10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2017.

OR

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

For the transition period from __________ to __________.

Commission file number   001-36108

ONE Gas, Inc.

(Exact name of registrant as specified in its charter)

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

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

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 X  No __

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted 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 and post such files). 

Yes X 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 X	Accelerated filer __
Non-accelerated filer __	(Do not check if a smaller reporting company)
	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 X

On October 24, 2017, the Company had 52,273,783 shares of common stock outstanding.

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ONE Gas, Inc.

TABLE OF CONTENTS

Part I.	Financial Information	Page No.
Item 1.	Financial Statements (Unaudited)	7
	Statements of Income - Three and Nine Months Ended September 30, 2017 and 2016	7
	Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2017 and 2016	8
	Balance Sheets - September 30, 2017 and December 31, 2016	9
	Statements of Cash Flows - Nine Months Ended September 30, 2017 and 2016	12
	Statement of Equity - Nine Months Ended September 30, 2017	13
	Notes to the Financial Statements	15
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36
Item 4.	Controls and Procedures	37
Part II.	Other Information	38
Item 1.	Legal Proceedings	38
Item 1A.	Risk Factors	38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 3.	Defaults Upon Senior Securities	38
Item 4.	Mine Safety Disclosures	38
Item 5.	Other Information	38
Item 6.	Exhibits	38
Signature		40

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 subsidiary, 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” 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,” in this Quarterly Report and under Part I, Item IA, “Risk Factors,” in our Annual Report.

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INFORMATION AVAILABLE ON OUR WEBSITE

We make available, free of charge, on our website (www.onegas.com) copies of our Annual Reports on Form 10-K, 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.  Copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines and Director Independence Guidelines are also available on our website, and we will provide copies of these documents upon request.  Our website and any contents thereof are not incorporated by reference into this report.

We also make available on our website the Interactive Data Files required to be submitted and posted pursuant to Rule 405 of Regulation S-T.

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GLOSSARY

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

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AAO	Accounting Authority Order
Annual Report	Annual Report on Form 10-K for the year ended December 31, 2016
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
COSA	Cost-of-Service Adjustment
DOT	United States Department of Transportation
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	Texas Gas Reliability Infrastructure Program
GSRS	Kansas 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
IRS	Internal Revenue Service
KCC	Kansas Corporation Commission
KDHE	Kansas Department of Health and Environment
LDC	Local distribution company
MGP	Manufactured Gas Plant
MMcf	Million cubic feet
Moody’s	Moody’s Investors Service, Inc.
NPRM	Notice of Proposed Rulemaking
NYMEX	New York Mercantile Exchange
OCC	Oklahoma Corporation Commission
ONE Gas	ONE Gas, Inc.
ONE Gas Credit Agreement	ONE Gas’ $700 million revolving credit agreement, as amended, which expires on October 5, 2022
ONEOK	ONEOK, Inc. and its subsidiaries
PBRC	Performance-Based Rate Change
PHMSA	United States Department of Transportation Pipeline and Hazardous Materials Safety Administration
Pipeline Safety, Regulatory Certainty    and Job Creation Act	Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, as amended
Quarterly Report(s)	Quarterly Report(s) on Form 10-Q
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 $300 million of 2.07 percent senior notes due 2019, $300 million of 3.61 percent senior notes due 2024 and $600 million of 4.658 percent notes due 2044.
Separation and Distribution Agreement	Separation and Distribution Agreement dated January 14, 2014, between ONEOK and ONE Gas
WNA	Weather-normalization adjustments
XBRL	eXtensible Business Reporting Language

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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ONE Gas, Inc.
STATEMENTS OF INCOME
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Unaudited)	2017			2016			2017			2016
	(Thousands of dollars, except per share amounts)
Revenues	$	247,142		$	232,191		$	1,077,239		$	986,479
Cost of natural gas	58,769			52,253			404,495			344,439
Net margin	188,373			179,938			672,744			642,040
Operating expenses
Operations and maintenance	95,371			99,402			305,969			302,652
Depreciation and amortization	38,423			36,241			113,293			106,490
General taxes	13,799			13,403			43,518			42,311
Total operating expenses	147,593			149,046			462,780			451,453
Operating income	40,780			30,892			209,964			190,587
Other income	1,042			911			3,163			1,345
Other expense	(444		)	(357		)	(1,246		)	(1,126		)
Interest expense, net	(11,495		)	(10,809		)	(34,281		)	(32,504		)
Income before income taxes	29,883			20,637			177,600			158,302
Income taxes	(11,086		)	(7,900		)	(61,724		)	(60,521		)
Net income	$	18,797		$	12,737		$	115,876		$	97,781
Earnings per share
Basic	$	0.36		$	0.24		$	2.21		$	1.86
Diluted	$	0.36		$	0.24		$	2.19		$	1.85
Average shares (thousands)
Basic	52,488			52,453			52,539			52,452
Diluted	52,926			52,942			52,984			52,962
Dividends declared per share of stock	$	0.42		$	0.35		$	1.26		$	1.05

See accompanying Notes to the Financial Statements.

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ONE Gas, Inc.
STATEMENTS OF COMPREHENSIVE INCOME
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(Unaudited)	2017		2016		2017		2016
	(Thousands of dollars)
Net income	$	18,797	$	12,737	$	115,876	$	97,781
Other comprehensive income (loss), net of tax
Change in pension and other postemployment benefit plan liability, net of tax of $(81), $(72), $(242) and $(217), respectively	128		116		386		347
Total other comprehensive income, net of tax	128		116		386		347
Comprehensive income	$	18,925	$	12,853	$	116,262	$	98,128

See accompanying Notes to the Financial Statements.

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ONE Gas, Inc.
BALANCE SHEETS
	September 30,		December 31,
(Unaudited)	2017		2016
Assets	(Thousands of dollars)
Property, plant and equipment
Property, plant and equipment	$	5,643,136	$	5,404,168
Accumulated depreciation and amortization	1,730,857		1,672,548
Net property, plant and equipment	3,912,279		3,731,620
Current assets
Cash and cash equivalents	6,872		14,663
Accounts receivable, net	127,689		290,944
Materials and supplies	38,789		34,084
Natural gas in storage	157,641		125,432
Regulatory assets	99,548		83,146
Other current assets	15,014		20,654
Total current assets	445,553		568,923
Goodwill and other assets
Regulatory assets	411,653		440,522
Goodwill	157,953		157,953
Other assets	43,625		43,773
Total goodwill and other assets	613,231		642,248
Total assets	$	4,971,063	$	4,942,791

See accompanying Notes to the Financial Statements.

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ONE Gas, Inc.
BALANCE SHEETS
(Continued)
	September 30,			December 31,
(Unaudited)	2017			2016
Equity and Liabilities	(Thousands of dollars)
Equity and long-term debt
Common stock, $0.01 par value: authorized 250,000,000 shares; issued 52,598,005 shares and outstanding 52,273,444 shares at September 30, 2017; issued 52,598,005 and outstanding 52,283,260 shares at December 31, 2016	$	526		$	526
Paid-in capital	1,735,638			1,749,574
Retained earnings	221,185			161,021
Accumulated other comprehensive income (loss)	(4,329		)	(4,715		)
Treasury stock, at cost: 324,561 shares at September 30, 2017 and 314,745 shares at December 31, 2016	(21,028		)	(18,126		)
Total equity	1,931,992			1,888,280
Long-term debt, excluding current maturities, and net of issuance costs of $8,239 and $8,851, respectively	1,193,052			1,192,446
Total equity and long-term debt	3,125,044			3,080,726
Current liabilities
Notes payable	174,000			145,000
Accounts payable	68,184			131,988
Accrued interest	7,742			18,854
Accrued taxes other than income	44,658			42,571
Accrued liabilities	18,535			22,931
Customer deposits	59,643			61,209
Other current liabilities	19,466			21,380
Total current liabilities	392,228			443,933
Deferred credits and other liabilities
Deferred income taxes	1,089,061			1,038,568
Employee benefit obligations	282,904			303,507
Other deferred credits	81,826			76,057
Total deferred credits and other liabilities	1,453,791			1,418,132
Commitments and contingencies
Total liabilities and equity	$	4,971,063		$	4,942,791

See accompanying Notes to the Financial Statements.

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ONE Gas, Inc.
STATEMENTS OF CASH FLOWS
	Nine Months Ended
	September 30,
(Unaudited)	2017			2016
	(Thousands of dollars)
Operating activities
Net income	$	115,876		$	97,781
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	113,293			106,490
Deferred income taxes	61,329			59,771
Share-based compensation expense	6,930			9,341
Provision for doubtful accounts	4,508			3,521
Changes in assets and liabilities:
Accounts receivable	158,747			107,762
Materials and supplies	(4,705		)	3,227
Natural gas in storage	(32,209		)	(2,077		)
Asset removal costs	(37,928		)	(40,715		)
Accounts payable	(65,983		)	(32,923		)
Accrued interest	(11,112		)	(11,182		)
Accrued taxes other than income	2,087			2,670
Accrued liabilities	(4,396		)	(13,658		)
Customer deposits	(1,566		)	100
Regulatory assets and liabilities	11,448			(18,726		)
Other assets and liabilities	(13,915		)	19,053
Cash provided by operating activities	302,404			290,435
Investing activities
Capital expenditures	(249,057		)	(231,336		)
Other	617			492
Cash used in investing activities	(248,440		)	(230,844		)
Financing activities
Borrowings (repayments) of notes payable, net	29,000			28,500
Repurchase of common stock	(17,512		)	(24,066		)
Issuance of common stock	2,208			1,983
Dividends paid	(65,996		)	(54,923		)
Tax withholdings related to net share settlements of stock compensation	(9,455		)	(9,005		)
Cash used in financing activities	(61,755		)	(57,511		)
Change in cash and cash equivalents	(7,791		)	2,080
Cash and cash equivalents at beginning of period	14,663			2,433
Cash and cash equivalents at end of period	$	6,872		$	4,513

See accompanying Notes to the Financial Statements.

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ONE Gas, Inc.
STATEMENT OF EQUITY
(Unaudited)	Common Stock Issued	Common Stock		Paid-in Capital
	(Shares)	(Thousands of dollars)
January 1, 2017	52,598,005	$	526	$	1,749,574
Cumulative effect of accounting change	—	—		—
Net income	—	—		—
Other comprehensive income	—	—		—
Repurchase of common stock	—	—		—
Common stock issued and other	—	—		(14,634		)
Common stock dividends - $1.26 per share	—	—		698
September 30, 2017	52,598,005	$	526	$	1,735,638

See accompanying Notes to the Financial Statements.

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ONE Gas, Inc.
STATEMENT OF EQUITY
(Continued)
(Unaudited)	Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Total Equity
	(Thousands of dollars)
January 1, 2017	$	161,021		$	(18,126	)	$	(4,715	)	$	1,888,280
Cumulative effect of accounting change	10,982			—			—			10,982
Net income	115,876			—			—			115,876
Other comprehensive income	—			—			386			386
Repurchase of common stock	—			(17,512		)	—			(17,512		)
Common stock issued and other	—			14,610			—			(24		)
Common stock dividends - $1.26 per share	(66,694		)	—			—			(65,996		)
September 30, 2017	$	221,185		$	(21,028	)	$	(4,329	)	$	1,931,992

See accompanying Notes to the Financial Statements.

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ONE Gas, Inc.

NOTES TO THE FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our accompanying unaudited 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 2016 year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. These unaudited financial statements should be read in conjunction with the audited financial statements and footnotes in our Annual Report. Due to the seasonal nature of our business, the results of operations for the three and nine months ended September 30, 2017, are not necessarily indicative of the results that may be expected for a 12-month period.

We provide natural gas distribution services to more than 2 million customers through our divisions in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. We serve residential, commercial, industrial and transportation customers in all three states. In addition, we also provide natural gas distribution services to wholesale and public authority customers.

Other - In October 2017, we filed and received approval from the Oklahoma Insurance Department to form a wholly-owned captive insurance company.

Use of Estimates - The preparation of our 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 financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, provision for doubtful accounts, unbilled revenues for natural gas delivered but for which meters have not been read, natural gas purchased but for which no invoice has been received, provision for income taxes, including any deferred tax valuation allowances, the results of litigation and various other recorded or disclosed amounts.

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

Segments - We operate in one reportable and operating business segment: regulated public utilities that deliver natural gas to residential, commercial, industrial, wholesale, public authority and transportation customers. The accounting policies for our segment are the same as described in Note 1 of our Notes to the Financial Statements in our Annual Report. We evaluate our financial performance principally on operating income. For the three and nine months ended September 30, 2017, and 2016, we had no single external customer from which we received 10 percent or more of our gross revenues.

Goodwill Impairment Test - We assess our goodwill for impairment at least annually as of July 1. At July 1, 2017, we assessed qualitative factors to determine whether it was more likely than not that the fair value of our reporting unit was less than its carrying amount. After assessing qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance), we determined that no further testing was necessary.

Recently Issued Accounting Standards Update - In August 2017, the FASB issued ASU 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities,” which allows more types of hedging strategies to be eligible for hedge accounting and simplifies application of hedge accounting. This new guidance is required for our interim and annual reports for periods beginning after December 15, 2018, and early adoption is permitted, but must be applied as of the beginning of the fiscal year, or initial application date. The impact of this guidance is not material to us, as we have not elected hedge accounting due to the nature of the types of derivatives we have entered.

