Edgar Filing: ONEOK INC /NEW/

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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 March 31, 2019.

___ 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 001-13643

ONEOK, Inc.

(Exact name of registrant as specified in its charter)



Oklahoma	73-1520922
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

100 West Fifth Street, Tulsa, OK	74103
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code (918) 588-7000

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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes 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 __

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 April 22, 2019, the Company had 412,756,216 shares of common stock outstanding.

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ONEOK, Inc.

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Part I.	Financial Information	Page No.
Item 1.	Financial Statements (Unaudited)	6
	Consolidated Statements of Income - Three Months Ended March 31, 2019 and 2018	6
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2019 and 2018	7
	Consolidated Balance Sheets - March 31, 2019, and December 31, 2018	8
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2019 and 2018	11
	Consolidated Statements of Changes in Equity - Three Months Ended March 31, 2019 and 2018	12
	Notes to Consolidated Financial Statements	14
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52
Item 4.	Controls and Procedures	54
Part II.	Other Information	54
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	54
Item 3.	Defaults Upon Senior Securities	54
Item 4.	Mine Safety Disclosures	54
Item 5.	Other Information	54
Item 6.	Exhibits	54
Signature		57

As used in this Quarterly Report, references to “we,” “our” or “us” refer to ONEOK, Inc., an Oklahoma corporation, and its predecessors, divisions, 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,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “might,” “plan,” “potential,” “project,” “scheduled,” “should,” “will,” “would” 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 1A, “Risk Factors,” in our Annual Report.

INFORMATION AVAILABLE ON OUR WEBSITE

We make available, free of charge, on our website (www.oneok.com) copies of our Annual Reports, Quarterly Reports, 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, Director Independence Guidelines, Bylaws and the written charter of our Audit Committee also are available on our website, and we will provide copies of these documents upon request.

In addition to our filings with the SEC and materials posted on our website, we also use social media platforms as additional channels of distribution to reach public investors. Information contained on our website, posted on our social media accounts, and any corresponding applications, are not incorporated by reference into this report.

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GLOSSARY

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



$1.5 Billion Term Loan Agreement	The senior unsecured delayed-draw three-year $1.5 billion term loan agreement dated November 19, 2018
$2.5 Billion Credit Agreement	ONEOK’s $2.5 billion revolving credit agreement, as amended
AFUDC	Allowance for funds used during construction
Annual Report	Annual Report on Form 10-K for the year ended December 31, 2018
ASU	Accounting Standards Update
Bbl	Barrels, 1 barrel is equivalent to 42 United States gallons
Bbl/d	Barrels per day
BBtu/d	Billion British thermal units per day
Bcf	Billion cubic feet
Bcf/d	Billion cubic feet per day
CFTC	U.S. Commodity Futures Trading Commission
Clean Air Act	Federal Clean Air Act, as amended
DJ	Denver-Julesburg
EBITDA	Earnings before interest expense, income taxes, depreciation and amortization
EPA	United States Environmental Protection Agency
Exchange Act	Securities Exchange Act of 1934, as amended
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States of America
Intermediate Partnership	ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary of ONEOK Partners, L.P.
LIBOR	London Interbank Offered Rate
MBbl/d	Thousand barrels per day
MDth/d	Thousand dekatherms per day
MMBbl	Million barrels
MMBtu	Million British thermal units
MMcf/d	Million cubic feet per day
Moody’s	Moody’s Investors Service, Inc.
NGL(s)	Natural gas liquid(s)
NGL products	Marketable natural gas liquid purity products, such as ethane, ethane/propane mix, propane, iso-butane, normal butane and natural gasoline
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
ONEOK	ONEOK, Inc.
ONEOK Partners	ONEOK Partners, L.P.
OPIS	Oil Price Information Service
PHMSA	United States Department of Transportation Pipeline and Hazardous Materials Safety Administration
POP	Percent of Proceeds
Quarterly Report(s)	Quarterly Report(s) on Form 10-Q
Roadrunner	Roadrunner Gas Transmission, LLC, a 50 percent-owned joint venture
S&P	S&P Global Ratings
SCOOP	South Central Oklahoma Oil Province, an area in the Anadarko Basin in Oklahoma
SEC	Securities and Exchange Commission
Series E Preferred Stock	Series E Non-Voting, Perpetual Preferred Stock, par value $0.01 per share
STACK	Sooner Trend Anadarko Canadian Kingfisher, an area in the Anadarko Basin in Oklahoma
West Texas LPG	West Texas LPG pipeline and Mesquite pipeline
WTI	West Texas Intermediate
WTLPG	West Texas LPG Pipeline Limited Partnership
XBRL	eXtensible Business Reporting Language

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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS



ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
	Three Months Ended
	March 31,
(Unaudited)	2019			2018
	(Thousands of dollars, except per share amounts)
Revenues (Note L)
Commodity sales	$	2,472,959		$	2,820,004
Services	306,999			282,073
Total revenues	2,779,958			3,102,077
Cost of sales and fuel (exclusive of items shown separately below)	1,956,377			2,368,026
Operations and maintenance	207,251			181,181
Depreciation and amortization	114,158			104,237
General taxes	33,490			29,023
Gain on sale of assets	(60		)	(89		)
Operating income	468,742			419,699
Equity in net earnings from investments (Note I)	43,481			40,187
Allowance for equity funds used during construction	12,441			230
Other income	9,360			738
Other expense	(3,462		)	(3,309		)
Interest expense (net of capitalized interest of $19,192, and $2,038, respectively)	(115,420		)	(115,725		)
Income before income taxes	415,142			341,820
Income taxes	(77,934		)	(75,771		)
Net income	337,208			266,049
Less: Net income attributable to noncontrolling interests	—			1,541
Net income attributable to ONEOK	337,208			264,508
Less: Preferred stock dividends	275			275
Net income available to common shareholders	$	336,933		$	264,233

Basic earnings per common share (Note G)	$	0.82		$	0.65

Diluted earnings per common share (Note G)	$	0.81		$	0.64
Average shares (thousands)
Basic	412,908			409,676
Diluted	415,233			412,173

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three Months Ended
	March 31,
(Unaudited)	2019			2018
	(Thousands of dollars)
Net income	$	337,208		$	266,049
Other comprehensive income (loss), net of tax
Unrealized gains (losses) on derivatives, net of tax of $20,593 and $(10,312), respectively	(68,944		)	34,524
Realized (gains) losses on derivatives recognized in net income, net of tax of $4,177 and $(3,578), respectively	(12,171		)	11,976
Change in retirement and other postretirement benefit plan liability, net of tax of $(699) and $(781), respectively	2,341			2,615
Other comprehensive income (loss) on investments in unconsolidated affiliates, net of tax of $750 and $(844), respectively	(2,511		)	2,824
Total other comprehensive income (loss), net of tax	(81,285		)	51,939
Comprehensive income	255,923			317,988
Less: Comprehensive income attributable to noncontrolling interests	—			1,541
Comprehensive income attributable to ONEOK	$	255,923		$	316,447

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	March 31,		December 31,
(Unaudited)	2019		2018
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	27,814	$	11,975
Accounts receivable, net	812,869		818,958
Materials and supplies	163,731		141,174
Natural gas and natural gas liquids in storage	243,223		296,667
Commodity imbalances	38,349		29,050
Other current assets	56,793		100,808
Total current assets	1,342,779		1,398,632
Property, plant and equipment
Property, plant and equipment	18,887,742		18,030,963
Accumulated depreciation and amortization	3,369,710		3,264,312
Net property, plant and equipment	15,518,032		14,766,651
Investments and other assets
Investments in unconsolidated affiliates	950,924		969,150
Goodwill and intangible assets	964,167		967,142
Other assets	158,423		130,096
Total investments and other assets	2,073,514		2,066,388
Total assets	$	18,934,325	$	18,231,671

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
(Continued)
	March 31,			December 31,
(Unaudited)	2019			2018
Liabilities and equity	(Thousands of dollars)
Current liabilities
Current maturities of long-term debt (Note D)	$	307,650		$	507,650
Accounts payable	1,027,322			1,116,337
Commodity imbalances	120,145			110,197
Accrued interest	113,567			161,377
Finance lease liability	1,809			1,765
Other current liabilities	119,176			211,110
Total current liabilities	1,689,669			2,108,436
Long-term debt, excluding current maturities (Note D)	10,004,341			8,873,334
Deferred credits and other liabilities
Deferred income taxes	270,751			219,731
Finance lease liability	25,775			26,244
Other deferred credits	501,783			424,383
Total deferred credits and other liabilities	798,309			670,358
Commitments and contingencies (Note J)
Equity (Note E)
ONEOK shareholders’ equity:
Preferred stock, $0.01 par value: authorized and issued 20,000 shares at March 31, 2019, and December 31, 2018	—			—
Common stock, $0.01 par value: authorized 1,200,000,000 shares, issued 445,016,234 shares and outstanding 412,752,687 shares at March 31, 2019; issued 445,016,234 shares and outstanding 411,532,606 shares at December 31, 2018	4,450			4,450
Paid-in capital	7,527,847			7,615,138
Accumulated other comprehensive loss (Note F)	(269,524		)	(188,239		)
Retained earnings	—			—
Treasury stock, at cost: 32,263,547 shares at March 31, 2019, and 33,483,628 shares at December 31, 2018	(820,767		)	(851,806		)
Total equity	6,442,006			6,579,543
Total liabilities and equity	$	18,934,325		$	18,231,671

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Three Months Ended
	March 31,
(Unaudited)	2019			2018
	(Thousands of dollars)
Operating activities
Net income	$	337,208		$	266,049
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	114,158			104,237
Equity in net earnings from investments	(43,481		)	(40,187		)
Distributions received from unconsolidated affiliates	45,936			41,095
Deferred income taxes	75,994			74,890
Share-based compensation expense	8,607			7,203
Pension and postretirement benefit expense, net of contributions	(12,250		)	(8,393		)
Allowance for equity funds used during construction	(12,441		)	(230		)
Gain on sale of assets	(60		)	(89		)
Changes in assets and liabilities:
Accounts receivable	6,089			358,733
Natural gas and natural gas liquids in storage	53,444			149,825
Accounts payable	(62,469		)	(361,008		)
Commodity imbalances, net	649			(39,755		)
Accrued interest	(47,810		)	(37,784		)
Risk-management assets and liabilities	4,362			34,387
Other assets and liabilities, net	(114,330		)	(53,652		)
Cash provided by operating activities	353,606			495,321
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	(889,705		)	(264,467		)
Contributions to unconsolidated affiliates	(1,016		)	(147		)
Distributions received from unconsolidated affiliates in excess of cumulative earnings	13,527			8,721
Proceeds from sale of assets	12,365			241
Cash used in investing activities	(864,829		)	(255,652		)
Financing activities
Dividends paid	(354,203		)	(316,408		)
Distributions to noncontrolling interests	—			(1,500		)
Borrowing (repayment) of short-term borrowings, net	—			(614,673		)
Issuance of long-term debt, net of discounts	1,442,782			—
Debt financing costs	(11,663		)	—
Repayment of long-term debt	(501,913		)	(501,913		)
Issuance of common stock	4,784			1,182,117
Other, net	(52,725		)	(7,011		)
Cash provided by (used in) financing activities	527,062			(259,388		)
Change in cash and cash equivalents	15,839			(19,719		)
Cash and cash equivalents at beginning of period	11,975			37,193
Cash and cash equivalents at end of period	$	27,814		$	17,474

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

	ONEOK Shareholders’ Equity
(Unaudited)	Common Stock Issued	Preferred Stock Issued	Common Stock		Preferred Stock		Paid-in Capital
	(Shares)		(Thousands of dollars)
January 1, 2019	445,016,234	20,000	$	4,450	$	—	$	7,615,138
Cumulative effect adjustment for adoption of ASU 2016-02 (Note A)	—	—	—		—		—
Net income	—	—	—		—		—
Other comprehensive income (loss) (Note F)	—	—	—		—		—
Preferred stock dividends - $13.75 per share (Note E)	—	—	—		—		—
Common stock issued	—	—	—		—		(24,779		)
Common stock dividends - $0.86 per share (Note E)	—	—	—		—		(17,438		)
Other	—	—	—		—		(45,074		)
March 31, 2019	445,016,234	20,000	$	4,450	$	—	$	7,527,847



	ONEOK Shareholders’ Equity
(Unaudited)	Common Stock Issued	Preferred Stock Issued	Common Stock		Preferred Stock		Paid-in Capital
	(Shares)		(Thousands of dollars)
January 1, 2018	423,166,234	20,000	$	4,232	$	—	$	6,588,878
Cumulative effect adjustment for adoption of ASUs (a)	—	—	—		—		—
Net income	—	—	—		—		—
Other comprehensive income (loss)	—	—	—		—		—
Preferred stock dividends - $13.75 per share	—	—	—		—		(275		)
Common stock issued	21,850,000	—	218		—		1,169,247
Common stock dividends - $0.77 per share	—	—	—		—		(11,960		)
Distributions to noncontrolling interests	—	—	—		—		—
Contributions from noncontrolling interests	—	—	—		—		—
Other	—	—	—		—		(10,717		)
March 31, 2018	445,016,234	20,000	$	4,450	$	—	$	7,735,173

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Continued)
	ONEOK Shareholders’ Equity
(Unaudited)	Accumulated Other Comprehensive Loss			Retained Earnings			Treasury Stock			Total Equity
	(Thousands of dollars)
January 1, 2019	$	(188,239	)	$	—		$	(851,806	)	$	6,579,543
Cumulative effect adjustment for adoption of ASU 2016-02 (Note A)	—			(67		)	—			(67		)
Net income	—			337,208			—			337,208
Other comprehensive income (loss) (Note F)	(81,285		)	—			—			(81,285		)
Preferred stock dividends - $13.75 per share (Note E)	—			(275		)	—			(275		)
Common stock issued	—			—			31,039			6,260
Common stock dividends - $0.86 per share (Note E)	—			(336,866		)	—			(354,304		)
Other	—			—			—			(45,074		)
March 31, 2019	$	(269,524	)	$	—		$	(820,767	)	$	6,442,006



	ONEOK Shareholders’ Equity
(Unaudited)	Accumulated Other Comprehensive Loss			Retained Earnings			Treasury Stock			Noncontrolling Interests in Consolidated Subsidiaries			Total Equity
	(Thousands of dollars)
January 1, 2018	$	(188,530	)	$	—		$	(876,713	)	$	157,485		$	5,685,352
Cumulative effect adjustment for adoption of ASUs (a)	(38,101		)	39,803			—			17			1,719
Net income	—			264,508			—			1,541			266,049
Other comprehensive income (loss)	51,939			—			—			—			51,939
Preferred stock dividends - $13.75 per share	—			—			—			—			(275		)
Common stock issued	—			—			13,228			—			1,182,693
Common stock dividends - $0.77 per share	—			(304,311		)	—			—			(316,271		)
Distributions to noncontrolling interests	—			—			—			(1,500		)	(1,500		)
Contributions from noncontrolling interests	—			—			—			10,263			10,263
Other	—			—			—			—			(10,717		)
March 31, 2018	$	(174,692	)	$	—		$	(863,485	)	$	167,806		$	6,869,252

(a) - Includes cumulative effect for adoption of the following: ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)”; ASU 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities”; and ASU 2018-02, “Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.”

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


A.	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 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 2018 year-end Consolidated Balance Sheet data was derived from our audited Consolidated Financial Statements but does not include all disclosures required by GAAP. Certain reclassifications have been made in the prior-year Consolidated Financial Statements to conform to the current year presentation. These unaudited Consolidated Financial Statements should be read in conjunction with our audited Consolidated Financial Statements in our Annual Report.

