ONE Gas (OGS) 10-Q 31 Oct 17 2017 Q3 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Oct. 24, 2017
Document Information [Line Items]
Entity Registrant Name	ONE Gas, Inc.
Entity Central Index Key	1,587,732
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		52,273,783
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017

STATEMENTS OF INCOME

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

STATEMENTS OF COMPREHENSIVE INC

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

STATEMENTS OF COMPREHENSIVE IN4

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

BALANCE SHEETS

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

BALANCE SHEETS BALANCE SHEETS P

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

STATEMENTS OF CASH FLOWS

STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Document Fiscal Year Focus	2,017
Operating activities
Net income	$ 115,876	$ 97,781
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	113,293	106,490
Deferred income taxes	61,329	59,771
Share-based compensation expense	6,930	9,341
Provision for doubtful accounts	4,508	3,521
Changes in assets and liabilities:
Accounts receivable	158,747	107,762
Materials and supplies	(4,705)	3,227
Natural gas in storage	(32,209)	(2,077)
Asset removal costs	(37,928)	(40,715)
Accounts payable	(65,983)	(32,923)
Accrued interest	(11,112)	(11,182)
Accrued taxes other than income	2,087	2,670
Accrued liabilities	(4,396)	(13,658)
Customer deposits	(1,566)	100
Regulatory assets and liabilities	11,448	(18,726)
Other assets and liabilities	(13,915)	19,053
Cash provided by operating activities	302,404	290,435
Investing activities
Capital expenditures	(249,057)	(231,336)
Other	617	492
Cash used in investing activities	(248,440)	(230,844)
Financing activities
Repayments of notes payable, net	29,000	28,500
Repurchase of common stock	(17,512)	(24,066)
Proceeds from Issuance of Common Stock	2,208	1,983
Dividends paid	(65,996)	(54,923)
Tax withholdings related to net share settlements of stock compensation	(9,455)	(9,005)
Cash used in financing activities	(61,755)	(57,511)
Change in cash and cash equivalents	(7,791)	2,080
Cash and cash equivalents at beginning of period	14,663	2,433
Cash and cash equivalents at end of period	$ 6,872	$ 4,513

