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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 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.3003.616004.6584004.50The indenture governing our Senior Notes includes an event of default upon the acceleration of other indebtedness of $100 million or more. 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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended March 31, 2021.
OR
Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from __________ to __________.

Commission file number  001-36108

ONE Gas, Inc.
(Exact name of registrant as specified in its charter)
Oklahoma46-3561936
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer Identification No.)
  
15 East Fifth Street
Tulsa,OK74103
(Address of principal
executive offices)
(Zip Code)

Registrant’s telephone number, including area code   (918) 947-7000

Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading SymbolName of exchange on which registered
Common Stock, par value $0.01 per shareOGSNew York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes No ☐

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.
Large accelerated filerAccelerated filer
Non-accelerated filerSmaller reporting company
Emerging growth company

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. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes        No  

On April 26, 2021, the Company had 53,245,144 shares of common stock outstanding.





























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ONE Gas, Inc.
TABLE OF CONTENTS
Part I.
Financial InformationPage No.
Item 1.
Consolidated Financial Statements (Unaudited)
 Consolidated Statements of Income - Three Months Ended March 31, 2021 and 2020
 Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2021 and 2020
 Consolidated Balance Sheets - March 31, 2021 and December 31, 2020
 Consolidated Statements of Cash Flows - Three Months Ended March 31, 2021 and 2020
 Consolidated Statements of Equity - Three Months Ended March 31, 2021 and 2020
 Notes to Consolidated Financial Statements
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
Item 4.
Controls and Procedures
Part II.
Other Information
Item 1.
Legal Proceedings
Item 1A.
Risk Factors
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
Item 3.
Defaults Upon Senior Securities
Item 4.
Mine Safety Disclosures
Item 5.
Other Information
Item 6.
Exhibits
Signature
 

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.

The statements in this Quarterly Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled,” “likely,” and other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that such expectations or assumptions will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Forward-Looking Statements,” and Part II, Item 1A, “Risk Factors” in this Quarterly Report and under Part I, Item IA, “Risk Factors,” in our Annual Report.

3


AVAILABLE INFORMATION

We make available, free of charge, on our website (www.onegas.com) copies of our Annual Report, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC, which also makes these materials available on its website (www.sec.gov). Copies of 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 Sustainability 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 or posted on or disseminated through our social media accounts is not incorporated by reference into this report.


4


GLOSSARY - The abbreviations, acronyms and industry terminology used in this Quarterly Report are defined as follows:
AAOAccounting Authority Order
ADITAccumulated deferred income tax
Annual ReportAnnual Report on Form 10-K for the year ended December 31, 2020
ASCAccounting Standards Codification
ASUAccounting Standards Update
BcfBillion cubic feet
CERCLAFederal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
Clean Air ActFederal Clean Air Act, as amended
Clean Water ActFederal Water Pollution Control Amendments of 1972, as amended
CodeInternal Revenue Code of 1986, as amended
COVID-19Coronavirus Disease 2019
DOTUnited States Department of Transportation
EDITExcess accumulated deferred income taxes resulting from a change in enacted tax rates
EPAUnited States Environmental Protection Agency
EPSEarnings per share
Exchange ActSecurities Exchange Act of 1934, as amended
FASBFinancial Accounting Standards Board
GAAPAccounting principles generally accepted in the United States of America
GPACGas Pipeline Advisory Committee
GRIPGas Reliability Infrastructure Program
GSRSGas System Reliability Surcharge
Heating Degree Day or HDD
A measure designed to reflect the demand for energy needed for heating based on the extent to which
  the daily average temperature falls below a reference temperature for which no heating is required,
  usually 65 degrees Fahrenheit
HCA(s)High consequence area(s)
KCCKansas Corporation Commission
KDHEKansas Department of Health and Environment
LDCLocal distribution company
LIBORLondon Interbank Offered Rate
MAOP(s)Maximum allowable operating pressure(s)
MGPManufactured gas plant
MMcfMillion cubic feet
Moody’sMoody’s Investors Service, Inc.
Net marginNon-GAAP measure defined as total revenues less cost of natural gas
NPRMNotice of Proposed Rulemaking
NYSENew York Stock Exchange
OCCOklahoma Corporation Commission
ONE GasONE Gas, Inc.
ONE Gas 2021 Term Loan FacilityONE Gas’ $2.5 billion two-year unsecured term loan facility, dated February 22, 2021, which terminated on March 11, 2021
ONE Gas 364-day Credit AgreementONE Gas’ $250 million 364-day revolving credit agreement, dated April 7, 2020, which terminated on March 16, 2021
ONE Gas Credit AgreementONE Gas’ $1 billion second amended and restated revolving credit agreement, which expires on March 16, 2026
ONE Gas 2017 Credit AgreementONE Gas’ $700 million amended and restated revolving credit agreement, dated October 5, 2017, which was     amended and restated on March 16, 2021
PBRCPerformance-Based Rate Change
PHMSAUnited States Department of Transportation Pipeline and Hazardous Materials Safety Administration
PPEPersonal protective equipment
Quarterly Report(s)Quarterly Report(s) on Form 10-Q
RNGRenewable natural gas
ROEReturn on equity, calculated consistent with utility ratemaking principles in each jurisdiction in which we operate
RRC
Railroad Commission of Texas
S&PStandard & Poor’s Ratings Services
SECSecurities and Exchange Commission
Securities ActSecurities Act of 1933, as amended
Senior Notes
ONE Gas’ registered notes consisting of $1 billion of 0.85 percent senior notes due 2023, $800 million of floating-rate senior notes due 2023, $700 million of 1.10 percent senior notes due 2024, $300 million of 3.61 percent senior notes due 2024, $300 million of 2.00 percent senior notes due 2030, $600 million of 4.658 percent senior notes due 2044 and $400 million of 4.50 percent notes due 2048
WNAWeather normalization adjustment(s)
XBRLeXtensible Business Reporting Language
5


PART I - FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
ONE Gas, Inc.  
CONSOLIDATED STATEMENTS OF INCOME  
Three Months Ended
 March 31,
(Unaudited)
20212020
(Thousands of dollars, except per share amounts)
Total revenues$625,293 $528,168 
Cost of natural gas314,069 226,139 
Operating expenses
Operations and maintenance110,886 104,839 
Depreciation and amortization52,266 47,513 
General taxes17,727 16,473 
Total operating expenses180,879 168,825 
Operating income130,345 133,204 
Other income (expense), net(405)(5,788)
Interest expense, net(15,440)(15,693)
Income before income taxes114,500 111,723 
Income taxes(18,925)(20,046)
Net income$95,575 $91,677 
Earnings per share
Basic$1.79 $1.73 
Diluted$1.79 $1.72 
Average shares (thousands)
Basic53,372 53,007 
Diluted53,515 53,268 
Dividends declared per share of stock$0.58 $0.54 
See accompanying Notes to Consolidated Financial Statements.
6


ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME 
 Three Months Ended
 March 31,
(Unaudited)
20212020
 
(Thousands of dollars)
Net income$95,575 $91,677 
Other comprehensive income, net of tax  
Change in pension and other postemployment benefit plan liability, net of tax of $(91) and $(74), respectively
300 224 
Total other comprehensive income, net of tax300 224 
Comprehensive income$95,875 $91,901 
See accompanying Notes to Consolidated Financial Statements.