Recently Issued Accounting Standards Update - Changes to GAAP are established by the Financial Accounting Standards Board (FASB) in the form of ASUs to the FASB Accounting Standards Codification. We consider the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or clarifications of ASUs listed below. The following table provides a brief description of recent accounting pronouncements and our analysis of the effects on our financial statements:



Standard	Description	Date of Adoption	Effect on the Financial Statements or Other Significant Matters
Standards that were adopted
ASU 2016-02, “Leases (Topic 842)”	The standard requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. It also requires qualitative disclosures along with specific quantitative disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing and uncertainty of cash flows arising from leases.	First quarter 2019	We adopted this standard on January 1, 2019, using the modified retrospective method and the optional transition method to record the adoption impact through a cumulative adjustment to equity. We recorded an immaterial cumulative effect for the adoption of the new standard and recorded $17.5 million of right-of-use assets and $17.4 million of lease liabilities related to operating leases that were not previously recorded on our Consolidated Balance Sheets. Our finance lease assets and liabilities of $28.1 million and $28.0 million, respectively, did not change as a result of adopting this standard. See Note K for additional disclosures.
ASU 2018-07, “Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting”	The standard aligns the measurement and classification guidance for share-based payments to nonemployees with the guidance for share-based payments to employees, with certain exceptions.	First quarter 2019	The impact of adopting this standard was not material.
Standards that are not yet adopted
ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments”	The standard requires a financial asset (or a group of financial assets) measured at amortized cost basis to be presented net of the allowance for credit losses to reflect the net carrying value at the amount expected to be collected on the financial asset; and the initial allowance for credit losses for purchased financial assets, including available-for-sale debt securities, to be added to the purchase price rather than being reported as a credit loss expense.	First quarter 2020	We do not expect the adoption of this standard to materially impact us.
ASU 2017-04, “Intangibles- Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment”	The standard simplifies the subsequent measurement of goodwill by eliminating the requirement to calculate the implied fair value of goodwill under step 2. Instead, an entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value. The standard does not change step zero or step 1 assessments.	First quarter 2020	We do not expect the adoption of this standard to materially impact us.

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B.	FAIR VALUE MEASUREMENTS

Determining Fair Value - For our fair value measurements, we utilize market prices, third-party pricing services, present value methods and standard option valuation models to determine the price we would receive from the sale of an asset or the transfer of a liability in an orderly transaction at the measurement date. 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.

While many of the contracts in our derivative portfolio are executed in liquid markets where price transparency exists, some contracts are executed in markets for which market prices may exist, but the market may be relatively inactive. This results in limited price transparency that requires management’s judgment and assumptions to estimate fair values. For certain transactions, we may utilize modeling techniques using NYMEX-settled pricing data and implied forward LIBOR curves. Inputs into our fair value estimates include commodity-exchange prices, data obtained from third-party pricing services, LIBOR and other liquid money-market instrument rates. Our financial commodity derivatives are generally settled through a NYMEX or Intercontinental Exchange (ICE) clearing broker account with daily margin requirements. We validate our valuation inputs with third-party information and settlement prices from other sources, where available.

We compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets and liabilities to present value using interest-rate yields to calculate present-value discount factors derived from the implied forward LIBOR yield curve. The fair value of our forward-starting interest-rate swaps is determined using financial models that incorporate the implied forward LIBOR yield curve for the same period as the future interest-rate swap settlements. We consider current market data in evaluating counterparties’, as well as our own, nonperformance risk, net of collateral, by using counterparty-specific bond yields. Although we use our best estimates to determine the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ materially from our estimates.

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


•	Level 1 - fair value measurements are based on unadjusted quoted prices for identical securities in active markets. These balances are comprised predominantly of exchange-traded derivative contracts for natural gas and crude oil.


•	Level 2 - fair value measurements are based on significant observable pricing inputs, including quoted prices for similar assets and liabilities in active markets and inputs from third-party pricing services supported with corroborative evidence. These balances are comprised of over-the-counter interest-rate derivatives.

•

Level 3 - fair value measurements are based on inputs that may include one or more unobservable inputs, including internally developed natural gas basis and NGL price curves that incorporate observable and unobservable market data from broker quotes and third-party pricing services. These balances are comprised predominantly of exchange-cleared and over-the-counter derivatives for natural gas basis and NGLs. Our commodity derivatives are generally valued using forward quotes provided by third-party pricing services that are validated with other market data. We believe any measurement uncertainty at March 31, 2019, is immaterial as our Level 3 fair value measurements are based on unadjusted pricing information from broker quotes and third-party pricing services. We do not believe that our Level 3 fair value estimates have a material impact on our results of operations, as our derivatives are accounted for as hedges.

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

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Recurring Fair Value Measurements - The following tables set forth our recurring fair value measurements for the periods indicated:



	March 31, 2019
	Level 1			Level 2			Level 3			Total - Gross			Netting (a)			Total - Net
	(Thousands of dollars)
Derivative assets
Commodity contracts
Financial contracts	$	1,468		$	—		$	32,840		$	34,308		$	(27,156	)	$	7,152
Physical contracts	—			—			751			751			—			751
Total derivative assets	$	1,468		$	—		$	33,591		$	35,059		$	(27,156	)	$	7,903
Derivative liabilities
Commodity contracts
Financial contracts	$	(5,094	)	$	—		$	(22,062	)	$	(27,156	)	$	27,156		$	—
Interest-rate contracts	—			(149,984		)	—			(149,984		)	—			(149,984		)
Total derivative liabilities	$	(5,094	)	$	(149,984	)	$	(22,062	)	$	(177,140	)	$	27,156		$	(149,984	)

(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At March 31, 2019, we held no cash and posted $20.0 million of cash with various counterparties, which is included in other current assets in our Consolidated Balance Sheet.



	December 31, 2018
	Level 1			Level 2			Level 3			Total - Gross			Netting (a)			Total - Net
	(Thousands of dollars)
Derivative assets
Commodity contracts
Financial contracts	$	10,812		$	—		$	69,165		$	79,977		$	(32,739	)	$	47,238
Physical contracts	—			—			1,142			1,142			—			1,142
Interest-rate contracts	—			19,005			—			19,005			—			19,005
Total derivative assets	$	10,812		$	19,005		$	70,307		$	100,124		$	(32,739	)	$	67,385
Derivative liabilities
Commodity contracts
Financial contracts	$	(2,916	)	$	—		$	(29,823	)	$	(32,739	)	$	32,739		$	—
Interest-rate contracts	—			(99,260		)	—			(99,260		)	—			(99,260		)
Total derivative liabilities	$	(2,916	)	$	(99,260	)	$	(29,823	)	$	(131,999	)	$	32,739		$	(99,260	)

(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2018, we held no cash and posted $0.8 million of cash with various counterparties, which is included in other current assets in our Consolidated Balance Sheet.

The following table sets forth a reconciliation of our Level 3 fair value measurements for the periods indicated:



	Three Months Ended
	March 31,
Derivative Assets (Liabilities)	2019			2018
	(Thousands of dollars)
Net assets (liabilities) at beginning of period	$	40,484		$	(32,838	)
Total realized/unrealized gains (losses):
Included in earnings (a)	—			(85		)
Included in other comprehensive income (loss) (b)	(28,955		)	36,021
Net assets (liabilities) at end of period	$	11,529		$	3,098

(a) - Included in commodity sales revenues in our Consolidated Statements of Income.

(b) - Included in unrealized gains (losses) on derivatives in our Consolidated Statements of Comprehensive Income.

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Realized/unrealized gains (losses) include the realization of our derivative contracts through maturity. During the three months ended March 31, 2019 and 2018, there were no transfers in or out of Level 3 of the fair value hierarchy.

Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable, accounts payable and short-term borrowings 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. Our short-term borrowings are classified as Level 2 since the estimated fair value of the short-term borrowings can be determined using information available in the commercial paper market.

The estimated fair value of our consolidated long-term debt, including current maturities, was $11.0 billion and $9.6 billion at March 31, 2019, and December 31, 2018, respectively. The book value of our consolidated long-term debt, including current maturities, was $10.3 billion and $9.4 billion at March 31, 2019, and December 31, 2018, respectively. The estimated fair value of the aggregate long-term debt outstanding was determined using quoted market prices for similar issues with similar terms and maturities. The estimated fair value of our consolidated long-term debt is classified as Level 2.


C.	RISK-MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

Risk-Management Activities - We are sensitive to changes in natural gas, crude oil and NGL prices, principally as a result of contractual terms under which these commodities are processed, purchased and sold. We are also subject to the risk of interest-rate fluctuation in the normal course of business. We use physical-forward purchases and sales and financial derivatives to secure a certain price for a portion of our natural gas, condensate and NGL products; to reduce our exposure to commodity price and interest-rate fluctuations; and to achieve more predictable cash flows. We follow established policies and procedures to assess risk and approve, monitor and report our risk-management activities. We have not used these instruments for trading purposes.

Commodity price risk - Commodity price risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in the price of natural gas, NGLs and condensate. We may use the following commodity derivative instruments to reduce the near-term commodity price risk associated with a portion of the forecasted sales of these commodities:


•	Futures contracts - Standardized contracts to purchase or sell natural gas and crude oil for future delivery or settlement under the provisions of exchange regulations;


•	Forward contracts - Nonstandardized commitments between two parties to purchase or sell natural gas, crude oil or NGLs for future physical delivery. These contracts are typically nontransferable and can only be canceled with the consent of both parties;


•	Swaps - Exchange of one or more payments based on the value of one or more commodities. These instruments transfer the financial risk associated with a future change in value between the counterparties of the transaction, without also conveying ownership interest in the asset or liability; and


•	Options - Contractual agreements that give the holder the right, but not the obligation, to buy or sell a fixed quantity of a commodity at a fixed price within a specified period of time. Options may either be standardized and exchange-traded or customized and nonexchange-traded.

We may also use other instruments including collars to mitigate commodity price risk. A collar is a combination of a purchased put option and a sold call option, which places a floor and a ceiling price for commodity sales being hedged.

In our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk as a result of retaining a portion of the commodity sales proceeds associated with our POP with fee contracts. Under certain POP with fee contracts, our fees and POP percentage may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds. We also are exposed to basis risk between the various production and market locations where we buy and sell commodities. As part of our hedging strategy, we use the previously described commodity derivative financial instruments and physical-forward contracts to reduce the impact of price fluctuations related to natural gas, NGLs and condensate.

In our Natural Gas Liquids segment, we are primarily exposed to commodity price risk resulting from the relative values of the various NGL products to each other, the value of NGLs in storage and the relative value of NGLs to natural gas. We are also exposed to location price differential risk as a result of the relative value of NGL purchases at one location and sales at another location, primarily related to our optimization and marketing activities. As part of our hedging strategy, we utilize physical-forward contracts and commodity derivative financial instruments to reduce the impact of price fluctuations related to NGLs.

In our Natural Gas Pipelines segment, we are exposed to commodity price risk because our intrastate and interstate pipelines consume natural gas in operations and retain natural gas from our customers for operations or as part of our fee for services

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provided. When the amount consumed in operations differs from the amount provided by our customers, our pipelines must buy or sell natural gas, or store or use natural gas from inventory, which can expose this segment to commodity price risk depending on the regulatory treatment for this activity. To the extent that commodity price risk in our Natural Gas Pipelines segment is not mitigated by fuel cost-recovery mechanisms, we may use physical-forward sales or purchases to reduce the impact of natural gas price fluctuations. At March 31, 2019, and December 31, 2018, there were no financial derivative instruments with respect to our natural gas pipeline operations.

Interest-rate risk - We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt, interest-rate swaps and treasury lock contracts. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts. In March 2019, we settled $1.0 billion of our forward-starting interest-rate swaps related to our underwritten public offering of $1.25 billion senior unsecured notes.

At March 31, 2019, and December 31, 2018, we had forward-starting interest-rate swaps with notional amounts totaling $2.0 billion and $3.0 billion, respectively, to hedge the variability of interest payments on a portion of our forecasted debt issuances. At March 31, 2019, and December 31, 2018, we had interest-rate swaps with notional amounts totaling $1.3 billion to hedge the variability of our LIBOR-based interest payments. All of our interest-rate swaps are designated as cash flow hedges.

Accounting Treatment - Our accounting treatment of derivative instruments is consistent with that disclosed in Note A of the Notes to Consolidated Financial Statements in our Annual Report.

Fair Values of Derivative Instruments - All derivatives held at March 31, 2019, and December 31, 2018, were designated as hedging instruments. See Note B for a discussion of the inputs associated with our fair value measurements. The following table sets forth the fair values of our derivative instruments presented on a gross basis for the periods indicated:



		March 31, 2019					December 31, 2018
	Location in our Consolidated Balance Sheets	Assets		(Liabilities)			Assets		(Liabilities)
		(Thousands of dollars)
Derivatives designated as hedging instruments
Commodity contracts (a)
Financial contracts	Other current assets	$	30,763	$	(24,662	)	$	78,891	$	(31,793	)
	Other assets	3,545		(2,494		)	1,086		(946		)
Physical contracts	Other current assets	751		—			1,142		—
Interest-rate contracts	Other current assets/other current liabilities	—		(4,714		)	19,005		(15,012		)
	Other deferred credits	—		(145,270		)	—		(84,248		)
Total derivatives designated as hedging instruments		$	35,059	$	(177,140	)	$	100,124	$	(131,999	)

(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us.

Notional Quantities for Derivative Instruments - The following table sets forth the notional quantities for derivative instruments held for the periods indicated:



		March 31, 2019					December 31, 2018
	Contract Type	Purchased/ Payor		Sold/ Receiver			Purchased/ Payor		Sold/ Receiver
Derivatives designated as hedging instruments:
Cash flow hedges
Fixed price
- Natural gas (Bcf)	Futures and swaps	—		(41.4		)	—		(29.9		)
- Crude oil and NGLs (MMBbl)	Futures, forwards and swaps	6.5		(13.5		)	6.5		(13.8		)
Basis
- Natural gas (Bcf)	Futures and swaps	—		(41.4		)	—		(29.9		)
Interest-rate contracts (Millions of dollars)	Swaps	$	3,250.0	$	—		$	4,250.0	$	—

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These notional amounts are used to summarize the volume of financial instruments; however, they do not reflect the extent to which the positions offset one another and, consequently, do not reflect our actual exposure to market or credit risk.

Cash Flow Hedges - The following table sets forth the unrealized effect of cash flow hedges recognized in other comprehensive income (loss) for the periods indicated:



	Three Months Ended
Derivatives in Cash Flow Hedging Relationships	March 31,
Derivatives in Cash Flow Hedging Relationships	2019			2018
	(Thousands of dollars)
Commodity contracts	$	(21,625	)	$	20,925
Interest-rate contracts	(67,912		)	23,911
Total unrealized gain (loss) recognized in other comprehensive income (loss) on derivatives	$	(89,537	)	$	44,836

The following table sets forth the effect of cash flow hedges in our Consolidated Statements of Income for the periods indicated:



Derivatives in Cash Flow Hedging Relationships	Location of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income	Three Months Ended
		March 31,
		2019			2018
		(Thousands of dollars)
Commodity contracts	Commodity sales revenues/cost of sales and fuel	$	18,852		$	(11,611	)
Interest-rate contracts	Interest expense	(2,504		)	(3,943		)
Total gain (loss) reclassified from accumulated other comprehensive loss into net income on derivatives		$	16,348		$	(15,554	)

Credit Risk - We monitor the creditworthiness of our counterparties and compliance with policies and limits established by our Risk Oversight and Strategy Committee. We maintain credit policies with regard to our counterparties that we believe minimize overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings, bond yields and credit default swap rates), collateral requirements under certain circumstances and the use of standardized master-netting agreements that allow us to net the positive and negative exposures associated with a single counterparty. We use internally developed credit ratings for counterparties that do not have a credit rating.

Our financial commodity derivatives are generally settled through a NYMEX or Intercontinental Exchange (ICE) clearing broker account with daily margin requirements. However, we may enter into financial derivative instruments that contain provisions that require us to maintain an investment-grade credit rating from S&P and/or Moody’s. If our credit ratings on our senior unsecured long-term debt were to decline below investment grade, the counterparties to the derivative instruments could request collateralization on derivative instruments in net liability positions. There were no financial derivative instruments with contingent features related to credit risk at March 31, 2019.

