ONE Gas (OGS) 10-Q 4 May 21 2021 Q1 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2021	Apr. 26, 2021
Document Information [Line Items]
Title of 12(b) Security	Common Stock, par value $0.01 per share
Entity Registrant Name	ONE Gas, Inc.
Entity Incorporation, State or Country Code	OK
Entity Tax Identification Number	46-3561936
Entity Address, Address Line One	15 East Fifth Street
Entity Address, City or Town	Tulsa,
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	74103
City Area Code	(918)
Local Phone Number	947-7000
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Shell Company	false
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		53,245,144
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q1
Document Type	10-Q
Document Quarterly Report	true
Entity Small Business	false
Amendment Flag	false
Document Period End Date	Mar. 31, 2021
Document Transition Report	false
Entity File Number	001-36108
Trading Symbol	OGS
Security Exchange Name	NYSE
Entity Emerging Growth Company	false
Entity Central Index Key	0001587732

STATEMENTS OF INCOME

STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Regulated Operating Revenue	$ 625,293	$ 528,168
Cost of natural gas	314,069	226,139
Operating expenses
Operations and maintenance	110,886	104,839
Depreciation and amortization	52,266	47,513
General taxes	17,727	16,473
Total operating expenses	180,879	168,825
Operating income	130,345	133,204
Other expense, net	(405)	(5,788)
Interest expense, net	(15,440)	(15,693)
Income before income taxes	114,500	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
Weighted Average Number of Shares Outstanding, Basic [Abstract]
Basic	53,372	53,007
Weighted Average Number of Shares Outstanding, Diluted [Abstract]
Diluted	53,515	53,268
Dividends declared per share of stock	$ 0.58	$ 0.54

STATEMENTS OF COMPREHENSIVE INC

STATEMENTS OF COMPREHENSIVE INCOME STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Net income	$ 95,575	$ 91,677
Other comprehensive income (loss), net of tax
Change in pension and postemployment benefit plan liability, net of tax of $(91) and $(74), respectively	300	224
Other comprehensive income, net of tax	300	224
Comprehensive income	95,875	91,901
Pension and other postemployment benefit plans, tax	$ (91)	$ (74)

STATEMENTS OF COMPREHENSIVE I_2

STATEMENTS OF COMPREHENSIVE INCOME STATEMENTS OF COMPREHENSIVE INCOME Parenthetical - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
STATEMENTS OF COMPREHENSIVE INCOME Parenthetical [Abstract]
Pension and other postemployment benefit plans, tax	$ (91)	$ (74)

BALANCE SHEETS

BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Property, plant and equipment
Property, plant and equipment	$ 6,915,000	$ 6,838,603
Accumulated depreciation and amortization	2,004,345	1,971,546
Net property, plant and equipment	4,910,655	4,867,057
Current assets
Cash and cash equivalents	704,911	7,993
Accounts receivable, net	279,591	292,985
Materials and supplies	51,147	52,766
Natural gas in storage	44,321	93,946
Regulatory assets	43,944	56,773
Other current assets	34,757	35,406
Total current assets	1,158,671	539,869
Goodwill and other assets
Regulatory assets	2,346,816	366,956
Goodwill	157,953	157,953
Other assets	105,809	96,877
Total goodwill and other assets	2,610,578	621,786
Total assets	8,679,904	6,028,712
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 Capital	1,755,476	1,756,921
Retained earnings	548,068	483,635
Accumulated other comprehensive loss	(7,477)	(7,777)
Total equity	2,296,599	2,233,311
Long-term debt, excluding current maturities and net issuance costs of $12,976 and $13,159, respectively	4,082,661	1,582,428
Total equity and long-term debt	6,379,260	3,815,739
Commercial Paper	447,000	418,225
Current liabilities
Accounts payable	227,955	152,313
Accrued taxes other than income	65,859	63,800
Regulatory Liability, Current	23,398	15,761
Customer deposits	57,241	68,028
Other current liabilities	57,583	78,952
Total current liabilities	879,036	797,079
Deferred credits and other liabilities
Deferred income taxes	685,901	656,806
Regulatory Liability, Noncurrent	537,129	547,563
Employee benefit obligations	89,860	97,637
Other deferred credits	108,718	113,888
Total deferred credits and other liabilities	1,421,608	1,415,894
Commitments and contingencies
Total liabilities and equity	$ 8,679,904	$ 6,028,712
Common stock, par value per share	$ 0.01	$ 0.01