In March 2017, the FASB issued ASU 2017-07, “Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost,” which requires (1) separation of net periodic service costs for pension and other postemployment benefits into service cost and other components, (2) presentation of the service cost component in the same line as other compensation costs rendered by pertinent employees during the period, and (3) reporting the other components of net periodic benefit costs separately from the service cost component and outside a subtotal of income from operations. Additionally, only the service cost component is eligible for capitalization, when

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applicable. However, all of our cost components remain eligible for capitalization under the accounting requirements for rate regulated entities.

We will adopt this guidance for our interim and annual reports for periods in the first quarter of 2018. When adopted, the presentation changes required for net periodic benefit costs will not impact previously reported net income; however, the reclassification of the other components of benefits costs will result in an increase in operating income and an increase in other expenses for 2016 and 2017. We will use the retroactive presentation that permits the use of the amounts disclosed for the various components of net benefit cost in our respective Annual Report’s Employee Benefit Plans footnote as the basis for the retrospective application. In addition, we are currently updating our systems for the capitalization of service costs to property and non-service costs to a regulatory asset on a prospective basis, as well as the appropriate accounts for non-service costs to apply retroactive reclassification.

In January 2017, the FASB issued ASU 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment,” which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 of the goodwill test, where the measurement of a goodwill impairment loss was determined by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Upon adoption, a goodwill impairment will be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill.  We early adopted this new guidance in the current quarter, and it did not have an impact on our financial statements. See our conclusions regarding our current year Goodwill Impairment Test above.

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. It is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and may be adopted a year earlier. The new guidance will be initially applied through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. We are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of 2021.

In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting,” which includes various new aspects to simplify how share-based payments are accounted for and presented in the financial statements. The new standard modifies several aspects of the accounting and reporting for employee share-based payments and related tax accounting impacts, including the presentation in the statements of operations and cash flows. We adopted this new guidance in the first quarter 2017, and in accordance with the transition requirements, we recorded $5.2 million of excess tax benefit in income tax expense and have transitioned all provisions of this new guidance prospectively, other than our presentation of our withholding shares for tax-withholding purposes, which we accounted for retrospectively in the financing activities section of the statement of cash flows. We recorded a noncash cumulative-effect increase of $11.0 million to retained earnings, with an offset to a deferred tax asset, as of the beginning of the reporting period in 2017, for excess tax benefits earned prior to January 1, 2017, that had not been recognized. We continue our use of the estimation method to account for share unit award forfeitures rather than actual forfeitures. The retrospective impact of our withholding shares for tax-withholding purposes to our Statement of Cash Flows for the nine months ended September 30, 2016, was a $9.0 million increase to net cash provided by operating activities and a $9.0 million decrease to net cash used in financing activities.

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” which prescribes recognizing lease assets and liabilities on the balance sheet and includes disclosure of key information about leasing arrangements.  A modified retrospective transition approach is required for leases existing at the time of adoption. We are evaluating our population of leases, analyzing lease agreements, and holding meetings with cross-functional teams to determine the potential impact of this accounting standard on our financial position and results of operations and the transition approach we will utilize. We are also continuing to monitor the FASB for additional guidance surrounding an exposure draft regarding land easements. This information will help us determine what information will ultimately be disclosed in our financial statements and footnotes. Until this item is resolved, we cannot complete our evaluation of the potential effect the new guidance will have on our financial position, results of operations, cash flows or business processes. We will adopt this new guidance in the first quarter of 2019.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers” (“ASC 606”), which clarifies and converges the revenue recognition principles under GAAP and International Financial Reporting Standards. In July 2015, FASB delayed the effective date for one year. We have substantially completed evaluating all of our sources of revenue to determine the potential effect on our financial position, results of operations, cash flows and the related accounting policies and business processes. We will adopt this new guidance for our interim and annual reports beginning in the first quarter 2018, using the modified retrospective method. Through our preliminary evaluation, we do not expect a cumulative adjustment to our opening retained earnings, if any, would be material. The only impact we expect would be a reclassification of certain revenues

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that do not meet the requirements under ASC 606 as revenues from contracts with customers, but will continue to be reflected as other revenues in determining total revenue. The items we expect to reclassify relate primarily to the weather normalization mechanism in Kansas, where the KCC determines how we account for variations in weather. We have determined the majority of our tariffs to be contracts with customers which are settled over time, where our performance obligation is settled with our customer when natural gas is received and simultaneously consumed. In addition, we will elect to use the invoice method, where we will recognize revenue for volumes delivered for which we have a right to invoice.

We will continue monitoring the accounting task forces and FASB for the final conclusions surrounding revenue recognition implementation guidance. This guidance will determine what will ultimately be disclosed in our financial statements and footnotes. In addition to updating our revenue recognition disclosures, additional disclosures may include disaggregation of revenues by types of service, source of revenue or customer class, performance obligations and other types of revenues. Until these items are resolved, we cannot complete our evaluation of the potential effect the new guidance will have on our financial position, results of operations, cash flows or business processes.

2. REGULATORY ASSETS AND LIABILITIES

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

	September 30, 2017
	Current			Noncurrent		Total
	(Thousands of dollars)
Under-recovered purchased-gas costs	$	43,997		$	—	$	43,997
Pension and postemployment benefit costs	31,530			399,154		430,684
Weather normalization	19,618			—		19,618
Reacquired debt costs	812			7,500		8,312
Other	3,591			4,999		8,590
Total regulatory assets, net of amortization	99,548			411,653		511,201
Over-recovered purchased-gas costs	(10,471		)	—		(10,471		)
Ad valorem tax	(356		)	—		(356		)
Total regulatory liabilities (a)	(10,827		)	—		(10,827		)
Net regulatory assets (liabilities)	$	88,721		$	411,653	$	500,374

(a) Included in other current liabilities in our Balance Sheets.

	December 31, 2016
	Current			Noncurrent		Total
	(Thousands of dollars)
Under-recovered purchased-gas costs	$	29,901		$	—	$	29,901
Pension and postemployment benefit costs	31,498			427,448		458,946
Weather normalization	17,661			—		17,661
Reacquired debt costs	812			8,108		8,920
Other	3,274			4,966		8,240
Total regulatory assets, net of amortization	83,146			440,522		523,668
Over-recovered purchased-gas costs	(10,154		)	—		(10,154		)
Ad valorem tax	(1,768		)	—		(1,768		)
Total regulatory liabilities (a)	(11,922		)	—		(11,922		)
Net regulatory assets (liabilities)	$	71,224		$	440,522	$	511,746

(a) Included in other current liabilities in our Balance Sheets.

Regulatory assets on our Balance Sheets, as authorized by various regulatory authorities, are probable of recovery. Base rates are designed to provide a recovery of costs during the period 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.

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3. CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE

In October 2017, we amended and restated our credit agreement. The ONE Gas Credit Agreement remains a $700.0 million revolving unsecured credit facility, and includes a $20.0 million letter of credit subfacility and a $60.0 million swingline subfacility. We will also be able to request an increase in commitments of up to an additional $500.0 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement expires in October 2022, 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 contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At September 30, 2017, our total debt-to-capital ratio was 41 percent and we were in compliance with all covenants under the ONE Gas Credit Agreement.

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

The ONE Gas Credit Agreement is available to repay the commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowing capacity under the ONE Gas Credit Agreement. At September 30, 2017, we had $174.0 million in short-term borrowings, $1.8 million in letters of credit issued under the ONE Gas Credit Agreement and $524.2 million of remaining credit available under the ONE Gas Credit Agreement.

4. LONG-TERM DEBT

We have senior notes consisting of $300 million of 2.07 percent senior notes due in 2019, $300 million of 3.61 percent senior notes due in 2024 and $600 million of 4.658 percent senior notes due in 2044. 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.

5. EQUITY

In the first six months of 2017, we repurchased approximately 256 thousand shares of our common stock for approximately $17.5 million. We did not repurchase any shares of our common stock during the three months ended September 30, 2017.

In October 2017, we declared a dividend of $0.42 per share ($1.68 per share on an annualized basis) for shareholders of record as of November 13, 2017, payable December 1, 2017.

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6. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following table sets forth the effect of reclassifications from accumulated other comprehensive income (loss) in our Statements of Income for the periods indicated:

	Three Months Ended						Nine Months Ended
Details about Accumulated Other Comprehensive	September 30,						September 30,						Affected Line Item in the
Income (Loss) Components	2017			2016			2017			2016			Statements of Income
	(Thousands of dollars)
Pension and other postemployment benefit plan obligations (a)
Amortization of net loss	$	10,648		$	10,040		$	31,944		$	30,113
Amortization of unrecognized prior service cost	(1,149		)	(909		)	(3,447		)	(2,725		)
	9,499			9,131			28,497			27,388
Regulatory adjustments (b)	(9,290		)	(8,943		)	(27,869		)	(26,824		)
	209			188			628			564			Income before income taxes
	(81		)	(72		)	(242		)	(217		)	Income tax expense
Total reclassifications for the period	$	128		$	116		$	386		$	347		Net income

(a) These components of accumulated other comprehensive income (loss) are included in the computation of net periodic benefit cost. See Note 8 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 2 for additional disclosures of regulatory assets and liabilities.

7. 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, 2017
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	18,797	52,488	$	0.36
Diluted EPS Calculation
Effect of dilutive securities	—		438
Net income available for common stock and common stock equivalents	$	18,797	52,926	$	0.36

	Three Months Ended September 30, 2016
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	12,737	52,453	$	0.24
Diluted EPS Calculation
Effect of dilutive securities	—		489
Net income available for common stock and common stock equivalents	$	12,737	52,942	$	0.24

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	Nine Months Ended September 30, 2017
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	115,876	52,539	$	2.21
Diluted EPS Calculation
Effect of dilutive securities	—		445
Net income available for common stock and common stock equivalents	$	115,876	52,984	$	2.19

	Nine Months Ended September 30, 2016
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	97,781	52,452	$	1.86
Diluted EPS Calculation
Effect of dilutive securities	—		510
Net income available for common stock and common stock equivalents	$	97,781	52,962	$	1.85

8. EMPLOYEE BENEFIT PLANS

In September 2017, we purchased group annuity contracts and transferred approximately $47 million of the assets and liabilities related to certain participants in our defined benefit pension plan to a third-party insurance company.

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,
	2017			2016			2017			2016
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	3,044		$	3,014		$	9,132		$	9,042
Interest cost	10,113			11,387			30,339			34,162
Expected return on assets	(14,624		)	(15,296		)	(43,872		)	(45,888		)
Amortization of net loss	9,027			8,886			27,081			26,657
Net periodic benefit cost	$	7,560		$	7,991		$	22,680		$	23,973

	Other Postemployment Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	627		$	637		$	1,881		$	1,913
Interest cost	2,472			2,626			7,416			7,880
Expected return on assets	(3,147		)	(3,070		)	(9,441		)	(9,212		)
Amortization of unrecognized prior service cost	(1,149		)	(909		)	(3,447		)	(2,725		)
Amortization of net loss	1,621			1,154			4,863			3,456
Net periodic benefit cost	$	424		$	438		$	1,272		$	1,312

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We recover qualified pension benefit plan and other postemployment benefit plan costs through rates charged to our customers. Certain regulatory authorities require that the recovery of these costs be based on specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as authorized by the applicable regulatory authorities. Regulatory deferrals related to net periodic benefit cost were not material for the three and nine months ended September 30, 2017.

9. COMMITMENTS AND CONTINGENCIES

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 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, 2017 and 2016.

We own or retain legal responsibility for the 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 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.

We have completed or addressed removal of the source of soil contamination at 11 of the 12 sites, and continue to monitor groundwater at eight of the 12 sites according to plans approved by the KDHE. Regulatory closure has been achieved at three of the 12 sites, but these sites remain subject to potential future requirements that may result in additional costs. During 2016, we completed a site assessment at the twelfth site where no active soil remediation has occurred. We have submitted a work plan to the KDHE for approval to address a source of contamination and associated contaminated soil on a portion of this site. We are also conducting a study of the feasibility of various options to address the remainder of the site. Costs associated with the remediation at this site are not expected to be material to our results of operations or financial position.

With regard to one of our former MGP sites, periodic monitoring and a 2016 interim site investigation indicated elevated levels of contaminants generally associated with MGP sites. Additional testing and work plan development is underway in 2017 to determine a remediation work plan to present to the KDHE for approval, which could impact our estimates of the cost of remediation at this site. In the fourth quarter of 2016, we estimated the potential costs associated with additional investigation and remediation to be in the range of $4.0 million to $7.0 million. A single reliable estimate of the remediation costs was not feasible due to the amount of uncertainty in the ultimate remediation approach that will be utilized. Accordingly, we recorded a reserve of $4.0 million for this site in the fourth quarter of 2016.

In April 2017, Kansas Gas Service filed an application with the KCC seeking approval of an AAO associated with the costs incurred at, and nearby, its 12 MGP sites. In October 2017, Kansas Gas Service, the KCC staff and the Citizens’ Utility Ratepayer Board filed a unanimous settlement agreement with the KCC.  If approved, the agreement will allow Kansas Gas Service to defer MGP costs (costs that are necessary for investigation and remediation at the 12 former MGP sites) incurred after January 1, 2017, up to a cap of $15.0 million, net of any related insurance recoveries. Costs approved 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. At the time future investigation and remediation work, net of any related insurance recoveries, is expected to exceed $15.0 million, Kansas Gas Service will be required to file an application with the KCC for approval to increase the $15.0 million cap. The KCC is expected to issue an order no later than early January 2018. If the agreement is approved, we expect to record a regulatory asset of approximately $5.9 million for estimated costs that have been accrued at January 1, 2017.