STATEMENT OF CHANGES IN EQUITY

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

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Notes)	9 Months Ended
	Sep. 30, 2017
Significant Accounting Policies [Line Items]
SIGNIFICANT ACCOUNTING POLICIES	1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Our accompanying unaudited financial statements have been prepared pursuant to the rules and regulations of the SEC. These statements also have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair statement of the results for the interim periods presented. All such adjustments are of a normal recurring nature. The 2016 year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. These unaudited financial statements should be read in conjunction with the audited financial statements and footnotes in our Annual Report. Due to the seasonal nature of our business, the results of operations for the three and nine months ended September 30, 2017 , are not necessarily indicative of the results that may be expected for a 12-month period. We provide natural gas distribution services to more than 2 million customers through our divisions in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. We serve residential, commercial, industrial and transportation customers in all three states. In addition, we also provide natural gas distribution services to wholesale and public authority customers. Other - In October 2017, we filed and received approval from the Oklahoma Insurance Department to form a wholly-owned captive insurance company. Use of Estimates - The preparation of our financial statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, provision for doubtful accounts, unbilled revenues for natural gas delivered but for which meters have not been read, natural gas purchased but for which no invoice has been received, provision for income taxes, including any deferred tax valuation allowances, the results of litigation and various other recorded or disclosed amounts. We evaluate these estimates on an ongoing basis using historical experience and other methods we consider reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on our financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known. Segments - We operate in one reportable and operating business segment: regulated public utilities that deliver natural gas to residential, commercial, industrial, wholesale, public authority and transportation customers. The accounting policies for our segment are the same as described in Note 1 of our Notes to the Financial Statements in our Annual Report. We evaluate our financial performance principally on operating income. For the three and nine months ended September 30, 2017 , and 2016 , we had no single external customer from which we received 10 percent or more of our gross revenues. Goodwill Impairment Test - We assess our goodwill for impairment at least annually as of July 1. At July 1, 2017, we assessed qualitative factors to determine whether it was more likely than not that the fair value of our reporting unit was less than its carrying amount. After assessing qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance), we determined that no further testing was necessary. Recently Issued Accounting Standards Update - In August 2017, the FASB issued ASU 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities,” which allows more types of hedging strategies to be eligible for hedge accounting and simplifies application of hedge accounting. This new guidance is required for our interim and annual reports for periods beginning after December 15, 2018, and early adoption is permitted, but must be applied as of the beginning of the fiscal year, or initial application date. The impact of this guidance is not material to us, as we have not elected hedge accounting due to the nature of the types of derivatives we have entered. In March 2017, the FASB issued ASU 2017-07, “Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost,” which requires (1) separation of net periodic service costs for pension and other postemployment benefits into service cost and other components, (2) presentation of the service cost component in the same line as other compensation costs rendered by pertinent employees during the period, and (3) reporting the other components of net periodic benefit costs separately from the service cost component and outside a subtotal of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all of our cost components remain eligible for capitalization under the accounting requirements for rate regulated entities. We will adopt this guidance for our interim and annual reports for periods in the first quarter of 2018. When adopted, the presentation changes required for net periodic benefit costs will not impact previously reported net income; however, the reclassification of the other components of benefits costs will result in an increase in operating income and an increase in other expenses for 2016 and 2017. We will use the retroactive presentation that permits the use of the amounts disclosed for the various components of net benefit cost in our respective Annual Report’s Employee Benefit Plans footnote as the basis for the retrospective application. In addition, we are currently updating our systems for the capitalization of service costs to property and non-service costs to a regulatory asset on a prospective basis, as well as the appropriate accounts for non-service costs to apply retroactive reclassification. In January 2017, the FASB issued ASU 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment,” which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 of the goodwill test, where the measurement of a goodwill impairment loss was determined by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Upon adoption, a goodwill impairment will be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. We early adopted this new guidance in the current quarter, and it did not have an impact on our financial statements. See our conclusions regarding our current year Goodwill Impairment Test above. In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses: Measurement of Credit Losses on Financial Instruments,’’ which introduces new guidance to the accounting for credit losses on instruments within its scope, including trade receivables. It is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and may be adopted a year earlier. The new guidance will be initially applied through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. We are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of 2021. In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting,” which includes various new aspects to simplify how share-based payments are accounted for and presented in the financial statements. The new standard modifies several aspects of the accounting and reporting for employee share-based payments and related tax accounting impacts, including the presentation in the statements of operations and cash flows. We adopted this new guidance in the first quarter 2017, and in accordance with the transition requirements, we recorded $5.2 million of excess tax benefit in income tax expense and have transitioned all provisions of this new guidance prospectively, other than our presentation of our withholding shares for tax-withholding purposes, which we accounted for retrospectively in the financing activities section of the statement of cash flows. We recorded a noncash cumulative-effect increase of $11.0 million to retained earnings, with an offset to a deferred tax asset, as of the beginning of the reporting period in 2017, for excess tax benefits earned prior to January 1, 2017, that had not been recognized. We continue our use of the estimation method to account for share unit award forfeitures rather than actual forfeitures. The retrospective impact of our withholding shares for tax-withholding purposes to our Statement of Cash Flows for the nine months ended September 30, 2016 , was a $9.0 million increase to net cash provided by operating activities and a $9.0 million decrease to net cash used in financing activities. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” which prescribes recognizing lease assets and liabilities on the balance sheet and includes disclosure of key information about leasing arrangements. A modified retrospective transition approach is required for leases existing at the time of adoption. We are evaluating our population of leases, analyzing lease agreements, and holding meetings with cross-functional teams to determine the potential impact of this accounting standard on our financial position and results of operations and the transition approach we will utilize. We are also continuing to monitor the FASB for additional guidance surrounding an exposure draft regarding land easements. This information will help us determine what information will ultimately be disclosed in our financial statements and footnotes. Until this item is resolved, we cannot complete our evaluation of the potential effect the new guidance will have on our financial position, results of operations, cash flows or business processes. We will adopt this new guidance in the first quarter of 2019. In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers” (“ASC 606”), which clarifies and converges the revenue recognition principles under GAAP and International Financial Reporting Standards. In July 2015, FASB delayed the effective date for one year. We have substantially completed evaluating all of our sources of revenue to determine the potential effect on our financial position, results of operations, cash flows and the related accounting policies and business processes. We will adopt this new guidance for our interim and annual reports beginning in the first quarter 2018, using the modified retrospective method. Through our preliminary evaluation, we do not expect a cumulative adjustment to our opening retained earnings, if any, would be material. The only impact we expect would be a reclassification of certain revenues that do not meet the requirements under ASC 606 as revenues from contracts with customers, but will continue to be reflected as other revenues in determining total revenue. The items we expect to reclassify relate primarily to the weather normalization mechanism in Kansas, where the KCC determines how we account for variations in weather. We have determined the majority of our tariffs to be contracts with customers which are settled over time, where our performance obligation is settled with our customer when natural gas is received and simultaneously consumed. In addition, we will elect to use the invoice method, where we will recognize revenue for volumes delivered for which we have a right to invoice. We will continue monitoring the accounting task forces and FASB for the final conclusions surrounding revenue recognition implementation guidance. This guidance will determine what will ultimately be disclosed in our financial statements and footnotes. In addition to updating our revenue recognition disclosures, additional disclosures may include disaggregation of revenues by types of service, source of revenue or customer class, performance obligations and other types of revenues. Until these items are resolved, we cannot complete our evaluation of the potential effect the new guidance will have on our financial position, results of operations, cash flows or business processes.

REGULATORY ASSETS AND LIABILITI

REGULATORY ASSETS AND LIABILITIES (Notes)	9 Months Ended
	Sep. 30, 2017
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
Schedule of Regulatory Assets and Liabilities	2. REGULATORY ASSETS AND LIABILITIES The tables below present a summary of regulatory assets, net of amortization, and liabilities for the periods indicated: September 30, 2017 Current Noncurrent Total ( Thousands of dollars ) Under-recovered purchased-gas costs $ 43,997 $ — $ 43,997 Pension and postemployment benefit costs 31,530 399,154 430,684 Weather normalization 19,618 — 19,618 Reacquired debt costs 812 7,500 8,312 Other 3,591 4,999 8,590 Total regulatory assets, net of amortization 99,548 411,653 511,201 Over-recovered purchased-gas costs (10,471 ) — (10,471 ) Ad valorem tax (356 ) — (356 ) Total regulatory liabilities (a) (10,827 ) — (10,827 ) Net regulatory assets (liabilities) $ 88,721 $ 411,653 $ 500,374 (a) Included in other current liabilities in our Balance Sheets. December 31, 2016 Current Noncurrent Total ( Thousands of dollars ) Under-recovered purchased-gas costs $ 29,901 $ — $ 29,901 Pension and postemployment benefit costs 31,498 427,448 458,946 Weather normalization 17,661 — 17,661 Reacquired debt costs 812 8,108 8,920 Other 3,274 4,966 8,240 Total regulatory assets, net of amortization 83,146 440,522 523,668 Over-recovered purchased-gas costs (10,154 ) — (10,154 ) Ad valorem tax (1,768 ) — (1,768 ) Total regulatory liabilities (a) (11,922 ) — (11,922 ) Net regulatory assets (liabilities) $ 71,224 $ 440,522 $ 511,746 (a) Included in other current liabilities in our Balance Sheets. Regulatory assets on our Balance Sheets, as authorized by various regulatory authorities, are probable of recovery. Base rates are designed to provide a recovery of costs during the period rates are in effect, but do not generally provide for a return on investment for amounts we have deferred as regulatory assets. All of our regulatory assets are subject to review by the respective regulatory authorities during future regulatory proceedings. We are not aware of any evidence that these costs will not be recoverable through either riders or base rates, and we believe that we will be able to recover such costs, consistent with our historical recoveries.