The counterparties to our derivative contracts typically consist of major energy companies, financial institutions and commercial and industrial end users. This concentration of counterparties may affect our overall exposure to credit risk, either positively or negatively, in that the counterparties may be affected similarly by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and other reserves, we do not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance.

At March 31, 2019, the credit exposure from our derivative assets is with investment-grade companies in the financial services sector.

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D.	DEBT

The following table sets forth our consolidated debt for the periods indicated:



	March 31, 2019			December 31, 2018
	(Thousands of dollars)
Commercial paper outstanding	$	—		$	—
Senior unsecured obligations:
$500,000 at 8.625% due March 2019	—			500,000
$300,000 at 3.8% due March 2020	300,000			300,000
$1,500,000 term loan, variable rate, due November 2021	750,000			550,000
$700,000 at 4.25% due February 2022	547,397			547,397
$900,000 at 3.375% due October 2022	900,000			900,000
$425,000 at 5.0% due September 2023	425,000			425,000
$500,000 at 7.5% due September 2023	500,000			500,000
$500,000 at 4.9% due March 2025	500,000			500,000
$500,000 at 4.0% due July 2027	500,000			500,000
$800,000 at 4.55% due July 2028	800,000			800,000
$100,000 at 6.875% due September 2028	100,000			100,000
$700,000 at 4.35% due March 2029	700,000			—
$400,000 at 6.0% due June 2035	400,000			400,000
$600,000 at 6.65% due October 2036	600,000			600,000
$600,000 at 6.85% due October 2037	600,000			600,000
$650,000 at 6.125% due February 2041	650,000			650,000
$400,000 at 6.2% due September 2043	400,000			400,000
$700,000 at 4.95% due July 2047	700,000			700,000
$1,000,000 at 5.2% due July 2048	1,000,000			450,000
Guardian Pipeline
Weighted average 7.85% due December 2022	27,045			28,957
Total debt	10,399,442			9,451,354
Unamortized portion of terminated swaps	16,320			16,750
Unamortized debt issuance costs and discounts	(103,771		)	(87,120		)
Current maturities of long-term debt	(307,650		)	(507,650		)
Long-term debt	$	10,004,341		$	8,873,334

$2.5 Billion Credit Agreement - In June 2018, we extended the term of our $2.5 Billion Credit Agreement by one year to June 2023. Our $2.5 Billion Credit Agreement is a revolving credit facility and contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in our $2.5 Billion Credit Agreement, adjusted for all noncash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5.5 to 1 at March 31, 2019, and 5.0 to 1 thereafter. Once the covenant decreases to 5.0 to 1, if we consummate one or more acquisitions in which the aggregate purchase is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will increase to 5.5 to 1 for the quarter in which the acquisition is completed and the two following quarters. At March 31, 2019, we had no borrowings outstanding, our ratio of indebtedness to adjusted EBITDA was 3.6 to 1, and we were in compliance with all covenants under our $2.5 Billion Credit Agreement.

Debt Issuances - In March 2019, we completed an underwritten public offering of $1.25 billion senior unsecured notes consisting of $700 million, 4.35% senior notes due 2029 and an additional issuance of $550 million of our existing 5.2% senior notes due 2048. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, and exclusive of accrued interest, were $1.23 billion. The proceeds were used for general corporate purposes, which included repayment of existing indebtedness and funding capital expenditures.

In November 2018, we entered into our $1.5 Billion Term Loan Agreement with a syndicate of banks, which is available to be drawn until May 2019. Our $1.5 Billion Term Loan Agreement matures in November 2021 and bears interest at LIBOR plus 112.5 basis points based on our current credit ratings. As of March 31, 2019, we had borrowings totaling $750 million

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outstanding under our $1.5 Billion Term Loan Agreement, which were used for general corporate purposes, including repayment of existing indebtedness and funding capital expenditures.

Debt Repayments - We repaid our $500 million, 8.625% senior notes due March 2019 with a combination of cash on hand and short-term borrowings.

For additional discussion of our $2.5 Billion Credit Agreement and our $1.5 Billion Term Loan Agreement, see Note F of the Notes to Consolidated Financial Statements in our Annual Report.


E.	EQUITY

Noncontrolling Interests - In July 2018, we acquired the remaining 20% interest that we did not own in WTLPG for $195 million with cash on hand. We are now the sole owner of the West Texas LPG pipeline system.

Equity Issuances - In July 2017, we established an “at-the-market” equity program for the offer and sale from time to time of our common stock up to an aggregate amount of $1 billion. The program allows us to offer and sell our common stock at prices we deem appropriate through a sales agent. Sales of our common stock may be made by means of ordinary brokers’ transactions on the NYSE, in block transactions or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common stock under the program. No shares have been sold through our “at-the-market” equity program since December 2017.

In January 2018, we completed an underwritten public offering of 21.9 million shares of our common stock, generating net proceeds of $1.2 billion. We used the net proceeds from this offering to fund capital expenditures and for general corporate purposes, which included repaying a portion of our outstanding indebtedness.

Dividends - Holders of our common stock share equally in any dividend declared by our board of directors, subject to the rights of the holders of outstanding preferred stock. Dividends paid on our common stock in February 2019 were $0.86 per share. A dividend of $0.865 per share was declared for shareholders of record at the close of business on April 29, 2019, payable May 15, 2019.

The Series E Preferred Stock pays quarterly dividends on each share of Series E Preferred Stock, when, as and if declared by our Board of Directors, at a rate of 5.5% per year. We paid dividends for the Series E Preferred Stock of $0.3 million in February 2019. Dividends totaling $0.3 million were declared for the Series E Preferred Stock and are payable May 15, 2019.


F.	ACCUMULATED OTHER COMPREHENSIVE LOSS

The following table sets forth the balance in accumulated other comprehensive loss for the period indicated:



	Unrealized Gains (Losses) on Risk- Management Assets/Liabilities (a)			Retirement and Other Postretirement Benefit Plan Obligations (a) (b)			Unrealized Gains (Losses) on Risk- Management Assets/Liabilities of Unconsolidated Affiliates (a)			Accumulated Other Comprehensive Loss (a)
	(Thousands of dollars)
January 1, 2019	$	(64,660	)	$	(121,785	)	$	(1,794	)	$	(188,239	)
Other comprehensive income (loss) before reclassifications	(68,944		)	(104		)	(2,453		)	(71,501		)
Amounts reclassified from accumulated other comprehensive loss	(12,171		)	2,445			(58		)	(9,784		)
Other comprehensive income (loss)	(81,115		)	2,341			(2,511		)	(81,285		)
March 31, 2019	$	(145,775	)	$	(119,444	)	$	(4,305	)	$	(269,524	)

(a) - All amounts are presented net of tax.

(b) - Includes amounts related to supplemental executive retirement plan.

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The following table sets forth information about the balance of accumulated other comprehensive loss at March 31, 2019, representing unrealized gains (losses) related to risk-management assets and liabilities:



	Risk- Management Assets/Liabilities (a)
	(Thousands of dollars)
Commodity derivative instruments expected to be realized within the next 21 months (b)	$	6,422
Settled interest-rate swaps to be recognized over the life of the long-term, fixed-rate debt (c)	(36,709		)
Interest-rate swaps with future settlement dates expected to be amortized over the life of long-term debt	(115,488		)
Accumulated other comprehensive loss at March 31, 2019	$	(145,775	)

(a) - All amounts are presented net of tax.

(b) - Based on March 31, 2019, commodity prices, we will realize $5.6 million in net gains, net of tax, over the next 12 months and $0.8 million in net gains, net of tax, thereafter.

(c) - Losses of $13.6 million, net of tax, will be reclassified into earnings during the next 12 months as the hedged items affect earnings.

The remaining amounts in accumulated other comprehensive loss relate primarily to our retirement and other postretirement benefit plan obligations, which are expected to be amortized over the average remaining service period of employees participating in these plans.

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



Details about Accumulated Other Comprehensive Loss Components	Three Months Ended						Affected Line Item in the Consolidated Statements of Income
	March 31,
	2019			2018
	(Thousands of dollars)
Risk-management assets/liabilities
Commodity contracts	$	18,852		$	(11,611	)	Commodity sales revenues/cost of sales and fuel
Interest-rate contracts	(2,504		)	(3,943		)	Interest expense
	16,348			(15,554		)	Income before income taxes
	(4,177		)	3,578			Income taxes
	$	12,171		$	(11,976	)	Net income

Retirement and other postretirement benefit plan obligations (a)
Amortization of net loss	$	(3,232	)	$	(4,592	)	Other income (expense)
Amortization of unrecognized prior service credit	57			415			Other income (expense)
	(3,175		)	(4,177		)	Income before income taxes
	730			961			Income taxes
	$	(2,445	)	$	(3,216	)	Net income

Risk-management assets/liabilities of unconsolidated affiliates
Interest-rate contracts	$	75		$	47		Equity in net earnings from investments
	(17		)	(11		)	Income taxes
	$	58		$	36		Net income

Total reclassifications for the period	$	9,784		$	(15,156	)	Net income

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

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G.	EARNINGS PER SHARE

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



	Three Months Ended March 31, 2019
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS
Net income available for common stock	$	336,933	412,908	$	0.82
Diluted EPS
Effect of dilutive securities	—		2,325
Net income available for common stock and common stock equivalents	$	336,933	415,233	$	0.81



	Three Months Ended March 31, 2018
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS
Net income attributable to ONEOK available for common stock	$	264,233	409,676	$	0.65
Diluted EPS
Effect of dilutive securities	—		2,497
Net income attributable to ONEOK available for common stock and common stock equivalents	$	264,233	412,173	$	0.64


H.	EMPLOYEE BENEFIT PLANS

The following table sets forth the components of net periodic benefit cost (income) for our retirement and other postretirement benefit plans for the periods indicated:



	Retirement Benefits						Other Postretirement Benefits
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2019			2018			2019			2018
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	1,954		$	1,832		$	117		$	211
Interest cost	5,126			4,408			509			527
Expected return on plan assets	(5,892		)	(5,969		)	(570		)	(672		)
Amortization of prior service credit	—			—			(57		)	(415		)
Amortization of net loss	3,158			4,258			74			334
Net periodic benefit cost (income)	$	4,346		$	4,529		$	73		$	(15	)

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I.	UNCONSOLIDATED AFFILIATES

Equity in Net Earnings from Investments - The following table sets forth our equity in net earnings (loss) from investments for the periods indicated:



	Three Months Ended
	March 31,
	2019			2018
	(Thousands of dollars)
Northern Border Pipeline	$	20,802		$	17,137
Overland Pass Pipeline Company	17,394			16,387
Roadrunner Gas Transmission	6,338			4,958
Other	(1,053		)	1,705
Equity in net earnings from investments	$	43,481		$	40,187

Unconsolidated Affiliates Financial Information - The following table sets forth summarized combined financial information of our unconsolidated affiliates for the periods indicated:



	Three Months Ended
	March 31,
	2019		2018
	(Thousands of dollars)
Income Statement
Revenues	$	167,046	$	158,908
Operating expenses	$	69,800	$	68,401
Net income	$	90,897	$	84,480

Distributions paid to us	$	59,463	$	49,816

We incurred expenses in transactions with unconsolidated affiliates of $41.8 million and $37.5 million for the three months ended March 31, 2019 and 2018, respectively, primarily related to Overland Pass Pipeline Company and Northern Border Pipeline. Accounts payable to our equity-method investees at March 31, 2019, and December 31, 2018, were $14.1 million and $14.7 million, respectively.

We have an operating agreement with Roadrunner that provides for reimbursement or payment to us for management services and certain operating costs. Reimbursements and payments from Roadrunner included in operating income in our Consolidated Statements of Income for the three months ended March 31, 2019 and 2018, were not material.


J.	COMMITMENTS AND CONTINGENCIES

Environmental Matters and Pipeline Safety - The operation of pipelines, plants and other facilities for the gathering, processing, transportation and storage of natural gas, NGLs, condensate and other products is subject to numerous and complex laws and regulations pertaining to health, safety and the environment. As an owner and/or operator of these facilities, we must comply with laws and regulations that relate to facility/pipeline safety and integrity as well as air and water quality, hazardous and solid waste management and disposal, cultural resource protection and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with these laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation or construction. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows.

Legal Proceedings - Gas Index Pricing Litigation - As previously reported, in March 2017, the United States District Court for the District of Nevada (the Nevada District Court) granted summary judgment to ONEOK Energy Services Company, L.P. (OESC) in Sinclair Oil Corporation v. ONEOK Energy Services Company, L.P. (filed in the United States District Court for the District of Wyoming (the Wyoming District Court) in September 2005, transferred to MDL-1566 in the Nevada District Court). In September 2017, the Nevada District Court entered a final judgment in favor of OESC in Sinclair, which was appealed by Sinclair Oil Corporation to the Ninth Circuit Court of Appeals. In August 2018, the Ninth Circuit Court of Appeals reversed

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the Nevada District Court’s granting of summary judgment and remanded the case back to the Nevada District Court. In February 2019, Sinclair was further remanded back to the Wyoming District Court. We expect that future charges, if any, from the ultimate resolution of the Sinclair case will not be material to our results of operations, financial position or cash flows.

Other Legal Proceedings - We are a party to various other litigation matters and claims that have arisen in the normal course of our operations. While the results of these litigation matters 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 consolidated results of operations, financial position or cash flows.


K.	LEASES

Adoption of ASC Topic 842: Leases - We adopted Topic 842 using the modified retrospective method and the optional transition method to record the adoption impact through a cumulative-effect adjustment to retained earnings as of January 1, 2019. Results for reporting periods beginning after January 1, 2019, are presented under Topic 842, while prior periods are not adjusted and continue to be reported under the accounting standards in effect for those periods.

Practical Expedients and Policies Elected - We applied the short-term policy election, which allows us to exclude from recognition leases with an initial term of 12 months or less. We elected the hindsight expedient, which allows us to use hindsight in assessing lease term; the package of practical expedients permitted under the guidance, which among other things, allows us to carry forward the historical lease classification; and the land easement expedient, which allows us to apply the guidance prospectively at adoption for land easements on existing agreements.

Adoption - Adoption of Topic 842 resulted in new operating lease assets and lease liabilities on our Consolidated Balance Sheet of $17.5 million and $17.4 million, respectively, as of January 1, 2019. The difference between the lease assets and lease liabilities was recorded as an adjustment to the beginning balance of retained earnings, which represents the cumulative impact of adopting the standard. Our accounting for finance leases did not change. Adoption of Topic 842 did not materially impact our Consolidated Financial Statements.

Leases - We lease certain buildings, warehouses, office space, land and equipment, including pipeline equipment, rail cars and information technology equipment. Our lease payments are generally straight-line and the exercise of lease renewal options, which vary in term, is at our sole discretion. We include renewal periods in a lease term if we are reasonably certain to exercise available renewal options. Our lease agreements do not include any residual value guarantees or material restrictive covenants.

Through ONEOK Leasing Company, L.L.C. and ONEOK Parking Company, L.L.C., we own an office building and a parking garage and lease excess space in these facilities to affiliates and others. Our consolidated lease income is not material.

For the three months ended March 31, 2019, cash paid for amounts included in the measurement of our lease liabilities was not material.

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The following table sets forth information about our lease assets and liabilities included in our Consolidated Balance Sheet for the period indicated:



Leases	Location in our Consolidated Balance Sheet	March 31, 2019
		(Thousands of dollars)
Assets
Operating lease assets	Other assets	$	16,374
Finance lease assets	Property, plant and equipment	28,286
Finance lease assets	Accumulated depreciation	(471		)
Total leased assets		$	44,189

Liabilities
Current
Operating	Other current liabilities	$	4,497
Finance	Finance lease liability	1,809
Noncurrent
Operating	Other deferred credits	12,281
Finance	Finance lease liability	25,775
Total lease liabilities		$	44,362

The following table sets forth information about our leases for the periods indicated:



	Location in our Consolidated Statement of Income	Three Months Ended March 31, 2019		At March 31, 2019
	Location in our Consolidated Statement of Income	Lease cost		Weighted-Average Remaining Lease Term	Weighted-Average Discount Rate (a)
		(Thousands of dollars)		(Years)
Operating leases	Operations and maintenance	$	1,730	9.3	4.58%
Finance lease				9.6	10.00%
Amortization of lease assets	Depreciation and amortization	283
Interest on lease liabilities	Interest expense	697
Total lease cost		$	2,710

(a) - Our weighted-average discount rates represent the rate implicit in the lease or our incremental borrowing rate for a term equal to the remaining term of the lease.

