ONE Gas, Inc. - Quarter Report: 2021 September (Form 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, 2021.

☐ 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, 2021, the Company had 53,587,508 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, 2021 and 2020	6
	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2021 and 2020	7
	Consolidated Balance Sheets - September 30, 2021 and December 31, 2020	8
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2021 and 2020	11
	Consolidated Statements of Equity - Three and Nine Months Ended September 30, 2021 and 2020	12
	Notes to Consolidated Financial Statements	14
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 4.	Controls and Procedures	49
Part II.	Other Information	50
Item 1.	Legal Proceedings	50
Item 1A.	Risk Factors	50
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 3.	Defaults Upon Senior Securities	50
Item 4.	Mine Safety Disclosures	50
Item 5.	Other Information	50
Item 6.	Exhibits	50
Signature		52

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

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

AVAILABLE INFORMATION

We make available, free of charge, on our website (www.onegas.com) copies of our Annual Report, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC, which also makes these materials available on its website (www.sec.gov). Copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Certificate of Incorporation, bylaws, the written charters of our Audit Committee, Executive Compensation Committee, Corporate Governance Committee and Executive Committee and our Environmental, Social and Governance Report are also available on our website, and copies of these documents are available upon request.

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

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, 2020
ASC			Accounting Standards Codification
ASU			Accounting Standards Update
Bcf			Billion cubic feet
CERCLA			Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
Clean Air Act			Federal Clean Air Act, as amended
Clean Water Act			Federal Water Pollution Control Amendments of 1972, as amended
CNG			Compressed natural gas
COVID-19			Coronavirus Disease 2019
DOT			United States Department of Transportation
EDIT			Excess accumulated deferred income taxes resulting from a change in enacted tax rates
EPA			United States Environmental Protection Agency
EPS			Earnings per share
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
GPAC			Gas Pipeline Advisory Committee
GRIP			Gas Reliability Infrastructure Program
GSRS			Gas System Reliability Surcharge
Heating Degree Day or HDD			A measure designed to reflect the demand for energy needed for heating based on the extent to which the daily average temperature falls below a reference temperature for which no heating is required, usually 65 degrees Fahrenheit
HCA(s)			High consequence area(s)
KCC			Kansas Corporation Commission
KDHE			Kansas Department of Health and Environment
LDC			Local distribution company
LIBOR			London Interbank Offered Rate
MAOP(s)			Maximum allowable operating pressure(s)
MGP			Manufactured gas plant
MMcf			Million cubic feet
Moody’s			Moody’s Investors Service, Inc.
Net margin			Non-GAAP measure defined as total revenues less cost of natural gas
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 second amended and restated revolving credit agreement, which expires on March 16, 2026
PBRC			Performance-Based Rate Change
PHMSA			United States Department of Transportation Pipeline and Hazardous Materials Safety Administration
PPE			Personal protective equipment
Quarterly Report(s)			Quarterly Report(s) on Form 10-Q
RNG			Renewable natural gas
ROE			Return on equity, calculated consistent with utility ratemaking principles in each jurisdiction in which we operate
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 $1.0 billion of 0.85 percent senior notes due 2023, $400 million of floating-rate senior notes due 2023, $700 million of 1.10 percent senior notes due 2024, $300 million of 3.61 percent senior notes due 2024, $300 million of 2.00 percent senior notes due 2030, $600 million of 4.658 percent senior notes due 2044 and $400 million of 4.50 percent notes due 2048
TPFA			Texas Public Finance Authority
WNA			Weather normalization adjustment(s)
XBRL			eXtensible Business Reporting Language

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)	2021		2020		2021		2020
	(Thousands of dollars, except per share amounts)

Total revenues	$	273,923	$	244,640	$	1,214,862	$	1,046,095

Cost of natural gas	59,399		40,485		467,169		329,134

Operating expenses
Operations and maintenance	105,732		100,285		320,152		308,641
Depreciation and amortization	51,150		47,998		154,288		142,898
General taxes	15,835		15,193		49,999		46,931
Total operating expenses	172,717		163,476		524,439		498,470
Operating income	41,807		40,679		223,254		218,491
Other income (expense), net	(1,805)		198		(1,758)		(3,196)
Interest expense, net	(15,392)		(15,542)		(45,828)		(47,078)
Income before income taxes	24,610		25,335		175,668		168,217
Income taxes	(4,357)		(4,256)		(29,746)		(30,136)
Net income	$	20,253	$	21,079	$	145,922	$	138,081

Earnings per share
Basic	$	0.38	$	0.40	$	2.73	$	2.60
Diluted	$	0.38	$	0.39	$	2.72	$	2.59

Average shares (thousands)
Basic	53,710		53,190		53,516		53,084
Diluted	53,793		53,408		53,618		53,313
Dividends declared per share of stock	$	0.58	$	0.54	$	1.74	$	1.62

See accompanying Notes to Consolidated Financial Statements.


ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(Unaudited)	2021		2020		2021		2020
	(Thousands of dollars)
Net income	$	20,253	$	21,079	$	145,922	$	138,081
Other comprehensive income, net of tax
Change in pension and other postemployment benefit plan liability, net of tax of $(91), $(75), $(273) and $(224), respectively	300		223		899		670
Total other comprehensive income, net of tax	300		223		899		670
Comprehensive income	$	20,553	$	21,302	$	146,821	$	138,751

See accompanying Notes to Consolidated Financial Statements.


ONE Gas, Inc.
CONSOLIDATED BALANCE SHEETS

	September 30,		December 31,
(Unaudited)	2021		2020
Assets	(Thousands of dollars)
Property, plant and equipment
Property, plant and equipment	$	7,138,445	$	6,838,603
Accumulated depreciation and amortization	2,060,335		1,971,546
Net property, plant and equipment	5,078,110		4,867,057
Current assets
Cash and cash equivalents	6,467		7,993
Accounts receivable, net	118,383		292,985
Materials and supplies	52,638		52,766

Natural gas in storage	166,778		93,946
Regulatory assets	300,485		56,773
Assets from price risk management activities	77,380		—
Other current assets	30,759		35,406
Total current assets	752,890		539,869
Goodwill and other assets
Regulatory assets	2,050,332		366,956
Goodwill	157,953		157,953

Other assets	94,633		96,877
Total goodwill and other assets	2,302,918		621,786
Total assets	$	8,133,918	$	6,028,712

See accompanying Notes to Consolidated Financial Statements.


ONE Gas, Inc.
CONSOLIDATED BALANCE SHEETS
(Continued)
	September 30,		December 31,
(Unaudited)	2021		2020
Equity and Liabilities	(Thousands of dollars)
Equity and long-term debt
Common stock, $0.01 par value: authorized 250,000,000 shares; issued and outstanding 53,584,326 shares at September 30, 2021; issued and outstanding 53,166,733 shares at December 31, 2020	$	536	$	532
Paid-in capital	1,785,476		1,756,921
Retained earnings	535,964		483,635
Accumulated other comprehensive loss	(6,878)		(7,777)

Total equity	2,315,098		2,233,311
Long-term debt, excluding current maturities and net of issuance costs of $12,605 and $13,159, respectively	3,683,137		1,582,428
Total equity and long-term debt	5,998,235		3,815,739
Current liabilities
Short-term debt	336,000		418,225
Accounts payable	127,544		152,313

Accrued taxes other than income	69,374		63,800

Regulatory liabilities	63,194		15,761
Customer deposits	59,433		68,028
Other current liabilities	64,591		78,952
Total current liabilities	720,136		797,079
Deferred credits and other liabilities
Deferred income taxes	677,034		656,806
Regulatory liabilities	556,843		547,563
Employee benefit obligations	74,373		97,637
Other deferred credits	107,297		113,888
Total deferred credits and other liabilities	1,415,547		1,415,894
Commitments and contingencies
Total liabilities and equity	$	8,133,918	$	6,028,712

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)	2021		2020
	(Thousands of dollars)
Operating activities
Net income	$	145,922	$	138,081
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	154,288		142,898
Deferred income taxes	29,224		11,175
Share-based compensation expense	8,076		7,439
Provision for doubtful accounts	8,128		8,836
Changes in assets and liabilities:
Accounts receivable	166,474		144,399
Materials and supplies	128		240
Natural gas in storage	(72,832)		(1,118)

Asset removal costs	(35,195)		(29,019)
Accounts payable	(17,244)		(50,848)

Accrued taxes other than income	5,574		9,776

Customer deposits	(8,595)		(2,668)
Regulatory assets and liabilities - current	(273,659)		(49,055)
Regulatory assets and liabilities - noncurrent	(1,651,445)		24,577
Other assets and liabilities - current	(10,537)		(20,550)
Other assets and liabilities - noncurrent	(8,884)		(8,834)
Cash provided by (used in) operating activities	(1,560,577)		325,329
Investing activities
Capital expenditures	(347,701)		(348,915)
Other investing expenditures	(3,374)		(1,379)
Other investing receipts	1,676		2,482
Cash used in investing activities	(349,399)		(347,812)
Financing activities
Borrowings (repayments) on short-term debt, net	(82,225)		(208,500)
Issuance of debt, net of discounts	2,498,895		297,750
Long-term debt financing costs	(35,110)		(2,885)
Issuance of common stock	24,104		16,325
Repayment of long-term debt	(400,000)		—
Dividends paid	(92,832)		(85,698)
Tax withholdings related to net share settlements of stock compensation	(4,382)		(6,178)
Cash provided by (used in) financing activities	1,908,450		10,814
Change in cash and cash equivalents	(1,526)		(11,669)
Cash and cash equivalents at beginning of period	7,993		17,853
Cash and cash equivalents at end of period	$	6,467	$	6,184

See accompanying Notes to Consolidated Financial Statements.


ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)	Common Stock Issued	Common Stock		Paid-in Capital
	(Shares)	(Thousands of dollars)

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

January 1, 2020	52,771,749	$	528	$	1,733,092
Net income	—	—		—
Other comprehensive income	—	—		—

Common stock issued and other	89,059	1		(3,737)
Common stock dividends - $0.54 per share	—	—		232
March 31, 2020	52,860,808	$	529	$	1,729,587
Net income	—	—		—
Other comprehensive income	—	—		—

Common stock issued and other	59,722	—		5,974
Common stock dividends - $0.54 per share	—	—		227
June 30, 2020	52,920,530	$	529	$	1,735,788
Net income	—	—		—
Other comprehensive income	—	—		—
Common stock issued and other	176,363	2		15,334
Common stock dividends - $0.54 per share	—	—		228
September 30, 2020	53,096,893	$	531	$	1,751,350

See accompanying Notes to Consolidated Financial Statements.


ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF EQUITY
(Continued)
(Unaudited)	Retained Earnings		Accumulated Other Comprehensive Loss		Total Equity
	(Thousands of dollars)

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

January 1, 2020	$	402,509	$	(6,739)	$	2,129,390
Net income	91,677		—		91,677
Other comprehensive income	—		224		224

Common stock issued and other	—		—		(3,736)
Common stock dividends - $0.54 per share	(28,775)		—		(28,543)
March 31, 2020	$	465,411	$	(6,515)	$	2,189,012
Net income	25,325		—		25,325
Other comprehensive income	—		223		223

Common stock issued and other	—		—		5,974
Common stock dividends - $0.54 per share	(28,774)		—		(28,547)
June 30, 2020	$	461,962	$	(6,292)	$	2,191,987
Net income	21,079		—		21,079
Other comprehensive income	—		223		223
Common stock issued and other	—		—		15,336
Common stock dividends - $0.54 per share	(28,836)		—		(28,608)
September 30, 2020	$	454,205	$	(6,069)	$	2,200,017

See accompanying Notes to Consolidated Financial Statements.

ONE Gas, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our accompanying unaudited consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. These statements also have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair statement of the results for the interim periods presented. All such adjustments are of a normal recurring nature. The 2020 year-end consolidated balance sheet data was derived from audited consolidated financial statements but does not include all disclosures required by GAAP. These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and footnotes in our Annual Report. Our significant accounting policies are described in Note 1 of our Notes to Consolidated Financial Statements in our Annual Report. Due to the seasonal nature of our business, the results of operations for the nine months ended September 30, 2021, are not necessarily indicative of the results that may be expected for a 12-month period.

We provide natural gas distribution services to our approximately 2.2 million customers through our divisions in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. We primarily serve residential, commercial and transportation customers in all three states.

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

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

Segments - We operate in one reportable business segment: regulated public utilities that deliver natural gas primarily to residential, commercial and transportation customers. The accounting policies for our segment are the same as those described in Note 1 of our Notes to Consolidated Financial Statements in our Annual Report. We evaluate our financial performance principally on net income. For the three and nine months ended September 30, 2021, and 2020, we had no single external customer from which we received 10 percent or more of our gross revenues.

Property, Plant and Equipment and Asset Removal Costs - Accounts payable for construction work in process and asset removal costs decreased by approximately $7.5 million and $4.3 million for the nine months ended September 30, 2021 and 2020, 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 2.2 million customers across three states, we are not exposed materially to a concentration of credit risk. We maintain an allowance for doubtful accounts based upon factors surrounding the credit risk of customers, historical trends, consideration of the current environment and other information. We recover natural

gas costs related to accounts written off when they are deemed uncollectible through the purchased-gas cost adjustment mechanisms in each of our jurisdictions. At September 30, 2021 and December 31, 2020, our allowance for doubtful accounts was $18.9 million and $16.6 million, respectively.

Reclassifications - Certain reclassifications have been made in the prior-year financial statements to conform to the current-year presentation. We have updated our 2020 Statements of Cash Flows for the nine months ended September 30, 2020, to disaggregate “regulatory assets and liabilities” and “other assets and liabilities” into current and non-current components that are presented on our balance sheet to conform to our current year presentation.

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

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

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

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

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,
	2021		2020		2021		2020
	(Thousands of dollars)
Natural gas sales to customers	$	240,591	$	212,723	$	1,105,835	$	936,749
Transportation revenues	25,342		24,305		87,760		82,543
Miscellaneous revenues	4,363		3,800		12,091		11,390
Total revenues from contracts with customers	270,296		240,828		1,205,686		1,030,682
Other revenues - natural gas sales related	545		(66)		849		6,478
Other revenues	3,082		3,878		8,327		8,935
Total other revenues	3,627		3,812		9,176		15,413
Total revenues	$	273,923	$	244,640	$	1,214,862	$	1,046,095

Accrued unbilled natural gas sales revenues at September 30, 2021 and December 31, 2020, were $54.3 million and $144.9 million, respectively, and are included in accounts receivable on our consolidated balance sheets.

3. REGULATORY ASSETS AND LIABILITIES

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


	September 30, 2021
	Current		Noncurrent		Total
	(Thousands of dollars)
Winter weather event costs	$	255,051	$	1,708,247	$	1,963,298

Pension and postemployment benefit costs	16,513		307,073		323,586
Reacquired debt costs	812		4,258		5,070
MGP remediation costs	98		29,865		29,963
Ad-valorem tax	8,065		—		8,065
WNA	1,563		—		1,563
Customer credit deferrals	16,153		—		16,153
Other	2,230		889		3,119
Total regulatory assets, net of amortization	300,485		2,050,332		2,350,817
Income tax rate changes	—		(556,843)		(556,843)
Over-recovered purchased-gas costs	(63,194)		—		(63,194)
Total regulatory liabilities, net of amortization	(63,194)		(556,843)		(620,037)
Net regulatory assets and liabilities	$	237,291	$	1,493,489	$	1,730,780


	December 31, 2020
	Current		Noncurrent		Total
	(Thousands of dollars)
Under-recovered purchased-gas costs	$	16,502	$	—	$	16,502
Pension and postemployment benefit costs	16,541		341,266		357,807
Reacquired debt costs	812		4,866		5,678
MGP remediation costs	98		18,711		18,809
Ad-valorem tax	5,558		—		5,558
WNA	4,806		—		4,806
Customer credit deferrals	10,267		—		10,267
Other	2,189		2,113		4,302
Total regulatory assets, net of amortization	56,773		366,956		423,729
Income tax rate changes	—		(547,563)		(547,563)
Over-recovered purchased-gas costs	(15,761)		—		(15,761)
Total regulatory liabilities	(15,761)		(547,563)		(563,324)
Net regulatory assets and liabilities	$	41,012	$	(180,607)	$	(139,595)

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

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

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

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

In April 2021, a bill permitting the state to pursue securitized financing of extraordinary expenses, such as fuel costs, financing costs and other operational costs incurred by regulated utilities during extreme weather events, was signed into law by the Oklahoma governor. On April 29, 2021, Oklahoma Natural Gas submitted an initial application requesting a financing order pursuant to this legislation. On July 30, 2021, Oklahoma Natural Gas filed a supplemental motion with its compliance report pursuant to the March 2, 2021 order from the OCC detailing the extent of extraordinary costs incurred and all required components pursuant to the legislation for the issuance of a financing order, which includes a proposed period of 20 years over which these costs will be collected from customers. On October 4, 2021, the Public Utility Division of the OCC filed responsive testimony recommending that a financing order for securitization be approved. A hearing before the administrative

law judge has been scheduled for November 22, 2021. The OCC has 180 days from the filing date of the supplemental motion to consider the issuance of a financing order. If the OCC approves the financing order, the ODFA has 24 months to complete the process to issue the securitized bonds.

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

On July 30, 2021, Kansas Gas Service submitted its compliance report to the KCC, which includes a proposal to issue securitized bonds and collect the extraordinary costs resulting from Winter Storm Uri from its customers over a period of either 5, 7 or 10 years. A procedural schedule will be developed to determine the timeline for evaluating Kansas Gas Service’s compliance report. If the KCC approves Kansas Gas Service’s proposed financing plan, then Kansas Gas Service will file an application, in a separate proceeding, requesting a financing order for the issuance of securitized utility tariff bonds. The KCC will have 180 days from the date of the filing requesting a financing order to consider Kansas Gas Service’s application. If the KCC approves the financing order, we can begin the process to issue the securitized bonds.