CREDIT FACILITIES (Notes)

CREDIT FACILITIES (Notes)	9 Months Ended
	Sep. 30, 2017
Short-term Debt [Line Items]
Short-term Debt [Text Block]	3. CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE In October 2017, we amended and restated our credit agreement. The ONE Gas Credit Agreement remains a $700.0 million revolving unsecured credit facility, and includes a $20.0 million letter of credit subfacility and a $60.0 million swingline subfacility. We will also be able to request an increase in commitments of up to an additional $500.0 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement expires in October 2022 , and is available to provide liquidity for working capital, capital expenditures, acquisitions and mergers, the issuance of letters of credit and for other general corporate purposes. The ONE Gas Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONE Gas’ total debt-to-capital ratio of no more than 70 percent at the end of any calendar quarter. At September 30, 2017 , our total debt-to-capital ratio was 41 percent and we were in compliance with all covenants under the ONE Gas Credit Agreement. We have a commercial paper program under which we may issue unsecured commercial paper up to a maximum amount of $700 million to fund short-term borrowing needs. The maturities of the commercial paper notes may vary but may not exceed 270 days from the date of issue. The commercial paper notes are generally sold at par less a discount representing an interest factor. The ONE Gas Credit Agreement is available to repay the commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowing capacity under the ONE Gas Credit Agreement. At September 30, 2017 , we had $174.0 million in short-term borrowings, $1.8 million in letters of credit issued under the ONE Gas Credit Agreement and $524.2 million of remaining credit available under the ONE Gas Credit Agreement.

LONG-TERM DEBT (Notes)

LONG-TERM DEBT (Notes)	9 Months Ended
	Sep. 30, 2017
Long-term Debt, Unclassified [Abstract]
Long-term Debt [Text Block]	4. LONG-TERM DEBT We have senior notes consisting of $300 million of 2.07 percent senior notes due in 2019 , $300 million of 3.61 percent senior notes due in 2024 and $600 million of 4.658 percent senior notes due in 2044 . The indenture governing our Senior Notes includes an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding Senior Notes to declare those Senior Notes immediately due and payable in full.

EQUITY (Notes)

EQUITY (Notes)	9 Months Ended
	Sep. 30, 2017
Class of Stock [Line Items]
Stockholders' Equity Note Disclosure [Text Block]	5. EQUITY In the first six months of 2017, we repurchased approximately 256 thousand shares of our common stock for approximately $17.5 million . We did not repurchase any shares of our common stock during the three months ended September 30, 2017 . In October 2017, we declared a dividend of $0.42 per share ( $1.68 per share on an annualized basis) for shareholders of record as of November 13, 2017, payable December 1, 2017.

ACCUMULATED OTHER COMPREHENSIVE

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Notes)	9 Months Ended
	Sep. 30, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Comprehensive Income (Loss) Note [Text Block]	6. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) The following table sets forth the effect of reclassifications from accumulated other comprehensive income (loss) in our Statements of Income for the periods indicated: Three Months Ended Nine Months Ended Details about Accumulated Other Comprehensive September 30, September 30, Affected Line Item in the Income (Loss) Components 2017 2016 2017 2016 Statements of Income ( Thousands of dollars ) Pension and other postemployment benefit plan obligations (a) Amortization of net loss $ 10,648 $ 10,040 $ 31,944 $ 30,113 Amortization of unrecognized prior service cost (1,149 ) (909 ) (3,447 ) (2,725 ) 9,499 9,131 28,497 27,388 Regulatory adjustments (b) (9,290 ) (8,943 ) (27,869 ) (26,824 ) 209 188 628 564 Income before income taxes (81 ) (72 ) (242 ) (217 ) Income tax expense Total reclassifications for the period $ 128 $ 116 $ 386 $ 347 Net income (a) These components of accumulated other comprehensive income (loss) are included in the computation of net periodic benefit cost. See Note 8 for additional detail of our net periodic benefit cost . (b) Regulatory adjustments represent pension and other postemployment benefit costs expected to be recovered through rates and are deferred as part of our regulatory assets. See Note 2 for additional disclosures of regulatory assets and liabilities.

EARNINGS PER SHARE (Notes)

EARNINGS PER SHARE (Notes)	9 Months Ended
	Sep. 30, 2017
EARNINGS PER SHARE [Line Items]
Earnings Per Share [Text Block]	7. EARNINGS PER SHARE Basic EPS is based on net income and is calculated based upon the daily weighted-average number of common shares outstanding during the periods presented. Also, this calculation includes fully vested stock awards that have not yet been issued as common stock. Diluted EPS includes basic EPS, plus unvested stock awards granted under our compensation plans, but only to the extent these instruments dilute earnings per share. The following tables set forth the computation of basic and diluted EPS from continuing operations for the periods indicated: Three Months Ended September 30, 2017 Income Shares Per Share Amount ( Thousands, except per share amounts ) Basic EPS Calculation Net income available for common stock $ 18,797 52,488 $ 0.36 Diluted EPS Calculation Effect of dilutive securities — 438 Net income available for common stock and common stock equivalents $ 18,797 52,926 $ 0.36 Three Months Ended September 30, 2016 Income Shares Per Share Amount ( Thousands, except per share amounts ) Basic EPS Calculation Net income available for common stock $ 12,737 52,453 $ 0.24 Diluted EPS Calculation Effect of dilutive securities — 489 Net income available for common stock and common stock equivalents $ 12,737 52,942 $ 0.24 Nine Months Ended September 30, 2017 Income Shares Per Share Amount ( Thousands, except per share amounts ) Basic EPS Calculation Net income available for common stock $ 115,876 52,539 $ 2.21 Diluted EPS Calculation Effect of dilutive securities — 445 Net income available for common stock and common stock equivalents $ 115,876 52,984 $ 2.19 Nine Months Ended September 30, 2016 Income Shares Per Share Amount ( Thousands, except per share amounts ) Basic EPS Calculation Net income available for common stock $ 97,781 52,452 $ 1.86 Diluted EPS Calculation Effect of dilutive securities — 510 Net income available for common stock and common stock equivalents $ 97,781 52,962 $ 1.85