BALANCE SHEETS BALANCE SHEETS P

BALANCE SHEETS BALANCE SHEETS Parenthetical - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Common stock, par value per share	$ 0.01	$ 0.01
Common stock, shares authorized	250,000,000	250,000,000
Common stock, shares issued	53,245,011	53,166,733
Common stock, shares outstanding	53,245,011	53,166,733
Debt issuance costs	$ 12,976	$ 13,159

STATEMENTS OF CASH FLOWS

STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Operating activities
Net income	$ 95,575	$ 91,677
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	52,266	47,513
Deferred income taxes	18,567	6,856
Share-based compensation expense	2,587	2,261
Provision for doubtful accounts	3,754	3,077
Changes in assets and liabilities:
Accounts receivable	9,640	22,608
Materials and supplies	1,619	2,342
Natural gas in storage	49,625	56,227
Increase (Decrease) in Other Regulatory Assets	(9,885)	(9,888)
Accounts payable	87,202	(34,227)
Accrued taxes other than income	2,059	(1,182)
Customer deposits	(10,787)	285
IncreaseDecreaseInRegulatoryAssetsAndLiabilitiesCurrent	20,466	(3,920)
IncreaseDecreaseInRegulatoryAssetsAndLiabilitiesNonCurrent	1,946,526	(8,852)
Increase (Decrease) in Other Current Assets and Liabilities, Net	(20,698)	(4,575)
Increase (Decrease) in Other Noncurrent Assets and Liabilities, Net	14,729	5,173
Cash provided by operating activities	(1,659,265)	182,733
Investing activities
Capital expenditures	(99,093)	(113,517)
Other	(2,351)	(314)
Proceeds from Sale of Other Assets, Investing Activities	241	650
Cash used in investing activities	(101,203)	(113,181)
Financing activities
Repayments of notes payable, net	28,775	(41,805)
Proceeds from Issuance of Senior Long-term Debt	2,498,895	0
Payments of Debt Issuance Costs	(35,110)	0
Dividends paid	(30,882)	(28,543)
Tax withholdings related to net share settlements of stock compensation	(4,292)	(5,988)
Cash used in financing activities	2,457,386	(76,336)
Change in cash and cash equivalents	696,918	(6,784)
Cash and cash equivalents at beginning of period	7,993	17,853
Cash and cash equivalents at end of period	$ 704,911	$ 11,069

STATEMENT OF CHANGES IN EQUITY

STATEMENT OF CHANGES IN EQUITY - USD ($) $ in Thousands	Total	Common Stock [Member]	Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
Shares issued, beginning balance at Dec. 31, 2019		52,771,749
Equity, beginning balance at Dec. 31, 2019	$ 2,129,390	$ 528	$ 1,733,092	$ 402,509	$ (6,739)
Net income	91,677	0	0	91,677
Other comprehensive income	224	$ 0	0		224
Common stock issued, shares		89,059
Common stock issued, value	(3,736)	$ 1	(3,737)
Common stock dividends - $0.58 and $0.54 per share per quarter as of 2021 and 2020, respectively	(28,543)	$ 0	232	(28,775)
Shares issued, ending balance at Mar. 31, 2020		52,860,808
Equity, ending balance at Mar. 31, 2020	$ 2,189,012	$ 529	1,729,587	465,411	(6,515)
Common Stock, Dividends, Per Share, Declared	$ 0.54
Document Period End Date	Mar. 31, 2021
Shares issued, beginning balance at Dec. 31, 2020	53,166,733	53,166,733
Equity, beginning balance at Dec. 31, 2020	$ 2,233,311	$ 532	1,756,921	483,635	(7,777)
Net income	95,575	0	0	95,575	0
Other comprehensive income	300	$ 0	0	0	300
Common stock issued, shares		78,278
Common stock issued, value	(1,705)	$ 0	(1,705)	0	0
Common stock dividends - $0.58 and $0.54 per share per quarter as of 2021 and 2020, respectively	$ (30,882)	$ 0	260	(31,142)	0
Shares issued, ending balance at Mar. 31, 2021	53,245,011	53,245,011
Equity, ending balance at Mar. 31, 2021	$ 2,296,599	$ 532	$ 1,755,476	$ 548,068	$ (7,477)
Common Stock, Dividends, Per Share, Declared	$ 0.58