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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, 2017 and 2016. A number of 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.

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 high-consequence areas. 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 high-consequence areas;

• a verification of records for pipelines in class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and

• a requirement to test previously untested pipelines operating above 30 percent yield strength in high-consequence areas.

In April 2016, PHMSA published a NPRM, the Safety of Gas Transmission & Gathering Lines Rule, in the Federal Register to revise pipeline safety regulations applicable to the safety of onshore natural gas transmission and gathering pipelines. Proposals include changes to pipeline integrity management requirements and other safety-related requirements. The NPRM comment period ended July 7, 2016, and comments are under review by PHMSA. As part of the comment review process, PHMSA is being advised by the Technical Pipeline Safety Standards Committee, informally known by PHMSA as the GPAC, a statutorily mandated advisory committee that advises PHMSA on proposed safety policies for natural gas pipelines.  The GPAC reviews PHMSA's proposed regulatory initiatives to assure the technical feasibility, reasonableness, cost-effectiveness and practicality of each proposal.  The potential capital and operating expenditures associated with compliance with the proposed rule are currently being evaluated and could be significant depending on the final regulations.

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.

10. DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS

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

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

		Recognition and Measurement
Accounting Treatment		Balance Sheet		Income Statement
Normal purchases and normal sales	-	Recorded at historical cost	-	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

We have not elected to designate any of our derivative instruments as hedges. Premiums paid and any cash settlements received associated with the commodity derivative instruments entered into by us are included in, and recoverable through, the purchased-gas cost adjustment mechanisms.

Determining Fair Value - 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 financial statements based on the observability of inputs used to estimate such fair value. The levels of the hierarchy are described below:

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

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

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

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

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

Derivative Instruments -At September 30, 2017, we held purchased natural gas call options for the heating season ending March 31, 2018, with total notional amounts of 33.5 Bcf, for which we paid premiums of $10.9 million, and had a fair value of $6.9 million. At December 31, 2016, we held purchased natural gas call options for the heating season ended March 31, 2017, with total notional amounts of 14.3 Bcf, for which we paid premiums of $5.4 million, and had a fair value of $6.5 million. The premiums paid and any cash settlements received are recorded as part of our unrecovered purchased-gas costs in current regulatory assets as these contracts are included in, and recoverable through, the purchased-gas cost adjustment mechanisms. Additionally, changes in fair value associated with these contracts are deferred as part of our unrecovered purchased-gas costs in our 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 NYMEX-settled prices. There were no transfers between levels for the three and nine months ended September 30,2017 and 2016.

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.

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 $1.2 billion at both September 30, 2017 and December 31, 2016. The estimated fair value of our long-term debt, including current maturities, was $1.3 billion and $1.2 billion at September 30, 2017 and December 31, 2016, respectively. The estimated fair value of our

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Senior Notes at September 30, 2017 and December 31, 2016, was determined using quoted market prices, and are classified as Level 2.

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

The following discussion and analysis should be read in conjunction with our unaudited financial statements and the Notes to the 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, 2017, are not necessarily indicative of the results that may be expected for a 12-month period.

RECENT DEVELOPMENTS

Dividend - In October 2017, we declared a dividend of $0.42 per share ($1.68 per share on an annualized basis) for shareholders of record as of November 13, 2017, payable December 1, 2017.

REGULATORY ACTIVITIES

Oklahoma - In March 2017, Oklahoma Natural Gas filed its first annual PBRC following the general rate case that was approved in January 2016. This filing was based on a calendar test year of 2016. The PBRC filing demonstrated that Oklahoma Natural Gas was earning within the allowed return on equity range of 9.0 to 10.0 percent. Therefore, Oklahoma Natural Gas did not seek a modification to base rates. The filing also requested an energy efficiency program true-up and utility incentive adjustment of approximately $1.9 million. A joint stipulation and settlement agreement was approved by the OCC in August 2017. As required, PBRC filings are made annually on March 15, until the next general rate case, which is currently required to be filed on or before June 30, 2021, based on a calendar test year of 2020.

Kansas - In August 2017, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $2.9 million related to its GSRS. An order from the KCC is expected no later than December 2017, with new rates effective January 1, 2018.

In April 2017, Kansas Gas Service filed an application with the KCC seeking approval of an AAO associated with the costs incurred at, and nearby, its 12 MGP sites. In October 2017, Kansas Gas Service, the KCC staff and the Citizens’ Utility Ratepayer Board filed a unanimous settlement agreement with the KCC.  If approved, the agreement will allow Kansas Gas Service to defer MGP costs (costs that are necessary for investigation and remediation at the 12 former MGP sites) incurred after January 1, 2017, up to a cap of $15.0 million, net of any related insurance recoveries. Costs approved 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. At the time future investigation and remediation work, net of any related insurance recoveries, is expected to exceed $15.0 million, Kansas Gas Service will be required to file an application with the KCC for approval to increase the $15.0 million cap. The KCC is expected to issue an order no later than early January 2018. If the agreement is approved, we expect to record a regulatory asset of approximately $5.9 million for estimated costs that have been accrued at January 1, 2017.

In May 2016, Kansas Gas Service filed a request with the KCC for an increase in base rates, reflecting system investments and operating costs necessary to maintain the safety and reliability of its natural gas distribution system. In October 2016, Kansas Gas Service reached a unanimous settlement agreement with all parties for a net increase in base rates of approximately $8.1 million. Including the GSRS of approximately $7.4 million, the total base rate increase was $15.5 million. The agreement was a “black-box settlement,” meaning the parties agreed to a specific revenue number but no specific return on equity or determination with respect to other contested issues. Additionally, the agreement modified the weather normalization clause to accrue the variation in net margin resulting from the difference in actual weather relative to normal weather over 12 months, rather than five months. The KCC approved the new rates effective January 1, 2017.

Texas - West Texas Service Area - In March 2017, Texas Gas Service made GRIP filings for all customers in the West Texas service area. The RRC and the cities approved an increase of $4.3 million for the customers in the service area, and new rates became effective in July 2017.

In March 2016, Texas Gas Service filed a rate case for its El Paso, Dell City and Permian service areas, as well as consolidation of these three areas. In September 2016, the RRC approved the consolidation and a base rate increase of $8.8 million, which was based on a 9.5 percent return on equity and a 60.1 percent common equity ratio. In October 2016, new rates went into effect for all customers, except for those in the cities of the former Permian service area. Texas Gas Service filed for these new

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rates for customers in the cities of the former Permian service area in October 2016, and the rates became effective in December 2016.

Rio Grande Valley Service Area - In October 2017, Texas Gas Service filed a rate case requesting an increase in revenues of $0.5 million for its unincorporated areas of the Rio Grande Valley service area. If approved, new rates are expected to be effective in the fourth quarter of 2017.

In June 2017, Texas Gas Service filed a rate case for customers in its Rio Grande Valley service area. In October 2017, Texas Gas Service and the cities in the Rio Grande Valley service area agreed to an increase of $3.6 million, and new rates became effective in October 2017.

Central Texas Service Area - In March 2017, Texas Gas Service made GRIP filings for customers of the consolidated Central Texas service area. The cities and the RRC approved an increase of $4.9 million, and new rates became effective in June 2017.

In June 2016, Texas Gas Service filed a rate case for its Central Texas and South Texas service areas. The filing included a request to consolidate the South Texas service area with the Central Texas service area. Texas Gas Service filed this rate case directly with the cities of the Central Texas service area, which includes the city of Austin, and the RRC for the unincorporated areas. In October 2016, all parties to the filing reached a unanimous settlement agreement for an increase in revenues of $6.8 million for the new consolidated service area. New rates were effective in November 2016, for customers in the cities of the former Central Texas service area. RRC approval was received in November 2016 and new rates became effective for customers in the unincorporated areas of the new consolidated Central Texas service area the same month. Texas Gas Service received approval for the same rates in the incorporated areas of the former South Texas service area, with new rates effective in January 2017.

Gulf Coast Service Area - In December 2015, Texas Gas Service filed a rate case for its Galveston and South Jefferson County service areas, which included a request to consolidate these two service areas into a new Gulf Coast service area. Texas Gas Service filed this rate case directly with the incorporated cities and the RRC for the unincorporated areas. Texas Gas Service reached a unanimous settlement agreement with representatives of the cities and the staff of the RRC, on behalf of the unincorporated areas for an increase in revenues of $2.3 million. Following RRC approval, new rates became effective in May 2016.

Other Texas Service Areas - In the normal course of business, Texas Gas Service has 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 approved filings totaled $1.4 million for the nine months ended September 30, 2017, and $2.0 million for the year ended 2016.

OTHER

In October 2017, we filed and received approval from the Oklahoma Insurance Department to form a wholly-owned captive insurance company.

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FINANCIAL RESULTS AND OPERATING INFORMATION

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

Selected Financial Results - For the three months ended September 30, 2017, net income was $18.8 million, or $0.36 per diluted share, compared with $12.7 million, or $0.24 per diluted share in the same period last year. For the nine months ended September 30, 2017, net income was $115.9 million, or $2.19 per diluted share, compared with $97.8 million, or $1.85 per diluted share in the same period last year. Our prospective adoption of ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting,” resulted in favorable impacts to income tax expense and our net income from recording $5.2 million of excess tax benefits as a reduction to income tax expense in the first quarter 2017. 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,				2017 vs. 2016					2017 vs. 2016
Financial Results	2017		2016		2017		2016		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars, except percentages)
Natural gas sales	$	218.7	$	204.3	$	981.9	$	892.9	$	14.4		7	%	$	89.0	10	%
Transportation revenues	21.5		21.2		73.1		72.2		0.3			1	%	0.9		1	%
Cost of natural gas	58.8		52.2		404.5		344.4		6.6			13	%	60.1		17	%
Net margin, excluding other revenues	181.4		173.3		650.5		620.7		8.1			5	%	29.8		5	%
Other revenues	6.9		6.6		22.2		21.3		0.3			5	%	0.9		4	%
Net margin	188.3		179.9		672.7		642.0		8.4			5	%	30.7		5	%
Operating costs	109.1		112.7		349.4		344.9		(3.6		)	(3	)%	4.5		1	%
Depreciation and amortization	38.4		36.3		113.3		106.5		2.1			6	%	6.8		6	%
Operating income	$	40.8	$	30.9	$	210.0	$	190.6	$	9.9		32	%	$	19.4	10	%
Capital expenditures	$	94.4	$	86.5	$	249.1	$	231.3	$	7.9		9	%	$	17.8	8	%

Net margin is comprised of total revenues less cost of natural gas.  Cost of natural gas includes commodity purchases, fuel, storage, transportation, the cost of gas component of bad debts and other gas purchase costs recovered through our cost of natural gas regulatory mechanisms during the periods presented and does not include an allocation of general operating costs or depreciation and amortization.  Our cost of natural gas 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 gas that we recover, net margin is not affected by fluctuations in the cost of natural gas.

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

	Three Months Ended				Nine Months Ended				Three Months				Nine Months
Net Margin, Excluding Other	September 30,				September 30,				2017 vs. 2016				2017 vs. 2016
Revenues	2017		2016		2017		2016		Increase (Decrease)				Increase (Decrease)
Natural gas sales	(Millions of dollars, except percentages)
Residential	$	133.4	$	126.9	$	481.2	$	454.4	$	6.5	5	%	$	26.8		6	%
Commercial and industrial	25.4		24.1		91.9		89.6		1.3		5	%	2.3			3	%
Wholesale and public authority	1.1		1.1		4.3		4.5		—		—	%	(0.2		)	(4	)%
Net margin on natural gas sales	159.9		152.1		577.4		548.5		7.8		5	%	28.9			5	%
Transportation revenues	21.5		21.2		73.1		72.2		0.3		1	%	0.9			1	%
Net margin, excluding other revenues	$	181.4	$	173.3	$	650.5	$	620.7	$	8.1	5	%	$	29.8		5	%

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. We believe that the combination of the significant residential component of our customer base, the fixed charge component of our sales margin and our regulatory rate mechanisms that we have in place result in a stable cash flow profile. The following table sets forth our net margin on natural gas sales by revenue type for the periods indicated:

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	Three Months Ended				Nine Months Ended				Three Months				Nine Months
	September 30,				September 30,				2017 vs. 2016				2017 vs. 2016
Net Margin on Natural Gas Sales	2017		2016		2017		2016		Increase (Decrease)				Increase (Decrease)
Net margin on natural gas sales	(Millions of dollars, except percentages)
Fixed margin	$	142.0	$	137.0	$	422.7	$	418.8	$	5.0	4	%	$	3.9	1	%
Variable margin	17.9		15.1		154.7		129.7		2.8		19	%	25.0		19	%
Net margin on natural gas sales	$	159.9	$	152.1	$	577.4	$	548.5	$	7.8	5	%	$	28.9	5	%

Net margin increased $8.4 million for the three months ended September 30, 2017, compared with the same period last year, due primarily to the following:

• an increase of $5.7 million from new rates in Texas and Kansas;

• an increase of $1.0 million in residential sales due primarily to net customer growth in Oklahoma and Texas; and

• an increase of $0.9 million from the impact of the modified weather-normalization mechanism in Kansas.