The following table sets forth the maturity of our lease liabilities as of March 31, 2019:



	Finance Lease		Operating Leases
	(Millions of dollars)
Remainder of 2019	$	3.4	$	5.1
2020	4.5		1.8
2021	4.5		1.7
2022	4.5		1.6
2023	4.5		1.6
2024 and beyond	21.6		9.2
Total lease payments	43.0		21.0
Less: Interest	15.4		4.2
Present value of lease liabilities	$	27.6	$	16.8

Our future lease payments presented under the previous accounting standard as of December 31, 2018, are not materially different than those presented above.

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L.	REVENUES

Accounting Policies - Our revenue recognition policy is described in Note A of the Notes to Consolidated Financial Statements in our Annual Report.

Contract Assets and Contract Liabilities - The following tables set forth the balances in contract assets and contract liabilities for the periods indicated:



Contract Assets	(Millions of dollars)
Balance at January 1, 2019 (a)	$	6.2
Amounts invoiced in excess of revenue recognized	(0.7		)
Balance at March 31, 2019 (b)	$	5.5

(a) - Contract assets of $1.7 million and $4.5 million are included in other current assets and other assets, respectively, in our Consolidated Balance Sheets.

(b) - Contract assets of $1.3 million and $4.2 million are included in other current assets and other assets, respectively, in our Consolidated Balance Sheets.



Contract Liabilities	(Millions of dollars)
Balance at January 1, 2019 (a)	$	31.7
Revenue recognized included in beginning balance	(13.2		)
Net additions	13.0
Balance at March 31, 2019 (b)	$	31.5

(a) - Contract liabilities of $15.6 million and $16.1 million are included in other current liabilities and other deferred credits, respectively, in our Consolidated Balance Sheets.

(b) - Contract liabilities of $10.6 million and $20.9 million are included in other current liabilities and other deferred credits, respectively, in our Consolidated Balance Sheets.

Receivables from Customers and Revenue Disaggregation - Substantially all of the balances in accounts receivable on our Consolidated Balance Sheets at March 31, 2019, and December 31, 2018, relate to customer receivables. Revenues sources are disaggregated in Note M.

Practical Expedients - We do not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) variable consideration on contracts for which we recognize revenue at the amount to which we have the right to invoice for services performed.

Transaction Price Allocated to Unsatisfied Performance Obligations - The following table presents aggregate value allocated to unsatisfied performance obligations as of March 31, 2019, and the amounts we expect to recognize in revenue in future periods, related primarily to firm transportation and storage contracts with remaining contract terms ranging from one month to 25 years:



Expected Period of Recognition in Revenue	(Millions of dollars)
Remainder of 2019	$	258.0
2020	296.0
2021	264.0
2022	202.3
2023 and beyond	907.9
Total estimated transaction price allocated to unsatisfied performance obligations	$	1,928.2

The table above excludes variable consideration allocated entirely to wholly unsatisfied performance obligations, wholly unsatisfied promises to transfer distinct goods or services that are part of a single performance obligation and consideration we determine to be fully constrained. The amounts we determined to be fully constrained relate to future sales obligations under long-term sales contracts where the transaction price is not known and minimum volume agreements, which we consider to be fully constrained until invoiced.


M.	SEGMENTS

Segment Descriptions - Our operations are divided into three reportable business segments, as follows:


•	our Natural Gas Gathering and Processing segment gathers, treats and processes natural gas;

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•	our Natural Gas Liquids segment gathers, treats, fractionates and transports NGLs and stores, markets and distributes NGL products; and


•	our Natural Gas Pipelines segment operates regulated interstate and intrastate natural gas transmission pipelines and natural gas storage facilities.

Other and eliminations consist of corporate costs, the operating and leasing activities of our headquarters building and related parking facility and eliminations necessary to reconcile our reportable segments to our Consolidated Financial Statements.

Accounting Policies - The accounting policies of the segments are described in Note A of the Notes to Consolidated Financial Statements in our Annual Report.

Operating Segment Information - The following tables set forth certain selected financial information for our operating segments for the periods indicated:



Three Months Ended March 31, 2019	Natural Gas Gathering and Processing			Natural Gas Liquids (a)			Natural Gas Pipelines (b)			Total Segments
	(Thousands of dollars)
NGL and condensate sales	$	332,332		$	2,158,103		$	—		$	2,490,435
Residue natural gas sales	319,036			—			970			320,006
Gathering, processing and exchange services revenue	39,742			98,534			—			138,276
Transportation and storage revenue	—			52,322			103,470			155,792
Other	3,551			2,541			11,960			18,052
Total revenues (c)	694,661			2,311,500			116,400			3,122,561

Cost of sales and fuel (exclusive of depreciation and operating costs)	(450,913		)	(1,846,673		)	(1,755		)	(2,299,341		)
Operating costs	(94,247		)	(110,438		)	(36,268		)	(240,953		)
Equity in net earnings (loss) from investments	(1,202		)	17,544			27,139			43,481
Noncash compensation expense and other	3,945			5,706			1,132			10,783
Segment adjusted EBITDA	$	152,244		$	377,639		$	106,648		$	636,531

Depreciation and amortization	$	(52,681	)	$	(46,401	)	$	(14,156	)	$	(113,238	)
Total assets	$	6,208,883		$	10,220,412		$	2,138,759		$	18,568,054
Capital expenditures	$	215,148		$	639,338		$	28,688		$	883,174

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $323.1 million, of which $270.0 million related to sales within the segment, and cost of sales and fuel of $118.5 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $70.1 million and cost of sales and fuel of $5.6 million.

(c) - Intersegment revenues for the Natural Gas Gathering and Processing, Natural Gas Liquids and Natural Gas Pipelines segments totaled $335.8 million, $3.5 million and $3.9 million, respectively.

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Three Months Ended March 31, 2019	Total Segments			Other and Eliminations			Total
	(Thousands of dollars)
Reconciliations of total segments to consolidated
NGL and condensate sales	$	2,490,435		$	(338,351	)	$	2,152,084
Residue natural gas sales	320,006			—			320,006
Gathering, processing and exchange services revenue	138,276			—			138,276
Transportation and storage revenue	155,792			(2,521		)	153,271
Other	18,052			(1,731		)	16,321
Total revenues (a)	$	3,122,561		$	(342,603	)	$	2,779,958

Cost of sales and fuel (exclusive of depreciation and operating costs)	$	(2,299,341	)	$	342,964		$	(1,956,377	)
Operating costs	$	(240,953	)	$	212		$	(240,741	)
Depreciation and amortization	$	(113,238	)	$	(920	)	$	(114,158	)
Equity in net earnings from investments	$	43,481		$	—		$	43,481
Total assets	$	18,568,054		$	366,271		$	18,934,325
Capital expenditures	$	883,174		$	6,531		$	889,705

(a) - Noncustomer revenue for the three months ended March 31, 2019, totaled $22.3 million related primarily to gains reclassified from accumulated other comprehensive loss from commodity derivative contracts.



Three Months Ended March 31, 2018	Natural Gas Gathering and Processing			Natural Gas Liquids (a)			Natural Gas Pipelines (b)			Total Segments
	(Thousands of dollars)
NGL and condensate sales	$	413,157		$	2,552,770		$	—		$	2,965,927
Residue natural gas sales	254,997			—			4,919			259,916
Gathering, processing and exchange services revenue	38,429			83,258			—			121,687
Transportation and storage revenue	—			53,478			98,338			151,816
Other	1,408			2,963			6,654			11,025
Total revenues (c)	707,991			2,692,469			109,911			3,510,371

Cost of sales and fuel (exclusive of depreciation and operating costs)	(492,622		)	(2,281,072		)	(5,454		)	(2,779,148		)
Operating costs	(88,359		)	(88,592		)	(33,190		)	(210,141		)
Equity in net earnings from investments	1,668			16,424			22,095			40,187
Other	1,873			2,850			263			4,986
Segment adjusted EBITDA	$	130,551		$	342,079		$	93,625		$	566,255

Depreciation and amortization	$	(47,748	)	$	(42,427	)	$	(13,269	)	$	(103,444	)
Total assets	$	5,462,305		$	8,370,364		$	2,060,700		$	15,893,369
Capital expenditures	$	111,729		$	124,921		$	19,898		$	256,548

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $300.0 million, of which $253.4 million related to sales within the segment, and cost of sales and fuel of $122.8 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $68.0 million and cost of sales and fuel of $9.1 million.

(c) - Intersegment revenues for the Natural Gas Gathering and Processing, Natural Gas Liquids and Natural Gas Pipelines segments totaled $397.8 million, $9.0 million and $2.1 million, respectively.

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Three Months Ended March 31, 2018	Total Segments			Other and Eliminations			Total
	(Thousands of dollars)
Reconciliations of total segments to consolidated
NGL and condensate sales	$	2,965,927		$	(408,910	)	$	2,557,017
Residue natural gas sales	259,916			2,250			262,166
Gathering, processing and exchange services revenue	121,687			(21		)	121,666
Transportation and storage revenue	151,816			(2,094		)	149,722
Other	11,025			481			11,506
Total revenues (a)	$	3,510,371		$	(408,294	)	$	3,102,077

Cost of sales and fuel (exclusive of depreciation and operating costs)	$	(2,779,148	)	$	411,122		$	(2,368,026	)
Operating costs	$	(210,141	)	$	(63	)	$	(210,204	)
Depreciation and amortization	$	(103,444	)	$	(793	)	$	(104,237	)
Equity in net earnings from investments	$	40,187		$	—		$	40,187
Total assets	$	15,893,369		$	538,978		$	16,432,347
Capital expenditures	$	256,548		$	7,919		$	264,467

(a) - Noncustomer revenue for the three months ended March 31, 2018, totaled $(9.0) million related primarily to losses reclassified from accumulated other comprehensive loss from commodity derivative contracts.



	Three Months Ended
	March 31,
	2019			2018
	(Thousands of dollars)
Reconciliation of net income to total segment adjusted EBITDA
Net income	$	337,208		$	266,049
Add:
Interest expense, net of capitalized interest	115,420			115,725
Depreciation and amortization	114,158			104,237
Income taxes	77,934			75,771
Noncash compensation expense	5,540			9,226
Other corporate costs and noncash items	(13,729		)	(4,753		)
Total segment adjusted EBITDA	$	636,531		$	566,255


N.	SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

ONEOK and ONEOK Partners are issuers of certain public debt securities. We, ONEOK Partners and the Intermediate Partnership guarantee the indebtedness of ONEOK and ONEOK Partners. The Intermediate Partnership holds all of ONEOK Partners’ partnership interests and equity in its subsidiaries, as well as a 50 percent interest in Northern Border Pipeline. In lieu of providing separate financial statements for each subsidiary issuer and guarantor, we have included the accompanying condensed consolidating financial statements based on Rule 3-10 of the SEC’s Regulation S-X. We have presented each of the parent and subsidiary issuers in separate columns in this single set of condensed consolidating financial statements.

For purposes of the following footnote:


•	we are referred to as “Parent Issuer and Guarantor”;


•	ONEOK Partners is referred to as “Subsidiary Issuer and Guarantor”;


•	the Intermediate Partnership is referred to as “Guarantor Subsidiary”; and


•	the “Non-Guarantor Subsidiaries” are all subsidiaries other than the Guarantor Subsidiary and Subsidiary Issuer and Guarantor.

The following unaudited supplemental condensed consolidating financial information is presented on an equity-method basis reflecting the separate accounts of ONEOK, ONEOK Partners and the Intermediate Partnership, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations, and our consolidated amounts for the periods indicated.

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Condensed Consolidating Statements of Income



	Three Months Ended March 31, 2019
(Unaudited)	Parent Issuer & Guarantor			Subsidiary Issuer & Guarantor			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Revenues
Commodity sales	$	—		$	—		$	—		$	2,473.0		$	—		$	2,473.0
Services	—			—			—			307.5			(0.5		)	307.0
Total revenues	—			—			—			2,780.5			(0.5		)	2,780.0
Cost of sales and fuel (exclusive of items shown separately below)	—			—			—			1,956.4			—			1,956.4
Operating expenses	—			—			—			355.5			(0.5		)	355.0
Gain on sale of assets	—			—			—			(0.1		)	—			(0.1		)
Operating income	—			—			—			468.7			—			468.7
Equity in net earnings from investments	456.7			460.6			460.6			30.1			(1,364.5		)	43.5
Other income (expense), net	6.8			81.0			81.0			11.5			(162.0		)	18.3
Interest expense, net	(52.8		)	(81.0		)	(81.0		)	(62.6		)	162.0			(115.4		)
Income before income taxes	410.7			460.6			460.6			447.7			(1,364.5		)	415.1
Income taxes	(73.5		)	—			—			(4.4		)	—			(77.9		)
Net income	337.2			460.6			460.6			443.3			(1,364.5		)	337.2
Less: Preferred stock dividends	0.3			—			—			—			—			0.3
Net income available to common shareholders	$	336.9		$	460.6		$	460.6		$	443.3		$	(1,364.5	)	$	336.9



	Three Months Ended March 31, 2018
(Unaudited)	Parent Issuer & Guarantor			Subsidiary Issuer & Guarantor			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Revenues
Commodity sales	$	—		$	—		$	—		$	2,820.0		$	—		$	2,820.0
Services	—			—			—			282.6			(0.5		)	282.1
Total revenues	—			—			—			3,102.6			(0.5		)	3,102.1
Cost of sales and fuel (exclusive of items shown separately below)	—			—			—			2,368.0			—			2,368.0
Operating expenses	(0.7		)	—			—			315.7			(0.5		)	314.5
Gain on sale of assets	—			—			—			(0.1		)	—			(0.1		)
Operating income	0.7			—			—			419.0			—			419.7
Equity in net earnings from investments	368.5			370.9			370.9			28.6			(1,098.7		)	40.2
Other income (expense), net	7.2			77.1			77.1			(9.6		)	(154.2		)	(2.4		)
Interest expense, net	(39.8		)	(77.1		)	(77.1		)	(75.9		)	154.2			(115.7		)
Income before income taxes	336.6			370.9			370.9			362.1			(1,098.7		)	341.8
Income taxes	(72.1		)	—			—			(3.7		)	—			(75.8		)
Net income	264.5			370.9			370.9			358.4			(1,098.7		)	266.0
Less: Net income attributable to noncontrolling interests	—			—			—			1.5			—			1.5
Net income attributable to ONEOK	264.5			370.9			370.9			356.9			(1,098.7		)	264.5
Less: Preferred stock dividends	0.3			—			—			—			—			0.3
Net income available to common shareholders	$	264.2		$	370.9		$	370.9		$	356.9		$	(1,098.7	)	$	264.2

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Condensed Consolidating Statements of Comprehensive Income



	Three Months Ended March 31, 2019
(Unaudited)	Parent Issuer & Guarantor			Subsidiary Issuer & Guarantor			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Net income	$	337.2		$	460.6		$	460.6		$	443.3		$	(1,364.5	)	$	337.2
Other comprehensive income (loss), net of tax
Unrealized gains (losses) on derivatives, net of tax	(52.3		)	(21.6		)	(21.6		)	(16.7		)	43.3			(68.9		)
Realized (gains) losses on derivatives recognized in net income, net of tax	(1.1		)	(14.4		)	(18.9		)	(15.5		)	37.7			(12.2		)
Change in retirement and other postretirement benefit plan liability, net of tax	2.4			(0.1		)	—			—			—			2.3
Other comprehensive income (loss) on investments in unconsolidated affiliates, net of tax	—			(3.3		)	(3.3		)	(2.5		)	6.6			(2.5		)
Total other comprehensive income (loss), net of tax	(51.0		)	(39.4		)	(43.8		)	(34.7		)	87.6			(81.3		)
Comprehensive income	$	286.2		$	421.2		$	416.8		$	408.6		$	(1,276.9	)	$	255.9



