ONE Gas, Inc. - Quarter Report: 2018 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2018.

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

For the transition period from __________ to __________.

Commission file number 001-36108

ONE Gas, Inc.

(Exact name of registrant as specified in its charter)



Oklahoma	46-3561936
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

15 East Fifth Street, Tulsa, OK	74103
(Address of principal executive offices)	(Zip Code)

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes X No __

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



Large accelerated filer X	Accelerated filer __

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

	Smaller reporting company__

	Emerging growth company__

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes __ No X

On July 24, 2018, the Company had 52,517,758 shares of common stock outstanding.

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ONE Gas, Inc.

TABLE OF CONTENTS



Part I.	Financial Information	Page No.
Item 1.	Consolidated Financial Statements (Unaudited)	6
	Consolidated Statements of Income - Three and Six Months Ended June 30, 2018 and 2017	6
	Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2018 and 2017	7
	Consolidated Balance Sheets - June 30, 2018 and December 31, 2017	8
	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2018 and 2017	11
	Consolidated Statement of Equity - Six Months Ended June 30, 2018	12
	Notes to the Consolidated Financial Statements	14
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	41
Part II.	Other Information	42
Item 1.	Legal Proceedings	42
Item 1A.	Risk Factors	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 3.	Defaults Upon Senior Securities	42
Item 4.	Mine Safety Disclosures	42
Item 5.	Other Information	42
Item 6.	Exhibits	42
Signature		44

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

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

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 use Twitter®, LinkedIn® and Facebook® as additional channels of distribution to reach public investors. Information contained on our website, posted on our Facebook® page or disseminated through Twitter® or LinkedIn®, and any corresponding applications, 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.

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



AAO	Accounting Authority Order
ADIT	Accumulated deferred income tax
Annual Report	Annual Report on Form 10-K for the year ended December 31, 2017
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
Code	Internal Revenue Code of 1986, as amended
COSA	Cost-of-Service Adjustment
DOT	United States Department of Transportation
EPA	United States Environmental Protection Agency
EPS	Earnings per share
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
GAAP	Accounting principles generally accepted in the United States of America
GPAC	Gas Pipeline Advisory Committee
GRIP	Texas Gas Reliability Infrastructure Program
GSRS	Kansas Gas System Reliability Surcharge
Heating Degree Day or HDD	A measure designed to reflect the demand for energy needed for heating based on the extent to which the daily average temperature falls below a reference temperature for which no heating is required, usually 65 degrees Fahrenheit
KCC	Kansas Corporation Commission
KDHE	Kansas Department of Health and Environment
LDC	Local distribution company
MGP	Manufactured Gas Plant
MMcf	Million cubic feet
Moody’s	Moody’s Investors Service, Inc.
NOL	Net operating loss
NPRM	Notice of Proposed Rulemaking
NYMEX	New York Mercantile Exchange
OCC	Oklahoma Corporation Commission
ONE Gas	ONE Gas, Inc.
ONE Gas Credit Agreement	ONE Gas’ $700 million amended and restated revolving credit agreement, which expires on October 5, 2022
ONEOK	ONEOK, Inc. and its subsidiaries
PBRC	Performance-Based Rate Change
PHMSA	United States Department of Transportation Pipeline and Hazardous Materials Safety Administration
Pipeline Safety, Regulatory Certainty and Job Creation Act	Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, as amended
Quarterly Report(s)	Quarterly Report(s) on Form 10-Q
RRC	Railroad Commission of Texas
S&P	Standard & Poor’s Ratings Services
SAB	Staff Accounting Bulletin
SEC	Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
Senior Notes	ONE Gas’ registered notes consisting of $300 million of 2.07 percent senior notes due 2019, $300 million of 3.61 percent senior notes due 2024 and $600 million of 4.658 percent notes due 2044
Separation and Distribution Agreement	Separation and Distribution Agreement dated January 14, 2014, between ONEOK and ONE Gas
WNA	Weather-normalization adjustments
XBRL	eXtensible Business Reporting Language

PART I - FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS



ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF INCOME
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(Unaudited)	2018			2017			2018			2017
	(Thousands of dollars, except per share amounts)
Revenues
Revenues from contracts with customers	$	291,168		$	274,033		$	926,405		$	810,193
Other revenues	1,353			5,656			4,580			19,904
Total revenues	292,521			279,689			930,985			830,097
Cost of natural gas	94,159			82,572			444,578			345,726
Net margin	198,362			197,117			486,407			484,371

Operating expenses
Operations and maintenance	102,995			96,928			205,660			201,972
Depreciation and amortization	39,757			37,851			78,647			74,870
General taxes	14,567			13,973			30,767			29,719
Total operating expenses	157,319			148,752			315,074			306,561
Operating income	41,043			48,365			171,333			177,810
Other expense, net	(2,194		)	(3,900		)	(4,358		)	(7,307		)
Interest expense, net	(12,003		)	(11,305		)	(24,355		)	(22,786		)
Income before income taxes	26,846			33,160			142,620			147,717
Income taxes	(6,427		)	(12,537		)	(31,366		)	(50,638		)
Net income	$	20,419		$	20,623		$	111,254		$	97,079

Earnings per share
Basic	$	0.39		$	0.39		$	2.11		$	1.85
Diluted	$	0.39		$	0.39		$	2.10		$	1.83

Average shares (thousands)
Basic	52,692			52,553			52,648			52,565
Diluted	52,899			52,969			52,898			53,012
Dividends declared per share of stock	$	0.46		$	0.42		$	0.92		$	0.84

See accompanying Notes to Consolidated Financial Statements.



ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(Unaudited)	2018		2017		2018		2017
	(Thousands of dollars)
Net income	$	20,419	$	20,623	$	111,254	$	97,079
Other comprehensive income (loss), net of tax
Change in pension and other postemployment benefit plan liability, net of tax of $(68), $(81), $(419) and $(161), respectively	203		129		123		258
Total other comprehensive income (loss), net of tax	203		129		123		258
Comprehensive income	$	20,622	$	20,752	$	111,377	$	97,337

See accompanying Notes to Consolidated Financial Statements.



ONE Gas, Inc.
CONSOLIDATED BALANCE SHEETS

	June 30,		December 31,
(Unaudited)	2018		2017
Assets	(Thousands of dollars)
Property, plant and equipment
Property, plant and equipment	$	5,870,814	$	5,713,912
Accumulated depreciation and amortization	1,745,124		1,706,327
Net property, plant and equipment	4,125,690		4,007,585
Current assets
Cash and cash equivalents	12,580		14,413
Accounts receivable, net	163,967		298,768
Materials and supplies	36,124		39,672
Natural gas in storage	80,482		130,154
Regulatory assets	39,402		88,180
Other current assets	18,154		17,807
Total current assets	350,709		588,994
Goodwill and other assets
Regulatory assets	385,564		405,189
Goodwill	157,953		157,953
Other assets	48,003		47,157
Total goodwill and other assets	591,520		610,299
Total assets	$	5,067,919	$	5,206,878

See accompanying Notes to Consolidated Financial Statements.



ONE Gas, Inc.
CONSOLIDATED BALANCE SHEETS
(Continued)
	June 30,			December 31,
(Unaudited)	2018			2017
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 52,516,828 shares at June 30, 2018; issued 52,598,005 and outstanding 52,312,516 shares at December 31, 2017	$	526		$	526
Paid-in capital	1,723,795			1,737,551
Retained earnings	308,652			246,121
Accumulated other comprehensive income (loss)	(5,370		)	(5,493		)
Treasury stock, at cost: 81,177 shares at June 30, 2018 and 285,489 shares at December 31, 2017	(5,259		)	(18,496		)
Total equity	2,022,344			1,960,209
Long-term debt, excluding current maturities, and net of issuance costs of $7,614 and $8,033, respectively	893,671			1,193,257
Total equity and long-term debt	2,916,015			3,153,466
Current liabilities
Current maturities of long-term debt	300,008			8
Notes payable	185,000			357,215
Accounts payable	70,429			143,681
Accrued interest	19,028			18,776
Accrued taxes other than income	34,931			41,324
Accrued liabilities	20,724			30,058
Regulatory liabilities	47,867			9,438
Customer deposits	61,249			60,811
Other current liabilities	10,102			12,019
Total current liabilities	749,338			673,330
Deferred credits and other liabilities
Deferred income taxes	628,532			599,945
Regulatory liabilities	521,717			519,421
Employee benefit obligations	160,382			172,938
Other deferred credits	91,935			87,778
Total deferred credits and other liabilities	1,402,566			1,380,082
Commitments and contingencies
Total liabilities and equity	$	5,067,919		$	5,206,878

See accompanying Notes to Consolidated Financial Statements.

