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, 2016.

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, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer X             Accelerated filer __             Non-accelerated filer __             Smaller reporting company__

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 25, 2016, the Company had 52,245,273 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)	6
	Statements of Income - Three and Nine Months Ended September 30, 2016 and 2015	6
	Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2016 and 2015	7
	Balance Sheets - September 30, 2016 and December 31, 2015	8
	Statements of Cash Flows - Nine Months Ended September 30, 2016 and 2015	11
	Statement of Equity - Nine Months Ended September 30, 2016	12
	Notes to the Financial Statements	14
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	33
Part II.	Other Information	34
Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 3.	Defaults Upon Senior Securities	34
Item 4.	Mine Safety Disclosures	34
Item 5.	Other Information	34
Item 6.	Exhibits	34
Signature		36

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:

Annual Report	Annual Report on Form 10-K for the year ended December 31, 2015
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
DOT	United States Department of Transportation
EPA	United States Environmental Protection Agency
EPARR	El Paso Annual Rate Review
EPS	Earnings per share
EPSA	El Paso Service Area
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
GAAP	Accounting principles generally accepted in the United States of America
GRIP	Texas Gas Reliability Infrastructure Program
GSRS	Gas System Reliability Surcharge
Heating Degree Day or HDD	A measure designed to reflect the demand for energy needed for heating based on   the extent to which the daily average temperature falls below a reference   temperature for which no heating is required, usually 65 degrees Fahrenheit
KCC	Kansas Corporation Commission
KDHE	Kansas Department of Health and Environment
LDCs	Local distribution companies
MMcf	Million cubic feet
Moody’s	Moody’s Investors Service, Inc.
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, which expires January, 2019
ONEOK	ONEOK, Inc. and its subsidiaries
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	S&P Global Ratings
SEC	Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
Separation and Distribution Agreement	Separation and Distribution Agreement dated January 14, 2014, between ONEOK and ONE Gas
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)	2016			2015			2016			2015
	(Thousands of dollars, except per share amounts)
Revenues	$	232,191		$	225,226		$	986,479		$	1,158,543
Cost of natural gas	52,253			54,724			344,439			548,226
Net margin	179,938			170,502			642,040			610,317
Operating expenses
Operations and maintenance	99,402			98,698			302,652			304,681
Depreciation and amortization	36,241			33,956			106,490			98,592
General taxes	13,403			12,897			42,311			41,818
Total operating expenses	149,046			145,551			451,453			445,091
Operating income	30,892			24,951			190,587			165,226
Other income	911			166			1,345			1,051
Other expense	(357		)	(1,884		)	(1,126		)	(2,840		)
Interest expense, net	(10,809		)	(11,233		)	(32,504		)	(33,592		)
Income before income taxes	20,637			12,000			158,302			129,845
Income taxes	(7,900		)	(4,629		)	(60,521		)	(50,017		)
Net income	$	12,737		$	7,371		$	97,781		$	79,828
Earnings per share
Basic	$	0.24		$	0.14		$	1.86		$	1.52
Diluted	$	0.24		$	0.14		$	1.85		$	1.50
Average shares (thousands)
Basic	52,453			52,408			52,452			52,627
Diluted	52,942			53,072			52,962			53,315
Dividends declared per share of stock	$	0.35		$	0.30		$	1.05		$	0.90

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)	2016		2015		2016		2015
	(Thousands of dollars)
Net income	$	12,737	$	7,371	$	97,781	$	79,828
Other comprehensive income (loss), net of tax
Change in pension and other postemployment benefit plan liability, net of tax of $(72), $(88), $(217) and $(264), respectively	116		141		347		423
Total other comprehensive income (loss), net of tax	116		141		347		423
Comprehensive income	$	12,853	$	7,512	$	98,128	$	80,251

See accompanying Notes to the Financial Statements.

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ONE Gas, Inc.
BALANCE SHEETS
	September 30,		December 31,
(Unaudited)	2016		2015
Assets	(Thousands of dollars)
Property, plant and equipment
Property, plant and equipment	$	5,338,591	$	5,132,682
Accumulated depreciation and amortization	1,658,266		1,620,771
Net property, plant and equipment	3,680,325		3,511,911
Current assets
Cash and cash equivalents	4,513		2,433
Accounts receivable, net	105,060		216,343
Materials and supplies	30,098		33,325
Income tax receivable	6,952		38,877
Natural gas in storage	144,230		142,153
Regulatory assets	73,863		32,925
Other current assets	12,457		16,789
Total current assets	377,173		482,845
Goodwill and other assets
Regulatory assets	431,086		435,863
Goodwill	157,953		157,953
Other assets	47,142		46,193
Total goodwill and other assets	636,181		640,009
Total assets	$	4,693,679	$	4,634,765

See accompanying Notes to the Financial Statements.

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ONE Gas, Inc.
BALANCE SHEETS
(Continued)
	September 30,			December 31,
(Unaudited)	2016			2015
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 52,245,273 shares at    September 30, 2016; issued 52,598,005 and outstanding 52,259,224 shares at December 31, 2015	$	526		$	526
Paid-in capital	1,748,965			1,764,875
Retained earnings	137,221			95,046
Accumulated other comprehensive income (loss)	(4,054		)	(4,401		)
Treasury stock, at cost: 352,732 shares at September 30, 2016 and 338,781 shares at December 31, 2015	(20,314		)	(14,491		)
Total equity	1,862,344			1,841,555
Long-term debt, excluding current maturities and net of issuance costs of $9,051 and $9,645, respectively	1,192,248			1,191,660
Total equity and long-term debt	3,054,592			3,033,215
Current liabilities
Current maturities of long-term debt	7			7
Notes payable	41,000			12,500
Accounts payable	70,562			107,482
Accrued interest	7,691			18,873
Accrued taxes other than income	39,919			37,249
Accrued liabilities	17,812			31,470
Customer deposits	60,425			60,325
Regulatory liabilities	13,204			24,615
Other current liabilities	8,212			11,700
Total current liabilities	258,832			304,221
Deferred credits and other liabilities
Deferred income taxes	1,011,691			951,785
Employee benefit obligations	291,230			272,309
Other deferred credits	77,334			73,235
Total deferred credits and other liabilities	1,380,255			1,297,329
Commitments and contingencies
Total liabilities and equity	$	4,693,679		$	4,634,765

See accompanying Notes to the Financial Statements.

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ONE Gas, Inc.
STATEMENTS OF CASH FLOWS
	Nine Months Ended
	September 30,
(Unaudited)	2016			2015
	(Thousands of dollars)
Operating activities
Net income	$	97,781		$	79,828
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	106,490			98,592
Deferred income taxes	59,771			19,384
Share-based compensation expense	9,341			3,863
Provision for doubtful accounts	3,521			2,951
Changes in assets and liabilities:
Accounts receivable	107,762			220,392
Materials and supplies	3,227			(5,889		)
Income tax receivable	31,925			20,075
Natural gas in storage	(2,077		)	25,388
Asset removal costs	(40,715		)	(33,744		)
Accounts payable	(32,923		)	(104,948		)
Accrued interest	(11,182		)	(11,225		)
Accrued taxes other than income	2,670			(4,313		)
Accrued liabilities	(13,658		)	(8,019		)
Customer deposits	100			(1,672		)
Regulatory assets and liabilities	(18,726		)	64,368
Other assets and liabilities	(21,877		)	(15,493		)
Cash provided by operating activities	281,430			349,538
Investing activities
Capital expenditures	(231,336		)	(199,678		)
Other	492			—
Cash used in investing activities	(230,844		)	(199,678		)
Financing activities
Borrowings (repayments) of notes payable, net	28,500			(42,000		)
Repurchase of common stock	(24,066		)	(24,122		)
Issuance of common stock	1,983			4,471
Dividends paid	(54,923		)	(47,178		)
Cash used in financing activities	(48,506		)	(108,829		)
Change in cash and cash equivalents	2,080			41,031
Cash and cash equivalents at beginning of period	2,433			11,943
Cash and cash equivalents at end of period	$	4,513		$	52,974

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, 2016	52,598,005	$	526	$	1,764,875
Net income	—	—		—
Other comprehensive income	—	—		—
Repurchase of common stock	—	—		—
Common stock issued and other	—	—		(16,593		)
Common stock dividends - $1.05 per share	—	—		683
September 30, 2016	52,598,005	$	526	$	1,748,965

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, 2016	$	95,046		$	(14,491	)	$	(4,401	)	$	1,841,555
Net income	97,781			—			—			97,781
Other comprehensive income	—			—			347			347
Repurchase of common stock	—			(24,066		)	—			(24,066		)
Common stock issued and other	—			18,243			—			1,650
Common stock dividends - $1.05 per share	(55,606		)	—			—			(54,923		)
September 30, 2016	$	137,221		$	(20,314	)	$	(4,054	)	$	1,862,344

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 2015 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, 2016, 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 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.