	Three Months Ended March 31, 2018
(Unaudited)	Parent Issuer & Guarantor		Subsidiary Issuer & Guarantor			Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidating Entries			Total
	(Millions of dollars)
Net income	$	264.5	$	370.9		$	370.9	$	358.4	$	(1,098.7	)	$	266.0
Other comprehensive income (loss), net of tax
Unrealized gains (losses) on derivatives, net of tax	18.4		20.9			20.9		16.1		(41.8		)	34.5
Realized (gains) losses on derivatives recognized in net income, net of tax	0.9		14.3			11.6		8.3		(23.1		)	12.0
Change in retirement and other postretirement benefit plan liability, net of tax	3.2		(0.6		)	—		—		—			2.6
Other comprehensive income (loss) on investments in unconsolidated affiliates, net of tax	—		3.7			3.7		2.8		(7.4		)	2.8
Total other comprehensive income (loss), net of tax	22.5		38.3			36.2		27.2		(72.3		)	51.9
Comprehensive income	287.0		409.2			407.1		385.6		(1,171.0		)	317.9
Less: Comprehensive income attributable to noncontrolling interests	—		—			—		1.5		—			1.5
Comprehensive income attributable to ONEOK	$	287.0	$	409.2		$	407.1	$	384.1	$	(1,171.0	)	$	316.4

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Condensed Consolidating Balance Sheets



	March 31, 2019
(Unaudited)	Parent Issuer & Guarantor		Subsidiary Issuer & Guarantor		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidating Entries			Total
Assets	(Millions of dollars)
Current assets
Cash and cash equivalents	$	27.8	$	—	$	—	$	—	$	—		$	27.8
Accounts receivable, net	—		—		—		812.9		—			812.9
Materials and supplies	—		—		—		163.7		—			163.7
Natural gas and natural gas liquids in storage	—		—		—		243.2		—			243.2
Other current assets	12.1		—		—		83.1		—			95.2
Total current assets	39.9		—		—		1,302.9		—			1,342.8
Property, plant and equipment
Property, plant and equipment	148.6		—		—		18,739.1		—			18,887.7
Accumulated depreciation and amortization	93.9		—		—		3,275.8		—			3,369.7
Net property, plant and equipment	54.7		—		—		15,463.3		—			15,518.0
Investments and other assets
Investments	6,251.4		3,631.9		10,109.9		783.1		(19,825.4		)	950.9
Intercompany notes receivable	6,523.9		7,189.5		711.5		—		(14,424.9		)	—
Other assets	127.6		—		—		995.9		(0.9		)	1,122.6
Total investments and other assets	12,902.9		10,821.4		10,821.4		1,779.0		(34,251.2		)	2,073.5
Total assets	$	12,997.5	$	10,821.4	$	10,821.4	$	18,545.2	$	(34,251.2	)	$	18,934.3
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	—	$	300.0	$	—	$	7.7	$	—		$	307.7
Accounts payable	6.2		—		—		1,021.1		—			1,027.3
Other current liabilities	73.1		64.0		—		217.6		—			354.7
Total current liabilities	79.3		364.0		—		1,246.4		—			1,689.7

Intercompany debt	—		—		7,189.5		7,235.4		(14,424.9		)	—

Long-term debt, excluding current maturities	5,942.7		4,042.3		—		19.3		—			10,004.3

Deferred credits and other liabilities	533.5		—		—		265.7		(0.9		)	798.3

Commitments and contingencies

Equity	6,442.0		6,415.1		3,631.9		9,778.4		(19,825.4		)	6,442.0
Total liabilities and equity	$	12,997.5	$	10,821.4	$	10,821.4	$	18,545.2	$	(34,251.2	)	$	18,934.3

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	December 31, 2018
(Unaudited)	Parent Issuer & Guarantor		Subsidiary Issuer & Guarantor		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidating Entries			Total
Assets	(Millions of dollars)
Current assets
Cash and cash equivalents	$	12.0	$	—	$	—	$	—	$	—		$	12.0
Accounts receivable, net	—		—		—		819.0		—			819.0
Materials and supplies	—		—		—		141.2		—			141.2
Natural gas and natural gas liquids in storage	—		—		—		296.7		—			296.7
Other current assets	29.1		—		—		100.6		—			129.7
Total current assets	41.1		—		—		1,357.5		—			1,398.6
Property, plant and equipment
Property, plant and equipment	145.5		—		—		17,885.5		—			18,031.0
Accumulated depreciation and amortization	92.0		—		—		3,172.3		—			3,264.3
Net property, plant and equipment	53.5		—		—		14,713.2		—			14,766.7
Investments and other assets
Investments	6,153.5		3,548.1		9,721.6		791.1		(19,245.1		)	969.2
Intercompany notes receivable	5,308.6		7,701.5		1,528.0		—		(14,538.1		)	—
Other assets	115.9		—		—		982.3		(1.0		)	1,097.2
Total investments and other assets	11,578.0		11,249.6		11,249.6		1,773.4		(33,784.2		)	2,066.4
Total assets	$	11,672.6	$	11,249.6	$	11,249.6	$	17,844.1	$	(33,784.2	)	$	18,231.7
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	—	$	500.0	$	—	$	7.7	$	—		$	507.7
Accounts payable	31.3		—		—		1,085.0		—			1,116.3
Other current liabilities	123.2		81.0		—		280.2		—			484.4
Total current liabilities	154.5		581.0		—		1,372.9		—			2,108.4

Intercompany debt	—		—		7,701.5		6,836.6		(14,538.1		)	—

Long-term debt, excluding current maturities	4,510.7		4,341.4		—		21.2		—			8,873.3

Deferred credits and other liabilities
Deferred income taxes	112.3		—		—		108.4		(1.0		)	219.7
Other deferred credits	315.6		—		—		135.2		—			450.8
Total deferred credits and other liabilities	427.9		—		—		243.6		(1.0		)	670.5

Commitments and contingencies

Equity	6,579.5		6,327.2		3,548.1		9,369.8		(19,245.1		)	6,579.5
Total liabilities and equity	$	11,672.6	$	11,249.6	$	11,249.6	$	17,844.1	$	(33,784.2	)	$	18,231.7

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Condensed Consolidating Statements of Cash Flows



	Three Months Ended March 31, 2019
(Unaudited)	Parent Issuer & Guarantor			Subsidiary Issuer & Guarantor			Guarantor Subsidiary				Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Operating activities
Cash provided by operating activities	$	207.4		$	320.6		$	20.8			$	470.8		$	(666.0	)	$	353.6
Investing activities
Capital expenditures	(6.4		)	—			—				(883.3		)	—			(889.7		)
Contributions to unconsolidated affiliates	—			—			—				(1.0		)	—			(1.0		)
Other investing activities	—			—			7.7				18.2			—			25.9
Cash used in investing activities	(6.4		)	—			7.7				(866.1		)	—			(864.8		)
Financing activities
Dividends paid	(354.2		)	(333.0		)	(333.0		)		—			666.0			(354.2		)
Intercompany borrowings (advances), net	(1,214.6		)	512.4			304.5				397.7			—			—
Issuance of long-term debt, net of discounts	1,442.8			—			—				—			—			1,442.8
Repayment of long-term debt	—			(500.0		)	—				(1.9		)	—			(501.9		)
Issuance of common stock	4.8			—			—				—			—			4.8
Other, net	(64.0		)	—			—				(0.5		)	—			(64.5		)
Cash provided by financing activities	(185.2		)	(320.6		)	(28.5		)	—	395.3			666.0			527.0
Change in cash and cash equivalents	15.8			—			—				—			—			15.8
Cash and cash equivalents at beginning of period	12.0			—			—				—			—			12.0
Cash and cash equivalents at end of period	$	27.8		$	—		$	—			$	—		$	—		$	27.8

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	Three Months Ended March 31, 2018
(Unaudited)	Parent Issuer & Guarantor			Subsidiary Issuer & Guarantor			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Operating activities
Cash provided by operating activities	$	266.8		$	319.7		$	17.1		$	557.7		$	(666.0	)	$	495.3
Investing activities
Capital expenditures	(5.7		)	—			—			(258.8		)	—			(264.5		)
Contributions to unconsolidated affiliates	—			—			—			(0.1		)	—			(0.1		)
Other investing activities	—			—			5.0			4.0			—			9.0
Cash used in investing activities	(5.7		)	—			5.0			(254.9		)	—			(255.6		)
Financing activities
Dividends paid	(316.4		)	(333.0		)	(333.0		)	—			666.0			(316.4		)
Distributions to noncontrolling interests	—			—			—			(1.5		)	—			(1.5		)
Intercompany borrowings (advances), net	(514.5		)	513.3			310.9			(309.7		)	—			—
Borrowing (repayment) of short-term borrowings, net	(614.7		)	—			—			—			—			(614.7		)
Repayment of long-term debt	—			(500.0		)	—			(1.9		)	—			(501.9		)
Issuance of common stock	1,182.1			—			—			—			—			1,182.1
Other, net	(17.3		)	—			—			10.3			—			(7.0		)
Cash used in financing activities	(280.8		)	(319.7		)	(22.1		)	(302.8		)	666.0			(259.4		)
Change in cash and cash equivalents	(19.7		)	—			—			—			—			(19.7		)
Cash and cash equivalents at beginning of period	37.2			—			—			—			—			37.2
Cash and cash equivalents at end of period	$	17.5		$	—		$	—		$	—		$	—		$	17.5

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

The following discussion and analysis should be read in conjunction with our unaudited Consolidated Financial Statements and the Notes to Consolidated Financial Statements in this Quarterly Report, as well as our Annual Report.

RECENT DEVELOPMENTS

Please refer to the “Financial Results and Operating Information” and “Liquidity and Capital Resources” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Quarterly Report for additional information.

Business Update and Market Conditions - We operate primarily fee-based businesses in each of our three reportable segments, and we expect our consolidated earnings to be approximately 85% fee-based in 2019. We are connected to supply in growing basins and have significant basin diversification, including the Williston, Permian, Powder River and DJ Basins and the STACK and SCOOP areas. While our Natural Gas Gathering and Processing and Natural Gas Liquids segments generate primarily fee-based earnings, those segments’ results of operations are exposed to volumetric risk. Our exposure to volumetric risk can result from declining well productivity, reduced drilling activity, severe weather disruptions, operational outages and ethane rejection. Commodity prices decreased in the fourth quarter 2018 with a moderate recovery in the first quarter 2019 and are expected to continue to fluctuate in 2019. However, we do not expect supply volumes in our three business segments to be materially impacted.

Volumes increased across our operating regions in our Natural Gas Gathering and Processing and Natural Gas Liquids segments in the first quarter 2019, compared with the same period in 2018, as a result of continued improvements in production due to enhanced completion techniques and increased demand for NGL products from petrochemical and NGL export facilities in the Gulf Coast. To date, we have spent approximately $2.7 billion of our announced capital-growth projects that include NGL pipelines, NGL fractionators, natural gas processing plants and related natural gas infrastructure supported by a combination of long-term primarily fee-based contracts, volume commitments and/or acreage dedications. Our NGL projects in the Gulf Coast also allow flexibility to construct additional NGL fractionators, storage and potentially, new export facilities in the future. We expect these projects to meet the needs of natural gas processors and producers and the petrochemical industry that require additional midstream infrastructure to accommodate increasing supply and demand in the areas in which we operate.

In the first quarter 2019, compared with the same period in 2018, we benefited from favorable NGL location price differentials as available pipeline and fractionation capacity in and between the Conway, Kansas, and Mont Belvieu, Texas, market centers tightened due to growing NGL supply from the Mid-Continent and Rocky Mountain regions, combined with increased petrochemical and NGL export demand in the Gulf Coast, resulting in higher earnings from our Natural Gas Liquids segment’s optimization and marketing activities. While we expect NGL location price differentials to fluctuate in 2019, we expect that they will be wider than historical norms due to additional NGL supply growth delivered to the Mid-Continent region, additional demand in the Gulf Coast and continuing fractionation and pipeline constraints. We expect these wider NGL location price differentials to continue until announced NGL pipeline and fractionation infrastructure projects, including our Arbuckle II pipeline, are completed in early 2020.

Rocky Mountain Region - We expect each of our business segments to benefit from increased production in this region, which includes the Williston, Powder River and DJ Basins. In our Natural Gas Gathering and Processing segment, gathered and processed volumes in this region increased in the first quarter 2019, compared with the same period in 2018, due primarily to increased producer activity and completion of new well connections. With continued volume growth expected, we are constructing our Demicks Lake I and Demicks Lake II natural gas processing plants. These projects will provide an additional 400 MMcf/d of processing capacity, increasing our total to more than 1.4 Bcf/d in the Williston Basin, which is expected to help producers meet North Dakota’s natural gas capture targets, add incremental NGLs to our NGL gathering system and supply natural gas to our 50 percent-owned Northern Border Pipeline. Our Demicks Lake I plant is expected to reach capacity soon after its completion in the fourth quarter 2019 due to more than 275 MMcf/d of natural gas currently flaring on our dedicated acreage due primarily to lack of processing capacity. In our Natural Gas Liquids segment, the volume growth in this region has resulted in the Overland Pass pipeline, of which we own 50%, and our Bakken NGL pipeline operating at or near full capacity. We are constructing our Elk Creek pipeline to support expected supply growth and provide needed infrastructure to transport NGLs out of the region to the Mid-Continent with connectivity to the Gulf Coast. We expect the southern section of our Elk Creek pipeline to be complete early in the third quarter 2019, which would allow NGL production from the Powder River Basin to be transported on this section of pipeline before the entire Elk Creek pipeline project is complete, creating available capacity on our Bakken NGL pipeline to transport additional NGL volumes from the Williston Basin. We expect the

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Elk Creek pipeline to reach 100 MBbl/d in the first quarter 2020 due to a combination of volumes from our processing plants, third-party processing plants and volumes currently transported by rail. We recently announced a project to extend our Bakken NGL pipeline into an area of the Williston Basin with no current access to raw feed NGL pipeline takeaway capacity. This project will provide connectivity for third-party processing plants to key NGL market centers as well as provide additional volumes to our Elk Creek pipeline.

STACK and SCOOP - As producers continue to develop the STACK and SCOOP areas in Oklahoma, we expect increased demand for our services from producers that need incremental takeaway capacity for natural gas and NGLs out of the Mid-Continent region. In our Natural Gas Gathering and Processing segment, natural gas gathered and processed volumes increased in the first quarter 2019, compared with the same period in 2018, due primarily to the completion of the 200 MMcf/d expansion of our Canadian Valley natural gas processing plant, which increased our total processing capacity to 1.2 Bcf/d in the Mid-Continent region. In our Natural Gas Liquids segment, we are the largest NGL takeaway provider in the STACK and SCOOP areas. We are constructing our Arbuckle II pipeline to support expected supply growth and transport NGLs to the Gulf Coast market. We also plan to construct an extension of our Arbuckle II pipeline further north along with additional NGL gathering infrastructure, as well as an expansion of our Arbuckle II pipeline by 100 MBbl/d to a total capacity of 500 MBbl/d. In our Natural Gas Pipelines segment, we are connected to more than 30 natural gas processing plants in Oklahoma, and we completed expansions in 2018 to provide increased westbound transportation services from the STACK area. In the first quarter 2019, we completed an additional expansion of our ONEOK Gas Transportation pipeline with a 150 MMcf/d eastbound expansion from the STACK and SCOOP areas to an eastern Oklahoma interstate pipeline delivery point.