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ONE Gas, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Six Months Ended
	June 30,
(Unaudited)	2018			2017
	(Thousands of dollars)
Operating activities
Net income	$	111,254		$	97,079
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	78,647			74,870
Deferred income taxes	30,546			50,308
Share-based compensation expense	4,080			4,951
Provision for doubtful accounts	4,071			3,501
Changes in assets and liabilities:
Accounts receivable	130,730			135,165
Materials and supplies	3,548			(2,792		)
Natural gas in storage	49,672			10,436
Asset removal costs	(25,774		)	(22,837		)
Accounts payable	(68,428		)	(68,992		)
Accrued interest	252			104
Accrued taxes other than income	(6,393		)	(9,009		)
Accrued liabilities	(9,334		)	(6,729		)
Customer deposits	438			(686		)
Regulatory assets and liabilities	105,967			19,782
Other assets and liabilities	(9,319		)	(5,880		)
Cash provided by operating activities	399,957			279,271
Investing activities
Capital expenditures	(175,834		)	(154,666		)
Other	—			477
Cash used in investing activities	(175,834		)	(154,189		)
Financing activities
Repayments of notes payable, net	(172,215		)	(66,000		)
Repurchase of common stock	—			(17,512		)
Issuance of common stock	2,390			2,208
Dividends paid	(48,272		)	(44,042		)
Tax withholdings related to net share settlements of stock compensation	(7,859		)	(9,286		)
Cash used in financing activities	(225,956		)	(134,632		)
Change in cash and cash equivalents	(1,833		)	(9,550		)
Cash and cash equivalents at beginning of period	14,413			14,663
Cash and cash equivalents at end of period	$	12,580		$	5,113

See accompanying Notes to Consolidated Financial Statements.



ONE Gas, Inc.
CONSOLIDATED STATEMENT OF EQUITY

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

January 1, 2018	52,598,005	$	526	$	1,737,551
Net income	—	—		—
Other comprehensive income	—	—		—
Common stock issued and other	—	—		(14,207		)
Common stock dividends - $0.92 per share	—	—		451
June 30, 2018	52,598,005	$	526	$	1,723,795

See accompanying Notes to Consolidated Financial Statements.



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

January 1, 2018	$	246,121		$	(18,496	)	$	(5,493	)	$	1,960,209
Net income	111,254			—			—			111,254
Other comprehensive income	—			—			123			123
Common stock issued and other	—			13,237			—			(970		)
Common stock dividends - $0.92 per share	(48,723		)	—			—			(48,272		)
June 30, 2018	$	308,652		$	(5,259	)	$	(5,370	)	$	2,022,344

See accompanying Notes to Consolidated Financial Statements.

ONE Gas, Inc.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS


1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our accompanying unaudited consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. These statements also have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair statement of the results for the interim periods presented. All such adjustments are of a normal recurring nature. The 2017 year-end consolidated balance sheet data was derived from audited consolidated financial statements, but does not include all disclosures required by GAAP. These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and footnotes in our Annual Report. Our significant accounting policies are described in Note 1 of our Notes to the Consolidated Financial Statements in our Annual Report. Due to the seasonal nature of our business, the results of operations for the three and six months ended June 30, 2018, 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. In 2017, we formed a wholly-owned captive insurance company in the state of Oklahoma to provide insurance to our divisions.

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

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 those described in Note 1 of our Notes to the Consolidated Financial Statements in our Annual Report. We evaluate our financial performance principally on operating income. For the three and six months ended June 30, 2018, and 2017, we had no single external customer from which we received 10 percent or more of our gross revenues.

Recently Issued Accounting Standards Update - In March 2018, the FASB issued ASU 2018-05, “Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118,” which updates the FASB’s Accounting Standards Codification to reflect the guidance in SAB 118, which adds Section EE, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act,” to SAB Topic 5, “Miscellaneous Accounting.” SAB 118 also provides guidance on applying ASC 740, Income Taxes, if the accounting for certain income tax effects of the Tax Cuts and Jobs Act of 2017 is incomplete when the financial statements are issued for a reporting period. See Note 10 for additional discussion regarding SAB 118.

In February 2018, the FASB issued ASU 2018-02, “Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income,” which allows a reclassification from accumulated other comprehensive income (loss) to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The new guidance is required for our interim and annual reports for periods beginning after December 15, 2018, and early adoption is permitted. We are currently assessing the timing and impacts of adopting this standard, but do not expect a material impact to our consolidated financial statements.

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

We adopted this guidance in the first quarter of 2018. The presentation changes required for net periodic benefit costs did not impact previously reported net income; however, the reclassification of the other components of benefits costs resulted in an increase in operating income and an increase in other expenses of $2.4 million and $4.3 million for the three months ended June 30, 2018 and 2017, respectively, and an increase in operating income and other expenses of $4.1 million and $8.6 million for the six months ended June 30, 2018 and 2017, respectively. We elected the practical expedient to use the retroactive presentation of the amounts disclosed for the various components of net benefit cost in our Employee Benefit Plans footnote as the basis for the retrospective application. In addition, we updated our information 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 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 early adoption is permitted for fiscal years beginning after December 15, 2018. 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 2020.

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. The FASB has issued multiple practical expedients that may be elected, but must be elected as a package and applied consistently to all leases. These practical expedients allow lessees and lessors to (1) not reassess expired or existing contracts to determine whether they are subject to lease accounting guidance, (2) not reconsider lease classification at transition, and (3) not evaluate previously capitalized initial direct costs under the revised requirements. The FASB has also issued several practical expedients that may be elected separately or in conjunction with the previously mentioned practical expedients. These practical expedients allow (1) lessees to not separate nonlease components from lease components and instead account for each separate lease component and the nonlease components associated with that lease component as a single lease component and (2) lessees and lessors to use hindsight in determining the lease term and in assessing impairment of the entity’s right-of-use assets. These expedients are only for leases in place at the transition date and cannot be applied to leases that are modified. At this time, we are evaluating these expedients.

In January 2018, the FASB issued ASU 2018-01, “Leases (Topic 842),” as an amendment to ASU 2016-02, “Leases (Topic 842)” to address stakeholder concerns about the costs and complexity of complying with the transition provisions of the new lease requirements to provide an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current lease guidance in Topic 840. We plan to utilize the provided practical expedient for existing and expired land easements and will assess all new or modified land easement and right-of-way agreements, under the guidance of ASU 2016-02, following its adoption.

In July 2018, the FASB issued ASU 2018-11, “Leases (Topic 842),” as an amendment to ASU 2016-02, “Leases (Topic 842) Targeted Improvements” which provides entities with an additional transition method in which an entity initially applies the new leases standard at the adoption date and recognizes a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The amendment also provides a practical expedient for lessors. At this time, we are evaluating these expedients.

We are continuing to evaluate our population of leases, analyze lease agreements, and hold 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. While we are currently evaluating the full impact of the standard, we expect to recognize additional assets and liabilities arising from current operating leases to our financial position upon adoption. 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. We have evaluated all of our sources of revenue to determine the effect on our financial position, results of operations, cash flows and the related accounting policies and business processes. We adopted this new guidance in the first quarter 2018, using the modified

retrospective method. Our adoption did not result in a cumulative adjustment to our opening retained earnings. Our adoption resulted in a reclassification of certain revenues associated with certain regulatory mechanisms that do not meet the requirements under ASC 606 as revenue from contracts with customers, but will continue to be reflected as other revenues in determining total revenues. The reclassified revenues relate primarily to the weather normalization mechanism in Kansas, where the KCC determines how we reflect variations in weather in our rates billed to customers. 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 delivered and simultaneously consumed. The majority of our revenues that meet the requirements under ASC 606 are considered implied contracts, as established by our tariff rates approved by regulatory authorities. Our sources of revenue are disaggregated by natural gas sales (including sales to residential, commercial, industrial, wholesale and public authority customers), transportation revenues, and other utility revenues, which are primarily one-time service fees, that meet the requirements under ASC 606. The reclassification of certain revenues that do not meet the requirements under ASC 606 have been classified as other revenues on the Consolidated Income Statement and in our Notes to Consolidated Financial Statements. Additionally, for our natural gas sales and transportation revenues, our customers receive the benefits of our performance when the commodity is delivered to the customer and the performance obligation is satisfied over time as the customer receives and consumes the natural gas. For our other utility revenues, the performance obligation of one-time services are satisfied at a point in time when services are rendered to the customer. In addition, we use the invoice method practical expedient, where we recognize revenue for volumes delivered for which we have a right to invoice.

See Note 2 of the Notes to the Consolidated Financial Statements in this Quarterly Report for additional information.