7


ONE Gas, Inc.  
CONSOLIDATED BALANCE SHEETS  
 March 31,December 31,
(Unaudited)
20212020
Assets
(Thousands of dollars)
Property, plant and equipment  
Property, plant and equipment$6,915,000 $6,838,603 
Accumulated depreciation and amortization2,004,345 1,971,546 
Net property, plant and equipment4,910,655 4,867,057 
Current assets  
Cash and cash equivalents704,911 7,993 
Accounts receivable, net279,591 292,985 
Materials and supplies51,147 52,766 
Natural gas in storage44,321 93,946 
Regulatory assets43,944 56,773 
Other current assets34,757 35,406 
Total current assets1,158,671 539,869 
Goodwill and other assets  
Regulatory assets2,346,816 366,956 
Goodwill157,953 157,953 
Other assets105,809 96,877 
Total goodwill and other assets2,610,578 621,786 
Total assets$8,679,904 $6,028,712 
See accompanying Notes to Consolidated Financial Statements.
8


ONE Gas, Inc.  
CONSOLIDATED BALANCE SHEETS  
(Continued)
 March 31,December 31,
(Unaudited)
20212020
Equity and Liabilities
(Thousands of dollars)
Equity and long-term debt
Common stock, $0.01 par value:
authorized 250,000,000 shares; issued and outstanding 53,245,011 shares at March 31, 2021; issued and outstanding 53,166,733 shares at December 31, 2020
$532 $532 
Paid-in capital1,755,476 1,756,921 
Retained earnings548,068 483,635 
Accumulated other comprehensive loss(7,477)(7,777)
   Total equity2,296,599 2,233,311 
Long-term debt, excluding current maturities and net of issuance costs of $12,976 and $13,159, respectively
4,082,661 1,582,428 
Total equity and long-term debt6,379,260 3,815,739 
Current liabilities  
Notes payable447,000 418,225 
Accounts payable227,955 152,313 
Accrued taxes other than income65,859 63,800 
Regulatory liabilities23,398 15,761 
Customer deposits57,241 68,028 
Other current liabilities57,583 78,952 
Total current liabilities879,036 797,079 
Deferred credits and other liabilities  
Deferred income taxes685,901 656,806 
Regulatory liabilities537,129 547,563 
Employee benefit obligations89,860 97,637 
Other deferred credits108,718 113,888 
Total deferred credits and other liabilities1,421,608 1,415,894 
Commitments and contingencies
Total liabilities and equity$8,679,904 $6,028,712 
See accompanying Notes to Consolidated Financial Statements.





















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10


ONE Gas, Inc.  
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months Ended
March 31,
(Unaudited)
20212020
 
(Thousands of dollars)
Operating activities  
Net income$95,575 $91,677 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization52,266 47,513 
Deferred income taxes18,567 6,856 
Share-based compensation expense2,587 2,261 
Provision for doubtful accounts3,754 3,077 
Changes in assets and liabilities:
Accounts receivable9,640 22,608 
Materials and supplies1,619 2,342 
Natural gas in storage49,625 56,227 
Asset removal costs(9,885)(9,888)
Accounts payable87,202 (34,227)
Accrued taxes other than income2,059 (1,182)
Customer deposits(10,787)285 
Regulatory assets and liabilities - current20,466 (3,920)
Regulatory assets and liabilities - non-current(1,946,526)8,852 
Other assets and liabilities - current(20,698)(4,575)
Other assets and liabilities - noncurrent(14,729)(5,173)
Cash provided by (used in) operating activities(1,659,265)182,733 
Investing activities  
Capital expenditures(99,093)(113,517)
Other investing expenditures(2,351)(314)
Other investing receipts241 650 
Cash used in investing activities(101,203)(113,181)
Financing activities  
Borrowings (repayments) on notes payable, net28,775 (41,805)
Issuance of debt, net of discounts2,498,895  
Long-term debt financing costs(35,110) 
Dividends paid(30,882)(28,543)
Tax withholdings related to net share settlements of stock compensation(4,292)(5,988)
Cash provided by (used in) financing activities2,457,386 (76,336)
Change in cash and cash equivalents696,918 (6,784)
Cash and cash equivalents at beginning of period7,993 17,853 
Cash and cash equivalents at end of period$704,911 $11,069 
See accompanying Notes to Consolidated Financial Statements.

11


ONE Gas, Inc. 
CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)
Common Stock IssuedCommon StockPaid-in Capital
 (Shares)
(Thousands of dollars)
January 1, 202153,166,733 $532 $1,756,921 
Net income   
Other comprehensive income   
Common stock issued and other78,278  (1,705)
Common stock dividends - $0.58 per share
  260 
March 31, 202153,245,011 $532 $1,755,476 
January 1, 202052,771,749 $528 $1,733,092 
Net income   
Other comprehensive income   
Common stock issued and other89,059 1 (3,737)
Common stock dividends - $0.54 per share
  232 
March 31, 202052,860,808 $529 $1,729,587 
See accompanying Notes to Consolidated Financial Statements.


12


ONE Gas, Inc. 
CONSOLIDATED STATEMENTS OF EQUITY
(Continued)
(Unaudited)
Retained EarningsAccumulated Other Comprehensive LossTotal Equity
 
(Thousands of dollars)
January 1, 2021$483,635 $(7,777)$2,233,311 
Net income95,575  95,575 
Other comprehensive income 300 300 
Common stock issued and other  (1,705)
Common stock dividends - $0.58 per share
(31,142) (30,882)
March 31, 2021$548,068 $(7,477)$2,296,599 
January 1, 2020$402,509 $(6,739)$2,129,390 
Net income91,677 — 91,677 
Other comprehensive income— 224 224 
Common stock issued and other— — (3,736)
Common stock dividends - $0.54 per share
(28,775)— (28,543)
March 31, 2020$465,411 $(6,515)$2,189,012 
See accompanying Notes to Consolidated Financial Statements.

13


ONE Gas, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 2020 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, 2021, 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 2.2 million customers through our divisions in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. We primarily serve residential, commercial and transportation customers in all three states.

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 revenues and expenses during the reporting period. Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, provision for doubtful accounts, 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 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 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 to us.

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 months ended March 31, 2021, and 2020, 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 $11.6 million and $4.2 million for the three months ended March 31, 2021 and 2020, respectively. Such amounts are not included in capital expenditures or asset removal costs in our consolidated statements of cash flows.

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 2.2 million customers across three states, we are not exposed materially to a concentration of credit risk. We maintain an allowance for doubtful accounts based upon factors surrounding the credit risk of customers, historical trends, consideration of the current environment and other information. We recover natural 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 March 31, 2021 and December 31, 2020, our allowance for doubtful accounts was $19.9 million and $16.6 million, respectively.

Reclassifications - Certain reclassifications have been made in the prior-year financial statements to conform to the current-year presentation. We have updated our 2020 Statements of Cash Flows for the three months ended March 31, 2020, to disaggregate “regulatory assets and liabilities” and “other assets and liabilities” into current and non-current components that are presented on our balance sheet to conform to our current year presentation.
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Recently Issued Accounting Standards Update - In March 2020, the FASB issued ASU 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting,” which provides relief from the accounting analysis and impacts that may otherwise be required for modifications to agreements (e.g., loans, debt securities, derivatives, borrowings) necessitated by reference rate reform. It also provides optional expedients to enable companies to continue to apply hedge accounting to certain hedging relationships impacted by reference rate reform. In the first quarter 2020, we adopted this new guidance effective for contracts modified between March 12, 2020 and December 31, 2022. Our revolving line of credit under the ONE Gas Credit Agreement and our $800 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.

In December 2019, the FASB issued ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes,” which removes certain exceptions for recognizing deferred taxes for investments, performing intra-period allocation and calculating income taxes in interim periods. ASU 2019-12 also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. This standard is effective for interim and annual periods in fiscal years beginning after December 15, 2020, and early adoption is permitted. We adopted this new guidance on January 1, 2021. Our adoption did not result in a material impact to our consolidated financial statements.

