ONE Gas (OGS) 10-Q2022 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

For the quarterly period ended March 31, 2022.

OR

☐ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from __________ to __________.

ONE Gas, Inc.

(Exact name of registrant as specified in its charter)

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

On April 25, 2022, the Company had 54,089,905 shares of common stock outstanding.

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ONE Gas, Inc.

TABLE OF CONTENTS

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

AVAILABLE INFORMATION

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

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

PART I - FINANCIAL INFORMATION

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ONE Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 three months ended March 31, 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.

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.

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. This guidance will apply to the anticipated securitizations in Oklahoma and Texas associated with Winter Storm Uri. 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.

In March 2020, the FASB issued ASU 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting,” which provides relief from the accounting analysis and impacts that may otherwise be required for modifications to agreements (e.g., loans, debt securities, derivatives, borrowings) necessitated by reference rate reform. It also provides optional expedients to enable companies to continue to apply hedge accounting to certain hedging relationships impacted by reference rate reform. In the first quarter 2020, we adopted this new guidance effective for contracts modified between March 12, 2020 and December 31, 2022. Our remaining $400 million of floating-rate senior notes due 2023 utilize LIBOR as the reference rate. If modified, we may elect the optional practical expedients to account for the modifications prospectively. Our adoption did not result in a material impact to our consolidated financial statements.

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

Accrued unbilled natural gas sales revenues at March 31, 2022 and December 31, 2021, were $148.0 million and $183.2 million, respectively, and are included in accounts receivable on our consolidated balance sheets.

3.    REGULATORY ASSETS AND LIABILITIES

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

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 rider, base rates, or securitization, and we believe that we will be able to recover such costs consistent with our historical recoveries.

our Kansas, Oklahoma, and Texas jurisdictions, which resulted in aggregated natural gas purchases for the month of February 2021 of approximately $2.1 billion.

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, Oklahoma Natural Gas submitted an initial application requesting a financing order pursuant to newly enacted 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 over a 25-year period. Following the issuance of the financing order, no parties to our application appealed the financing order to the Oklahoma Supreme Court during the 30-day appeal period. 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. Pursuant to the securitization statute in Oklahoma, the Oklahoma Supreme Court must validate that the bond issuance proposed by the ODFA complies with the securitization statute and the laws of Oklahoma. The ODFA received a hearing before the Oklahoma Supreme Court on April 13, 2022, seeking validation of the bond issuance. If the Oklahoma Supreme Court issues a ruling that validates the bond issuance by the ODFA complies with the Oklahoma securitization statute and the laws of Oklahoma, the ODFA will continue the process to issue the securitized bonds associated with the Oklahoma Natural Gas financing order. At March 31, 2022, Oklahoma Natural Gas has deferred approximately $1.3 billion in extraordinary costs attributable to Winter Storm Uri.

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 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. Any amounts collected from these penalties will reduce the regulatory asset for the winter weather event up to $52.6 million. Through April 29, 2022, we have collected $47.5 million of these penalties.

In July 2021, Kansas Gas Service submitted its financial plan to the KCC as required by the company-specific docket opened by the KCC in March 2021. The plan includes a proposal for the Company 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. The KCC issued an order approving a unanimous settlement agreement on February 8, 2022, that allows 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, by seeking a financing order from the KCC for the issuance of securitized utility tariff bonds. The extraordinary costs, other than purchased gas costs, will be trued-up and validated.

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 over 5, 7, 10 or 12 years. The KCC has until September 27, 2022, to review the application and issue a financing order if it deems the issuance of securitized bonds to be appropriate. If the KCC approves the financing order, we can begin the process to issue the securitized bonds. At March 31, 2022, Kansas Gas Service has deferred approximately $335.6 million in extraordinary costs, net of penalties billed, attributable to Winter Storm Uri.

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.

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. 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.

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, which by statute must be issued no later than August 7, 2022. At March 31, 2022, Texas Gas Service has deferred approximately $248.3 million in extraordinary costs associated with Winter Storm Uri, which includes $50.7 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.

In accordance with these regulatory orders associated with the winter weather event, we have deferred approximately $1.9 billion in extraordinary costs for natural gas purchases, related financing and carrying costs and other operational costs. The amounts deferred at March 31, 2022, 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 we have deferred are not expected to have a material impact on earnings.