2.	REVENUE

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



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2018			2017		2018			2017
	(Thousands of dollars)
Natural gas sales to customers	$	261,347		$	247,494	$	856,273		$	747,663
Transportation revenues	24,062			21,343		57,605			51,549
Miscellaneous revenues	5,759			5,196		12,527			10,981
Total revenues from contracts with customers	291,168			274,033		926,405			810,193
Other revenues - natural gas sales related	(1,108		)	3,377		(78		)	15,540
Other revenues	2,461			2,279		4,658			4,364
Total other revenues	1,353			5,656		4,580			19,904
Total revenues	$	292,521		$	279,689	$	930,985		$	830,097

Our natural gas sales to customers represent revenue from contracts with customers through implied contracts established by our tariff rates approved by the regulatory authorities and includes residential, commercial, industrial, wholesale and public authority customers. For natural gas sales, the customer receives the benefits of our performance when the commodity is received and simultaneously consumed by the customer. The performance obligation is satisfied over time as the customer consumes the natural gas.

Our transportation revenues represent revenue from contracts with customers through implied contracts established by our tariff rates approved by the regulatory authorities and tariff-based negotiated contracts. The customer receives the benefits of our performance when the commodity is delivered to the customer and the performance obligation is satisfied over time as the customer receives the natural gas.

Our miscellaneous revenues from contracts with customers represent implied contracts established by our tariff rates approved by the regulatory authorities and includes miscellaneous service charges with the performance obligation satisfied at a point in time when services are rendered to the customer.

Total other revenues consist of revenues associated with regulatory mechanisms that do not meet the requirements under ASC 606 as revenue from contracts with customers, but authorize us to accrue revenues earned based on tariffs approved by the regulatory authorities. Total other revenues primarily reflect our natural gas sales related weather normalization mechanism in Kansas. This mechanism adjusts our revenues earned for the variance between actual and normal HDDs. This mechanism can have either positive (warmer than normal) or negative (colder than normal) effects on revenues.

We have elected to use the invoice method practical expedient, where we recognize revenue for volumes delivered for which we have a right to invoice for our natural gas sales, transportation revenues and other utility revenues. For regulated deliveries of natural gas, we read meters and bill customers on a monthly cycle. We recognize revenue upon the delivery of the natural gas commodity or services rendered to customers. The billing cycles for customers do not necessarily coincide with the accounting periods used for financial reporting purposes. Revenue is accrued for natural gas delivered and services rendered to

customers, but not yet billed. Accrued unbilled revenue is based on a percentage estimate of amounts unbilled each month, which is dependent upon a number of factors, some of which require management's judgment. These factors include customer consumption patterns and the impact of weather on usage. The accrued unbilled natural gas sales revenue at June 30, 2018 and December 31, 2017, were $52.0 million and $138.5 million, respectively.

We collect and remit other taxes on behalf of government authorities, and we record these amounts in accrued taxes other than income in our Consolidated Balance Sheets on a net basis.

Cost of natural gas includes commodity purchases, fuel, storage, transportation and other gas purchase costs recovered through our cost of natural gas regulatory mechanisms and does not include an allocation of general operating costs or depreciation and amortization. In addition, our cost of natural gas regulatory mechanisms provide a method of recovering natural gas costs on an ongoing basis without a profit. Our revenues will fluctuate with the cost of gas that we purchase.


3.	REGULATORY ASSETS AND LIABILITIES

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



	June 30, 2018
	Current			Noncurrent			Total
	(Thousands of dollars)
Under-recovered purchased-gas costs	$	6,741		$	—		$	6,741
Pension and postemployment benefit costs	25,109			367,751			392,860
Reacquired debt costs	812			6,892			7,704
MGP remediation costs	—			7,724			7,724
Ad valorem tax	662			—			662
Other	6,078			3,197			9,275
Total regulatory assets, net of amortization	39,402			385,564			424,966
Federal income tax rate changes (a)	(16,183		)	(521,717		)	(537,900		)
Over-recovered purchased-gas costs	(31,457		)	—			(31,457		)
Weather normalization	(227		)	—			(227		)
Total regulatory liabilities	(47,867		)	(521,717		)	(569,584		)
Net regulatory assets (liabilities)	$	(8,465	)	$	(136,153	)	$	(144,618	)

(a) See Note 10 for additional information regarding our federal income tax rate changes to regulatory liabilities.



	December 31, 2017
	Current			Noncurrent			Total
	(Thousands of dollars)
Under-recovered purchased-gas costs	$	41,238		$	—		$	41,238
Pension and postemployment benefit costs	25,156			387,582			412,738
Weather normalization	17,461			—			17,461
Reacquired debt costs	812			7,298			8,110
MGP remediation costs	—			6,104			6,104
Other	3,513			4,205			7,718
Total regulatory assets, net of amortization	88,180			405,189			493,369
Federal income tax rate changes (a)	—			(519,421		)	(519,421		)
Over-recovered purchased-gas costs	(9,434		)	—			(9,434		)
Ad valorem tax	(4		)	—			(4		)
Total regulatory liabilities	(9,438		)	(519,421		)	(528,859		)
Net regulatory assets (liabilities)	$	78,742		$	(114,232	)	$	(35,490	)

(a) See Note 10 for additional information regarding our federal income tax rate changes to regulatory liabilities.

Regulatory assets on our Consolidated 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 such rates are in effect, but do not generally provide for a return on investment for amounts we have deferred as regulatory assets. All of our regulatory assets are subject to review by the respective regulatory authorities during future regulatory proceedings. We are not aware of any evidence that these costs

will not be recoverable through either riders or base rates, and we believe that we will be able to recover such costs, consistent with our historical recoveries.


4.	CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE

The ONE Gas Credit Agreement is a $700 million revolving unsecured credit facility. We are able to request an increase in commitments of up to an additional $500 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement 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 June 30, 2018, 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 June 30, 2018, we had $185.0 million of commercial paper with no borrowings and $514.2 million of remaining credit available under the ONE Gas Credit Agreement.


5.	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.


6.	EQUITY

Dividends Declared - In July 2018, we declared a dividend of $0.46 per share ($1.84 per share on an annualized basis) for shareholders of record as of August 13, 2018, payable September 4, 2018.


7.	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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



	Three Months Ended						Six Months Ended						Affected Line Item in the
Details about Accumulated Other	June 30,						June 30,						Consolidated Statements
Comprehensive Income (Loss) Components	2018			2017			2018			2017			of Income
	(Thousands of dollars)
Pension and other postemployment benefit plan obligations (a)
Amortization of net loss	$	10,950		$	10,648		$	21,900		$	21,296
Amortization of unrecognized prior service cost	(1,142		)	(1,149		)	(2,284		)	(2,298		)
	9,808			9,499			19,616			18,998
Regulatory adjustments (b)	(9,537		)	(9,289		)	(19,074		)	(18,579		)
	271			210			542			419			Income before income taxes
	(68		)	(81		)	(419		)	(161		)	Income tax expense
Total reclassifications for the period	$	203		$	129		$	123		$	258		Net income

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

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


8.	EARNINGS PER SHARE

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

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



	Three Months Ended June 30, 2018
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	20,419	52,692	$	0.39
Diluted EPS Calculation
Effect of dilutive securities	—		207
Net income available for common stock and common stock equivalents	$	20,419	52,899	$	0.39



	Three Months Ended June 30, 2017
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	20,623	52,553	$	0.39
Diluted EPS Calculation
Effect of dilutive securities	—		416
Net income available for common stock and common stock equivalents	$	20,623	52,969	$	0.39



	Six Months Ended June 30, 2018
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	111,254	52,648	$	2.11
Diluted EPS Calculation
Effect of dilutive securities	—		250
Net income available for common stock and common stock equivalents	$	111,254	52,898	$	2.10



	Six Months Ended June 30, 2017
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS Calculation
Net income available for common stock	$	97,079	52,565	$	1.85
Diluted EPS Calculation
Effect of dilutive securities	—		447
Net income available for common stock and common stock equivalents	$	97,079	53,012	$	1.83


9.	EMPLOYEE BENEFIT PLANS

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



	Pension Benefits
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	3,230		$	3,044		$	6,460		$	6,088
Interest cost (a)	9,200			10,113			18,400			20,226
Expected return on assets (a)	(15,145		)	(14,624		)	(30,290		)	(29,248		)
Amortization of net loss (a)	9,978			9,027			19,956			18,054
Net periodic benefit cost	$	7,263		$	7,560		$	14,526		$	15,120

(a) Upon adoption of ASU 2017-07 on January 1, 2018, these amounts are recognized as other income (expense) in the Consolidated Statements of Income. See Note 11 for additional detail of our other income (expense).



	Other Postemployment Benefits
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
	(Thousands of dollars)
Components of net periodic benefit (credit) cost
Service cost	$	589		$	627		$	1,178		$	1,254
Interest cost (a)	2,279			2,472			4,558			4,944
Expected return on assets (a)	(3,571		)	(3,147		)	(7,142		)	(6,294		)
Amortization of unrecognized prior service cost (a)	(1,142		)	(1,149		)	(2,284		)	(2,298		)
Amortization of net loss (a)	972			1,621			1,944			3,242
Net periodic benefit (credit) cost	$	(873	)	$	424		$	(1,746	)	$	848

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 six months ended June 30, 2018.