In August 2018, the FASB issued ASU 2018-15, “Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (a consensus of the FASB Emerging Issues Task Force).” Under this guidance, a company should defer implementation costs that it incurs if a company would capitalize those same costs under the internal-use software guidance for an arrangement that is a software license. The deferred implementation costs should be amortized over the term of the hosting arrangement, including any probable renewals. We are party to hosting arrangements identified as service contracts for various information systems used in our operations. We adopted this new guidance using the prospective transition approach for implementation costs incurred in hosting arrangement service contracts beginning January 1, 2020. In certain jurisdictions, we have orders from our regulators allowing us to amortize deferred implementation costs for hosting arrangements entered into after January 1, 2020, over the life approved by our regulators for our internal-use software systems rather than the term of the hosting arrangement. The difference in amortization calculated between the term of the hosting arrangement and internal-use software life approved by our regulators is deferred as a regulatory asset and amortized over the remaining internal-use software life that exceeds the term of the hosting arrangement. Our adoption did not result in a material impact to our consolidated financial statements. 

In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses: Measurement of Credit Losses on Financial Instruments,’’ which introduces new guidance to the accounting for credit losses on instruments within its scope, including trade receivables. We adopted this new guidance in the first quarter 2020 using the modified retrospective method. Our financial assets within scope of this guidance primarily include our trade receivables from customers. Our policy for measuring our allowance for doubtful accounts is disclosed in Note 1 of our Notes to Consolidated Financial Statements in our Annual Report. We did not create any new accounting policies, nor did we modify any of our existing policies as a result of adopting this guidance. Our adoption did not result in a cumulative adjustment to our opening retained earnings or have a material impact to our consolidated financial statements.
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2.REVENUE

The following table sets forth our revenues disaggregated by source for the periods indicated:
Three Months Ended
March 31,
20212020
(Thousands of dollars)
Natural gas sales to customers$583,794 $480,718 
Transportation revenues36,202 33,757 
Miscellaneous revenues3,655 4,470 
Total revenues from contracts with customers623,651 518,945 
Other revenues - natural gas sales related(1,021)6,547 
Other revenues 2,663 2,676 
Total other revenues1,642 9,223 
Total revenues$625,293 $528,168 

Accrued unbilled natural gas sales revenues at March 31, 2021 and December 31, 2020, were $91.2 million and $144.9 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:
March 31, 2021
CurrentNoncurrentTotal
(Thousands of dollars)
Winter weather event costs$ $1,992,072 $1,992,072 
Pension and postemployment benefit costs16,513 330,037 346,550 
Reacquired debt costs812 4,663 5,475 
MGP remediation costs98 18,687 18,785 
Ad-valorem tax4,834  4,834 
WNA628  628 
Customer credit deferrals19,453  19,453 
Other1,606 `1,357 2,963 
Total regulatory assets, net of amortization43,944 2,346,816 2,390,760 
Income tax rate changes (537,129)(537,129)
Over-recovered purchased-gas costs(23,398) (23,398)
Total regulatory liabilities, net of amortization(23,398)(537,129)(560,527)
Net regulatory assets and liabilities$20,546 $1,809,687 $1,830,233 

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December 31, 2020
CurrentNoncurrentTotal
(Thousands of dollars)
Under-recovered purchased-gas costs$16,502 $ $16,502 
Pension and postemployment benefit costs16,541 341,266 357,807 
Reacquired debt costs812 4,866 5,678 
MGP remediation costs98 18,711 18,809 
Ad-valorem tax5,558  5,558 
WNA4,806 4,806 
Customer credit deferrals10,267 10,267 
Other2,189 2,113 4,302 
Total regulatory assets, net of amortization56,773 366,956 423,729 
Income tax rate changes (a) (547,563)(547,563)
Over-recovered purchased-gas costs(15,761) (15,761)
Total regulatory liabilities(15,761)(547,563)(563,324)
Net regulatory assets and liabilities$41,012 $(180,607)$(139,595)
(a) Includes the reclassification of $81.5 million of deferred taxes related to the elimination of state income tax for utilities in Kansas.

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

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

On February 16, 2021, the OCC approved an emergency order (the “OCC Order”) (i) directing natural gas and electric utilities to prioritize deliveries of natural gas and electricity for services necessary for life, health, and public safety, and of natural gas to electric generation facilities that serve human needs customers, and (ii) directing local utilities to communicate with their customers in order to reduce all non-essential energy consumption, and to reduce load in a safe and reasonable manner. The OCC Order recognized that the severe weather conditions resulted in increased commodity prices for both gas and electric utilities, along with issues relating to commodity acquisition, line pressure, and supply shortages. The OCC Order expired on February 20, 2021.

In response to a motion filed by Oklahoma Natural Gas, on March 2, 2021, the OCC issued an order stating that Oklahoma Natural Gas shall defer to a regulatory asset the extraordinary costs associated with this unprecedented winter weather event, including commodity costs, operational costs and carrying costs. The order further states that after all deferred costs have been accumulated and recorded, Oklahoma Natural Gas shall file a compliance report detailing the extent of such costs incurred. The order states that recovery of the deferred costs will be addressed in a future proceeding that will include a prudence review.

On February 15, 2021, the KCC issued an emergency order (i) directing all jurisdictional natural gas and electric utilities to coordinate efforts and take all reasonably feasible, lawful, and appropriate actions to ensure adequate delivery of natural gas and electricity to interconnected, non-jurisdictional utilities in Kansas, (ii) requiring jurisdictional natural gas and electric utilities to do all things possible and necessary to ensure that natural gas and electricity utility services continued to be provided to their customers in Kansas, and (iii) allowing those electric and natural gas distribution utilities who incur extraordinary costs to ensure their customers and other interconnected customers continued to receive utility service during this unprecedented cold weather event to defer those costs to a regulatory asset account. These deferred costs may also include carrying costs at the utility’s weighted average cost of capital. Each jurisdictional utility will be required to file a compliance report detailing the extent of such costs incurred and presenting a plan to minimize the financial impacts of this event on ratepayers over a
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reasonable time frame. These costs will be subject to review for reasonableness and accuracy in future regulatory proceedings. On March 9, 2021, the KCC issued an order adopting the KCC staff’s recommendation to open company-specific dockets to accept each utility’s filing of financial impact compliance reports and permit the KCC staff to conduct a review of the utility’s compliance report and its actions during the winter weather event. Kansas Gas Service expects to file its compliance report in the second quarter of 2021.

On February 13, 2021, the RRC issued a Notice to Local Distribution Companies acknowledging that due to the demand for natural gas expected during the upcoming winter weather event, natural gas utility LDCs may be required to pay extraordinarily high prices in the market for natural gas and may be subjected to other extraordinary costs when responding to the event. The RRC also encouraged natural gas utilities to continue to work to ensure that the citizens of the State of Texas were provided with safe and reliable natural gas service. To partially defer and reduce the impact on customers for these costs that ultimately are reflected in customer bills, the RRC authorized LDCs to record a regulatory asset to account for the extraordinary costs associated with this winter weather event, including but not limited to gas cost and other costs related to the procurement and transportation of gas supply. These costs will be subject to review for reasonableness and accuracy in future regulatory proceedings.

In accordance with these regulatory orders associated with the winter weather event, we have deferred approximately $2.0 billion in extraordinary costs for natural gas purchases, related financing and carrying costs and other operational costs, which includes $1.32 billion of costs attributable to Oklahoma Natural Gas customers, $381 million of costs attributable to Kansas Gas Service customers and $295 million of costs attributable to Texas Gas Service customers. The amounts deferred at March 31, 2021, include invoiced costs for natural gas purchases that have not been paid as we work with our suppliers to resolve discrepancies in invoiced amounts. The amounts deferred may be adjusted as the differences are resolved. In addition, as a result of the winter storm, we were assessed and may assess penalties as a result of over- or under-deliveries during periods that operational flow orders were imposed on us or that we, in turn, imposed on our transport customers or their agents. Amounts recorded reflect management’s best estimate and may be adjusted in future periods as the disposition of such penalties is determined. As these amounts are related to the extraordinary gas purchase costs associated with Winter Storm Uri, which are deferred, future adjustments are not expected to have a material impact on earnings.

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.