In May 2021, Kansas Gas Service filed a motion requesting a limited waiver of 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. On October 8, 2021, a non-unanimous settlement agreement was filed with the KCC to reach a resolution on these penalties. A proposed procedural schedule for consideration of the settlement agreement was filed and under this proposed agreement, the KCC would issue an order on the settlement by December 30, 2021. Under the terms of the settlement, if approved, any amounts collected from these penalties would reduce the regulatory asset for the winter weather event by no more than $83.0 million.

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

application and an additional 90 days to issue a single financing order for Texas Gas Service and any other natural gas utilities in Texas participating in the securitization process, which will include a determination of the period over which the costs will be collected from customers. Upon issuance of a financing order, the TPFA will begin the process to issue the securitized bonds.

In accordance with these regulatory orders associated with the winter weather event, we have deferred approximately $2.0 billion in extraordinary costs for natural gas purchases, related financing and carrying costs and other operational costs, which includes $1.3 billion of costs attributable to Oklahoma Natural Gas customers, $385.8 million of costs attributable to Kansas Gas Service customers and $255.1 million of costs attributable to Texas Gas Service customers, which includes $59.5 million attributable to the West Texas Service Area. The amounts deferred at September 30, 2021, include invoiced costs for natural gas purchases that have not been paid as we work with our suppliers to resolve discrepancies in invoiced amounts. The amounts deferred may be adjusted as the differences are resolved. In addition, as a result of Winter Storm Uri, we were assessed penalties as a result of over- or under-deliveries of natural gas during periods that operational flow orders were imposed on us. Regarding Kansas Gas Service’s motion requesting a limited waiver of penalty provisions of its tariff, if the non-unanimous settlement agreement filed with the KCC is approved, we anticipate assessing penalties on our transport customers or their agents. 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 such penalties is determined. As these amounts are related to the extraordinary gas purchase costs associated with Winter Storm Uri, which are deferred, future adjustments are not expected to have a material impact on earnings.

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

The customer credit deferrals and the noncurrent regulatory liability for income tax rate changes represents deferral of the effects of enacted federal and state income tax rate changes on our ADIT and the effects of these changes on our rates. At September 30, 2021, the noncurrent regulatory liability for income tax rate changes includes the reclassification of $29.3 million of deferred taxes related to the reduction of the state income tax rate in Oklahoma. Additionally, it includes the reclassification of $81.5 million of deferred taxes related to the elimination of state income tax for utilities in Kansas at September 30, 2021 and December 31, 2020. See Note 10 for additional information regarding the impact of income tax rate changes during the third quarter 2021.

See Note 12 for additional information regarding our regulatory assets for MGP remediation costs.

We have received accounting orders in each of our jurisdictions authorizing us to accumulate and defer for regulatory purposes certain incremental costs incurred, including bad debt expenses, and certain lost revenues, net of offsetting expense reductions associated with COVID-19. Pursuant to these orders, the recovery of any net incremental costs and lost revenues will be determined in future rate cases or alternative rate recovery filings in each jurisdiction. For financial reporting purposes, any amounts deferred as a regulatory asset for future recovery under these accounting orders must be probable of recovery. At September 30, 2021, no regulatory assets have been recorded. We continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable.

Recovery through rates resulted in amortization of regulatory assets of approximately $0.5 million and $0.3 million for the three months ended September 30, 2021 and 2020, respectively, and approximately $4.4 million and $2.4 million for the nine months ended September 30, 2021 and 2020, respectively.

4.CREDIT FACILITY AND SHORT-TERM DEBT

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. The commercial paper are generally sold at par less a discount representing an interest factor. At September 30, 2021, we had $336.0 million of commercial paper outstanding.

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

The ONE Gas Credit Agreement provides for a $1.0 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. We will be able to extend the maturity date by one year, subject to the lenders’ consent, up to two times. The ONE Gas Credit Agreement expires in March 2026, and is available to provide liquidity for working capital, capital expenditures, acquisitions and mergers, the issuance of letters of credit and for other general corporate purposes.

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

The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 72.5 percent at the end of any calendar quarter through December 31, 2021, and 70 percent at the end of any calendar quarter thereafter. At September 30, 2021, our total debt-to-capital ratio was 63 percent and we were in compliance with all covenants under the ONE Gas Credit Agreement. We may reduce the unutilized portion of the ONE Gas Credit Agreement in whole or in part without premium or penalty. The ONE Gas Credit Agreement contains customary events of default. Upon the occurrence of certain events of default, the obligations under the ONE Gas Credit Agreement may be accelerated and the commitments may be terminated.

At September 30, 2021, we had $1.2 million in letters of credit issued and no borrowings under the ONE Gas Credit Agreement, with $998.8 million of remaining credit, which is available to repay any of our commercial paper borrowings.

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

5.LONG-TERM DEBT

Senior Notes - In March 2021, we issued $1.0 billion of 0.85 percent senior notes due 2023, $700 million of 1.10 percent senior notes due 2024, and $800 million of floating-rate senior notes due 2023. The floating-rate senior notes bear interest at a rate equal to three-month LIBOR plus 61 basis points per year, reset quarterly for the applicable interest period (0.73 percent at September 30, 2021). 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 the event LIBOR is not available, and such circumstances are unlikely to be temporary, we or our designee may establish an alternative interest rate for our floating-rate senior notes due 2023 by replacing LIBOR with one or more secured financing-based rates or another alternate benchmark rate.

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

On September 21, 2021, we redeemed $400 million of the floating-rate senior notes due 2023 at par, using a combination of cash on hand and commercial paper.

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

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

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

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, 2021 and 2020, respectively, we issued and sold 281,124 shares and 179,514 shares of our common stock for $21.4 million and $13.6 million, generating proceeds, net of issuance costs, of $21.1 million and $13.5 million. At September 30, 2021, we had $215.0 million of equity available for issuance under the program.

Dividends Declared - In November 2021, we declared a dividend of $0.58 per share ($2.32 per share on an annualized basis) for shareholders of record as of November 15, 2021, payable on December 1, 2021.

7.ACCUMULATED OTHER COMPREHENSIVE LOSS

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


	Three Months Ended				Nine Months Ended				Affected Line Item in the
Details About Accumulated Other	September 30,				September 30,				Consolidated Statements
Comprehensive Loss Components	2021		2020		2021		2020		of Income
	(Thousands of dollars)
Pension and other postemployment benefit plan obligations (a)
Amortization of net loss	$	11,474	$	10,623	$	34,422	$	31,869
Amortization of unrecognized prior service credit	(70)		(29)		(210)		(87)
	11,404		10,594		34,212		31,782
Regulatory adjustments (b)	(11,013)		(10,296)		(33,040)		(30,888)
	391		298		1,172		894		Income before income taxes
	(91)		(75)		(273)		(224)		Income tax expense
Total reclassifications for the period	$	300	$	223	$	899	$	670	Net income

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

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

8.EARNINGS PER SHARE

Basic EPS is based on net income and is calculated based upon the daily weighted-average number of common shares outstanding during the periods presented. Also, this calculation includes fully vested stock awards that have not yet been issued

as common stock. Diluted EPS includes basic EPS, plus unvested stock awards granted under our compensation plans, but only to the extent these instruments dilute earnings per share.

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


	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


	Three Months Ended September 30, 2020
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	21,079	53,190	$	0.40
Diluted EPS Calculation
Effect of dilutive securities	—		218
Net income available for common stock and common stock equivalents	$	21,079	53,408	$	0.39


	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


	Nine Months Ended September 30, 2020
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	138,081	53,084	$	2.60
Diluted EPS Calculation
Effect of dilutive securities	—		229
Net income available for common stock and common stock equivalents	$	138,081	53,313	$	2.59

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,
	2021		2020		2021		2020
	(Thousands of dollars)
Components of net periodic benefit cost (credit)
Service cost	$	3,453	$	3,217	$	10,359	$	9,651
Interest cost	7,365		8,545		22,095		25,635
Expected return on assets	(15,596)		(15,280)		(46,788)		(45,840)
Amortization of net loss	11,381		10,580		34,143		31,740
Net periodic benefit cost	$	6,603	$	7,062	$	19,809	$	21,186


	Other Postemployment Benefits
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
	(Thousands of dollars)
Components of net periodic benefit cost (credit)
Service cost	$	397	$	423	$	1,191	$	1,269
Interest cost	1,563		1,889		4,689		5,667
Expected return on assets	(4,202)		(3,867)		(12,606)		(11,601)
Amortization of unrecognized prior service credit	(70)		(29)		(210)		(87)
Amortization of net loss	93		43		279		129
Net periodic benefit cost (credit)	$	(2,219)	$	(1,541)	$	(6,657)	$	(4,623)

We recover qualified pension benefit plan and other postemployment benefit plan costs through rates charged to our customers. Certain regulatory authorities require that the recovery of these costs be based on specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as authorized by the applicable regulatory authorities. Regulatory deferrals related to net periodic benefit cost were not material for the nine months ended September 30, 2021 and 2020, respectively.