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 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, 2016, and 2015, 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, 2016, 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 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 will modify 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. This new guidance is required to be adopted for our interim and annual reports for periods beginning after December 15, 2016, but may be adopted early. We are evaluating the impact of this guidance and the timing of adoption.

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-divisional teams to determine the potential impact of this accounting standard on our financial position, results of operations and cash flows and the transition approach we will utilize. This new guidance is required for our interim and annual reports for periods beginning after December 15, 2018, and early adoption is permitted.

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In August 2015, the FASB issued ASU 2015-15, “Interest-Imputation of Interest (Subtopic 835-30),” which addresses the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements. We adopted this guidance in the first quarter 2016, and it did not have an impact on our financial position or results of operations.

In April 2015, the FASB issued ASU 2015-03, “Interest-Imputation of Interest,” which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. We adopted this guidance in the first quarter of 2016, and have applied the changes retrospectively to all periods presented. We have presented such amounts as a direct deduction from the face amount of our long-term debt, rather than in other assets as a deferred charge in our Balance Sheets. Amortization of the debt issuance costs continues to be reported as interest expense in our Statements of Income.   

In April 2015, the FASB issued ASU 2015-05, “Intangibles-Goodwill and Other-Internal-Use Software,” which helps entities evaluate the accounting for fees paid by a customer in a cloud computing arrangement. We adopted this guidance prospectively in the first quarter of 2016, and it did not have a material impact on our financial position or results of operations.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” 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 are evaluating all of our sources of revenue to determine the potential effect on our financial position, results of operations and cash flows and the transition approach we will utilize. We are monitoring the FASB for additional implementation guidance that may impact the final conclusions of our evaluation. We are required to adopt this guidance for our interim and annual reports beginning with the first quarter 2018.

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, 2016
	Current			Noncurrent			Total
	(Thousands of dollars)
Under-recovered purchased-gas costs	$	29,109		$	—		$	29,109
Pension and postemployment benefit costs	24,706			416,327			441,033
Weather normalization	17,004			—			17,004
Reacquired debt costs	812			8,312			9,124
Other	2,232			6,447			8,679
Total regulatory assets, net of amortization	73,863			431,086			504,949
Accumulated removal costs (a)	—			(7,019		)	(7,019		)
Over-recovered purchased-gas costs	(11,538		)	—			(11,538		)
Ad valorem tax	(1,666		)	—			(1,666		)
Total regulatory liabilities	(13,204		)	(7,019		)	(20,223		)
Net regulatory assets (liabilities)	$	60,659		$	424,067		$	484,726

(a) Included in other deferred credits in our Balance Sheets.

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	December 31, 2015
	Current			Noncurrent			Total
	(Thousands of dollars)
Under-recovered purchased-gas costs	$	13,336		$	—		$	13,336
Pension and postemployment benefit costs	15,670			425,175			440,845
Weather normalization	2,198			—			2,198
Reacquired debt costs	812			8,919			9,731
Other	909			1,769			2,678
Total regulatory assets, net of amortization	32,925			435,863			468,788
Accumulated removal costs (a)	—			(9,032		)	(9,032		)
Over-recovered purchased-gas costs	(22,884		)	—			(22,884		)
Ad valorem tax	(1,731		)	—			(1,731		)
Total regulatory liabilities	(24,615		)	(9,032		)	(33,647		)
Net regulatory assets (liabilities)	$	8,310		$	426,831		$	435,141

(a) Included in other deferred credits 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.

In January 2016, as a result of the OCC’s approval of our rate case in Oklahoma, we recorded a regulatory asset of $2.4 million to recover certain information technology costs incurred as a result of our separation from ONEOK in 2014, which will be recovered over four years.

3. CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE

The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At September 30, 2016, our debt-to-capital ratio was 40 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, 2016, we had $41.0 million in short-term borrowings, $1.0 million in letters of credit issued under the ONE Gas Credit Agreement and $658.0 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 (collectively, our “Senior Notes”). 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 quarter of 2016, we repurchased approximately 407 thousand shares of our common stock for approximately $24.1 million.

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In October 2016, a dividend of $0.35 per share ($1.40 per share on an annualized basis) was declared for shareholders of record on November 14, 2016, payable December 1, 2016.

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	2016			2015			2016			2015			Statements of Income
	(Thousands of dollars)
Pension and other postemployment benefit plan obligations (a)
Amortization of net loss	$	10,040		$	12,564		$	30,113		$	37,694
Amortization of unrecognized prior service cost	(909		)	(374		)	(2,725		)	(1,120		)
	9,131			12,190			27,388			36,574
Regulatory adjustments (b)	(8,943		)	(11,961		)	(26,824		)	(35,887		)
	188			229			564			687			Income before income taxes
	(72		)	(88		)	(217		)	(264		)	Income tax expense
Total reclassifications for the period	$	116		$	141		$	347		$	423		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, 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

	Three Months Ended September 30, 2015
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	7,371	52,408	$	0.14
Diluted EPS Calculation
Effect of dilutive securities	—		664
Net income available for common stock and common stock equivalents	$	7,371	53,072	$	0.14

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	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

	Nine Months Ended September 30, 2015
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	79,828	52,627	$	1.52
Diluted EPS Calculation
Effect of dilutive securities	—		688
Net income available for common stock and common stock equivalents	$	79,828	53,315	$	1.50

8. EMPLOYEE BENEFIT PLANS

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

	Pension Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	3,014		$	3,497		$	9,042		$	10,518
Interest cost	11,387			10,652			34,162			31,956
Expected return on assets	(15,296		)	(15,363		)	(45,888		)	(46,087		)
Amortization of unrecognized prior service cost	—			66			—			200
Amortization of net loss	8,886			11,054			26,657			33,164
Net periodic benefit cost	$	7,991		$	9,906		$	23,973		$	29,751

	Other Postemployment Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	637		$	849		$	1,913		$	2,547
Interest cost	2,626			2,665			7,880			7,997
Expected return on assets	(3,070		)	(2,908		)	(9,212		)	(8,724		)
Amortization of unrecognized prior service cost	(909		)	(440		)	(2,725		)	(1,320		)
Amortization of net loss	1,154			1,510			3,456			4,530
Net periodic benefit cost	$	438		$	1,676		$	1,312		$	5,030

We recover qualified pension benefit plan and other postemployment benefit plan costs through rates charged to our customers. Certain utility commissions 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

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liability and amortized to expense over periods in which this difference will be recovered in rates, as authorized by the applicable utility commission. Regulatory deferrals related to net periodic benefit cost were not material for the three and nine months ended September 30, 2016.

In October 2015, we announced to certain pre-65 participants in our postretirement medical plans a change from a self-insured postretirement medical plan to a plan providing participants an annual benefit that would allow them to select coverage on a healthcare exchange beginning January 1, 2017. In September 2016, due to uncertain market conditions with health insurance exchange providers, we elected not to move the eligible pre-65 participants in our postemployment medical plans to a healthcare exchange. As a result, we remeasured the respective plan assets and benefit obligations, effective September 30, 2016, which resulted in an increase in benefit obligations of our postemployment benefit plan of $31.5 million. The remeasurement will increase the net periodic benefit cost of our postemployment benefit plan by $0.8 million for the three months ending December 31, 2016.

The following table sets forth the weighted-average assumptions used in the remeasurement of the benefit obligations for postemployment benefits for the periods indicated:

	September 30, 2016	December 31, 2015
Discount rate	3.75%	4.75%
Expected long-term return on plan assets	7.75%	8.00%

The following table sets forth the weighted-average assumptions used in the remeasurement to determine periodic benefit costs for the periods indicated:

	Three Months Ended December 31,	Nine Months Ended September 30,
	2016	2016
Discount rate - other postemployment plans	3.75%	4.75%
Expected long-term return on plan assets	7.75%	8.00%

There were no other changes in assumptions for the other postemployment benefits calculations, which are described in our Annual Report. There was no impact to our previously disclosed obligations and benefit costs for our pension plan.

9. COMMITMENTS AND CONTINGENCIES

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 at our facilities. 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, results of operations and cash flows.

We own or retain legal responsibility for the environmental conditions at 12 former manufactured natural gas sites in Kansas. These sites contain potentially harmful materials that 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 allow 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 according to plans approved by the KDHE. Regulatory closure has been achieved at three of the sites. We have begun site assessment at the remaining site where no active remediation has occurred.

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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 30,2016 and 2015. 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 notice of proposed rulemaking (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. The potential capital and operating expenditures associated with the NPRM 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.

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.