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

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

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

The customer credit deferrals and the noncurrent regulatory liability for income tax rate changes represents deferral of the effects of enacted federal and state income tax rate changes on our ADIT and the effects of these changes on our rates.

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, 2021, no regulatory assets have been recorded. We continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable.

Recovery through rates resulted in amortization of regulatory assets of approximately $2.9 million and $1.5 million for the three months ended March 31, 2021 and 2020, respectively. For the three months ended March 31, 2021 and 2020, income tax expense reflects credits of $8.1 million and $6.9 million, respectively, for the amortization of the regulatory liability associated with EDIT that was returned to customers.
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4.CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE

We have a commercial paper program under which we may issue unsecured commercial paper up to a maximum amount of $700 million to fund short-term borrowing needs. The maturities of the commercial paper notes vary but may not exceed 270 days from the date of issue. The commercial paper notes are generally sold at par less a discount representing an interest factor. At March 31, 2021, we had $447.0 million of commercial paper outstanding.

On March 16, 2021, we entered into the second amended and restated ONE Gas Credit Agreement, which was previously amended and restated on October 5, 2017.

The ONE Gas Credit Agreement provides for a $1 billion revolving unsecured credit facility and includes a $20 million letter of credit subfacility and a $60 million swingline subfacility. We can request an increase in commitments of up to an additional $500 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. We will be able to extend the maturity date by one year, subject to the lenders’ consent, up to two times. The ONE Gas Credit Agreement expires in March 2026, and is available to provide liquidity for working capital, capital expenditures, acquisitions and mergers, the issuance of letters of credit and for other general corporate purposes.

The ONE Gas Credit Agreement utilizes LIBOR as the reference rate for determining interest to accrue on the borrowings. In the event LIBOR is not available, and such circumstances are unlikely to be temporary, our lenders may establish an alternative interest rate for the senior notes by replacing LIBOR with one or more secured overnight financing-based rates or another alternate benchmark rate.

The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 72.5 percent at the end of any calendar quarter through December 31, 2021, and 70 percent at the end of any calendar quarter thereafter. At March 31, 2021, our total debt-to-capital ratio was 66 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, 2021, we had $1.2 million in letters of credit issued and no borrowings under the ONE Gas Credit Agreement, with $998.8 million of remaining credit, which is available to repay any of our commercial paper borrowings.

In connection with the second amendment 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 364-day Credit Agreement were paid in full and discharged.

5.LONG-TERM DEBT

Senior Notes - In March 2021, ONE Gas issued $1.0 billion of 0.85 percent senior notes due 2023, $700 million of 1.10 percent senior notes due 2024, and $800 million of floating-rate senior notes due 2023. The floating-rate senior notes bear interest at a rate equal to three-month LIBOR plus 61 basis points per year, reset quarterly for the applicable interest period (0.79% at March 31, 2021). The net proceeds from the issuance were used for general corporate purposes, including payment of gas purchase costs resulting from Winter Storm Uri.

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

We may redeem the senior notes issued in March 2021 in whole or in part, plus accrued and unpaid interest to the redemption date, on or after September 11, 2021. We do not have the right to redeem these senior notes prior to September 11, 2021.

In April 2020, ONE Gas issued $300 million of 2.00 percent senior notes due 2030. The proceeds from the issuance were used to reduce the amount of outstanding commercial paper and for general corporate purposes.

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.
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ONE Gas 2021 Term Loan Facility - On February 22, 2021, we entered into the ONE Gas 2021 Term Loan Facility as part of the financing of our natural gas purchases in order to provide sufficient liquidity to satisfy our obligations as a result of Winter Storm Uri. The net proceeds of the March 2021 debt issuance reduced the commitments under the ONE Gas 2021 Term Loan Facility on a dollar-for-dollar basis, and as a result no commitments remained outstanding and the facility was terminated concurrently with the closing of the debt issuance.

6.EQUITY

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. During the quarters ended March 31, 2021 and 2020, we did not issue or sell shares of our common stock under the at-the-market equity program. At March 31, 2021, we had $236.4 million of equity available for issuance under the program.

Dividends Declared - In May 2021, we declared a dividend of $0.58 per share ($2.32 per share on an annualized basis) for shareholders of record as of May 17, 2021, payable on June 1, 2021.

7.ACCUMULATED OTHER COMPREHENSIVE LOSS

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 EndedAffected Line Item in the
Details About Accumulated OtherMarch 31,Consolidated Statements
Comprehensive Loss Components20212020of Income
(Thousands of dollars)
Pension and other postemployment benefit plan obligations (a)
Amortization of net loss$11,474 $10,623 
Amortization of unrecognized prior service credit(70)(29)
11,404 10,594 
Regulatory adjustments (b)(11,013)(10,296)
391 298 Income before income taxes
(91)(74)Income tax expense
Total reclassifications for the period$300 $224 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.

8.EARNINGS PER SHARE

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

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The following tables set forth the computation of basic and diluted EPS from continuing operations for the periods indicated:
 Three Months Ended March 31, 2021
 IncomeSharesPer Share
Amount
 
(Thousands, except per share amounts)
Basic EPS Calculation   
Net income available for common stock
$95,575 53,372 $1.79 
Diluted EPS Calculation   
Effect of dilutive securities 143  
Net income available for common stock and common stock equivalents$95,575 53,515 $1.79 
 Three Months Ended March 31, 2020
 IncomeSharesPer Share
Amount
 
(Thousands, except per share amounts)
Basic EPS Calculation   
Net income available for common stock
$91,677 53,007 $1.73 
Diluted EPS Calculation  
Effect of dilutive securities 261  
Net income available for common stock and common stock equivalents$91,677 53,268 $1.72 

9.EMPLOYEE BENEFIT PLANS

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
March 31,
20212020
(Thousands of dollars)
Components of net periodic benefit cost 
Service cost$3,453 $3,217 
Interest cost 7,365 8,545 
Expected return on assets (15,596)(15,280)
Amortization of net loss 11,381 10,580 
Net periodic benefit cost$6,603 $7,062 

Other Postemployment Benefits
Three Months Ended
March 31,
20212020
(Thousands of dollars)
Components of net periodic benefit cost (credit) 
Service cost$397 $423 
Interest cost 1,563 1,889 
Expected return on assets (4,202)(3,867)
Amortization of unrecognized prior service credit (70)(29)
Amortization of net loss 93 43 
Net periodic benefit cost (credit)$(2,219)$(1,541)

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. Regulatory deferrals related to net periodic benefit cost were not material for the three months ended March 31, 2021 and 2020.

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 $6.2 million and $6.0 million as of March 31, 2021 and December 31, 2020, respectively. See Note 3 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.

10.INCOME TAXES

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, 2021, we have no uncertain tax positions. Changes in tax laws or tax rates are recognized in the financial reporting period that includes the enactment date. We are no longer subject to income tax examination for years prior to 2017.

11.OTHER INCOME AND OTHER EXPENSE

The following table sets forth the components of other income and other expense for the periods indicated:
Three Months Ended
March 31,
20212020
(Thousands of dollars)
Net periodic benefit cost other than service cost$(770)$(1,123)
Earnings (losses) on investments associated with nonqualified employee benefit plans616 (4,259)
Other, net252 (406)
Total other income (expense), net$(405)$(5,788)

12.COMMITMENTS AND CONTINGENCIES

COVID-19 -Throughout the COVID-19 pandemic, we have continued to provide essential services to our customers. We have implemented a comprehensive set of policies, procedures and guidelines to protect the safety of our employees, customers and communities. These actions include following safety protocols developed during the pandemic, remote work for our office- based employees, limiting direct contact with our customers, and generally suspending disconnections and late payment fees beginning in mid-March 2020 through April 2021, when disconnects were resumed in all service areas, except Texas, which is still subject to a moratorium.