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Notes)	3 Months Ended
	Mar. 31, 2021
Significant Accounting Policies [Line Items]
SIGNIFICANT ACCOUNTING POLICIES	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. 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.

REVENUE (Notes)

REVENUE (Notes)	3 Months Ended
	Mar. 31, 2021
Revenue [Policy Text Block]	REVENUE The following table sets forth our revenues disaggregated by source for the periods indicated: Three Months Ended March 31, 2021 2020 (Thousands of dollars) Natural gas sales to customers $ 583,794 $ 480,718 Transportation revenues 36,202 33,757 Miscellaneous revenues 3,655 4,470 Total revenues from contracts with customers 623,651 518,945 Other revenues - natural gas sales related (1,021) 6,547 Other revenues 2,663 2,676 Total other revenues 1,642 9,223 Total revenues $ 625,293 $ 528,168

REGULATORY ASSETS AND LIABILITI

REGULATORY ASSETS AND LIABILITIES (Notes)	3 Months Ended
	Mar. 31, 2021
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Schedule of Regulatory Assets and Liabilities	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 Current Noncurrent Total ( Thousands of dollars ) Winter weather event costs $ — $ 1,992,072 $ 1,992,072 Pension and postemployment benefit costs 16,513 330,037 346,550 Reacquired debt costs 812 4,663 5,475 MGP remediation costs 98 18,687 18,785 Ad-valorem tax 4,834 — 4,834 WNA 628 — 628 Customer credit deferrals 19,453 — 19,453 Other 1,606 ` 1,357 2,963 Total regulatory assets, net of amortization 43,944 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 December 31, 2020 Current Noncurrent Total ( Thousands of dollars ) Under-recovered purchased-gas costs $ 16,502 $ — $ 16,502 Pension and postemployment benefit costs 16,541 341,266 357,807 Reacquired debt costs 812 4,866 5,678 MGP remediation costs 98 18,711 18,809 Ad-valorem tax 5,558 — 5,558 WNA 4,806 4,806 Customer credit deferrals 10,267 10,267 Other 2,189 2,113 4,302 Total regulatory assets, net of amortization 56,773 366,956 423,729 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 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.

CREDIT FACILITIES (Notes)

CREDIT FACILITIES (Notes)	3 Months Ended
	Mar. 31, 2021
Short-term Debt [Line Items]
Short-term Debt [Text Block]	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.

LONG-TERM DEBT (Notes)

LONG-TERM DEBT (Notes)	3 Months Ended
	Mar. 31, 2021
Long-term Debt, Unclassified [Abstract]
Long-term Debt [Text Block]	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. 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.

EQUITY (Notes)

EQUITY (Notes)	3 Months Ended
	Mar. 31, 2021
Class of Stock [Line Items]
Stockholders' Equity Note Disclosure [Text Block]	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.

ACCUMULATED OTHER COMPREHENSIVE

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Notes)	3 Months Ended
	Mar. 31, 2021
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Comprehensive Income (Loss) Note	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 Ended Affected Line Item in the Details About Accumulated Other March 31, Consolidated Statements Comprehensive Loss Components 2021 2020 of 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.

EARNINGS PER SHARE (Notes)

EARNINGS PER SHARE (Notes)	3 Months Ended
	Mar. 31, 2021
EARNINGS PER SHARE [Line Items]
Earnings Per Share [Text Block]	EARNINGS PER SHAREBasic 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. 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 Income Shares Per Share ( 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 Income Shares Per Share ( 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

EMPLOYEE BENEFIT PLANS (Notes)

EMPLOYEE BENEFIT PLANS (Notes)	3 Months Ended
	Mar. 31, 2021
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Employee Benefit Plans (Notes)	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, 2021 2020 ( 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, 2021 2020 ( 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 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.