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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, 2016, we held purchased natural gas call options for the heating season ending March 2017, with total notional amounts of 30.5 Bcf, for which we paid premiums of $9.4 million, and had a fair value of $8.1 million. At December 31, 2015, we held purchased natural gas call options for the heating season ended March 2016, with total notional amounts of 17.0 Bcf, for which we paid premiums of $5.8 million, and had a fair value of $0.4 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 30,2016 and 2015.

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 deposits 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, 2016 and December 31, 2015. The estimated fair value of our long-term debt, including current maturities, was $1.3 billion and $1.2 billion at September 30, 2016 and December 31, 2015, respectively. The estimated fair value of our Senior Notes at September 30, 2016 and December 31, 2015, was determined using quoted market prices, and are considered 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, 2016, are not necessarily indicative of the results that may be expected for a 12-month period.

RECENT DEVELOPMENTS

Dividend - In October 2016, a dividend of $0.35 per share ($1.40 per share on an annualized basis) was declared for shareholders of record on November 14, 2016, payable December 1, 2016.

Regulatory Activities - Oklahoma - In March 2016, Oklahoma Natural Gas filed its energy-efficiency program true-up application for its 2015 program year, requesting a utility incentive of $1.9 million and a program true-up adjustment of $3.1 million. This filing also sought approval for the demand portfolio of conservation and energy efficiency programs for calendar years 2017 through 2019. In July 2016, the staff of the OCC filed testimony in support of the filing. In August 2016, a stipulation and settlement agreement was filed and supporting testimony was heard by the administrative law judge. In October 2016, the OCC approved the joint stipulation and settlement agreement.

In July 2015, Oklahoma Natural Gas filed a request with the OCC 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 January 2016, the OCC approved a joint stipulation and settlement agreement to allow an increase in revenue of $29,995,000. We also recorded a regulatory asset of $2.4 million to recover certain information technology costs incurred as a result of our separation from ONEOK in 2014, which will be recovered over four years. The agreement set Oklahoma Natural Gas’ authorized return on equity at 9.5 percent, which represents the midpoint of the allowed range of 9.0 to 10.0 percent, and approved a rate base of approximately $1.2 billion. The agreement includes the continuation, with certain modifications, of the Performance-Based Rate Change tariff that was established in 2009. Oklahoma Natural Gas expects to make its next Performance-Based Rate Change filing on or before March 15, 2017.

Kansas - 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. Kansas Gas Service’s request represented a net base rate increase of $28.0 million. Kansas Gas Service is already recovering approximately $7.4 million from customers through the GSRS, resulting in a total base rate increase of $35.4 million. The filing was based on a 10.0 percent return on equity and a common equity ratio of 55.0 percent. The filing represented a rate base of $903 million, compared with $826 million included in existing base rates plus previously approved GSRS-eligible investments. 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 is $15.5 million. The agreement is a “black-box settlement,” meaning the parties agreed to a specific revenue number but no specific return on equity. The KCC has until December 28, 2016, to make a ruling, with new rates effective no earlier than January 1, 2017.

In August 2015, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $2.4 million related to its GSRS. In November 2015, the KCC approved the $2.4 million increase effective December 2015.

Texas - In June 2016, Texas Gas Service filed a rate case requesting an increase in revenues of $11.6 million 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 incorporated 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 will be effective in November 2016, for customers in the incorporated cities of the former Central Texas service area. Upon RRC approval, new rates will be effective for customers in the unincorporated areas of the new consolidated Central Texas service area, which is expected by January 9, 2017. Texas Gas Service expects to file for the same rates in the incorporated areas of the former South Texas service area by January 2017. In the agreement, the parties established a 9.5 percent return on equity and 60.1 percent common equity ratio.

In November 2015, Texas Gas Service notified the EPSA that it would be filing a full rate case in 2016 in lieu of the EPARR. In March 2016, Texas Gas Service filed a rate case requesting an increase in revenues of $12.8 million for the EPSA and its

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Dell City and Permian service areas. The filing included a request to consolidate these three service areas into a new West Texas service area. Texas Gas Service filed this rate case directly with the incorporated cities of the EPSA and Dell City service area and the RRC for the unincorporated areas. In July 2016, several incorporated cities, including the city of El Paso, denied the request and Texas Gas Service appealed the denial to the RRC. In September 2016, the RRC approved consolidation of the three service areas into the new West Texas service area 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, rates went into effect for all service areas, except for the incorporated cities in the former Permian service area, for which Texas Gas Service expects to file for these new rates in the fourth quarter of 2016. Also in October 2016, Texas Gas Service filed a motion for rehearing asking the RRC to reconsider incentive compensation cost recovery. The City of El Paso also filed a motion for rehearing to address the issues of  consolidation, depreciation rates, capital structure and inclusion of certain invested capital in rate base.  The RRC has until January 5, 2017, to make a ruling.

In December 2015, Texas Gas Service filed a rate case requesting an increase in revenues of $3.1 million for its Galveston and South Jefferson County service areas. The filing 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 incorporated cities and the staff of the RRC on behalf of the unincorporated areas for an increase in revenues of $2.3 million. New rates became effective in May 2016.

In March 2015, Texas Gas Service filed under the annual rate review mechanism called EPARR, requesting an increase in revenues totaling $11.2 million in the city of El Paso and surrounding incorporated cities in the EPSA. In August 2015, Texas Gas Service and the incorporated cities in the EPSA reached an agreement on a rate increase of $8.0 million to take effect in August 2015. In April 2015, Texas Gas Service filed with the RRC under the GRIP statute, requesting an increase of $0.4 million in revenues for the unincorporated areas of the EPSA. GRIP is a capital-recovery mechanism that allows for a rate adjustment providing recovery of and a return on incremental capital investments made between rate cases. The RRC approved the filing in July 2015.

Texas Gas Service received approval under the GRIP statute with the city of Austin, Texas, and surrounding communities in May 2015, for an increase in revenues of approximately $3.7 million. The new rates were effective in June 2015.

In the normal course of business, Texas Gas Service has filed rate cases and sought GRIP and cost of service adjustments in various other Texas jurisdictions to address investments in rate base and changes in expenses. Annual rate increases associated with these filings totaling $4.8 million were approved in 2015. To date in 2016, the increases approved total $2.0 million.

FINANCIAL RESULTS AND OPERATING INFORMATION

We operate in one reportable business segment: regulated public utilities that deliver natural gas to residential, commercial, industrial, wholesale, public authority and transportation customers. We evaluate our financial performance principally on operating income.

Selected Financial Results - 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,				2016 vs. 2015					2016 vs. 2015
Financial Results	2016		2015		2016		2015		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars, except percentages)
Natural gas sales	$	204.3	$	197.9	$	892.9	$	1,063.7	$	6.4		3	%	$	(170.8	)	(16	)%
Transportation revenues	21.2		20.9		72.2		72.9		0.3			1	%	(0.7		)	(1	)%
Cost of natural gas	52.2		54.7		344.4		548.2		(2.5		)	(5	)%	(203.8		)	(37	)%
Net margin, excluding other revenues	173.3		164.1		620.7		588.4		9.2			6	%	32.3			5	%
Other revenues	6.6		6.4		21.3		21.9		0.2			3	%	(0.6		)	(3	)%
Net margin	179.9		170.5		642.0		610.3		9.4			6	%	31.7			5	%
Operating costs	112.7		111.6		344.9		346.5		1.1			1	%	(1.6		)	—	%
Depreciation and amortization	36.3		34.0		106.5		98.6		2.3			7	%	7.9			8	%
Operating income	$	30.9	$	24.9	$	190.6	$	165.2	$	6.0		24	%	$	25.4		15	%
Capital expenditures	$	86.5	$	74.3	$	231.3	$	199.7	$	12.2		16	%	$	31.6		16	%

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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,				2016 vs. 2015				2016 vs. 2015
Revenues	2016		2015		2016		2015		Increase (Decrease)				Increase (Decrease)
Natural gas sales	(Millions of dollars, except percentages)
Residential	$	126.9	$	118.9	$	454.4	$	425.8	$	8.0	7	%	$	28.6		7	%
Commercial and industrial	24.1		23.3		89.6		85.4		0.8		3	%	4.2			5	%
Wholesale and public authority	1.1		1.0		4.5		4.3		0.1		10	%	0.2			5	%
Net margin on natural gas sales	152.1		143.2		548.5		515.5		8.9		6	%	33.0			6	%
Transportation revenues	21.2		20.9		72.2		72.9		0.3		1	%	(0.7		)	(1	)%
Net margin, excluding other revenues	$	173.3	$	164.1	$	620.7	$	588.4	$	9.2	6	%	$	32.3		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, which include weather normalization, 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:

	Three Months Ended				Nine Months Ended				Three Months					Nine Months
	September 30,				September 30,				2016 vs. 2015					2016 vs. 2015
Net Margin on Natural Gas Sales	2016		2015		2016		2015		Increase (Decrease)					Increase (Decrease)
Net margin on natural gas sales	(Millions of dollars, except percentages)
Fixed margin	$	137.0	$	128.0	$	418.8	$	387.8	$	9.0		7	%	$	31.0	8	%
Variable margin	15.1		15.2		129.7		127.7		(0.1		)	(1	)%	2.0		2	%
Net margin on natural gas sales	$	152.1	$	143.2	$	548.5	$	515.5	$	8.9		6	%	$	33.0	6	%

Net margin increased $9.4 million for the three months ended September 30, 2016, compared with the same period last year, due primarily to the following:

• an increase of $8.2 million from new rates primarily in Oklahoma and Texas; and

• an increase of $1.1 million in residential sales due primarily to customer growth in Oklahoma and Texas.