Since the onset of the pandemic in the first quarter of 2020, impacts on our results of operations as a result of COVID-19 include but are not limited to:

lower late payment, reconnect and collection fees and incremental expenses for bad debts related to the suspension of disconnects for nonpayment in each of our jurisdictions;
incremental expenses for PPE, cleaning supplies, outside services and other expenses; and
lower expenses for travel and employee training that have been impacted by the pandemic.

Going forward, we expect these impacts on our revenues and expenses to continue during the course of the pandemic. We also could experience a reduction in revenues from commercial and transportation customers temporarily or permanently impacted by the pandemic.

We have received accounting orders in each of our jurisdictions authorizing us to accumulate and defer for regulatory purposes certain incremental costs incurred, including bad debt expenses, and certain lost revenues, net of offsetting expense reductions associated with COVID-19. Pursuant to these orders, the recovery of any net incremental costs and lost revenue 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
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March 31, 2021, no regulatory assets have been recorded. We continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable. We do not expect COVID-related impacts to have a material adverse effect on our results of operations or cash flows during 2021.

Environmental Matters - We are subject to multiple historical, wildlife preservation and environmental laws and/or regulations, 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, hazardous materials 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 Clean Air Act 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 months ended March 31, 2021 and 2020.

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

We have completed or are addressing removal of the source of soil contamination at all 12 sites and continue to monitor groundwater at eight of the 12 sites according to plans approved by the KDHE. In 2019, we completed a project to remove a source of contamination and associated contaminated materials at the twelfth site where no active soil remediation had previously occurred. A remediation plan was submitted to the KDHE concerning this site in 2020 and the KDHE has provided comments that we are addressing. We are also working on a remediation plan that will be submitted to the KDHE in 2021 for an additional site. At March 31, 2021, the reserve for remediation of our MGP sites was $13.7 million.

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, 2021, we have deferred $18.8 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 2021.

We also own or retain legal responsibility for certain environmental conditions at a former MGP site in Texas. At the request of the Texas Commission on Environmental Quality, we began investigating the level and extent of contamination associated with the site under their Texas Risk Reduction Program. A preliminary site investigation revealed that this site contains contaminants generally associated with MGP sites and is subject to control or remediation under various environmental laws and regulations. Until the investigation is complete, we are unable to determine what, if any, active remediation will be required. A reliable estimate of potential remediation costs is not feasible at this point due to the amount of uncertainty as to the levels and extent of contamination.

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three months ended March 31, 2021 and 2020. 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
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and governmental regulations, and to the extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition, results of operations or cash flows.

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

Pipeline Safety - We are subject to PHMSA regulations, including integrity-management regulations. PHMSA regulations require pipeline companies operating high-pressure transmission pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated HCAs. In January 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act was signed into law. The law increased maximum penalties for violating federal pipeline safety regulations and directs the DOT and the Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us. These issues include, but are not limited to, the following:

an evaluation of whether natural gas pipeline integrity-management requirements should be expanded beyond current HCAs;
a verification of records for pipelines in class 3 and 4 locations and HCAs to confirm MAOPs; and
a requirement to test previously untested pipelines operating above 30 percent yield strength in HCAs.

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 include changes to pipeline integrity-management requirements and other safety-related requirements. The NPRM comment period ended July 7, 2016, and comments are under review by PHMSA. As part of the comment review process, PHMSA is being advised by the Technical Pipeline Safety Standards Committee, informally known by PHMSA as the GPAC, a statutorily mandated advisory committee that advises PHMSA on proposed safety policies for natural gas pipelines. The GPAC reviews PHMSA's proposed regulatory initiatives to assure the technical feasibility, reasonableness, cost-effectiveness and practicality of each proposal. The GPAC met six times since January 2017 to review public comments and make recommendations to PHMSA. The GPAC completed their review of the NPRM on March 28, 2018, except for gas gathering pipelines. The GPAC met in June 2019 on gas gathering pipelines. In addition to reviewing public and committee comments, PHMSA announced they will split this NPRM into three separate final rulemakings:

the first final rule addresses the legislative mandates from the Pipeline Safety, Regulatory Certainty and Jobs Creation Act and will be called the Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments;
the second final rule will be called the Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments and will cover all remaining elements of the NPRM (except for gas gathering pipelines); and
the third final rule will be called the Safety of Gas Gathering Pipelines and will address gas gathering pipelines.

A significant number of recommendations have been made to PHMSA to improve the NPRM. The industry trade associations filed joint comments to the “legislative mandates” rulemaking to amend the federal safety regulations applicable to gas transmission and 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. The estimated capital and operating expenditures associated with compliance with the first final rule were not material.

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

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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.

13.DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS

Accounting Treatment - We record all derivative instruments at fair value, except for normal purchases and normal sales that are expected to result in physical delivery. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it, or if regulatory rulings require a different accounting treatment.

If certain conditions are met, we may elect to designate a derivative instrument as a hedge to mitigate the risk 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 March 31, 2021, we had no purchased natural gas call options. At December 31, 2020, we held purchased natural gas call options for the heating season ended March 2021, with total notional amounts of 14.7 Bcf, for which we paid premiums of $6.7 million, and which had a fair value of $0.8 million. The premiums paid and any cash settlements received are recorded as part of our unrecovered purchased-gas costs in current regulatory assets as these contracts are included in, and recoverable through, the purchased-gas cost adjustment mechanisms. Additionally, changes in fair value 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.

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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 March 31, 2021 and December 31, 2020, our other current and noncurrent assets include $3.6 million and $1.6 million of corporate bonds, respectively, and $3.2 million and $3.2 million of United States treasury notes, respectively. The fair value of corporate bonds and United States treasury notes approximate our carrying value, and are classified as Level 2 and Level 1, respectively.

Short-term notes payable and commercial paper are due upon demand and, therefore, the carrying amounts approximate fair value and are classified as Level 1. The book value of our long-term debt, including current maturities, was $4.1 billion and $1.6 billion at March 31, 2021 and December 31, 2020, respectively. The estimated fair value of our long-term debt, including current maturities, was $4.2 billion and $2.0 billion at March 31, 2021 and December 31, 2020, respectively. The estimated fair value of our long-term debt at March 31, 2021 and December 31, 2020, was determined using quoted market prices, and is classified as Level 2.

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ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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, 2021 are not necessarily indicative of the results that may be expected for a 12-month period.

RECENT DEVELOPMENTS

Winter Storm Uri - In February 2021, the U.S. experienced Winter Storm Uri, a historic winter weather event impacting supply, market pricing and demand for natural gas in a number of states, including our service territories of 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 gas costs in our Kansas, Oklahoma, and Texas jurisdictions, which resulted in aggregated natural gas purchases for the month of February of approximately $2.1 billion.

On February 22, 2021, we entered into the ONE Gas 2021 Term Loan Facility as part of the financing of our natural gas purchases in order to provide sufficient liquidity to satisfy our obligations as a result of Winter Storm Uri.

On March 11, 2021, we issued $1.0 billion of 0.85 percent senior notes due 2023, $700 million of 1.10 percent senior notes due 2024, and $800 million of floating-rate senior notes due 2023. The floating-rate senior notes bear interest at a rate equal to three-month LIBOR plus 61 basis points per year reset quarterly for the applicable interest period (0.79% at March 31, 2021). The net proceeds from the issuance were used for general corporate purposes, including payment of gas purchase costs resulting from Winter Storm Uri. The net proceeds of the March 2021 debt issuance reduced the commitments under the ONE Gas 2021 Term Loan Facility on a dollar-for-dollar basis, and as a result no commitments remained outstanding and the facility was terminated concurrently with the closing of the debt issuance.

Our purchased gas costs are recoverable through our 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 local natural gas distribution companies, 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. We have deferred approximately $2.0 billion in 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 the 2021 winter weather event on us.