We continue to capitalize all eligible service cost and non-service cost components under the accounting requirements of ASC Topic 980 (Regulated Operations) for rate-regulated entities. Our consolidated balance sheets reflect the capitalized non-service cost components as a regulatory asset in the amount of $6.1 million and $6.0 million as of September 30, 2021 and December 31, 2020, respectively. See Note 3 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.

10.INCOME TAXES

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

As of September 30, 2021, we have no uncertain tax positions. Changes in tax laws or tax rates are recognized in the financial reporting period that includes the enactment date. We are no longer subject to income tax examination for years prior to 2017.

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, will be addressed during the processing of the March 15, 2022 PBRC filing.

Income tax expense reflects credits for the amortization of the regulatory liability associated with EDIT that was returned to customers of $1.5 million and $2.2 million for the three months ended September 30, 2021 and 2020, respectively, and credits of $12.2 million and $11.6 million for the nine months ended September 30, 2021 and 2020, 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,
	2021		2020		2021		2020
	(Thousands of dollars)
Net periodic benefit cost other than service cost	$	(1,069)	$	(1,310)	$	(2,844)	$	(3,686)
Earnings (losses) on investments associated with nonqualified employee benefit plans	(267)		1,820		2,232		1,508

Other, net	(469)		(312)		(1,146)		(1,018)
Total other income (expense), net	$	(1,805)	$	198	$	(1,758)	$	(3,196)

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. Safety protocols developed during the pandemic include remote work for our office-based employees, limiting direct contact with our customers and requiring the use of PPE and a self-assessment health screening mobile application.

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

•lower late payment, reconnect and collection fees and incremental expenses for bad debts related to the suspension of disconnects for nonpayment in each of our jurisdictions;

•incremental expenses for PPE, cleaning supplies, outside services and other expenses; and

•lower expenses for travel and employee training that have been impacted by the pandemic.

We have received accounting orders in each of our jurisdictions authorizing us to accumulate and defer for regulatory purposes certain incremental costs incurred, including bad debt expenses, and certain lost revenues, net of offsetting expense reductions associated with COVID-19. Pursuant to these orders, the recovery of any net incremental costs and lost revenue will be determined in future rate cases or alternative rate recovery filings in each jurisdiction. For financial reporting purposes, any amounts deferred as a regulatory asset for future recovery under these accounting orders must be probable of recovery. At September 30, 2021, no regulatory assets have been recorded. We continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable. We do not expect COVID-related impacts to have a material adverse effect on our results of operations or cash flows during 2021.

Environmental Matters - We are subject to multiple historical, wildlife preservation and environmental laws and/or regulations, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits or the discovery of presently unknown environmental conditions may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation and remediation compliance to-date have not been significant in relation to our financial position, results of

operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and nine months ended September 30, 2021 and 2020.

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

We have completed or are addressing removal of the source of soil contamination at all 12 sites and continue to monitor groundwater at 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 was submitted to the KDHE concerning this site in 2020 and the KDHE has provided comments that we are addressing. We are also working on a remediation plan that will be submitted to the KDHE in 2021 for an additional site. In the third quarter 2021, we increased the estimates for contractor costs due to increased demand for the types of resources needed to conduct work contemplated in our remediation plans, resulting in an increase in our reserves of $11.2 million. At September 30, 2021, the reserve for remediation of our MGP sites was $24.7 million.

We have an AAO that allows Kansas Gas Service to defer and seek recovery of costs necessary for investigation and remediation at, and nearby, these 12 former MGP sites that are incurred after January 1, 2017, up to a cap of $15.0 million, net of any related insurance recoveries. Costs approved for recovery in a future rate proceeding would then be amortized over a 15-year period. The unamortized amounts will not be included in rate base or accumulate carrying charges. Following a determination that future investigation and remediation work approved by the KDHE is expected to exceed $15.0 million, net of any related insurance recoveries, Kansas Gas Service will be required to file an application with the KCC for approval to increase the $15.0 million cap. At September 30, 2021, we have deferred $30.0 million for accrued investigation and remediation costs pursuant to our AAO. Kansas Gas Service expects to file an application as soon as practicable after the KDHE approves the plans we have submitted and anticipates that filing will occur in 2021.

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

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and nine months ended September 30, 2021 and 2020. Environmental issues may exist with respect to MGP sites that are unknown to us. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation required, changing technology and governmental regulations, and to the extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition, results of operations or cash flows.

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

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

•an evaluation of whether natural gas pipeline integrity-management requirements should be expanded beyond current HCAs;

•a verification of records for pipelines in class 3 and 4 locations and HCAs to confirm MAOPs; and

•a requirement to test previously untested pipelines operating above 30 percent yield strength in HCAs.

In April 2016, PHMSA published a NPRM, the Safety of Gas Transmission & Gathering Lines Rule, in the Federal Register to revise pipeline safety regulations applicable to the safety of onshore natural gas transmission and gathering pipelines. Proposals include changes to pipeline integrity-management requirements and other safety-related requirements. The NPRM comment period ended July 7, 2016, and comments were reviewed by PHMSA. As part of the comment review process, PHMSA was advised by the Technical Pipeline Safety Standards Committee, informally known by PHMSA as the GPAC, a statutorily mandated advisory committee that advises PHMSA on proposed safety policies for natural gas pipelines. The GPAC reviews PHMSA's proposed regulatory initiatives to assure the technical feasibility, reasonableness, cost-effectiveness and practicality of each proposal. The GPAC met six times since January 2017 to review public comments and make recommendations to PHMSA. The GPAC completed their review of the NPRM on March 28, 2018, except for gas gathering pipelines. The GPAC met in June 2019 on gas gathering pipelines. In addition to reviewing public and committee comments, PHMSA split this NPRM into three separate final rulemakings:

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

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

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

A significant number of recommendations have been made to PHMSA to improve the NPRM. The industry trade associations filed joint comments to the “legislative mandates” rulemaking to amend the federal safety regulations applicable to gas transmission and gathering pipelines.

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

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

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

13.DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS

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

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

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

Recognition and Measurement

Accounting Treatment

Balance Sheet

Income Statement

Normal purchases and
normal sales

Fair value not recorded

Change in fair value not recognized in earnings

Mark-to-market

Recorded at fair value

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

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

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

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

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

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

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

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

Price Risk Management Activities - At September 30, 2021, we held purchased natural gas call options for the heating season ending March 2022, with total notional amounts of 34.1 Bcf, for which we paid premiums of $17.2 million, and which had a fair value of $77.4 million. At December 31, 2020, we held purchased natural gas call options for the heating season ended March 2021, with total notional amounts of 14.7 Bcf, for which we paid premiums of $6.7 million, and which had a fair value of $0.8 million. 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, 2021 and December 31, 2020, our other current and noncurrent assets include $4.1 million and $1.6 million of corporate bonds, respectively, and $2.3 million and $3.2 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.

Short-term notes payable and commercial paper are due upon demand and, therefore, the carrying amounts approximate fair value and are classified as Level 1. The book value of our long-term debt, including current maturities, was $3.7 billion and $1.6 billion at September 30, 2021 and December 31, 2020, respectively. The estimated fair value of our long-term debt,

including current maturities, was $3.9 billion and $2.0 billion at September 30, 2021 and December 31, 2020, respectively. The estimated fair value of our long-term debt was determined using quoted market prices, and is classified as Level 2.

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

RECENT DEVELOPMENTS

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

On March 11, 2021, we issued $1.0 billion of 0.85 percent senior notes due 2023, $700 million of 1.10 percent senior notes due 2024, and $800 million of floating-rate senior notes due 2023. The floating-rate senior notes bear interest at a rate equal to three-month LIBOR plus 61 basis points per year reset quarterly for the applicable interest period (0.73 percent at September 30, 2021). The net proceeds from the issuance were used for general corporate purposes, including payment of gas purchase costs resulting from Winter Storm Uri. The net proceeds of the March 2021 debt issuance reduced the commitments under the ONE Gas 2021 Term Loan Facility on a dollar-for-dollar basis, and as a result no commitments remained outstanding and the facility was terminated concurrently with the closing of the debt issuance.

Our purchased gas costs are recoverable through our tariffs in each state where we operate. Due to the higher level of gas purchase costs during Winter Storm Uri, related financing costs and other operational response costs, we are working with regulators to extend the recovery periods of such costs in order to lessen the immediate customer impact. In that regard, the OCC, KCC and the RRC each authorized certain utilities, including local natural gas distribution companies, to record regulatory assets to account for the extraordinary costs associated with this winter weather event, including but not limited to gas purchase costs and other costs related to the procurement and transportation of gas supply, carrying costs and other operational costs. As of September 30, 2021, we have deferred approximately $2.0 billion in costs associated with Winter Storm Uri.

