resulting from Winter Storm Uri from Kansas Gas Service’s customers. On February 8, 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.

On March 31, 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 bonds to recover extraordinary costs resulting from Winter Storm Uri and flexibility to recover the costs. On July 14, 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 the amount of approximately $328.0 million plus issuance fees. The final amount to be securitized will be provided in the final issuance advice letter. The agreement provides for the issuance of bonds with a scheduled final maturity of between 7 and 10 years with flexibility within that range, if necessary, to achieve a AAA rating. On August 18, 2022, the KCC issued an order approving the agreement and also issued a financing order.

As part of the settlement agreement, 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 bonds. After the SEC declares the registration statement effective, KGSS-I expects to begin the process to issue the bonds.

At September 30, 2022, Kansas Gas Service has deferred approximately $339.6 million in extraordinary costs, net of penalties billed, attributable to Winter Storm Uri. The amount deferred at September 30, 2022, in excess of the amount securitized, primarily includes accrued costs for natural gas purchases that have not been paid as we work with our suppliers to resolve discrepancies in invoiced amounts. These amounts will be recovered through our purchased gas cost mechanisms or other regulatory filings and may be adjusted as the differences are resolved.

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 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.

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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.

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, that will issue the securitized bonds, which are expected to be issued in the fourth quarter of 2022. At September 30, 2022, Texas Gas Service has deferred approximately $246.7 million in extraordinary costs associated with Winter Storm Uri, which includes $47.8 million attributable to the 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 West Texas service area from those customers.

General - In accordance with these regulatory orders associated with the winter weather event, our regulatory asset totaled approximately $586.2 million in extraordinary costs for natural gas purchases, related financing and carrying costs and other operational costs that have not been recovered at September 30, 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. In addition, as a result of Winter Storm Uri, we were assessed penalties as a result of over- or under-deliveries of natural gas during periods that operational flow orders were imposed on us. Additionally, Kansas Gas Service assessed penalties under the modified penalty provisions of its tariff on marketers and individually-balanced transportation customers, or their agents, as approved by the KCC in March 2022. Amounts recorded reflect management’s best estimate of the amounts we may pay or receive and may be adjusted in future periods as the disposition of disputed invoices and the collectability of such penalties is determined. As these amounts are related to the extraordinary gas purchase costs associated with Winter Storm Uri, which are deferred, future adjustments to the amounts deferred are not expected to have a material impact on earnings.

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

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

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

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

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

The customer credit deferrals and the noncurrent regulatory liability for income tax rate changes represents deferral of the effects of enacted federal and state income tax rate changes on our ADIT and the effects of these changes on our rates. See Note 10 for additional information regarding the impact of income tax rate changes.

See Note 12 and “Environmental, Safety and Regulatory Matters” in Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information regarding our regulatory assets for MGP remediation costs.

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We have received accounting orders in each of our jurisdictions authorizing us to accumulate and defer for regulatory purposes certain incremental costs incurred, including bad debt expenses, and certain lost revenues, net of offsetting expense reductions associated with COVID-19. Pursuant to these orders, the recovery of any net incremental costs and lost revenues will be determined in future rate cases or alternative rate recovery filings in each jurisdiction. For financial reporting purposes, any amounts deferred as a regulatory asset for future recovery under these accounting orders must be probable of recovery. At September 30, 2022, 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 new rates that became effective in November 2021. In addition, annual PBRC filings, including the PBRC filing made in March 2022, 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.

Recoveries of regulatory assets through rates were not material for the three months ended September 30, 2022 and 2021, respectively. Recovery through rates resulted in amortization of regulatory assets of approximately $6.9 million and $4.4 million for the nine months ended September 30, 2022 and 2021, respectively.

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 September 30, 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.

At September 30, 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, which is available to repay any of our commercial paper borrowings.

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 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 September 30, 2022 and December 31, 2021, we had $423.4 million and $494.0 million of commercial paper outstanding with a weighted-average interest rate of 3.53 percent and 0.38 percent, respectively.

In connection with the second amendment and restatement of the ONE Gas Credit Agreement on March 16, 2021, all commitments under our ONE Gas 364-day Credit Agreement, dated as of April 7, 2020, were terminated and all obligations under the ONE Gas 364-day Credit Agreement were paid in full and discharged.