ONE Gas Credit Agreement - On March 16, 2021, we entered into the second amended and restated ONE Gas Credit Agreement, which was previously amended and restated on October 5, 2017. The ONE Gas Credit Agreement provides for a $1 billion revolving unsecured credit facility and includes a $20 million letter of credit subfacility and a $60 million swingline subfacility. In connection with the amendment of the ONE Gas Credit Agreement, all commitments under the ONE Gas 364-day Credit Agreement were terminated, and all obligations under the 364-day Credit Agreement were paid in full and discharged.

COVID-19 - Throughout the COVID-19 pandemic, we have continued to provide essential services to our customers. We have implemented a comprehensive set of policies, procedures and guidelines to protect the safety of our employees, customers and communities. These actions include following safety protocols developed during the pandemic, remote work for our office-based employees, limiting direct contact with our customers, and generally suspending disconnections and late payment fees beginning in mid-March 2020 through April 2021, when disconnects were resumed in all service areas, except Texas, which is still subject to a moratorium. Although we have experienced employee absences due to our protocols for self-isolation of employees who may be exhibiting symptoms or who may have been exposed to or contracted the COVID-19 virus, we have continued, and expect to continue, to execute our work in the field, including our capital work for system integrity, pipeline replacements and extending service to new customers.

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During the three months ended March 31, 2021, impacts on our results of operations as a result of COVID-19 include but are not limited to:

lower late payment, reconnect and collection fees and incremental expenses for bad debts related to the suspension of disconnects for nonpayment in each of our jurisdictions;
incremental expenses for PPE, cleaning supplies, outside services and other expenses; and
lower expenses for travel and employee training that have been impacted by the pandemic.

Going forward, we expect these impacts on our revenues and expenses to continue during the course of the pandemic. We also could experience a reduction in revenues from commercial and transportation customers temporarily or permanently impacted by the pandemic. However, we do not expect COVID-related impacts to have a material adverse effect on our results of operations or cash flows during 2021.

We are in regular communication with our regulators to keep them apprised of the effects COVID-19 is having on the service we provide. 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 revenue 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, 2021, no regulatory assets have been recorded. We continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable. Accordingly, there could be a delay in the recognition of amounts that may be approved for recovery until the conclusion of future regulatory proceedings.

See “Regulatory Activities,” “Financial Results and Operating Information,” “Capital Expenditures and Asset Removal Costs,” and Note 3 and Note 12 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion of the effects of COVID-19 on us.

Dividend - In May 2021, we declared a dividend of $0.58 per share ($2.32 per share on an annualized basis) for shareholders of record as of May 17, 2021, payable on June 1, 2021.

REGULATORY ACTIVITIES

Oklahoma - On February 12, 2021, the governor of Oklahoma declared a state of emergency for all 77 counties in the state of Oklahoma in light of expected severe weather and freezing temperatures associated with a winter weather event. The declaration cited anticipated damage to private and public properties and utilities, including electric, gas, and water systems, within the state of Oklahoma.

On February 16, 2021, the OCC approved an emergency order (the “OCC Order”) (i) directing natural gas and electric utilities to prioritize deliveries of natural gas and electricity for services necessary for life, health, and public safety, and of natural gas to electric generation facilities that serve human needs customers, and (ii) directing local utilities to communicate with their customers in order to reduce all non-essential energy consumption, and to reduce load in a safe and reasonable manner. The OCC Order recognized that the severe weather conditions resulted in increased commodity prices for both gas and electric utilities, along with issues relating to commodity acquisition, line pressure, and supply shortages. The OCC Order expired on February 20, 2021.

In response to a motion filed by Oklahoma Natural Gas on March 2, 2021, the OCC issued an order stating that Oklahoma Natural Gas shall defer to a regulatory asset the extraordinary costs associated with this unprecedented winter weather event, including commodity costs, operational costs and carrying costs. The order further states that after all deferred costs have been accumulated and recorded, Oklahoma Natural Gas shall file a compliance report detailing the extent of such costs incurred. The order also provides that recovery of the deferred costs will be addressed in a future proceeding that will include a prudence review. At March 31, 2021, we have deferred approximately $1.32 billion in extraordinary costs attributable to Oklahoma Natural Gas customers associated with Winter Storm Uri.

In April 2021, a bill permitting the state to pursue securitized financing of extraordinary expenses, such as fuel costs, financing costs and other operational costs incurred by regulated utilities during extreme weather events, was signed into law by the Oklahoma governor. Pursuant to this legislation, we will submit an application to the OCC for a financing order authorizing extraordinary costs approved for recovery, the period over which costs will be recovered, and other such specifications necessary for the issuance of securitized bonds. The OCC will have 180 days to consider our application. After issuance of the
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financing order by the OCC, the Oklahoma Development Finance Authority (ODFA) has 24 months to complete the process to issue the securitized bonds. On April 29, 2021, Oklahoma Natural Gas submitted an initial application requesting a financing order pursuant to this legislation. In the application, Oklahoma Natural Gas indicates it will file a supplemental motion with all required components pursuant to the legislation for the issuance of a financing order. Upon filing the supplemental motion, the OCC will have 180 days to issue an order regarding our application. See “Liquidity and Capital Resources,” in this Quarterly Report for additional discussion.

In June 2020, the OCC issued an order permitting the creation of regulatory assets and deferrals related to COVID-19. Each utility is authorized under the OCC’s order to record as a regulatory asset increased bad debt expenses, costs associated with expanded payment plans, waived fees, and incremental expenses that are directly related to the suspension of or delay in disconnection of service (or the reconnection of service) beginning March 15, 2020, as a result of the governor’s executive order declaring a state of emergency. In addition, the OCC recognizes that utilities report taking many steps to ensure the continuity of utility service, while protecting utility personnel, customers, and the general public. Such steps include procuring additional PPE, increasing sanitation efforts at facilities, implementing health-screening processes, and securing temporary facilities for potential sequestration of critical operations personnel. The OCC has stated it supports the continuation of these critical response and planning efforts and acknowledges such efforts cause incremental costs that it will allow to be deferred and reviewed in a future rate case. The OCC’s deferral authorization does not bind the OCC to any specific treatment of these items in any future proceeding, nor does it prohibit the OCC from considering the effect of any operational savings, or other financial impacts that may occur as a result of COVID-19. Determination of the recovery of the regulatory assets and deferrals will occur in the next rate case that is required to be filed on or before June 30, 2021.

In February 2020, Oklahoma Natural Gas filed its fourth annual PBRC application following the general rate case that was approved in January 2016. A settlement was reached, and the OCC approved a joint stipulation in July 2020. This stipulation includes a base rate increase of $9.7 million and an energy efficiency incentive of $2.2 million, with new rates reflecting these changes effective in June 2020. This stipulation also includes a credit of $12.2 million associated with EDIT issued through a bill credit to Oklahoma customers in the first quarter of 2021.

As required, PBRC filings are made annually on or before March 15, until the next general rate case, which is currently required to be filed on or before June 30, 2021, based on a calendar 2020 test year.

Kansas - On February 14, 2021, the governor of Kansas issued a State of Disaster Emergency due to wind chill warnings and stress on utility and natural gas providers expected from the significantly colder than normal weather forecasted throughout Kansas. The executive order also urged Kansas citizens to conserve energy to help ensure a continued supply of natural gas and electricity and keep their personal costs down. The declaration also noted that due to increased energy demand and natural gas supply constraints caused by sub-zero temperatures, utilities at the time were experiencing wholesale natural gas prices anywhere from 10 to 100 times higher than normal.