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

ONE Gas Commercial Paper Program - On June 22, 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.

ONE Gas Credit Agreement - On March 16, 2021, we entered into the second amended and restated ONE Gas Credit Agreement, which was previously amended and restated on October 5, 2017. The ONE Gas Credit Agreement provides for a $1.0 billion revolving unsecured credit facility and includes a $20 million letter of credit subfacility and a $60 million swingline subfacility. In connection with the amendment of the ONE Gas Credit Agreement, all commitments under the ONE Gas 364- day Credit Agreement were terminated, and all obligations under the ONE Gas 364-day Credit Agreement were paid in full and discharged.

Debt Redemption - On September 21, 2021, we redeemed $400 million of the floating-rate senior notes due 2023 at par, using a combination of cash on hand and commercial paper.

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. Safety protocols developed during the pandemic include remote work for our office-based employees, limiting direct contact with our customers and requiring the use of PPE and a self-assessment health screening mobile application.

During the nine months ended September 30, 2021, impacts on our results of operations as a result of COVID-19 include but are not limited to:

•lower late payment, reconnect and collection fees and incremental expenses for bad debts related to the suspension of disconnects for nonpayment in each of our jurisdictions;

•incremental expenses for PPE, cleaning supplies, outside services and other expenses; and

•lower expenses for travel and employee training that have been impacted by the pandemic.

We have received accounting orders in each of our jurisdictions authorizing us to accumulate and defer for regulatory purposes certain incremental costs incurred, including bad debt expenses, and certain lost revenues, net of offsetting expense reductions associated with COVID-19. Pursuant to these orders, the recovery of any net incremental costs and lost revenue will be determined in future rate cases or alternative rate recovery filings in each jurisdiction. For financial reporting purposes, any amounts deferred as a regulatory asset for future recovery under these accounting orders must be probable of recovery. At September 30, 2021, no regulatory assets have been recorded. We continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial reporting purposes at such time as recovery is deemed probable. Accordingly, there could be a delay in the recognition of amounts that may be approved for recovery until the conclusion of future regulatory proceedings.

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

Dividend - In November 2021, we declared a dividend of $0.58 per share ($2.32 per share on an annualized basis) for shareholders of record as of November 15, 2021, payable on December 1, 2021.

REGULATORY ACTIVITIES

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

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

responsive testimony recommending that a financing order for securitization be approved. A hearing before the administrative law judge has been scheduled for November 22, 2021. The OCC has 180 days from the filing date of this supplemental motion to consider the issuance of a financing order. If the OCC approves the financing order, the ODFA has 24 months to complete the process to issue the securitized bonds. At September 30, 2021, Oklahoma Natural Gas has deferred approximately $1.3 billion in extraordinary costs attributable to Winter Storm Uri. See “Liquidity and Capital Resources,” in this Quarterly Report for additional discussion.

As required, PBRC filings are made annually on or before March 15, until the next general rate case, which was required to be filed on or before June 30, 2021, based on a calendar 2020 test year. On May 28, 2021, Oklahoma Natural Gas filed its general rate case. In October 2021, a joint stipulation and settlement agreement was signed by all parties to the rate case. The joint stipulation and settlement agreement was presented for consideration to an administrative law judge at a hearing on October 28, 2021. At the hearing, the administrative law judge recommended approval of the joint stipulation and settlement agreement. In accordance with Oklahoma law, the OCC has 180 days from the May 28, 2021 filing date to consider the recommendation and render a decision.

If the joint stipulation and settlement agreement is approved by the OCC as filed, Oklahoma Natural Gas’ base rates would increase $15.3 million. The joint stipulation also includes the continuation of the PBRC tariff that was established in 2009. The joint stipulation and settlement agreement includes a return on equity of 9.4 percent and a common equity ratio of 58.55 percent. Oklahoma Natural Gas would be required to file a rate case in 2027 based on a 12-month test year ending December 31, 2026. The joint stipulation and settlement agreement also states that Oklahoma Natural Gas shall 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 renewable natural gas to those customers who choose RNG for their fuel source.

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

In June 2020, the OCC issued an order permitting the creation of regulatory assets and deferrals related to COVID-19. Each utility is authorized under the OCC’s order to record as a regulatory asset increased bad debt expenses, costs associated with expanded payment plans, waived fees, and incremental expenses that are directly related to the suspension of or delay in disconnection of service (or the reconnection of service) beginning March 15, 2020, as a result of the governor’s executive order declaring a state of emergency. As of September 30, 2021, no regulatory assets have been recorded. In our May 2021 general rate case application, the test year includes the impacts of COVID-19 on our revenues and expenses through December 31, 2020, and we have proposed to include future impacts as part of the annual PBRC mechanism.

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

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

weather event to defer those costs to a regulatory asset account. These deferred costs may also include carrying costs at the utility’s weighted average cost of capital. Each jurisdictional utility will be required to file a compliance report detailing the extent of such costs incurred and presenting a plan to minimize the financial impacts of this event on ratepayers over a reasonable time frame. These costs will be subject to review for reasonableness and accuracy in future regulatory proceedings. On March 9, 2021, the KCC issued an order adopting the KCC staff’s recommendation to open company-specific dockets to accept each utility’s filing of financial impact compliance reports and permit the KCC staff to conduct a review of the utility’s compliance report and its actions during the winter weather event. In April 2021, a bill permitting utilities to pursue securitization to finance extraordinary expenses incurred during extreme weather events, was signed into law by the Kansas governor. This bill gives the KCC the authority to oversee and authorize the issuance of ratepayer-backed securitized bonds issued by a public utility.

On July 30, 2021, Kansas Gas Service submitted a compliance report to the KCC, which includes a proposal to issue securitized bonds and collect the extraordinary costs resulting from Winter Storm Uri from its customers over a period of either 5, 7, or 10 years. A procedural schedule will be developed to determine the timeline for evaluating Kansas Gas Service’s compliance report. If the KCC approves Kansas Gas Service’s proposed financing plan, then Kansas Gas Service will file an application, in a separate proceeding, requesting a financing order for the issuance of securitized utility tariff bonds. The KCC will have 180 days from the date of the filing requesting a financing order to consider Kansas Gas Service’s application. If the KCC approves the financing order, we can begin the process to issue the securitized bonds. At September 30, 2021, Kansas Gas Service has deferred approximately $385.8 million in extraordinary costs associated with Winter Storm Uri. See “Liquidity and Capital Resources,” in this Quarterly Report for additional discussion.

In August 2021, Kansas Gas Service submitted an application to the KCC requesting an increase related to its GSRS. On October 25, 2021, the KCC staff issued their Report and Recommendation for an increase of approximately $7.6 million. The KCC is expected to issue an order by December 23, 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 $81.5 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, 2021. The bill stipulates that, if requested by the utility, this EDIT will be returned to Kansas customers over a period of no less than 30 years, with the exact timing to be determined in our next general rate proceeding. In August 2020, Kansas Gas Service submitted an application to the KCC to reduce its base rates to reflect the elimination of Kansas state income taxes by approximately $4.9 million. In December 2020, the KCC approved the reduction, effective January 1, 2021. See Note 3 of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.

In April 2020, Kansas Gas Service filed an application with the KCC for an AAO to accumulate and defer certain incremental costs incurred, including bad debt expenses and lost revenues, as well as associated carrying costs, related to COVID-19 beginning March 1, 2020, for recovery in Kansas Gas Service’s next rate case filing. In July 2020, the KCC approved the request for an AAO subject to the recommendations set forth in its Staff Report and Recommendation and clarifications sought by Kansas Gas Service. The AAO provides notice that Kansas Gas Service may identify, track, document, accumulate, and defer in a regulatory asset extraordinary costs (net of any cost decreases) and lost revenue, plus carrying costs, associated with the COVID-19 pandemic. The KCC states that approval of the AAO is not a finding that tracked costs and lost revenue will be included in future rates; rather, any determination regarding recoverability will occur in a future rate proceeding. In a separate order applicable to all regulated utilities, the KCC approved the deferral of bad debt expense and late payment fees associated with the KCC’s suspension of disconnection activity and customer protection provisions. The recovery, the carrying charges and amortization period will be determined in Kansas Gas Service’s next rate case or alternative rate recovery filing. At September 30, 2021, no regulatory assets have been recorded. We continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial statement purposes at such time as recovery is deemed probable.

In November 2018, Kansas Gas Service submitted an application to the KCC requesting approval of its contract to operate and maintain the natural gas distribution system at Fort Riley, a United States Army installation. The KCC approved the Company’s application in May 2019. The transition period ended in June 2021, after which Kansas Gas Service assumed operation of the system.

