10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2022.

OR

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

For the transition period from __________ to __________.

Commission file number  001-36108

ONE Gas, Inc.

(Exact name of registrant as specified in its charter)

Oklahoma		46-3561936
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
15 East Fifth Street
Tulsa,	OK	74103
(Address of principal executive offices)		(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol	Name of exchange on which registered
Common Stock, par value $0.01 per share	OGS	New York Stock Exchange

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

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

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

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

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

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

On October 25, 2022, the Company had 54,141,036 shares of common stock outstanding.

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ONE Gas, Inc.

TABLE OF CONTENTS

Part I.	Financial Information	Page No.
Item 1.	Consolidated Financial Statements (Unaudited)	6
	Consolidated Statements of Income - Three and Nine Months Ended September 30, 2022 and 2021	6
	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2022 and 2021	7
	Consolidated Balance Sheets - September 30, 2022 and December 31, 2021	8
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2022 and 2021	11
	Consolidated Statements of Equity - Three and Nine Months Ended September 30, 2022 and 2021	12
	Notes to Consolidated Financial Statements	14
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46
Item 4.	Controls and Procedures	46
Part II.	Other Information	47
Item 1.	Legal Proceedings	47
Item 1A.	Risk Factors	47
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 3.	Defaults Upon Senior Securities	47
Item 4.	Mine Safety Disclosures	47
Item 5.	Other Information	47
Item 6.	Exhibits	47
Signature		50

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

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

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AVAILABLE INFORMATION

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

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

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GLOSSARY - The abbreviations, acronyms and industry terminology used in this Quarterly Report are defined as follows:

AAO	Accounting Authority Order
ADIT	Accumulated deferred income taxes
Annual Report	Annual Report on Form 10-K for the year ended December 31, 2021
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
Bcf	Billion cubic feet
CAA	Federal Clean Air Act, as amended
CERCLA	Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CISA	Cybersecurity, & Infrastructure Security Agency
Clean Water Act	Federal Water Pollution Control Amendments of 1972, as amended
COSA	Cost-of-Service Adjustment
COVID-19	Coronavirus Disease 2019
EDIT	Excess accumulated deferred income taxes resulting from a change in enacted tax rates
EPA	United States Environmental Protection Agency
EPS	Earnings per share
ESG	Environmental, social and governance
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
GAAP	Accounting principles generally accepted in the United States of America
GRIP	Gas Reliability Infrastructure Program
GSRS	Gas System Reliability Surcharge
HCA(s)	High consequence area(s)
Heating Degree Day or HDD	A measure designed to reflect the demand for energy needed for heating based on the extent to which the daily average temperature falls below a reference temperature for which no heating is required, usually 65 degrees Fahrenheit
IRA of 2022	Inflation Reduction Act of 2022
KCC	Kansas Corporation Commission
KDHE	Kansas Department of Health and Environment
KGSS-I	Kansas Gas Service Securitization I, L.L.C.
LDC	Local distribution company
MAOP(s)	Maximum allowable operating pressure(s)
MGP	Manufactured gas plant
MMcf	Million cubic feet
Moody’s	Moody’s Investors Service, Inc.
NPRM	Notice of Proposed Rulemaking
NYSE	New York Stock Exchange
OCC	Oklahoma Corporation Commission
ODFA	Oklahoma Development Finance Authority
ONE Gas	ONE Gas, Inc.
ONE Gas 2021 Term Loan Facility	ONE Gas’ $2.5 billion two-year unsecured term loan facility, dated February 22, 2021, which terminated on March 11, 2021
ONE Gas 364-day Credit Agreement	ONE Gas’ $250 million 364-day revolving credit agreement, dated April 7, 2020, which terminated on March 16, 2021
ONE Gas Credit Agreement	ONE Gas’ $1.0 billion revolving credit agreement, as amended
PBRC	Performance-Based Rate Change
PHMSA	United States Department of Transportation Pipeline and Hazardous Materials Safety Administration
PIPES Act	Protecting Our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act of 2020
Quarterly Report(s)	Quarterly Report(s) on Form 10-Q
RNG	Renewable natural gas
RRC	Railroad Commission of Texas
S&P	Standard & Poor’s Ratings Services
SEC	Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
Senior Notes	ONE Gas’ registered notes consisting of $250 million of 0.85 percent senior notes due March 2023, $300 million of 3.61 percent senior notes due February 2024, $550 million of 1.10 percent senior notes due March 2024, $300 million of 2.00 percent senior notes due May 2030, $300 million of 4.25 percent senior notes due 2032, $600 million of 4.658 percent senior notes due February 2044 and $400 million of 4.50 percent notes due November 2048
SOFR	Secured Overnight Financing Rate administered by the Federal Reserve Bank of New York
TCEQ	Texas Commission on Environmental Quality
TPFA	Texas Public Finance Authority
TSA	Transportation Security Administration
WNA	Weather normalization adjustment(s)
XBRL	eXtensible Business Reporting Language

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PART I - FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF INCOME
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(Unaudited)	2022		2021		2022		2021
	(Thousands of dollars, except per share amounts)
Total revenues	$	359,363	$	273,923	$	1,759,797	$	1,214,862
Cost of natural gas	126,197		59,399		954,394		467,169
Operating expenses
Operations and maintenance	113,832		105,732		339,506		320,152
Depreciation and amortization	55,234		51,150		167,414		154,288
General taxes	17,048		15,835		52,105		49,999
Total operating expenses	186,114		172,717		559,025		524,439
Operating income	47,052		41,807		246,378		223,254
Other income (expense), net	793		(1,805)		(7,335)		(1,758)
Interest expense, net	(19,551)		(15,392)		(51,466)		(45,828)
Income before income taxes	28,294		24,610		187,577		175,668
Income taxes	(4,593)		(4,357)		(32,867)		(29,746)
Net income	$	23,701	$	20,253	$	154,710	$	145,922
Earnings per share
Basic	$	0.44	$	0.38	$	2.86	$	2.73
Diluted	$	0.44	$	0.38	$	2.85	$	2.72
Average shares (thousands)
Basic	54,310		53,710		54,164		53,516
Diluted	54,482		53,793		54,282		53,618
Dividends declared per share of stock	$	0.62	$	0.58	$	1.86	$	1.74

See accompanying Notes to Consolidated Financial Statements.

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ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(Unaudited)	2022		2021		2022		2021
	(Thousands of dollars)
Net income	$	23,701	$	20,253	$	154,710	$	145,922
Other comprehensive income, net of tax
Change in pension and other postemployment benefit plan liability, net of tax of $(4), $(91), $(33) and $(273), respectively	12		300		111		899
Total other comprehensive income, net of tax	12		300		111		899
Comprehensive income	$	23,713	$	20,553	$	154,821	$	146,821

See accompanying Notes to Consolidated Financial Statements.

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ONE Gas, Inc.
CONSOLIDATED BALANCE SHEETS
	September 30,		December 31,
(Unaudited)	2022		2021
Assets	(Thousands of dollars)
Property, plant and equipment
Property, plant and equipment	$	7,647,792	$	7,274,268
Accumulated depreciation and amortization	2,172,271		2,083,433
Net property, plant and equipment	5,475,521		5,190,835
Current assets
Cash and cash equivalents	10,366		8,852
Accounts receivable, net	192,741		341,756
Materials and supplies	66,966		54,892
Natural gas in storage	343,377		179,646
Regulatory assets	316,131		1,611,676
Other current assets	28,845		27,742
Total current assets	958,426		2,224,564
Goodwill and other assets
Regulatory assets	624,484		724,862
Goodwill	157,953		157,953
Other assets	105,125		103,906
Total goodwill and other assets	887,562		986,721
Total assets	$	7,321,509	$	8,402,120

See accompanying Notes to Consolidated Financial Statements.

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ONE Gas, Inc.
CONSOLIDATED BALANCE SHEETS
(Continued)
	September 30,		December 31,
(Unaudited)	2022		2021
Equity and Liabilities	(Thousands of dollars)
Equity and long-term debt
Common stock, $0.01 par value: authorized 250,000,000 shares; issued and outstanding 54,137,925 shares at September 30, 2022; issued and outstanding 53,633,210 shares at December 31, 2021	$	541	$	536
Paid-in capital	1,833,480		1,790,362
Retained earnings	618,669		565,161
Accumulated other comprehensive loss	(6,416)		(6,527)
Total equity	2,446,274		2,349,532
Long-term debt, excluding current maturities and net of issuance costs of $14,520 and $12,418, respectively	2,429,053		3,683,378
Total equity and long-term debt	4,875,327		6,032,910
Current liabilities
Current maturities of long-term debt	250,012		11
Short-term debt	423,400		494,000
Accounts payable	191,117		258,554
Accrued taxes other than income	73,387		67,035
Regulatory liabilities	38,171		8,090
Customer deposits	62,005		62,454
Other current liabilities	66,572		90,349
Total current liabilities	1,104,664		980,493
Deferred credits and other liabilities
Deferred income taxes	690,146		695,284
Regulatory liabilities	536,612		552,928
Employee benefit obligations	22,151		35,226
Other deferred credits	92,609		105,279
Total deferred credits and other liabilities	1,341,518		1,388,717
Commitments and contingencies
Total liabilities and equity	$	7,321,509	$	8,402,120

See accompanying Notes to Consolidated Financial Statements.

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ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Nine Months Ended
	September 30,
(Unaudited)	2022		2021
	(Thousands of dollars)
Operating activities
Net income	$	154,710	$	145,922
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	167,414		154,288
Deferred income taxes	(21,498)		29,224
Share-based compensation expense	8,286		8,076
Provision for doubtful accounts	3,885		8,128
Proceeds from securitization of winter weather event costs	1,330,582		—
Changes in assets and liabilities:
Accounts receivable	149,533		166,474
Materials and supplies	(12,074)		128
Natural gas in storage	(163,731)		(72,832)
Asset removal costs	(34,386)		(35,195)
Accounts payable	(84,404)		(17,244)
Accrued taxes other than income	6,352		5,574
Customer deposits	(449)		(8,595)
Regulatory assets and liabilities - current	16,324		(273,659)
Regulatory assets and liabilities - noncurrent	60,650		(1,651,445)
Other assets and liabilities - current	(23,051)		(10,537)
Other assets and liabilities - noncurrent	(2,317)		(8,884)
Cash provided by (used in) operating activities	1,555,826		(1,560,577)
Investing activities
Capital expenditures	(412,519)		(347,701)
Other investing expenditures	(2,419)		(3,374)
Other investing receipts	2,695		1,676
Cash used in investing activities	(412,243)		(349,399)
Financing activities
Borrowings (repayments) on short-term debt, net	(70,600)		(82,225)
Issuance of debt, net of discounts	297,591		2,498,895
Long-term debt financing costs	(2,695)		(35,110)
Issuance of common stock	37,104		24,104
Repayment of long-term debt	(1,300,000)		(400,000)
Dividends paid	(100,386)		(92,832)
Tax withholdings related to net share settlements of stock compensation	(3,083)		(4,382)
Cash provided by (used in) financing activities	(1,142,069)		1,908,450
Change in cash and cash equivalents	1,514		(1,526)
Cash and cash equivalents at beginning of period	8,852		7,993
Cash and cash equivalents at end of period	$	10,366	$	6,467

See accompanying Notes to Consolidated Financial Statements.

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ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)	Common Stock Issued	Common Stock		Paid-in Capital
	(Shares)	(Thousands of dollars)
January 1, 2022	53,633,210	$	536	$	1,790,362
Net income	—	—		—
Other comprehensive income	—	—		—
Common stock issued and other	456,607	5		34,135
Common stock dividends - $0.62 per share	—	—		274
March 31, 2022	54,089,817	$	541	$	1,824,771
Net income	—	—		—
Other comprehensive income	—	—		—
Common stock issued and other	47,400	—		5,636
Common stock dividends - $0.62 per share	—	—		271
June 30, 2022	54,137,217	$	541	$	1,830,678
Net income	—	—		—
Other comprehensive income	—	—		—
Common stock issued and other	708	—		2,531
Common stock dividends - $0.62 per share	—	—		271
September 30, 2022	54,137,925	$	541	$	1,833,480
January 1, 2021	53,166,733	$	532	$	1,756,921
Net income	—	—		—
Other comprehensive income	—	—		—
Common stock issued and other	78,278	—		(1,705)
Common stock dividends - $0.58 per share	—	—		260
March 31, 2021	53,245,011	$	532	$	1,755,476
Net income	—	—		—
Other comprehensive income	—	—		—
Common stock issued and other	254,226	3		21,175
Common stock dividends - $0.58 per share	—	—		260
June 30, 2021	53,499,237	$	535	$	1,776,911
Net income	—	—		—
Other comprehensive income	—	—		—
Common stock issued and other	85,089	1		8,324
Common stock dividends - $0.58 per share	—	—		241
September 30, 2021	53,584,326	$	536	$	1,785,476

See accompanying Notes to Consolidated Financial Statements.

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ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF EQUITY
(Continued)
(Unaudited)	Retained Earnings		Accumulated Other Comprehensive Loss		Total Equity
	(Thousands of dollars)
January 1, 2022	$	565,161	$	(6,527)	$	2,349,532
Net income	98,934		—		98,934
Other comprehensive income	—		69		69
Common stock issued and other	—		—		34,140
Common stock dividends - $0.62 per share	(33,559)		—		(33,285)
March 31, 2022	$	630,536	$	(6,458)	$	2,449,390
Net income	32,075		—		32,075
Other comprehensive income	—		30		30
Common stock issued and other	—		—		5,636
Common stock dividends - $0.62 per share	(33,806)		—		(33,535)
June 30, 2022	$	628,805	$	(6,428)	$	2,453,596
Net income	23,701		—		23,701
Other comprehensive income	—		12		12
Common stock issued and other	—		—		2,531
Common stock dividends - $0.62 per share	(33,837)		—		(33,566)
September 30, 2022	$	618,669	$	(6,416)	$	2,446,274
January 1, 2021	$	483,635	$	(7,777)	$	2,233,311
Net income	95,575		—		95,575
Other comprehensive income	—		300		300
Common stock issued and other	—		—		(1,705)
Common stock dividends - $0.58 per share	(31,142)		—		(30,882)
March 31, 2021	$	548,068	$	(7,477)	$	2,296,599
Net income	30,093		—		30,093
Other comprehensive income	—		299		299
Common stock issued and other	—		—		21,178
Common stock dividends - $0.58 per share	(31,163)		—		(30,903)
June 30, 2021	$	546,998	$	(7,178)	$	2,317,266
Net income	20,253		—		20,253
Other comprehensive income	—		300		300
Common stock issued and other	—		—		8,325
Common stock dividends - $0.58 per share	(31,287)		—		(31,046)
September 30, 2021	$	535,964	$	(6,878)	$	2,315,098

See accompanying Notes to Consolidated Financial Statements.

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ONE Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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

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

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

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

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

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

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

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

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

2.REVENUE

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

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

Accrued unbilled natural gas sales revenues at September 30, 2022 and December 31, 2021, were $79.2 million and $183.2 million, respectively, and are included in accounts receivable on our consolidated balance sheets.

3.    REGULATORY ASSETS AND LIABILITIES

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

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

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

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

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

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

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

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

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

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

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

In May 2021, Kansas Gas Service filed a motion in its company-specific docket opened by the KCC, requesting a limited waiver of the penalty provisions of its tariff to eliminate the multipliers in the penalty calculation when calculating the penalties to assess on marketers and individually-balanced transportation customers for their unauthorized natural gas usage during Winter Storm Uri. In October 2021, a nonunanimous settlement agreement was filed with the KCC to reach a resolution on these penalties. Prior to a hearing on the amended settlement in January 2022, all parties reached a unanimous settlement, which was filed with a motion requesting approval of the unanimous settlement. Under the terms of the unanimous settlement, the carrying charge on assessed penalties was reduced to two percent, consistent with the nonunanimous agreement in the financial docket. On March 3, 2022, the KCC issued an order approving the settlement which modified the penalty provisions of Kansas Gas Service’s tariffs and included a carrying charge of two percent on amounts due to Kansas Gas Service. Amounts collected from these penalties will reduce the regulatory asset for the winter weather event, up to $52.6 million. Through September 30, 2022, we have collected $49.4 million of these penalties.