Upon adoption of ASU 2017-07 on January 1, 2018, we continue to capitalize all eligible service cost and non-service cost components under the accounting requirements of Topic 980 (Regulated Operations) for rate regulated entities. Our consolidated balance sheets reflect the capitalized non-service cost components as a regulatory asset. See Note 3 of the Notes to the Consolidated Financial Statements in this Quarterly Report for additional information.


10.	INCOME TAXES

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

Changes in tax laws or tax rates are recognized in the financial reporting period that includes the enactment date.

Tax Reform - In December 2017, the Tax Cuts and Jobs Act of 2017 was signed into law. Substantially all of the provisions of the new law are effective for taxable years beginning after December 31, 2017. The new law includes significant changes to the Code, including amendments which significantly change the taxation of business entities and includes specific provisions related to regulated utilities. The more significant changes that impact us include reductions in the corporate federal statutory income tax rate to 21 percent from 35 percent, and several technical provisions including, among others, the elimination of full expensing for tax purposes of certain property acquired after September 27, 2017, the continuation of certain rate normalization requirements for accelerated depreciation benefits and the general allowance for the continued deductibility of interest expense. Additionally, the new law limits the utilization of NOLs arising after December 31, 2017, to 80 percent of taxable income with an indefinite carryforward.

The staff of the SEC issued guidance in SAB 118 which clarifies accounting for income taxes under ASC 740 if information is not yet available or complete and provides for up to a one-year period in which to complete the required analyses and accounting. We have completed or made a reasonable estimate for the measurement and accounting of the effects of the Tax Cuts and Jobs Act of 2017, which were reflected in our December 31, 2017, consolidated financial statements. We are still analyzing certain aspects of the Tax Cuts and Jobs Act of 2017, refining our calculations and expect additional guidance from the U.S. Department of the Treasury and the Internal Revenue Service. Any additional issued guidance or future actions of our regulators could potentially affect the final determination of the accounting effects arising from the implementation of the Tax Cuts and Jobs Act of 2017.

Reductions in our ADIT balances to reflect the reduced corporate income tax rate of 21 percent will result in amounts previously collected from our customers for these deferred income taxes to be refunded to our customers. The Tax Cuts and Jobs Act of 2017 retains the provisions of the Code that stipulate how these excess deferred income taxes are to be refunded, as well as the timing of any such refunds, to customers for certain accelerated tax depreciation benefits. Potential refunds of these and other deferred income taxes will be determined by our regulators. At June 30, 2018, the regulatory liability associated with the remeasurement of our ADIT totaled $521.7 million.

We are working with our regulators in Oklahoma, Kansas and Texas to address the impact of the Tax Cuts and Jobs Act of 2017 on our rates. In each state, we have received accounting orders requiring us to refund the remeasurement of our ADIT and to establish a separate regulatory liability for the difference in taxes included in our rates that have been calculated based on a 35 percent federal statutory income tax rate and the new 21 percent federal statutory income tax rate effective in January 2018. The establishment of this separate regulatory liability associated with the change in tax rates collected in our rates resulted in a reduction to our revenues of $9.2 million and $21.5 million for the three and six months ended June 30, 2018, respectively. The amount, period and timing of the return of these regulatory liabilities to our customers will be determined by the regulators in each of our jurisdictions.


11.	OTHER INCOME AND OTHER EXPENSE

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
	(Thousands of dollars)
Net periodic benefit cost other than service cost	$	(2,403	)	$	(4,313	)	$	(4,137	)	$	(8,626	)
Other, net	209			413			(221		)	1,319
Total other income (expense), net	$	(2,194	)	$	(3,900	)	$	(4,358	)	$	(7,307	)


12.	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 or the discovery of presently unknown environmental conditions may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. In addition, emission controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental investigation and remediation compliance to-date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and six months ended June 30, 2018 and 2017.

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

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. In 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. Additional testing and work plan development continued 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 second quarter of 2018, we revised our estimate of the potential costs associated with additional investigation and remediation to be in the range of $5.6 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 an adjustment to the reserve of $1.6 million for this site in the second quarter of 2018, which also increased our regulatory asset pursuant to our AAO in Kansas.

In October 2017, Kansas Gas Service, the KCC staff and the Citizens’ Utility Ratepayer Board filed a unanimous settlement agreement with the KCC. The agreement allows Kansas Gas Service to defer and seek recovery of 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 issued an order approving the settlement agreement in November 2017. A regulatory asset of approximately $5.9 million was recorded 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 six months ended June 30, 2018 and 2017. 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.

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

Pipeline Safety - We are subject to PHMSA regulations, including integrity-management regulations. PHMSA regulations require pipeline companies operating high-pressure transmission pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated 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 GPAC has met five times since January 2017 to review public comments and make recommendations to PHMSA. The GPAC completed their review of the NPRM on March 28, 2018, except for gas gathering. The next GPAC meeting, scheduled for September 2018, will focus on gas gathering. In addition to reviewing public and committee comments, PHMSA announced they will split this NPRM into three separate final rulemakings:


•	the first final rule will address the legislative mandates from the Pipeline Safety, Regulatory Certainty and Jobs Creation Act and will be called the Safety of Gas Transmission Pipelines: Maximum Allowable Operating Pressure Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments;


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


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

A significant number of recommendations have been made to PHMSA to improve the NPRM. The industry trade associations filed joint comments to the “legislative mandates” rulemaking to amend the federal safety regulations applicable to gas transmission and gathering pipelines. The timing of each final rule being published is unknown, but the first and second final rules are expected to be published during 2019. The potential capital and operating expenditures associated with compliance with the proposed rules 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.


13.	DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS

Accounting Treatment - We record all derivative instruments at fair value, with the exception of normal purchases and normal sales that are expected to result in physical delivery. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it, or if regulatory 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 consolidated 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 consolidated financial statements based on the observability of inputs used to estimate such fair value. The levels of the hierarchy are described below:


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


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


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

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

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

Derivative Instruments - At June 30, 2018, we held purchased natural gas call options for the heating season ending March 31, 2019, with total notional amounts of 15.1 Bcf, for which we paid premiums of $3.6 million, and had a fair value of $3.8 million. At December 31, 2017, we held purchased natural gas call options for the heating season ended March 31, 2018, with total notional amounts of 14.1 Bcf, for which we paid premiums of $5.5 million, and had a fair value of $1.1 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 Consolidated Balance Sheets. Our natural gas call options are classified as Level 1 as fair value amounts are based on unadjusted quoted prices in active markets including NYMEX-settled prices. There were no transfers between levels for the three and six months ended June 30, 2018 and 2017.

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 June 30, 2018 and December 31, 2017. The estimated fair value of our long-term debt, including current maturities, was $1.2 billion and 1.3 billion at June 30, 2018 and December 31, 2017, respectively. The estimated fair value of our Senior Notes at June 30, 2018 and December 31, 2017, was determined using quoted market prices, and are classified as Level 2.


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

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and the Notes to the Consolidated Financial Statements in this Quarterly Report, as well as our Annual Report. Due to the seasonal nature of our business, the results of operations for the three and six months ended June 30, 2018, are not necessarily indicative of the results that may be expected for a 12-month period.

RECENT DEVELOPMENTS

Tax Reform - In December 2017, the Tax Cuts and Jobs Act of 2017 was signed into law. Substantially all the provisions of the new law are effective for taxable years beginning after December 31, 2017. The new law includes significant changes to the Code, including amendments which significantly change the taxation of business entities and includes specific provisions related to regulated utilities. The more significant changes that impact us include reductions in the corporate federal statutory income tax rate to 21 percent from 35 percent, and several technical provisions including, among others, the elimination of full expensing for tax purposes of certain property acquired after September 27, 2017, the continuation of certain rate normalization requirements for accelerated depreciation benefits and the general allowance for the continued deductibility of interest expense. Additionally, the new law limits the utilization of NOLs arising after December 31, 2017, to 80 percent of taxable income with an indefinite carryforward.

As a result of the enactment of the Tax Cuts and Jobs Act of 2017, we remeasured our ADIT. As a regulated entity, the change in ADIT was recorded as a regulatory liability and is subject to refund to our customers. The Tax Cuts and Jobs Act of 2017 retains the provisions of the Code that stipulate how these excess deferred income taxes are to be refunded, as well as the timing of any such refunds, to customers for certain accelerated tax depreciation benefits. Potential refunds of these and other deferred income taxes will be determined by our regulators. At June 30, 2018, the regulatory liability associated with the remeasurement of our ADIT totaled $521.7 million.

See additional information on the impact of the Tax Cuts and Jobs Act of 2017 below under Regulatory Activities.

Dividend - In July 2018, we declared a dividend of $0.46 per share ($1.84 per share on an annualized basis) for shareholders of record as of August 13, 2018, payable September 4, 2018.