On February 15, 2021, the KCC issued an emergency order (i) directing all jurisdictional natural gas and electric utilities to coordinate efforts and take all reasonably feasible, lawful, and appropriate actions to ensure adequate delivery of natural gas and electricity to interconnected, non-jurisdictional utilities in Kansas, (ii) requiring jurisdictional natural gas and electric utilities to do all things possible and necessary to ensure that natural gas and electricity utility services continued to be provided to their customers in Kansas, and (iii) allowing those electric and natural gas distribution utilities who incur extraordinary costs to ensure their customers and other interconnected customers continued to receive utility service during this unprecedented cold weather event to defer those costs to a regulatory asset account. Each jurisdictional utility will be required to file a compliance report detailing the extent of such costs incurred and presenting a plan to minimize the financial impacts of this event on ratepayers over a reasonable time frame. These costs will be subject to review for reasonableness and accuracy in future regulatory proceedings. On March 9, 2021, the KCC issued an order adopting the KCC staff’s recommendation to open company-specific investigations to accept each utility’s filing of financial impact compliance reports and permit the KCC staff to conduct a review of the utility’s compliance report and its actions during the winter weather event. Kansas Gas Service expects to file its compliance report in the second quarter of 2021. At March 31, 2021, we have deferred approximately $381 million in extraordinary costs attributable to Kansas Gas Service customers associated with Winter Storm Uri.

In April 2021, a bill permitting 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. This bill gives the KCC the authority to oversee and authorize the issuance of ratepayer-backed securitized bonds issued by a public utility. Pursuant to this legislation, we can submit an application to the KCC for a financing order authorizing extraordinary costs approved for recovery, the period over which costs will be recovered, and other such specifications necessary for the issuance of securitized bonds. The KCC will have 180 days to consider our application. Following KCC approval of the financing order, we can begin the process to issue the securitized bonds. See “Liquidity and Capital Resources,” in this Quarterly Report for additional discussion.
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In August 2020, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $7.8 million related to its GSRS. This filing incorporates the effect on the requested GSRS rate increase of a bill amending the Kansas income tax code that eliminates public utilities regulated by the KCC from paying Kansas state income taxes beginning January 1, 2021. In September 2020, Kansas Gas Service submitted an erratum to the application which modified the requested increase to approximately $7.5 million. In November 2020, the KCC approved the increase effective December 2020.

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 $81.5 million was recorded as an EDIT regulatory liability and will be refunded to our customers. This adjustment had no material impact on our income tax expense and no impact on our cash flows for the year ended December 31, 2020. The bill stipulates that, if requested by the utility, this EDIT will be returned to Kansas customers over a period of no less than 30 years, with the exact timing to be determined in our next general rate proceeding. In August 2020, Kansas Gas Service submitted an application to the KCC to reduce its base rates to reflect the elimination of Kansas state income taxes by approximately $4.9 million. In December 2020, the KCC approved the reduction, effective January 1, 2021. See Note 3 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.

In April 2020, Kansas Gas Service filed an application with the KCC for an AAO to accumulate and defer certain incremental costs incurred, including bad debt expenses and lost revenues, as well as associated carrying costs, related to COVID-19 beginning March 1, 2020, for recovery in Kansas Gas Service’s next rate case filing. In July 2020, the KCC approved the request for an AAO subject to the recommendations set forth in its Staff Report and Recommendation and clarifications sought by Kansas Gas Service. The AAO provides notice that Kansas Gas Service may identify, track, document, accumulate, and defer in a regulatory asset extraordinary costs (net of any cost decreases) and lost revenue, plus carrying costs, associated with the COVID-19 pandemic. The KCC states that approval of the AAO is not a finding that tracked costs and lost revenue will be included in future rates; rather, any determination regarding recoverability will occur in a future rate proceeding. In a separate order applicable to all regulated utilities, the KCC approved the deferral of bad debt expense and late payment fees associated with the KCC’s suspension of disconnection activity and customer protection provisions. The recovery, the carrying charges and amortization period will be determined in Kansas Gas Service’s next rate case or alternative rate recovery filing.

In November 2018, Kansas Gas Service submitted an application to the KCC requesting approval of its contract to own, operate and maintain the natural gas distribution system at Fort Riley, a United States Army installation. The KCC approved the Company’s application in May 2019 and the transition period, which was delayed due to COVID-19, has been extended to June 1, 2021. The acquisition of these assets is now expected to be completed before the end of third quarter 2021 for approximately $8.5 million.

Texas - On February 12, 2021, the governor of Texas issued a state of disaster for all 254 counties in Texas in response to the then-forecasted weather conditions. The declaration certified that severe winter weather posed an imminent threat due to prolonged freezing temperatures, heavy snow, and freezing rain statewide.

Also, on February 12, 2021, the RRC issued an emergency order to temporarily implement a statewide utilities curtailment program intended to protect residences, hospitals, schools, churches, and other human needs customers. On February 17, 2021, the RRC extended its emergency order issued on February 12, 2021, to February 23, 2021.

On February 13, 2021, the RRC issued a Notice to Local Distribution Companies acknowledging that due to the demand for natural gas expected during the upcoming winter weather event, natural gas utility LDCs may be required to pay extraordinarily high prices in the market for natural gas and may be subjected to other extraordinary costs when responding to the event. The RRC also encouraged natural gas utilities to continue to work to ensure that the citizens of the State of Texas were provided with safe and reliable natural gas service. To partially defer and reduce the impact on customers for these costs that ultimately are reflected in customer bills, the RRC authorized LDCs to record a regulatory asset to account for the extraordinary costs associated with this winter weather event, including but not limited to gas cost and other costs related to the procurement and transportation of gas supply. These costs will be subject to review for reasonableness and accuracy in future regulatory proceedings. At March 31, 2021, we have deferred approximately $295 million in extraordinary costs attributable to Texas Gas Service customers associated with Winter Storm Uri.

In April 2021, a bill permitting the state to pursue securitized financing of extraordinary expenses, such as fuel costs, financing costs and other operational costs incurred during extreme weather events, was proposed and is advancing in the Texas legislature. This proposed bill would give the RRC the authority to approve the amounts to be recovered from the issuance of
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ratepayer-backed securitized bonds by the Texas Public Financing Authority (TPFA). Pursuant to this proposed legislation, we will submit an application to the RRC, within 60 days of the legislation becoming effective, for an order authorizing the amount of extraordinary costs for recovery, the period over which costs will be recovered, and other such specifications necessary for the issuance of securitized bonds. The RRC will have 90 days to consider our application. If approved, the TPFA will begin the process to issue the securitized bonds. See “Liquidity and Capital Resources,” in this Quarterly Report for additional discussion.

In April 2020, the RRC issued an order authorizing utilities to use a regulatory accounting mechanism and a subsequent process through which Texas Gas Service may seek future recovery of incremental expenses resulting from the effects of COVID-19, including bad debt and associated credit and collections costs, and other reasonable and necessary incremental costs to address the impact of COVID-19. The timing of any recovery will be determined as we work with our regulators.

West Texas Service Area - In March 2021, Texas Gas Service made GRIP filings for all customers in the West Texas service area requesting an increase of $9.7 million to be effective in July 2021.

In March 2020, Texas Gas Service made GRIP filings for all customers in the West Texas service area. In June 2020, the RRC and the cities in the West Texas service area agreed to an increase of $4.7 million, and new rates became effective in June 2020.

Central-Gulf Service Area - In February 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.

In 2019, Texas Gas Service filed a rate case for all customers in the Central Texas and Gulf Coast service areas, seeking a rate increase of $15.6 million and a $1.3 million credit to customers associated with EDIT, and requesting to consolidate the two service areas into one. In August 2020, the RRC approved all terms of a $10.3 million settlement, as well as consolidation of the Central Texas service area and the Gulf Coast service area into a new Central-Gulf service area. The RRC also approved an $8.5 million credit to customers associated with EDIT. The settlement included an ROE of 9.5 percent and a capital structure with equity of 59 percent and debt of 41 percent, and new rates became effective in August 2020.

Other Texas Service Areas - In April 2021, Texas Gas Service filed annual Cost-of-Service Adjustments (COSA) for the incorporated areas of the Rio Grande Valley service area and the North Texas service area requesting increases in rates of $4.6 million and $2.2 million, respectively. If approved in each service area, new rates will become 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. As of the three months ended March 31, 2021, no annual rate increases associated with these filings have been approved and $1.8 million were approved for the year ended December 31, 2020.