INCOME TAXES (Notes)

INCOME TAXES (Notes)	3 Months Ended
	Mar. 31, 2021
Income Tax Disclosure [Abstract]
Income Tax Disclosure	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.

OTHER INCOME AND OTHER EXPENSE

OTHER INCOME AND OTHER EXPENSE (Notes)	3 Months Ended
	Mar. 31, 2021
Other Income and Other Expense Disclosure [Text Block]	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, 2021 2020 ( Thousands of dollars ) Net periodic benefit cost other than service cost $ (770) $ (1,123) Earnings (losses) on investments associated with nonqualified employee benefit plans 616 (4,259) Other, net 252 (406) Total other income (expense), net $ (405) $ (5,788)

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Notes)	3 Months Ended
	Mar. 31, 2021
Commitments and Contingencies [Line Items]
COMMITMENTS AND CONTINGENCIES	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 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 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. 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.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS (Notes)	3 Months Ended
	Mar. 31, 2021
Fair Value Disclosures [Abstract]
Fair Value Disclosures	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 - 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. 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.

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	3 Months Ended
	Mar. 31, 2021
Significant Accounting Policies [Line Items]
Use of Estimates	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.
Receivables, Trade and Other Accounts Receivable, Allowance for Doubtful Accounts, Policy [Policy Text Block]	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.
Recently Issued Accounting Standards Update	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.
Segments	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.

DERIVATIVE FINANCIAL INSTRUME_2

DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS (Policies)	3 Months Ended
	Mar. 31, 2021
Accounting Policies [Abstract]
Derivatives	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 - 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 Measurement	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.

REVENUE (Tables)

REVENUE (Tables)	3 Months Ended
	Mar. 31, 2021
Revenues Disaggregated by Source [Table]	The following table sets forth our revenues disaggregated by source for the periods indicated: Three Months Ended March 31, 2021 2020 (Thousands of dollars) Natural gas sales to customers $ 583,794 $ 480,718 Transportation revenues 36,202 33,757 Miscellaneous revenues 3,655 4,470 Total revenues from contracts with customers 623,651 518,945 Other revenues - natural gas sales related (1,021) 6,547 Other revenues 2,663 2,676 Total other revenues 1,642 9,223 Total revenues $ 625,293 $ 528,168

REGULATORY ASSETS AND LIABILI_2

REGULATORY ASSETS AND LIABILITIES (Tables)	3 Months Ended
	Mar. 31, 2021
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES	The tables below present a summary of regulatory assets and liabilities, net of amortization, for the periods indicated: March 31, 2021 Current Noncurrent Total ( Thousands of dollars ) Winter weather event costs $ — $ 1,992,072 $ 1,992,072 Pension and postemployment benefit costs 16,513 330,037 346,550 Reacquired debt costs 812 4,663 5,475 MGP remediation costs 98 18,687 18,785 Ad-valorem tax 4,834 — 4,834 WNA 628 — 628 Customer credit deferrals 19,453 — 19,453 Other 1,606 ` 1,357 2,963 Total regulatory assets, net of amortization 43,944 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 December 31, 2020 Current Noncurrent Total ( Thousands of dollars ) Under-recovered purchased-gas costs $ 16,502 $ — $ 16,502 Pension and postemployment benefit costs 16,541 341,266 357,807 Reacquired debt costs 812 4,866 5,678 MGP remediation costs 98 18,711 18,809 Ad-valorem tax 5,558 — 5,558 WNA 4,806 4,806 Customer credit deferrals 10,267 10,267 Other 2,189 2,113 4,302 Total regulatory assets, net of amortization 56,773 366,956 423,729 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)

ACCUMULATED OTHER COMPREHENSI_2

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)	3 Months Ended
	Mar. 31, 2021
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	The following table sets forth the effect of reclassifications from accumulated other comprehensive loss in our consolidated statements of income for the periods indicated: Three Months Ended Affected Line Item in the Details About Accumulated Other March 31, Consolidated Statements Comprehensive Loss Components 2021 2020 of 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.