Permian Basin - We expect our Natural Gas Liquids and Natural Gas Pipelines business segments to benefit from increased production in the Permian Basin from the highly productive Delaware and Midland Basins. In our Natural Gas Liquids segment, we are well-positioned in the Permian Basin through our West Texas LPG pipeline system. Due to the recent expansion of the system and new plant connections, volumes increased in the first quarter 2019, compared with the same period in 2018. We expect volumes to continue to increase on our West Texas LPG pipeline system when the second expansion is completed, which will increase the mainline capacity out of the Permian Basin by 80 MBbl/d as well as connect our West Texas LPG pipeline with our Arbuckle II pipeline. These projects are expected to position our West Texas LPG pipeline system for significant future NGL volume growth and are backed by long-term acreage and/or plant dedications. In our Natural Gas Pipelines segment, our Roadrunner joint venture and our WesTex pipeline are well-positioned to serve growth in the Permian Basin. The Roadrunner pipeline connects with our existing natural gas pipeline and storage infrastructure in Texas and, together with our completed WesTex intrastate natural gas pipeline expansion project, creates future opportunities for us to deliver natural gas supply to Mexico and transport natural gas to other markets in the region.

Gulf Coast - Demand for NGLs is expected to continue to increase at the Mont Belvieu, Texas, NGL market center as new world-scale ethylene production projects, petrochemical plant expansions and NGL export facilities continue to be completed. NGL supply growth and new NGL pipelines recently completed or being constructed, including our Elk Creek pipeline, Arbuckle II pipeline and West Texas LPG pipeline projects, are increasing NGL deliveries to Mont Belvieu, Texas. While we have significant NGL fractionation and storage assets in this area, additional capacity is needed to accommodate expected volume growth. To respond to this need, we are constructing two additional 125 MBbl/d fractionators with related infrastructure in Mont Belvieu, Texas, MB-4 and MB-5, which are both fully contracted. Following the completion of MB-4 and MB-5, we expect our Gulf Coast NGL fractionation capacity to be approximately 600 MBbl/d and more than 1 million Bbl/d across our entire system. Our MB-5 project also includes system expansions that provide infrastructure capacity to support additional assets as we continue to evaluate opportunities for fractionation, storage and, potentially, export facilities to meet the supply and demand for NGLs.

Ethane Opportunity - Ethane volumes delivered to our NGL system generally have been increasing since 2016, primarily as a result of NGL demand increasing from exports and petrochemical companies completing ethylene production projects and plant expansions. Ethane volumes across our system increased to 410 MBbl/d in the first quarter 2019, compared with 355 MBbl/d in the first quarter 2018. Our NGL capital-growth projects are expected to help alleviate system constraints, enabling additional NGLs, including ethane, to reach the Mont Belvieu, Texas, market center. We expect the amount of ethane delivered to our system to continue to fluctuate as NGL supply continues to increase, petrochemical companies complete expansion projects and exports increase.

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Growth Projects - Our announced large capital-growth projects are outlined in the tables below:



Project	Scope	Approximate Costs (a)	Expected Completion
Natural Gas Gathering and Processing		(In millions)
Canadian Valley expansion and related infrastructure	200 MMcf/d processing plant expansion in the STACK area and related gathering infrastructure	160	Complete
	Increases capacity to more than 400 MMcf/d
	20 MBbl/d additional NGL volume
	Supported by acreage dedications, long-term primarily fee-based contracts and minimum volume commitments
Demicks Lake I plant and related infrastructure	200 MMcf/d processing plant and related infrastructure in the core of the Williston Basin	400	Fourth Quarter 2019
	Supported by acreage dedications with long-term primarily fee-based contracts
Demicks Lake II plant and related infrastructure	200 MMcf/d processing plant and related infrastructure in the core of the Williston Basin	410	First Quarter 2020
	Supported by acreage dedications with long-term primarily fee-based contracts
Total Natural Gas Gathering and Processing		$970

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Project	Scope	Approximate Costs (a)	Expected Completion
Natural Gas Liquids		(In millions)
West Texas LPG pipeline expansion	120-mile pipeline lateral extension with capacity of 110 MBbl/d in the Permian Basin	$200 (b)	Complete
	Supported by long-term dedicated NGL production from two planned third-party natural gas processing plants
Sterling III pipeline expansion and Arbuckle connection	60 MBbl/d NGL pipeline expansion	130	Complete
Sterling III pipeline expansion and Arbuckle connection	Increases capacity to 250 MBbl/d
	Includes additional NGL gathering system expansions
	Supported by long-term third-party contracts
Elk Creek pipeline and related infrastructure	900-mile NGL pipeline from the Williston Basin to the Mid-Continent region, with capacity of up to 240 MBbl/d, and related infrastructure	1,400	Fourth Quarter 2019 (c)
	Anchored by long-term contracts supported primarily by minimum volume commitments
	Expansion capability up to 400 MBbl/d with additional pump facilities
Arbuckle II pipeline and related infrastructure	530-mile NGL pipeline from the STACK area to Mont Belvieu, Texas, with initial capacity up to 400 MBbl/d, and related infrastructure	1,360	First Quarter 2020
	Supported by long-term contracts
	Expansion capability up to 1,000 MBbl/d
West Texas LPG pipeline expansion and Arbuckle II connection	Increasing mainline capacity by 80 MBbl/d with additional pump facilities and pipeline looping	295	First Quarter 2020
	Connecting West Texas LPG pipeline system to the previously announced Arbuckle II pipeline
	Supported by long-term dedicated production from six third-party processing plants expected to produce up to 60 MBbl/d
MB-4 fractionator and related infrastructure	125 MBbl/d NGL fractionator in Mont Belvieu, Texas, and related infrastructure, which includes additional NGL storage in Mont Belvieu	575	First Quarter 2020
	Fully contracted with long-term contracts
Bakken NGL pipeline extension	75-mile NGL pipeline in the Williston Basin connecting to a third-party processing plant	100	Fourth Quarter 2020
	Supported by a long-term contract with a minimum volume commitment
Arbuckle II extension project and additional gathering infrastructure	Provide additional takeaway capacity in the STACK area	240	First Quarter 2021
	Allow increasing volumes on the Elk Creek pipeline access to fractionation capacity at Mont Belvieu
Arbuckle II pipeline expansion	Increasing mainline capacity by 100 MBbl/d with additional pump facilities	60	First Quarter 2021
	Increases capacity to 500 MBbl/d
MB-5 fractionator and related infrastructure	125 MBbl/d NGL fractionator in Mont Belvieu, Texas, and related infrastructure, which includes additional NGL storage in Mont Belvieu	750	First Quarter 2021
	Fully contracted with long-term contracts
Total Natural Gas Liquids		$5,110
Total		$6,080

(a) - Excludes capitalized interest/AFUDC.

(b) - Reflects total project cost. In July 2018, we acquired the remaining 20% interest in WTLPG.

Dividends - In February 2019, we paid quarterly dividends of $0.86 per share ($3.44 per share on an annualized basis), an increase of 12% compared with the same quarter in the prior year. We declared a quarterly dividend of $0.865 per share ($3.46

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per share on an annualized basis) in April 2019. The quarterly dividend will be paid May 15, 2019, to shareholders of record at the close of business on April 29, 2019.

FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

Selected Financial Results - The following table sets forth certain selected financial results for the periods indicated:



	Three Months Ended						Three Months
	March 31,						2019 vs. 2018
Financial Results	2019			2018			Increase (Decrease)
	(Millions of dollars)
Revenues
Commodity sales	$	2,473.0		$	2,820.0		$	(347.0	)	(12	%)
Services	307.0			282.1			24.9			9	%
Total revenues	2,780.0			3,102.1			(322.1		)	(10	%)
Cost of sales and fuel (exclusive of items shown separately below)	1,956.4			2,368.0			(411.6		)	(17	%)
Operating costs	240.8			210.3			30.5			15	%
Depreciation and amortization	114.2			104.2			10.0			10	%
Gain on sale of assets	(0.1		)	(0.1		)	—			—	%
Operating income	$	468.7		$	419.7		$	49.0		12	%
Equity in net earnings from investments	$	43.5		$	40.2		$	3.3		8	%
Interest expense, net of capitalized interest	$	(115.4	)	$	(115.7	)	$	(0.3	)	—	%
Net income	$	337.2		$	266.0		$	71.2		27	%
Adjusted EBITDA	$	637.5		$	570.3		$	67.2		12	%
Capital expenditures	$	889.7		$	264.5		$	625.2		*

* Percentage change is greater than 100%.

See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.

Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel in our Consolidated Statements of Income, and, therefore, the impact is largely offset between the two line items.

Operating income increased for the three months ended March 31, 2019, compared with the same period in 2018, primarily as a result of the following:


•	an increase of $69.2 million due to volume growth, primarily in the Williston and Permian Basins and STACK and SCOOP areas in our Natural Gas Liquids segment and the Williston Basin in our Natural Gas Gathering and Processing segment;


•	an increase of $26.5 million due to higher optimization and marketing earnings primarily from the sale of NGL products previously held in inventory and wider location price differentials in our Natural Gas Liquids segment; and


•	an increase of $15.7 million from higher transportation services due primarily to firm transportation capacity contracted in our Natural Gas Pipelines segment; offset partially by


•	an increase in operating costs of $30.5 million due primarily to higher employee-related costs associated with labor and benefits and the growth of our operations;


•	an increase of $21.7 million in rail transportation and third-party fractionation costs in our Natural Gas Liquids segment; and


•	an increase in depreciation expense of $10.0 million due to capital projects placed in service.

Net income increased due to the items discussed above, higher allowance for equity funds used during construction due to our capital-growth projects and was favorably impacted by a higher tax deduction associated with our equity incentive plan.

Capital expenditures increased for the three months ended March 31, 2019, compared with the same period in 2018, due primarily to spending on our announced capital-growth projects.

Additional information regarding our financial results and operating information is provided in the following discussion for each of our segments.

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Natural Gas Gathering and Processing

Overview - Our Natural Gas Gathering and Processing segment provides midstream services to producers in North Dakota, Montana, Wyoming, Kansas and Oklahoma. Raw natural gas is typically gathered at the wellhead, compressed and transported through pipelines to our processing facilities. Processed natural gas, usually referred to as residue natural gas, is then recompressed and delivered to natural gas pipelines, storage facilities and end users. The NGLs separated from the raw natural gas are sold and delivered through natural gas liquids pipelines to fractionation facilities for further processing.

Our Natural Gas Gathering and Processing segment’s earnings are primarily fee-based, but we have some direct commodity price exposure related primarily to POP contracts. To mitigate the impact of this commodity price exposure, we have hedged a significant portion of our Natural Gas Gathering and Processing segment’s commodity price risk for 2019 and 2020. This segment has substantial long-term acreage dedications in some of the most productive areas of the Williston Basin and Mid-Continent region, specifically the STACK and SCOOP areas, which helps to mitigate volumetric risk.

Growth Projects - Our Natural Gas Gathering and Processing segment is investing in growth projects in NGL-rich areas, including the Bakken Shale and Three Forks formations in the Williston Basin and the STACK and SCOOP areas, that we expect will enable us to meet the needs of crude oil and natural gas producers in those areas. See “Growth Projects” in the “Recent Developments” section for discussion of our announced capital-growth projects.

For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources” section.

Selected Financial Results - The following table sets forth certain selected financial results for our Natural Gas Gathering and Processing segment for the periods indicated:



	Three Months Ended						Three Months
	March 31,						2019 vs. 2018
Financial Results	2019			2018			Increase (Decrease)
	(Millions of dollars)
NGL sales	$	287.4		$	362.8		$	(75.4	)	(21	%)
Condensate sales	44.9			50.4			(5.5		)	(11	%)
Residue natural gas sales	319.0			255.0			64.0			25	%
Gathering, compression, dehydration and processing fees and other revenue	43.4			39.8			3.6			9	%
Cost of sales and fuel (exclusive of depreciation and operating costs)	(450.9		)	(492.6		)	(41.7		)	(8	%)
Operating costs, excluding noncash compensation adjustments	(89.3		)	(85.5		)	3.8			4	%
Equity in net earnings (loss) from investments	(1.2		)	1.7			(2.9		)	*
Other	(1.1		)	(1.0		)	(0.1		)	(10	%)
Adjusted EBITDA	$	152.2		$	130.6		$	21.6		17	%
Capital expenditures	$	215.1		$	111.7		$	103.4		93	%

* Percentage change is greater than 100%.

See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.

Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel, and, therefore, the impact is largely offset between these line items.

Adjusted EBITDA increased $21.6 million for the three months ended March 31, 2019, compared with the same period in 2018, primarily as a result of the following:


•	an increase of $24.4 million due primarily to natural gas volume growth in the Williston Basin, offset partially by natural production declines; and


•	an increase of $4.0 million due primarily to higher realized natural gas prices, net of hedges; offset partially by


•	an increase of $3.8 million in operating costs due primarily to higher employee-related costs due to growth of our operations, offset partially by lower materials and supplies expense; and


•	a decrease of $2.9 million due primarily to lower equity in net earnings from investments due to a decrease in supply volumes in the coal-bed methane area of the Powder River Basin.

Capital expenditures increased for the three months ended March 31, 2019, compared with the same period in 2018, due to our announced capital-growth projects.

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Selected Operating Information - The following table sets forth selected operating information for our Natural Gas Gathering and Processing segment for the periods indicated:



	Three Months Ended
	March 31,
Operating Information	2019		2018
Natural gas gathered (BBtu/d) (a)	2,636		2,460
Natural gas processed (BBtu/d) (b)	2,442		2,285
NGL sales (MBbl/d) (a)	214		194
Residue natural gas sales (BBtu/d) (b)	1,130		964
Average fee rate ($/MMBtu) (a)	$	0.91	$	0.88

(a) - Includes volumes for consolidated entities only.

(b) - Includes volumes we processed at company-owned and third-party facilities.

Our natural gas gathered and processed volumes increased for the three months ended March 31, 2019, compared with the same period in 2018, due primarily to continued producer improvements in production due to enhanced completion techniques, offset partially by natural production declines.

Commodity Price Risk - See discussion regarding our commodity price risk under “Commodity Price Risk” in Item 3, Quantitative and Qualitative Disclosures about Market Risk in this Quarterly Report.

Natural Gas Liquids

Overview - Our Natural Gas Liquids segment owns and operates facilities that gather, fractionate, treat and distribute NGLs and store NGL products, primarily in Oklahoma, Kansas, Texas, New Mexico and the Rocky Mountain region, which includes the Williston, Powder River and DJ Basins, where we provide midstream services to producers of NGLs and deliver those products to the two primary market centers, one in the Mid-Continent in Conway, Kansas, and the other in the Gulf Coast in Mont Belvieu, Texas. We own or have an ownership interest in FERC-regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas, Texas, New Mexico, Montana, North Dakota, Wyoming and Colorado, and terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois. We also own FERC-regulated natural gas liquids distribution pipelines in Kansas, Missouri, Nebraska, Iowa, Illinois and Indiana that connect our Mid-Continent assets with Midwest markets, including Chicago, Illinois. A portion of our ONEOK North System transports refined petroleum products, including unleaded gasoline and diesel, from Kansas to Iowa. The majority of the pipeline-connected natural gas processing plants in Oklahoma, Kansas and the Texas Panhandle are connected to our natural gas liquids gathering systems. We own and operate truck- and rail-loading and -unloading facilities connected to our natural gas liquids fractionation and pipeline assets.

Growth Projects - Our growth strategy in our Natural Gas Liquids segment is focused around the crude oil and NGL-rich natural gas drilling activity in shale and other nonconventional resource areas from the Rocky Mountain region through the Mid-Continent region and the Permian Basin. Crude oil, natural gas and NGL production from this activity; higher petrochemical industry demand for NGL products; and increased exports have resulted in our making additional capital investments to expand our infrastructure to bring these commodities from supply basins to market.

Our Natural Gas Liquids segment invests in NGL-related projects to transport, fractionate, store and deliver to the market NGL supply from shale and other resource development areas across our asset base and alleviate expected infrastructure constraints between the Mid-Continent and Gulf Coast market centers and to meet increasing petrochemical industry and NGL export demand in the Gulf Coast. See “Growth Projects” in the “Recent Developments” section for discussion of our announced capital-growth projects.

In the first quarter 2019, one third-party natural gas processing plant connected to our system was expanded in the STACK and SCOOP areas of the Mid-Continent region.

For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources” section.