EMPLOYEE BENEFIT PLANS (Notes)

EMPLOYEE BENEFIT PLANS (Notes)	9 Months Ended
	Sep. 30, 2017
Employee Benefit Plans [Line Items]
EMPLOYEE BENEFIT PLANS	8. EMPLOYEE BENEFIT PLANS In September 2017, we purchased group annuity contracts and transferred approximately $47 million of the assets and liabilities related to certain participants in our defined benefit pension plan to a third-party insurance company. The following tables set forth the components of net periodic benefit cost for our pension and other postemployment benefit plans for the periods indicated: Pension Benefits Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 ( Thousands of dollars ) Components of net periodic benefit cost Service cost $ 3,044 $ 3,014 $ 9,132 $ 9,042 Interest cost 10,113 11,387 30,339 34,162 Expected return on assets (14,624 ) (15,296 ) (43,872 ) (45,888 ) Amortization of net loss 9,027 8,886 27,081 26,657 Net periodic benefit cost $ 7,560 $ 7,991 $ 22,680 $ 23,973 Other Postemployment Benefits Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 ( Thousands of dollars ) Components of net periodic benefit cost Service cost $ 627 $ 637 $ 1,881 $ 1,913 Interest cost 2,472 2,626 7,416 7,880 Expected return on assets (3,147 ) (3,070 ) (9,441 ) (9,212 ) Amortization of unrecognized prior service cost (1,149 ) (909 ) (3,447 ) (2,725 ) Amortization of net loss 1,621 1,154 4,863 3,456 Net periodic benefit cost $ 424 $ 438 $ 1,272 $ 1,312 We recover qualified pension benefit plan and other postemployment benefit plan costs through rates charged to our customers. Certain regulatory authorities require that the recovery of these costs be based on specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as authorized by the applicable regulatory authorities. Regulatory deferrals related to net periodic benefit cost were not material for the three and nine months ended September 30, 2017 .