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

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

In June 2021, a bill permitting the state to pursue securitized financing of extraordinary expenses, such as fuel costs, financing costs and other operational costs incurred by utilities during Winter Storm Uri, was signed into law by the Texas governor. This bill gives the RRC the authority to approve amounts to be recovered from the issuance of ratepayer-backed securitized bonds by the TPFA. Pursuant to this legislation and a June 17, 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. On October 29, 2021, Texas Gas Service, the other natural gas utilities in Texas participating in the securitization process, staff of the RRC and all intervenors filed a unanimous settlement agreement with the RRC. The signatories agreed that all costs to purchase natural gas volumes during Winter Storm Uri by Texas Gas Service 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. The unanimous settlement agreement will be considered by the RRC at a hearing on November 2, 2021. The RRC has 150 days from the date of the filing to consider Texas Gas Service’s application and an additional 90 days to issue a single financing order for Texas Gas Service and any other natural gas utilities in Texas participating in the securitization process, which will include a determination of the period over which the costs will be collected from customers. Upon issuance of a financing order, the TPFA will begin the process to issue the securitized bonds. At September 30, 2021, Texas Gas Service has deferred approximately $255.1 million in extraordinary costs associated with Winter Storm Uri, which includes $59.5 million attributable to the West Texas Service Area. See “Liquidity and Capital Resources,” in this Quarterly Report for additional discussion.

In April 2020, the RRC issued an order authorizing utilities to use a regulatory accounting mechanism and a subsequent process through which Texas Gas Service may seek future recovery of incremental expenses resulting from the effects of COVID-19, including bad debt and associated credit and collections costs, and other reasonable and necessary incremental costs to address the impact of COVID-19. The timing of any recovery will be determined as we work with our regulators. At September 30, 2021, no regulatory assets have been recorded. We continue to evaluate the impacts of COVID-19 on our business and will record regulatory assets for financial statement purposes at such time as recovery is deemed probable.

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

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

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

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

Other Texas Service Areas - In April 2021, Texas Gas Service filed annual Cost-of-Service Adjustments (COSA) for the incorporated areas of the Rio Grande Valley service area and the North Texas service area. In July 2021, the cities in the Rio Grande Valley and North Texas service areas agreed to increases of $3.5 million and $1.4 million, respectively. New rates will become effective in August 2021.

In the normal course of business, Texas Gas Service has filed rate cases and sought GRIP and COSA increases in various other Texas jurisdictions to address investments in rate base and changes in expenses. Annual rate increases associated with these filings that were approved totaled $0.3 million for the nine months ended September 30, 2021 and $1.8 million for the year ended December 31, 2020.

Winter Storm Uri Deferred Costs - The amounts deferred at September 30, 2021, include invoiced costs for natural gas purchases that have not been paid as we work with our suppliers to resolve discrepancies in invoiced amounts. The amounts deferred may be adjusted as the differences are resolved. In addition, as a result of Winter Storm Uri, we were assessed penalties as a result of over- or under-deliveries of natural gas during periods that operational flow orders were imposed on us. Regarding Kansas Gas Service’s motion requesting a limited waiver of penalty provisions of its tariff, if the non-unanimous settlement agreement filed with the KCC is approved, we anticipate assessing penalties on our transport customers or their agents. Amounts recorded reflect management’s best estimate and may be adjusted in future periods as the disposition of such penalties is determined. As these amounts are related to the extraordinary gas purchase costs associated with Winter Storm Uri, which are deferred, future adjustments are not expected to have a material impact on earnings.

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, 2021, net income was $20.3 million, or $0.38 per diluted share, compared with $21.1 million, or $0.39 per diluted share, in the same period last year. For the nine months ended September 30, 2021, net income was $145.9 million, or $2.72 per diluted share, compared with $138.1 million, or $2.59 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,				2021 vs. 2020				2021 vs. 2020
Financial Results	2021		2020		2021		2020		Increase (Decrease)				Increase (Decrease)
	(Millions of dollars, except percentages)
Natural gas sales	$	241.2	$	212.7	$	1,106.7	$	943.0	$	28.5	13	%	$	163.7	17	%
Transportation revenues	25.3		24.3		87.8		82.8		1.0		4	%	5.0		6	%
Other revenues	7.4		7.6		20.4		20.3		(0.2)		(3)	%	0.1		—	%
Total revenues	273.9		244.6		1,214.9		1,046.1		29.3		12	%	168.8		16	%
Cost of natural gas	59.4		40.5		467.2		329.1		18.9		47	%	138.1		42	%
Net margin	214.5		204.1		747.7		717.0		10.4		5	%	30.7		4	%
Operating costs	121.5		115.4		370.1		355.6		6.1		5	%	14.5		4	%
Depreciation and amortization	51.2		48.0		154.3		142.9		3.2		7	%	11.4		8	%
Operating income	$	41.8	$	40.7	$	223.3	$	218.5	$	1.1	3	%	$	4.8	2	%
Capital expenditures and asset removal costs	$	144.5	$	123.9	$	382.9	$	377.9	$	20.6	17	%	$	5.0	1	%

Natural gas sales to customers represent revenue from contracts with customers through implied contracts established by our tariffs and rates approved by the regulatory authorities, as well as revenues from regulatory mechanisms related to natural gas sales, which are included as other revenues in our Notes to Consolidated Financial Statements.

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

Other utility revenues include primarily miscellaneous service charges which represent implied contracts with customers established by our tariffs and rates approved by the regulatory authorities and other revenues from regulatory mechanisms, which are included in the consolidated statements of income and our Notes to Consolidated Financial Statements as other revenues.

Non-GAAP Financial Measure - We have disclosed net margin, which is considered a non-GAAP financial measure, in our selected financial data and selected financial results. Net margin is comprised of total revenues less cost of natural gas. Cost of natural gas includes commodity purchases, fuel, storage, transportation and other gas purchase costs recovered through our cost of natural gas regulatory mechanisms and does not include an allocation of general operating costs or depreciation and amortization. In addition, these regulatory mechanisms provide a method of recovering natural gas costs on an ongoing basis without a profit. Therefore, although our revenues will fluctuate with the cost of natural gas that we pass-through to our customers, net margin is not affected by fluctuations in the cost of natural gas. Accordingly, we routinely use net margin in the analysis of our financial performance. We believe that net margin provides investors a more relevant and useful measure to analyze our financial performance as a 100 percent regulated natural gas utility than total revenues because the change in the cost of natural gas from period to period does not impact our operating income. As such, the following discussion and analysis of our financial performance will reference net margin rather than total revenues and cost of natural gas individually.

The following table sets forth a reconciliation of net margin to the most directly comparable GAAP measure for the periods indicated:


	Three Months Ended				Nine Months Ended				Three Months				Nine Months
	September 30,				September 30,				2021 vs. 2020				2021 vs. 2020
Non-GAAP Reconciliation	2021		2020		2021		2020		Increase (Decrease)				Increase (Decrease)
	(Millions of dollars, except percentages)
Total revenues	$	273.9	$	244.6	$	1,214.9	$	1,046.1	$	29.3	12	%	$	168.8	16	%
Cost of natural gas	59.4		40.5		467.2		329.1		18.9		47	%	138.1		42	%
Net margin	$	214.5	$	204.1	$	747.7	$	717.0	$	10.4	5	%	$	30.7	4	%

The following table sets forth our net margin by type of customer for the periods indicated:


	Three Months Ended				Nine Months Ended				Three Months				Nine Months
	September 30,				September 30,				2021 vs. 2020				2021 vs. 2020
Net Margin	2021		2020		2021		2020		Increase (Decrease)				Increase (Decrease)
Natural gas sales	(Millions of dollars, except percentages)
Residential	$	151.2	$	144.1	$	531.9	$	511.4	$	7.1	5	%	$	20.5	4	%
Commercial and industrial	28.7		26.7		101.5		96.9		2.0		7	%	4.6		5	%
Other	1.9		1.4		6.1		5.6		0.5		36	%	0.5		9	%
Net margin on natural gas sales	181.8		172.2		639.5		613.9		9.6		6	%	25.6		4	%
Transportation revenues	25.3		24.3		87.8		82.8		1.0		4	%	5.0		6	%
Other revenues	7.4		7.6		20.4		20.3		(0.2)		(3)	%	0.1		—	%
Net margin	$	214.5	$	204.1	$	747.7	$	717.0	$	10.4	5	%	$	30.7	4	%

Our net margin on natural gas sales is comprised of two components, fixed and variable margin. Fixed margin reflects the portion of our net margin attributable to the monthly fixed customer charge component of our rates, which does not fluctuate based on customer usage in each period. Variable margin reflects the portion of our net margin that fluctuates with the volumes delivered and billed and the effects of weather normalization. The following table sets forth our net margin on natural gas sales by revenue type for the periods indicated:


	Three Months Ended				Nine Months Ended				Three Months				Nine Months
	September 30,				September 30,				2021 vs. 2020				2021 vs. 2020
Net Margin on Natural Gas Sales	2021		2020		2021		2020		Increase (Decrease)				Increase (Decrease)
Net margin on natural gas sales	(Millions of dollars, except percentages)
Fixed margin	$	162.0	$	154.2	$	472.5	$	457.7	$	7.8	5	%	$	14.8	3	%
Variable margin	19.8		18.0		167.0		156.2		1.8		10	%	10.8		7	%
Net margin on natural gas sales	$	181.8	$	172.2	$	639.5	$	613.9	$	9.6	6	%	$	25.6	4	%

Net margin increased $10.4 million for the three months ended September 30, 2021, compared with the same period last year, due primarily to the following:

•an increase of $7.0 million from new rates, primarily in Texas and Oklahoma;

•an increase of $2.1 million in residential sales due primarily to net customer growth in Oklahoma and Texas; and

•an increase of $0.8 million due to higher sales volumes, net of weather normalization.