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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.

On August 25, 2022, we called $750 million of the $1.0 billion of 0.85 percent senior notes due March 2023, $150 million of the $700 million of 1.10 percent senior notes due March 2024 and the remaining $400 million of outstanding floating-rate senior notes due March 2023, using the proceeds received from the securitization transaction for Oklahoma Natural Gas. See Note 3 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion of the securitization transaction. We expect to use the proceeds from the issuance of securitized bonds in Kansas and Texas, as discussed in Note 3, to call the outstanding senior notes due March 2023 and a portion of the senior notes due March 2024.

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.

ONE Gas 2021 Term Loan Facility - 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-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 nine months ended September 30, 2022 and 2021, we issued and sold 403,792 shares and 281,124 shares of our common stock for $35.0 million and $21.4 million, generating proceeds, net of issuance costs, of $34.7 million and $21.1 million, respectively.

For the nine months ended September 30, 2022, we executed forward sale agreements for shares of our common stock. No shares of common stock have been settled under these forward sale agreements. Had we settled all shares under the forward agreements as of September 30, 2022, we would have generated net proceeds of $93.9 million, as detailed below:

Maturity			Shares Available			Net Proceeds Available (in thousands)			Forward Price
September 29, 2023			570,335			$	45,890		$	80.46
January 2, 2024			591,736			48,052			81.21
Total			1,162,071			$	93,942		$	80.84

At September 30, 2022, we had $85.1 million of equity available for issuance under the program.

Dividends Declared - In October 2022, we declared a dividend of $0.62 per share ($2.48 per share on an annualized basis) for shareholders of record as of November 15, 2022, payable on December 1, 2022.

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

						Three Months Ended									Nine Months Ended									Affected Line Item in the
Details About Accumulated Other						September 30,									September 30,									Consolidated Statements
Comprehensive Loss Components						2022			2021						2022			2021						of Income
						(Thousands of dollars)
Pension and other postemployment benefit plan obligations (a)
Amortization of net loss						$	2,278		$	11,474					$	14,731		$	34,422
Amortization of unrecognized prior service cost (credit)						103			(70)						185			(210)
						2,381			11,404						14,916			34,212
Regulatory adjustments (b)						(2,365)			(11,013)						(14,772)			(33,040)
						16			391						144			1,172						Income before income taxes
						(4)			(91)						(33)			(273)						Income tax expense
Total reclassifications for the period						$	12		$	300					$	111		$	899					Net income

(a) These components of accumulated other comprehensive loss are included in the computation of net periodic benefit cost. See Note 9 for additional detail of our net periodic benefit cost.

(b) Regulatory adjustments represent pension and other postemployment benefit costs expected to be recovered through rates and are deferred as part of our regulatory assets. See Note 3 for additional disclosures of regulatory assets and liabilities.

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

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

			Three Months Ended September 30, 2022
			Income						Shares						Per Share Amount
			(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock			$	23,701					54,310						$	0.44
Diluted EPS Calculation
Effect of dilutive securities			—						172
Net income available for common stock and common stock equivalents			$	23,701					54,482						$	0.44

			Three Months Ended September 30, 2021
			Income						Shares						Per Share Amount
			(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock			$	20,253					53,710						$	0.38
Diluted EPS Calculation
Effect of dilutive securities			—						83
Net income available for common stock and common stock equivalents			$	20,253					53,793						$	0.38

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			Nine Months Ended September 30, 2022
			Income						Shares						Per Share Amount
			(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock			$	154,710					54,164						$	2.86
Diluted EPS Calculation
Effect of dilutive securities			—						118
Net income available for common stock and common stock equivalents			$	154,710					54,282						$	2.85

			Nine Months Ended September 30, 2021
			Income						Shares						Per Share Amount
			(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock			$	145,922					53,516						$	2.73
Diluted EPS Calculation
Effect of dilutive securities			—						102
Net income available for common stock and common stock equivalents			$	145,922					53,618						$	2.72

The following tables set forth the components of net periodic benefit cost for our pension and other postemployment benefit plans for the periods indicated:

			Pension Benefits
			Three Months Ended									Nine Months Ended
			September 30,									September 30,
			2022			2021						2022			2021
			(Thousands of dollars)
Components of net periodic benefit cost (credit)
Service cost			$	2,341		$	3,453					$	8,027		$	10,359
Interest cost			9,654			7,365						26,495			22,095
Expected return on assets			(14,642)			(15,596)						(43,887)			(46,788)
Amortization of unrecognized prior service cost			93			—						155			—
Amortization of net loss			2,224			11,381						14,569			34,143
Net periodic benefit cost (credit)			$	(330)		$	6,603					$	5,359		$	19,809

			Other Postemployment Benefits
			Three Months Ended									Nine Months Ended
			September 30,									September 30,
			2022			2021						2022			2021
			(Thousands of dollars)
Components of net periodic benefit cost (credit)
Service cost			$	318		$	397					$	954		$	1,191
Interest cost			1,612			1,563						4,836			4,689
Expected return on assets			(3,295)			(4,202)						(9,885)			(12,606)
Amortization of unrecognized prior service cost (credit)			10			(70)						30			(210)
Amortization of net loss			54			93						162			279
Net periodic benefit cost (credit)			$	(1,301)		$	(2,219)					$	(3,903)		$	(6,657)

We recover qualified pension benefit plan and other postemployment benefit plan costs through rates charged to our customers. Certain regulatory authorities require that the recovery of these costs be based on specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as authorized by the

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applicable regulatory authorities. For the nine months ended September 30, 2022, regulatory deferrals related to net periodic benefit cost were $3.4 million. For the nine months ended September 30, 2021, regulatory deferrals related to net periodic benefit cost were not material.

We use a December 31 measurement date for our plans. On April 30, 2022, we amended our defined benefit pension plans to change the variable cost of living adjustment for eligible participants to a fixed rate. Accordingly, we remeasured our net benefit obligations as of April 30, 2022, resulting in an adjustment of approximately $7.2 million to our pension expense, net of capitalization and regulatory deferrals, for the year ending December 31, 2022, beginning May 1, 2022.

We capitalize all eligible service cost and non-service cost components under the accounting requirements of ASC Topic 980 (Regulated Operations) for rate-regulated entities. Our consolidated balance sheets reflect the capitalized non-service cost components as a regulatory asset in the amount of $4.0 million and $6.1 million at September 30, 2022 and December 31, 2021, respectively. See Note 3 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.

We use an estimated annual effective tax rate for purposes of determining the income tax provision during interim reporting periods. In calculating our estimated annual effective tax rate, we consider forecasted annual pre-tax income and estimated permanent book versus tax differences, as well as tax credits. Adjustments to the effective tax rate and estimates will occur as information and assumptions change.

At September 30, 2022, we have no uncertain tax positions. Changes in tax laws or tax rates are recognized in the financial reporting period that includes the enactment date. We are no longer subject to income tax examination for years prior to 2019.

In August 2022, the IRA of 2022 was signed into law. Based upon our review of the legislation, we do not expect it to have any material impacts to our Company.

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, which is pending approval by the OCC.

Income tax expense reflects credits for the amortization of the regulatory liability associated with EDIT that was returned to customers of $1.6 million and $1.5 million for the three months ended September 30, 2022 and 2021, respectively, and credits of $12.5 million and $12.2 million for the nine months ended September 30, 2022 and 2021, respectively.

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

						Three Months Ended												Nine Months Ended
						September 30,												September 30,
						2022						2021						2022						2021
						(Thousands of dollars)
Net periodic benefit (cost) credit other than service cost						$	1,430					$	(1,069)					$	2,209					$	(2,844)
Earnings (losses) on investments associated with nonqualified employee benefit plans						(1,789)						(267)						(9,241)						2,232
Other, net						1,152						(469)						(303)						(1,146)
Total other income (expense), net						$	793					$	(1,805)					$	(7,335)					$	(1,758)

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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 the three and nine months ended September 30, 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 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 September 30, 2022, we have deferred $29.9 million for accrued investigation and remediation costs pursuant to our AAO. Kansas Gas Service expects to file an application as soon as practicable after the KDHE approves the plans we have submitted and anticipates that filing will occur in 2023.

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 an additional site that we expect to submit to the KDHE in 2023.