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 the 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 for additional information regarding our regulatory assets for MGP remediation costs.

We have received accounting orders in each of our jurisdictions authorizing us to accumulate and defer for regulatory purposes certain incremental costs incurred, including bad debt expenses, and certain lost revenues, net of offsetting expense reductions associated with COVID-19. Pursuant to these orders, the recovery of any net incremental costs and lost revenues will be determined in future rate cases or alternative rate recovery filings in each jurisdiction. For financial reporting purposes, any amounts deferred as a regulatory asset for future recovery under these accounting orders must be probable of recovery. At March 31, 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.

Recovery through rates resulted in amortization of regulatory assets of approximately $4.4 million and $2.9 million for the three months ended March 31, 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 as administered by the Federal Reserve Bank of New York. 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 March 31, 2022, our total debt-to-capital ratio was 63 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 March 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, 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 March 31, 2022, we had $505.2 million of commercial paper outstanding.

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.

In the event LIBOR is not available, and such circumstances are unlikely to be temporary, we or our designee may establish an alternative interest rate for our floating-rate senior notes due March 2023 by replacing LIBOR with one or more secured financing-based rates or another alternate benchmark rate.

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. As discussed in Note 3, the OCC and RRC have authorized financing orders and the KCC has authorized a financial plan for the recovery of the extraordinary costs incurred, including any future carrying costs, by Oklahoma Natural Gas, Texas Gas Service (excluding the West Texas service area) and Kansas Gas Service, respectively, through the issuance of securitized bonds. We anticipate securitized bonds will be issued in Oklahoma and Texas in 2022 and in Kansas in 2023. We expect to use these proceeds to call the outstanding senior notes due in March 2023 and March 2024, and use our commercial paper program to call any remaining notes.

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.

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

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, 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:

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

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 applicable regulatory authorities. Regulatory deferrals related to net periodic benefit cost were not material for the three months ended March 31, 2022 and 2021, respectively.

We continue to 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 $5.8 million and $6.1 million as of March 31, 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.

As of March 31, 2022, we have no uncertain tax positions. Changes in tax laws or tax rates are recognized in the financial reporting period that includes the enactment date. We are no longer subject to income tax examination for years prior to 2018.

crediting mechanism for the EDIT regulatory liability, will be addressed during the processing of the March 15, 2022 PBRC filing.

Income tax expense reflects credits for the amortization of the regulatory liability associated with EDIT that was returned to customers of $7.9 million and $8.1 million for the three months ended March 31, 2022 and 2021, respectively.

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

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 5 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 March 31, 2022, we have deferred $30.0 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 7 of the 12 sites according to plans approved by the KDHE. In 2019, we completed a project to remove a source of contamination and associated contaminated materials at the twelfth site where no active soil remediation had previously occurred. A remediation plan concerning this site was submitted to the KDHE in 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 2022.

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 March 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 three months ended March 31, 2022 and 2021. The reserve for remediation of our MGP sites was $20.3 million and $23.0 million at March 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.

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:

On October 1, 2019, PHMSA published the first of the three final rules referenced above, which addressed the 2011 congressional mandates. This final rule expands integrity management principles beyond HCAs and requires operators to collect traceable, verifiable and complete records moving forward, retain existing and new records for the life of the pipeline, and reconfirm pipeline MAOP in populated areas. The final rule also outlines methods for reconfirming a pipeline’s MAOP

within 15 years. The first final rule became effective July 1, 2020. Our estimated capital and operating expenditures associated with compliance with the first final rulemaking were not material.

PHMSA has not yet issued the second final rule. The potential capital and operating expenditures associated with compliance with this rule are currently being evaluated and could be significant depending on the final regulation. We do not expect to be impacted by the third final rule, as we do not own gas gathering pipelines.

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

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:

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.

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 $3.7 billion at March 31, 2022 and December 31, 2021. The estimated fair value of our long-term debt, including current maturities, was $3.7 billion and $3.9 billion at March 31, 2022 and December 31, 2021, respectively. The estimated fair value of our long-term debt was determined using quoted market prices, and is classified as Level 2.

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and the Notes to Consolidated Financial Statements in this Quarterly Report, as well as our Annual Report. Due to the seasonal nature of our business, the results of operations for the three months ended March 31, 2022 are not necessarily indicative of the results that may be expected for a 12-month period.