In July 2021, Kansas Gas Service submitted its financial plan to the KCC as required by the company-specific docket opened by the KCC in March 2021. The plan includes a proposal for a newly formed, bankruptcy remote subsidiary of the Company to issue securitized bonds to recover the extraordinary costs resulting from Winter Storm Uri from Kansas Gas Service’s customers. On February 8, 2022, the KCC issued an order approving a unanimous settlement agreement that allows Kansas Gas Service to recover extraordinary costs, net of any penalties recovered from marketers and individually-balanced transportation customers, plus carrying costs, by seeking a financing order from the KCC for the issuance of securitized utility tariff bonds.

On March 31, 2022, Kansas Gas Service submitted its application for a financing order to the KCC as contemplated by the unanimous settlement agreement, requesting approval to issue securitized bonds to recover extraordinary costs resulting from Winter Storm Uri and flexibility to recover the costs. On July 14, 2022, Kansas Gas Service, the KCC Staff and the Citizens’ Utility Ratepayer Board reached a settlement agreement for the issuance of a financing order allowing a newly formed, bankruptcy remote subsidiary of the Company to issue securitized utility tariff bonds in the amount of approximately $328.0 million plus issuance fees. The final amount to be securitized will be provided in the final issuance advice letter. The agreement provides for the issuance of bonds with a scheduled final maturity of between 7 and 10 years with flexibility within that range, if necessary, to achieve a AAA rating. On August 18, 2022, the KCC issued an order approving the agreement and also issued a financing order.

As part of the settlement agreement, we created KGSS-I, a special-purpose, wholly-owned subsidiary of ONE Gas, and filed a registration statement with the SEC, for the purpose of issuing securitized bonds. After the SEC declares the registration statement effective, KGSS-I expects to begin the process to issue the bonds.

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

Texas - Pursuant to securitization legislation enacted in Texas as a result of Winter Storm Uri and a June 2021 RRC Notice to Gas Utilities, Texas Gas Service submitted an application to the RRC on July 30, 2021, for an order authorizing the amount of extraordinary costs for recovery and other such specifications necessary for the issuance of securitized bonds.

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

On February 8, 2022, the RRC issued a single financing order for Texas Gas Service and other natural gas utilities in Texas participating in the securitization process, which included a determination that the approved costs will be collected from customers over a period of not more than 30 years. The TPFA formed the Texas Natural Gas Securitization Finance Corporation, a new independent public authority, that will issue the securitized bonds, which are expected to be issued in the fourth quarter of 2022. At September 30, 2022, Texas Gas Service has deferred approximately $246.7 million in extraordinary costs associated with Winter Storm Uri, which includes $47.8 million attributable to the West Texas service area. Pursuant to the approved settlement order, in January 2022, Texas Gas Service began collecting the extraordinary costs, including carrying costs, associated with Winter Storm Uri attributable to the West Texas service area from those customers.

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

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

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

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

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

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

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

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

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We have received accounting orders in each of our jurisdictions authorizing us to accumulate and defer for regulatory purposes certain incremental costs incurred, including bad debt expenses, and certain lost revenues, net of offsetting expense reductions associated with COVID-19. Pursuant to these orders, the recovery of any net incremental costs and lost revenues will be determined in future rate cases or alternative rate recovery filings in each jurisdiction. For financial reporting purposes, any amounts deferred as a regulatory asset for future recovery under these accounting orders must be probable of recovery. At September 30, 2022, no regulatory assets have been recorded. In Oklahoma, the test period for our recently completed rate case included the impacts of COVID-19 on our cost of service in determining new rates that became effective in November 2021. In addition, annual PBRC filings, including the PBRC filing made in March 2022, allow us to include any impacts from COVID-19 in our test period cost of service to determine the impact on our rates. In Kansas and Texas, we continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable.

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

4.CREDIT FACILITY AND SHORT-TERM DEBT

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

The ONE Gas Credit Agreement provides for a $1.0 billion revolving unsecured credit facility and includes a $20 million letter of credit subfacility and a $60 million swingline subfacility. We can request an increase in commitments of up to an additional

$500 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement is available to provide liquidity for working capital, capital expenditures, acquisitions and mergers, the issuance of letters of credit and for other general corporate purposes.

The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At September 30, 2022, our total debt-to-capital ratio was 56 percent and we were in compliance with all covenants under the ONE Gas Credit Agreement. We may reduce the unutilized portion of the ONE Gas Credit Agreement in whole or in part without premium or penalty. The ONE Gas Credit Agreement contains customary events of default. Upon the occurrence of certain events of default, the obligations under the ONE Gas Credit Agreement may be accelerated and the commitments may be terminated.

At September 30, 2022, we had $1.2 million in letters of credit issued and no borrowings under the ONE Gas Credit Agreement, with $998.8 million of remaining credit, which is available to repay any of our commercial paper borrowings.

In June 2021, we increased the size of our commercial paper program to permit the issuance of commercial paper to fund short-term borrowing needs in an aggregate principal amount not to exceed $1.0 billion outstanding at any time. Prior to this increase, our commercial paper program permitted us to issue commercial paper in an aggregate principal amount not to exceed $700 million outstanding at any time. The maturities of the commercial paper vary but may not exceed 270 days from the date of issue. Commercial paper is generally sold at par less a discount representing an interest factor. At September 30, 2022 and December 31, 2021, we had $423.4 million and $494.0 million of commercial paper outstanding with a weighted-average interest rate of 3.53 percent and 0.38 percent, respectively.

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

5.LONG-TERM DEBT

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

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

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

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

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

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

6.EQUITY

At-the-Market Equity Program - In February 2020, we initiated an at-the-market equity program by entering into an equity distribution agreement under which we may issue and sell shares of our common stock with an aggregate offering price up to $250 million (including any shares of common stock that may be sold pursuant to the master forward sale confirmation entered into in connection with the equity distribution agreement and the related supplemental confirmations). Sales of common stock are made by means of ordinary brokers’ transactions on the NYSE, in block transactions or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common stock under the program. For the nine months ended September 30, 2022 and 2021, we issued and sold 403,792 shares and 281,124 shares of our common stock for $35.0 million and $21.4 million, generating proceeds, net of issuance costs, of $34.7 million and $21.1 million, respectively.

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

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

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

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

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7.ACCUMULATED OTHER COMPREHENSIVE LOSS

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

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

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

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

8.EARNINGS PER SHARE

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

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

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

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

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

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

9.EMPLOYEE BENEFIT PLANS

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

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

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

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

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

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

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

10.INCOME TAXES

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

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

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

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

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

11. OTHER INCOME AND OTHER EXPENSE

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

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

12.COMMITMENTS AND CONTINGENCIES

COVID-19 - Throughout the COVID-19 pandemic, we have continued to provide essential services to our customers. We have implemented a comprehensive set of policies, procedures and guidelines to protect the safety of our employees, customers and communities. See Note 3 for more information regarding the effects of COVID-19 on us.

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Environmental Matters - We are subject to multiple laws and regulations regarding protection of the environment and natural and cultural resources, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, plant and wildlife protection, hazardous materials use, storage and transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits or the discovery of presently unknown environmental conditions may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other regulatory or permitting mandates under the CAA and other similar federal and state laws could require unexpected capital expenditures. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and nine months ended September 30, 2022 and 2021.

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

We have an AAO that allows Kansas Gas Service to defer and seek recovery of costs necessary for investigation and remediation at, and nearby, these 12 former MGP sites that are incurred after January 1, 2017, up to a cap of $15.0 million, net of any related insurance recoveries. Costs approved for recovery in a future rate proceeding would then be amortized over a 15-year period. The unamortized amounts will not be included in rate base or accumulate carrying charges. Following a determination that future investigation and remediation work approved by the KDHE is expected to exceed $15.0 million, net of any related insurance recoveries, Kansas Gas Service will be required to file an application with the KCC for approval to increase the $15.0 million cap. At September 30, 2022, we have deferred $29.9 million for accrued investigation and remediation costs pursuant to our AAO. Kansas Gas Service expects to file an application as soon as practicable after the KDHE approves the plans we have submitted and anticipates that filing will occur in 2023.

We have completed or are addressing removal of the source of soil contamination at all 12 sites and continue to monitor groundwater at seven of the 12 sites according to plans approved by the KDHE. In 2019, we completed a project to remove a source of contamination and associated contaminated materials at the twelfth site where no active soil remediation had previously occurred. Remediation plans concerning various sites were submitted to the KDHE in 2021 and 2020 and the KDHE has provided comments that we are addressing. We are also working on a remediation plan for an additional site that we expect to submit to the KDHE in 2023.

We also own or retain legal responsibility for certain environmental conditions at a former MGP site in Texas. At the request of the TCEQ, we began investigating the level and extent of contamination associated with the site under their Texas Risk Reduction Program. A preliminary site investigation revealed that this site contains contaminants generally associated with MGP sites and is subject to control or remediation under various environmental laws and regulations. Impacts have been identified in the soil and groundwater at the site with limited impacts observed in surrounding areas. On April 14, 2022, we submitted a remediation work plan to address the areas impacted to the TCEQ. At September 30, 2022, estimated costs associated with expected remediation activities for this site are not material.

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and nine months ended September 30, 2022 and 2021. The reserve for remediation of our MGP sites was $13.2 million and $22.8 million at September 30, 2022 and December 31, 2021, respectively. Environmental issues may exist with respect to MGP sites that are unknown to us. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation required, changing technology and governmental regulations, and to the extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition, results of operations or cash flows.

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

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

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

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

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

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

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

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

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

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

13.DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS

Accounting Treatment - We record all derivative instruments at fair value, with the exception of 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 requirements impose a different accounting treatment.

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

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

		Recognition and Measurement
Accounting Treatment		Balance Sheet		Income Statement
Normal purchases and normal sales	-	Fair value not recorded	-	Change in fair value not recognized in earnings
Mark-to-market	-	Recorded at fair value	-	Change in fair value recognized in, and recoverable through, the purchased-gas cost adjustment mechanisms

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

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

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

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

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

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

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

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

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

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

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$2.4 billion and $3.9 billion at September 30, 2022 and December 31, 2021, respectively. The estimated fair value of our long-term debt was determined using quoted market prices, and is classified as Level 2.

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

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and the Notes to Consolidated Financial Statements in this Quarterly Report, as well as our Annual Report. Due to the seasonal nature of our business, the results of operations for the three and nine months ended September 30, 2022 are not necessarily indicative of the results that may be expected for a 12-month period.

RECENT DEVELOPMENTS

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

On August 25, 2022, we called $750 million of the $1.0 billion of 0.85 percent senior notes due March 2023, $150 million of the $700 million of 1.10 percent senior notes due March 2024 and the remaining $400 million of outstanding floating-rate senior notes due March 2023, using the proceeds received from the securitization transaction for Oklahoma Natural Gas. See “Regulatory Activities,” “Liquidity and Capital Resources,” and Note 3 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion of the securitization transaction.

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

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

In March 2021, we issued $1.0 billion of 0.85 percent senior notes due March 2023, $700 million of 1.10 percent senior notes due March 2024, and $800 million of floating-rate senior notes due March 2023. The net proceeds from the issuance were used for payment of gas purchases and related costs resulting from Winter Storm Uri and general corporate purposes. The net proceeds of the March 2021 debt issuance reduced the commitments under the ONE Gas 2021 Term Loan Facility on a dollar-for-dollar basis, and as a result no commitments remained outstanding and the facility was terminated concurrently with the closing of the debt issuance.

In the second quarter of 2021, legislation in Oklahoma, Kansas and Texas was approved that permits utilities to pursue securitization to finance extraordinary expenses, such as fuel costs, incurred during extreme weather events. In August 2022, we received approximately $1.3 billion from the ODFA’s issuance of securitized bonds. We have received approval from our regulators in Kansas and Texas to utilize the securitization legislation in each state to repay or refinance the debt we incurred to finance the extraordinary costs associated with Winter Storm Uri.

See “Regulatory Activities,” “Liquidity and Capital Resources,” and Note 3 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion of the effects of Winter Storm Uri on us.

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

At-the-Market Equity Program - For the nine months ended September 30, 2022, we executed forward sale agreements for shares of our common stock. No shares of common stock have been settled under these forward sale agreements. Had we settled these shares under the forward agreements at September 30, 2022, we would have generated net proceeds of $93.9 million. See “Liquidity and Capital Resources” and Note 6 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion of our at-the-market equity program.

ONE Gas Credit Agreement - On March 16, 2022, we entered into the first amendment to the second amended and restated ONE Gas Credit Agreement, which was previously amended and restated on March 16, 2021. The amendment extends the

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maturity date of the ONE Gas Credit Agreement to March 16, 2027, from March 16, 2026, and amends the ONE Gas Credit Agreement to provide that we may extend the maturity date, subject to the lenders’ consent, by one year two additional times. The amendment also changes the benchmark rate defined in the ONE Gas Credit Agreement to SOFR. All other material terms and conditions of the ONE Gas Credit Agreement remain in full force and effect.

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.

We have received accounting orders in each of our jurisdictions authorizing us to accumulate and defer for regulatory purposes certain incremental costs incurred, including bad debt expenses, and certain lost revenues, net of offsetting expense reductions associated with COVID-19. Pursuant to these orders, the recovery of any net incremental costs and lost revenues will be determined in future rate cases or alternative rate recovery filings in each jurisdiction. For financial reporting purposes, any amounts deferred as a regulatory asset for future recovery under these accounting orders must be probable of recovery. At September 30, 2022, no regulatory assets have been recorded. In Oklahoma, the test period for our recently completed rate case included the impacts of COVID-19 on our cost of service in determining new rates that became effective in November 2021. In addition, annual PBRC filings, including the PBRC filing made in March 2022, allow us to include any impacts from COVID-19 in our test period cost of service to determine the impact on our rates. In Kansas and Texas, we continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable.

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

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

REGULATORY ACTIVITIES

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

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

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

As required, PBRC filings are made annually on or before March 15, until the next general rate case which is required to be filed on or before June 30, 2027. On March 15, 2022, Oklahoma Natural Gas filed its required PBRC application for a calendar year 2021 test year. The filed request includes a $19.7 million base rate revenue increase, $2.3 million energy efficiency incentive, and $9.1 million of estimated EDIT to be credited to customers in 2023. On May 27, 2022, the Public Utility Division (“PUD”) of the OCC filed responsive testimony supporting an increase of $19.6 million. On May 31, 2022, the Office of the Attorney General filed a statement of position supporting PUD’s position. Pursuant to its tariff, Oklahoma Natural Gas placed new rates into effect on July 13, 2022, reflecting a base rate revenue increase of $19.6 million. These rates are subject to refund until approved by the OCC. On August 16, 2022 a stipulation was filed reflecting the $19.6 million increase supported by PUD. On September 29, 2022, a hearing before an administrative law judge was held. At the conclusion of the hearing, the administrative law judge recommended approval of the joint stipulation. An order is expected to be approved in the fourth quarter of 2022.

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As required by OCC rule, on April 6, 2022, Oklahoma Natural Gas filed a request for approval of a demand portfolio of conservation and energy efficiency programs for calendar years 2023-2025. The request includes an annual portfolio of program costs of $17.4 million with an estimated annual utility incentive of $2.6 million. On July 29, 2022, the PUD filed responsive testimony in support of Oklahoma Natural Gas’ filed request. On August 5, 2022, the Attorney General’s office filed a statement of position stating that it did not oppose Oklahoma Natural Gas’s filed request. On September 14, 2022, a joint stipulation and settlement agreement was entered into with the PUD supporting Oklahoma Natural Gas’ request. A hearing was held on October 17, 2022, and the administrative law judge recommended approval of the joint stipulation and settlement agreement. An order is expected to be approved in the fourth quarter of 2022.

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

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

Kansas - In March 2021, the KCC issued an order adopting the KCC staff’s recommendation to open company-specific dockets to accept each utility’s filing of financial impact compliance reports and permit the KCC staff to conduct a review of the utility’s compliance report and its actions during Winter Storm Uri.

In May 2021, Kansas Gas Service filed a motion in its company-specific docket opened by the KCC, requesting a limited waiver of the penalty provisions of its tariff to eliminate the multipliers in the penalty calculation when calculating the penalties to assess on marketers and individually-balanced transportation customers for their unauthorized natural gas usage during Winter Storm Uri. In October 2021, a nonunanimous settlement agreement was filed with the KCC to reach a resolution on these penalties. Prior to a hearing on the amended settlement in January 2022, all parties reached a unanimous settlement, which was filed with a motion requesting approval of the unanimous settlement. Under the terms of the unanimous settlement, the carrying charge on assessed penalties was reduced to two percent, consistent with the nonunanimous agreement in the financial docket. On March 3, 2022, the KCC issued an order approving the settlement which modified the penalty provisions of Kansas Gas Service’s tariffs and included a carrying charge of two percent on amounts due to Kansas Gas Service. Amounts collected from these penalties will reduce the regulatory asset for the winter weather event, up to $52.6 million. Through September 30, 2022, we have collected $49.4 million of these penalties.