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	3 Months Ended
	Mar. 31, 2021
EARNINGS PER SHARE [Line Items]
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	Three Months Ended March 31, 2021 Income Shares Per Share ( 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 Income Shares Per Share ( 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

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	3 Months Ended
	Mar. 31, 2021
Employee Benefit Plans [Line Items]
Schedule of Net Benefit Costs [Table Text Block]	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, 2021 2020 ( 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, 2021 2020 ( 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)

OTHER INCOME AND OTHER EXPENS_2

OTHER INCOME AND OTHER EXPENSE (Tables)	3 Months Ended
	Mar. 31, 2021
Other Income and Other Expense Disclosure	The following table sets forth the components of other income and other expense for the periods indicated: Three Months Ended March 31, 2021 2020 ( Thousands of dollars ) Net periodic benefit cost other than service cost $ (770) $ (1,123) Earnings (losses) on investments associated with nonqualified employee benefit plans 616 (4,259) Other, net 252 (406) Total other income (expense), net $ (405) $ (5,788)

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2021USD ($)	Mar. 31, 2020USD ($)	Dec. 31, 2020USD ($)
Significant Accounting Policies [Line Items]
Number of natural gas distribution services customers	2,200,000
Segment Reporting, Disclosure of Major Customers	no	—
Capital Expenditures Incurred but Not yet Paid	$ 11,600	$ 4,200
Allowance for Doubtful Accounts, Premiums and Other Receivables	$ 19,900		$ 16,600

REVENUE (Details)

REVENUE (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Unbilled Receivables, Current	$ 91,200		$ 144,900
Regulated Operating Revenue, Gas	623,651	$ 518,945
Regulated Operating Revenue, Other	1,642	9,223
Regulated Operating Revenue	625,293	528,168
Natural gas sales to customers [Member]
Regulated Operating Revenue, Gas	583,794	480,718
Transportation revenues [Member]
Regulated Operating Revenue, Gas	36,202	33,757
Miscellaneous revenues [Member]
Regulated Operating Revenue, Gas	3,655	4,470
Other revenues - natural gas sales related [Member]
Other revenues - natural gas sales related	(1,021)	6,547
Other revenues [Member]
Regulated Operating Revenue, Other	$ 2,663	$ 2,676

REGULATORY ASSETS AND LIABILI_3

REGULATORY ASSETS AND LIABILITIES (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Feb. 28, 2021	Dec. 31, 2020
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Kansas Gas Service tax reform regulatory liability				$ 81,500
Regulatory Assets, Current	$ 43,944			56,773
Regulatory Assets, Noncurrent	2,346,816			366,956
Regulatory Liability, Current	(23,398)			(15,761)
Regulatory Liability, Noncurrent	(537,129)			(547,563)
Net regulatory assets (liabilities), current	20,546			41,012
Net regulatory assets (liabilities), noncurrent	1,809,687			(180,607)
Net Regulatory Assets	1,830,233			(139,595)
Reduction in income tax expense for the amortization of the regulatory liability associated with excess ADIT that was returned to customers	8,100	$ 6,900
February 2021 Natural Gas Purchases			$ 2,100,000
Total Deferred Extraordinary Costs from 2021 Winter Weather Event	2,000,000
ONG Deferred Extraordinary Costs from 2021 Winter Storm Uri	1,320,000
KGS Deferred Extraordinary Costs from 2021 Winter Storm Uri	381,000
TGS Deferred Extraordinary Costs from 2021 Winter Storm Uri	295,000
Amortization of Rate Deferral	2,900	$ 1,500
Income tax rate changes [Member] [Domain]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Liability, Current	0			0
Regulatory Liability, Noncurrent	(537,129)			(547,563)
Regulatory Liabilities	(537,129)			(547,563)
Over-recovered purchased-gas costs [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Liability, Current	(23,398)			(15,761)
Regulatory Liability, Noncurrent	0			0
Regulatory Liabilities	(23,398)			(15,761)
Total regulated liabilities [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Liability, Current	(23,398)			(15,761)
Regulatory Liability, Noncurrent	(537,129)			(547,563)
Regulatory Liabilities	(560,527)			(563,324)
Under-recovered purchased-gas costs [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	0			16,502
Regulatory Assets, Noncurrent	1,992,072			0
Regulatory Assets	1,992,072			16,502
Pension and postretirement benefit costs [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	16,513			16,541
Regulatory Assets, Noncurrent	330,037			341,266
Regulatory Assets	346,550			357,807
Reacquired debt costs [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	812			812
Regulatory Assets, Noncurrent	4,663			4,866
Regulatory Assets	5,475			5,678
MGP Costs [Member] [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	98			98
Regulatory Assets, Noncurrent	18,687			18,711
Regulatory Assets	18,785			18,809
Ad valorem tax [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	4,834			5,558
Regulatory Assets, Noncurrent	0			0
Regulatory Assets	4,834			5,558
Other regulatory assets [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	1,606			2,189
Regulatory Assets, Noncurrent	1,357			2,113
Regulatory Assets	2,963			4,302
Total regulatory assets, net of amortization [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	43,944			56,773
Regulatory Assets, Noncurrent	2,346,816			366,956
Regulatory Assets	2,390,760			423,729
Customer credit deferrals
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	19,453			10,267
Regulatory Assets, Noncurrent	0
Regulatory Assets	19,453			10,267
Weather normalization [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	628			4,806
Regulatory Assets, Noncurrent	0
Regulatory Assets	$ 628			$ 4,806