REGULATORY ACTIVITIES

Oklahoma - On March 15, 2018, Oklahoma Natural Gas filed its second annual PBRC application following the general rate case that was approved in January 2016. This filing was based on a calendar test year of 2017. The PBRC filing identified a $5.6 million credit to base rates primarily due to the reduction in the corporate federal statutory income tax rate. If approved as filed, this credit will be applied to customers’ bills over a 12-month period following receipt of an order. The filing also requested an energy efficiency program true-up and utility incentive adjustment of approximately $2.1 million. A hearing before the administrative law judge was held on July 27, 2018, with an order expected in the third quarter of 2018. As required, PBRC filings are made annually on or before March 15, until the next general rate case, which is currently required to be filed on or before June 30, 2021, based on a calendar test year of 2020.

Kansas - In June 2018, Kansas Gas Service filed a request with the KCC for an increase in base rates, reflecting investments in system improvements and changes in operating costs necessary to maintain the safety and reliability of its natural gas distribution system. Kansas Gas Service’s request, if approved, represents a net base rate increase of $42.7 million. Kansas Gas Service is already recovering $2.9 million from customers through the GSRS, resulting in a total base rate increase of $45.6 million. The filing is based on a 10.0 percent return on equity and a 62.2 percent common equity ratio. The filing represents a rate base of $1 billion, compared with $947 million included in existing base rates plus previously approved GSRS-eligible investments. Since the last general rate case in 2016, Kansas Gas Service has invested $179 million in its natural gas distribution system. Benefits of the corporate income tax cuts associated with the Tax Cuts and Jobs Act of 2017 are also reflected in Kansas Gas Service’s filing. Kansas Gas Service’s filing includes a Revenue Normalization Adjustment that is designed to ensure that Kansas Gas Service collects the amount of revenue set by the KCC from residential, general sales and small transport customers, regardless of customer usage. In accordance with Kansas law, the KCC has 240 days to consider Kansas Gas Service’s filing.

In April 2018, a bill amending the GSRS statute was approved. Beginning January 1, 2019, the scope of projects eligible for recovery under the statute will include all investments to replace, upgrade or modernize obsolete facilities, as well as projects that enhance the integrity of pipeline system components or extend the useful life of such assets. Safety-related investments will also include expenditures for physical and cyber security. Additionally, the cap on the monthly residential surcharge will increase to 80 cents from 40 cents.

In August 2017, Kansas Gas Service submitted an application to the KCC requesting an increase of approximately $2.9 million related to its GSRS. In November 2017, the KCC approved the increase effective December 2017.

Texas - West Texas Service Area - In March 2018, Texas Gas Service made GRIP filings for all customers in the West Texas service area. In June 2018, the RRC and the cities in the West Texas service area agreed to an increase of $3.5 million, and new rates became effective in July 2018.

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

Rio Grande Valley Service Area - In April 2018, Texas Gas Service filed an annual COSA for the incorporated areas of the Rio Grande Valley service area. The cities approved an increase of $1.1 million, and new rates will become effective in August 2018.

In March 2018, the RRC approved an increase in base rates of $0.5 million for the unincorporated areas of the Rio Grande Valley service area, with new rates effective in April 2018. This rate case settlement reflects a corporate federal statutory income tax rate of 21 percent and required Texas Gas Service to calculate, defer and refund to customers $0.1 million associated with the changes to the corporate income tax rate for the period between January 1, 2018, and the implementation of the new rates in April 2018.

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

Central Texas Service Area - In March 2018, Texas Gas Service made GRIP filings for all customers in the Central Texas service area. In June 2018, the RRC and the cities in the Central Texas service area agreed to an increase of $3.3 million, and new rates became effective in July 2018.

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

North Texas Service Area - In June 2018, Texas Gas Service filed a rate case for customers in its North Texas service area for an increase of $1.0 million. If approved, new rates are expected to take effect in December 2018.

In April 2017, Texas Gas Service filed an annual COSA in its North Texas service area. In October 2017, Texas Gas Service and the cities in the North Texas service area agreed to an increase of $0.8 million, and new rates became effective in August 2017.

Other Texas Service Areas - In the normal course of business, Texas Gas Service has filed rate cases and sought GRIP and COSA increases in various other Texas jurisdictions to address investments in rate base and changes in expenses. Annual rate

adjustments associated with these filings that were approved totaled $(0.7) million for the six months ended June 30, 2018 and $0.6 million for the year ended December 31, 2017.

Tax Reform - Oklahoma - In December 2017, the Oklahoma Attorney General filed a motion on behalf of customers in Oklahoma requesting that the OCC take action for an immediate reduction in rates and protection of rate payers’ interests. On January 9, 2018, the OCC approved an order directing Oklahoma Natural Gas to record a deferred liability beginning on the effective date of the order, January 9, 2018, to reflect the reduced federal corporate tax rate of 21 percent and the associated savings in excess ADIT and any other tax implications of the Tax Cuts and Jobs Act of 2017 on an interim basis, subject to refund, until utility rates are adjusted to reflect the federal tax savings and a final order is issued in Oklahoma Natural Gas’ next scheduled PBRC proceeding. This order also directs Oklahoma Natural Gas, to the extent not already accounted for in Oklahoma Natural Gas’ current PBRC tariff, to accrue interest at a rate equivalent to Oklahoma Natural Gas’ cost of capital as recognized in the most recent PBRC filing on the amounts of any refunds determined to be owed to customers until issuance of a final order in the upcoming PBRC proceeding. This order also dismissed the Oklahoma Attorney General’s motion.

In compliance with the order, Oklahoma Natural Gas’ March 15, 2018, PBRC filing contains two deferred liabilities subject to review and potential refund. First, a regulatory liability has been established reflecting the revaluation of ADIT for the change in the federal corporate income tax rate. This liability will be returned to customers over an amortization period in compliance with tax normalization rules included in the Code, as amended. An additional $2.9 million liability, including interest, has been established for the estimated impact on customer rates of the reduced tax rate for the period between January 9, 2018, and the date new rates are expected to go into effect following receipt of an order in the PBRC filing. A hearing before the administrative law judge was held on July 27, 2018.

Kansas - On January 18, 2018, the KCC opened a general investigation for the purposes of examining the financial impact of the Tax Cuts and Jobs Act of 2017 on regulated public utilities operating in Kansas and made the following findings and conclusions: (1) utilities are to track and accumulate, in a deferred revenue account, the portion of their revenue that results from the use of a 35 percent federal corporate tax rate for its last KCC-approved revenue determination instead of the new lower federal corporate tax rate; (2) deferrals are to commence on the effective date of the new federal corporate tax rate;

(3) excess ADIT should be captured in a manner consistent with tax normalization rules; and (4) the portion of current rates affected by the Tax Cuts and Jobs Act of 2017 should be considered interim and subject to refund, with interest compounded monthly at the rate for customer deposits, until the KCC has an opportunity to evaluate the reasonableness of those rates with new lower federal tax rates.

In March 2018, Kansas Gas Service reached a settlement with the KCC Staff and the Citizens’ Utility Ratepayer Board related to the impact of the Tax Cuts and Jobs Act of 2017. The agreement indicates for the period between January 1, 2018, and through the date on which the KCC issues a final order in Kansas Gas Service’s next general rate case, Kansas Gas Service agrees to accrue monthly, as a regulatory liability on its general ledger, the portion of its revenue representing the difference between the 21 percent and 35 percent corporate tax rate. The annual amount of the regulatory liability is $14.1 million, excluding interest. The agreement also established the interest rate to be applied as the customer deposit interest rate, currently 1.62 percent. The disposition of the actual amount to be refunded to customers will be determined by the KCC in its final order at the completion of Kansas Gas Service’s next general rate case filing. Through this agreement, Kansas Gas Service also established a regulatory liability to account for the revaluation of ADIT for the change in the federal corporate income tax rate. Issues regarding the treatment of this regulatory liability will also be determined in Kansas Gas Service’s next general rate proceeding. As part of the agreement, Kansas Gas Service is required to file a general rate case no later than 150 days from the date of a KCC order approving the settlement agreement. Kansas Gas Service filed a general rate case in June 2018.

In December 2017, Kansas Industrial Consumers (“KIC”) filed a complaint against all utilities asking the KCC to act to ensure that KIC members are not charged unreasonable rates because of the Tax Cuts and Jobs Act of 2017. In January 2018, the Citizens’ Utility Ratepayer Board filed a complaint stating that the change in tax rates requires the KCC to not only address the reduction in the corporate tax rate to 21 percent from 35 percent, but also excess ADIT. In March 2018, the KCC granted the Citizens’ Utility Ratepayer Board’s motion to dismiss its complaint.