In July 2021, Kansas Gas Service submitted its financial plan to the KCC as required by the company-specific docket opened by the KCC in March 2021. The plan includes a proposal for a newly formed, bankruptcy remote subsidiary of the Company to issue securitized bonds to recover the extraordinary costs resulting from Winter Storm Uri from Kansas Gas Service’s customers. On February 8, 2022, the KCC issued an order approving a unanimous settlement agreement that allows Kansas Gas Service to recover extraordinary costs, net of any penalties recovered from marketers and individually-balanced transportation customers, plus carrying costs, by seeking a financing order from the KCC for the issuance of securitized utility tariff bonds.

On March 31, 2022, Kansas Gas Service submitted its application for a financing order to the KCC as contemplated by the unanimous settlement agreement, requesting approval to issue securitized bonds to recover extraordinary costs resulting from Winter Storm Uri and flexibility to recover the costs. On July 14, 2022, Kansas Gas Service, the KCC Staff and the Citizens’ Utility Ratepayer Board reached a settlement agreement for the issuance of a financing order allowing a newly formed, bankruptcy remote subsidiary of the Company to issue securitized utility tariff bonds in the amount of approximately $328.0 million plus issuance fees. The final amount to be securitized will be provided in the final issuance advice letter. The agreement provides for the issuance of bonds with a scheduled final maturity of between 7 and 10 years with flexibility within that range, if necessary, to achieve a AAA rating. On August 18, 2022, the KCC issued an order approving the agreement and also issued a financing order.

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As part of the settlement agreement, we created KGSS-I, a special-purpose, wholly-owned subsidiary of the Company, and filed a registration statement with the SEC, for the purpose of issuing securitized bonds. After the SEC declares the registration statement effective, KGSS-I expects to begin the process to issue the bonds.

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

In August 2022, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $7.8 million related to its GSRS. The KCC has until late December 2022 to issue an order.

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

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

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

Texas - Pursuant to securitization legislation enacted in Texas as a result of Winter Storm Uri and a June 2021 RRC Notice to Gas Utilities, Texas Gas Service submitted an application to the RRC on July 30, 2021, for an order authorizing the amount of extraordinary costs for recovery and other such specifications necessary for the issuance of securitized bonds.

In November 2021, the RRC approved a unanimous settlement agreement between Texas Gas Service, the other natural gas utilities in Texas participating in the securitization process, the staff of the RRC and all intervenors. The settlement agreement provides that all costs incurred by Texas Gas Service to purchase natural gas during Winter Storm Uri were reasonable, necessary and prudently incurred. Texas Gas Service agreed to reduce its regulatory asset amount to be securitized by the amount of extraordinary costs attributable to the West Texas service area, which will be recovered through a separate surcharge over a three-year period.

On February 8, 2022, the RRC issued a single financing order for Texas Gas Service and other natural gas utilities in Texas participating in the securitization process, which included a determination that the approved costs will be collected from customers over a period of not more than 30 years. The TPFA formed the Texas Natural Gas Securitization Finance Corporation, a new independent public authority, that will issue the securitized bonds, which are expected to be issued in the fourth quarter of 2022. At September 30, 2022, Texas Gas Service has deferred approximately $246.7 million in extraordinary costs associated with Winter Storm Uri, which includes $47.8 million attributable to the West Texas service area. Pursuant to the approved settlement order, in January 2022, Texas Gas Service began collecting the extraordinary costs, including carrying costs, associated with Winter Storm Uri attributable to the West Texas service area from those customers.

West Texas Service Area - In March 2022, Texas Gas Service made GRIP filings for all customers in the West Texas service area, requesting a $5.0 million increase to be effective in July 2022. On June 23, 2022, the city of El Paso denied the requested increase and assessed fees associated with its review of the filing. Texas Gas Service appealed the city’s action to the RRC. In August 2022, the RRC approved the appealed rates. All other municipalities, and the RRC, approved the new rates or allowed them to take effect with no action. Texas Gas Service implemented the new rates in July 2022.

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On June 30, 2022, Texas Gas Service filed a rate case seeking to consolidate its West Texas, North Texas and Borger/Skellytown service areas into a single West-North service area and requesting a rate increase of $13.0 million. If approved, new rates are expected to take effect in the first quarter of 2023.

In March 2021, Texas Gas Service made GRIP filings for all customers in the West Texas service area, requesting an increase of $9.7 million to be effective in July 2021. On June 21, 2021, the city of El Paso approved a motion which found the GRIP filing to be in compliance with the GRIP statute. The city subsequently denied the requested increase and assessed fees associated with its review of the filing. On July 2, 2021, Texas Gas Service appealed the city’s action to the RRC. The RRC granted and approved the appeal, and new rates were effective on August 3, 2021. All other municipalities, and the RRC, approved the new rates or allowed them to take effect with no action.

Central-Gulf Service Area - In February 2022, Texas Gas Service made GRIP filings for all customers in the Central-Gulf service area, requesting a $9.1 million increase effective in June 2022. All municipalities, and the RRC, approved the new rates or allowed them to take effect with no action.

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

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

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

In the normal course of business, Texas Gas Service has filed rate cases and sought GRIP and COSA increases in various other Texas jurisdictions to address investments in rate base and changes in expenses. For the nine months ended September 30, 2022, and the year ended December 31, 2021, the impact of these filings was not material.

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

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FINANCIAL RESULTS AND OPERATING INFORMATION

We operate in one reportable business segment: regulated public utilities that deliver natural gas to residential, commercial and transportation customers. The accounting policies for our segment are the same as described in Note 1 of our Notes to Consolidated Financial Statements in our Annual Report. We evaluate our financial performance principally on net income.

Selected Financial Results - For the three months ended September 30, 2022, net income was $23.7 million, or $0.44 per diluted share, compared with $20.3 million, or $0.38 per diluted share, in the same period last year. For the nine months ended September 30, 2022, net income was $154.7 million, or $2.85 per diluted share, compared with $145.9 million, or $2.72 per diluted share, in the same period last year.

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

	Three Months Ended				Nine Months Ended				Three Months				Nine Months
	September 30,				September 30,				2022 vs. 2021				2022 vs. 2021
Financial Results	2022		2021		2022		2021		Increase (Decrease)				Increase (Decrease)
	(Millions of dollars, except percentages)
Natural gas sales	$	322.9	$	241.2	$	1,643.1	$	1,106.7	$	81.7	34	%	$	536.4	48	%
Transportation revenues	28.0		25.3		92.8		87.8		2.7		11	%	5.0		6	%
Other revenues	8.5		7.4		23.9		20.4		1.1		15	%	3.5		17	%
Total revenues	359.4		273.9		1,759.8		1,214.9		85.5		31	%	544.9		45	%
Cost of natural gas	126.2		59.4		954.4		467.2		66.8		112	%	487.2		104	%
Operating costs	130.9		121.5		391.6		370.1		9.4		8	%	21.5		6	%
Depreciation and amortization	55.2		51.2		167.4		154.3		4.0		8	%	13.1		8	%
Operating income	$	47.1	$	41.8	$	246.4	$	223.3	$	5.3	13	%	$	23.1	10	%
Capital expenditures and asset removal costs	$	174.9	$	144.5	$	446.9	$	382.9	$	30.4	21	%	$	64.0	17	%

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

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

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

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

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

Operating income increased $5.3 million for the three months ended September 30, 2022, compared with the same period last year, due primarily to the following:

•an increase of $15.6 million from new rates;

•an increase of $1.3 million in residential sales due primarily to net customer growth in Oklahoma and Texas; and

•a decrease of $1.3 million in bad debt expense.

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These increases were offset partially by:

•an increase of $4.8 million in outside service costs;

•an increase of $4.0 million in depreciation expense due to additional capital expenditures being placed in service; and

•an increase of $2.4 million in employee-related costs, due primarily to higher labor and employee benefit costs.

Operating income increased $23.1 million for the nine months ended September 30, 2022, compared with the same period last year, due primarily to the following:

•an increase of $45.1 million from new rates;

•an increase of $5.4 million in residential sales due primarily to net customer growth in Oklahoma and Texas;

•a decrease of $2.0 million in COVID-19 related expenses; and

•a decrease of $4.2 million in bad debt expense.

These increases were offset partially by:

•an increase of $14.4 million in outside service costs;

•an increase of $13.1 million in depreciation expense due to additional capital expenditures being placed in service; and

•an increase of $5.3 million in employee-related costs, due primarily to higher labor and employee benefit costs.

Other Factors Affecting Net Income - Other factors that affected net income for the three months ended September 30, 2022, compared with the same period last year, include an increase of $2.6 million in other income and an increase of $4.2 million in interest expense. The increase in other income, net, is due primarily to a $2.5 million decrease in net periodic benefit costs other than service costs. The increase in interest expense is due primarily to interest on our commercial paper and the issuance of $300 million of 4.25 percent senior notes in August 2022, compared with the same period last year.

Other factors that affected net income for the nine months ended September 30, 2022, compared with the same period last year, include an increase of $5.6 million in other expense, net, and an increase of $5.6 million in interest expense. The increase in other expense, net, is due primarily to an $11.5 million decrease in the market value of investments associated with our nonqualified employee benefit plans, offset partially by a $5.1 million decrease in net periodic benefit costs other than service costs. The increase in interest expense is due primarily to interest on our commercial paper and the issuance of $300 million of 4.25 percent senior notes in August 2022, compared with the same period last year.

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

Capital Expenditures and Asset Removal Costs - Our capital expenditures program includes expenditures for pipeline integrity, extending service to new areas, increasing system capabilities, pipeline replacements, automated meter reading, government-mandated pipeline relocations, fleet, facilities, IT assets and cybersecurity. It is our practice to maintain and upgrade our infrastructure, facilities and systems to ensure safe, reliable and efficient operations. Asset removal costs include expenditures associated with the replacement or retirement of long-lived assets that result from the construction, development and/or normal use of our assets, primarily our pipeline assets. While we have not experienced a significant impact to our capital expenditures program in the nine months ended September 30, 2022, our capital expenditure activity for the remainder of the year could experience a delay if economic conditions worsen, impacting our supply chain for contract labor, materials and supplies.

Capital expenditures and asset removal costs were $30.4 million and $64.0 million higher for the three and nine months ended September 30, 2022, respectively, compared with the same period last year, due primarily to expenditures for system integrity and extension of service to new areas. Our full-year capital expenditures and asset removal costs are expected to be approximately $650 million for 2022.

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

	Three Months Ended								Variances
	September 30,								2022 vs. 2021
(in thousands)	2022				2021				Increase (Decrease)
Average Number of Customers	OK	KS	TX	Total	OK	KS	TX	Total	OK	KS	TX	Total
Residential	826	587	655	2,068	820	588	650	2,058	6	(1)	5	10
Commercial and industrial	76	50	35	161	75	50	34	159	1	—	1	2
Other	—	—	3	3	—	—	3	3	—	—	—	—
Transportation	5	6	1	12	5	6	1	12	—	—	—	—
Total customers	907	643	694	2,244	900	644	688	2,232	7	(1)	6	12

	Nine Months Ended								Variances
	September 30,								2022 vs. 2021
(in thousands)	2022				2021				Increase (Decrease)
Average Number of Customers	OK	KS	TX	Total	OK	KS	TX	Total	OK	KS	TX	Total
Residential	831	592	656	2,079	824	592	649	2,065	7	—	7	14
Commercial and industrial	77	51	35	163	76	50	35	161	1	1	—	2
Other	—	—	3	3	—	—	3	3	—	—	—	—
Transportation	5	6	1	12	5	6	1	12	—	—	—	—
Total customers	913	649	695	2,257	905	648	688	2,241	8	1	7	16

The increase in the average number of customers for the periods presented is due primarily to the connection of new customers resulting from the extension and expansion of our system in our service areas. For the three months ended September 30, 2022, our average customer count includes approximately 7,200 new customer connections during the period compared to approximately 5,600 for the same period last year. For the nine months ended September 30, 2022, our average customer count includes approximately 19,600 new customer connections during the period compared to approximately 16,900 for the same period last year. For the year ended December 31, 2021, our average customer count included approximately 24,900 new customer connections.

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
Volumes (MMcf)	2022	2021	2022	2021
Natural gas sales
Residential	7,496	6,760	81,936	84,541
Commercial and industrial	4,261	3,539	29,818	27,645
Other	93	270	1,768	1,772
Total sales volumes delivered	11,850	10,569	113,522	113,958
Transportation	50,738	57,647	171,201	174,423
Total volumes delivered	62,588	68,216	284,723	288,381

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

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

	Three Months Ended
	September 30,
	2022		2021		2022 vs. 2021		2022		2021
Heating Degree Days	Actual	Normal	Actual	Normal	Actual Variance		Actual as a percent of Normal
Oklahoma	—	8	—	2	—	%	—	%	—	%
Kansas	14	46	7	46	100	%	30	%	15	%
Texas	—	—	—	—	—	%	—	%	—	%

	Nine Months Ended
	September 30,
	2022		2021		2022 vs. 2021		2022		2021
Heating Degree Days	Actual	Normal	Actual	Normal	Actual Variance		Actual as a percent of Normal
Oklahoma	2,204	2,028	2,319	1,968	(5)	%	109	%	118	%
Kansas	2,945	2,901	2,912	2,901	1	%	102	%	100	%
Texas	1,199	1,049	1,127	1,050	6	%	114	%	107	%

Normal HDDs are established through rate proceedings in each of our jurisdictions for use primarily in weather normalization billing calculations. See further discussion on weather normalization in our Regulatory Overview section in Part 1, Item 1, “Business,” of our Annual Report. Normal HDDs disclosed above are based on:

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

•Kansas - For April 2019 and forward, a 30-year rolling average for years 1988-2017 calculated using three weather stations across Kansas and weighted on HDDs by weather station and customers.

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

Actual HDDs are based on the quarter-to-date weighted average of:

•11 weather stations and customers by month for Oklahoma;

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

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

CONTINGENCIES

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

LIQUIDITY AND CAPITAL RESOURCES

General - We have relied primarily on operating cash flow and commercial paper for our liquidity and capital resource requirements. We fund operating expenses, working capital requirements, including purchases of natural gas other than the extraordinary gas purchases during Winter Storm Uri, and capital expenditures, primarily with cash from operations and commercial paper. Natural gas prices have increased during the nine months ended September 30, 2022, which impacts our investment in natural gas in storage as well as working capital for receivables and payables.

We believe that the combination of the significant residential component of our customer base, the fixed-charge component of our natural gas sales revenues and our rate mechanisms that we have in place result in a stable cash flow profile and historically has generated stable earnings. Additionally, we have rate mechanisms in place in our jurisdictions that reduce the lag in earning

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a return on our capital expenditures and provide for recovery of certain changes in our cost of service by allowing for adjustments to rates between rate cases. We anticipate that our cash flow generated from operations and our expected short- and long-term financing arrangements will enable us to maintain our current and planned level of operations and provide us flexibility to finance our infrastructure investments. Our ability to access capital markets for debt and equity financing under reasonable terms depends on market conditions, our financial condition and credit ratings.

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

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

The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At September 30, 2022, our total debt-to-capital ratio was 56 percent and we were in compliance with all covenants under the ONE Gas Credit Agreement. We may reduce the unutilized portion of the ONE Gas Credit Agreement in whole or in part without premium or penalty. The ONE Gas Credit Agreement contains customary events of default. Upon the occurrence of certain events of default, the obligations under the ONE Gas Credit Agreement may be accelerated and the commitments may be terminated.

In June 2021, we increased the size of our commercial paper program to permit the issuance of commercial paper to fund short-term borrowing needs in an aggregate principal amount not to exceed $1.0 billion outstanding at any time. Prior to this increase, our commercial paper program permitted us to issue commercial paper in an aggregate principal amount not to exceed $700 million outstanding at any time. The maturities of the commercial paper vary but may not exceed 270 days from the date of issue. Commercial paper is generally sold at par less a discount representing an interest factor. At September 30, 2022 and December 31, 2021, we had $423.4 million and $494.0 million of commercial paper outstanding with a weighted-average interest rate of 3.53 percent and 0.38 percent, respectively.