CREDIT FACILITIES (Details)

CREDIT FACILITIES (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2021USD ($)	Dec. 31, 2020USD ($)
Short-term Debt [Line Items]
Line of Credit Facility Sublimit	$ 20,000
Line of Credit Facility Option to Increase Borrowing Capacity	$ 500,000
Ratio of Indebtedness to Net Capital	0.66
Letters of Credit Outstanding, Amount	$ 1,200
Line of Credit Facility, Remaining Borrowing Capacity	998,800
Commercial paper maximum borrowing capacity	700,000
Commercial Paper	447,000	$ 418,225
Bridge Loan	60,000
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,000,000
Approved Debt Capital Ratio	0.725
Approved Debt to Capital Ratio After December 31, 2021	0.70
Line of Credit Facility, Interest Rate Description	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.
Line of Credit [Member]
Short-term Debt [Line Items]
Debt Instrument, Covenant Description	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.

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2021USD ($)
Note Payable Due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Description	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.
Long-term Debt, Gross	$ 300,000
Debt Instrument, Interest Rate, Stated Percentage	3.61%
Notes Payable Due 2044 [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Description	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.
Long-term Debt, Gross	$ 600,000
Debt Instrument, Interest Rate, Stated Percentage	4.658%
Note Payable Due 2048 [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Description	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.
Long-term Debt, Gross	$ 400,000
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Note Payable Due 2030 [Member] [Domain]
Debt Instrument [Line Items]
Debt Instrument, Covenant Description	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.
Note Payable Due 2030 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 300,000
Debt Instrument, Interest Rate, Stated Percentage	2.00%
OGS Note Payable Due 2023
Debt Instrument [Line Items]
Debt Instrument, Covenant Description	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.
Long-term Debt, Gross	$ 800,000
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	0.79%
Debt Instrument, Interest Rate Terms	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).
Debt Instrument, Basis Spread on Variable Rate	0.61%
OGS Note Payable Due 2024 at 1.10 Percent
Debt Instrument [Line Items]
Debt Instrument, Covenant Description	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.
Long-term Debt, Gross	$ 700,000
Debt Instrument, Interest Rate, Stated Percentage	1.10%
Notes Payable at 0.85% Due 2023
Debt Instrument [Line Items]
Debt Instrument, Covenant Description	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.
Long-term Debt, Gross	$ 1,000,000
Debt Instrument, Interest Rate, Stated Percentage	0.85%

EQUITY (Details)

EQUITY (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Jun. 30, 2021	Mar. 31, 2021	Mar. 31, 2020
At-the-Market Equity Program, Aggregate Offering Price Limit		$ 250,000
At-the-Market Equity Program, Equity Available for Issuance		$ 236,400
Common Stock, Dividends, Per Share, Declared		$ 0.58	$ 0.54
Subsequent Event [Member]
Common Stock, Dividends, Per Share, Declared	$ 0.58
Common Stock, Dividends, Declared, Annualized Basis	$ 2.32
Dividends Payable, Date of Record	May 17, 2021
Dividends Payable, Date to be Paid	Jun. 1, 2021