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Notes)	9 Months Ended
	Sep. 30, 2017
Commitments and Contingencies [Line Items]
COMMITMENTS AND CONTINGENCIES	9. COMMITMENTS AND CONTINGENCIES Environmental Matters - We are subject to multiple historical, wildlife preservation and environmental laws and/or regulations, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation, and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and nine months ended September 30, 2017 and 2016 . We own or retain legal responsibility for the environmental conditions at 12 former MGP sites in Kansas. These sites contain contaminants generally associated with MGP sites and are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE governs all work at these sites. The terms of the consent agreement require us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater. We have completed or addressed removal of the source of soil contamination at 11 of the 12 sites, and continue to monitor groundwater at eight of the 12 sites according to plans approved by the KDHE. Regulatory closure has been achieved at three of the 12 sites, but these sites remain subject to potential future requirements that may result in additional costs. During 2016, we completed a site assessment at the twelfth site where no active soil remediation has occurred. We have submitted a work plan to the KDHE for approval to address a source of contamination and associated contaminated soil on a portion of this site. We are also conducting a study of the feasibility of various options to address the remainder of the site. Costs associated with the remediation at this site are not expected to be material to our results of operations or financial position. With regard to one of our former MGP sites, periodic monitoring and a 2016 interim site investigation indicated elevated levels of contaminants generally associated with MGP sites. Additional testing and work plan development is underway in 2017 to determine a remediation work plan to present to the KDHE for approval, which could impact our estimates of the cost of remediation at this site. In the fourth quarter of 2016, we estimated the potential costs associated with additional investigation and remediation to be in the range of $4.0 million to $7.0 million . A single reliable estimate of the remediation costs was not feasible due to the amount of uncertainty in the ultimate remediation approach that will be utilized. Accordingly, we recorded a reserve of $4.0 million for this site in the fourth quarter of 2016. In April 2017, Kansas Gas Service filed an application with the KCC seeking approval of an AAO associated with the costs incurred at, and nearby, its 12 MGP sites. In October 2017, Kansas Gas Service, the KCC staff and the Citizens’ Utility Ratepayer Board filed a unanimous settlement agreement with the KCC. If approved, the agreement will allow Kansas Gas Service to defer MGP costs (costs that are necessary for investigation and remediation at the 12 former MGP sites) incurred after January 1, 2017, up to a cap of $15.0 million , net of any related insurance recoveries. Costs approved in a future rate proceeding would then be amortized over a 15-year period. The unamortized amounts will not be included in rate base or accumulate carrying charges. At the time future investigation and remediation work, net of any related insurance recoveries, is expected to exceed $15.0 million , Kansas Gas Service will be required to file an application with the KCC for approval to increase the $15.0 million cap. The KCC is expected to issue an order no later than early January 2018. If the agreement is approved, we expect to record a regulatory asset of approximately $5.9 million for estimated costs that have been accrued at January 1, 2017. Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and nine months ended September 30, 2017 and 2016 . A number of environmental issues may exist with respect to MGP sites that are unknown to us. Accordingly, future costs are dependent on the final determination and regulatory approval of any remedial actions, the complexity of the site, level of remediation required, changing technology and governmental regulations, and to the extent not recovered by insurance or recoverable in rates from our customers, could be material to our financial condition, results of operations or cash flows. With the trend toward stricter standards, greater regulation and more extensive permit requirements for the types of assets operated by us, our environmental expenditures could increase in the future, and such expenditures may not be fully recovered by insurance or recoverable in rates from our customers, and those costs may adversely affect our financial condition, results of operations and cash flows. We do not expect expenditures for these matters to have a material adverse effect on our financial condition, results of operations or cash flows. Pipeline Safety - We are subject to PHMSA regulations, including integrity-management regulations. PHMSA regulations require pipeline companies operating high-pressure transmission pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. In January 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act was signed into law. The law increased maximum penalties for violating federal pipeline safety regulations and directs the DOT and the Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us. These issues include, but are not limited to, the following: • an evaluation of whether natural gas pipeline integrity-management requirements should be expanded beyond current high-consequence areas; • a verification of records for pipelines in class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and • a requirement to test previously untested pipelines operating above 30 percent yield strength in high-consequence areas. In April 2016, PHMSA published a NPRM, the Safety of Gas Transmission & Gathering Lines Rule, in the Federal Register to revise pipeline safety regulations applicable to the safety of onshore natural gas transmission and gathering pipelines. Proposals include changes to pipeline integrity management requirements and other safety-related requirements. The NPRM comment period ended July 7, 2016, and comments are under review by PHMSA. As part of the comment review process, PHMSA is being advised by the Technical Pipeline Safety Standards Committee, informally known by PHMSA as the GPAC, a statutorily mandated advisory committee that advises PHMSA on proposed safety policies for natural gas pipelines. The GPAC reviews PHMSA's proposed regulatory initiatives to assure the technical feasibility, reasonableness, cost-effectiveness and practicality of each proposal. The potential capital and operating expenditures associated with compliance with the proposed rule are currently being evaluated and could be significant depending on the final regulations. Legal Proceedings - We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses from such matters, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not have a material adverse effect on our results of operations, financial position or cash flows.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS (Notes)	9 Months Ended
	Sep. 30, 2017
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Fair Value Disclosures	10. DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS Accounting Treatment - We record all derivative instruments at fair value, with the exception of normal purchases and normal sales that are expected to result in physical delivery. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it, or if regulatory rulings require a different accounting treatment. If certain conditions are met, we may elect to designate a derivative instrument as a hedge to mitigate the risk of exposure to changes in fair values or cash flows. The table below summarizes the various ways in which we account for our derivative instruments and the impact on our financial statements: Recognition and Measurement Accounting Treatment Balance Sheet Income Statement Normal purchases and normal sales - Recorded at historical cost - Change in fair value not recognized in earnings Mark-to-market - Recorded at fair value - Change in fair value recognized in, and recoverable through, the purchased-gas cost adjustment mechanisms We have not elected to designate any of our derivative instruments as hedges. Premiums paid and any cash settlements received associated with the commodity derivative instruments entered into by us are included in, and recoverable through, the purchased-gas cost adjustment mechanisms. Determining Fair Value - We define fair value as the price that would be received from the sale of an asset or the transfer of a liability in an orderly transaction between market participants at the measurement date. We use the market and income approaches to determine the fair value of our assets and liabilities and consider the markets in which the transactions are executed. We measure the fair value of a group of financial assets and liabilities consistent with how a market participant would price the net risk exposure at the measurement date. Fair Value Hierarchy - At each balance sheet date, we utilize a fair value hierarchy to classify fair value amounts recognized or disclosed in our financial statements based on the observability of inputs used to estimate such fair value. The levels of the hierarchy are described below: • Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities; • Level 2 - Significant observable pricing inputs other than quoted prices included within Level 1 that are, either directly or indirectly, observable as of the reporting date. Essentially, this represents inputs that are derived principally from or corroborated by observable market data; and • Level 3 - May include one or more unobservable inputs that are significant in establishing a fair value estimate. These unobservable inputs are developed based on the best information available and may include our own internal data. We recognize transfers into and out of the levels as of the end of each reporting period. Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data. We categorize derivatives for which fair value is determined using multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety. Derivative Instruments - At September 30, 2017 , we held purchased natural gas call options for the heating season ending March 31, 2018, with total notional amounts of 33.5 Bcf, for which we paid premiums of $10.9 million , and had a fair value of $6.9 million . At December 31, 2016 , we held purchased natural gas call options for the heating season ended March 31, 2017, with total notional amounts of 14.3 Bcf, for which we paid premiums of $5.4 million , and had a fair value of $6.5 million . The premiums paid and any cash settlements received are recorded as part of our unrecovered purchased-gas costs in current regulatory assets as these contracts are included in, and recoverable through, the purchased-gas cost adjustment mechanisms. Additionally, changes in fair value associated with these contracts are deferred as part of our unrecovered purchased-gas costs in our Balance Sheets. Our natural gas call options are classified as Level 1 as fair value amounts are based on unadjusted quoted prices in active markets including NYMEX-settled prices. There were no transfers between levels for the three and nine months ended September 30, 2017 and 2016 . Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable and accounts payable is equal to book value, due to the short-term nature of these items. Our cash and cash equivalents are comprised of bank and money market accounts, and are classified as Level 1. Short-term notes payable and commercial paper are due upon demand and, therefore, the carrying amounts approximate fair value and are classified as Level 1. The book value of our long-term debt, including current maturities, was $1.2 billion at both September 30, 2017 and December 31, 2016 . The estimated fair value of our long-term debt, including current maturities, was $1.3 billion and $1.2 billion at September 30, 2017 and December 31, 2016 , respectively. The estimated fair value of our Senior Notes at September 30, 2017 and December 31, 2016 , was determined using quoted market prices, and are classified as Level 2.