Net margin increased $31.7 million for the nine months ended September 30, 2016, compared with the same period last year, due primarily to the following:

• an increase of $32.6 million from new rates primarily in Oklahoma and Texas;

• an increase of $2.9 million in residential sales due primarily to customer growth in Oklahoma and Texas; and

• an increase of $1.2 million in ad valorem recoveries in Kansas, which is offset with higher related amortization expense; offset partially by

• a decrease of $3.0 million due to lower sales volumes, net of weather normalization, primarily from warmer weather for the nine months ended September 30, 2016, compared with the same period last year; and

• a decrease of $1.3 million due primarily to lower transportation volumes from weather-sensitive customers in Kansas and Oklahoma.

Operating costs increased $1.1 million for the three months ended September 30, 2016, compared with the same period last year, due primarily to an increase of $0.8 million in outside services and fleet and materials expense.

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Operating costs decreased $1.6 million for the nine months ended September 30, 2016, compared with the same period last year, due primarily to the following:

• a decrease of $3.8 million in outside service costs and fleet and materials expense;

• a decrease of $2.6 million in information technology costs; and

• a decrease of $2.4 million from the deferral 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; offset partially by

• an increase of $4.9 million in employee-related costs; and

• an increase of $2.7 million in legal-related costs.

Depreciation and amortization expense increased $2.3 million and $7.9 million for the three and nine months ended September 30, 2016, respectively, compared with the same periods last year, due primarily to an increase in depreciation from our capital expenditures being placed into service.

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 $12.2 million and $31.6 million for the three and nine months ended September 30, 2016, respectively, compared with the same respective periods last year, due primarily to increased system integrity activities and extending service to new areas.

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

	Three Months Ended								Variances
	September 30,								2016 vs. 2015
(in thousands)	2016				2015				Increase (Decrease)
Average Number of Customers	OK	KS	TX	Total	OK	KS	TX	Total	OK	KS	TX	Total
Residential	782	576	612	1,970	776	573	606	1,955	6	3	6	15
Commercial and industrial	71	50	34	155	71	50	33	154	—	—	1	1
Wholesale and public authority	—	—	3	3	—	—	3	3	—	—	—	—
Transportation	6	6	1	13	6	6	1	13	—	—	—	—
Total customers	859	632	650	2,141	853	629	643	2,125	6	3	7	16

	Nine Months Ended								Variances
	September 30,								2016 vs. 2015
(in thousands)	2016				2015				Increase (Decrease)
Average Number of Customers	OK	KS	TX	Total	OK	KS	TX	Total	OK	KS	TX	Total
Residential	788	582	612	1,982	783	580	607	1,970	5	2	5	12
Commercial and industrial	73	50	35	158	73	50	34	157	—	—	1	1
Wholesale and public authority	—	—	3	3	—	—	3	3	—	—	—	—
Transportation	5	6	1	12	5	6	1	12	—	—	—	—
Total customers	866	638	651	2,155	861	636	645	2,142	5	2	6	13

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	Three Months Ended		Nine Months Ended
	September 30,		September 30,
Volumes (MMcf)	2016	2015	2016	2015
Natural gas sales
Residential	7,425	7,476	69,687	78,987
Commercial and industrial	3,590	3,676	22,408	25,460
Wholesale and public authority	261	247	1,542	1,719
Total volumes sold	11,276	11,399	93,637	106,166
Transportation	46,036	43,056	154,857	150,611
Total volumes delivered	57,312	54,455	248,494	256,777

Total volumes delivered decreased for the nine months ended September 30, 2016, compared with the same period last year, due primarily to warmer temperatures in 2016. The impact on residential and commercial margins was mitigated significantly by weather-normalization mechanisms. Transportation volumes increased for the nine months ended September 30, 2016, compared with the same period last year, due to a large industrial customer’s facility undergoing maintenance in the prior year, offset by a decrease in transportation volumes associated with smaller weather-sensitive customers.

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,
	2016		2015		2016 vs 2015		2016		2015
Heating Degree Days	Actual	Normal	Actual	Normal	Actual Variance		Actual as a percent of Normal
Oklahoma	3	2	—	14	100	%	150	%	—	%
Kansas	19	52	9	52	111	%	37	%	17	%
Texas	2	1	—	1	100	%	200	%	—	%

	Nine Months Ended
	September 30,
	2016		2015		2016 vs 2015		2016		2015
Heating Degree Days	Actual	Normal	Actual	Normal	Actual Variance		Actual as a percent of Normal
Oklahoma	1,730	1,968	2,067	2,012	(16	)%	88	%	103	%
Kansas	2,459	2,965	2,824	2,965	(13	)%	83	%	95	%
Texas	899	1,034	1,117	1,023	(20	)%	87	%	109	%

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 13 weather stations across Kansas and weighted on HDDs by weather station and customers for Kansas; and

• a rolling 10-year average of actual natural gas distribution sales volumes by service area for Texas.

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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;

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

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

CONTINGENCIES

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.

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 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 - The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At September 30, 2016, our debt-to-capital ratio was 40 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, 2016, we had $41.0 million in short-term borrowings and $1.0 million in letters of credit issued under the ONE Gas Credit Agreement. At September 30, 2016, we had approximately $4.5 million of cash and cash equivalents and $658.0 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 - We have senior 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 senior notes due 2044 (collectively, our “Senior Notes”). 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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Credit Ratings- Our credit ratings as of September 30, 2016, were:

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

Our commercial paper is currently rated Prime-1 by Moody’s and A-2 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. In June 2016, S&P changed our outlook to Positive from Stable.

Pension and Other Postemployment Benefit Plans- Information about our pension and other postemployment benefit plans, including anticipated contributions, is included under Note 12 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.

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
	2016			2015			2016 vs. 2015
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	281.4		$	349.5		$	(68.1	)
Investing activities	(230.8		)	(199.6		)	(31.2		)
Financing activities	(48.5		)	(108.8		)	60.3
Change in cash and cash equivalents	2.1			41.1			(39.0		)
Cash and cash equivalents at beginning of period	2.4			11.9			(9.5		)
Cash and cash equivalents at end of period	$	4.5		$	53.0		$	(48.5	)

Operating Cash Flows - Changes in cash flows from operating activities, before changes in operating assets and liabilities, 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.

For the nine months ended September 30, 2016, cash flows from operating activities, before changes in operating assets and liabilities, reflects the positive impact on income taxes from bonus depreciation, which is offset by a net decrease in cash flows from operating assets and liabilities, due primarily to the impact of lower natural gas prices on accounts receivable, accounts payable and natural gas in storage. We purchase natural gas for storage during the second and third quarters and withdraw gas from storage for our heating season during the first and fourth quarters. With lower gas costs for the 2015/2016 heating season compared with the 2014/2015 heating season, the value of natural gas withdrawn from storage was lower, resulting in less cash collected as our storage was utilized. Additionally, through the third quarter of 2015, our net over-recovered purchased gas costs increased by $38.7 million. Through the third quarter of 2016, our net over-recovered purchased gas costs decreased by $27.1 million. The change in the recoveries between periods also contributed to the decrease in cash flows from operating assets and liabilities.

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Investing Cash Flows-Cash used in investing activities increased for the nine months ended September 30, 2016, compared with the prior period, due primarily to increased system integrity activities and extending service to new areas during the nine months ended September 30, 2016. Capital expenditures for fiscal 2016 are expected to be comparable to fiscal 2015.

Financing Cash Flows-Cash used in financing activities decreased for the nine months ended September 30, 2016, compared with the prior period, due primarily to an increase in borrowings of notes payable.

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 at our facilities. 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, results of operations and cash flows.

We own or retain legal responsibility for the environmental conditions at 12 former manufactured natural gas sites in Kansas. These sites contain potentially harmful materials that 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 allow 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 according to plans approved by the KDHE. Regulatory closure has been achieved at three of the sites. We have begun site assessment at the remaining site where no active remediation has occurred.

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, 2016 and 2015. 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 notice of proposed rulemaking (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. The potential capital and operating expenditures associated with the NPRM are currently being evaluated and could be significant depending on the final regulations.