At September 30, 2022, we had $1.2 million in letters of credit issued and no borrowings under the ONE Gas Credit Agreement, with $998.8 million of remaining credit, which is available to repay any of our commercial paper borrowings.

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

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

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

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

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

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

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

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

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

At September 30, 2022, our long-term debt-to-capital ratio was 52 percent.

Credit Ratings - On August 25, 2022, S&P upgraded our debt rating to A- from BBB+ and revised our outlook to stable from positive. Our credit ratings at September 30, 2022, were:

Rating Agency	Rating	Outlook
Moody’s	A3	Stable
S&P	A-	Stable

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

At-the-Market Equity Program - In February 2020, we initiated an at-the-market equity program by entering into an equity distribution agreement under which we may issue and sell shares of our common stock with an aggregate offering price up to $250 million (including any shares of common stock that may be sold pursuant to the master forward sale confirmation entered into in connection with the equity distribution agreement and the related supplemental confirmations). Sales of common stock are made by means of ordinary brokers’ transactions on the NYSE, in block transactions or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common stock under the program. For the nine months ended September 30, 2022 and 2021, we issued and sold 403,792 shares and 281,124 shares of our common stock for $35.0 million and $21.4 million, generating proceeds, net of issuance costs, of $34.7 million and $21.1 million, respectively.

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

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

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

EDIT - The return of EDIT to our customers is not expected to have a material impact on earnings, as any reduction or credit in rates is largely offset by a noncash reduction in income tax expense. However, as a result, cash flows for the three months ended September 30, 2022 and 2021, were reduced by approximately $1.6 million and $1.5 million, respectively, for EDIT returned to customers. Cash flows for the nine months ended September 30, 2022 and 2021, were reduced by approximately $12.5 million and $12.2 million, respectively, for EDIT returned to customers.

Pension and Other Postemployment Benefit Plans - In 2022, our contributions are expected to be $1.5 million to our defined benefit pension plans, and no contributions are expected to be made to our other postemployment benefit plans. We use a December 31 measurement date for our plans. On April 30, 2022, we amended our defined benefit pension plans to change the variable cost of living adjustment for eligible participants to a fixed rate. Accordingly, we remeasured our net benefit obligations as of April 30, 2022, resulting in an adjustment of approximately $7.2 million to our pension expense, net of capitalization and regulatory deferrals, for the year ending December 31, 2022, beginning May 1, 2022.

Information about our pension and other postemployment benefits plans, including anticipated contributions, is included under Note 14 of the Notes to Consolidated Financial Statements in our Annual Report. See Note 9 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.

CASH FLOW ANALYSIS

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

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

	Nine Months Ended
	September 30,				Variance
	2022		2021		2022 vs. 2021
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	1,555.8	$	(1,560.6)	$	3,116.4
Investing activities	(412.2)		(349.4)		(62.8)
Financing activities	(1,142.1)		1,908.5		(3,050.6)
Change in cash and cash equivalents	1.5		(1.5)		3.0
Cash and cash equivalents at beginning of period	8.9		8.0		0.9
Cash and cash equivalents at end of period	$	10.4	$	6.5	$	3.9

Operating Cash Flows - Changes in cash flows from operating activities are due primarily to changes in sales revenues, natural gas costs and operating expenses discussed in Financial Results and Operating Information, the effects of Winter Storm Uri and tax reform discussed in Regulatory Activities and changes in working capital. Changes in natural gas prices and demand for our services or natural gas, whether because of general economic conditions, variations in weather not mitigated by WNAs, changes in supply or increased competition from other service providers, could affect our earnings and operating cash flows. Typically, our cash flows from operations are greater in the first half of the year compared with the second half of the year.

Operating cash flows were higher for the nine months ended September 30, 2022, compared with the prior period, due primarily to recovery of the winter weather event regulatory asset through securitization and increased natural gas purchases in the prior period resulting from Winter Storm Uri, which were deferred and included in regulatory assets. See Note 3 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.

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Investing Cash Flows - Cash used in investing activities increased for the nine months ended September 30, 2022, due primarily to an increase in capital expenditures for system integrity and extension of service to new areas.

Financing Cash Flows - Cash used in financing activities increased for the nine months ended September 30, 2022, compared with the prior period, due primarily to repayment of prior period borrowings to finance natural gas purchases resulting from Winter Storm Uri and the issuance in August 2022 of the $300 million of 4.25 percent senior notes due 2032.

ENVIRONMENTAL, SAFETY AND REGULATORY MATTERS

COVID-19 - See “Recent Developments,” as well as Notes 3 and 12 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion regarding the effects of COVID-19 on us.

Environmental Matters - We are subject to multiple laws and regulations regarding protection of the environment and natural and cultural resources, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, plant and wildlife protection, hazardous materials use, storage and transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits or the discovery of presently unknown environmental conditions may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other regulatory or permitting mandates under the CAA and other similar federal and state laws could require unexpected capital expenditures. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and nine months ended September 30, 2022 and 2021.

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

We have an AAO that allows Kansas Gas Service to defer and seek recovery of costs necessary for investigation and remediation at, and nearby, these 12 former MGP sites that are incurred after January 1, 2017, up to a cap of $15.0 million, net of any related insurance recoveries. Costs approved for recovery in a future rate proceeding would then be amortized over a 15-year period. The unamortized amounts will not be included in rate base or accumulate carrying charges. Following a determination that future investigation and remediation work approved by the KDHE is expected to exceed $15.0 million, net of any related insurance recoveries, Kansas Gas Service will be required to file an application with the KCC for approval to increase the $15.0 million cap. At September 30, 2022, we have deferred $29.9 million for accrued investigation and remediation costs pursuant to our AAO. Kansas Gas Service expects to file an application as soon as practicable after the KDHE approves the plans we have submitted and anticipates that filing will occur in 2023.

We have completed or are addressing removal of the source of soil contamination at all 12 sites and continue to monitor groundwater at seven of the 12 sites according to plans approved by the KDHE. In 2019, we completed a project to remove a source of contamination and associated contaminated materials at the twelfth site where no active soil remediation had previously occurred. A remediation plan concerning this site was submitted to the KDHE in 2020 and the KDHE has provided comments that we are addressing. We are also working on a remediation plan for an additional site that we expect to submit to the KDHE in 2023.

We also own or retain legal responsibility for certain environmental conditions at a former MGP site in Texas. At the request of the TCEQ, we began investigating the level and extent of contamination associated with the site under their Texas Risk Reduction Program. A preliminary site investigation revealed that this site contains contaminants generally associated with MGP sites and is subject to control or remediation under various environmental laws and regulations. Impacts have been identified in the soil and groundwater at the site with limited impacts observed in surrounding areas. On April 14, 2022, we

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submitted a remediation work plan to address the areas impacted to the TCEQ. At September 30, 2022, estimated costs associated with expected remediation activities for this site are not material.

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and nine months ended September 30, 2022 and 2021. The reserve for remediation of our MGP sites was $13.2 million and $22.8 million at September 30, 2022 and December 31, 2021, respectively. Environmental issues may exist with respect to MGP sites that are unknown to us. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation required, changing technology and governmental regulations, and to the extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition, results of operations or cash flows.

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

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

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

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

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

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

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

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

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

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

Climate – The threat of climate change continues to attract considerable attention. International, federal, regional and/or state legislative and/or regulatory initiatives may be proposed in the future to regulate greenhouse gas emissions. We monitor relevant legislation and regulatory initiatives to assess the potential impact on our operations. On August 16, 2022, the IRA of 2022 was signed into law. The IRA of 2022 contains approximately $369 billion in climate funding, largely consisting of tax credits for clean energy. The EPA’s Mandatory Greenhouse Gas Reporting Rule requires annual greenhouse gas emissions reporting as carbon dioxide equivalents from affected facilities and for the natural gas delivered by us to our natural gas distribution customers who are not otherwise required to report their own emissions. The additional cost to gather and report this emission data did not have, and we do not expect it to have, a material impact on our results of operations, financial position or cash flows. In addition, Congress has considered, and may consider in the future, legislation to reduce greenhouse gas emissions, including carbon dioxide and methane. While the IRA of 2022 imposes a charge on methane emissions from certain facilities, the charge does not apply to distribution companies such as ONE Gas. Likewise, the EPA may institute additional regulatory rulemaking associated with greenhouse gas emissions. At this time, no rule or legislation has been enacted for natural gas distribution that assesses any costs, fees or expenses on any of these emissions.

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

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

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

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

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increased utilization of CNG for vehicles. In addition, we are considering potential avenues to incorporate RNG and low-carbon hydrogen into our operations. RNG and low-carbon hydrogen technologies offer potential opportunities to secure lower-carbon supply sources that could be transported on our pipeline system and potentially reduce the carbon intensity of the product we deliver.

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

We continue to assess various opportunities for emission reductions and other potential improvements to our environmental footprint. However, we cannot guarantee that we will be able to implement any of the opportunities that we may review or explore. For any such opportunities that we do choose to implement, we cannot guarantee that we will be able to implement them within a specific timeframe or across all operational assets.

In September 2020, we announced membership in ONE Future, a group of natural gas companies working together to voluntarily reduce methane emissions across the natural gas value chain to one percent or less by 2025. We have submitted our 2020 and 2021 data, which ONE Future aggregates with peer members. In its most recent report, ONE Future stated that its members registered a 2020 methane intensity of 0.424 percent, which surpassed the 2025 goal of 1.0 percent. The intensity for the distribution sector, which includes us, was 0.118 percent, beating the goal of 0.225 percent by 46 percent. Participating distribution companies represented 40 percent of the natural gas delivered in the U.S. in 2020. The report based on 2021 data has not yet been released.

Additional information about our environmental matters is included in the section entitled “Environmental Matters” in Note 12 of the Notes to Consolidated Financial Statements in this Quarterly Report. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation, and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows for the three and nine months ended September 30, 2022 and 2021.

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

IMPACT OF NEW ACCOUNTING STANDARDS

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

ESTIMATES AND CRITICAL ACCOUNTING POLICIES

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

Information about our estimates and critical accounting policies is included under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Estimates and Critical Accounting Policies,” in our Annual Report.

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FORWARD-LOOKING STATEMENTS

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

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

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

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

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

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

•our ability to manage our operations and maintenance costs;

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

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

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

commercial customers;

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

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

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

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

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

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

•operational and mechanical hazards or interruptions;

•adverse labor relations;

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

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

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

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

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

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

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

•changes in inflation and interest rates;

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

•impact of potential impairment charges;

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

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

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

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

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

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

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

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

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

•the sufficiency of insurance coverage to cover losses;

•the effects of our strategies to reduce tax payments;

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

•changes in accounting standards;

•changes in corporate governance standards;

•existence of material weaknesses in our internal controls;

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

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

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

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

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

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our quantitative and qualitative disclosures about market risk are consistent with those discussed in Part II, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, in our Annual Report.

Commodity Price Risk

Our commodity price risk, driven primarily by fluctuations in the price of natural gas, is mitigated by our purchased-gas cost adjustment mechanisms through which we pass-through natural gas costs to our customers without profit. We may use derivative instruments to economically hedge the cost of a portion of our anticipated natural gas purchases during the winter heating months to reduce the impact on our customers of upward market price volatility of natural gas. Additionally, we inject natural gas into storage during the summer months, when natural gas prices are typically lower, and withdraw the natural gas during the winter heating season. Gains or losses associated with these derivative instruments and storage activities are included in, and recoverable through our purchased-gas cost adjustment mechanisms, which are subject to review by regulatory authorities.

Interest-Rate Risk

We are exposed to interest-rate risk primarily associated with commercial paper borrowings and new debt financing needed to fund capital requirements, including future contractual obligations and maturities of long-term and short-term debt. We may manage interest-rate risk on future borrowings through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps. Fixed-rate swaps may be used to reduce our risk of increased interest costs during periods of rising interest rates. Floating-rate swaps may be used to convert the fixed rates of long-term borrowings into short-term variable rates.

Counterparty Credit Risk

We assess the creditworthiness of our customers. Those customers who do not meet minimum standards are required to provide security, including deposits and other forms of collateral, when appropriate and allowed by tariff. With approximately 2.3 million customers across three states, we are not exposed materially to a concentration of credit risk. We maintain a provision for doubtful accounts based upon factors surrounding the credit risk of customers, historical trends, consideration of the current credit environment and other information. We are able to recover the fuel-related portion of bad debts through our purchased-gas cost adjustment mechanisms.

ITEM 4.CONTROLS AND PROCEDURES

Quarterly Evaluation of Disclosure Controls and Procedures - Our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer) have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report based on the evaluation of the controls and procedures required by Rules 13(a)-15(b) of the Exchange Act.

Changes in Internal Control Over Financial Reporting - There have been no changes in our internal control over financial reporting during the third quarter ended September 30, 2022, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

ITEM 1.    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 final outcome of such matters will not have a material adverse effect on our results of operations, financial position or cash flows.

ITEM 1A.    RISK FACTORS

Our investors should consider the risks set forth in Part I, Item 1A, Risk Factors, of our Annual Report that could affect us and our business. Although we have tried to discuss key factors, our investors need to be aware that other risks may prove to be important in the future. New risks may emerge at any time, and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors should carefully consider the discussion of risks and the other information included or incorporated by reference in this Quarterly Report, including “Forward-Looking Statements,” which are included in Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Not applicable.

ITEM 3.    DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM 4.    MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.    OTHER INFORMATION

On July 18, 2022, our Board of Directors amended and restated our Deferred Compensation Plan for Non-Employee Directors to provide for deferral of phantom stock units in a lump sum or annual installments over a specified number of years, revise the subsequent election provisions, and make certain administrative and compliance revisions. The description of our Deferred Compensation Plan for Non-Employee Directors, as amended to date, is qualified in its entirety by reference to the full text of such plan, which is attached hereto or incorporated by reference as Exhibit 10.3.

ITEM 6.    EXHIBITS

Readers of this report should not rely on or assume the accuracy of any representation or warranty or the validity of any opinion contained in any agreement filed as an exhibit to this Quarterly Report, because such representation, warranty or opinion may be subject to exceptions and qualifications contained in separate disclosure schedules, may represent an allocation of risk between parties in the particular transaction, may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes, or may no longer continue to be true as of any given date. All exhibits attached to this Quarterly Report are included for the purpose of complying with requirements of the SEC. Other than the certifications made by our officers pursuant to the Sarbanes-Oxley Act of 2002 included as exhibits to this Quarterly Report, all exhibits are included only to provide information to investors regarding their respective terms and should not be relied upon as constituting or providing any factual disclosures about us, any other persons, any state of affairs or other matters.

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The following exhibits are filed as part of this Quarterly Report:

Exhibit No.		Exhibit Description
	3.1	Amended Certificate of Incorporation of ONE Gas, Inc., dated May 24, 2018 (incorporated by reference to Exhibit 3.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on May 30, 2018 (File No. 1-36108)).
	3.2	Amended and Restated By-Laws of ONE Gas, Inc. dated April 27, 2020 (incorporated by reference to Exhibit 3.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on April 27, 2020 (File No. 1-36108)).
	4.1	Sixth Supplemental Indenture, dated as of August 8, 2022, between ONE Gas, Inc. and U.S. Bank Trust Company, National Association, as trustee, with respect to the 4.25% Notes due 2032 (incorporated by reference to Exhibit 4.2 of ONE Gas Inc.’s Current Report on Form 8-K filed on August 8, 2022 (File No. 1-36108)).
	10.1	Underwriting Agreement, dated August 4, 2022, between ONE Gas, Inc., and RBC Capital Markets, LLC, Truist Securities, Inc., and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein (incorporated by reference to Exhibit 1.1 of ONE Gas Inc.’s Current Report on Form 8-K filed on August 8, 2022 (File No. 1-36108)).
	10.2	Securitization Property Purchase and Sale Agreement dated as of August 25, 2022 by and between the Oklahoma Development Finance Authority, as Issuer, and Oklahoma Natural Gas Company, a division of ONE Gas, Inc., as Seller (incorporated by reference to Exhibit 10.1 of ONE Gas Inc.’s Current Report on Form 8-K filed on August 26, 2022 (File No. 1-36108)).
	10.3	ONE Gas, Inc. Deferred Compensation Plan for Non-Employee Directors, amended and restated effective July 18, 2022.
	31.1	Certification of Robert S. McAnnally pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2	Certification of Caron A. Lawhorn pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32.1	Certification of Robert S. McAnnally pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).
	32.2	Certification of Caron A. Lawhorn pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).