Net margin increased $30.7 million for the nine months ended September 30, 2017, compared with the same period last year, due primarily to the following:

• an increase of $20.0 million from new rates in Texas and Kansas;

• an increase of $5.5 million from the impact of weather-normalization mechanisms, which offset warmer weather in 2017 compared with the same period in 2016;

• an increase of $2.7 million in residential sales due primarily to net customer growth in Oklahoma and Texas; and

• an increase of $1.7 million due primarily to higher transportation volumes from customers in Oklahoma and Kansas.

Operating costs decreased $3.6 million for the three months ended September 30, 2017, compared with the same period last year, due primarily to the following:

• a decrease of $1.6 million in costs associated with pipeline maintenance activities; and

• a decrease of $1.3 million in legal-related costs.

Operating costs increased $4.5 million for the nine months ended September 30, 2017, compared with the same period last year, due primarily to the following:

• an increase of $2.4 million from the deferral in the first quarter of 2016 of certain information technology costs incurred as a result of our separation from ONEOK in 2014, which was approved in Oklahoma as a regulatory asset;

• an increase of $1.7 million in information technology costs;

• an increase of $1.5 million in employee-related costs;

• an increase of $1.0 million in bad debt expense; and

• an increase of $0.8 million in costs associated with pipeline maintenance activities; offset partially by

• a decrease of $3.1 million in legal-related costs.

Depreciation and amortization expense increased $2.1 million and $6.8 million for the three and nine months ended September 30, 2017, respectively, compared with the same periods last year, due primarily to an increase in depreciation from our capital expenditures being placed in service, offset by decreases of $0.6 million and $1.7 million, respectively, in amortization expense associated primarily with other postemployment benefit deferrals in Kansas.

Capital Expenditures - Our capital expenditures program includes expenditures for pipeline integrity, extending service to new areas, modifications to customer service lines, increasing system capabilities, pipeline replacements, fleet, facilities and information technology assets. It is our practice to maintain and upgrade our infrastructure, facilities and systems to ensure safe, reliable and efficient operations.

Capital expenditures increased $7.9 million and $17.8 million for the three and nine months ended September 30, 2017, respectively, compared with the same periods last year, due primarily to increased system integrity activities and extending service to new areas.

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

	Three Months Ended								Variances
	September 30,								2017 vs. 2016
(in thousands)	2017				2016				Increase (Decrease)
Average Number of Customers	OK	KS	TX	Total	OK	KS	TX	Total	OK		KS	TX	Total
Residential	788	577	618	1,983	782	576	612	1,970	6		1	6	13
Commercial and industrial	72	50	34	156	71	50	34	155	1		—	—	1
Wholesale and public authority	—	—	3	3	—	—	3	3	—		—	—	—
Transportation	5	6	1	12	6	6	1	13	(1	)	—	—	(1	)
Total customers	865	633	656	2,154	859	632	650	2,141	6		1	6	13

	Nine Months Ended								Variances
	September 30,								2017 vs. 2016
(in thousands)	2017				2016				Increase (Decrease)
Average Number of Customers	OK	KS	TX	Total	OK	KS	TX	Total	OK	KS	TX	Total
Residential	793	583	618	1,994	788	582	612	1,982	5	1	6	12
Commercial and industrial	73	50	35	158	73	50	35	158	—	—	—	—
Wholesale and public authority	—	—	3	3	—	—	3	3	—	—	—	—
Transportation	6	6	1	13	5	6	1	12	1	—	—	1
Total customers	872	639	657	2,168	866	638	651	2,155	6	1	6	13

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
Volumes (MMcf)	2017	2016	2017	2016
Natural gas sales
Residential	7,449	7,425	69,578	69,687
Commercial and industrial	3,808	3,590	22,993	22,408
Wholesale and public authority	223	261	1,211	1,542
Total volumes sold	11,480	11,276	93,782	93,637
Transportation	46,412	46,036	156,589	154,857
Total volumes delivered	57,892	57,312	250,371	248,494

Total volumes sold increased slightly for the three months ended September 30, 2017, compared with the same period last year. The impact of weather on residential and commercial net margin is mitigated by weather-normalization mechanisms in all jurisdictions.

Wholesale sales represent contracted natural gas volumes that exceed the needs of our residential, commercial and industrial customer base and are available for sale to other parties. The impact to net margin from changes in volumes associated with these customers is minimal.

	Three Months Ended
	September 30,
	2017		2016		2017 vs. 2016		2017		2016
Heating Degree Days	Actual	Normal	Actual	Normal	Actual Variance		Actual as a percent of Normal
Oklahoma	3	2	3	2	—	%	150	%	150	%
Kansas	13	58	19	52	(32	)%	22	%	37	%
Texas	1	1	2	1	(50	)%	100	%	200	%

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	Nine Months Ended
	September 30,
	2017		2016		2017 vs. 2016		2017		2016
Heating Degree Days	Actual	Normal	Actual	Normal	Actual Variance		Actual as a percent of Normal
Oklahoma	1,577	1,968	1,730	1,968	(9	)%	80	%	88	%
Kansas	2,344	2,980	2,459	2,965	(5	)%	79	%	83	%
Texas	659	1,063	899	1,034	(27	)%	62	%	87	%

Normal HDDs are established through rate proceedings in each of our rate 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:

• 10-year weighted average HDDs as of December 31, 2014, for years 2005-2014, as calculated using 11 weather stations across Oklahoma and weighted on average customer count for Oklahoma;

• 30-year average for years 1981-2010 published by the National Oceanic and Atmospheric Administration, as calculated using 4 weather stations across Kansas and weighted on HDDs by weather station and customers for Kansas; and

• 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 jurisdiction for Texas.

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

• 11 weather stations and customers by month for Oklahoma;

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

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

Through March 31, 2017, Kansas Gas Services’ WNA clause required it to accrue the variation in net margin resulting from actual weather differing from normal weather occurring from November through March. Beginning in April 2017, Kansas Gas Services’ WNA clause requires an accrual each month of the year.

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 final 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, 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 regulatory rate mechanisms that we have in place result in a stable cash flow profile. Because the energy consumption of residential customers is less volatile compared with commercial and industrial customers, our business historically has generated stable and predictable net margin and cash flows. Additionally, we have several regulatory rate mechanisms in place to reduce the lag in earning a return on our capital expenditures. 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 and our financial condition and credit ratings. We believe that stronger credit ratings will provide a significant advantage to our business. By maintaining a conservative financial profile and stable revenue base, we believe that we will be able to maintain

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an investment-grade credit rating, which we believe will provide us access to diverse sources of capital at favorable rates in order to finance our infrastructure investments.

Short-term Financing - In October 2017, we amended and restated our credit agreement. The ONE Gas Credit Agreement remains a $700.0 million revolving unsecured credit facility, and includes a $20.0 million letter of credit subfacility and a $60.0 million swingline subfacility. We will also be able to request an increase in commitments of up to an additional $500.0 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement expires in October 2022, 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 contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At September 30, 2017, our total debt-to-capital ratio was 41 percent, and we were in compliance with all covenants under the ONE Gas Credit Agreement.

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

The ONE Gas Credit Agreement is available to repay the commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowing capacity under the ONE Gas Credit Agreement. At September 30, 2017, we had $174.0 million in short-term borrowings and $1.8 million in letters of credit issued under the ONE Gas Credit Agreement. At September 30, 2017, we had approximately $6.9 million of cash and cash equivalents and $524.2 million of remaining credit available under the ONE Gas Credit Agreement. The total amount of short-term borrowings authorized by ONE Gas’ Board of Directors is $1.2 billion.

Long-Term Debt - 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. At September 30, 2017, our long-term debt-to-capital ratio was 38 percent.

Credit Ratings- Our credit ratings as of September 30, 2017, were:

Rating Agency	Rating	Outlook
Moody’s	A2	Stable
S&P	A	Stable

Our commercial paper is currently rated Prime-1 by Moody’s and A-1 by S&P. We intend to maintain strong credit metrics while we pursue a 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.

Pension and Other Postemployment Benefit Plans- Information about our pension and other postemployment benefits plans, including anticipated contributions, is included under Note 11 of the ONE Gas Notes to the Financial Statements in our Annual Report. See Note 8 of the Notes to the Financial Statements in this Quarterly Report for additional information.

CASH FLOW ANALYSIS

We use the indirect method to prepare our 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.

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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
	2017			2016			2017 vs. 2016
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	302.4		$	290.4		$	12.0
Investing activities	(248.4		)	(230.8		)	(17.6		)
Financing activities	(61.8		)	(57.5		)	(4.3		)
Change in cash and cash equivalents	(7.8		)	2.1			(9.9		)
Cash and cash equivalents at beginning of period	14.7			2.4			12.3
Cash and cash equivalents at end of period	$	6.9		$	4.5		$	2.4

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. Changes in natural gas prices and demand for our services or natural gas, whether because of general economic conditions, changes in supply or increased competition from other service providers, could affect our earnings and operating cash flows.Typically, our cash flows from operations are greater in the first half of the year compared with the second half of the year.

Operating cash flows were higher for the nine months ended September 30, 2017, compared with the same period in 2016, due primarily to an increase in net income, offset partially by cash flows from operating asset and liability changes. Working capital changes related to accounts payable and natural gas in storage were impacted by higher costs of natural gas in the first nine months of 2017, compared with the same period in 2016. Changes in accounts receivable were impacted by a higher cost of natural gas delivered in the fourth quarter of 2016 collected in the nine months ended September 30, 2017, compared with the same period in 2015 collected in the nine months ended September 30, 2016. Additionally, we collected a tax receivable in 2016 related to the extension of the IRS rules for bonus depreciation in late 2015.

Investing Cash Flows-Cash used in investing activities increased for the nine months ended September 30, 2017, compared with the prior period, due primarily to an increase in capital expenditures related to increased system integrity activities and extending service to new areas during the nine months ended September 30, 2017.

Financing Cash Flows-Cash used in financing activities increased for the nine months ended September 30, 2017, compared with the prior period, due primarily to an increase in the dividend rate of seven cents compared with the same period in 2016, offset by the purchase of fewer shares of treasury stock.

ENVIRONMENTAL, SAFETY AND REGULATORY MATTERS

Environmental Matters - We are subject to multiple historical, wildlife preservation and environmental laws and/or regulations that 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 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, 2017 and 2016.

We own or retain legal responsibility for the 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

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and regulations. A consent agreement with the KDHE governs all 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.

We have completed or addressed removal of the source of soil contamination at 11 of the 12 sites, and continue to monitor groundwater at eight of the 12 sites according to plans approved by the KDHE. Regulatory closure has been achieved at three of the 12 sites, but these sites remain subject to potential future requirements that may result in additional costs. During 2016, we completed a site assessment at the twelfth site where no active soil remediation has occurred. We have submitted a work plan to the KDHE for approval to address a source of contamination and associated contaminated soil on a portion of this site. We are also conducting a study of the feasibility of various options to address the remainder of the site. Costs associated with the remediation at this site are not expected to be material to our results of operations or financial position.

With regard to one of our former MGP sites, periodic monitoring and a 2016 interim site investigation indicated elevated levels of contaminants generally associated with MGP sites. Additional testing and work plan development is underway in 2017 to determine a remediation work plan to present to the KDHE for approval, which could impact our estimates of the cost of remediation at this site. In the fourth quarter of 2016, we estimated the potential costs associated with additional investigation and remediation to be in the range of $4.0 million to $7.0 million. A single reliable estimate of the remediation costs was not feasible due to the amount of uncertainty in the ultimate remediation approach that will be utilized. Accordingly, we recorded a reserve of $4.0 million for this site in the fourth quarter of 2016.

In April 2017, Kansas Gas Service filed an application with the KCC seeking approval of an AAO associated with the costs incurred at, and nearby, its 12 MGP sites. In October 2017, Kansas Gas Service, the KCC staff and the Citizens’ Utility Ratepayer Board filed a unanimous settlement agreement with the KCC.  If approved, the agreement will allow Kansas Gas Service to defer MGP costs (costs that are necessary for investigation and remediation at the 12 former MGP sites) incurred after January 1, 2017, up to a cap of $15.0 million, net of any related insurance recoveries. Costs approved 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. At the time future investigation and remediation work, net of any related insurance recoveries, is expected to exceed $15.0 million, Kansas Gas Service will be required to file an application with the KCC for approval to increase the $15.0 million cap. The KCC is expected to issue an order no later than early January 2018. If the agreement is approved, we expect to record a regulatory asset of approximately $5.9 million for estimated costs that have been accrued at January 1, 2017.

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, 2017 and 2016. A number of 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.

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 high-consequence areas. 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 high-consequence areas;

• a verification of records for pipelines in class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and

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• a requirement to test previously untested pipelines operating above 30 percent yield strength in high-consequence areas.

In April 2016, PHMSA published a NPRM, the Safety of Gas Transmission & Gathering Lines Rule, in the Federal Register to revise pipeline safety regulations applicable to the safety of onshore natural gas transmission and gathering pipelines. Proposals include changes to pipeline integrity management requirements and other safety-related requirements. The NPRM comment period ended July 7, 2016, and comments are under review by PHMSA. As part of the comment review process, PHMSA is being advised by the Technical Pipeline Safety Standards Committee, informally known by PHMSA as the GPAC, a statutorily mandated advisory committee that advises PHMSA on proposed safety policies for natural gas pipelines.  The GPAC reviews PHMSA's proposed regulatory initiatives to assure the technical feasibility, reasonableness, cost-effectiveness and practicality of each proposal.  The potential capital and operating expenditures associated with compliance with the proposed rule are currently being evaluated and could be significant depending on the final regulations.

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 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 results of operations, financial position or cash flows.