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Air and Water Emissions -The Clean Air Act, the Clean Water Act and analogous state laws and/or regulations promulgated thereunder, impose restrictions and controls regarding the discharge of pollutants into the air and water in the United States. Under the Clean Air Act, a federally enforceable operating permit is required for sources of significant air emissions. We may be required to incur certain capital expenditures for air-pollution-control equipment in connection with obtaining or maintaining permits and approvals for sources of air emissions. We do not expect that these expenditures will have a material impact on our respective results of operations, financial position or cash flows. The Clean Water Act imposes substantial potential liability for the removal of pollutants discharged to waters of the United States and remediation of waters affected by such discharge.

Federal, state and regional initiatives to measure and regulate greenhouse gas emissions are underway. We monitor relevant federal and state legislation 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 that assesses any costs, fees or expenses on any of these emissions.

CERCLA -The federal CERCLA, also commonly known as Superfund, imposes strict, joint and several liability, without regard to fault or the legality of the original act, on certain classes of “persons” (defined under CERCLA) that caused and/or contributed to the release of a hazardous substance into the environment. These persons include but are not limited to the owner or operator of a facility where the release occurred and/or companies that disposed or arranged for the disposal of the hazardous substances found at the facility. Under CERCLA, these persons may be liable for the costs of cleaning up the hazardous substances released into the environment, damages to natural resources and the costs of certain health studies. We do not expect that our responsibilities under CERCLA will have a material impact on our respective results of operations, financial position or cash flows.

Pipeline Security -The United States 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 lease 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.

Regulatory - Several regulatory initiatives impacted the earnings and future earnings potential of our business.  See discussion of 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.

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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, including the application of market rates by state and local agencies;

• 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;

• 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;

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• changes in inflation and interest rates;

• our ability to purchase and sell assets at reasonable prices and on other reasonable terms;

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

• changes in law resulting from new federal or state legislation;

• changes in environmental, safety, tax and other laws to which we and our subsidiaries are subject;

• 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 cyber attacks or breaches of technology systems and war;

• the sufficiency of insurance coverage to cover losses;

• the effects of our strategies to reduce tax payments;

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

• changes in accounting standards;

• changes in corporate governance standards;

• discovery of material weaknesses in our internal controls;

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

• the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including our credit ratings and general economic conditions;

• 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.

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 the state commissions, 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 issuance of debt or commercial paper. 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

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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 most jurisdictions, we are able to recover the natural gas cost component of our uncollectible accounts through our purchased-gas cost 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, 2016, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

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

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

Not applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

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.

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

Exhibit No.		Exhibit Description
	3.1	Amended and Restated By-laws of ONE Gas, Inc. (incorporated by reference to Exhibit 3.1 to ONE Gas, Inc.’s Current Report on Form 8-K/A filed on July 26, 2016 (File No. 001-36108)).
	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, 2016 and 2015; (iii) Statements of Comprehensive Income for the three and nine months ended September 30, 2016 and 2015; (iv) Balance Sheets at September 30, 2016 and December 31, 2015; (v) Statements of Cash Flows for the nine months ended September 30, 2016 and 2015; (vi) Statement of Equity for the nine months ended September 30, 2016; 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.

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SIGNATURE

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

Date: November 1, 2016		ONE Gas, Inc.
		Registrant
	By:	/s/ Curtis L. Dinan
		Curtis L. Dinan
		Senior Vice President,
		Chief Financial Officer and Treasurer
		(Principal Financial Officer)

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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: November 1, 2016

/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: November 1, 2016

/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, 2016, 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

November 1, 2016

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, 2016, 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

November 1, 2016

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

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Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 25, 2016
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		52,245,273
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016

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STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Gross Margin
Revenues	$ 232,191	$ 225,226	$ 986,479	$ 1,158,543
Cost of natural gas	52,253	54,724	344,439	548,226
Net margin	179,938	170,502	642,040	610,317
Operating expenses
Operations and maintenance	99,402	98,698	302,652	304,681
Depreciation and amortization	36,241	33,956	106,490	98,592
General taxes	13,403	12,897	42,311	41,818
Total operating expenses	149,046	145,551	451,453	445,091
Operating income	30,892	24,951	190,587	165,226
Other income	911	166	1,345	1,051
Other expense	(357)	(1,884)	(1,126)	(2,840)
Interest expense, net	(10,809)	(11,233)	(32,504)	(33,592)
Income before income taxes	20,637	12,000	158,302	129,845
Income taxes	(7,900)	(4,629)	(60,521)	(50,017)
Net income	$ 12,737	$ 7,371	$ 97,781	$ 79,828
Earnings per share
Basic	$ 0.24	$ 0.14	$ 1.86	$ 1.52
Diluted	$ 0.24	$ 0.14	$ 1.85	$ 1.50
Average shares (thousands)
Basic	52,453	52,408	52,452	52,627
Diluted	52,942	53,072	52,962	53,315
Dividends declared per share of stock	$ 0.35	$ 0.30	$ 1.05	$ 0.90

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STATEMENTS OF COMPREHENSIVE INCOME STATEMENTS OF COMPREHENSIVE INCOME Parenthetical - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
STATEMENTS OF COMPREHENSIVE INCOME Parenthetical [Abstract]
Pension and other postretirement benefit plans, tax	$ (72)	$ (88)	$ (217)	$ (264)

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STATEMENTS OF COMPREHENSIVE INCOME STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Net income	$ 12,737	$ 7,371	$ 97,781	$ 79,828
Other comprehensive income (loss), net of tax
Change in pension and postretirement benefit plan liability, net of tax of $(72), $(88), $(217) and $(264), respectively	116	141	347	423
Other comprehensive income (loss), net of tax	116	141	347	423
Comprehensive income	$ 12,853	$ 7,512	$ 98,128	$ 80,251

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BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Property, plant and equipment
Property, plant and equipment	$ 5,338,591	$ 5,132,682
Accumulated depreciation and amortization	1,658,266	1,620,771
Net property, plant and equipment	3,680,325	3,511,911
Current assets
Cash and cash equivalents	4,513	2,433
Accounts receivable, net	105,060	216,343
Materials and supplies	30,098	33,325
Income tax receivable	6,952	38,877
Natural gas in storage	144,230	142,153
Regulatory assets	73,863	32,925
Other current assets	12,457	16,789
Total current assets	377,173	482,845
Goodwill and other assets
Regulatory assets	431,086	435,863
Goodwill	157,953	157,953
Other assets	47,142	46,193
Total goodwill and other assets	636,181	640,009
Total assets	4,693,679	4,634,765
Equity and long-term debt
Common stock, $0.01 par value: authorized 250,000,000 shares; issued 52,598,005 shares and outstanding 52,245,273 shares at September 30, 2016; issued 52,598,005 shares and outstanding 52,259,224 shares at December 31, 2015	526	526
Paid-in Capital	1,748,965	1,764,875
Retained earnings	137,221	95,046
Accumulated other comprehensive income (loss)	(4,054)	(4,401)
Treasury stock, at cost: 352,732 shares at September 30, 2016 and 338,781 shares at December 31, 2015	(20,314)	(14,491)
Total equity	1,862,344	1,841,555
Long-term debt, excluding current maturities and net of issuance costs of $9,051 and $9,645, respectively	1,192,248	1,191,660
Total equity and long-term debt	3,054,592	3,033,215
Current liabilities
Current maturities of long-term debt	7	7
Notes payable	41,000	12,500
Accounts payable	70,562	107,482
Accrued interest	7,691	18,873
Accrued taxes other than income	39,919	37,249
Accrued liabilities	17,812	31,470
Customer deposits	60,425	60,325
Regulatory liabilities	13,204	24,615
Other current liabilities	8,212	11,700
Total current liabilities	258,832	304,221
Deferred credits and other liabilities [Abstract]
Deferred income taxes	1,011,691	951,785
Employee benefit obligations	291,230	272,309
Other deferred credits	77,334	73,235
Total deferred credits and other liabilities	1,380,255	1,297,329
Commitments and contingencies
Total liabilities and equity	$ 4,693,679	$ 4,634,765

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BALANCE SHEETS BALANCE SHEETS Parenthetical - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
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	52,245,273	52,259,224
Treasury Stock, Shares	352,732	338,781
Debt Issuance Cost	$ 9,051,000	$ 9,645,000