101.INS	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH	XBRL Schema Document.
101.CAL	XBRL Calculation Linkbase Document.
101.LAB	XBRL Label Linkbase Document.
101.PRE	XBRL Presentation Linkbase Document.
101.DEF	XBRL Extension Definition Linkbase Document.
104	Cover Page Interactive Data File (embedded within the Inline XBRL document and contained in Exhibit 101).

Attached as Exhibit 101 to this Quarterly Report are the following XBRL-related documents: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three and nine months ended months ended September 30, 2022 and 2021; (iii) Consolidated Statements of Comprehensive Income for the three and nine months ended months ended September 30, 2022 and 2021; (iv) Consolidated Balance Sheets at September 30, 2022 and December 31, 2021; (v) Consolidated Statements of Cash Flows for the nine months ended September 30, 2022 and 2021; (vi) Consolidated Statements

48

of Equity for the three and nine months ended months ended September 30, 2022 and 2021; and (vii) Notes to Consolidated Financial Statements.

We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report.

49

SIGNATURE

Pursuant to the requirements of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: November 1, 2022		ONE Gas, Inc.
		Registrant
	By:	/s/ Caron A. Lawhorn
		Caron A. Lawhorn
		Senior Vice President and
		Chief Financial Officer
		(Principal Financial Officer)

50

EX-10.3

ONE GAS, INC. DEFERRED COMPENSATION PLAN FOR NON-EMPLOYEE DIRECTORS Effective July 18, 2022 ARTICLE I ESTABLISHMENT OF PLAN The Board of Directors of ONE Gas, Inc., an Oklahoma corporation (the "Company"), on February 18, 2014, established this ONE Gas, Inc. Deferred Compensation Plan for Non- Employee Directors (the "Plan), a non-qualified deferred compensation plan pursuant to which any Director of the Company who is not an officer or present employee of the Company, and who is in a position to contribute to its continued growth, development and future financial success, may be offered an opportunity to defer all or a portion of his/her compensation under terms and conditions that will represent a meaningful benefit to such Director. The Plan is hereby amended and restated effective July 18, 2022. Amounts deferred for calendar years beginning prior to the restated effective date will continue to be paid in accordance with the Elections and Plan terms under which the amounts were deferred, except to the extent the time and form of payment are changed by the Participant or the Company in accordance with this Plan restatement. ARTICLE II PURPOSE The purpose of the Plan is to improve the Company's ability to attract and retain Non- Employee Directors who will contribute to the overall success of the Company. ARTICLE III DEFINITIONS "Beneficiary" shall mean any person designated by a Participant on a form furnished by the Plan Administrator. "Board" shall mean the Board of Directors of the Company. "Cash Deferral Option" shall mean the deferral option specified in Article IX of the Plan. "Code" shall mean the Internal Revenue Code of 1986, as amended. "Committee" shall mean the Executive Compensation Committee of the Board. "Common Stock" shall mean the $0.01 par value common stock of the Company.

2 "Company" shall mean ONE Gas, Inc., an Oklahoma corporation, or any successor thereto. "Deferred Compensation" shall mean Director Compensation that is deferred by a Non- Employee Director pursuant to this Plan. "Deferred Compensation Account" shall mean the deferred compensation account created by the Company which is payable to a participating Non-Employee Director under the Plan. "Deferred Compensation Agreement" shall mean a written agreement to defer compensation as described in Article VII of the Plan. "Determination Date" shall mean the last day of a Participant's term of service as a Non- Employee Director. "Director" shall mean a member of the Board. "Director Annual Cash Retainer Fee" shall mean an annual retainer fee paid in cash by the Company to a Non-Employee Director for service in or for a Plan Year. "Director Annual Stock Retainer Fee" shall mean an annual retainer fee paid in Common Stock by Company to a Non-Employee Director for service in or for a Plan Year. “Director Annual Chairman of the Board Cash Retainer Fee” shall mean an annual retainer fee paid in cash by the Company to a Non-Employee Director for service as the chairperson of the Board in or for a Plan Year. "Director Annual Committee Chair Cash Retainer Fee" shall mean an annual retainer fee paid in cash by the Company to a Non-Employee Director for service as the chairperson of a committee of the Board in or for a Plan Year. “Director Annual Lead Director Cash Retainer Fee” shall mean an annual retainer fee paid in cash by the Company to a Non-Employee Director for service as the lead independent director of the Board in or for a Plan Year. "Director Compensation" shall mean the compensation paid or payable to an individual for his/her services as a Non-Employee Director. “Director Retainer Fees” means the Director annual retainer fees defined herein. "Director Services Fee" shall mean such other fees or compensation as the Company may pay to a Non-Employer Director, in cash or in Common Stock, in lieu of or in addition to Director Retainer Fees. "Disabled" and/or "Disability" shall mean that a Participant is unable to engage in substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, or is, by reason of any medically determinable physical or mental impairment which can be expected to result in death or expected to last for a continuous period of

3 not less than twelve (12) months, receiving income replacement benefits for a period of not less than three (3) months under an accident or health plan covering employees of any employer by whom such participant is employed. A Participant will be deemed to be Disabled if such Participant is determined to be totally disabled by the Social Security Administration. "Distributable Balance" shall mean the balance of a Participant's Deferred Compensation Account on the Determination Date as provided in paragraph XI of the Plan. "Distribution Date" shall mean the date specified by a Participant in his or her Election or Subsequent Election for all or a portion of such Participant’s Deferred Compensation Account to be paid or commence payment, as permitted by Section 409A, the Treasury Regulations and other guidance promulgated or issued thereunder. "Dividend Reinvestment Plan" means the dividend reinvestment plan established and maintained by or for the Company with respect to Common Stock. "Election" shall mean an irrevocable written election to defer Director Compensation made by a Non-Employee Director pursuant to the Plan that shall specify the time and form of distribution of the Deferred Compensation. "Employee" shall mean an individual who is employed by the Company or any subsidiary or affiliate thereof. "Equity Compensation Plan" shall mean the ONE Gas, Inc. Amended and Restated Equity Compensation Plan (2018), as amended from time to time. "Fair Market Value" shall mean on a particular date the average of the high and low sale prices of a share of Common Stock in consolidated trading on the date in question as reported by The Wall Street Journal or another reputable source designated by the Committee; provided that if there were no sales on such date reported as provided above, the respective prices on the most recent prior day for which a sale was so reported. "Investment Return Rate" shall mean the deemed investment rate of return to be credited to a Participant's Deferred Compensation Account pursuant to Articles X and XI of the Plan. “Measurement Date” shall mean the regular payment date of the Director Compensation, as applicable. "Non-Employee Director" shall mean any Director who is not also an Employee of the Company. "Participant" shall mean any Non-Employee Director of the Company who elects to defer compensation under the Plan. "Phantom Stock Option" shall mean the deferral option specified in Article IX of the Plan. “Phantom Stock Unit” shall mean the right to receive one share of Common Stock, subject to the terms and conditions set forth in this Plan.

4 "Plan" shall mean this ONE Gas, Inc. Deferred Compensation Plan for Non-Employee Directors as set forth in its entirety in this document as it may be amended from time to time. "Plan Administrator" shall mean the Executive Compensation Committee of the Board or any other committee appointed by the Board to act in that capacity. "Plan Year" shall mean the calendar year. "Section 409A" shall mean section 409A of the Code. "Subsequent Election" shall mean an irrevocable written election made by a Participant to delay the time of distribution or change the form of payment for all or a portion of the Participant’s Deferred Compensation that is made at any time after the initial Election and Deferred Compensation Agreement with respect to such Deferred Compensation. ARTICLE IV EFFECTIVE DATE The Plan was adopted, established and effective February 18, 2014. The Plan is hereby amended and restated effective July 18, 2022. ARTICLE V ELIGIBILITY All Non-Employee Directors of the Company shall be eligible to participate in the Plan. ARTICLE VI NON-EMPLOYEE DIRECTOR COMPENSATION DEFERRAL Non-Employee Directors of the Company are customarily paid annual Director Compensation by the Company in the form of Director Retainer Fees. The Company may from time to time pay other kinds or amounts of compensation to Non-Employee Directors of the Company. The Plan allows the Non-Employee Directors to elect to defer all, part, or none of their Director Compensation, and to have two (2) deemed investment options, either the Cash Deferral Option or the Phantom Stock Option, from which to choose as more specifically provided below. ARTICLE VII ELECTION TO DEFER DIRECTOR COMPENSATION A. Participant Elections. The Plan is a voluntary participation plan, pursuant to which a Non-Employee Director may make an Election to defer all or a portion of his/her Director Compensation for a Plan Year by written instrument filed with the Committee in such form as it may prescribe, subject to the following: 1. An Election and Deferred Compensation Agreement by a Non-Employee Director to defer his/her Director Compensation for services performed during a Plan Year shall be made no later than December 31 of the preceding Plan Year.

5 2. A separate Election and Deferred Compensation Agreement shall be made for each Plan Year that a Non-Employee Director elects to defer his/her Director Compensation under the Plan; provided, however, if a Non-Employee Director has made an Election and Deferred Compensation Agreement for a Plan Year, such Election and Deferred Compensation Agreement shall remain in effect and be irrevocable for subsequent Plan Years if a new and separate Election and Deferred Compensation Agreement is not made and entered into on or before December 31 of the preceding Plan Year. 3. In the case of the first Plan Year in which a Non-Employee Director becomes eligible to participate in the Plan, the Non-Employee Director may make an initial Election and Deferred Compensation Agreement within thirty (30) days after the date the Non-Employee Director became eligible to participate in the Plan, with respect to Director Compensation payable for services performed after the date of such Election and Deferred Compensation Agreement. Any such initial Election shall be effective for the Plan Year in which it is made, and thereafter such new Non-Employee Director shall make his/her Election to defer for subsequent Plan Years pursuant to Article VII, paragraph A.1. 4. A Non-Employee Director who is to participate in the Plan and defer Director Compensation must elect the amount, if any, to be deferred, the type of deferral option, and the time and form of payment, all of which are more specifically described below. B. Participant Subsequent Elections. A Participant may make a Subsequent Election for Deferred Compensation by written instrument filed with the Committee in such form as it may prescribe, subject to the following: 1. A Subsequent Election must satisfy the following requirements: a. The Subsequent Election shall not take effect until at least twelve (12) months after the date on which it is made. b. In the case of a Subsequent Election related to a payment to be made upon separation from service of a Participant, at a specified time or pursuant to a fixed schedule, the payment with respect to which the Subsequent Election is made shall be deferred for a period of not less than five (5) years from the date such payment would otherwise have been made (or in the case of installment payments, five (5) years from the date the first amount was scheduled to be paid). c. Any Subsequent Election related to a payment at a specified time or pursuant to a fixed schedule may not be made less than twelve (12) months prior to the date the payment is scheduled to be paid (or in the case of installment payments, twelve (12) months before the date the first amount was scheduled to be paid). 2. A Subsequent Election that fails to comply with the provisions of Section 409A and the Treasury Regulations thereunder shall be void and not allowed under the Plan.

6 3. A Participant who has made a Subsequent Election under the Plan shall be allowed to make another Subsequent Election with respect to the same Deferred Compensation, in accordance with this Article VII., paragraph B., and other provisions of the Plan. 4. Notwithstanding the foregoing provisions, the Committee, in its sole discretion, shall be authorized to determine, from time to time and/or in the particular case of any one or more Participants, that a Subsequent Election is not allowed to be made. ARTICLE VIII AMOUNT OF DEFERRAL; DIRECTOR COMPENSATION DEFERRALS A. Deferral Amounts. A Non-Employee Director who elects to participate in the Plan, may defer all, a portion or none of the following types of Director Compensation for a Plan Year, as applicable: 1. Director Annual Stock Retainer Fee 2. Director Annual Cash Retainer Fee 3. Director Annual Committee Chair Cash Retainer Fee 4. Director Annual Chairman of the Board Cash Retainer Fee 5. Director Annual Lead Director Cash Retainer Fee 6. Any other Director Services Fees B. Designation. The deferral of Director Compensation shall be designated in the Non-Employee Director’s Election as a percentage of the form and amount of the type of Director Compensation to which it applies. ARTICLE IX DEFERRAL OPTIONS A. Deferral Options. A Non-Employee Director who makes an Election to defer his/her Director Compensation for a Plan Year may elect either: 1. A Cash Deferral Option; or 2. A Phantom Stock Option. All amounts deferred are subject to the terms of the option elected. The Election shall be made as part of the Election procedure described in Article VII, above. B. Cash Deferral Option. Under the Cash Deferral Option, a participating Non- Employee Director may elect to defer all or a portion of their eligible Director Compensation payable in cash. Interest will accrue at the rate defined in Article X, below.

7 C. Phantom Stock Option 1. Under the Phantom Stock Option, a participating Non-Employee Director may elect to defer and convert to Phantom Stock Units all or a portion of their eligible Director Compensation. 2. The Director Compensation deferred under the Phantom Stock Option shall be converted into Phantom Stock Units as of the Measurement Date. The number of Phantom Stock Units credited to the Participant’s Deferred Compensation Account as a result of the conversion shall be determined by dividing the dollar amount of the Director Compensation being converted by the Fair Market Value of a share of Common Stock on the Measurement Date. 3. Fractional Phantom Stock Units will be accounted for as non-interest bearing cash based on the Fair Market Value of a share of Common Stock. 4. Dividend reinvestment attributable to such Phantom Stock Units shall be credited as provided in Article X, below. ARTICLE X DEFERRED COMPENSATION ACCOUNT A. General. The Company shall establish a separate Deferred Compensation Account for each Non-Employee Director who becomes a Participant in the Plan and elects to defer Director Compensation under the Plan and shall credit such Deferred Compensation Account with the Director Compensation deferred by the Non-Employee Director. B. Interest Rate. The amount deferred under the Cash Deferral Option (including interest earned thereon) will earn interest at the Investment Return Rate determined annually by the Committee which shall be the Moody’s Bond Indices Corporate AAA, or comparable index on the first business day of the Plan Year, plus 100 basis points. Interest will be credited quarterly (on the 1st day of April, July, October and January) at the applicable Investment Return Rate. C. Deemed Dividends. The Deferred Compensation Account of a Non-Employee Director who has elected the Phantom Stock Option, shall have phantom or deemed "dividends" on the Phantom Stock Units in his/her Deferred Compensation Account credited to such account in an amount equal to the dividends paid on Common Stock. The deemed dividend equivalent received will be treated in a manner similar to the treatment of dividends under the Dividend Reinvestment Plan when a Participant therein elects to have dividends reinvested in Common Stock, and will be deemed to be used to purchase additional Phantom Stock Units based on the closing price of the Common Stock on the date the Common Stock dividend is paid. Any fractional Phantom Stock Units will be accounted for as non-interest bearing cash based on the Fair Market Value of a share of Common Stock. The Deferred Compensation Account shall also be adjusted for any stock dividends, stock splits, etc. In the event the Dividend Reinvestment Plan is modified in any way, such deemed dividends credited through this Plan will be handled in accordance with said modification. If the Dividend Reinvestment Plan is terminated, such deemed dividends credited through this Plan will continue to be reinvested in accordance with the provisions of the terminated Dividend Reinvestment Plan.

8 D. Amount of Account. The amount equal to the balance in the Deferred Compensation Account of the Participant, taking into account all credits, shall be the amount a Participant shall be entitled to receive under the terms of the Plan; provided, that with respect to all deferrals converted to Phantom Stock Units, the Phantom Stock Units will be settled in shares of Common Stock made available under the Equity Compensation Plan. E. Statement of Account. The Company shall furnish or cause to be furnished to each Participant in the Plan an annual statement of his/her Deferred Compensation Account. ARTICLE XI DISTRIBUTIONS AND PAYMENTS A. Requirements for Distributions and Payments. Notwithstanding anything to the contrary expressed or implied herein, the following requirements shall apply to the Plan, to all Elections or Subsequent Elections made by Participants under the Plan, and to all distributions and payments made pursuant to the Plan. 1. Any compensation deferred under the Plan shall not be distributed earlier than: a. separation from service of the Participant, b. the date the Participant becomes Disabled, c. death of the Participant, or d. a specified time (or pursuant to a fixed schedule) specified under the Plan at the date of deferral of such compensation. 2. No acceleration of the time or schedule of any distribution or payment under the Plan shall be permitted or allowed, except to the extent provided in Treasury Regulations issued under Section 409A. 3. If a Subsequent Election is made pursuant to the Plan, payment shall be made or commence on the Distribution Date specified in such Subsequent Election. If a Subsequent Election changes the form of payment, the form of payment must be a form of payment otherwise permitted under this Plan. B. Distribution Options. Participants shall specify a time and form of payment in their Election for their Deferred Compensation covered by the Election (including any interest or deemed dividends attributable thereto), in accordance with the following: 1. Participants may elect for payment to be made (or commence, in the case of installments) on their Determination Date or a Distribution Date following their Determination Date; provided that, the Participant must select from among the available Distribution Date(s) designated by the Committee and set forth in the Election.