SUMMARY OF SIGNIFICANT ACCOUN19

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	9 Months Ended
	Sep. 30, 2017
Significant Accounting Policies [Line Items]
Use of Estimates	Use of Estimates - The preparation of our financial statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, provision for doubtful accounts, unbilled revenues for natural gas delivered but for which meters have not been read, natural gas purchased but for which no invoice has been received, provision for income taxes, including any deferred tax valuation allowances, the results of litigation and various other recorded or disclosed amounts. We evaluate these estimates on an ongoing basis using historical experience and other methods we consider reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on our financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known.
Segments	Segments - We operate in one reportable and operating business segment: regulated public utilities that deliver natural gas to residential, commercial, industrial, wholesale, public authority and transportation customers. The accounting policies for our segment are the same as described in Note 1 of our Notes to the Financial Statements in our Annual Report. We evaluate our financial performance principally on operating income. For the three and nine months ended September 30, 2017 , and 2016 , we had no single external customer from which we received 10 percent or more of our gross revenues.
Recently Issued Accounting Standards Update	Recently Issued Accounting Standards Update - In August 2017, the FASB issued ASU 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities,” which allows more types of hedging strategies to be eligible for hedge accounting and simplifies application of hedge accounting. This new guidance is required for our interim and annual reports for periods beginning after December 15, 2018, and early adoption is permitted, but must be applied as of the beginning of the fiscal year, or initial application date. The impact of this guidance is not material to us, as we have not elected hedge accounting due to the nature of the types of derivatives we have entered. In March 2017, the FASB issued ASU 2017-07, “Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost,” which requires (1) separation of net periodic service costs for pension and other postemployment benefits into service cost and other components, (2) presentation of the service cost component in the same line as other compensation costs rendered by pertinent employees during the period, and (3) reporting the other components of net periodic benefit costs separately from the service cost component and outside a subtotal of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all of our cost components remain eligible for capitalization under the accounting requirements for rate regulated entities. We will adopt this guidance for our interim and annual reports for periods in the first quarter of 2018. When adopted, the presentation changes required for net periodic benefit costs will not impact previously reported net income; however, the reclassification of the other components of benefits costs will result in an increase in operating income and an increase in other expenses for 2016 and 2017. We will use the retroactive presentation that permits the use of the amounts disclosed for the various components of net benefit cost in our respective Annual Report’s Employee Benefit Plans footnote as the basis for the retrospective application. In addition, we are currently updating our systems for the capitalization of service costs to property and non-service costs to a regulatory asset on a prospective basis, as well as the appropriate accounts for non-service costs to apply retroactive reclassification. In January 2017, the FASB issued ASU 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment,” which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 of the goodwill test, where the measurement of a goodwill impairment loss was determined by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Upon adoption, a goodwill impairment will be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. We early adopted this new guidance in the current quarter, and it did not have an impact on our financial statements. See our conclusions regarding our current year Goodwill Impairment Test above. In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses: Measurement of Credit Losses on Financial Instruments,’’ which introduces new guidance to the accounting for credit losses on instruments within its scope, including trade receivables. It is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and may be adopted a year earlier. The new guidance will be initially applied through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. We are currently assessing the timing and impacts of adopting this standard, which must be adopted by the first quarter of 2021. In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting,” which includes various new aspects to simplify how share-based payments are accounted for and presented in the financial statements. The new standard modifies several aspects of the accounting and reporting for employee share-based payments and related tax accounting impacts, including the presentation in the statements of operations and cash flows. We adopted this new guidance in the first quarter 2017, and in accordance with the transition requirements, we recorded $5.2 million of excess tax benefit in income tax expense and have transitioned all provisions of this new guidance prospectively, other than our presentation of our withholding shares for tax-withholding purposes, which we accounted for retrospectively in the financing activities section of the statement of cash flows. We recorded a noncash cumulative-effect increase of $11.0 million to retained earnings, with an offset to a deferred tax asset, as of the beginning of the reporting period in 2017, for excess tax benefits earned prior to January 1, 2017, that had not been recognized. We continue our use of the estimation method to account for share unit award forfeitures rather than actual forfeitures. The retrospective impact of our withholding shares for tax-withholding purposes to our Statement of Cash Flows for the nine months ended September 30, 2016 , was a $9.0 million increase to net cash provided by operating activities and a $9.0 million decrease to net cash used in financing activities. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” which prescribes recognizing lease assets and liabilities on the balance sheet and includes disclosure of key information about leasing arrangements. A modified retrospective transition approach is required for leases existing at the time of adoption. We are evaluating our population of leases, analyzing lease agreements, and holding meetings with cross-functional teams to determine the potential impact of this accounting standard on our financial position and results of operations and the transition approach we will utilize. We are also continuing to monitor the FASB for additional guidance surrounding an exposure draft regarding land easements. This information will help us determine what information will ultimately be disclosed in our financial statements and footnotes. Until this item is resolved, we cannot complete our evaluation of the potential effect the new guidance will have on our financial position, results of operations, cash flows or business processes. We will adopt this new guidance in the first quarter of 2019. In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers” (“ASC 606”), which clarifies and converges the revenue recognition principles under GAAP and International Financial Reporting Standards. In July 2015, FASB delayed the effective date for one year. We have substantially completed evaluating all of our sources of revenue to determine the potential effect on our financial position, results of operations, cash flows and the related accounting policies and business processes. We will adopt this new guidance for our interim and annual reports beginning in the first quarter 2018, using the modified retrospective method. Through our preliminary evaluation, we do not expect a cumulative adjustment to our opening retained earnings, if any, would be material. The only impact we expect would be a reclassification of certain revenues that do not meet the requirements under ASC 606 as revenues from contracts with customers, but will continue to be reflected as other revenues in determining total revenue. The items we expect to reclassify relate primarily to the weather normalization mechanism in Kansas, where the KCC determines how we account for variations in weather. We have determined the majority of our tariffs to be contracts with customers which are settled over time, where our performance obligation is settled with our customer when natural gas is received and simultaneously consumed. In addition, we will elect to use the invoice method, where we will recognize revenue for volumes delivered for which we have a right to invoice. We will continue monitoring the accounting task forces and FASB for the final conclusions surrounding revenue recognition implementation guidance. This guidance will determine what will ultimately be disclosed in our financial statements and footnotes. In addition to updating our revenue recognition disclosures, additional disclosures may include disaggregation of revenues by types of service, source of revenue or customer class, performance obligations and other types of revenues. Until these items are resolved, we cannot complete our evaluation of the potential effect the new guidance will have on our financial position, results of operations, cash flows or business processes.