Winter Storm Uri Deferred Costs - The amounts deferred at March 31, 2021, include invoiced costs for natural gas purchases that have not been paid as we work with our suppliers to resolve discrepancies in invoiced amounts. The amounts deferred may be adjusted as the differences are resolved. In addition, as a result of Winter Storm Uri, we were assessed and may assess penalties as a result of over- or under-deliveries during periods that operational flow orders were imposed on us or that we, in turn, imposed on our transport customers or their agents. Amounts recorded reflect management’s best estimate and may be adjusted in future periods as the disposition of such penalties is determined. As these amounts are related to the extraordinary gas purchase costs associated with Winter Storm Uri, which are deferred, future adjustments are not expected to have a material impact on earnings.
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FINANCIAL RESULTS AND OPERATING INFORMATION

We operate in one reportable business segment: regulated public utilities that deliver natural gas to residential, commercial and transportation customers. 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.

Selected Financial Results - For the three months ended March 31, 2021, net income was $95.6 million, or $1.79 per diluted share, compared with $91.7 million, or $1.72 per diluted share, in the same period last year.

The following table sets forth certain selected financial results for our operations for the periods indicated:
 Three Months EndedThree Months
 March 31,2021 vs. 2020
Financial Results20212020Increase (Decrease)
 
(Millions of dollars, except percentages)
Natural gas sales $582.8 $486.8 $96.0 20 %
Transportation revenues36.2 34.2 2.0 6 %
Other revenues6.3 7.2 (0.9)(13)%
Total revenues625.3 528.2 97.1 18 %
Cost of natural gas314.1 226.1 88.0 39 %
Net margin311.2 302.1 9.1 3 %
Operating costs 128.6 121.4 7.2 6 %
Depreciation and amortization52.3 47.5 4.8 10 %
Operating income $130.3 $133.2 $(2.9)(2)%
Capital expenditures and asset removal costs$109.0 $123.4 $(14.4)(12)%

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, which are included as other revenues in our Notes to Consolidated Financial Statements.

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 utility 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, which are included in the consolidated statements of income and our Notes to Consolidated Financial Statements as other revenues.

Non-GAAP Financial Measure - We have disclosed net margin, which is considered a non-GAAP financial measure, in our selected financial data and selected financial results. Net margin is comprised of total revenues less cost of natural gas. Cost of natural gas includes commodity purchases, fuel, storage, transportation and other gas purchase costs recovered through our cost of natural gas regulatory mechanisms and does not include an allocation of general operating costs or depreciation and amortization. In addition, 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, net margin is not affected by fluctuations in the cost of natural gas. Accordingly, we routinely use net margin in the analysis of our financial performance. We believe that net margin provides investors a more relevant and useful measure to analyze our financial performance as a 100 percent regulated natural gas utility than total revenues because the change in the cost of natural gas from period to period does not impact our operating income. As such, the following discussion and analysis of our financial performance will reference net margin rather than total revenues and cost of natural gas individually.

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The following table sets forth a reconciliation of net margin to the most directly comparable GAAP measure for the periods indicated:
 Three Months EndedThree Months
 March 31,2021 vs. 2020
Non-GAAP Reconciliation20212020Increase (Decrease)
 (Millions of dollars, except percentages)
Total revenues$625.3 $528.2 $97.1 18 %
Cost of natural gas314.1 226.1 88.0 39 %
Net margin$311.2 $302.1 $9.1 3 %

The following table sets forth our net margin by type of customer for the periods indicated:
 Three Months EndedThree Months
March 31,2021 vs. 2020
Net Margin20212020Increase (Decrease)
Natural gas sales
(Millions of dollars, except percentages)
Residential$223.2 $215.6 $7.6 4 %
Commercial and industrial43.0 42.4 0.6 1 %
Other2.5 2.7 (0.2)(7)%
Net margin on natural gas sales268.7 260.7 8.0 3 %
Transportation revenues36.2 34.2 2.0 6 %
Other revenues6.3 7.2 (0.9)(13)%
Net margin$311.2 $302.1 $9.1 3 %

Our net margin on natural gas sales is comprised of two components, fixed and variable margin. Fixed margin reflects the portion of our net margin attributable to the monthly fixed customer charge component of our rates, which does not fluctuate based on customer usage in each period. Variable margin reflects the portion of our net margin that fluctuates with the volumes delivered and billed and the effects of weather normalization. The following table sets forth our net margin on natural gas sales by revenue type for the periods indicated:
 Three Months EndedThree Months
 March 31,2021 vs. 2020
Net Margin on Natural Gas Sales20212020Increase (Decrease)
Net margin on natural gas sales
(Millions of dollars, except percentages)
Fixed margin$152.1 $149.6 $2.5 2 %
Variable margin116.6 111.1 5.5 5 %
Net margin on natural gas sales$268.7 $260.7 $8.0 3 %

Net margin increased $9.1 million for the three months ended March 31, 2021, compared with the same period last year, due primarily to the following:
an increase of $9.1 million from new rates, primarily in Texas and Oklahoma;
an increase of $2.3 million in residential sales due primarily to net customer growth in Oklahoma and Texas; and
an increase of $1.4 million in rider and surcharge recoveries due to a higher ad-valorem surcharge in Kansas, which was offset with higher regulatory amortization expense, in depreciation and amortization expense, offset partially by:
a decrease of $3.1 million due to the reduction in net margin associated with the impact of weather normalization, net of increased sales volumes, primarily in Texas and Kansas. For the three months ended March 31, 2021, heating degree days in Texas and Kansas were 24% and 12% higher, respectively, compared with the same period in 2020.

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Operating costs increased $7.2 million for the three months ended March 31, 2021, compared with the same period last year, due primarily to the following:

an increase of $3.4 million in employee-related costs;
an increase of $1.6 million in outside services costs;
an increase of $1.5 million in expenses related to our response to the COVID-19 pandemic; and
an increase of $1.0 million in ad valorem taxes.

The portion of the decrease in late payment, reconnect and collection fees resulting from the moratoriums on disconnecting customers for nonpayment in response to the COVID-19 pandemic, increased bad debt expense and the net incremental expenses related to the COVID-19 pandemic are eligible for future recovery under the regulatory orders we have received in each of our jurisdictions. For financial reporting purposes, the amounts deferred as a regulatory asset for future recovery under the accounting orders must be probable of recovery. At March 31, 2021, no regulatory assets have been recorded. We continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial statement purposes at such time as recovery is deemed probable.

Depreciation and amortization expense increased $4.8 million for the three months ended March 31, 2021, compared with the same period last year, due primarily to an increase in depreciation from our capital expenditures being placed in service and an increase in the amortization of the ad-valorem surcharge rider in Kansas.

Other Factors Affecting Net Income - Other factors that affected net income for the three months ended March 31, 2021, compared with the same period last year, include a decrease of $5.4 million in other expense, net, due primarily to a $4.9 million reduction in expense resulting from the change in the value of investments associated with nonqualified employee benefit plans.

During the three months ended March 31, 2021 and 2020, we credited income tax expense $8.1 million and $6.9 million, respectively, for the amortization of the regulatory liability associated with EDIT that was returned to customers.

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

Capital expenditures and asset removal costs decreased $14.4 million for the three months ended March 31, 2021, compared with the same period last year, due primarily to the timing of our capital projects in the first quarter 2021, compared with the first quarter 2020. Our capital expenditures and asset removal costs are expected to be $540 million for 2021.

Selected Operating Information - The following tables set forth certain selected operating information for the periods indicated:
Three Months EndedVariances
 March 31,2021 vs. 2020
(in thousands)20212020Increase (Decrease)
Average Number of CustomersOKKSTXTotalOKKS