9 2. With respect to the Cash Deferral Option, Participants may elect for payment to be made in a lump sum or in monthly installments over a specified number of years; provided that, if the Participant elects to have amounts paid in installments, the Participant must select from among the permissible installment schedules selected by the Committee and set forth in the Election. Payments under the Cash Deferral Option shall be made in cash. 3. With respect to the Phantom Stock Option, Participants may elect for payment to be made in a lump sum or annual installments over a specified number of years; provided that, if the Participant elects to have amounts paid in installments, the Participant must select from among the permissible installment schedules selected by the Committee and set forth in the Election. Payments under the Phantom Stock Option shall be paid in shares of Common Stock, except for fractional Phantom Stock Units, which shall be paid in cash based on the Fair Market Value of a share of Common Stock on the payment date. 4. In the absence of a valid Election with respect to the time and form of payment, amounts will be paid in a lump sum on the Participant’s Determination Date. C. Distributable Balance; Cash Deferral Option. The Distributable Balance in the Deferred Compensation Account of a Participant for any deferrals under the Cash Deferral Option is the cash balance of such Deferred Compensation Account at the Participant's Determination Date. D. Distributable Balance; Phantom Stock Option. The Distributable Balance in the Deferred Compensation Account of a Participant for any deferrals under the Phantom Stock Option shall be the number of shares of Common Stock equal to the number of Phantom Stock Units plus any cash amounts held in respect of fractional Phantom Stock Units at the Participant’s Determination Date. E. Valuation. At the Determination Date of a Participant, such Participant's Deferred Compensation Account Distributable Balance for all Plan Years shall be valued. From that Determination Date forward, any remaining cash balance in the Participant’s Deferred Compensation Account (e.g., balance during the time of installment payments) shall bear interest at the Investment Return Rate and any remaining Phantom Stock Unit balance shall continue to be credited with "dividends" as provided in Article X, paragraph C above. In the event a Participant elects payment of all or a portion of the Participant's Deferred Compensation Account in installments, each installment shall be calculated by dividing that portion of the Deferred Compensation Account which is payable in installments by the number of installments remaining as of such date. With respect to installments payable in shares of Common Stock, the resulting number of shares of Common Stock to be distributed shall be rounded down to the next whole number, except that the final installment shall be rounded up to the next whole number. That part of the Participant's Deferred Compensation Account that consists of Phantom Stock Units and phantom dividends, which is payable in shares of Common Stock, shall be issued to the Participants under the Company's Equity Compensation Plan on the Distribution Date, and in the form, elected by the Participant. F. Distribution; Disability or Death of Participant. Distribution of a Participant's Distributable Balance shall commence immediately upon the occurrence of the Disability or death of the Participant, if such event occurs prior to the Distribution Date, and such distribution shall

10 be made in the form elected by the Participant. In such a case, the Distributable Balance in the Deferred Compensation Account of the Participant shall be determined as of the date of such event in like manner as if such event was a Determination Date for such Participant. G. Distributions Continued; Disability or Death of Participant. Distribution of the Distributable Balance in the form elected by the Participant shall continue in the event of Disability or death of the Participant on or after the Distribution Date. H. Distribution Recipient; Disability. Distribution of the Distributable Balance in the form elected by the Participant shall be made to the Participant in the event of Disability of such Participant; provided, that the Committee may, in its sole discretion, direct that such distribution instead be made to a guardian or other representative of a Participant who is disabled. I. Distribution Recipient; Death of Participant. Each Participant shall also designate a Beneficiary to receive the unpaid balance in the Participant's Deferred Compensation Account in the event of the Participant's death prior to complete distribution of their Deferred Compensation Account. The unpaid balance shall be paid in the form elected by the Participant. If no Beneficiary is designated, then the Participant's Deferred Compensation Account shall be distributed to the estate of the deceased Participant. J. Section 409A Compliance. This Plan is intended to comply with Section 409A of the Code or an exemption therefrom and shall be construed and interpreted in a manner that is consistent with the requirements for avoiding additional taxes or penalties under Section 409A of the Code. ARTICLE XII NON-ASSIGNABILITY The right of a Non-Employee Director or Beneficiary to receive payments under this Plan shall not be pledged, assigned, transferred or subject to garnishment attachment or other legal process by creditors of such Non-Employee Director or Beneficiary. ARTICLE XIII ADMINISTRATION OF THE PLAN The Plan shall be administered by the Executive Compensation Committee of the Board, or by such other Committee as may be appointed and designated by the Board to administer the Plan from time to time. The Executive Compensation Committee shall supervise and direct the administration and operation of the Plan, and shall have such powers and duties as are specified in the Plan, or are otherwise necessary and appropriate thereto. The Committee, in its sole discretion, may establish rules and procedures governing the administration of the Plan, and shall have the power to interpret provisions of the Plan, and construe and determine the effect of Participant Elections and other instruments pertaining to the Plan, and all actions taken by the Executive Compensation Committee pursuant to the foregoing shall be binding on all Participants, Beneficiaries and other persons. Day-to-day authority and responsibility for administration of the Plan may be delegated to the Company’s Benefits Committee and its authorized representatives, and all actions taken thereby shall be entitled to the same deference as if taken by the Committee itself.

11 ARTICLE XIV FUNDING A. Company Obligation. The amounts of compensation deferred by any Non- Employee Director under this Plan shall constitute an unfunded and unsecured promise by the Company to pay such Non-Employee Director the deferred compensation from the general assets of the Company in the future. B. Nonqualified Trust. Although the Company may make, in its sole discretion, investments for the purpose of providing funds to pay such unsecured obligations made by it to the Plan, any such investments shall remain the sole and exclusive property of the Company subject to claims of its creditors generally; provided, that the Company may, at its option, create a grantor or rabbi trust to pay part or all of its obligations under the Plan as it determines to the extent permissible without changing the unfunded and unsecured nature of its deferred compensation obligations to Participants under the Plan. ARTICLE XV STATE LAWS GOVERNING PLAN This Plan shall be governed by the laws of the State of Oklahoma. ARTICLE XVI AMENDMENT OR TERMINATION OF PLAN This Plan shall continue in effect until amended or terminated by the Board of Directors. Any such amendment or termination shall not adversely affect any Deferred Compensation Account of a Participant then in existence under the Plan or any rights of a Participant under a Deferred Compensation Agreement entered into prior to such amendment or termination.

EX-31.1

Exhibit 31.1

Certification

I, Robert S. McAnnally, certify that:

I have reviewed this quarterly report on Form 10-Q of ONE Gas, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors:

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 1, 2022

/s/ Robert S. McAnnally

Robert S. McAnnally

Chief Executive Officer

EX-31.2

Exhibit 31.2

Certification

I, Caron A. Lawhorn, certify that:

I have reviewed this quarterly report on Form 10-Q of ONE Gas, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors:

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 1, 2022

/s/ Caron A. Lawhorn

Caron A. Lawhorn

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of ONE Gas, Inc. (the “Registrant”) for the period ending September 30, 2022, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert S. McAnnally, Chief Executive Officer of the Registrant, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

/s/ Robert S. McAnnally

Robert S. McAnnally

Chief Executive Officer

November 1, 2022

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to ONE Gas, Inc. and will be retained by ONE Gas, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of ONE Gas, Inc. (the “Registrant”) for the period ending September 30, 2022, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Caron A. Lawhorn, Chief Financial Officer of the Registrant, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

/s/ Caron A. Lawhorn

Caron A. Lawhorn

Chief Financial Officer

November 1, 2022

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to ONE Gas, Inc. and will be retained by ONE Gas, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

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Cover Page - shares	9 Months Ended
	Sep. 30, 2022	Oct. 25, 2022
Document Information [Line Items]
Document Type	10-Q
Document Period End Date	Sep. 30, 2022
Entity Registrant Name	ONE Gas, Inc.
Entity Central Index Key	0001587732
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Information [Line Items]
Document Quarterly Report	true
Document Transition Report	false
Entity File Number	001-36108
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
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	OGS
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		54,141,036

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STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Regulated Operating Revenue	$ 359,363	$ 273,923	$ 1,759,797	$ 1,214,862
Cost of natural gas	126,197	59,399	954,394	467,169
Operating expenses
Operations and maintenance	113,832	105,732	339,506	320,152
Depreciation and amortization	55,234	51,150	167,414	154,288
General taxes	17,048	15,835	52,105	49,999
Total operating expenses	186,114	172,717	559,025	524,439
Operating income	47,052	41,807	246,378	223,254
Other income (expense), net	793	(1,805)	(7,335)	(1,758)
Interest expense, net	(19,551)	(15,392)	(51,466)	(45,828)
Income before income taxes	28,294	24,610	187,577	175,668
Income taxes	(4,593)	(4,357)	(32,867)	(29,746)
Net income	$ 23,701	$ 20,253	$ 154,710	$ 145,922
Earnings per share
Basic	$ 0.44	$ 0.38	$ 2.86	$ 2.73
Diluted	$ 0.44	$ 0.38	$ 2.85	$ 2.72
Weighted Average Number of Shares Outstanding, Basic [Abstract]
Basic	54,310	53,710	54,164	53,516
Weighted Average Number of Shares Outstanding, Diluted [Abstract]
Diluted	54,482	53,793	54,282	53,618
Common Stock, Dividends, Per Share, Declared	$ 0.62	$ 0.58	$ 1.86	$ 1.74

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STATEMENTS OF COMPREHENSIVE INCOME STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Net income	$ 23,701	$ 20,253	$ 154,710	$ 145,922
Other comprehensive income (loss), net of tax
Change in pension and other postemployment benefit plan liability, net of tax of $(4), $(91), $(33) and $(273), respectively	12	300	111	899
Other comprehensive income, net of tax	12	300	111	899
Comprehensive income	$ 23,713	$ 20,553	$ 154,821	$ 146,821

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STATEMENTS OF COMPREHENSIVE INCOME STATEMENTS OF COMPREHENSIVE INCOME Parenthetical - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Pension and other postemployment benefit plans, tax	$ (4)	$ (91)	$ (33)	$ (273)

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BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2022	Dec. 31, 2021
Property, plant and equipment
Property, plant and equipment	$ 7,647,792	$ 7,274,268
Accumulated depreciation and amortization	2,172,271	2,083,433
Net property, plant and equipment	5,475,521	5,190,835
Current assets
Cash and cash equivalents	10,366	8,852
Accounts receivable, net	192,741	341,756
Materials and supplies	66,966	54,892
Natural gas in storage	343,377	179,646
Regulatory assets, Current	316,131	1,611,676
Other current assets	28,845	27,742
Total current assets	958,426	2,224,564
Goodwill and other assets
Regulatory assets, Noncurrent	624,484	724,862
Goodwill	157,953	157,953
Other assets	105,125	103,906
Total goodwill and other assets	887,562	986,721
Total assets	7,321,509	8,402,120
Equity and long-term debt
Common stock, $0.01 par value: authorized 250,000,000 shares; issued and outstanding 54,137,925 shares at September 30, 2022; issued and outstanding 53,633,210 shares at December 31, 2021	541	536
Paid-in Capital	1,833,480	1,790,362
Retained earnings	618,669	565,161
Accumulated other comprehensive loss	(6,416)	(6,527)
Total equity	2,446,274	2,349,532
Long-term debt, excluding current maturities and net of issuance costs of $14,520 and $12,418, respectively	2,429,053	3,683,378
Total equity and long-term debt	4,875,327	6,032,910
Current liabilities
Long-term Debt, Current Maturities	250,012	11
Short-term debt	423,400	494,000
Accounts payable	191,117	258,554
Accrued taxes other than income	73,387	67,035
Regulatory Liability, Current	38,171	8,090
Customer deposits	62,005	62,454
Other current liabilities	66,572	90,349
Total current liabilities	1,104,664	980,493
Deferred credits and other liabilities
Deferred income taxes	690,146	695,284
Regulatory Liability, Noncurrent	536,612	552,928
Employee benefit obligations	22,151	35,226
Other deferred credits	92,609	105,279
Liabilities, Other than Long-term Debt, Noncurrent	1,341,518	1,388,717
Commitments and contingencies
Total liabilities and equity	$ 7,321,509	$ 8,402,120

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BALANCE SHEETS BALANCE SHEETS Parenthetical - USD ($) $ in Thousands	Sep. 30, 2022	Dec. 31, 2021
Common stock, par value per share	$ 0.01
Common stock, shares authorized	250,000,000	250,000,000
Common stock, shares issued	54,137,925	53,633,210
Common stock, shares outstanding	54,137,925	53,633,210
Debt issuance costs	$ 14,520	$ 12,418

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STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021
Operating activities
Net income	$ 154,710	$ 145,922
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	167,414	154,288
Deferred income taxes	(21,498)	29,224
Share-based compensation expense	8,286	8,076
Provision for doubtful accounts	3,885	8,128
Proceeds from Securitization Bonds	1,330,582	0
Changes in assets and liabilities:
Accounts receivable	149,533	166,474
Materials and supplies	(12,074)	128
Natural gas in storage	(163,731)	(72,832)
Asset Removal Costs	34,386	35,195
Accounts payable	(84,404)	(17,244)
Accrued taxes other than income	6,352	5,574
Customer deposits	(449)	(8,595)
Increase (Decrease) In Regulatory Assets And Liabilities Current, net	16,324	(273,659)
Increase (Decrease) In Regulatory Assets And Liabilities Noncurrent, net	60,650	(1,651,445)
Increase (Decrease) in Other Current Assets and Liabilities, Net	(23,051)	(10,537)
Increase (Decrease) in Other Noncurrent Assets and Liabilities, Net	(2,317)	(8,884)
Cash provided by operating activities	1,555,826	(1,560,577)
Investing activities
Capital expenditures	(412,519)	(347,701)
Payments for Other Investing Activities	(2,419)	(3,374)
Proceeds from Sale of Other Assets, Investing Activities	2,695	1,676
Cash used in investing activities	(412,243)	(349,399)
Financing activities
Borrowings (repayments) of short-term debt, net	(70,600)	(82,225)
Proceeds from Issuance of Senior Long-term Debt	297,591	2,498,895
Payments of Debt Issuance Costs	(2,695)	(35,110)
Proceeds from Issuance of Common Stock	37,104	24,104
Repayments of Other Long-term Debt	(1,300,000)	(400,000)
Dividends paid	(100,386)	(92,832)
Payment, Tax Withholding, Share-based Payment Arrangement	(3,083)	(4,382)
Cash used in financing activities	(1,142,069)	1,908,450
Change in cash and cash equivalents	1,514	(1,526)
Cash and cash equivalents at beginning of period	8,852	7,993
Cash and cash equivalents at end of period	$ 10,366	$ 6,467