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STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Operating activities
Net income	$ 97,781	$ 79,828
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	106,490	98,592
Deferred income taxes	59,771	19,384
Share-based compensation expense	9,341	3,863
Provision for doubtful accounts	3,521	2,951
Changes in assets and liabilities:
Accounts receivable	107,762	220,392
Materials and supplies	3,227	(5,889)
Income tax receivable	31,925	20,075
Natural gas in storage	(2,077)	25,388
Asset removal costs	(40,715)	(33,744)
Accounts payable	(32,923)	(104,948)
Accrued interest	(11,182)	(11,225)
Accrued taxes other than income	2,670	(4,313)
Accrued liabilities	(13,658)	(8,019)
Customer deposits	100	(1,672)
Regulatory assets and liabilities	(18,726)	64,368
Other assets and liabilities	(21,877)	(15,493)
Cash provided by operating activities	281,430	349,538
Investing activities
Capital expenditures	(231,336)	(199,678)
Other	492	0
Cash used in investing activities	(230,844)	(199,678)
Financing activities
Borrowings (repayments) on notes payable, net	28,500	(42,000)
Repurchase of common stock	(24,066)	(24,122)
Issuance of common stock	1,983	4,471
Dividends paid	(54,923)	(47,178)
Cash provided by (used in) financing activities	(48,506)	(108,829)
Change in cash and cash equivalents	2,080	41,031
Cash and cash equivalents at beginning of period	2,433	11,943
Cash and cash equivalents at end of period	$ 4,513	$ 52,974

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STATEMENT OF CHANGES IN EQUITY - 9 months ended Sep. 30, 2016 - 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, 2015	52,598,005	52,598,005
Equity, beginning balance at Dec. 31, 2015	$ 1,841,555	$ 526	$ 1,764,875	$ 95,046	$ (14,491)	$ (4,401)
Net income	97,781	0	0	97,781	0	0
Other comprehensive income	347	0	0	0		347
Repurchase of common stock	(24,066)	$ 0	0	0	(24,066)	0
Common stock issued, shares		0
Common stock issued, value	1,650	$ 0	(16,593)	0	18,243	0
Common stock dividends - $1.05 per share	$ 54,923	$ 0	(683)	55,606	0	0
Shares issued, ending balance at Sep. 30, 2016	52,598,005	52,598,005
Equity, ending balance at Sep. 30, 2016	$ 1,862,344	$ 526	$ 1,748,965	$ 137,221	$ (20,314)	$ (4,054)

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Notes)

9 Months Ended

Sep. 30, 2016

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 2015 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, 2016, 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 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.

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 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, 2016, and 2015, 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, 2016, 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 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 will modify 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. This new guidance is required to be adopted for our interim and annual reports for periods beginning after December 15, 2016, but may be adopted early. We are evaluating the impact of this guidance and the timing of adoption.

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-divisional teams to determine the potential impact of this accounting standard on our financial position, results of operations and cash flows and the transition approach we will utilize. This new guidance is required for our interim and annual reports for periods beginning after December 15, 2018, and early adoption is permitted.

In August 2015, the FASB issued ASU 2015-15, “Interest-Imputation of Interest (Subtopic 835-30),” which addresses the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements. We adopted this guidance in the first quarter 2016, and it did not have an impact on our financial position or results of operations.

In April 2015, the FASB issued ASU 2015-03, “Interest-Imputation of Interest,” which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. We adopted this guidance in the first quarter of 2016, and have applied the changes retrospectively to all periods presented. We have presented such amounts as a direct deduction from the face amount of our long-term debt, rather than in other assets as a deferred charge in our Balance Sheets. Amortization of the debt issuance costs continues to be reported as interest expense in our Statements of Income.   

In April 2015, the FASB issued ASU 2015-05, “Intangibles-Goodwill and Other-Internal-Use Software,” which helps entities evaluate the accounting for fees paid by a customer in a cloud computing arrangement. We adopted this guidance prospectively in the first quarter of 2016, and it did not have a material impact on our financial position or results of operations.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” 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 are evaluating all of our sources of revenue to determine the potential effect on our financial position, results of operations and cash flows and the transition approach we will utilize. We are monitoring the FASB for additional implementation guidance that may impact the final conclusions of our evaluation. We are required to adopt this guidance for our interim and annual reports beginning with the first quarter 2018.

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REGULATORY ASSETS AND LIABILITIES (Notes)

9 Months Ended

Sep. 30, 2016

SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]

Schedule of Regulatory Assets and Liabilities [Text Block]

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, 2016
	Current			Noncurrent			Total
	(Thousands of dollars)
Under-recovered purchased-gas costs	$	29,109		$	—		$	29,109
Pension and postemployment benefit costs	24,706			416,327			441,033
Weather normalization	17,004			—			17,004
Reacquired debt costs	812			8,312			9,124
Other	2,232			6,447			8,679
Total regulatory assets, net of amortization	73,863			431,086			504,949
Accumulated removal costs (a)	—			(7,019		)	(7,019		)
Over-recovered purchased-gas costs	(11,538		)	—			(11,538		)
Ad valorem tax	(1,666		)	—			(1,666		)
Total regulatory liabilities	(13,204		)	(7,019		)	(20,223		)
Net regulatory assets (liabilities)	$	60,659		$	424,067		$	484,726

(a) Included in other deferred credits in our Balance Sheets.

	December 31, 2015
	Current			Noncurrent			Total
	(Thousands of dollars)
Under-recovered purchased-gas costs	$	13,336		$	—		$	13,336
Pension and postemployment benefit costs	15,670			425,175			440,845
Weather normalization	2,198			—			2,198
Reacquired debt costs	812			8,919			9,731
Other	909			1,769			2,678
Total regulatory assets, net of amortization	32,925			435,863			468,788
Accumulated removal costs (a)	—			(9,032		)	(9,032		)
Over-recovered purchased-gas costs	(22,884		)	—			(22,884		)
Ad valorem tax	(1,731		)	—			(1,731		)
Total regulatory liabilities	(24,615		)	(9,032		)	(33,647		)
Net regulatory assets (liabilities)	$	8,310		$	426,831		$	435,141

(a) Included in other deferred credits 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.

In January 2016, as a result of the OCC’s approval of our rate case in Oklahoma, we recorded a regulatory asset of $2.4 million to recover certain information technology costs incurred as a result of our separation from ONEOK in 2014, which will be recovered over four years.

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CREDIT FACILITIES (Notes)

9 Months Ended

Sep. 30, 2016

Line of Credit Facility [Line Items]

Short-term Debt [Text Block]

3. CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE

The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At September 30, 2016, our debt-to-capital ratio was 40 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, 2016, we had $41.0 million in short-term borrowings, $1.0 million in letters of credit issued under the ONE Gas Credit Agreement and $658.0 million of remaining credit available under the ONE Gas Credit Agreement.

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LONG-TERM DEBT (Notes)

9 Months Ended

Sep. 30, 2015

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 (collectively, our “Senior Notes”). 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, 2016

EQUITY [Line Items]

Stockholders' Equity Note Disclosure [Text Block]

5. EQUITY

In the first quarter of 2016, we repurchased approximately 407 thousand shares of our common stock for approximately $24.1 million.

In October 2016, a dividend of $0.35 per share ($1.40 per share on an annualized basis) was declared for shareholders of record on November 14, 2016, payable December 1, 2016.

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Notes)

9 Months Ended

Sep. 30, 2016

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	2016			2015			2016			2015			Statements of Income
	(Thousands of dollars)
Pension and other postemployment benefit plan obligations (a)
Amortization of net loss	$	10,040		$	12,564		$	30,113		$	37,694
Amortization of unrecognized prior service cost	(909		)	(374		)	(2,725		)	(1,120		)
	9,131			12,190			27,388			36,574
Regulatory adjustments (b)	(8,943		)	(11,961		)	(26,824		)	(35,887		)
	188			229			564			687			Income before income taxes
	(72		)	(88		)	(217		)	(264		)	Income tax expense
Total reclassifications for the period	$	116		$	141		$	347		$	423		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, 2016

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, 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

	Three Months Ended September 30, 2015
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	7,371	52,408	$	0.14
Diluted EPS Calculation
Effect of dilutive securities	—		664
Net income available for common stock and common stock equivalents	$	7,371	53,072	$	0.14

	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

	Nine Months Ended September 30, 2015
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	79,828	52,627	$	1.52
Diluted EPS Calculation
Effect of dilutive securities	—		688
Net income available for common stock and common stock equivalents	$	79,828	53,315	$	1.50

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EMPLOYEE BENEFIT PLANS (Notes)

9 Months Ended

Sep. 30, 2016

Employee Benefit Plans [Line Items]

EMPLOYEE BENEFIT PLANS

8. EMPLOYEE BENEFIT PLANS

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

	Pension Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	3,014		$	3,497		$	9,042		$	10,518
Interest cost	11,387			10,652			34,162			31,956
Expected return on assets	(15,296		)	(15,363		)	(45,888		)	(46,087		)
Amortization of unrecognized prior service cost	—			66			—			200
Amortization of net loss	8,886			11,054			26,657			33,164
Net periodic benefit cost	$	7,991		$	9,906		$	23,973		$	29,751

	Other Postemployment Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	637		$	849		$	1,913		$	2,547
Interest cost	2,626			2,665			7,880			7,997
Expected return on assets	(3,070		)	(2,908		)	(9,212		)	(8,724		)
Amortization of unrecognized prior service cost	(909		)	(440		)	(2,725		)	(1,320		)
Amortization of net loss	1,154			1,510			3,456			4,530
Net periodic benefit cost	$	438		$	1,676		$	1,312		$	5,030

We recover qualified pension benefit plan and other postemployment benefit plan costs through rates charged to our customers. Certain utility commissions 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 utility commission. Regulatory deferrals related to net periodic benefit cost were not material for the three and nine months ended September 30, 2016.