ACCUMULATED OTHER COMPREHENSI_3

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amortization of net loss	$ 11,474	$ 10,623
Amortization of unrecognized prior service cost	(70)	(29)
Reclassification adjustment, before tax and regulatory adjustments	11,404	10,594
Regulatory adjustments	(11,013)	(10,296)
Reclassification adjustment, before tax	391	298
Reclassification adjustment, Tax	(91)	(74)
Reclassification adjustment, net of tax	$ 300	$ 224

EARNINGS PER SHARE (Details)

EARNINGS PER SHARE (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Basic EPS Calculation
Net income available for common stock	$ 95,575	$ 91,677
Weighted Average Number of Shares Outstanding, Basic	53,372	53,007
Earnings Per Share, Basic	$ 1.79	$ 1.73
Diluted EPS Calculation
Net income available for common stock	$ 95,575	$ 91,677
Effect of dilutive securities on income	$ 0	$ 0
Effect of dilutive securities on shares	143	261
Weighted Average Number of Shares Outstanding, Diluted	53,515	53,268
Earnings Per Share, Diluted	$ 1.79	$ 1.72

EMPLOYEE BENEFIT PLANS (Details

EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Employee Benefit Plans [Line Items]
Capitalized non-service cost components as a regulatory asset	$ 6,200		$ 6,000
Components of net periodic benefit cost:
Amortization of unrecognized prior service cost	70	$ 29
Amortization of net loss	(11,474)	(10,623)
ONE Gas Pension Plans [Member]
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
ONE Gas Postretirement Benefit Plans [Member]
Components of net periodic benefit cost:
Service cost	397	423
Interest cost	1,563	1,889
Expected return on assets	(4,202)	(3,867)
Amortization of unrecognized prior service cost	(70)	(29)
Amortization of net loss	93	43
Net periodic benefit cost	$ (2,219)	$ (1,541)

OTHER INCOME AND OTHER EXPENS_3

OTHER INCOME AND OTHER EXPENSE (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Other, net	$ (405)	$ (5,788)
Net periodic cost other than service cost [Member]
Other, net	(770)	(1,123)
Earnings (losses) on investments associated with nonqualified employee benefit plans [Member]
Earnings on Investments Associated with Nonqualified Employee Benefit Plans	616	(4,259)
Other, net [Member]
Other, net	$ 252	$ (406)

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Details) $ in Thousands	Mar. 31, 2021USD ($)	Dec. 31, 2017USD ($)
Commitments and Contingencies [Line Items]
Number Of Former Manufactured Gas Sites Where We Own Or Retain Legal Responsibility For Environmental Conditions	12
Number of sites where regulatory closure has been achieved	3
Number of sites with ongoing groundwater monitoring	8
Percentage yield of high consequence pipeline areas	30.00%
Accrual for Environmental Loss Contingencies	$ 13,700
Deferred MGP Costs, Maximum		$ 15,000
Regulatory Asset for Costs Associated with Manufactured Gas Sites	$ 18,800

DERIVATIVE FINANCIAL INSTRUME_3

DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS (Details)	3 Months Ended
	Mar. 31, 2021USD ($)MMcf	Mar. 31, 2020USD ($)	Dec. 31, 2020USD ($)MMcf
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative, Nonmonetary Notional Amount | MMcf	0		14,700
Premiums recorded in other current assets on natural gas contracts held			$ 6,700,000
Fair Value Assets, Transfers between Levels	$ 0	$ 0
Corporate bonds in other assets	3,600,000		1,600,000
Treasury notes in other assets	3,200,000		3,200,000
Long-term Debt, including current maturities	4,082,661,000		1,582,428,000
Long-term Debt	4,100,000,000		1,600,000,000
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Fair value, natural gas call options			800,000
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Long-term Debt, Fair Value	$ 4,200,000,000		$ 2,000,000,000