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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, 2020		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 - $0.62 and $0.58 per share per quarter as of 2022 and 2021, respectively	(30,882)	$ 0	260	(31,142)	0
Shares issued, ending balance at Mar. 31, 2021		53,245,011
Equity, ending balance at Mar. 31, 2021	$ 2,296,599	$ 532	1,755,476	548,068	(7,477)
Dividends paid per share of stock	$ 0.58
Shares issued, beginning balance at Dec. 31, 2020		53,166,733
Equity, beginning balance at Dec. 31, 2020	$ 2,233,311	$ 532	1,756,921	483,635	(7,777)
Net income	145,922
Other comprehensive income	899
Shares issued, ending balance at Sep. 30, 2021		53,584,326
Equity, ending balance at Sep. 30, 2021	2,315,098	$ 536	1,785,476	535,964	(6,878)
Shares issued, beginning balance at Mar. 31, 2021		53,245,011
Equity, beginning balance at Mar. 31, 2021	2,296,599	$ 532	1,755,476	548,068	(7,477)
Net income	30,093	0	0	30,093	0
Other comprehensive income	299	$ 0	0	0	299
Common stock issued, shares		254,226
Common stock issued, value	21,178	$ 3	21,175	0	0
Common stock dividends - $0.62 and $0.58 per share per quarter as of 2022 and 2021, respectively	(30,903)	$ 0	260	(31,163)	0
Shares issued, ending balance at Jun. 30, 2021		53,499,237
Equity, ending balance at Jun. 30, 2021	$ 2,317,266	$ 535	1,776,911	546,998	(7,178)
Dividends paid per share of stock	$ 0.58
Net income	$ 20,253	0	0	20,253	0
Other comprehensive income	300	$ 0	0	0	300
Common stock issued, shares		85,089
Common stock issued, value	8,325	$ 1	8,324	0	0
Common stock dividends - $0.62 and $0.58 per share per quarter as of 2022 and 2021, respectively	(31,046)	$ 0	241	(31,287)	0
Shares issued, ending balance at Sep. 30, 2021		53,584,326
Equity, ending balance at Sep. 30, 2021	$ 2,315,098	$ 536	1,785,476	535,964	(6,878)
Dividends paid per share of stock	$ 0.58
Shares issued, beginning balance at Dec. 31, 2021	53,633,210	53,633,210
Equity, beginning balance at Dec. 31, 2021	$ 2,349,532	$ 536	1,790,362	565,161	(6,527)
Net income	98,934	0	0	98,934	0
Other comprehensive income	69	$ 0	0	0	69
Common stock issued, shares		456,607
Common stock issued, value	34,140	$ 5	34,135	0	0
Common stock dividends - $0.62 and $0.58 per share per quarter as of 2022 and 2021, respectively	(33,285)	$ 0	274	(33,559)	0
Shares issued, ending balance at Mar. 31, 2022		54,089,817
Equity, ending balance at Mar. 31, 2022	$ 2,449,390	$ 541	1,824,771	630,536	(6,458)
Dividends paid per share of stock	$ 0.62
Shares issued, beginning balance at Dec. 31, 2021	53,633,210	53,633,210
Equity, beginning balance at Dec. 31, 2021	$ 2,349,532	$ 536	1,790,362	565,161	(6,527)
Net income	154,710
Other comprehensive income	$ 111
Shares issued, ending balance at Sep. 30, 2022	54,137,925	54,137,925
Equity, ending balance at Sep. 30, 2022	$ 2,446,274	$ 541	1,833,480	618,669	(6,416)
Shares issued, beginning balance at Mar. 31, 2022		54,089,817
Equity, beginning balance at Mar. 31, 2022	2,449,390	$ 541	1,824,771	630,536	(6,458)
Net income	32,075	0	0	32,075	0
Other comprehensive income	30	$ 0	0	0	30
Common stock issued, shares		47,400
Common stock issued, value	5,636	$ 0	5,636	0	0
Common stock dividends - $0.62 and $0.58 per share per quarter as of 2022 and 2021, respectively	(33,535)	$ 0	271	(33,806)	0
Shares issued, ending balance at Jun. 30, 2022		54,137,217
Equity, ending balance at Jun. 30, 2022	$ 2,453,596	$ 541	1,830,678	628,805	(6,428)
Dividends paid per share of stock	$ 0.62
Net income	$ 23,701	0	0	23,701	0
Other comprehensive income	12	$ 0	0	0	12
Common stock issued, shares		708
Common stock issued, value	2,531	$ 0	2,531	0	0
Common stock dividends - $0.62 and $0.58 per share per quarter as of 2022 and 2021, respectively	$ (33,566)	$ 0	271	(33,837)	0
Shares issued, ending balance at Sep. 30, 2022	54,137,925	54,137,925
Equity, ending balance at Sep. 30, 2022	$ 2,446,274	$ 541	$ 1,833,480	$ 618,669	$ (6,416)
Dividends paid per share of stock	$ 0.62

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Notes)

9 Months Ended

Sep. 30, 2022

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 2021 year-end consolidated balance sheet data was derived from audited consolidated financial statements but does not include all disclosures required by GAAP. These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and footnotes in our Annual Report. Our significant accounting policies are described in Note 1 of our Notes to Consolidated Financial Statements in our Annual Report. Due to the seasonal nature of our business, the results of operations for the nine months ended September 30, 2022, are not necessarily indicative of the results that may be expected for a 12-month period.

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

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

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

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

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

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

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

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

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

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REVENUE (Notes)

9 Months Ended

Sep. 30, 2022

Revenue from Contract with Customer

REVENUE

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

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

Accrued unbilled natural gas sales revenues at September 30, 2022 and December 31, 2021, were $79.2 million and $183.2 million, respectively, and are included in accounts receivable on our consolidated balance sheets.

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REGULATORY ASSETS AND LIABILITIES (Notes)

9 Months Ended

Sep. 30, 2022

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:

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

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

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

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

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

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

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

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

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

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

In May 2021, Kansas Gas Service filed a motion in its company-specific docket opened by the KCC, requesting a limited waiver of the penalty provisions of its tariff to eliminate the multipliers in the penalty calculation when calculating the penalties to assess on marketers and individually-balanced transportation customers for their unauthorized natural gas usage during Winter Storm Uri. In October 2021, a nonunanimous settlement agreement was filed with the KCC to reach a resolution on these penalties. Prior to a hearing on the amended settlement in January 2022, all parties reached a unanimous settlement, which was filed with a motion requesting approval of the unanimous settlement. Under the terms of the unanimous settlement, the carrying charge on assessed penalties was reduced to two percent, consistent with the nonunanimous agreement in the financial docket. On March 3, 2022, the KCC issued an order approving the settlement which modified the penalty provisions of Kansas Gas Service’s tariffs and included a carrying charge of two percent on amounts due to Kansas Gas Service. Amounts collected from these penalties will reduce the regulatory asset for the winter weather event, up to $52.6 million. Through September 30, 2022, we have collected $49.4 million of these penalties.

In July 2021, Kansas Gas Service submitted its financial plan to the KCC as required by the company-specific docket opened by the KCC in March 2021. The plan includes a proposal for a newly formed, bankruptcy remote subsidiary of the Company to issue securitized bonds to recover the extraordinary costs resulting from Winter Storm Uri from Kansas Gas Service’s customers. On February 8, 2022, the KCC issued an order approving a unanimous settlement agreement that allows Kansas Gas Service to recover extraordinary costs, net of any penalties recovered from marketers and individually-balanced transportation customers, plus carrying costs, by seeking a financing order from the KCC for the issuance of securitized utility tariff bonds.

On March 31, 2022, Kansas Gas Service submitted its application for a financing order to the KCC as contemplated by the unanimous settlement agreement, requesting approval to issue securitized bonds to recover extraordinary costs resulting from Winter Storm Uri and flexibility to recover the costs. On July 14, 2022, Kansas Gas Service, the KCC Staff and the Citizens’ Utility Ratepayer Board reached a settlement agreement for the issuance of a financing order allowing a newly formed, bankruptcy remote subsidiary of the Company to issue securitized utility tariff bonds in the amount of approximately $328.0 million plus issuance fees. The final amount to be securitized will be provided in the final issuance advice letter. The agreement provides for the issuance of bonds with a scheduled final maturity of between 7 and 10 years with flexibility within that range, if necessary, to achieve a AAA rating. On August 18, 2022, the KCC issued an order approving the agreement and also issued a financing order.

As part of the settlement agreement, we created KGSS-I, a special-purpose, wholly-owned subsidiary of ONE Gas, and filed a registration statement with the SEC, for the purpose of issuing securitized bonds. After the SEC declares the registration statement effective, KGSS-I expects to begin the process to issue the bonds.

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

Texas - Pursuant to securitization legislation enacted in Texas as a result of Winter Storm Uri and a June 2021 RRC Notice to Gas Utilities, Texas Gas Service submitted an application to the RRC on July 30, 2021, for an order authorizing the amount of extraordinary costs for recovery and other such specifications necessary for the issuance of securitized bonds.

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

On February 8, 2022, the RRC issued a single financing order for Texas Gas Service and other natural gas utilities in Texas participating in the securitization process, which included a determination that the approved costs will be collected from customers over a period of not more than 30 years. The TPFA formed the Texas Natural Gas Securitization Finance Corporation, a new independent public authority, that will issue the securitized bonds, which are expected to be issued in the fourth quarter of 2022. At September 30, 2022, Texas Gas Service has deferred approximately $246.7 million in extraordinary costs associated with Winter Storm Uri, which includes $47.8 million attributable to the West Texas service area. Pursuant to the approved settlement order, in January 2022, Texas Gas Service began collecting the extraordinary costs, including carrying costs, associated with Winter Storm Uri attributable to the West Texas service area from those customers.

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

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

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

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

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

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

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

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

We have received accounting orders in each of our jurisdictions authorizing us to accumulate and defer for regulatory purposes certain incremental costs incurred, including bad debt expenses, and certain lost revenues, net of offsetting expense reductions associated with COVID-19. Pursuant to these orders, the recovery of any net incremental costs and lost revenues will be determined in future rate cases or alternative rate recovery filings in each jurisdiction. For financial reporting purposes, any amounts deferred as a regulatory asset for future recovery under these accounting orders must be probable of recovery. At September 30, 2022, no regulatory assets have been recorded. In Oklahoma, the test period for our recently completed rate case included the impacts of COVID-19 on our cost of service in determining new rates that became effective in November 2021. In addition, annual PBRC filings, including the PBRC filing made in March 2022, allow us to include any impacts from COVID-19 in our test period cost of service to determine the impact on our rates. In Kansas and Texas, we continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable.

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

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CREDIT FACILITIES (Notes)

9 Months Ended

Sep. 30, 2022

Short-term Debt [Line Items]

Short-term Debt [Text Block]

CREDIT FACILITY AND SHORT-TERM DEBT

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

The ONE Gas Credit Agreement provides for a $1.0 billion revolving unsecured credit facility and includes a $20 million letter of credit subfacility and a $60 million swingline subfacility. We can request an increase in commitments of up to an additional

$500 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement is available to provide liquidity for working capital, capital expenditures, acquisitions and mergers, the issuance of letters of credit and for other general corporate purposes.

The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At September 30, 2022, our total debt-to-capital ratio was 56 percent and we were in compliance with all covenants under the ONE Gas Credit Agreement. We may reduce the unutilized portion of the ONE Gas Credit Agreement in whole or in part without premium or penalty. The ONE Gas Credit Agreement contains customary events of default. Upon the occurrence of certain events of default, the obligations under the ONE Gas Credit Agreement may be accelerated and the commitments may be terminated.

At September 30, 2022, we had $1.2 million in letters of credit issued and no borrowings under the ONE Gas Credit Agreement, with $998.8 million of remaining credit, which is available to repay any of our commercial paper borrowings.

In June 2021, we increased the size of our commercial paper program to permit the issuance of commercial paper to fund short-term borrowing needs in an aggregate principal amount not to exceed $1.0 billion outstanding at any time. Prior to this increase, our commercial paper program permitted us to issue commercial paper in an aggregate principal amount not to exceed $700 million outstanding at any time. The maturities of the commercial paper vary but may not exceed 270 days from the date of issue. Commercial paper is generally sold at par less a discount representing an interest factor. At September 30, 2022 and December 31, 2021, we had $423.4 million and $494.0 million of commercial paper outstanding with a weighted-average interest rate of 3.53 percent and 0.38 percent, respectively.

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

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LONG-TERM DEBT (Notes)

9 Months Ended

Sep. 30, 2022

Long-Term Debt, Unclassified [Abstract]

Long-term Debt [Text Block]

LONG-TERM DEBTSenior Notes - On August 8, 2022, ONE Gas issued $300 million of 4.25 percent senior notes due 2032. The proceeds from the issuance were used to repay amounts outstanding under our commercial paper program and for general corporate purposes.

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

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

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

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

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

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EQUITY (Notes)

9 Months Ended

Sep. 30, 2022

Class of Stock [Line Items]

Stockholders' Equity Note Disclosure [Text Block]

EQUITY

At-the-Market Equity Program - In February 2020, we initiated an at-the-market equity program by entering into an equity distribution agreement under which we may issue and sell shares of our common stock with an aggregate offering price up to $250 million (including any shares of common stock that may be sold pursuant to the master forward sale confirmation entered into in connection with the equity distribution agreement and the related supplemental confirmations). Sales of common stock are made by means of ordinary brokers’ transactions on the NYSE, in block transactions or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common stock under the program. For the nine months ended September 30, 2022 and 2021, we issued and sold 403,792 shares and 281,124 shares of our common stock for $35.0 million and $21.4 million, generating proceeds, net of issuance costs, of $34.7 million and $21.1 million, respectively.

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

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

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

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

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Notes)

9 Months Ended

Sep. 30, 2022

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

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

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

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EARNINGS PER SHARE (Notes)

9 Months Ended

Sep. 30, 2022

EARNINGS PER SHARE [Line Items]

Earnings Per Share [Text Block]

EARNINGS PER SHARE

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

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

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

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

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

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

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EMPLOYEE BENEFIT PLANS (Notes)

9 Months Ended

Sep. 30, 2022

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

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

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

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

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

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

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INCOME TAXES (Notes)

9 Months Ended

Sep. 30, 2022

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.

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

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

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

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

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OTHER INCOME AND OTHER EXPENSE (Notes)

9 Months Ended

Sep. 30, 2022

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

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COMMITMENTS AND CONTINGENCIES (Notes)

9 Months Ended

Sep. 30, 2022

Commitments and Contingencies [Line Items]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIESCOVID-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. See Note 3 for more information regarding the effects of COVID-19 on us.

Environmental Matters - We are subject to multiple laws and regulations regarding protection of the environment and natural and cultural resources, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, plant and wildlife protection, hazardous materials use, storage and transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits or the discovery of presently unknown environmental conditions may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other regulatory or permitting mandates under the CAA and other similar federal and state laws could require unexpected capital expenditures. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and nine months ended September 30, 2022 and 2021.

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

We have an AAO that allows Kansas Gas Service to defer and seek recovery of costs necessary for investigation and remediation at, and nearby, these 12 former MGP sites that are incurred after January 1, 2017, up to a cap of $15.0 million, net of any related insurance recoveries. Costs approved for recovery in a future rate proceeding would then be amortized over a 15-year period. The unamortized amounts will not be included in rate base or accumulate carrying charges. Following a determination that future investigation and remediation work approved by the KDHE is expected to exceed $15.0 million, net of any related insurance recoveries, Kansas Gas Service will be required to file an application with the KCC for approval to increase the $15.0 million cap. At September 30, 2022, we have deferred $29.9 million for accrued investigation and remediation costs pursuant to our AAO. Kansas Gas Service expects to file an application as soon as practicable after the KDHE approves the plans we have submitted and anticipates that filing will occur in 2023.

We have completed or are addressing removal of the source of soil contamination at all 12 sites and continue to monitor groundwater at seven of the 12 sites according to plans approved by the KDHE. In 2019, we completed a project to remove a source of contamination and associated contaminated materials at the twelfth site where no active soil remediation had previously occurred. Remediation plans concerning various sites were submitted to the KDHE in 2021 and 2020 and the KDHE has provided comments that we are addressing. We are also working on a remediation plan for an additional site that we expect to submit to the KDHE in 2023.

We also own or retain legal responsibility for certain environmental conditions at a former MGP site in Texas. At the request of the TCEQ, we began investigating the level and extent of contamination associated with the site under their Texas Risk Reduction Program. A preliminary site investigation revealed that this site contains contaminants generally associated with MGP sites and is subject to control or remediation under various environmental laws and regulations. Impacts have been identified in the soil and groundwater at the site with limited impacts observed in surrounding areas. On April 14, 2022, we submitted a remediation work plan to address the areas impacted to the TCEQ. At September 30, 2022, estimated costs associated with expected remediation activities for this site are not material.

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and nine months ended September 30, 2022 and 2021. The reserve for remediation of our MGP sites was $13.2 million and $22.8 million at September 30, 2022 and December 31, 2021, respectively. Environmental issues may exist with respect to MGP sites that are unknown to us. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation required, changing technology and governmental regulations, and to the extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition, results of operations or cash flows.

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

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

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

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

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

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

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

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

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

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

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DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS (Notes)

9 Months Ended

Sep. 30, 2022

Fair Value Disclosures [Abstract]

Fair Value Disclosures

DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTSAccounting Treatment - We record all derivative instruments at fair value, with the exception of 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 requirements impose a different accounting treatment.