RECENT DEVELOPMENTS

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.

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 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 (1.41 percent at March 31, 2022). 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. The net proceeds of the March 2021 debt issuance reduced the commitments under the ONE Gas 2021 Term Loan Facility on a dollar-for-dollar basis, and as a result no commitments remained outstanding and the facility was terminated concurrently with the closing of the debt issuance.

On September 21, 2021, we called $400 million of the floating-rate senior notes due 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.

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 March 31, 2022, we have deferred approximately $1.9 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,” and Note 3 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion of the effects of Winter Storm Uri on us.

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.

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 March 31, 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.

See Notes 3 and 12 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion regarding the effects of COVID-19 on us.

REGULATORY ACTIVITIES

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. On March 15, 2022, Oklahoma Natural Gas filed its required PBRC application for a calendar year 2021 test year. The filed request includes 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. A hearing is scheduled for August 4, 2022.

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 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. The approved order also states that Oklahoma Natural Gas may recover commodity

costs of no more than $5.0 million annually for the purchase of RNG and that Oklahoma Natural Gas shall file an application on or before December 31, 2022, requesting approval of an RNG pilot program including an “opt-in” tariff allowing Oklahoma Natural Gas to allocate costs and benefits of RNG to those customers who choose RNG for their fuel source.

In May 2021, a bill amending the Oklahoma state income tax code was signed into law that reduced the state income tax rate to four percent from six percent beginning January 1, 2022. As a result of the enactment of this legislation, we remeasured our ADIT. As a regulated entity, the reduction in ADIT of $29.3 million was recorded as a regulatory liability. The impact of the change in the state income tax rate on Oklahoma Natural Gas’ rates was included in the general rate case previously discussed. The impact on the annual crediting mechanism for the EDIT regulatory liability, will be addressed during the processing of the March 15, 2022 PBRC filing.

In 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. Any amounts collected from these penalties will reduce the regulatory asset for the winter weather event up to $52.6 million. Through April 29, 2022, we collected $47.5 million of these penalties.

In July 2021, Kansas Gas Service submitted its financial plan to the KCC as required by the company-specific docket opened by the KCC in March 2021. The plan includes a proposal for the Company 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. The KCC issued an order approving a unanimous settlement agreement on February 8, 2022, that allows 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, by seeking a financing order from the KCC for the issuance of securitized utility tariff bonds. The extraordinary costs, other than purchased gas costs, will be trued-up and validated.

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 over 5, 7, 10 or 12 years. The KCC has until September 27, 2022, to review the application and issue a financing order if it deems the issuance of securitized bonds to be appropriate. If the KCC approves the financing order, we can begin the process to issue the securitized bonds. At March 31, 2022, Kansas Gas Service has deferred approximately $335.6 million in extraordinary costs, net of penalties billed, attributable to Winter Storm Uri.

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 three months ended March 31, 2022. 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 3 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.

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. 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.

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, which by statute must be issued no later than August 7, 2022. At March 31, 2022, Texas Gas Service has deferred approximately $248.3 million in extraordinary costs associated with Winter Storm Uri, which includes $50.7 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.

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. On June 21, 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. On July 2, 2021, Texas Gas Service appealed the city’s action to the RRC. The RRC granted and approved the appeal, and new rates were effective on August 3, 2021. All other municipalities, and the RRC, approved the new rates or allowed them to take effect with no action.

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

In 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 three months ended March 31, 2022, no annual rate increases associated with these filings have been approved and $0.4 million were approved for the year ended December 31, 2021.

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 we have deferred are not expected to have a material impact on earnings.

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. The accounting policies for our segment are the same as described in Note 1 of our Notes to Consolidated Financial Statements in our Annual Report. 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 the regulatory authorities, as well as revenues from regulatory mechanisms related to natural gas sales. Additionally, natural gas sales includes the recovery of our cost of natural gas.

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 the regulatory authorities, as well as tariff-based negotiated contracts.

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

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

Operating income increased $10.5 million for the three months ended March 31, 2022, compared with the same period last year, due primarily to the following:

These increases were offset partially by:

EDIT - For the three months ended March 31, 2022 and 2021, we credited income tax expense $7.9 million and $8.1 million, respectively, for the amortization of the regulatory liability associated with EDIT that was returned to customers.