Net margin increased $30.7 million for the nine months ended September 30, 2021, compared with the same period last year, due primarily to the following:

•an increase of $22.5 million from new rates, primarily in Texas and Oklahoma;

•an increase of $6.7 million in residential sales due primarily to net customer growth in Oklahoma and Texas;

•an increase of $2.0 million in rider and surcharge recoveries due to a higher ad-valorem surcharge in Kansas, which was offset by higher depreciation and amortization expense; and

•an increase of $1.8 million in transportation volumes, primarily in Kansas and Oklahoma, offset partially by;

•a decrease of $2.4 million due to the reduction in net margin associated with the impact of weather normalization, net of increased sales volumes, primarily in Texas and Oklahoma. For the nine months ended September 30, 2021, heating

degree days in Texas and Oklahoma were 24 percent and 19 percent higher, respectively, compared with the same period in 2020; and

•a decrease of $1.3 million due to the beneficial impact of a retroactive CNG federal excise tax credit in the prior year.

Operating costs increased $6.1 million for the three months ended September 30, 2021, compared with the same period last year, due primarily to the following:

•an increase of $3.1 million in outside services costs;

•an increase of $1.4 million in bad-debt expense; and

•an increase of $1.2 million in employee-related costs, offset partially by;

•a decrease of $1.1 million in expenses related to our response to the COVID-19 pandemic.

Operating costs increased $14.5 million for the nine months ended September 30, 2021, compared with the same period last year, due primarily to the following:

•an increase of $6.4 million in outside services costs;

•an increase of $5.8 million in employee-related costs; and

•an increase of $2.5 million in ad valorem taxes.

Depreciation and amortization expense increased $3.2 million and $11.4 million for the three and nine months ended September 30, 2021, compared with the same periods last year, due primarily to an increase in depreciation from our capital expenditures being placed in service and an increase in the amortization of the ad-valorem surcharge rider in Kansas.

Other Factors Affecting Net Income - Other factors that affected net income for the three months ended September 30, 2021, compared with the same period last year, include a decrease of $2.0 million in other income (expense), net, due primarily to a $2.1 million reduction in income resulting from the change in the value of investments associated with nonqualified employee benefit plans.

Other factors that affected net income for the nine months ended September 30, 2021, compared with the same period last year, include an increase of $1.4 million in other income (expense), net, due primarily to a $0.7 million increase in income resulting from the change in the value of investments associated with nonqualified employee benefit plans.

EDIT - We credited income tax expense $1.5 million and $2.2 million, respectively, for the amortization of the regulatory liability associated with EDIT that was returned to customers during the three months ended September 30, 2021 and 2020, and $12.2 million and $11.6 million, respectively, during the nine months ended September 30, 2021 and 2020.

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

Capital expenditures and asset removal costs were $20.6 million higher for the three months ended September 30, 2021, compared with the same period last year, due primarily to the timing of our capital projects in the third quarter 2021, compared with the third quarter 2020. Capital expenditures and asset removal costs were $5.0 million higher for the nine months ended September 30, 2021, compared with the same period last year, due primarily to the timing of capital projects in the first quarter 2021 being negatively impacted by Winter Storm Uri. Our full-year capital expenditures and asset removal costs are expected to be approximately $540 million for 2021.

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


	Three Months Ended								Variances
	September 30,								2021 vs. 2020
(in thousands)	2021				2020				Increase (Decrease)
Average Number of Customers	OK	KS	TX	Total	OK	KS	TX	Total	OK	KS	TX	Total
Residential	820	588	650	2,058	811	585	642	2,038	9	3	8	20
Commercial and industrial	75	50	34	159	74	49	35	158	1	1	(1)	1
Other	—	—	3	3	—	—	3	3	—	—	—	—
Transportation	5	6	1	12	5	6	1	12	—	—	—	—
Total customers	900	644	688	2,232	890	640	681	2,211	10	4	7	21


	Nine Months Ended								Variances
	September 30,								2021 vs. 2020
(in thousands)	2021				2020				Increase (Decrease)
Average Number of Customers	OK	KS	TX	Total	OK	KS	TX	Total	OK	KS	TX	Total
Residential	824	592	649	2,065	813	589	640	2,042	11	3	9	23
Commercial and industrial	76	50	35	161	75	50	36	161	1	—	(1)	—
Other	—	—	3	3	—	—	3	3	—	—	—	—
Transportation	5	6	1	12	5	6	1	12	—	—	—	—
Total customers	905	648	688	2,241	893	645	680	2,218	12	3	8	23

The increase in the average number of customers for the three and nine months ended September 30, 2021, compared with the same periods last year, is due primarily to the connection of new customers resulting from the extension and expansion of our system. For the three months ended September 30, 2021, our average customer count includes approximately 5,600 new customer connections during the period compared to approximately 6,700 for the same period last year. For the nine months ended September 30, 2021, our average customer count includes the impact of approximately 16,900 new customer connections during the period compared to approximately 18,600 for the same period last year. Also contributing to the increase is a reduction in disconnects for nonpayment in the first half of 2021 and other collection activities in response to the COVID-19 pandemic that have allowed customers to continue to receive service.

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


	Three Months Ended		Nine Months Ended
	September 30,		September 30,
Volumes (MMcf)	2021	2020	2021	2020
Natural gas sales
Residential	6,760	8,251	84,541	79,135
Commercial and industrial	3,539	3,603	27,645	24,644
Other	270	265	1,772	1,598
Total sales volumes delivered	10,569	12,119	113,958	105,377
Transportation	57,647	49,574	174,423	165,905
Total volumes delivered	68,216	61,693	288,381	271,282

Total sales volumes delivered increased for the nine months ended September 30, 2021, compared with the same period last year, due primarily to additional transportation volumes delivered in nine months ended September 30, 2021, and colder weather in the first quarter 2021. The impact of weather on residential and commercial net margin is mitigated by WNA mechanisms in all jurisdictions.

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


	Three Months Ended
	September 30,
	2021		2020		2021 vs. 2020		2021		2020
Heating Degree Days	Actual	Normal	Actual	Normal	Actual Variance		Actual as a percent of Normal
Oklahoma	—	2	22	2	(100)	%	—	%	1,100	%
Kansas	7	46	55	46	(87)	%	15	%	120	%
Texas	—	—	10	—	(100)	%	100	%	100	%


	Nine Months Ended
	September 30,
	2021		2020		2021 vs. 2020		2021		2020
Heating Degree Days	Actual	Normal	Actual	Normal	Actual Variance		Actual as a percent of Normal
Oklahoma	2,319	1,968	1,947	1,968	19	%	118	%	99	%
Kansas	2,912	2,901	2,719	2,901	7	%	100	%	94	%
Texas	1,127	1,050	910	1,062	24	%	107	%	86	%

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 2016 through the current period, 10-year weighted average HDDs as of December 31, 2014, 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. For 2017 to March 2019, 30-year average for years 1981-2010 published by the National Oceanic and Atmospheric Administration, as calculated using four 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.

We believe that the combination of the significant residential component of our customer base, the fixed-charge component of our natural gas sales net margin 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 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. By maintaining a conservative financial profile and stable revenue base, we expect to maintain an investment-grade credit rating, which we believe will provide us access to diverse sources of capital.

Short-term Debt - On June 22, 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. The commercial paper are generally sold at par less a discount representing an interest factor. At September 30, 2021, we had $336.0 million commercial paper outstanding.

On March 16, 2021, we entered into the second amended and restated ONE Gas Credit Agreement, which was previously amended and restated on October 5, 2017. The ONE Gas Credit Agreement provides for a $1.0 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. We will be able to extend the maturity date by one year, subject to the lenders’ consent, up to two times. The ONE Gas Credit Agreement expires in March 2026, and is available to provide liquidity for working capital, capital expenditures, acquisitions and mergers, the issuance of letters of credit and for other general corporate purposes.

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

At September 30, 2021, we had $1.2 million in letters of credit issued and no borrowings under the ONE Gas Credit Agreement, with $998.8 million of remaining credit available to repay our commercial paper borrowings.