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

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

		Recognition and Measurement
Accounting Treatment		Balance Sheet		Income Statement
Normal purchases and normal sales	-	Fair value not recorded	-	Change in fair value not recognized in earnings
Mark-to-market	-	Recorded at fair value	-	Change in fair value recognized in, and recoverable through, the purchased-gas cost adjustment mechanisms

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

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

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

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

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

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

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

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

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

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

$2.4 billion and $3.9 billion at September 30, 2022 and December 31, 2021, respectively. The estimated fair value of our long-term debt was determined using quoted market prices, and is classified as Level 2.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2022

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 revenue and expense during the reporting period. Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, provisions for doubtful accounts receivable, unbilled revenues for natural gas delivered but for which meters have not been read, natural gas purchased but for which no invoice has been received, provision for income taxes, including any deferred income tax valuation allowances, the results of litigation and various other recorded or disclosed amounts.

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

Segments

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

Goodwill and Intangible Assets, Policy

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

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 2.3 million customers across three states, we are not exposed materially to a concentration of credit risk. We maintain an allowance for doubtful accounts based upon factors surrounding the credit risk of customers, historical trends, consideration of the current environment and other information. We recover natural gas costs related to accounts written off when they are deemed uncollectible through the purchased-gas cost adjustment mechanisms in each of our jurisdictions. At September 30, 2022 and December 31, 2021, our allowance for doubtful accounts was $15.6 million and $18.7 million, respectively.

Recently Issued Accounting Standards Update

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

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DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS (Policies)

9 Months Ended

Sep. 30, 2022

Accounting Policies [Abstract]

Derivatives

Accounting Treatment - We record all derivative instruments at fair value, with the exception of 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 requirements impose a different accounting treatment.

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

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

		Recognition and Measurement
Accounting Treatment		Balance Sheet		Income Statement
Normal purchases and normal sales	-	Fair value not recorded	-	Change in fair value not recognized in earnings
Mark-to-market	-	Recorded at fair value	-	Change in fair value recognized in, and recoverable through, the purchased-gas cost adjustment mechanisms

Fair Value 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.

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.

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REVENUE (Tables)

9 Months Ended

Sep. 30, 2022

Revenues Disaggregated by Source [Table]

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

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

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REGULATORY ASSETS AND LIABILITIES (Tables)

9 Months Ended

Sep. 30, 2022

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:

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

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

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)

9 Months Ended

Sep. 30, 2022

Accumulated Other Comprehensive Income (Loss) [Line Items]

Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]

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

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

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

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EARNINGS PER SHARE (Tables)

9 Months Ended

Sep. 30, 2022

EARNINGS PER SHARE [Line Items]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

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

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

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

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

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

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EMPLOYEE BENEFIT PLANS (Tables)

9 Months Ended

Sep. 30, 2022

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

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

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OTHER INCOME AND OTHER EXPENSE (Tables)

9 Months Ended

Sep. 30, 2022

Schedule of Other Nonoperating Income (Expense)

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

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

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) number in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022 USD ($)	Sep. 30, 2021	Sep. 30, 2022 USD ($)	Sep. 30, 2021 USD ($)	Dec. 31, 2021 USD ($)
Significant Accounting Policies [Line Items]
Number of natural gas distribution services customers	2.3		2.3
Segment Reporting, Disclosure of Major Customers	no	no	no	no
Capital Expenditures Incurred but Not yet Paid			$ 4.0	$ 7.5
Allowance for Doubtful Accounts, Premiums and Other Receivables	$ 15.6		$ 15.6		$ 18.7

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REVENUE (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021	Dec. 31, 2021
Regulated Operating Revenue, Gas	$ 355,470	$ 270,296	$ 1,747,858	$ 1,205,686
Regulated Operating Revenue, Other	3,893	3,627	11,939	9,176
Regulated Operating Revenue	359,363	273,923	1,759,797	1,214,862
Unbilled Receivables, Current	79,200		79,200		$ 183,200
Natural gas sales to customers [Member]
Regulated Operating Revenue, Gas	322,444	240,591	1,640,893	1,105,835
Transportation revenues [Member]
Regulated Operating Revenue, Gas	28,035	25,342	92,350	87,760
Miscellaneous revenues [Member]
Regulated Operating Revenue, Gas	4,991	4,363	14,615	12,091
Other revenues - natural gas sales related [Member]
Regulated Operating Revenue, Other	427	545	2,658	849
Other revenues [Member]
Regulated Operating Revenue, Other	$ 3,466	$ 3,082	$ 9,281	$ 8,327

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REGULATORY ASSETS AND LIABILITIES (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Aug. 25, 2022	Dec. 31, 2021	Feb. 28, 2021
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	$ 316,131			$ 1,611,676
Regulatory Assets, Noncurrent	624,484			724,862
Regulatory Assets	940,615			2,336,538
Regulatory Liability, Current	(38,171)			(8,090)
Regulatory Liability, Noncurrent	(536,612)			(552,928)
Regulatory Liabilities	(574,783)			(561,018)
Net regulatory assets (liabilities), current	277,960			1,603,586
Net regulatory assets (liabilities), noncurrent	87,872			171,934
Net Regulatory Assets	365,832			1,775,520
February 2021 Natural Gas Purchases					$ 2,100,000
ONG Deferred Extraordinary Costs from 2021 Winter Storm Uri	1,300,000
Maximum amount the regulatory asset for the winter storm can be reduced by for collections of penalties assessed on marketers and individually balanced transportation customers	52,600
Collections of penalties assessed on marketers and individually balanced transportation customers as a result of Winter Storm Uri	49,400
KGS Winter Weather Securitized Utility Tariff Bond	328,000
KGS Deferred Extraordinary Costs from 2021 Winter Storm Uri	339,600
TGS Deferred Extraordinary Costs from 2021 Winter Storm Uri	246,700
Deferred Extraordinary Costs from 2021 Winter Storm Uri	586,200
Amortization of Rate Deferral	6,900	$ 4,400
ONG Proceeds from Securitization Bonds	1,300,000
ONG Securitization Bond Issuance			$ 1,350,000
West Texas Service Area
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
TGS Deferred Extraordinary Costs from 2021 Winter Storm Uri	47,800
Income tax rate changes [Member] [Domain]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Liability, Current	0			0
Regulatory Liability, Noncurrent	(536,612)			(552,928)
Regulatory Liabilities	(536,612)			(552,928)
Over-recovered purchased-gas costs [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Liability, Current	(38,171)			(8,090)
Regulatory Liability, Noncurrent	0			0
Regulatory Liabilities	(38,171)			(8,090)
Winter weather event costs
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	243,232			1,536,054
Regulatory Assets, Noncurrent	342,997			428,023
Regulatory Assets	586,229			1,964,077
Under-recovered purchased-gas costs [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	28,193			31,863
Regulatory Assets, Noncurrent	0			0
Regulatory Assets	28,193			31,863
Pension and postretirement benefit costs [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	4,010			11,507
Regulatory Assets, Noncurrent	245,637			260,559
Regulatory Assets	249,647			272,066
Reacquired debt costs [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	811			812
Regulatory Assets, Noncurrent	3,528			4,070
Regulatory Assets	4,339			4,882
MGP Costs [Member] [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	98			98
Regulatory Assets, Noncurrent	29,767			29,841
Regulatory Assets	29,865			29,939
Ad valorem tax [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	12,779			8,561
Regulatory Assets, Noncurrent	0			0
Regulatory Assets	12,779			8,561
Weather normalization [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	10,555			10,044
Regulatory Assets, Noncurrent	0			0
Regulatory Assets	10,555			10,044
Customer credit deferrals
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	14,595			10,685
Regulatory Assets, Noncurrent	0			0
Regulatory Assets	14,595			10,685
Other regulatory assets [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	1,858			2,052
Regulatory Assets, Noncurrent	2,555			2,369
Regulatory Assets	$ 4,413			$ 4,421

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CREDIT FACILITIES (Details) $ in Thousands	Sep. 30, 2022 USD ($)	Dec. 31, 2021 USD ($)
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,000,000
Line of Credit Facility Sublimit	20,000
Bridge Loan	60,000
Line of Credit Facility Option to Increase Borrowing Capacity	$ 500,000
Approved Debt to Capital Ratio	0.70
Ratio of Indebtedness to Net Capital	0.56
Letters of Credit Outstanding, Amount	$ 1,200
Line of Credit Facility, Remaining Borrowing Capacity	998,800
Commercial paper maximum borrowing capacity	1,000,000
Maximum borrowing capacity under the commercial paper program prior to June 2021	700,000
Commercial Paper	$ 423,400	$ 494,000
Short-Term Debt, Weighted Average Interest Rate, at Point in Time	3.53%	0.38%

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LONG-TERM DEBT (Details) - USD ($) $ in Thousands			9 Months Ended
	Aug. 25, 2022	Sep. 21, 2021	Sep. 30, 2022	Sep. 30, 2021
Debt Instrument [Line Items]
Repayments of Other Long-term Debt			$ 1,300,000	$ 400,000
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.
OGS Note Payable Due 2023
Debt Instrument [Line Items]
Long-term Debt, Gross			$ 800,000
Repayments of Other Long-term Debt	$ 400,000	$ 400,000
OGS Note Payable Due 2024 at 1.10 Percent
Debt Instrument [Line Items]
Long-term Debt, Gross			$ 700,000
Debt Instrument, Interest Rate, Stated Percentage			1.10%
Repayments of Other Long-term Debt	150,000
Notes Payable at 0.85% Due 2023
Debt Instrument [Line Items]
Long-term Debt, Gross			$ 1,000,000
Debt Instrument, Interest Rate, Stated Percentage			0.85%
Repayments of Other Long-term Debt	$ 750,000
Notes Payable at 4.25% Due 2032
Debt Instrument [Line Items]
Long-term Debt, Gross			$ 300,000
Debt Instrument, Interest Rate, Stated Percentage			4.25%

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EQUITY (Details) - USD ($)	3 Months Ended							9 Months Ended
	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Sep. 30, 2022	Sep. 30, 2021
Common stock issued, value		$ 2,531,000	$ 5,636,000	$ 34,140,000	$ 8,325,000	$ 21,178,000	$ (1,705,000)
Proceeds from Issuance of Common Stock								$ 37,104,000	$ 24,104,000
Common Stock, Dividends, Per Share, Declared		$ 0.62			$ 0.58			$ 1.86	$ 1.74
Subsequent Event [Member]
Common Stock, Dividends, Per Share, Declared	$ 0.62
Common Stock, Dividends, Declared, Annualized Basis	$ 2.48
Dividends Payable, Date of Record	Nov. 15, 2022
Dividends Payable, Date to be Paid	Dec. 01, 2022
At-The-Market Program
Aggregate Offering Price Limit		$ 250,000,000						$ 250,000,000
Common stock issued, shares								403,792	281,124
Common stock issued, value								$ 35,000,000	$ 21,400,000
Proceeds from Issuance of Common Stock								$ 34,700,000	$ 21,100,000
Forward Contract Indexed to Issuer's Equity, Indexed Shares								1,162,071
Forward Contract Indexed to Equity, Settlement, Cash, Amount		93,942,000						$ 93,942,000
Forward Contract Indexed to Issuer's Equity, Forward Rate Per Share								$ 80.84
Equity Available for Issuance		85,100,000						$ 85,100,000
At-The-Market Program | Settled on or before September 29, 2023
Forward Contract Indexed to Issuer's Equity, Indexed Shares								570,335
Forward Contract Indexed to Equity, Settlement, Cash, Amount		45,890,000						$ 45,890,000
Forward Contract Indexed to Issuer's Equity, Forward Rate Per Share								$ 80.46
At-The-Market Program | Settled on or before January 2, 2024
Forward Contract Indexed to Issuer's Equity, Indexed Shares								591,736
Forward Contract Indexed to Equity, Settlement, Cash, Amount		$ 48,052,000						$ 48,052,000
Forward Contract Indexed to Issuer's Equity, Forward Rate Per Share								$ 81.21

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amortization of net loss	$ 2,278	$ 11,474	$ 14,731	$ 34,422
Amortization of unrecognized prior service cost	103	(70)	185	(210)
Reclassification adjustment, before tax and regulatory adjustments	2,381	11,404	14,916	34,212
Regulatory adjustments	(2,365)	(11,013)	(14,772)	(33,040)
Reclassification adjustment, before tax	16	391	144	1,172
Reclassification adjustment, Tax	(4)	(91)	(33)	(273)
Reclassification adjustment, net of tax	$ 12	$ 300	$ 111	$ 899

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EARNINGS PER SHARE (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended						9 Months Ended
	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Sep. 30, 2022	Sep. 30, 2021
Basic EPS Calculation
Net income available for common stock	$ 23,701	$ 32,075	$ 98,934	$ 20,253	$ 30,093	$ 95,575	$ 154,710	$ 145,922
Weighted Average Number of Shares Outstanding, Basic	54,310			53,710			54,164	53,516
Earnings Per Share, Basic	$ 0.44			$ 0.38			$ 2.86	$ 2.73
Diluted EPS Calculation
Net Income (Loss) Available to Common Stockholders, Diluted	$ 23,701			$ 20,253			$ 154,710	$ 145,922
Effect of dilutive securities on shares	172			83			118	102
Weighted Average Number of Shares Outstanding, Diluted	54,482			53,793			54,282	53,618
Earnings Per Share, Diluted	$ 0.44			$ 0.38			$ 2.85	$ 2.72

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EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021	Apr. 30, 2022	Dec. 31, 2021
Components of net periodic benefit cost:
Amortization of unrecognized prior service cost	$ (103)	$ 70	$ (185)	$ 210
Amortization of net loss	(2,278)	(11,474)	(14,731)	(34,422)
Regulatory Deferral of net periodic benefit costs			3,400
Adjustment to Pension Expense Due to Remeasurment					$ 7,200
Capitalized non-service cost components as a regulatory asset	4,000		4,000			$ 6,100
ONE Gas Pension Plans [Member]
Components of net periodic benefit cost:
Service cost	2,341	3,453	8,027	10,359
Interest cost	9,654	7,365	26,495	22,095
Expected return on assets	(14,642)	(15,596)	(43,887)	(46,788)
Amortization of unrecognized prior service cost	93	0	155	0
Amortization of net loss	2,224	11,381	14,569	34,143
Net periodic benefit cost	(330)	6,603	5,359	19,809
ONE Gas Postretirement Benefit Plans [Member]
Components of net periodic benefit cost:
Service cost	318	397	954	1,191
Interest cost	1,612	1,563	4,836	4,689
Expected return on assets	(3,295)	(4,202)	(9,885)	(12,606)
Amortization of unrecognized prior service cost	10	(70)	30	(210)
Amortization of net loss	54	93	162	279
Net periodic benefit cost	$ (1,301)	$ (2,219)	$ (3,903)	$ (6,657)

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INCOME TAXES (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Income Tax Disclosure [Abstract]
Reduction in ADIT recorded as an EDIT regulatory liability associated with reduction of Oklahoma state income tax	$ 29.3		$ 29.3
Reduction in income tax expense for the amortization of the regulatory liability associated with excess ADIT that was returned to customers	$ 1.6	$ 1.5	$ 12.5	$ 12.2

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OTHER INCOME AND OTHER EXPENSE (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Other, net	$ 793	$ (1,805)	$ (7,335)	$ (1,758)
Net periodic cost other than service cost [Member]
Other, net	1,430	(1,069)	2,209	(2,844)
Earnings (losses) on investments associated with nonqualified employee benefit plans [Member]
Other, net	(1,789)	(267)	(9,241)	2,232
Other, net [Member]
Other, net	$ 1,152	$ (469)	$ (303)	$ (1,146)

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COMMITMENTS AND CONTINGENCIES (Details) $ in Millions	Sep. 30, 2022 USD ($)	Dec. 31, 2021 USD ($)
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	5
Number of sites with ongoing groundwater monitoring	7
Deferred MGP Costs, Maximum	$ 15.0
Regulatory Asset for Costs Associated with Manufactured Gas Sites	29.9
Accrual for Environmental Loss Contingencies	$ 13.2	$ 22.8

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DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS (Details)	9 Months Ended
	Sep. 30, 2022 USD ($) Bcf	Sep. 30, 2021 USD ($)	Dec. 31, 2021 USD ($) Bcf
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative, Nonmonetary Notional Amount | Bcf	17.4		13.2
Premiums recorded in other current assets on natural gas contracts held	$ 27,100,000		$ 9,500,000
Fair Value Assets, Transfers between Levels	0	$ 0
Corporate bonds in other assets	7,100,000		6,900,000
Treasury notes in other assets	2,400,000		3,500,000
Long-term Debt	2,700,000,000		3,700,000,000
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Fair value, natural gas call options	3,500,000		2,300,000
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Long-term Debt, Fair Value	$ 2,400,000,000		$ 3,900,000,000