Pipeline Security - The U.S. Department of Homeland Security’s Transportation Security Administration issued updated pipeline security guidelines in April 2012. Our pipeline facilities have been reviewed according to the current guidelines and no material changes have been required to date.

Environmental Footprint - Our environmental and climate change strategy focuses on taking steps to minimize the impact of our operations on the environment. These strategies include: (1) developing and maintaining an accurate greenhouse gas emissions inventory according to current rules issued by the EPA; (2) improving the integrity of our various pipelines; (3) following developing technologies for emission control; and (4) utilizing practices to reduce the loss of methane from our facilities.

We participate in the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions. We continue to focus on maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices 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 anticipate reporting in 2018 our calendar year 2017 performance relative to our commitment.

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Additional information about our environmental matters is included in the section entitled “Environmental Matters” in Note 9 of the Notes to the Financial Statements in this Quarterly Report.

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 the Financial Statements in this Quarterly Report.

ESTIMATES AND CRITICAL ACCOUNTING POLICIES

The preparation of our 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 financial statements. These estimates and assumptions also affect the reported amounts of revenue 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,” 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, 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 operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our regulated rates;

• our ability to manage our operations and maintenance costs;

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

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

commercial industrial customers;

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

• conservation efforts of our customers;

• variations in weather, including seasonal effects on demand, the occurrence of storms and disasters, and climate change;

• 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;

35

• 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;

• the mechanical integrity of facilities operated;

• operational hazards and unforeseen operational interruptions;

• adverse labor relations;

• the effectiveness of our strategies to reduce earnings lag, margin protection strategies and risk mitigation strategies;

• our ability to generate sufficient cash flows to meet all our cash needs;

• 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;

• 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;

• impact of potential impairment charges;

• volatility and changes in markets for natural gas;

• 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;

• changes in existing or the addition of new environmental, safety, tax and other laws, rules and regulations to which we and our subsidiaries are subject;

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

• advances in technology;

• population growth rates and changes in the demographic patterns of the markets we serve;

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

• cyber attacks or breaches of technology systems or information, affecting us, our customers or vendors;

• the sufficiency of insurance coverage to cover losses;

• the effects of our strategies to reduce tax payments;

• the outcomes, timing and effects of litigation and regulatory investigations, proceedings, including our rate cases, or inquiries;

• 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 and the ONE Gas Credit Agreement, a violation of which, if not cured in a timely manner, could trigger a default of our obligations;

• our ability to attract and retain talented employees, management and directors;

• declines in the discount rates on, declines in the market value of the debt and equity securities of, and increases in funding requirements for, our defined benefit plans;

• 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;

• the final resolutions or outcomes with respect to our contingent and other corporate liabilities related to the natural gas distribution business and any related actions for indemnification made pursuant to the Separation and Distribution Agreement with ONEOK; and

• the costs associated with increased regulation and enhanced disclosure and corporate governance requirements pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010.

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 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.

36

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. Additionally, we inject natural gas into storage during the summer months and withdraw the natural gas during the winter heating season. Pursuant to programs that are approved by our regulatory authorities, we use derivative instruments to mitigate the volatility of natural gas prices for anticipated natural gas purchases during the winter heating months. Premiums paid and any cash settlements received associated with these derivative instruments are included in, and recoverable through our purchased-gas cost adjustment mechanisms.

Interest-Rate Risk

We would be exposed to interest-rate risk with any new debt financing. We are able to manage interest-rate risk 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. With more than 2 million customers across three states, we are not exposed materially to a concentration of credit risk. We maintain a provision for doubtful accounts based upon factors surrounding the credit risk of customers, historical trends, consideration of the current credit environment and other information. In Oklahoma, Kansas and most jurisdictions we serve in Texas, we are able to recover the natural gas cost component of our uncollectible accounts 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, 2017, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

37

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.

38

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

Exhibit No.		Exhibit Description
	10.1	Credit Agreement, dated as of October 5, 2017, among ONE Gas, Inc., Bank of America, N.A., as administrative agent, swingline lender and a letter of credit issuer, and the other lenders and letter of credit issuers parties thereto (incorporated by reference to Exhibit 10.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed October 6, 2017 (File No. 1-36108)).
	31.1	Certification of Pierce H. Norton II pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2	Certification of Curtis L. Dinan pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32.1	Certification of Pierce H. Norton II 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 Curtis L. Dinan 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.
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.

Attached as Exhibit 101 to this Quarterly Report are the following XBRL-related documents: (i) Document and Entity Information; (ii) Statements of Income for the three and nine months ended September 30, 2017 and 2016; (iii) Statements of Comprehensive Income for the three and nine months ended September 30, 2017 and 2016; (iv) Balance Sheets at September 30, 2017 and December 31, 2016; (v) Statements of Cash Flows for the nine months ended September 30, 2017 and 2016; (vi) Statement of Equity for the nine months ended September 30, 2017; and (vii) Notes to the Financial Statements.

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

39

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: October 31, 2017		ONE Gas, Inc.
		Registrant
	By:	/s/ Curtis L. Dinan
		Curtis L. Dinan
		Senior Vice President,
		Chief Financial Officer and Treasurer
		(Principal Financial Officer)

40

EX-31.1

Exhibit 31.1

Certification

I, Pierce H. Norton II, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: October 31, 2017

/s/ Pierce H. Norton II

Pierce H. Norton II

Chief Executive Officer

EX-31.2

Exhibit 31.2

Certification

I, Curtis L. Dinan, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: October 31, 2017

/s/ Curtis L. Dinan

Curtis L. Dinan

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of ONE Gas, Inc. (the “Registrant”) for the period ending September 30, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Pierce H. Norton II, Chief Executive Officer of the Registrant, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ Pierce H. Norton II

Pierce H. Norton II

Chief Executive Officer

October 31, 2017

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

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of ONE Gas, Inc. (the “Registrant”) for the period ending September 30, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Curtis L. Dinan, Chief Financial Officer of the Registrant, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ Curtis L. Dinan

Curtis L. Dinan

Chief Financial Officer

October 31, 2017

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

XML

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Oct. 24, 2017
Document Information [Line Items]
Entity Registrant Name	ONE Gas, Inc.
Entity Central Index Key	0001587732
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		52,273,783
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017

XML

STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Gross Margin
Revenues	$ 247,142	$ 232,191	$ 1,077,239	$ 986,479
Cost of natural gas	58,769	52,253	404,495	344,439
Net margin	188,373	179,938	672,744	642,040
Operating expenses
Operations and maintenance	95,371	99,402	305,969	302,652
Depreciation and amortization	38,423	36,241	113,293	106,490
General taxes	13,799	13,403	43,518	42,311
Total operating expenses	147,593	149,046	462,780	451,453
Operating income	40,780	30,892	209,964	190,587
Other income	1,042	911	3,163	1,345
Other expense	(444)	(357)	(1,246)	(1,126)
Interest expense, net	(11,495)	(10,809)	(34,281)	(32,504)
Income before income taxes	29,883	20,637	177,600	158,302
Income taxes	(11,086)	(7,900)	(61,724)	(60,521)
Net income	$ 18,797	$ 12,737	$ 115,876	$ 97,781
Earnings per share
Basic	$ 0.36	$ 0.24	$ 2.21	$ 1.86
Diluted	$ 0.36	$ 0.24	$ 2.19	$ 1.85
Average shares (thousands)
Basic	52,488	52,453	52,539	52,452
Diluted	52,926	52,942	52,984	52,962
Dividends declared per share of stock	$ 0.42	$ 0.35	$ 1.26	$ 1.05

XML

STATEMENTS OF COMPREHENSIVE INCOME STATEMENTS OF COMPREHENSIVE INCOME Parenthetical - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
STATEMENTS OF COMPREHENSIVE INCOME Parenthetical [Abstract]
Pension and other postemployment benefit plans, tax	$ (81)	$ (72)	$ (242)	$ (217)

XML

STATEMENTS OF COMPREHENSIVE INCOME STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Net income	$ 18,797	$ 12,737	$ 115,876	$ 97,781
Other comprehensive income (loss), net of tax
Change in pension and postemployment benefit plan liability, net of tax of $(81), $(72), $(242), and $(217), respectively respectively	128	116	386	347
Other comprehensive income, net of tax	128	116	386	347
Comprehensive income	$ 18,925	$ 12,853	$ 116,262	$ 98,128

XML

BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Property, plant and equipment
Property, plant and equipment	$ 5,643,136	$ 5,404,168
Accumulated depreciation and amortization	1,730,857	1,672,548
Net property, plant and equipment	3,912,279	3,731,620
Current assets
Cash and cash equivalents	6,872	14,663
Accounts receivable, net	127,689	290,944
Materials and supplies	38,789	34,084
Natural gas in storage	157,641	125,432
Regulatory assets	99,548	83,146
Other current assets	15,014	20,654
Total current assets	445,553	568,923
Goodwill and other assets
Regulatory assets	411,653	440,522
Goodwill	157,953	157,953
Other assets	43,625	43,773
Total goodwill and other assets	613,231	642,248
Total assets	4,971,063	4,942,791
Equity and long-term debt
Common stock, $0.01 par value: authorized 250,000,000 shares; issued 52,598,005 shares and outstanding 52,273,444 shares at September 30, 2017; issued 52,598,005 and outstanding 52,283,260 at December 31, 2016	526	526
Paid-in Capital	1,735,638	1,749,574
Retained earnings	221,185	161,021
Accumulated other comprehensive income (loss)	(4,329)	(4,715)
Treasury stock, at cost: 324,561 shares at September 30, 2017 and 314,745 shares at December 31, 2016	21,028	18,126
Total equity	1,931,992	1,888,280
Long-term debt, excluding current maturities and net issuance costs of $8,239 and $8,851, respectively	1,193,052	1,192,446
Total equity and long-term debt	3,125,044	3,080,726
Current liabilities
Notes payable	174,000	145,000
Accounts payable	68,184	131,988
Accrued interest	7,742	18,854
Accrued taxes other than income	44,658	42,571
Accrued liabilities	18,535	22,931
Customer deposits	59,643	61,209
Other current liabilities	19,466	21,380
Total current liabilities	392,228	443,933
Deferred credits and other liabilities [Abstract]
Deferred income taxes	1,089,061	1,038,568
Employee benefit obligations	282,904	303,507
Other deferred credits	81,826	76,057
Total deferred credits and other liabilities	1,453,791	1,418,132
Commitments and contingencies
Total liabilities and equity	$ 4,971,063	$ 4,942,791

XML

BALANCE SHEETS BALANCE SHEETS Parenthetical - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Common stock, par value per share	$ 0.01	$ 0.01
Common stock, shares authorized	250,000,000	250,000,000
Common stock, shares issued	52,598,005	52,598,005
Common stock, shares outstanding	52,273,444	52,283,260
Treasury stock, shares	324,561	314,745
Debt issuance costs	$ 8,239	$ 8,851

XML

STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Document Fiscal Year Focus	2017
Operating activities
Net income	$ 115,876	$ 97,781
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	113,293	106,490
Deferred income taxes	61,329	59,771
Share-based compensation expense	6,930	9,341
Provision for doubtful accounts	4,508	3,521
Changes in assets and liabilities:
Accounts receivable	158,747	107,762
Materials and supplies	(4,705)	3,227
Natural gas in storage	(32,209)	(2,077)
Asset removal costs	(37,928)	(40,715)
Accounts payable	(65,983)	(32,923)
Accrued interest	(11,112)	(11,182)
Accrued taxes other than income	2,087	2,670
Accrued liabilities	(4,396)	(13,658)
Customer deposits	(1,566)	100
Regulatory assets and liabilities	11,448	(18,726)
Other assets and liabilities	(13,915)	19,053
Cash provided by operating activities	302,404	290,435
Investing activities
Capital expenditures	(249,057)	(231,336)
Other	617	492
Cash used in investing activities	(248,440)	(230,844)
Financing activities
Repayments of notes payable, net	29,000	28,500
Repurchase of common stock	(17,512)	(24,066)
Proceeds from Issuance of Common Stock	2,208	1,983
Dividends paid	(65,996)	(54,923)
Tax withholdings related to net share settlements of stock compensation	(9,455)	(9,005)
Cash used in financing activities	(61,755)	(57,511)
Change in cash and cash equivalents	(7,791)	2,080
Cash and cash equivalents at beginning of period	14,663	2,433
Cash and cash equivalents at end of period	$ 6,872	$ 4,513

XML

STATEMENT OF CHANGES IN EQUITY - 9 months ended Sep. 30, 2017 - USD ($) $ in Thousands	Total	Common Stock [Member]	Paid-in Capital [Member]	Retained Earnings [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
Shares issued, beginning balance at Dec. 31, 2016	52,598,005	52,598,005
Equity, beginning balance at Dec. 31, 2016	$ 1,888,280	$ 526	$ 1,749,574	$ 161,021	$ (18,126)	$ (4,715)
Cumulative effect of accounting change	10,982	0	0	10,982	0	0
Net income	115,876	0	0	115,876	0	0
Other comprehensive income	386	0	0	0		386
Repurchase of common stock	(17,512)	$ 0	0	0	(17,512)	0
Common stock issued, shares		0
Common stock issued, value	(24)	$ 0	(14,634)	0	14,610	0
Common stock dividends - $1.26 per share	$ (65,996)	$ 0	698	(66,694)	0	0
Shares issued, ending balance at Sep. 30, 2017	52,598,005	52,598,005
Equity, ending balance at Sep. 30, 2017	$ 1,931,992	$ 526	$ 1,735,638	$ 221,185	$ (21,028)	$ (4,329)

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Notes)

9 Months Ended

Sep. 30, 2017

Significant Accounting Policies [Line Items]

SIGNIFICANT ACCOUNTING POLICIES

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our accompanying unaudited 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 2016 year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. These unaudited financial statements should be read in conjunction with the audited financial statements and footnotes in our Annual Report. Due to the seasonal nature of our business, the results of operations for the three and nine months ended September 30, 2017, are not necessarily indicative of the results that may be expected for a 12-month period.