We also own or retain legal responsibility for certain environmental conditions at a former MGP site in Texas. At the request of the TCEQ, we began investigating the level and extent of contamination associated with the site under their Texas Risk Reduction Program. A preliminary site investigation revealed that this site contains contaminants generally associated with MGP sites and is subject to control or remediation under various environmental laws and regulations. Impacts have been identified in the soil and groundwater at the site with limited impacts observed in surrounding areas. On April 14, 2022, we submitted a remediation work plan to address the areas impacted to the TCEQ. At September 30, 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 three and nine months ended September 30, 2022 and 2021. The reserve for remediation of our MGP sites was $13.2 million and $22.8 million at September 30, 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.

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

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

As part of regulating pipeline safety, PHMSA promulgates various regulations. For example, in April 2016, PHMSA published a NPRM, the Safety of Gas Transmission & Gathering Lines Rule, in the Federal Register to revise pipeline safety regulations applicable to the safety of onshore natural gas transmission and gathering pipelines. Proposals included changes to pipeline integrity management requirements and other safety-related requirements. Subsequently, PHMSA announced they would split this NPRM into three separate final rulemakings:

•the first final rule addresses the legislative mandates from the Pipeline Safety, Regulatory Certainty and Job Creation Act and is called the Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments;

•the second final rule is called the Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments and will cover all remaining elements of the NPRM (except for gas gathering pipelines); and

•the third final rule is called the Safety of Gas Gathering Pipelines and will address gas gathering pipelines.

On October 1, 2019, PHMSA published the first of the three final rules referenced above, which addressed the 2011 congressional mandates. This final rule expands integrity management principles beyond HCAs and requires operators to collect traceable, verifiable and complete records moving forward, retain existing and new records for the life of the pipeline, and reconfirm pipeline MAOP in populated areas. The final rule also outlines methods for reconfirming a pipeline’s MAOP within 15 years. The first final rule became effective July 1, 2020. Our estimated capital and operating expenditures associated with compliance with the first final rulemaking were not material.

On August 24, 2022, PHMSA published the second final rule in the Federal Register. The potential capital and operating expenditures associated with compliance with this rule are currently being evaluated. The third final rule has also been issued, but we are not impacted by it as we do not own gas gathering pipelines.

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

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

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

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

Recognition and Measurement

Accounting Treatment

Balance Sheet

Income Statement

Normal purchases and normal sales

-

Fair value not recorded

-

Change in fair value not recognized in earnings

Mark-to-market

-

Recorded at fair value

-

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

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

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

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

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

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

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

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

Derivative Instruments - At September 30, 2022, we held purchased natural gas call options for the heating season ending March 2023, with total notional amounts of 17.4 Bcf, for which we paid premiums of $27.1 million, and which had a fair value of $3.5 million. At December 31, 2021, we held purchased natural gas call options for the heating season ended March 2022, with total notional amounts of 13.2 Bcf, for which we paid premiums of $9.5 million, and which had a fair value of $2.3 million. These contracts are included in, and recoverable through, our purchased-gas cost adjustment mechanisms. Additionally, premiums paid, changes in fair value and any settlements received associated with these contracts are deferred as part of our unrecovered purchased-gas costs in our consolidated balance sheets. Our natural gas call options are classified as Level 1, as fair value amounts are based on unadjusted quoted prices in active markets including settled prices on the New York Mercantile Exchange. There were no transfers between levels for the periods presented.

Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable and accounts payable is equal to book value, due to the short-term nature of these items. Our cash and cash equivalents are comprised of bank and money market accounts and are classified as Level 1. At September 30, 2022 and December 31, 2021, our other current and noncurrent assets included $7.1 million and $6.9 million of corporate bonds, respectively, and $2.4 million and $3.5 million of United States treasury notes, respectively. The fair value of corporate bonds and United States treasury notes approximate carrying value, and are classified as Level 2 and Level 1, respectively.

Commercial paper is due upon demand and, therefore, the carrying amounts approximate fair value and are classified as Level 1. The book value of our long-term debt, including current maturities, was $2.7 billion and $3.7 billion at September 30, 2022 and December 31, 2021, respectively. The estimated fair value of our long-term debt, including current maturities, was

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