DERIVATIVE FINANCIAL INSTRUME20

DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS (Policies)	9 Months Ended
	Sep. 30, 2017
Derivatives and Fair Value Measurement [Abstract]
Derivatives	Accounting Treatment - We record all derivative instruments at fair value, with the exception of normal purchases and normal sales that are expected to result in physical delivery. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it, or if regulatory rulings require a different accounting treatment. If certain conditions are met, we may elect to designate a derivative instrument as a hedge to mitigate the risk of exposure to changes in fair values or cash flows. The table below summarizes the various ways in which we account for our derivative instruments and the impact on our financial statements: Recognition and Measurement Accounting Treatment Balance Sheet Income Statement Normal purchases and normal sales - Recorded at historical cost - Change in fair value not recognized in earnings Mark-to-market - Recorded at fair value - Change in fair value recognized in, and recoverable through, the purchased-gas cost adjustment mechanisms We have not elected to designate any of our derivative instruments as hedges. Premiums paid and any cash settlements received associated with the commodity derivative instruments entered into by us are included in, and recoverable through, the purchased-gas cost adjustment mechanisms.
Fair Value Measurement	Determining Fair Value - We define fair value as the price that would be received from the sale of an asset or the transfer of a liability in an orderly transaction between market participants at the measurement date. We use the market and income approaches to determine the fair value of our assets and liabilities and consider the markets in which the transactions are executed. We measure the fair value of a group of financial assets and liabilities consistent with how a market participant would price the net risk exposure at the measurement date. Fair Value Hierarchy - At each balance sheet date, we utilize a fair value hierarchy to classify fair value amounts recognized or disclosed in our financial statements based on the observability of inputs used to estimate such fair value. The levels of the hierarchy are described below: • Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities; • Level 2 - Significant observable pricing inputs other than quoted prices included within Level 1 that are, either directly or indirectly, observable as of the reporting date. Essentially, this represents inputs that are derived principally from or corroborated by observable market data; and • Level 3 - May include one or more unobservable inputs that are significant in establishing a fair value estimate. These unobservable inputs are developed based on the best information available and may include our own internal data. We recognize transfers into and out of the levels as of the end of each reporting period. Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data. We categorize derivatives for which fair value is determined using multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety.

REGULATORY ASSETS AND LIABILI21

REGULATORY ASSETS AND LIABILITIES (Tables)	9 Months Ended
	Sep. 30, 2017
SCHEDULE OF REGULATED ASSETS AND LIABILITIES [Line Items]
SCHEDULE OF REGULATED ASSETS AND LIABILITIES	The tables below present a summary of regulatory assets, net of amortization, and liabilities for the periods indicated: September 30, 2017 Current Noncurrent Total ( Thousands of dollars ) Under-recovered purchased-gas costs $ 43,997 $ — $ 43,997 Pension and postemployment benefit costs 31,530 399,154 430,684 Weather normalization 19,618 — 19,618 Reacquired debt costs 812 7,500 8,312 Other 3,591 4,999 8,590 Total regulatory assets, net of amortization 99,548 411,653 511,201 Over-recovered purchased-gas costs (10,471 ) — (10,471 ) Ad valorem tax (356 ) — (356 ) Total regulatory liabilities (a) (10,827 ) — (10,827 ) Net regulatory assets (liabilities) $ 88,721 $ 411,653 $ 500,374 (a) Included in other current liabilities in our Balance Sheets. December 31, 2016 Current Noncurrent Total ( Thousands of dollars ) Under-recovered purchased-gas costs $ 29,901 $ — $ 29,901 Pension and postemployment benefit costs 31,498 427,448 458,946 Weather normalization 17,661 — 17,661 Reacquired debt costs 812 8,108 8,920 Other 3,274 4,966 8,240 Total regulatory assets, net of amortization 83,146 440,522 523,668 Over-recovered purchased-gas costs (10,154 ) — (10,154 ) Ad valorem tax (1,768 ) — (1,768 ) Total regulatory liabilities (a) (11,922 ) — (11,922 ) Net regulatory assets (liabilities) $ 71,224 $ 440,522 $ 511,746

ACCUMULATED OTHER COMPREHENSI22

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)	9 Months Ended
	Sep. 30, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	The following table sets forth the effect of reclassifications from accumulated other comprehensive income (loss) in our Statements of Income for the periods indicated: Three Months Ended Nine Months Ended Details about Accumulated Other Comprehensive September 30, September 30, Affected Line Item in the Income (Loss) Components 2017 2016 2017 2016 Statements of Income ( Thousands of dollars ) Pension and other postemployment benefit plan obligations (a) Amortization of net loss $ 10,648 $ 10,040 $ 31,944 $ 30,113 Amortization of unrecognized prior service cost (1,149 ) (909 ) (3,447 ) (2,725 ) 9,499 9,131 28,497 27,388 Regulatory adjustments (b) (9,290 ) (8,943 ) (27,869 ) (26,824 ) 209 188 628 564 Income before income taxes (81 ) (72 ) (242 ) (217 ) Income tax expense Total reclassifications for the period $ 128 $ 116 $ 386 $ 347 Net income (a) These components of accumulated other comprehensive income (loss) are included in the computation of net periodic benefit cost. See Note 8 for additional detail of our net periodic benefit cost . (b) Regulatory adjustments represent pension and other postemployment benefit costs expected to be recovered through rates and are deferred as part of our regulatory assets. See Note 2 for additional disclosures of regulatory assets and liabilities.