We provide natural gas distribution services to more than 2 million customers through our divisions in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. We serve residential, commercial, industrial and transportation customers in all three states. In addition, we also provide natural gas distribution services to wholesale and public authority customers.

Other - In October 2017, we filed and received approval from the Oklahoma Insurance Department to form a wholly-owned captive insurance company.

Use of Estimates - The preparation of our 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 financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, provision for doubtful accounts, unbilled revenues for natural gas delivered but for which meters have not been read, natural gas purchased but for which no invoice has been received, provision for income taxes, including any deferred tax valuation allowances, the results of litigation and various other recorded or disclosed amounts.

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

Segments - We operate in one reportable and operating business segment: regulated public utilities that deliver natural gas to residential, commercial, industrial, wholesale, public authority and transportation customers. The accounting policies for our segment are the same as described in Note 1 of our Notes to the Financial Statements in our Annual Report. We evaluate our financial performance principally on operating income. For the three and nine months ended September 30, 2017, and 2016, we had no single external customer from which we received 10 percent or more of our gross revenues.

Goodwill Impairment Test - We assess our goodwill for impairment at least annually as of July 1. At July 1, 2017, we assessed qualitative factors to determine whether it was more likely than not that the fair value of our reporting unit was less than its carrying amount. After assessing qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance), we determined that no further testing was necessary.

Recently Issued Accounting Standards Update - In August 2017, the FASB issued ASU 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities,” which allows more types of hedging strategies to be eligible for hedge accounting and simplifies application of hedge accounting. This new guidance is required for our interim and annual reports for periods beginning after December 15, 2018, and early adoption is permitted, but must be applied as of the beginning of the fiscal year, or initial application date. The impact of this guidance is not material to us, as we have not elected hedge accounting due to the nature of the types of derivatives we have entered.

In March 2017, the FASB issued ASU 2017-07, “Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost,” which requires (1) separation of net periodic service costs for pension and other postemployment benefits into service cost and other components, (2) presentation of the service cost component in the same line as other compensation costs rendered by pertinent employees during the period, and (3) reporting the other components of net periodic benefit costs separately from the service cost component and outside a subtotal of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all of our cost components remain eligible for capitalization under the accounting requirements for rate regulated entities.

We will adopt this guidance for our interim and annual reports for periods in the first quarter of 2018. When adopted, the presentation changes required for net periodic benefit costs will not impact previously reported net income; however, the reclassification of the other components of benefits costs will result in an increase in operating income and an increase in other expenses for 2016 and 2017. We will use the retroactive presentation that permits the use of the amounts disclosed for the various components of net benefit cost in our respective Annual Report’s Employee Benefit Plans footnote as the basis for the retrospective application. In addition, we are currently updating our systems for the capitalization of service costs to property and non-service costs to a regulatory asset on a prospective basis, as well as the appropriate accounts for non-service costs to apply retroactive reclassification.

In January 2017, the FASB issued ASU 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment,” which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 of the goodwill test, where the measurement of a goodwill impairment loss was determined by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Upon adoption, a goodwill impairment will be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill.  We early adopted this new guidance in the current quarter, and it did not have an impact on our financial statements. See our conclusions regarding our current year Goodwill Impairment Test above.

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. It is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and may be adopted a year earlier. The new guidance will be initially applied through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. We are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of 2021.

In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting,” which includes various new aspects to simplify how share-based payments are accounted for and presented in the financial statements. The new standard modifies several aspects of the accounting and reporting for employee share-based payments and related tax accounting impacts, including the presentation in the statements of operations and cash flows. We adopted this new guidance in the first quarter 2017, and in accordance with the transition requirements, we recorded $5.2 million of excess tax benefit in income tax expense and have transitioned all provisions of this new guidance prospectively, other than our presentation of our withholding shares for tax-withholding purposes, which we accounted for retrospectively in the financing activities section of the statement of cash flows. We recorded a noncash cumulative-effect increase of $11.0 million to retained earnings, with an offset to a deferred tax asset, as of the beginning of the reporting period in 2017, for excess tax benefits earned prior to January 1, 2017, that had not been recognized. We continue our use of the estimation method to account for share unit award forfeitures rather than actual forfeitures. The retrospective impact of our withholding shares for tax-withholding purposes to our Statement of Cash Flows for the nine months ended September 30, 2016, was a $9.0 million increase to net cash provided by operating activities and a $9.0 million decrease to net cash used in financing activities.

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” which prescribes recognizing lease assets and liabilities on the balance sheet and includes disclosure of key information about leasing arrangements.  A modified retrospective transition approach is required for leases existing at the time of adoption. We are evaluating our population of leases, analyzing lease agreements, and holding meetings with cross-functional teams to determine the potential impact of this accounting standard on our financial position and results of operations and the transition approach we will utilize. We are also continuing to monitor the FASB for additional guidance surrounding an exposure draft regarding land easements. This information will help us determine what information will ultimately be disclosed in our financial statements and footnotes. Until this item is resolved, we cannot complete our evaluation of the potential effect the new guidance will have on our financial position, results of operations, cash flows or business processes. We will adopt this new guidance in the first quarter of 2019.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers” (“ASC 606”), which clarifies and converges the revenue recognition principles under GAAP and International Financial Reporting Standards. In July 2015, FASB delayed the effective date for one year. We have substantially completed evaluating all of our sources of revenue to determine the potential effect on our financial position, results of operations, cash flows and the related accounting policies and business processes. We will adopt this new guidance for our interim and annual reports beginning in the first quarter 2018, using the modified retrospective method. Through our preliminary evaluation, we do not expect a cumulative adjustment to our opening retained earnings, if any, would be material. The only impact we expect would be a reclassification of certain revenues that do not meet the requirements under ASC 606 as revenues from contracts with customers, but will continue to be reflected as other revenues in determining total revenue. The items we expect to reclassify relate primarily to the weather normalization mechanism in Kansas, where the KCC determines how we account for variations in weather. We have determined the majority of our tariffs to be contracts with customers which are settled over time, where our performance obligation is settled with our customer when natural gas is received and simultaneously consumed. In addition, we will elect to use the invoice method, where we will recognize revenue for volumes delivered for which we have a right to invoice.

We will continue monitoring the accounting task forces and FASB for the final conclusions surrounding revenue recognition implementation guidance. This guidance will determine what will ultimately be disclosed in our financial statements and footnotes. In addition to updating our revenue recognition disclosures, additional disclosures may include disaggregation of revenues by types of service, source of revenue or customer class, performance obligations and other types of revenues. Until these items are resolved, we cannot complete our evaluation of the potential effect the new guidance will have on our financial position, results of operations, cash flows or business processes.

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REGULATORY ASSETS AND LIABILITIES (Notes)

9 Months Ended

Sep. 30, 2017

SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]

Schedule of Regulatory Assets and Liabilities

2. REGULATORY ASSETS AND LIABILITIES

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

	September 30, 2017
	Current			Noncurrent		Total
	(Thousands of dollars)
Under-recovered purchased-gas costs	$	43,997		$	—	$	43,997
Pension and postemployment benefit costs	31,530			399,154		430,684
Weather normalization	19,618			—		19,618
Reacquired debt costs	812			7,500		8,312
Other	3,591			4,999		8,590
Total regulatory assets, net of amortization	99,548			411,653		511,201
Over-recovered purchased-gas costs	(10,471		)	—		(10,471		)
Ad valorem tax	(356		)	—		(356		)
Total regulatory liabilities (a)	(10,827		)	—		(10,827		)
Net regulatory assets (liabilities)	$	88,721		$	411,653	$	500,374

(a) Included in other current liabilities in our Balance Sheets.

	December 31, 2016
	Current			Noncurrent		Total
	(Thousands of dollars)
Under-recovered purchased-gas costs	$	29,901		$	—	$	29,901
Pension and postemployment benefit costs	31,498			427,448		458,946
Weather normalization	17,661			—		17,661
Reacquired debt costs	812			8,108		8,920
Other	3,274			4,966		8,240
Total regulatory assets, net of amortization	83,146			440,522		523,668
Over-recovered purchased-gas costs	(10,154		)	—		(10,154		)
Ad valorem tax	(1,768		)	—		(1,768		)
Total regulatory liabilities (a)	(11,922		)	—		(11,922		)
Net regulatory assets (liabilities)	$	71,224		$	440,522	$	511,746

(a) Included in other current liabilities in our Balance Sheets.

Regulatory assets on our Balance Sheets, as authorized by various regulatory authorities, are probable of recovery. Base rates are designed to provide a recovery of costs during the period 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.

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CREDIT FACILITIES (Notes)

9 Months Ended

Sep. 30, 2017

Short-term Debt [Line Items]

Short-term Debt [Text Block]

3. CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE

In October 2017, we amended and restated our credit agreement. The ONE Gas Credit Agreement remains a $700.0 million revolving unsecured credit facility, and includes a $20.0 million letter of credit subfacility and a $60.0 million swingline subfacility. We will also be able to request an increase in commitments of up to an additional $500.0 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement expires in October 2022, 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 contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At September 30, 2017, our total debt-to-capital ratio was 41 percent and we were in compliance with all covenants under the ONE Gas Credit Agreement.

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

The ONE Gas Credit Agreement is available to repay the commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowing capacity under the ONE Gas Credit Agreement. At September 30, 2017, we had $174.0 million in short-term borrowings, $1.8 million in letters of credit issued under the ONE Gas Credit Agreement and $524.2 million of remaining credit available under the ONE Gas Credit Agreement.

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LONG-TERM DEBT (Notes)

9 Months Ended

Sep. 30, 2017

Long-term Debt, Unclassified [Abstract]

Long-term Debt [Text Block]

4. LONG-TERM DEBT

We have senior notes consisting of $300 million of 2.07 percent senior notes due in 2019, $300 million of 3.61 percent senior notes due in 2024 and $600 million of 4.658 percent senior notes due in 2044. The indenture governing our Senior Notes includes an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding Senior Notes to declare those Senior Notes immediately due and payable in full.

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EQUITY (Notes)

9 Months Ended

Sep. 30, 2017

Class of Stock [Line Items]

Stockholders' Equity Note Disclosure [Text Block]

5. EQUITY

In the first six months of 2017, we repurchased approximately 256 thousand shares of our common stock for approximately $17.5 million. We did not repurchase any shares of our common stock during the three months ended September 30, 2017.

In October 2017, we declared a dividend of $0.42 per share ($1.68 per share on an annualized basis) for shareholders of record as of November 13, 2017, payable December 1, 2017.

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Notes)

9 Months Ended

Sep. 30, 2017

Accumulated Other Comprehensive Income (Loss) [Line Items]

Comprehensive Income (Loss) Note [Text Block]

6. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following table sets forth the effect of reclassifications from accumulated other comprehensive income (loss) in our Statements of Income for the periods indicated:

	Three Months Ended						Nine Months Ended
Details about Accumulated Other Comprehensive	September 30,						September 30,						Affected Line Item in the
Income (Loss) Components	2017			2016			2017			2016			Statements of Income
	(Thousands of dollars)
Pension and other postemployment benefit plan obligations (a)
Amortization of net loss	$	10,648		$	10,040		$	31,944		$	30,113
Amortization of unrecognized prior service cost	(1,149		)	(909		)	(3,447		)	(2,725		)
	9,499			9,131			28,497			27,388
Regulatory adjustments (b)	(9,290		)	(8,943		)	(27,869		)	(26,824		)
	209			188			628			564			Income before income taxes
	(81		)	(72		)	(242		)	(217		)	Income tax expense
Total reclassifications for the period	$	128		$	116		$	386		$	347		Net income

(a) These components of accumulated other comprehensive income (loss) are included in the computation of net periodic benefit cost. See Note 8 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 2 for additional disclosures of regulatory assets and liabilities.

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EARNINGS PER SHARE (Notes)

9 Months Ended

Sep. 30, 2017

EARNINGS PER SHARE [Line Items]

Earnings Per Share [Text Block]

7. 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, 2017
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	18,797	52,488	$	0.36
Diluted EPS Calculation
Effect of dilutive securities	—		438
Net income available for common stock and common stock equivalents	$	18,797	52,926	$	0.36

	Three Months Ended September 30, 2016
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	12,737	52,453	$	0.24
Diluted EPS Calculation
Effect of dilutive securities	—		489
Net income available for common stock and common stock equivalents	$	12,737	52,942	$	0.24

	Nine Months Ended September 30, 2017
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	115,876	52,539	$	2.21
Diluted EPS Calculation
Effect of dilutive securities	—		445
Net income available for common stock and common stock equivalents	$	115,876	52,984	$	2.19

	Nine Months Ended September 30, 2016
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	97,781	52,452	$	1.86
Diluted EPS Calculation
Effect of dilutive securities	—		510
Net income available for common stock and common stock equivalents	$	97,781	52,962	$	1.85

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EMPLOYEE BENEFIT PLANS (Notes)

9 Months Ended

Sep. 30, 2017

Employee Benefit Plans [Line Items]

EMPLOYEE BENEFIT PLANS

8. EMPLOYEE BENEFIT PLANS

In September 2017, we purchased group annuity contracts and transferred approximately $47 million of the assets and liabilities related to certain participants in our defined benefit pension plan to a third-party insurance company.