Texas - In February 2018, the RRC issued an accounting order for determining how the impact of the Tax Cuts and Jobs Act of 2017 will be reflected in gas utility rates in Texas. Gas utilities were ordered to either file a new rate case or file to voluntarily reduce rates by September 1, 2018, to reflect the reduction of the federal corporate income tax rate to 21 percent from 35 percent. Gas utilities were further ordered to calculate, defer and refund rate reductions resulting from changes to the corporate tax rate that occurred between January 1, 2018 and the effective date of new rates. Per the order, the impact of the Tax Cuts and Jobs Act of 2017 on ADIT is to be determined in the next rate case in each jurisdiction.

Central Texas Service Area - In March 2018, Texas Gas Service requested a $4.9 million decrease to rates for customers in the Central Texas service area due to the reduction of the corporate income tax rate, and a one-time refund of $2.5 million for the reduction in the corporate income tax rate for the period between January 1, 2018, to the date new rates are implemented. The request was approved by the RRC and the cities, and new rates became effective in July 2018.

West Texas Service Area - In March 2018, Texas Gas Service requested a $4.7 million decrease to rates for customers in the West Texas service area due to the reduction of the corporate income tax rate, and a one-time refund of $2.4 million for changes to the corporate income tax rate for the period between January 1, 2018, to the date new rates are implemented. The request was approved by the RRC and the cities, and new rates became effective in July 2018.

Rio Grande Valley Service Area - In March 2018, Texas Gas Service requested a $1.5 million decrease to rates for customers in the incorporated areas of the Rio Grande Valley service area due to the reduction of the corporate income tax rate, and a one-time refund of $0.4 million for changes to the corporate income tax rate for the period between January 1, 2018, to the implementation of new rates, which became effective in April 2018.

Gulf Coast Service Area - In April 2018, Texas Gas Service filed for a one-time refund of $0.6 million for changes to the corporate income tax rate for the period between January 1, 2018, to the implementation of new rates, which will become effective in August 2018.

See Liquidity and Capital Resources - Tax Reform for additional discussion of the Tax Cuts and Jobs Act of 2017.

OTHER

In 2017, we formed a wholly-owned captive insurance company in the state of Oklahoma to provide insurance to our divisions.

FINANCIAL RESULTS AND OPERATING INFORMATION

We operate in one reportable and operating business segment: regulated 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 Consolidated Financial Statements in our Annual Report. We evaluate our financial performance principally on operating income.

Selected Financial Results - For the three months ended June 30, 2018, net income was $20.4 million, or $0.39 per diluted share, compared with $20.6 million, or $0.39 per diluted share in the same period last year. For the six months ended June 30, 2018, net income was $111.3 million, or $2.10 per diluted share, compared with $97.1 million, or $1.83 per diluted share in the same period last year.

Our results for the three and six months ended June 30, 2018, reflect lower income tax expense due primarily to a $3.8 million and $20.0 million decrease, respectively, associated with the reduction in the federal statutory income tax rate to 21 percent in 2018 from 35 percent in 2017 as a result of the Tax Cuts and Jobs Act of 2017. This decrease is offset partially by the change in the tax benefits on vested long-term incentive awards which vested in the first quarter of 2018 compared to the awards that vested in the first quarter of 2017. The tax benefits on our vested long-term incentive awards are reflected in income tax expense due to the share-based compensation accounting standard adopted in the first quarter of 2017. The following table sets forth certain selected financial results for our operations for the periods indicated:



	Three Months Ended				Six Months Ended				Three Months					Six Months
	June 30,				June 30,				2018 vs. 2017					2018 vs. 2017
Financial Results	2018		2017		2018		2017		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars, except percentages)
Natural gas sales to customers	$	260.2	$	250.9	$	856.2	$	763.2	$	9.3		4	%	$	93.0		12	%
Transportation revenues	24.1		21.4		57.6		51.6		2.7			13	%	6.0			12	%
Cost of natural gas	94.2		82.5		444.6		345.7		11.7			14	%	98.9			29	%
Net margin, excluding other revenues	190.1		189.8		469.2		469.1		0.3			—	%	0.1			—	%
Other utility revenues	8.3		7.4		17.2		15.3		0.9			12	%	1.9			12	%
Net margin	198.4		197.2		486.4		484.4		1.2			1	%	2.0			—	%
Operating costs	117.6		110.9		236.4		231.7		6.7			6	%	4.7			2	%
Depreciation and amortization	39.8		37.9		78.7		74.9		1.9			5	%	3.8			5	%
Operating income	$	41.0	$	48.4	$	171.3	$	177.8	$	(7.4	)	(15	)%	$	(6.5	)	(4	)%
Capital expenditures	$	89.2	$	84.2	$	175.8	$	154.7	$	5.0		6	%	$	21.1		14	%

Natural gas sales to customers represent revenue from contracts with customers through implied contracts established by our tariff rates approved by the regulatory authorities, as well as revenues from regulatory mechanisms related to natural gas sales that do not meet the requirements under ASC 606 which are included in the consolidated statements of income and in our footnotes as other revenues. Natural gas sales includes residential, commercial, industrial, wholesale and public authority customers.

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

Other utility revenues include primarily miscellaneous service charges which represent implied contracts with customers established by our tariff rates approved by the regulatory authorities and other revenues from regulatory mechanisms that do not meet the requirements of ASC 606.

Cost of natural gas includes commodity purchases, fuel, storage, transportation and other gas purchase costs recovered through our cost of natural gas regulatory mechanisms and does not include an allocation of general operating costs or depreciation and amortization. In addition, our cost of natural gas regulatory mechanisms provide a method of recovering natural gas costs on an ongoing basis without a profit. As a result, changes in the cost of gas are offset by a corresponding change in revenues.

Net margin is comprised of total revenues less cost of natural gas. While our revenues will fluctuate with the cost of natural gas that we recover, net margin is not affected by fluctuations in the cost of natural gas. Accordingly, we believe net margin is a better indicator of our financial performance than total revenues, as it provides a useful and more relevant measure to analyze our financial performance. As such, the following discussion and analysis of our financial performance will reference net margin rather than total revenues and cost of natural gas individually.

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



	Three Months Ended				Six Months Ended				Three Months					Six Months
Net Margin, Excluding Other	June 30,				June 30,				2018 vs. 2017					2018 vs. 2017
Revenues	2018		2017		2018		2017		Increase (Decrease)					Increase (Decrease)
Natural gas sales	(Millions of dollars, except percentages)
Residential	$	137.1	$	139.7	$	341.2	$	347.9	$	(2.6	)	(2	)%	$	(6.7	)	(2	)%
Commercial and industrial	27.5		27.5		67.2		66.4		—			—	%	0.8			1	%
Wholesale and public authority	1.4		1.2		3.2		3.2		0.2			17	%	—			—	%
Net margin on natural gas sales	166.0		168.4		411.6		417.5		(2.4		)	(1	)%	(5.9		)	(1	)%
Transportation revenues	24.1		21.4		57.6		51.6		2.7			13	%	6.0			12	%
Net margin, excluding other revenues	$	190.1	$	189.8	$	469.2	$	469.1	$	0.3		—	%	$	0.1		—	%

Our net margin on natural gas sales is comprised of two components, fixed and variable margin. Fixed margin reflects the portion of our net margin attributable to the monthly fixed customer charge component of our rates, which does not fluctuate based on customer usage in each period. Variable margin reflects the portion of our net margin that fluctuates with the volumes delivered and billed and the effects of weather normalization. We believe that the combination of the significant residential component of our customer base, the fixed charge component of our sales margin and our regulatory rate mechanisms that we have in place result in a stable cash flow profile. The following table sets forth our net margin on natural gas sales by revenue type for the periods indicated:



	Three Months Ended				Six Months Ended				Three Months					Six Months
	June 30,				June 30,				2018 vs. 2017					2018 vs. 2017
Net Margin on Natural Gas Sales	2018		2017		2018		2017		Increase (Decrease)					Increase (Decrease)
Net margin on natural gas sales	(Millions of dollars, except percentages)
Fixed margin	$	137.7	$	141.5	$	274.1	$	280.7	$	(3.8	)	(3	)%	$	(6.6	)	(2	)%
Variable margin	28.3		26.9		137.5		136.8		1.4			5	%	0.7			1	%
Net margin on natural gas sales	$	166.0	$	168.4	$	411.6	$	417.5	$	(2.4	)	(1	)%	$	(5.9	)	(1	)%

Net margin increased $1.2 million for the three months ended June 30, 2018, compared with the same period last year, due primarily to the following:


•	an increase of $3.8 million from new rates in Texas and Kansas;


•	an increase of $2.4 million due to higher sales volumes, net of weather normalization, primarily from colder weather in 2018 compared with 2017;


•	an increase of $2.1 million due primarily to higher transportation volumes; and


•	an increase of $1.1 million in residential sales due primarily to net customer growth in Oklahoma and Texas; offset by


•	a decrease of $9.2 million related to the deferral of potential refund obligations associated with the Tax Cuts and Jobs Act of 2017.