In October 2015, we announced to certain pre-65 participants in our postretirement medical plans a change from a self-insured postretirement medical plan to a plan providing participants an annual benefit that would allow them to select coverage on a healthcare exchange beginning January 1, 2017. In September 2016, due to uncertain market conditions with health insurance exchange providers, we elected not to move the eligible pre-65 participants in our postemployment medical plans to a healthcare exchange. As a result, we remeasured the respective plan assets and benefit obligations, effective September 30, 2016, which resulted in an increase in benefit obligations of our postemployment benefit plan of $31.5 million. The remeasurement will increase the net periodic benefit cost of our postemployment benefit plan by $0.8 million for the three months ending December 31, 2016.

The following table sets forth the weighted-average assumptions used in the remeasurement of the benefit obligations for postemployment benefits for the periods indicated:

	September 30, 2016	December 31, 2015
Discount rate	3.75%	4.75%
Expected long-term return on plan assets	7.75%	8.00%

The following table sets forth the weighted-average assumptions used in the remeasurement to determine periodic benefit costs for the periods indicated:

	Three Months Ended December 31,	Nine Months Ended September 30,
	2016	2016
Discount rate - other postemployment plans	3.75%	4.75%
Expected long-term return on plan assets	7.75%	8.00%

There were no other changes in assumptions for the other postemployment benefits calculations, which are described in our Annual Report. There was no impact to our previously disclosed obligations and benefit costs for our pension plan.

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COMMITMENTS AND CONTINGENCIES (Notes)

9 Months Ended

Sep. 30, 2016

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 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 at our facilities. 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, results of operations and cash flows.

We own or retain legal responsibility for the environmental conditions at 12 former manufactured natural gas sites in Kansas. These sites contain potentially harmful materials that 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 allow 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 according to plans approved by the KDHE. Regulatory closure has been achieved at three of the sites. We have begun site assessment at the remaining site where no active remediation has occurred.

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 30,2016 and 2015. 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 notice of proposed rulemaking (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. The potential capital and operating expenditures associated with the NPRM 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, 2016

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, 2016, we held purchased natural gas call options for the heating season ending March 2017, with total notional amounts of 30.5 Bcf, for which we paid premiums of $9.4 million, and had a fair value of $8.1 million. At December 31, 2015, we held purchased natural gas call options for the heating season ended March 2016, with total notional amounts of 17.0 Bcf, for which we paid premiums of $5.8 million, and had a fair value of $0.4 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 30,2016 and 2015.

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 deposits 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, 2016 and December 31, 2015. The estimated fair value of our long-term debt, including current maturities, was $1.3 billion and $1.2 billion at September 30, 2016 and December 31, 2015, respectively. The estimated fair value of our Senior Notes at September 30, 2016 and December 31, 2015, was determined using quoted market prices, and are considered Level 2.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2016

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 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, 2016, and 2015, we had no single external customer from which we received 10 percent or more of our gross revenues.

Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block]

Goodwill Impairment Test - We assess our goodwill for impairment at least annually as of July 1. At July 1, 2016, 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

Recently Issued Accounting Standards Update - 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 will modify 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. This new guidance is required to be adopted for our interim and annual reports for periods beginning after December 15, 2016, but may be adopted early. We are evaluating the impact of this guidance and the timing of adoption.

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-divisional teams to determine the potential impact of this accounting standard on our financial position, results of operations and cash flows and the transition approach we will utilize. This new guidance is required for our interim and annual reports for periods beginning after December 15, 2018, and early adoption is permitted.

In August 2015, the FASB issued ASU 2015-15, “Interest-Imputation of Interest (Subtopic 835-30),” which addresses the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements. We adopted this guidance in the first quarter 2016, and it did not have an impact on our financial position or results of operations.

In April 2015, the FASB issued ASU 2015-03, “Interest-Imputation of Interest,” which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. We adopted this guidance in the first quarter of 2016, and have applied the changes retrospectively to all periods presented. We have presented such amounts as a direct deduction from the face amount of our long-term debt, rather than in other assets as a deferred charge in our Balance Sheets. Amortization of the debt issuance costs continues to be reported as interest expense in our Statements of Income.   

In April 2015, the FASB issued ASU 2015-05, “Intangibles-Goodwill and Other-Internal-Use Software,” which helps entities evaluate the accounting for fees paid by a customer in a cloud computing arrangement. We adopted this guidance prospectively in the first quarter of 2016, and it did not have a material impact on our financial position or results of operations.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” 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 are evaluating all of our sources of revenue to determine the potential effect on our financial position, results of operations and cash flows and the transition approach we will utilize. We are monitoring the FASB for additional implementation guidance that may impact the final conclusions of our evaluation. We are required to adopt this guidance for our interim and annual reports beginning with the first quarter 2018.

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

9 Months Ended

Sep. 30, 2016

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, 2016

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, 2016
	Current			Noncurrent			Total
	(Thousands of dollars)
Under-recovered purchased-gas costs	$	29,109		$	—		$	29,109
Pension and postemployment benefit costs	24,706			416,327			441,033
Weather normalization	17,004			—			17,004
Reacquired debt costs	812			8,312			9,124
Other	2,232			6,447			8,679
Total regulatory assets, net of amortization	73,863			431,086			504,949
Accumulated removal costs (a)	—			(7,019		)	(7,019		)
Over-recovered purchased-gas costs	(11,538		)	—			(11,538		)
Ad valorem tax	(1,666		)	—			(1,666		)
Total regulatory liabilities	(13,204		)	(7,019		)	(20,223		)
Net regulatory assets (liabilities)	$	60,659		$	424,067		$	484,726

(a) Included in other deferred credits in our Balance Sheets.

	December 31, 2015
	Current			Noncurrent			Total
	(Thousands of dollars)
Under-recovered purchased-gas costs	$	13,336		$	—		$	13,336
Pension and postemployment benefit costs	15,670			425,175			440,845
Weather normalization	2,198			—			2,198
Reacquired debt costs	812			8,919			9,731
Other	909			1,769			2,678
Total regulatory assets, net of amortization	32,925			435,863			468,788
Accumulated removal costs (a)	—			(9,032		)	(9,032		)
Over-recovered purchased-gas costs	(22,884		)	—			(22,884		)
Ad valorem tax	(1,731		)	—			(1,731		)
Total regulatory liabilities	(24,615		)	(9,032		)	(33,647		)
Net regulatory assets (liabilities)	$	8,310		$	426,831		$	435,141

(a) Included in other deferred credits in our Balance Sheets.

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)

9 Months Ended

Sep. 30, 2016

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	2016			2015			2016			2015			Statements of Income
	(Thousands of dollars)
Pension and other postemployment benefit plan obligations (a)
Amortization of net loss	$	10,040		$	12,564		$	30,113		$	37,694
Amortization of unrecognized prior service cost	(909		)	(374		)	(2,725		)	(1,120		)
	9,131			12,190			27,388			36,574
Regulatory adjustments (b)	(8,943		)	(11,961		)	(26,824		)	(35,887		)
	188			229			564			687			Income before income taxes
	(72		)	(88		)	(217		)	(264		)	Income tax expense
Total reclassifications for the period	$	116		$	141		$	347		$	423		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, 2016

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, 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

	Three Months Ended September 30, 2015
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	7,371	52,408	$	0.14
Diluted EPS Calculation
Effect of dilutive securities	—		664
Net income available for common stock and common stock equivalents	$	7,371	53,072	$	0.14

	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

	Nine Months Ended September 30, 2015
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	79,828	52,627	$	1.52
Diluted EPS Calculation
Effect of dilutive securities	—		688
Net income available for common stock and common stock equivalents	$	79,828	53,315	$	1.50

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EMPLOYEE BENEFIT PLANS (Tables)

9 Months Ended

Sep. 30, 2016

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,
	2016			2015			2016			2015
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	3,014		$	3,497		$	9,042		$	10,518
Interest cost	11,387			10,652			34,162			31,956
Expected return on assets	(15,296		)	(15,363		)	(45,888		)	(46,087		)
Amortization of unrecognized prior service cost	—			66			—			200
Amortization of net loss	8,886			11,054			26,657			33,164
Net periodic benefit cost	$	7,991		$	9,906		$	23,973		$	29,751