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,
	2017			2016			2017			2016
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	3,044		$	3,014		$	9,132		$	9,042
Interest cost	10,113			11,387			30,339			34,162
Expected return on assets	(14,624		)	(15,296		)	(43,872		)	(45,888		)
Amortization of net loss	9,027			8,886			27,081			26,657
Net periodic benefit cost	$	7,560		$	7,991		$	22,680		$	23,973

	Other Postemployment Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	627		$	637		$	1,881		$	1,913
Interest cost	2,472			2,626			7,416			7,880
Expected return on assets	(3,147		)	(3,070		)	(9,441		)	(9,212		)
Amortization of unrecognized prior service cost	(1,149		)	(909		)	(3,447		)	(2,725		)
Amortization of net loss	1,621			1,154			4,863			3,456
Net periodic benefit cost	$	424		$	438		$	1,272		$	1,312

We recover qualified pension benefit plan and other postemployment benefit plan costs through rates charged to our customers. Certain regulatory authorities require that the recovery of these costs be based on specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as authorized by the applicable regulatory authorities. Regulatory deferrals related to net periodic benefit cost were not material for the three and nine months ended September 30, 2017.

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COMMITMENTS AND CONTINGENCIES (Notes)

9 Months Ended

Sep. 30, 2017

Commitments and Contingencies [Line Items]

COMMITMENTS AND CONTINGENCIES

9. COMMITMENTS AND CONTINGENCIES

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 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, 2017 and 2016.

We own or retain legal responsibility for the 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 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.

We have completed or addressed removal of the source of soil contamination at 11 of the 12 sites, and continue to monitor groundwater at eight of the 12 sites according to plans approved by the KDHE. Regulatory closure has been achieved at three of the 12 sites, but these sites remain subject to potential future requirements that may result in additional costs. During 2016, we completed a site assessment at the twelfth site where no active soil remediation has occurred. We have submitted a work plan to the KDHE for approval to address a source of contamination and associated contaminated soil on a portion of this site. We are also conducting a study of the feasibility of various options to address the remainder of the site. Costs associated with the remediation at this site are not expected to be material to our results of operations or financial position.

With regard to one of our former MGP sites, periodic monitoring and a 2016 interim site investigation indicated elevated levels of contaminants generally associated with MGP sites. Additional testing and work plan development is underway in 2017 to determine a remediation work plan to present to the KDHE for approval, which could impact our estimates of the cost of remediation at this site. In the fourth quarter of 2016, we estimated the potential costs associated with additional investigation and remediation to be in the range of $4.0 million to $7.0 million. A single reliable estimate of the remediation costs was not feasible due to the amount of uncertainty in the ultimate remediation approach that will be utilized. Accordingly, we recorded a reserve of $4.0 million for this site in the fourth quarter of 2016.

In April 2017, Kansas Gas Service filed an application with the KCC seeking approval of an AAO associated with the costs incurred at, and nearby, its 12 MGP sites. In October 2017, Kansas Gas Service, the KCC staff and the Citizens’ Utility Ratepayer Board filed a unanimous settlement agreement with the KCC.  If approved, the agreement will allow Kansas Gas Service to defer MGP costs (costs that are necessary for investigation and remediation at the 12 former MGP sites) incurred after January 1, 2017, up to a cap of $15.0 million, net of any related insurance recoveries. Costs approved 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. At the time future investigation and remediation work, net of any related insurance recoveries, is expected to exceed $15.0 million, Kansas Gas Service will be required to file an application with the KCC for approval to increase the $15.0 million cap. The KCC is expected to issue an order no later than early January 2018. If the agreement is approved, we expect to record a regulatory asset of approximately $5.9 million for estimated costs that have been accrued at January 1, 2017.

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, 2017 and 2016. A number of 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.

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 high-consequence areas. 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 high-consequence areas;

• a verification of records for pipelines in class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and

• a requirement to test previously untested pipelines operating above 30 percent yield strength in high-consequence areas.

In April 2016, PHMSA published a NPRM, the Safety of Gas Transmission & Gathering Lines Rule, in the Federal Register to revise pipeline safety regulations applicable to the safety of onshore natural gas transmission and gathering pipelines. Proposals include changes to pipeline integrity management requirements and other safety-related requirements. The NPRM comment period ended July 7, 2016, and comments are under review by PHMSA. As part of the comment review process, PHMSA is being advised by the Technical Pipeline Safety Standards Committee, informally known by PHMSA as the GPAC, a statutorily mandated advisory committee that advises PHMSA on proposed safety policies for natural gas pipelines.  The GPAC reviews PHMSA's proposed regulatory initiatives to assure the technical feasibility, reasonableness, cost-effectiveness and practicality of each proposal.  The potential capital and operating expenditures associated with compliance with the proposed rule are currently being evaluated and could be significant depending on the final regulations.

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.

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DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS (Notes)

9 Months Ended

Sep. 30, 2017

Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]

Fair Value Disclosures

10. DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS

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

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

		Recognition and Measurement
Accounting Treatment		Balance Sheet		Income Statement
Normal purchases and normal sales	-	Recorded at historical cost	-	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

We have not elected to designate any of our derivative instruments as hedges. Premiums paid and any cash settlements received associated with the commodity derivative instruments entered into by us are included in, and recoverable through, the purchased-gas cost adjustment mechanisms.

Determining Fair Value - 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 financial statements based on the observability of inputs used to estimate such fair value. The levels of the hierarchy are described below:

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

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

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

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

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

Derivative Instruments -At September 30, 2017, we held purchased natural gas call options for the heating season ending March 31, 2018, with total notional amounts of 33.5 Bcf, for which we paid premiums of $10.9 million, and had a fair value of $6.9 million. At December 31, 2016, we held purchased natural gas call options for the heating season ended March 31, 2017, with total notional amounts of 14.3 Bcf, for which we paid premiums of $5.4 million, and had a fair value of $6.5 million. The premiums paid and any cash settlements received are recorded as part of our unrecovered purchased-gas costs in current regulatory assets as these contracts are included in, and recoverable through, the purchased-gas cost adjustment mechanisms. Additionally, changes in fair value associated with these contracts are deferred as part of our unrecovered purchased-gas costs in our 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 NYMEX-settled prices. There were no transfers between levels for the three and nine months ended September 30,2017 and 2016.

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.

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 $1.2 billion at both September 30, 2017 and December 31, 2016. The estimated fair value of our long-term debt, including current maturities, was $1.3 billion and $1.2 billion at September 30, 2017 and December 31, 2016, respectively. The estimated fair value of our Senior Notes at September 30, 2017 and December 31, 2016, was determined using quoted market prices, and are classified as Level 2.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2017

Significant Accounting Policies [Line Items]

Use of Estimates

Use of Estimates - The preparation of our 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 financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, provision for doubtful accounts, unbilled revenues for natural gas delivered but for which meters have not been read, natural gas purchased but for which no invoice has been received, provision for income taxes, including any deferred tax valuation allowances, the results of litigation and various other recorded or disclosed amounts.

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

Segments

Segments - We operate in one reportable and operating business segment: regulated public utilities that deliver natural gas to residential, commercial, industrial, wholesale, public authority and transportation customers. The accounting policies for our segment are the same as described in Note 1 of our Notes to the Financial Statements in our Annual Report. We evaluate our financial performance principally on operating income. For the three and nine months ended September 30, 2017, and 2016, we had no single external customer from which we received 10 percent or more of our gross revenues.

Recently Issued Accounting Standards Update

Recently Issued Accounting Standards Update - In August 2017, the FASB issued ASU 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities,” which allows more types of hedging strategies to be eligible for hedge accounting and simplifies application of hedge accounting. This new guidance is required for our interim and annual reports for periods beginning after December 15, 2018, and early adoption is permitted, but must be applied as of the beginning of the fiscal year, or initial application date. The impact of this guidance is not material to us, as we have not elected hedge accounting due to the nature of the types of derivatives we have entered.

In March 2017, the FASB issued ASU 2017-07, “Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost,” which requires (1) separation of net periodic service costs for pension and other postemployment benefits into service cost and other components, (2) presentation of the service cost component in the same line as other compensation costs rendered by pertinent employees during the period, and (3) reporting the other components of net periodic benefit costs separately from the service cost component and outside a subtotal of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all of our cost components remain eligible for capitalization under the accounting requirements for rate regulated entities.

We will adopt this guidance for our interim and annual reports for periods in the first quarter of 2018. When adopted, the presentation changes required for net periodic benefit costs will not impact previously reported net income; however, the reclassification of the other components of benefits costs will result in an increase in operating income and an increase in other expenses for 2016 and 2017. We will use the retroactive presentation that permits the use of the amounts disclosed for the various components of net benefit cost in our respective Annual Report’s Employee Benefit Plans footnote as the basis for the retrospective application. In addition, we are currently updating our systems for the capitalization of service costs to property and non-service costs to a regulatory asset on a prospective basis, as well as the appropriate accounts for non-service costs to apply retroactive reclassification.

In January 2017, the FASB issued ASU 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment,” which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 of the goodwill test, where the measurement of a goodwill impairment loss was determined by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Upon adoption, a goodwill impairment will be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill.  We early adopted this new guidance in the current quarter, and it did not have an impact on our financial statements. See our conclusions regarding our current year Goodwill Impairment Test above.

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. It is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and may be adopted a year earlier. The new guidance will be initially applied through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. We are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of 2021.

In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting,” which includes various new aspects to simplify how share-based payments are accounted for and presented in the financial statements. The new standard modifies several aspects of the accounting and reporting for employee share-based payments and related tax accounting impacts, including the presentation in the statements of operations and cash flows. We adopted this new guidance in the first quarter 2017, and in accordance with the transition requirements, we recorded $5.2 million of excess tax benefit in income tax expense and have transitioned all provisions of this new guidance prospectively, other than our presentation of our withholding shares for tax-withholding purposes, which we accounted for retrospectively in the financing activities section of the statement of cash flows. We recorded a noncash cumulative-effect increase of $11.0 million to retained earnings, with an offset to a deferred tax asset, as of the beginning of the reporting period in 2017, for excess tax benefits earned prior to January 1, 2017, that had not been recognized. We continue our use of the estimation method to account for share unit award forfeitures rather than actual forfeitures. The retrospective impact of our withholding shares for tax-withholding purposes to our Statement of Cash Flows for the nine months ended September 30, 2016, was a $9.0 million increase to net cash provided by operating activities and a $9.0 million decrease to net cash used in financing activities.

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” which prescribes recognizing lease assets and liabilities on the balance sheet and includes disclosure of key information about leasing arrangements.  A modified retrospective transition approach is required for leases existing at the time of adoption. We are evaluating our population of leases, analyzing lease agreements, and holding meetings with cross-functional teams to determine the potential impact of this accounting standard on our financial position and results of operations and the transition approach we will utilize. We are also continuing to monitor the FASB for additional guidance surrounding an exposure draft regarding land easements. This information will help us determine what information will ultimately be disclosed in our financial statements and footnotes. Until this item is resolved, we cannot complete our evaluation of the potential effect the new guidance will have on our financial position, results of operations, cash flows or business processes. We will adopt this new guidance in the first quarter of 2019.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers” (“ASC 606”), which clarifies and converges the revenue recognition principles under GAAP and International Financial Reporting Standards. In July 2015, FASB delayed the effective date for one year. We have substantially completed evaluating all of our sources of revenue to determine the potential effect on our financial position, results of operations, cash flows and the related accounting policies and business processes. We will adopt this new guidance for our interim and annual reports beginning in the first quarter 2018, using the modified retrospective method. Through our preliminary evaluation, we do not expect a cumulative adjustment to our opening retained earnings, if any, would be material. The only impact we expect would be a reclassification of certain revenues that do not meet the requirements under ASC 606 as revenues from contracts with customers, but will continue to be reflected as other revenues in determining total revenue. The items we expect to reclassify relate primarily to the weather normalization mechanism in Kansas, where the KCC determines how we account for variations in weather. We have determined the majority of our tariffs to be contracts with customers which are settled over time, where our performance obligation is settled with our customer when natural gas is received and simultaneously consumed. In addition, we will elect to use the invoice method, where we will recognize revenue for volumes delivered for which we have a right to invoice.

We will continue monitoring the accounting task forces and FASB for the final conclusions surrounding revenue recognition implementation guidance. This guidance will determine what will ultimately be disclosed in our financial statements and footnotes. In addition to updating our revenue recognition disclosures, additional disclosures may include disaggregation of revenues by types of service, source of revenue or customer class, performance obligations and other types of revenues. Until these items are resolved, we cannot complete our evaluation of the potential effect the new guidance will have on our financial position, results of operations, cash flows or business processes.

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

9 Months Ended

Sep. 30, 2017

Derivatives and Fair Value Measurement [Abstract]

Derivatives

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

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

		Recognition and Measurement
Accounting Treatment		Balance Sheet		Income Statement
Normal purchases and normal sales	-	Recorded at historical cost	-	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

We have not elected to designate any of our derivative instruments as hedges. Premiums paid and any cash settlements received associated with the commodity derivative instruments entered into by us are included in, and recoverable through, the purchased-gas cost adjustment mechanisms.