Net margin increased $2.0 million for the six months ended June 30, 2018, compared with the same period last year, due primarily to the following:


•	an increase of $8.9 million from new rates in Texas and Kansas;


•	an increase of $4.8 million due to higher sales volumes, net of weather normalization, primarily from colder weather in 2018 compared with 2017;


•	an increase of $4.6 million due primarily to higher transportation volumes;


•	an increase of $2.4 million in residential sales due primarily to net customer growth in Oklahoma and Texas;


•	an increase of $1.1 million in rider and surcharge recoveries due to higher ad-valorem surcharge in Kansas, offset by higher regulatory amortization in depreciation and amortization expense below; and


•	an increase of $0.9 million due to the benefit of the retroactive 2017 compressed natural gas federal excise tax credit enacted in February 2018; offset by


•	a decrease of $21.5 million related to the deferral of potential refund obligations associated with the Tax Cuts and Jobs Act of 2017.

Operating costs increased $6.7 million for the three months ended June 30, 2018, compared with the same period last year, due primarily to the following:


•	an increase of $7.9 million in employee-related costs; offset by


•	a decrease of $1.3 million in outside service costs associated with pipeline maintenance activities.

Operating costs increased $4.7 million for the six months ended June 30, 2018, compared with the same period last year, due primarily to the following:


•	an increase of $7.9 million in employee-related costs; offset by


•	a decrease of $2.4 million in outside service costs associated with pipeline maintenance activities.

Depreciation and amortization expense increased $1.9 million and $3.8 million for the three and six months ended June 30, 2018, respectively, compared with the same periods last year, due primarily to an increase in depreciation from our capital expenditures being placed in service and an increase in the amortization of the ad-valorem surcharge rider in Kansas.

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 $5.0 million and $21.1 million for the three and six months ended June 30, 2018, respectively, compared with the same 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
	June 30,								2018 vs. 2017
(in thousands)	2018				2017				Increase (Decrease)
Average Number of Customers	OK	KS	TX	Total	OK	KS	TX	Total	OK	KS	TX	Total
Residential	798	586	624	2,008	794	584	619	1,997	4	2	5	11
Commercial and industrial	74	50	35	159	73	50	35	158	1	—	—	1
Wholesale and public authority	—	—	3	3	—	—	3	3	—	—	—	—
Transportation	5	6	1	12	5	6	1	12	—	—	—	—
Total customers	877	642	663	2,182	872	640	658	2,170	5	2	5	12



	Six Months Ended								Variances
	June 30,								2018 vs. 2017
(in thousands)	2018				2017				Increase (Decrease)
Average Number of Customers	OK	KS	TX	Total	OK	KS	TX	Total	OK	KS	TX	Total
Residential	801	588	624	2,013	796	587	618	2,001	5	1	6	12
Commercial and industrial	74	50	35	159	74	50	35	159	—	—	—	—
Wholesale and public authority	—	—	3	3	—	—	3	3	—	—	—	—
Transportation	5	6	1	12	5	6	1	12	—	—	—	—
Total customers	880	644	663	2,187	875	643	657	2,175	5	1	6	12

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



	Three Months Ended		Six Months Ended
	June 30,		June 30,
Volumes (MMcf)	2018	2017	2018	2017
Natural gas sales
Residential	15,605	11,704	76,590	55,891
Commercial and industrial	5,881	4,895	23,871	17,776
Wholesale and public authority	355	334	1,222	994
Total sales volumes delivered	21,841	16,933	101,683	74,661
Transportation	51,770	49,087	116,686	110,177
Total volumes delivered	73,611	66,020	218,369	184,838

Total volumes delivered increased for the three and six months ended June 30, 2018, compared with the same periods last year, due primarily to colder weather. The impact of weather on residential and commercial net margin is mitigated by weather-normalization mechanisms in all jurisdictions.



	Three Months Ended
	June 30,
	2018		2017		2018 vs. 2017		2018		2017
Heating Degree Days	Actual	Normal	Actual	Normal	Actual Variance		Actual as a percent of Normal
Oklahoma	337	191	182	191	85	%	176	%	95	%
Kansas	486	419	345	419	41	%	116	%	82	%
Texas	35	54	29	53	21	%	65	%	55	%



	Six Months Ended
	June 30,
	2018		2017		2018 vs. 2017		2018		2017
Heating Degree Days	Actual	Normal	Actual	Normal	Actual Variance		Actual as a percent of Normal
Oklahoma	2,207	1,966	1,574	1,966	40	%	112	%	80	%
Kansas	2,975	2,947	2,331	2,922	28	%	101	%	80	%
Texas	938	1,062	658	1,062	43	%	88	%	62	%

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


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


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


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

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


•	11 weather stations and customers by month for Oklahoma;


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


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

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

CONTINGENCIES

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

LIQUIDITY AND CAPITAL RESOURCES

General - We have relied primarily on operating cash flow and commercial paper for our liquidity and capital resource requirements. We fund operating expenses, working capital requirements, including purchases of natural gas, and capital expenditures primarily with cash from operations and commercial paper.

We believe that the combination of the significant residential component of our customer base, the fixed-charge component of our natural gas sales net margin and our regulatory rate mechanisms that we have in place result in a stable cash flow profile. Because the energy consumption of residential customers is less volatile compared with commercial and industrial customers, our business historically has generated stable and predictable net margin and cash flows. Additionally, we have several regulatory rate mechanisms in place to reduce the lag in earning a return on our capital expenditures. We anticipate that our cash flow generated from operations and our expected short- and long-term financing arrangements will enable us to maintain our current and planned level of operations and provide us flexibility to finance our infrastructure investments.

Our ability to access capital markets for debt and equity financing under reasonable terms depends on market conditions and our financial condition and credit ratings. 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.

Tax Reform - The Tax Cuts and Jobs Act of 2017 will have an overall negative impact on our operating cash flow due to several dynamics. The reduction in the tax rate will result in less revenues collected from customers related to the recovery of tax expense included in our rates. Although cash collected from this revenue is ultimately used to remit our income tax expense payments, under the new law, we will lose a portion of the timing benefit when we collect and remit tax payments, thereby reducing cash that may have been retained for several years. Under the new tax law, natural gas utilities are not eligible to take bonus depreciation, but they are also not subject to the new limitations on the deduction of interest expense. The loss of bonus depreciation will result in earlier cash tax payments, as compared to the previous tax law, once accumulated NOLs are fully extinguished. Additionally, the lowering of the tax rate effectively resulted in an over-collection of tax expenses, as customers’ rates include tax expenses based on the statutory tax rate. Future cash flows will be reduced as we refund the excess ADIT collection to customers.

The timing of these changes in our cash flows and the degree to which it impacts us will not be known until we finalize our current regulatory filings and make future regulatory filings. When new rates are approved by our regulators, the manner and timing in which we refund previously collected taxes will be determined. We believe that our capital structure and available liquidity resources will be adequate to adjust for these changes. See additional discussion under Regulatory Activities - Tax Reform and Note 10 of the Notes to the Consolidated Financial Statements in this Quarterly Report for additional information.

Short-term Financing - The ONE Gas Credit Agreement is a $700 million revolving unsecured credit facility. We are able to request an increase in commitments of up to an additional $500 million upon satisfaction of customary conditions, including receipt of commitments from either new lenders or increased commitments from existing lenders. The ONE Gas Credit Agreement 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 June 30, 2018, our total debt-to-capital ratio was 41 percent, and we were in compliance with all covenants under the ONE Gas Credit Agreement.

We may reduce the unutilized portion of the ONE Gas Credit Agreement in whole or in part without premium or penalty. The ONE Gas Credit Agreement contains customary events of default. Upon the occurrence of certain events of default, the obligations under the ONE Gas Credit Agreement may be accelerated and the commitments may be terminated.

At June 30, 2018, we had $185.0 million in the form of commercial paper with no borrowings under the ONE Gas Credit Agreement. At June 30, 2018, we had approximately $12.6 million of cash and cash equivalents and $514.2 million of remaining credit available under the ONE Gas Credit Agreement.

Long-Term Debt - The indenture governing our Senior Notes includes an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding Senior Notes to declare those Senior Notes immediately due and payable in full. At June 30, 2018, $300 million of 2.07 percent senior notes were reclassified as current maturities of long-term debt in our Consolidated Balance Sheets. At June 30, 2018 our long-term debt-to-capital ratio was 37 percent.

Credit Ratings - Our credit ratings as of June 30, 2018, were:



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

On January 19, 2018, Moody’s changed our outlook to negative from stable based on the potential impacts of the Tax Cuts and Jobs Act of 2017.

Our commercial paper is currently rated Prime-1 by Moody’s and A-1 by S&P. We intend to maintain strong credit metrics while we pursue a balanced approach to capital investment and a return of capital to shareholders via a dividend that we believe will be competitive with our peer group.