	Other Postemployment Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	637		$	849		$	1,913		$	2,547
Interest cost	2,626			2,665			7,880			7,997
Expected return on assets	(3,070		)	(2,908		)	(9,212		)	(8,724		)
Amortization of unrecognized prior service cost	(909		)	(440		)	(2,725		)	(1,320		)
Amortization of net loss	1,154			1,510			3,456			4,530
Net periodic benefit cost	$	438		$	1,676		$	1,312		$	5,030

Schedule of Assumptions Used [Table Text Block]

	September 30, 2016	December 31, 2015
Discount rate	3.75%	4.75%
Expected long-term return on plan assets	7.75%	8.00%

The following table sets forth the weighted-average assumptions used in the remeasurement to determine periodic benefit costs for the periods indicated:

	Three Months Ended December 31,	Nine Months Ended September 30,
	2016	2016
Discount rate - other postemployment plans	3.75%	4.75%
Expected long-term return on plan assets	7.75%	8.00%

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) number in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Significant Accounting Policies [Line Items]
Number of natural gas distribution services customers	2		2
Segment Reporting, Disclosure of Major Customers	0	0	0	0

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REGULATORY ASSETS AND LIABILITIES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jan. 31, 2016	Dec. 31, 2015
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Current		$ 73,863		$ 32,925
Regulatory Assets, Noncurrent		431,086		435,863
Regulatory Liability, Current		(13,204)		(24,615)
Net regulatory assets (liabilities), current		60,659		8,310
Net regulatory assets (liabilities), noncurrent		424,067		426,831
Net Regulatory Assets		484,726		435,141
Accumulated removal costs [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Liability, Current		0		0
Regulatory Liability, Noncurrent		(7,019)		(9,032)
Regulatory Liabilities		(7,019)		(9,032)
Over-recovered purchased-gas costs [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Liability, Current		(11,538)		(22,884)
Regulatory Liability, Noncurrent		0		0
Regulatory Liabilities		(11,538)		(22,884)
Ad valorem tax [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Liability, Current		(1,666)		(1,731)
Regulatory Liability, Noncurrent		0		0
Regulatory Liabilities		(1,666)		(1,731)
Total regulated liabilities [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Liability, Current		(13,204)		(24,615)
Regulatory Liability, Noncurrent		(7,019)		(9,032)
Regulatory Liabilities		(20,223)		(33,647)
Information Technology Costs [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets, Noncurrent			$ 2,400
Information Technology Costs [Member] | Subsequent Event [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Estimated Recovery Period	4
Under-recovered purchased-gas costs [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets		29,109		13,336
Regulatory Assets, Current		29,109		13,336
Regulatory Assets, Noncurrent		0		0
Pension and postretirement benefit costs [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets		441,033		440,845
Regulatory Assets, Current		24,706		15,670
Regulatory Assets, Noncurrent		416,327		425,175
Weather normalization [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets		17,004		2,198
Regulatory Assets, Current		17,004		2,198
Regulatory Assets, Noncurrent		0		0
Reacquired debt costs [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets		9,124		9,731
Regulatory Assets, Current		812		812
Regulatory Assets, Noncurrent		8,312		8,919
Other regulatory assets [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets		8,679		2,678
Regulatory Assets, Current		2,232		909
Regulatory Assets, Noncurrent		6,447		1,769
Total regulatory assets, net of amortization [Member]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Regulatory Assets		504,949		468,788
Regulatory Assets, Current		73,863		32,925
Regulatory Assets, Noncurrent		$ 431,086		$ 435,863

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CREDIT FACILITIES (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($)
Line of Credit Facility [Line Items]
Ratio of Indebtedness to Net Capital	0.4
Commercial paper maximum borrowing capacity	$ 700.0
Commercial paper	41.0
Letters of Credit Outstanding, Amount	1.0
Line of Credit Facility, Remaining Borrowing Capacity	$ 658.0
Line of Credit [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Covenant Description	The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter.

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LONG-TERM DEBT (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016 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		9 Months Ended
	Sep. 30, 2016	Mar. 31, 2016	Sep. 30, 2016
Dividends Declared [Line Items]
Treasury Stock, Shares, Acquired		407
Treasury Stock		$ 24,100	$ 24,066
Common Stock, Dividends, Per Share, Declared	$ 0.35
Common Stock, Dividends, Declared, Annualized Basis	$ 1.40

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amortization of net loss	$ 10,040	$ 12,564	$ 30,113	$ 37,694
Amortization of unrecognized prior service cost	(909)	(374)	(2,725)	(1,120)
Reclassification adjustment, before tax and regulatory adjustments	9,131	12,190	27,388	36,574
Regulatory adjustments	(8,943)	(11,961)	(26,824)	(35,887)
Reclassification adjustment, before tax	188	229	564	687
Reclassification adjustment, Tax	(72)	(88)	(217)	(264)
Reclassification adjustment, net of tax	$ 116	$ 141	$ 347	$ 423

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EARNINGS PER SHARE (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
EARNINGS PER SHARE [Line Items]
Common stock, shares issued	52,598,005		52,598,005		52,598,005
Basic EPS Calculation
Net income available for common stock	$ 12,737	$ 7,371	$ 97,781	$ 79,828
Weighted Average Number of Shares Outstanding, Basic	52,453,000	52,408,000	52,452,000	52,627,000
Earnings Per Share, Basic	$ 0.24	$ 0.14	$ 1.86	$ 1.52
Diluted EPS Calculation
Net income available for common stock	$ 12,737	$ 7,371	$ 97,781	$ 79,828
Effect of dilutive securities on income	$ 0	$ 0	$ 0	$ 0
Effect of dilutive securities on shares	489,000	664,000	510,000	688,000
Weighted Average Number of Shares Outstanding, Diluted	52,942,000	53,072,000	52,962,000	53,315,000
Earnings Per Share, Diluted	$ 0.24	$ 0.14	$ 1.85	$ 1.50

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EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Thousands	3 Months Ended			9 Months Ended		12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Employee Benefit Plans [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		3.75%		3.75%		4.75%
Components of net periodic benefit cost:
Amortization of unrecognized prior service cost		$ (909)	$ (374)	$ (2,725)	$ (1,120)
Amortization of net loss		10,040	12,564	30,113	37,694
Defined Benefit Plan, Effect of Plan Amendment on Net Periodic Benefit Cost		$ 800		$ 800
Discount Rate		4.75%		4.75%
Expected long-term return on plan assets				8.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets				7.75%		8.00%
Subsequent Event [Member]
Components of net periodic benefit cost:
Discount Rate	3.75%
Expected long-term return on plan assets	7.75%
ONE Gas Pension Plans [Member]
Components of net periodic benefit cost:
Service cost		$ 3,014	3,497	$ 9,042	10,518
Interest cost		11,387	10,652	34,162	31,956
Expected return on assets		(15,296)	(15,363)	(45,888)	(46,087)
Amortization of unrecognized prior service cost		0	66	0	200
Amortization of net loss		8,886	11,054	26,657	33,164
Net periodic benefit cost		7,991	9,906	23,973	29,751
ONE Gas Postretirement Benefit Plans [Member]
Employee Benefit Plans [Line Items]
Defined Benefit Plan, Plan Amendments				31,500
Components of net periodic benefit cost:
Service cost		637	849	1,913	2,547
Interest cost		2,626	2,665	7,880	7,997
Expected return on assets		(3,070)	(2,908)	(9,212)	(8,724)
Amortization of unrecognized prior service cost		(909)	(440)	(2,725)	(1,320)
Amortization of net loss		1,154	1,510	3,456	4,530
Net periodic benefit cost		$ 438	$ 1,676	$ 1,312	$ 5,030

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COMMITMENTS AND CONTINGENCIES (Details)	Sep. 30, 2016
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 where regulatory closure has been achieved	3
Percentage yield of high consequence pipeline areas	30.00%

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DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2016 USD ($) MMcf	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($) MMcf	Sep. 30, 2015 USD ($)	Dec. 31, 2015 USD ($) MMcf	Dec. 31, 2014 USD ($)
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative, Nonmonetary Notional Amount | MMcf	30,500		30,500		17,000
Premiums recorded in other current assets on natural gas contracts held	$ 9,400,000		$ 9,400,000		$ 5,800,000
Fair Value Assets, Transfers between Levels	0	$ 0	0	$ 0
Long-term Debt, including current maturities	1,192,248,000		1,192,248,000		1,191,660,000
Cash and Cash Equivalents, at Carrying Value	4,513,000	$ 52,974,000	4,513,000	$ 52,974,000	2,433,000	$ 11,943,000
Long-term Debt	1,200,000,000		1,200,000,000		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	8,100,000		8,100,000		400,000
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