Long-term Debt - In March 2021, we issued $1.0 billion of 0.85 percent senior notes due 2023, $700 million of 1.10 percent senior notes due 2024, and $800 million of floating-rate senior notes due 2023. The floating-rate senior notes bear interest at a rate equal to three-month LIBOR plus 61 basis points per year reset quarterly for the applicable interest period (0.73 percent at September 30, 2021). The net proceeds from the issuance were used for general corporate purposes, including payment of gas purchase costs resulting from Winter Storm Uri.

On September 21, 2021, we redeemed $400 million of the floating-rate senior notes due 2023 at par, using a combination of cash on hand and commercial paper.

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

In April 2021, legislation in Oklahoma and Kansas was approved and in June 2021, legislation in Texas was approved that permits utilities to pursue securitization to finance extraordinary expenses, such as fuel costs, incurred during extreme weather events. See “Regulatory Activities” for Oklahoma, Kansas and Texas in this Quarterly Report for additional discussion of the securitization legislation in each state. We are currently seeking approval from our regulators to utilize the securitization legislation in each state to repay or refinance the debt we incurred to finance the extraordinary costs associated with Winter Storm Uri.

At September 30, 2021, our long-term debt-to-capital ratio was 63 percent.

Credit Ratings - Our credit ratings as of September 30, 2021, were:


Rating Agency	Rating	Outlook
Moody’s	A3	Negative
S&P	BBB+	Negative

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. Sales of common stock are made by means of ordinary brokers’ transactions on the NYSE, in block transactions or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common stock under the program. During the nine months ended September 30, 2021 and 2020, respectively, we had issued and sold 281,124 shares and 179,514 shares of our common stock for $21.4 million and $13.6 million, generating proceeds, net of issuance costs, of $21.1 million and $13.5 million. At September 30, 2021, we had $215.0 million of equity available for issuance under the program. Proceeds from the program are available for general corporate purposes, which may include repaying or refinancing a portion of our outstanding indebtedness and funding working capital and capital expenditures.

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 offset by a noncash reduction in income tax expense. However, as a result, cash flows for the three months ended September 30, 2021 and 2020, were reduced by approximately $1.5 million and $2.2 million, respectively, for EDIT returned to customers. Cash flows for the nine months ended September 30, 2021 and 2020, were reduced by approximately $12.2 million and $11.6 million, respectively, for EDIT returned to customers.

Pension and Other Postemployment Benefit Plans - In 2021, our contributions are expected to be $1.1 million to our defined benefit pension plans, and no contributions are expected to be made to our other postemployment benefit plans. 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
	2021		2020		2021 vs. 2020
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	(1,560.6)	$	325.3	$	(1,885.9)
Investing activities	(349.4)		(347.8)		(1.6)
Financing activities	1,908.5		10.8		1,897.7
Change in cash and cash equivalents	(1.5)		(11.7)		10.2
Cash and cash equivalents at beginning of period	8.0		17.9		(9.9)
Cash and cash equivalents at end of period	$	6.5	$	6.2	$	0.3

Operating Cash Flows - Changes in cash flows from operating activities are due primarily to changes in net margin 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 lower for the nine months ended September 30, 2021, compared with the prior period, due primarily to the increased natural gas purchases 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.

Investing Cash Flows - Cash used in investing activities for the nine months ended September 30, 2021 was consistent compared with the prior period.

Financing Cash Flows - Cash provided by financing activities increased for the nine months ended September 30, 2021, compared with the prior period, due primarily to borrowings to finance the increased natural gas purchases resulting from Winter Storm Uri.

ENVIRONMENTAL, SAFETY AND REGULATORY MATTERS

COVID-19 - See “Regulatory Activities,” “Financial Results and Operating Information,” and “Capital Expenditures and Asset Removal Costs,” 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.

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, 2021 and 2020.

•an evaluation of whether natural gas pipeline integrity-management requirements should be expanded beyond current HCAs;

•a verification of records for pipelines in class 3 and 4 locations and HCAs to confirm MAOPs; and

•a requirement to test previously untested pipelines operating above 30 percent yield strength in HCAs.

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

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

Air and Water Emissions - The Clean Air Act, the Clean Water Act, 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. Under the Clean Air Act, 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. We do not expect that these expenditures will have a material impact on our respective results of operations, financial position or cash flows. The Clean Water Act imposes substantial potential liability for the removal of pollutants discharged to waters of the United States and remediation of waters affected by such discharge.

International, federal, regional and/or state legislative and/or regulatory initiatives may attempt to regulate greenhouse gas emissions. We monitor relevant legislation and regulatory initiatives to assess the potential impact on our operations. 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. 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.

CERCLA - 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) that caused and/or contributed to the release of a hazardous substance into the environment. 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. We do not expect that our responsibilities under CERCLA will have a material impact on our respective results of operations, financial position or cash flows.

Pipeline Security - In May and July 2021, the U.S. Department of Homeland Security’s Transportation Security Administration issued security directives which included several new cybersecurity requirements for critical pipeline owners and operators. We are currently evaluating 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.

The Transportation Security Administration issued pipeline security guidelines in March 2018. Our pipeline facilities have been reviewed according to those guidelines and no material changes have been required to date.

Environmental Footprint - Our environmental and climate change strategy focuses on taking steps to reduce the impact of our operations on the environment and exploring new opportunities for cleaner energy. These strategies include: (1) reducing emissions through our pipeline replacement program; (2) employing advanced leak detection technologies and reducing leaks on our pipelines; (3) promoting end-use conservation through programs that educate and incentivize customers to use energy efficient equipment; (4) reducing the release of methane into the atmosphere from operational practices, such as blow-downs and third-party line hits; (5) working to incorporate RNG into our system; and (6) investing in research and developing partnerships to understand the viability of blending renewable hydrogen into our system.

We participate in the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions. We continue to focus on reducing emissions through expanded implementation of best practices, such as mobile compression and vacuum technologies to limit the release of natural gas during pipeline and facility maintenance and operations. Additionally, in March 2016, we were one of 40 founding partners to launch the EPA’s Natural Gas STAR Methane Challenge Program, whereby oil and natural gas companies agree to promote and track commitments to reduce methane emissions beyond what is federally required. Our Methane Challenge Program commitment to annually replace or rehabilitate at least two percent of our combined inventory of cast iron and noncathodically-protected steel pipe 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 in 2016, 2017, 2018, and 2019 and anticipate reporting on our 2020 progress in 2021.

In September 2020, we announced membership in Our Nation’s Energy Future (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. In its most recent report, ONE Future reported that its members registered a 2019 methane intensity of 0.334%. We have submitted our 2020 data and anticipate that ONE Future will report on 2020 methane intensity in the fourth quarter of 2021.

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, 2021 and 2020.

Regulatory - Several regulatory initiatives impacted the earnings and future earnings potential of our business. See additional information regarding our regulatory initiatives in 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.

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 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), 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;

•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;

•regulations in local jurisdictions in which we operate authorizing utilities to record in a regulatory asset account or comparable account the expenses associated with Winter Storm Uri, including but not limited to gas costs, other costs related to the procurement and transportation of gas supply and the associated financing costs;

•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 may implement to address the pandemic or other health crises, 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;

•conservation and energy efficiency efforts of our customers;

•adverse weather conditions and variations in weather, including seasonal effects on demand and/or supply, the occurrence of storms, including Winter Storm Uri 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;

•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, margin 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 borrow funds, if needed, to meet our liquidity needs including raising the funds 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 each of our jurisdictions;

•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 conditions in these areas’ housing markets;

•acts of nature and the potential effects of threatened or actual terrorism and war;

•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;

•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;

•discovery of material weaknesses in our internal controls;

•our ability to comply with all covenants in our indentures, 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, and 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, increases in funding requirements for, our defined benefit plans; and

•the 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 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 2.2 million customers across three states, we are not exposed materially to a concentration of credit risk. As a result of regulatory orders and safety considerations, customer disconnects for nonpayment were generally suspended beginning mid-March 2020 through April 2021, when disconnects were resumed in all service areas, except Texas, where disconnects were resumed in June 2021. 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. See “Recent Developments” in this Quarterly Report for additional discussion

of the effects of COVID-19 on us. 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, 2021, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

Not applicable.

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.

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)).

	10.1	ONE Gas, Inc. Nonqualified Deferred Compensation Plan, as amended and restated effective January 1, 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 September 30, 2021 and 2020; (iii) Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2021 and 2020; (iv) Consolidated Balance Sheets at September 30, 2021 and December 31, 2020; (v) Consolidated Statements of Cash Flows for the nine months ended September 30, 2021 and 2020; (vi) Consolidated Statements of Equity for the three and nine months ended September 30, 2021 and 2020; 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.

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 2, 2021		ONE Gas, Inc.
		Registrant

	By:	/s/ Caron A. Lawhorn
		Caron A. Lawhorn
		Senior Vice President and
		Chief Financial Officer
		(Principal Financial Officer)