Pension and Other Postemployment Benefit Plans - Information about our pension and other postemployment benefits plans, including anticipated contributions, is included under Note 11 of the Notes to the Consolidated Financial Statements in our Annual Report. See Note 9 of the Notes to the Consolidated Financial Statements in this Quarterly Report for additional information.

CASH FLOW ANALYSIS

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

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



	Six Months Ended
	June 30,						Variance
	2018			2017			2018 vs. 2017
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	400.0		$	279.3		$	120.7
Investing activities	(175.8		)	(154.3		)	(21.5		)
Financing activities	(226.0		)	(134.6		)	(91.4		)
Change in cash and cash equivalents	(1.8		)	(9.6		)	7.8
Cash and cash equivalents at beginning of period	14.4			14.7			(0.3		)
Cash and cash equivalents at end of period	$	12.6		$	5.1		$	7.5

Operating Cash Flows - Changes in cash flows from operating activities are due primarily to changes in net margin and operating expenses discussed in Financial Results and Operating Information. Changes in natural gas prices and demand for our services or natural gas, whether because of general economic conditions, changes in supply or increased competition from other service providers, could affect our earnings and operating cash flows. Typically, our cash flows from operations are greater in the first half of the year compared with the second half of the year.

Operating cash flows were higher for the six months ended June 30, 2018, compared with the same period in 2017, due primarily to working capital changes related to under-recovered purchased-gas costs, natural gas in storage and weather normalization adjustments which were impacted by higher volumes of natural gas delivered in the first six months of 2018, compared with the same period in 2017, due to colder weather.

Investing Cash Flows - Cash used in investing activities increased for the six months ended June 30, 2018, compared with the prior period, due primarily to an increase in capital expenditures related to increased system integrity activities and extending service to new areas during the six months ended June 30, 2018.

Financing Cash Flows - Cash used in financing activities increased for the six months ended June 30, 2018, compared with the prior period, due primarily to larger repayments of notes payable, offset by no purchases of treasury stock shares in the first half of 2018.

ENVIRONMENTAL, SAFETY AND REGULATORY MATTERS

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.

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, the 12 former MGP sites which we own or retain responsibility for certain environmental conditions. In October 2017, Kansas Gas Service, the KCC staff and the Citizens’ Utility Ratepayer Board filed a unanimous settlement agreement with the KCC. The agreement allows Kansas Gas Service to defer and seek recovery of 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 issued an order approving the settlement agreement in November 2017. A regulatory asset of approximately $5.9 million was recorded for estimated costs that have been accrued at January 1, 2017.


•	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.


•	the first final rule will address the legislative mandates from the Pipeline Safety, Regulatory Certainty and Jobs Creation Act and will be called the Safety of Gas Transmission Pipelines: Maximum Allowable Operating Pressure Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments;


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


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

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

International, federal, regional and/or state legislative and/or regulatory initiatives may attempt to regulate greenhouse gas emissions. We monitor relevant legislation and regulatory initiatives to assess the potential impact on our operations. The EPA’s Mandatory Greenhouse Gas Reporting Rule requires annual greenhouse gas emissions reporting as carbon dioxide equivalents from affected facilities and for the natural gas delivered by us to our natural gas distribution customers who are not otherwise required to report their own emissions. The additional cost to gather and report this emission data did not have, and we do not expect it to have, a material impact on our results of operations, financial position or cash flows. In addition, Congress has considered, and may consider in the future, legislation to reduce greenhouse gas emissions, including carbon dioxide and methane. Likewise, the EPA may institute additional regulatory rulemaking associated with greenhouse gas emissions. At this time, no rule or legislation has been enacted for natural gas distribution that assesses any costs, fees or expenses on any of these emissions.

CERCLA - The 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 U.S. Department of Homeland Security’s Transportation Security Administration issued updated pipeline security guidelines in March 2018. Our pipeline facilities have been reviewed according to the current guidelines and no material changes have been required to date.

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

We participate in the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions. We continue to focus on maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices to limit the release of natural gas during pipeline and facility maintenance and operations. Additionally, in March 2016, we were one of 40 founding partners to launch the EPA’s Natural Gas STAR Methane Challenge Program, whereby oil and natural gas companies agree to promote and track commitments to reduce methane emissions beyond what is federally required. Our Methane Challenge Program commitment to annually replace or rehabilitate at least two percent of our combined inventory of cast iron and noncathodically-protected steel pipe aligns with our planned system integrity expenditures for infrastructure replacements. We exceeded our goal by achieving an overall replacement rate of seven percent in 2016. Results for 2017 have not been finalized.

Additional information about our environmental matters is included in the section entitled “Environmental Matters” in Note 12 of the Notes to the Consolidated Financial Statements in this Quarterly Report.

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

IMPACT OF NEW ACCOUNTING STANDARDS

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

ESTIMATES AND CRITICAL ACCOUNTING POLICIES

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

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

FORWARD-LOOKING STATEMENTS

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

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

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


•	our ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our regulated rates;


•	our ability to manage our operations and maintenance costs;


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


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

commercial industrial customers;


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


•	conservation and energy storage 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, which may be affected by risks beyond our control such as commodity price volatility and counterparty creditworthiness;


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


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


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


•	changes in inflation and interest rates;


•	our ability to recover the costs of natural gas purchased for our customers;


•	impact of potential impairment charges;


•	volatility and changes in markets for natural gas;


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


•	payment and performance by counterparties and customers as contracted and when due;


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


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


•	advances in technology;


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


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


•	cyber attacks or breaches of technology systems that could disrupt our operations or result in the loss or exposure of confidential or sensitive customer, employee or company information;


•	the sufficiency of insurance coverage to cover losses;


•	the effects of our strategies to reduce tax payments;


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


•	changes in accounting standards;


•	changes in corporate governance standards;


•	discovery of material weaknesses in our internal controls;


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


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


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


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


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


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

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


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

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

Interest-Rate Risk

We would be exposed to interest-rate risk with any new debt financing. We are able to manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps. Fixed-rate swaps may be used to reduce our risk of increased interest costs during periods of rising interest rates. Floating-rate swaps may be used to convert the fixed rates of long-term borrowings into short-term variable rates.

Counterparty Credit Risk

We assess the creditworthiness of our customers. Those customers who do not meet minimum standards are required to provide security, including deposits and other forms of collateral, when appropriate. With more than 2 million customers across three states, we are not exposed materially to a concentration of credit risk. We are able to recover the natural gas cost component of our uncollectible accounts through our purchased-gas cost adjustment mechanisms. 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.


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 second quarter ended June 30, 2018, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS


ITEM 1A.	RISK FACTORS

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


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

Not applicable.


ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

Not applicable.


ITEM 4.	MINE SAFETY DISCLOSURES

Not applicable.


ITEM 5.	OTHER INFORMATION

Not applicable.


ITEM 6.	EXHIBITS

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

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



Exhibit No.		Exhibit Description


	3.1	Amended Certificate of Incorporation of ONE Gas, Inc., dated May 24, 2018 (incorporated by reference to Exhibit 3.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on May 30, 2018 (File No. 1-36180)).

	3.2	Amended and Restated By-Laws of ONE Gas, Inc., dated July 23, 2018 (incorporated by reference to Exhibit 3.1 to ONE Gas, Inc.’s Current Report on Form 8-K filed on July 27, 2018 (File No. 1-36180)).

	10.1	The ONE Gas, Inc. Amended and Restated Equity Compensation Plan (2018) (filed as Appendix A to the Company’s definitive proxy statement on Schedule 14A filed on April 4, 2018 (File No. 1-36108)).

	31.1	Certification of Pierce H. Norton II pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2	Certification of Curtis L. Dinan pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	32.1	Certification of Pierce H. Norton II pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).

	32.2	Certification of Curtis L. Dinan pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).



	101.INS	XBRL Instance Document.

	101.SCH	XBRL Schema Document.

	101.CAL	XBRL Calculation Linkbase Document.

	101.LAB	XBRL Label Linkbase Document.

	101. PRE	XBRL Presentation Linkbase Document.

	101.DEF	XBRL Extension Definition Linkbase Document.

Attached as Exhibit 101 to this Quarterly Report are the following XBRL-related documents: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three and six months ended June 30, 2018 and 2017; (iii) Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2018 and 2017; (iv) Consolidated Balance Sheets at June 30, 2018 and December 31, 2017; (v) Consolidated Statements of Cash Flows for the six months ended June 30, 2018 and 2017; (vi) Consolidated Statement of Equity for the six months ended June 30, 2018; and (vii) Notes to the Consolidated Financial Statements.

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

SIGNATURE

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



Date: August 1, 2018		ONE Gas, Inc.
		Registrant

	By:	/s/ Curtis L. Dinan
		Curtis L. Dinan
		Senior Vice President and
		Chief Financial Officer
		(Principal Financial Officer)