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Selected Financial Results - The following table sets forth certain selected financial results for our Natural Gas Liquids segment for the periods indicated:



	Three Months Ended						Three Months
	March 31,						2019 vs. 2018
Financial Results	2019			2018			Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	2,158.1		$	2,552.8		$	(394.7	)	(15	%)
Exchange service revenues and other	101.1			86.2			14.9			17	%
Transportation and storage revenues	52.3			53.5			(1.2		)	(2	%)
Cost of sales and fuel (exclusive of depreciation and operating costs)	(1,846.7		)	(2,281.1		)	(434.4		)	(19	%)
Operating costs, excluding noncash compensation adjustments	(103.4		)	(84.6		)	18.8			22	%
Equity in net earnings from investments	17.5			16.4			1.1			7	%
Other	(1.3		)	(1.1		)	(0.2		)	(18	%)
Adjusted EBITDA	$	377.6		$	342.1		$	35.5		10	%
Capital expenditures	$	639.3		$	124.9		$	514.4		*

* Percentage change is greater than 100%.

See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.

Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel, and, therefore, the impact is largely offset between these line items.

Adjusted EBITDA increased $35.5 million for the three months ended March 31, 2019, compared with the same period in 2018, primarily as a result of the following:

•

an increase of $30.5 million in exchange services due to $44.8 million in higher volumes primarily in the Williston and Permian Basins and the STACK and SCOOP areas and $21.6 million in higher average fee rates primarily in the Permian Basin, offset partially by $21.7 million in higher rail transportation and third-party fractionation costs, $7.5 million due primarily to narrower product price differentials and $4.7 million related to unfractionated NGLs in inventory; and


•	an increase of $26.5 million in optimization and marketing due primarily to higher earnings on the sale of NGL products previously held in inventory and wider location price differentials; offset partially by


•	an increase of $18.8 million in operating costs due primarily to higher employee-related costs associated with labor and benefits and spending on routine maintenance projects.

Capital expenditures increased for the three months ended March 31, 2019, compared with the same period in 2018, due primarily to our announced capital-growth projects.

Selected Operating Information - The following table sets forth selected operating information for our Natural Gas Liquids segment for the periods indicated:



	Three Months Ended
	March 31,
Operating Information	2019		2018
Raw feed throughput (MBbl/d) (a)	1,028		949
NGLs transported-gathering lines (MBbl/d) (b)	944		855
NGLs fractionated (MBbl/d) (c)	729		693
Average Conway-to-Mont Belvieu OPIS price differential - ethane in ethane/propane mix ($/gallon)	$	0.10	$	0.09

(a) - Represents physical raw feed volumes on which we charge a fee for transportation and/or fractionation services.

(b) - Includes volumes for consolidated entities only.

Volumes increased for the three months ended March 31, 2019, compared with the same period in 2018, primarily from the Williston and Permian Basins and the STACK and SCOOP areas. While overall volumes, including ethane, increased, a portion of the contractual fees associated with those volumes gathered and fractionated was previously being earned under contracts with minimum volume obligations.

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Natural Gas Pipelines

Overview - Our Natural Gas Pipelines segment provides transportation and storage services to end users through its wholly owned assets and its 50% ownership interests in Northern Border Pipeline and Roadrunner.

Our natural gas pipelines primarily serve end users, such as natural gas distribution and electric-generation companies, that require natural gas to operate their businesses regardless of location price differentials. The development of shale and other resource areas has continued to increase available natural gas supply, and we expect producers to demand incremental transportation services in the future as additional supply is developed.

Growth Projects - We recently expanded our natural gas pipeline infrastructure in Oklahoma and the Permian Basin. The projects included an eastbound expansion of our ONEOK Gas Transportation system by 150 MMcf/d from the STACK and SCOOP areas to an interstate pipeline delivery point in eastern Oklahoma, a westbound expansion of our ONEOK Gas Transportation system by 100 MMcf/d from the STACK area to multiple interstate pipeline delivery points in western Oklahoma, and an expansion of our WesTex Transmission system by 300 MMcf/d from the Permian Basin to interstate pipeline delivery points in the Texas Panhandle. Additionally, we completed an expansion project on our Roadrunner joint venture to make the pipeline bidirectional, which resulted in 750 MMcf/d of eastbound transportation capacity, expanding to approximately 1.0 Bcf/d in third quarter 2019, from the Delaware Basin to the Waha area.

Selected Financial Results - The following table sets forth certain selected financial results and operating information for our Natural Gas Pipelines segment for the periods indicated:



	Three Months Ended						Three Months
	March 31,						2019 vs. 2018
Financial Results	2019			2018			Increase (Decrease)
	(Millions of dollars)
Transportation revenues	$	86.9		$	81.8		$	5.1		6	%
Storage revenues	16.6			16.5			0.1			1	%
Residue natural gas sales and other revenues	12.9			11.6			1.3			11	%
Cost of sales and fuel (exclusive of depreciation and operating costs)	(1.8		)	(5.5		)	(3.7		)	(67	%)
Operating costs, excluding noncash compensation adjustments	(34.2		)	(31.9		)	2.3			7	%
Equity in net earnings from investments	27.1			22.1			5.0			23	%
Other	(0.9		)	(1.0		)	0.1			10	%
Adjusted EBITDA	$	106.6		$	93.6		$	13.0		14	%
Capital expenditures	$	28.7		$	19.9		$	8.8		44	%

See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.

Adjusted EBITDA increased $13.0 million for the three months ended March 31, 2019, compared with the same period in 2018, primarily as a result of the following:


•	an increase of $15.7 million from transportation services due primarily to higher firm transportation capacity contracted; and


•	an increase of $5.0 million due primarily to higher equity in net earnings from investments due to increased seasonal transportation capacity contracted on Northern Border Pipeline; offset partially by


•	a decrease of $4.6 million from lower net retained fuel and timing of equity gas sales; and


•	an increase of $2.3 million in operating costs due primarily to employee-related costs associated with labor and benefits.

Capital expenditures increased for the three months ended March 31, 2019, compared with the same period in 2018, due primarily to capital-growth projects.

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Selected Operating Information - The following table sets forth selected operating information for our Natural Gas Pipelines segment for the periods indicated:



	Three Months Ended
	March 31,
Operating Information (a)	2019		2018
Natural gas transportation capacity contracted (MDth/d)	7,480		6,779
Transportation capacity subscribed	99	%	97	%

(a) - Includes volumes for consolidated entities only.

Natural gas transportation capacity contracted increased for the three months ended March 31, 2019, compared with the same period in 2018, due to increased available capacity from our completed expansion projects on our ONEOK Gas Transportation and WesTex Transmission systems.

Roadrunner, in which we have a 50% ownership interest, has contracted all of its westbound capacity through 2041.

Northern Border Pipeline, in which we have a 50% ownership interest, has contracted substantially all of its long-haul transportation capacity through the fourth quarter 2020.

Adjusted EBITDA

Adjusted EBITDA is a non-GAAP measure of our financial performance. Adjusted EBITDA is defined as net income adjusted for interest expense, depreciation and amortization, noncash impairment charges, income taxes, allowance for equity funds used during construction, noncash compensation expense and other noncash items. We believe this non-GAAP financial measure is useful to investors because it and similar measures are used by many companies in our industry as a measurement of financial performance and is commonly employed by financial analysts and others to evaluate our financial performance and to compare financial performance among companies in our industry. Adjusted EBITDA should not be considered an alternative to net income, earnings per share or any other measure of financial performance presented in accordance with GAAP. Additionally, this calculation may not be comparable with similarly titled measures of other companies.

The following table sets forth a reconciliation of net income, the nearest comparable GAAP financial performance measure, to adjusted EBITDA for the periods indicated:



	Three Months Ended
	March 31,
	2019			2018
Reconciliation of net income to adjusted EBITDA	(Thousands of dollars)
Net income	$	337,208		$	266,049
Add:
Interest expense, net of capitalized interest	115,420			115,725
Depreciation and amortization	114,158			104,237
Income taxes	77,934			75,771
Noncash compensation expense	5,540			9,226
Equity AFUDC and other noncash items	(12,778		)	(672		)
Adjusted EBITDA	$	637,482		$	570,336
Reconciliation of segment adjusted EBITDA to adjusted EBITDA
Segment adjusted EBITDA:
Natural Gas Gathering and Processing	$	152,244		$	130,551
Natural Gas Liquids	377,639			342,079
Natural Gas Pipelines	106,648			93,625
Other	951			4,081
Adjusted EBITDA	$	637,482		$	570,336

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CONTINGENCIES

See Note J of the Notes to Consolidated Financial Statements in this Quarterly Report for a discussion of developments concerning the Gas Index Pricing Litigation.

Other 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 these litigation matters 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 consolidated results of operations, financial position or cash flows.

LIQUIDITY AND CAPITAL RESOURCES

General - Our primary sources of cash inflows are operating cash flows, proceeds from our commercial paper program and our $2.5 Billion Credit Agreement, debt issuances and the issuance of common stock for our liquidity and capital resources requirements. In addition, we expect cash outflows related to (i) capital expenditures, (ii) interest and repayment of debt maturities and (iii) dividends paid to shareholders. We expect our cash outflows related to capital expenditures and dividends paid to increase due to our announced capital-growth projects and higher anticipated dividends per share, subject to board of directors’ approval.

We expect our sources of cash inflow to provide sufficient resources to finance our operations, capital expenditures and quarterly cash dividends, including expected future dividend increases. Our $2.5 Billion Credit Agreement and the remaining $750 million available to be drawn on our $1.5 Billion Term Loan Agreement provide significant liquidity to fund capital expenditures and repay existing indebtedness. We may access the capital markets to issue debt or equity securities as we consider prudent to provide additional liquidity to refinance existing debt, improve credit metrics or to fund capital expenditures. Although we expect to continue to fund capital projects primarily with cash from operations, short-term borrowings and long-term debt, we continue to have access to $550 million available through our “at-the-market” equity program and the ability to issue equity and other securities under our universal shelf registration statement.

We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt, interest-rate swaps and treasury lock contracts. For additional information on our interest-rate swaps, see Note C of the Notes to Consolidated Financial Statements in this Quarterly Report.

Cash Management - We use a centralized cash management program that concentrates the cash assets of our operating subsidiaries in joint accounts for the purposes of providing financial flexibility and lowering the cost of borrowing, transaction costs and bank fees. Our centralized cash management program provides that funds in excess of the daily needs of our operating subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within our consolidated group. Our operating subsidiaries participate in this program to the extent they are permitted pursuant to FERC regulations or their operating agreements. Under the cash management program, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, we provide cash to the subsidiary or the subsidiary provides cash to us.

Short-term Liquidity - Our principal sources of short-term liquidity consist of cash generated from operating activities, distributions received from our equity-method investments, proceeds from our commercial paper program, our $2.5 Billion Credit Agreement and the remaining $750 million available to be drawn on our $1.5 Billion Term Loan Agreement. As of March 31, 2019, we are in compliance with all covenants of the $2.5 Billion Credit Agreement and the $1.5 Billion Term Loan Agreement.

At March 31, 2019, we had $27.8 million of cash and cash equivalents and $2.5 billion of borrowing capacity under the $2.5 Billion Credit Agreement.

We had working capital (defined as current assets less current liabilities) deficits of $346.9 million and $709.8 million as of March 31, 2019, and December 31, 2018, respectively. Although working capital is influenced by several factors, including, among other things: (i) the timing of (a) scheduled debt payments, (b) the collection and payment of accounts receivable and payable, and (c) equity and debt issuances, and (ii) the volume and cost of inventory and commodity imbalances, our working capital deficit at March 31, 2019 and December 31, 2018, was driven primarily by current maturities of long-term debt. We may have working capital deficits in future periods as we continue to finance our capital-growth projects and repay long-term debt, often initially with short-term borrowings. Our decision to utilize short-term borrowings rather than long-term debt, due

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to more favorable interest rates, may also contribute to our working capital deficit. We do not expect this working capital deficit to have an adverse impact to our cash flows or operations.

For additional information on our $2.5 Billion Credit Agreement and $1.5 Billion Term Loan Agreement, see Note D of the Notes to Consolidated Financial Statements in this Quarterly Report.

Long-term Financing - In addition to our principal sources of short-term liquidity discussed above, we expect to fund our longer-term financing requirements by issuing long-term notes. Other options to obtain financing include, but are not limited to, issuance of common stock, loans from financial institutions, issuance of convertible debt securities or preferred equity securities, asset securitization and the sale and lease-back of facilities.

In November 2018, we entered into our $1.5 Billion Term Loan Agreement with a syndicate of banks, which matures in November 2021 and bears interest at LIBOR plus 112.5 basis points based on our current credit ratings. As of March 31, 2019, we had borrowings totaling $750 million outstanding under our $1.5 Billion Term Loan Agreement, which were used for general corporate purposes, including repayment of existing indebtedness and funding capital expenditures. We expect to draw the remaining $750 million in May 2019.

Debt Repayments - We repaid our $500 million, 8.625% senior notes due March 2019 with a combination of cash on hand and short-term borrowings.

For additional information on our long-term debt, see Note D of the Notes to Consolidated Financial Statements in this Quarterly Report.

Capital Expenditures - We classify expenditures that are expected to generate additional revenue, return on investment or significant operating efficiencies as capital-growth expenditures. Maintenance capital expenditures are those capital expenditures required to maintain our existing assets and operations and do not generate additional revenues. Maintenance capital expenditures are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives. Our capital expenditures are financed typically through operating cash flows, short- and long-term debt and the issuance of equity.

Capital expenditures, excluding AFUDC and capitalized interest, were $889.7 million and $264.5 million for the three months ended March 31, 2019 and 2018, respectively.

We expect our total 2019 growth capital expenditures to range from $2.5 billion to $3.7 billion and our maintenance capital expenditures to range from $160 million to $200 million, excluding AFUDC and capitalized interest. See discussion of our announced capital-growth projects in the “Recent Developments” section.

Credit Ratings - Our long-term debt credit ratings as of April 22, 2019, are shown in the table below:



Rating Agency	Long-Term Rating	Short-Term Rating	Outlook
Moody’s	Baa3	Prime-3	Stable
S&P	BBB	A-2	Stable

Our credit ratings, which are investment grade, may be affected by a material change in our financial ratios or a material event affecting our business and industry. The most common criteria for assessment of our credit ratings are the debt-to-EBITDA ratio, interest coverage, business risk profile and liquidity. If our credit ratings were downgraded, our cost to borrow funds under our $2.5 Billion Credit Agreement and $1.5 Billion Term Loan Agreement would increase and a potential loss of access to the commercial paper market could occur. In the event that we are unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we would continue to have access to our $1.5 Billion Term Loan Agreement until fully drawn or through May 2019, as well as our $2.5 Billion Credit Agreement, which expires in 2023. An adverse credit rating change alone is not a default under our $2.5 Billion Credit Agreement or our $1.5 Billion Term Loan Agreement. We do not expect a downgrade in our credit rating to have a material impact on our results of operations.

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In the normal course of business, our counterparties provide us with secured and unsecured credit. In the event of a downgrade in our credit ratings or a significant change in our counterparties’ evaluation of our creditworthiness, we could be required to provide additional collateral in the form of cash, letters of credit or other negotiable instruments as a condition of continuing to conduct business with such counterparties. We may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments.

Dividends - Holders of our common stock share equally in any dividend declared by our board of directors, subject to the rights of the holders of outstanding preferred stock. In February 2019, we paid a quarterly dividend of $0.86 per share ($3.44 per share on an annualized basis), an increase of 12% compared with the same quarter in the prior year. A dividend of $0.865 per share was declared for the shareholders of record at the close of business on April 29, 2019, payable May 15, 2019.

Our Series E Preferred Stock pays quarterly dividends on each share of Series E Preferred Stock, when, as and if declared by our Board of Directors, at a rate of 5.5% per year. In February 2019, we paid dividends totaling $0.3 million for the Series E Preferred Stock. Dividends totaling $0.3 million were declared for the Series E Preferred Stock and are payable May 15, 2019.