Fair Value Measurement

Determining Fair Value - 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 financial statements based on the observability of inputs used to estimate such fair value. The levels of the hierarchy are described below:

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

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

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

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

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

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REGULATORY ASSETS AND LIABILITIES (Tables)

9 Months Ended

Sep. 30, 2017

SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]

SCHEDULE OF REGULATED ASSETS AND LIABILITIES

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

	September 30, 2017
	Current			Noncurrent		Total
	(Thousands of dollars)
Under-recovered purchased-gas costs	$	43,997		$	—	$	43,997
Pension and postemployment benefit costs	31,530			399,154		430,684
Weather normalization	19,618			—		19,618
Reacquired debt costs	812			7,500		8,312
Other	3,591			4,999		8,590
Total regulatory assets, net of amortization	99,548			411,653		511,201
Over-recovered purchased-gas costs	(10,471		)	—		(10,471		)
Ad valorem tax	(356		)	—		(356		)
Total regulatory liabilities (a)	(10,827		)	—		(10,827		)
Net regulatory assets (liabilities)	$	88,721		$	411,653	$	500,374

(a) Included in other current liabilities in our Balance Sheets.

	December 31, 2016
	Current			Noncurrent		Total
	(Thousands of dollars)
Under-recovered purchased-gas costs	$	29,901		$	—	$	29,901
Pension and postemployment benefit costs	31,498			427,448		458,946
Weather normalization	17,661			—		17,661
Reacquired debt costs	812			8,108		8,920
Other	3,274			4,966		8,240
Total regulatory assets, net of amortization	83,146			440,522		523,668
Over-recovered purchased-gas costs	(10,154		)	—		(10,154		)
Ad valorem tax	(1,768		)	—		(1,768		)
Total regulatory liabilities (a)	(11,922		)	—		(11,922		)
Net regulatory assets (liabilities)	$	71,224		$	440,522	$	511,746

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)

9 Months Ended

Sep. 30, 2017

Accumulated Other Comprehensive Income (Loss) [Line Items]

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

The following table sets forth the effect of reclassifications from accumulated other comprehensive income (loss) in our Statements of Income for the periods indicated:

	Three Months Ended						Nine Months Ended
Details about Accumulated Other Comprehensive	September 30,						September 30,						Affected Line Item in the
Income (Loss) Components	2017			2016			2017			2016			Statements of Income
	(Thousands of dollars)
Pension and other postemployment benefit plan obligations (a)
Amortization of net loss	$	10,648		$	10,040		$	31,944		$	30,113
Amortization of unrecognized prior service cost	(1,149		)	(909		)	(3,447		)	(2,725		)
	9,499			9,131			28,497			27,388
Regulatory adjustments (b)	(9,290		)	(8,943		)	(27,869		)	(26,824		)
	209			188			628			564			Income before income taxes
	(81		)	(72		)	(242		)	(217		)	Income tax expense
Total reclassifications for the period	$	128		$	116		$	386		$	347		Net income

(a) These components of accumulated other comprehensive income (loss) are included in the computation of net periodic benefit cost. See Note 8 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 2 for additional disclosures of regulatory assets and liabilities.

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EARNINGS PER SHARE (Tables)

9 Months Ended

Sep. 30, 2017

EARNINGS PER SHARE [Line Items]

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

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

	Three Months Ended September 30, 2017
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	18,797	52,488	$	0.36
Diluted EPS Calculation
Effect of dilutive securities	—		438
Net income available for common stock and common stock equivalents	$	18,797	52,926	$	0.36

	Three Months Ended September 30, 2016
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	12,737	52,453	$	0.24
Diluted EPS Calculation
Effect of dilutive securities	—		489
Net income available for common stock and common stock equivalents	$	12,737	52,942	$	0.24

	Nine Months Ended September 30, 2017
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	115,876	52,539	$	2.21
Diluted EPS Calculation
Effect of dilutive securities	—		445
Net income available for common stock and common stock equivalents	$	115,876	52,984	$	2.19

	Nine Months Ended September 30, 2016
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	97,781	52,452	$	1.86
Diluted EPS Calculation
Effect of dilutive securities	—		510
Net income available for common stock and common stock equivalents	$	97,781	52,962	$	1.85

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EMPLOYEE BENEFIT PLANS (Tables)

9 Months Ended

Sep. 30, 2017

Employee Benefit Plans [Line Items]

Schedule of Net Benefit Costs [Table Text Block]

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

	Pension Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	3,044		$	3,014		$	9,132		$	9,042
Interest cost	10,113			11,387			30,339			34,162
Expected return on assets	(14,624		)	(15,296		)	(43,872		)	(45,888		)
Amortization of net loss	9,027			8,886			27,081			26,657
Net periodic benefit cost	$	7,560		$	7,991		$	22,680		$	23,973

	Other Postemployment Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	627		$	637		$	1,881		$	1,913
Interest cost	2,472			2,626			7,416			7,880
Expected return on assets	(3,147		)	(3,070		)	(9,441		)	(9,212		)
Amortization of unrecognized prior service cost	(1,149		)	(909		)	(3,447		)	(2,725		)
Amortization of net loss	1,621			1,154			4,863			3,456
Net periodic benefit cost	$	424		$	438		$	1,272		$	1,312

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) number in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017 USD ($)	Sep. 30, 2016
Significant Accounting Policies [Line Items]
Number of natural gas distribution services customers	2		2
Segment Reporting, Disclosure of Major Customers	0	0	0	0
Excess tax benefit related to the share-based compensation provision			$ 5.2
Operating loss carryforward related to the share-based compensation provision			11.0
Prior period cash flow reclass related to the share-based compensation provision			$ 9.0

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REGULATORY ASSETS AND LIABILITIES (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	$ 99,548	$ 83,146
Regulatory Assets, Noncurrent	411,653	440,522
Net regulatory assets (liabilities), current	88,721	71,224
Net regulatory assets (liabilities), noncurrent	411,653	440,522
Net Regulatory Assets	500,374	511,746
Over-recovered purchased-gas costs [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Liability, Current	(10,471)	(10,154)
Regulatory Liability, Noncurrent	0	0
Regulatory Liabilities	(10,471)	(10,154)
Ad valorem tax [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Liability, Current	(356)	(1,768)
Regulatory Liability, Noncurrent	0	0
Regulatory Liabilities	(356)	(1,768)
Total regulated liabilities [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Liability, Current	(10,827)	(11,922)
Regulatory Liability, Noncurrent	0	0
Regulatory Liabilities	(10,827)	(11,922)
Under-recovered purchased-gas costs [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	43,997	29,901
Regulatory Assets, Noncurrent	0	0
Regulatory Assets	43,997	29,901
Pension and postretirement benefit costs [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	31,530	31,498
Regulatory Assets, Noncurrent	399,154	427,448
Regulatory Assets	430,684	458,946
Weather normalization [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	19,618	17,661
Regulatory Assets, Noncurrent	0	0
Regulatory Assets	19,618	17,661
Reacquired debt costs [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	812	812
Regulatory Assets, Noncurrent	7,500	8,108
Regulatory Assets	8,312	8,920
Other regulatory assets [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	3,591	3,274
Regulatory Assets, Noncurrent	4,999	4,966
Regulatory Assets	8,590	8,240
Total regulatory assets, net of amortization [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current	99,548	83,146
Regulatory Assets, Noncurrent	411,653	440,522
Regulatory Assets	$ 511,201	$ 523,668

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CREDIT FACILITIES (Details) $ in Millions	Sep. 30, 2017 USD ($)
Short-term Debt [Line Items]
Line of Credit Facility Sublimit	$ 20.0
Line of Credit Facility Swingline Subfacility	60.0
Line of Credit Facility Option to Increase Borrowing Capacity	$ 500.0
Ratio of Indebtedness to Net Capital	0.41
Commercial paper maximum borrowing capacity	$ 700.0
Short-term Debt	174.0
Letters of Credit Outstanding, Amount	1.8
Line of Credit Facility, Remaining Borrowing Capacity	$ 524.2

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LONG-TERM DEBT (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017 USD ($)
Note Payable Due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Description	The indenture governing our Senior Notes includes an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding Senior Notes to declare those senior notes immediately due and payable in full.
Long-term Debt, Gross	$ 300
Debt Instrument, Interest Rate, Stated Percentage	2.07%
Note Payable Due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Description	The indenture governing our Senior Notes includes an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding Senior Notes to declare those senior notes immediately due and payable in full.
Long-term Debt, Gross	$ 300
Debt Instrument, Interest Rate, Stated Percentage	3.61%
Notes Payable Due 2044 [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Description	The indenture governing our Senior Notes includes an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding Senior Notes to declare those senior notes immediately due and payable in full.
Long-term Debt, Gross	$ 600
Debt Instrument, Interest Rate, Stated Percentage	4.658%

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EQUITY (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended	6 Months Ended	9 Months Ended
	Dec. 31, 2017	Jun. 30, 2016	Sep. 30, 2017
Treasury stock acquired, shares		256
Treasury stock acquired, value		$ 17,500	$ 17,512
Subsequent Event [Member]
Common Stock, Dividends, Per Share, Declared	$ 0.42
Common Stock, Dividends, Declared, Annualized Basis	$ 1.68

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amortization of net loss	$ 10,648	$ 10,040	$ 31,944	$ 30,113
Amortization of unrecognized prior service cost	(1,149)	(909)	(3,447)	(2,725)
Reclassification adjustment, before tax and regulatory adjustments	9,499	9,131	28,497	27,388
Regulatory adjustments	(9,290)	(8,943)	(27,869)	(26,824)
Reclassification adjustment, before tax	209	188	628	564
Reclassification adjustment, Tax	(81)	(72)	(242)	(217)
Reclassification adjustment, net of tax	$ 128	$ 116	$ 386	$ 347

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EARNINGS PER SHARE (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Basic EPS Calculation
Net income available for common stock	$ 18,797	$ 12,737	$ 115,876	$ 97,781
Weighted Average Number of Shares Outstanding, Basic	52,488	52,453	52,539	52,452
Earnings Per Share, Basic	$ 0.36	$ 0.24	$ 2.21	$ 1.86
Diluted EPS Calculation
Net income available for common stock	$ 18,797	$ 12,737	$ 115,876	$ 97,781
Effect of dilutive securities on income	$ 0	$ 0	$ 0	$ 0
Effect of dilutive securities on shares	438	489	445	510
Weighted Average Number of Shares Outstanding, Diluted	52,926	52,942	52,984	52,962
Earnings Per Share, Diluted	$ 0.36	$ 0.24	$ 2.19	$ 1.85

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EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Employee Benefit Plans [Line Items]
Defined Benefit Plan, Settlements, Plan Assets	$ 47,000
Defined Benefit Plan, Settlements, Benefit Obligation	47,000
Components of net periodic benefit cost:
Amortization of unrecognized prior service cost	(1,149)	$ (909)	$ (3,447)	$ (2,725)
Amortization of net loss	10,648	10,040	31,944	30,113
ONE Gas Pension Plans [Member]
Components of net periodic benefit cost:
Service cost	3,044	3,014	9,132	9,042
Interest cost	10,113	11,387	30,339	34,162
Expected return on assets	(14,624)	(15,296)	(43,872)	(45,888)
Amortization of net loss	9,027	8,886	27,081	26,657
Net periodic benefit cost	7,560	7,991	22,680	23,973
ONE Gas Postretirement Benefit Plans [Member]
Components of net periodic benefit cost:
Service cost	627	637	1,881	1,913
Interest cost	2,472	2,626	7,416	7,880
Expected return on assets	(3,147)	(3,070)	(9,441)	(9,212)
Amortization of unrecognized prior service cost	(1,149)	(909)	(3,447)	(2,725)
Amortization of net loss	1,621	1,154	4,863	3,456
Net periodic benefit cost	$ 424	$ 438	$ 1,272	$ 1,312

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COMMITMENTS AND CONTINGENCIES (Details) $ in Millions	3 Months Ended	9 Months Ended
	Dec. 31, 2017 USD ($)	Sep. 30, 2017
Commitments and Contingencies [Line Items]
Number Of Former Manufactured Gas Sites Where We Own Or Retain Legal Responsibility For Environmental Conditions		12
Number of sites where we have completed or addressed removal of the source of soil contamination according to plans approved by KDHE.		11
Number of sites with ongoing groundwater monitoring		8
Number of sites where regulatory closure has been achieved		3
Environmental Reserve Estimate Range, Low		4
Environmental Reserve Estimate Range, High		7
Environmental Reserve Estimate, Actual		4
Percentage yield of high consequence pipeline areas		30.00%
Subsequent Event [Member]
Commitments and Contingencies [Line Items]
AAO associated with MGP costs requested amount, cap	$ 15.0
Regulatory asset expected to be recorded for MGP costs accrued at January 1, 2017	$ 5.9

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DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2017 USD ($) MMcf	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($) MMcf	Sep. 30, 2016 USD ($)	Dec. 31, 2016 USD ($) MMcf
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative, Nonmonetary Notional Amount | MMcf	33,500		33,500		14,300
Premiums recorded in other current assets on natural gas contracts held	$ 10,900,000		$ 10,900,000		$ 5,400,000
Fair Value Assets, Transfers between Levels	0	$ 0	0	$ 0
Long-term Debt, including current maturities	1,193,052,000		1,193,052,000		1,192,446,000
Long-term Debt					1,200,000,000
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Fair value, natural gas call options	6,900,000		6,900,000		6,500,000
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Long-term Debt, Fair Value	$ 1,300,000,000		$ 1,300,000,000		$ 1,200,000,000