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	9 Months Ended
	Sep. 30, 2017
EARNINGS PER SHARE [Line Items]
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	The following tables set forth the computation of basic and diluted EPS from continuing operations for the periods indicated: Three Months Ended September 30, 2017 Income Shares Per Share Amount ( Thousands, except per share amounts ) Basic EPS Calculation Net income available for common stock $ 18,797 52,488 $ 0.36 Diluted EPS Calculation Effect of dilutive securities — 438 Net income available for common stock and common stock equivalents $ 18,797 52,926 $ 0.36 Three Months Ended September 30, 2016 Income Shares Per Share Amount ( Thousands, except per share amounts ) Basic EPS Calculation Net income available for common stock $ 12,737 52,453 $ 0.24 Diluted EPS Calculation Effect of dilutive securities — 489 Net income available for common stock and common stock equivalents $ 12,737 52,942 $ 0.24 Nine Months Ended September 30, 2017 Income Shares Per Share Amount ( Thousands, except per share amounts ) Basic EPS Calculation Net income available for common stock $ 115,876 52,539 $ 2.21 Diluted EPS Calculation Effect of dilutive securities — 445 Net income available for common stock and common stock equivalents $ 115,876 52,984 $ 2.19 Nine Months Ended September 30, 2016 Income Shares Per Share Amount ( Thousands, except per share amounts ) Basic EPS Calculation Net income available for common stock $ 97,781 52,452 $ 1.86 Diluted EPS Calculation Effect of dilutive securities — 510 Net income available for common stock and common stock equivalents $ 97,781 52,962 $ 1.85

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	9 Months Ended
	Sep. 30, 2017
Employee Benefit Plans [Line Items]
Schedule of Net Benefit Costs [Table Text Block]	The following tables set forth the components of net periodic benefit cost for our pension and other postemployment benefit plans for the periods indicated: Pension Benefits Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 ( Thousands of dollars ) Components of net periodic benefit cost Service cost $ 3,044 $ 3,014 $ 9,132 $ 9,042 Interest cost 10,113 11,387 30,339 34,162 Expected return on assets (14,624 ) (15,296 ) (43,872 ) (45,888 ) Amortization of net loss 9,027 8,886 27,081 26,657 Net periodic benefit cost $ 7,560 $ 7,991 $ 22,680 $ 23,973 Other Postemployment Benefits Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 ( Thousands of dollars ) Components of net periodic benefit cost Service cost $ 627 $ 637 $ 1,881 $ 1,913 Interest cost 2,472 2,626 7,416 7,880 Expected return on assets (3,147 ) (3,070 ) (9,441 ) (9,212 ) Amortization of unrecognized prior service cost (1,149 ) (909 ) (3,447 ) (2,725 ) Amortization of net loss 1,621 1,154 4,863 3,456 Net periodic benefit cost $ 424 $ 438 $ 1,272 $ 1,312

SUMMARY OF SIGNIFICANT ACCOUN25

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) number in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017USD ($)	Sep. 30, 2016
Significant Accounting Policies [Line Items]
Number of natural gas distribution services customers	2		2
Segment Reporting, Disclosure of Major Customers	0	0	0	0
Excess tax benefit related to the share-based compensation provision			$ 5.2
Operating loss carryforward related to the share-based compensation provision			11
Prior period cash flow reclass related to the share-based compensation provision			$ 9

REGULATORY ASSETS AND LIABILI26

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

CREDIT FACILITIES (Details)

CREDIT FACILITIES (Details) $ in Millions	Sep. 30, 2017USD ($)
Short-term Debt [Line Items]
Line of Credit Facility Sublimit	$ 20
Line of Credit Facility Swingline Subfacility	60
Line of Credit Facility Option to Increase Borrowing Capacity	$ 500
Ratio of Indebtedness to Net Capital	0.41
Commercial paper maximum borrowing capacity	$ 700
Short-term Debt	174
Letters of Credit Outstanding, Amount	1.8
Line of Credit Facility, Remaining Borrowing Capacity	$ 524.2

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)
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%

EQUITY (Details)

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

ACCUMULATED OTHER COMPREHENSI30

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

EARNINGS PER SHARE (Details)

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

EMPLOYEE BENEFIT PLANS (Details

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

COMMITMENTS AND CONTINGENCIES33

COMMITMENTS AND CONTINGENCIES (Details) $ in Millions	3 Months Ended	9 Months Ended
	Dec. 31, 2017USD ($)	Sep. 30, 2017
Commitments and Contingencies [Line Items]
Number Of Former Manufactured Gas Sites Where We Own Or Retain Legal Responsibility For Environmental Conditions		12
Number of sites where we have completed or addressed removal of the source of soil contamination according to plans approved by KDHE.		11
Number of sites with ongoing groundwater monitoring		8
Number of sites where regulatory closure has been achieved		3
Environmental Reserve Estimate Range, Low		4
Environmental Reserve Estimate Range, High		7
Environmental Reserve Estimate, Actual		4
Percentage yield of high consequence pipeline areas		30.00%
Subsequent Event [Member]
Commitments and Contingencies [Line Items]
AAO associated with MGP costs requested amount, cap	$ 15
Regulatory asset expected to be recorded for MGP costs accrued at January 1, 2017	$ 5.9

DERIVATIVE FINANCIAL INSTRUME34

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