For the three months ended March 31, 2019, our cash dividends paid slightly exceeded our cash flows from operations, and, as a result, we utilized our other sources of short-term liquidity to fund an immaterial portion of our dividends. We expect increases in cash flows from operations in the remainder of 2019 due primarily to expected volume increases across our systems and from the completion of capital-growth projects.

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 affect net income but do not result in actual cash receipts or payments during the period and for operating cash items that do not impact net income. These reconciling items can include depreciation and amortization, impairment charges, allowance for equity funds used during construction, gain or loss on sale of assets, deferred income taxes, net undistributed earnings from equity-method investments, share-based compensation expense, other amounts and changes in our assets and liabilities not classified as investing or financing activities.

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



							Variances
	Three Months Ended						2019 vs. 2018
	March 31,						Favorable (Unfavorable)
	2019			2018			Favorable (Unfavorable)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	353.6		$	495.3		$	(141.7	)
Investing activities	(864.8		)	(255.6		)	(609.2		)
Financing activities	527.0			(259.4		)	786.4
Change in cash and cash equivalents	15.8			(19.7		)	35.5
Cash and cash equivalents at beginning of period	12.0			37.2			(25.2		)
Cash and cash equivalents at end of period	$	27.8		$	17.5		$	10.3

Operating Cash Flows - Operating cash flows are affected by earnings from our business activities and changes in our operating assets and liabilities. Changes in commodity prices and demand for our services or products, whether because of general economic conditions, changes in supply, changes in demand for the end products that are made with our products or increased competition from other service providers, could affect our earnings and operating cash flows. Our operating cash flows can also be impacted by changes in our natural gas and NGL inventory balances, which are driven primarily by commodity prices, supply, demand and the operation of our assets.

Cash flows from operating activities, before changes in operating assets and liabilities for the three months ended March 31, 2019, increased $69.1 million, compared with the same period in 2018. This increase is due primarily to higher earnings resulting from volume growth in the Williston and Permian Basins and STACK and SCOOP areas in our Natural Gas Liquids segment and the Williston Basin in our Natural Gas Gathering and Processing segment and higher optimization and marketing

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earnings due primarily to the sales of NGL products previously held in inventory and wider location price differentials in our Natural Gas Liquids segment, as discussed in “Financial Results and Operating Information.”

The changes in operating assets and liabilities decreased operating cash flows $160.1 million for the three months ended March 31, 2019, compared with an increase of $50.7 million for the same period in 2018. This change is due primarily to the change in natural gas and NGLs in storage, which vary from period to period and vary with changes in commodity prices, and the change in accounts receivable, accounts payable, and other accruals and deferrals resulting from the timing of receipt of cash from customers and payments to vendors, suppliers and other third parties.

Investing Cash Flows - Cash used in investing activities for the three months ended March 31, 2019, increased $609.2 million compared with the same period in 2018, due primarily to increased capital expenditures related to our capital-growth projects.

Financing Cash Flows - Cash from financing activities for the three months ended March 31, 2019, increased $786.4 million compared with the same period in 2018, due primarily to the issuance of $1.25 billion in senior unsecured notes, the $200 million draw on our $1.5 Billion Term Loan Agreement and the repayment of short-term borrowings in 2018, offset partially by a decrease due to issuances of common stock in 2018.

REGULATORY, ENVIRONMENTAL AND SAFETY MATTERS

Environmental Matters - We are subject to a variety of historical preservation and environmental laws and/or regulations that affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetlands and waterways preservation, cultural resource protection, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. For example, if a leak or spill of hazardous substances or petroleum products occurs from pipelines or facilities that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including response, investigation and cleanup costs, which could affect materially our results of operations and cash flows. In addition, emissions controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us.

Additional information about our regulatory, environmental and safety matters can be found in “Regulatory, Environmental and Safety Matters” under Part I, Item 1, Business, in our Annual Report.

IMPACT OF NEW ACCOUNTING STANDARDS

See Note A of the Notes to Consolidated Financial Statements in this Quarterly Report for discussion of new accounting standards.

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 revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.

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

FORWARD-LOOKING STATEMENTS

Some of the statements contained and incorporated in this Quarterly Report are forward-looking statements as defined under federal securities laws. The forward-looking statements relate to our anticipated financial performance (including projected operating income, net income, capital expenditures, cash flows and projected levels of dividends), liquidity, management’s plans and objectives for our future capital-growth projects and other future operations (including plans to construct additional

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natural gas and natural gas liquids pipelines and processing facilities and related cost estimates), 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 federal securities legislation and other applicable laws. 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,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “might,” “plan,” “potential,” “project,” “scheduled,” “should,” “will,” “would” and other words and terms of similar meaning.

One should not place undue reliance on forward-looking statements. 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:


•	competition from other United States and foreign energy suppliers and transporters, as well as alternative forms of energy, including, but not limited to, solar power, wind power, geothermal energy and biofuels such as ethanol and biodiesel;


•	the capital intensive nature of our businesses;


•	the profitability of assets or businesses acquired or constructed by us;


•	risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties;


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


•	the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, pipeline safety, environmental compliance, climate change initiatives and authorized rates of recovery of natural gas and natural gas transportation costs;


•	the impact on drilling and production by factors beyond our control, including the demand for natural gas and crude oil; producers’ desire and ability to drill and obtain necessary permits; reserve performance; and capacity constraints on the pipelines that transport crude oil, natural gas and NGLs from producing areas and our facilities;


•	difficulties or delays experienced by trucks, railroads or pipelines in delivering products to or from our terminals or pipelines;


•	the effects of weather and other natural phenomena, including climate change, on our operations, demand for our services and energy prices;


•	changes in demand for the use of natural gas, NGLs and crude oil because of market conditions caused by concerns about climate change;


•	the impact of unforeseen changes in interest rates, debt and equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension and postretirement expense and funding resulting from changes in equity and bond market returns;


•	our indebtedness and guarantee obligations could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared with our competitors that have less debt or have other adverse consequences;


•	actions by rating agencies concerning our credit;


•	the results of administrative proceedings and litigation, regulatory actions, rule changes and receipt of expected clearances involving any local, state or federal regulatory body, including the FERC, the National Transportation Safety Board, the PHMSA, the EPA and CFTC;


•	our ability to access capital at competitive rates or on terms acceptable to us;


•	risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines that outpace new drilling or extended periods of ethane rejection;


•	the risk that material weaknesses or significant deficiencies in our internal controls over financial reporting could emerge or that minor problems could become significant;


•	the impact and outcome of pending and future litigation;


•	the timing and extent of changes in energy commodity prices;


•	the ability to market pipeline capacity on favorable terms, including the effects of:


–	future demand for and prices of natural gas, NGLs and crude oil;


–	competitive conditions in the overall energy market;

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–	availability of supplies of United States natural gas and crude oil; and


–	availability of additional storage capacity;


•	performance of contractual obligations by our customers, service providers, contractors and shippers;


•	the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances;


•	our ability to acquire all necessary permits, consents or other approvals in a timely manner, to promptly obtain all necessary materials and supplies required for construction, and to construct gathering, processing, storage, fractionation and transportation facilities without labor or contractor problems;


•	the mechanical integrity of facilities operated;


•	demand for our services in the proximity of our facilities;


•	our ability to control operating costs and make cost-saving changes;


•	acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’, customers’ or shippers’ facilities;


•	economic climate and growth in the geographic areas in which we do business;


•	the risk of a prolonged slowdown in growth or decline in the United States or international economies, including liquidity risks in United States or foreign credit markets;


•	the impact of recently issued and future accounting updates and other changes in accounting policies;


•	the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions throughout the world;


•	the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;


•	risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions;


•	the impact of uncontracted capacity in our assets being greater or less than expected;


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


•	the composition and quality of the natural gas and NGLs we gather and process in our plants and transport on our pipelines;


•	the efficiency of our plants in processing natural gas and extracting and fractionating NGLs;


•	the impact of potential impairment charges;


•	the risk inherent in the use of information systems in our respective businesses, implementation of new software and hardware, and the impact on the timeliness of information for financial reporting;


•	our ability to control construction costs and completion schedules of our pipelines and other projects; and


•	the risk factors listed in the reports we have filed and may file with the SEC, which are incorporated by reference.

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 I, Item 1A, Risk Factors, in our Annual Report and in our other filings that we make with the SEC, which are available via the SEC’s website at www.sec.gov and our website at www.oneok.com. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Any such forward-looking statement speaks only as of the date on which such statement is made, and 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

As part of our hedging strategy, we use commodity derivative financial instruments and physical-forward contracts described in Note C of the Notes to Consolidated Financial Statements in this Quarterly Report to reduce the impact of near-term price fluctuations of natural gas, NGLs and condensate.

Although our businesses are primarily fee-based, in our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk as a result of retaining a portion of the commodity sales proceeds associated with our POP with fee contracts. Under certain POP with fee contracts, our contractual fees and POP percentage may increase or decrease if

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production volumes, delivery pressures or commodity prices change relative to specified thresholds. We are exposed to basis risk between the various production and market locations where we buy and sell commodities.

The following tables set forth hedging information for our Natural Gas Gathering and Processing segment’s forecasted equity volumes for the periods indicated:



	Nine Months Ending December 31, 2019
	Volumes Hedged	Average Price			Percentage Hedged
NGLs - excluding ethane (MBbl/d) - Conway/Mont Belvieu	7.6	$	0.71	/ gallon	74%
Condensate (MBbl/d) - WTI-NYMEX	2.7	$	58.55	/ Bbl	90%
Natural gas (BBtu/d) - NYMEX and basis	82.0	$	2.30	/ MMBtu	80%



	Year Ending December 31, 2020
	Volumes Hedged	Average Price			Percentage Hedged
NGLs - excluding ethane (MBbl/d) - Conway/Mont Belvieu	2.6	$	0.63	/ gallon	29%
Condensate (MBbl/d) - WTI-NYMEX	0.8	$	55.25	/ Bbl	26%
Natural gas (BBtu/d) - NYMEX and basis	51.6	$	2.52	/MMBtu	65%

Our Natural Gas Gathering and Processing segment’s commodity price sensitivity is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at March 31, 2019. Condensate sales are typically based on the price of crude oil. Assuming normal operating conditions, we estimate the following for our forecasted equity volumes:


•	a $0.01 per-gallon change in the composite price of NGLs, excluding ethane, would change adjusted EBITDA for the nine months ending December 31, 2019, and for the year ending December 31, 2020, by approximately $1.2 million and $1.7 million, respectively;


•	a $1.00 per-barrel change in the price of crude oil would change adjusted EBITDA for the nine months ending December 31, 2019, and for the year ending December 31, 2020, by approximately $1.1 million and $1.6 million, respectively; and


•	a $0.10 per-MMBtu change in the price of residue natural gas would change adjusted EBITDA for the nine months ending December 31, 2019, and for the year ending December 31, 2020, by approximately $3.0 million and $3.6 million, respectively.

These estimates do not include any effects of hedging or effects on demand for our services or natural gas processing plant operations that might be caused by, or arise in conjunction with, commodity price fluctuations. For example, a change in the gross processing spread may cause a change in the amount of ethane extracted from the natural gas stream, impacting gathering and processing financial results for certain contracts.

INTEREST-RATE RISK

We are exposed to interest-rate risk through our $2.5 Billion Credit Agreement, $1.5 Billion Term Loan Agreement, commercial paper program and long-term debt issuances. Future increases in LIBOR, corporate commercial paper rates or corporate bond rates could expose us to increased interest costs on future borrowings. We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt, interest-rate swaps and treasury lock contracts. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts. In March 2019, we settled $1.0 billion of our forward-starting interest-rate swaps related to our underwritten public offering of $1.25 billion senior unsecured notes.

See Note C of the Notes to Consolidated Financial Statements in this Quarterly Report for more information on our hedging activities.

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COUNTERPARTY CREDIT RISK

We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate. Certain of our counterparties may be impacted by a relatively low commodity price environment and could experience financial problems, which could result in nonpayment and/or nonperformance, which could impact adversely our results of operations.

The creditworthiness of our counterparties and our customer concentration are consistent with those discussed in Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk, in our Annual Report.


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 Rule 13a-15(e) and 15d-15(e) 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 quarter ended March 31, 2019, 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

Additional information about our legal proceedings is included in Note J of the Notes to Consolidated Financial Statements in this Quarterly Report and under Note N of the Notes to Consolidated Financial Statements in our Annual Report.


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 consider carefully 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

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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 and Restated By-laws of ONEOK, Inc. (incorporated by reference from Exhibit 3.1 to ONEOK Inc.’s Current Report on Form 8-K filed September 20, 2018 (File No. 1-13643)).

3.2	Amended and Restated Certificate of Incorporation of ONEOK, Inc., dated July 3, 2017, as amended (incorporated by reference from Exhibit 3.2 to ONEOK Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2017, filed November 1, 2017 (File No. 1-13643)).

4.1	Seventh Supplemental Indenture, dated as of July 2, 2018, among ONEOK, Inc., ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and U.S. Bank National Association, as trustee, with respect to the 5.20% Notes due 2048 (incorporated by reference from Exhibit 4.2 to ONEOK Inc.’s Current Report on Form 8-K, filed July 2, 2018 (File No. 1-13643)).

4.2	Eighth Supplemental Indenture, dated as of March 13, 2019, among ONEOK, Inc., ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and U.S. Bank National Association, as trustee, with respect to the 4.35% Notes due 2029 (incorporated by reference from Exhibit 4.2 to ONEOK Inc.’s Current Report on Form 8-K, filed March 13, 2019 (File No. 1-13643)).

4.3	Ninth Supplemental Indenture, dated as of March 13, 2019, among ONEOK, Inc., ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and U.S. Bank National Association, as trustee, with respect to the 5.20% Notes due 2048 (incorporated by reference from Exhibit 4.3 to ONEOK Inc.’s Current Report on Form 8-K, filed March 13, 2019 (File No. 1-13643)).

10.1	Underwriting Agreement, dated March 11, 2019, between ONEOK, Inc., ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Barclays Capital Inc., Goldman Sachs & Co. LLC, MUFG Securities Americas Inc. and TD Securities (USA) LLC, as representatives of the several underwriters named therein (incorporated by reference from Exhibit 1.1 to ONEOK Inc.’s Current Report on Form 8-K, filed March 13, 2019 (File No. 1-13643)).

10.2	Form of 2019 Restricted Unit Award Agreement, dated February 20, 2019 (incorporated by reference from Exhibit 10.54 to ONEOK Inc.’s Annual Report on Form 10-K, filed February 26, 2019 (File No. 1-13643).

10.3	Form of 2019 Performance Unit Award Agreement, dated February 20, 2019 (incorporated by reference from Exhibit 10.55 to ONEOK Inc.’s Annual Report on Form 10-K, filed February 26, 2019 (File No. 1-13643).

31.1	Certification of Terry K. Spencer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification of Walter S. Hulse III pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Certification of Terry K. Spencer 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 Walter S. Hulse III 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 Taxonomy Extension Schema Document.

101.CAL	XBRL Taxonomy Calculation Linkbase Document.

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101.DEF	XBRL Taxonomy Extension Definitions Document.

101.LAB	XBRL Taxonomy Label Linkbase Document.

101.PRE	XBRL Taxonomy Presentation 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 months ended March 31, 2019 and 2018; (iii) Consolidated Statements of Comprehensive Income for the three months ended March 31, 2019 and 2018; (iv) Consolidated Balance Sheets at March 31, 2019, and December 31, 2018; (v) Consolidated Statements of Cash Flows for the three months ended March 31, 2019 and 2018; (vi) Consolidated Statements of Changes in Equity for the three months ended March 31, 2019 and 2018; and (vii) Notes to Consolidated Financial Statements.

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SIGNATURE

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



	ONEOK, Inc.
	Registrant


Date: May 1, 2019	By:	/s/ Walter S. Hulse III
		Walter S. Hulse III
		Chief Financial Officer, Treasurer and
		Executive Vice President, Strategic Planning
		and Corporate Affairs
		(Principal Financial Officer)