ONEOK INC /NEW/ - Quarter Report: 2021 March (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2021.

☐ 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,

74103

(Address of principal executive offices)

(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common stock, par value of $0.01	OKE	New York Stock Exchange

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 ☒ 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 ☒ 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 ☒ 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 ☒

On April 19, 2021, the Company had 445,536,572 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, 2021 and 2020	6
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2021 and 2020	7
	Consolidated Balance Sheets - March 31, 2021, and December 31, 2020	8
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2021 and 2020	11
	Consolidated Statements of Changes in Equity - Three Months Ended March 31, 2021 and 2020	12
	Notes to Consolidated Financial Statements	14
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	43
Part II.	Other Information	44
Item 1.	Legal Proceedings	44
Item 1A.	Risk Factors	44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 3.	Defaults Upon Senior Securities	44
Item 4.	Mine Safety Disclosures	44
Item 5.	Other Information	44
Item 6.	Exhibits	44
Signature		46

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

The statements in this Quarterly Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may include words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “might,” “outlook,” “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,” and Part II, Item 1A, “Risk Factors,” 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, Corporate Sustainability Report, Response to COVID-19 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:


$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, 2020
ASU			Accounting Standards Update
Bbl			Barrels, 1 barrel is equivalent to 42 United States gallons
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
COVID-19			Coronavirus disease 2019
DJ			Denver-Julesburg
EBITDA			Earnings before interest expense, income taxes, depreciation and amortization
EPA			United States Environmental Protection Agency
EPS			Earnings (loss) per share of common stock
Exchange Act			Securities Exchange Act of 1934, as amended
FERC			Federal Energy Regulatory Commission
Fitch			Fitch Ratings, Inc.
GAAP			Accounting principles generally accepted in the United States of America
ICE			Intercontinental Exchange
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.
Natural Gas Act			Natural Gas Act of 1938, as amended
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
Northern Border Pipeline			Northern Border Pipeline Company, a 50% owned joint venture
NYMEX			New York Mercantile Exchange
ONEOK			ONEOK, Inc.
ONEOK Partners			ONEOK Partners, L.P., a wholly owned subsidiary of ONEOK, Inc.
OPIS			Oil Price Information Service
Overland Pass Pipeline			Overland Pass Pipeline Company, LLC, a 50% owned joint venture
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% owned joint venture
S&P			S&P Global Ratings
SEC			Securities and Exchange Commission
Series E Preferred Stock			Series E Non-Voting, Perpetual Preferred Stock, par value $0.01 per share
WTI			West Texas Intermediate
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)		2021		2020
		(Thousands of dollars, except per share amounts)
Revenues
Commodity sales		$	2,836,109	$	1,808,620
Services		358,570		328,052
Total revenues (Note K)		3,194,679		2,136,672
Cost of sales and fuel (exclusive of items shown separately below)		2,121,510		1,276,928
Operations and maintenance		207,158		175,096
Depreciation and amortization		157,120		132,353
Impairment charges		—		604,024
General taxes		44,439		31,944
Gain on sale of assets		(269)		(204)
Operating income (loss)		664,721		(83,469)
Equity in net earnings from investments (Note I)		33,320		44,627
Impairment of equity investments		—		(37,730)
Allowance for equity funds used during construction		812		15,409
Other income		215		16,475
Other expense		(5,237)		(11,948)
Interest expense (net of capitalized interest of $5,095 and $30,875, respectively)		(185,523)		(140,616)
Income (loss) before income taxes		508,308		(197,252)
Income tax (expense) benefit		(122,132)		55,395
Net income (loss)		386,176		(141,857)
Less: Preferred stock dividends		275		275
Net income (loss) available to common shareholders		$	385,901	$	(142,132)

Basic EPS (Note G)		$	0.87	$	(0.34)

Diluted EPS (Note G)		$	0.86	$	(0.34)
Average shares (thousands)
Basic		445,894		414,282
Diluted		446,885		414,282

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)		2021		2020
		(Thousands of dollars)
Net income (loss)		$	386,176	$	(141,857)
Other comprehensive income (loss), net of tax
Change in fair value of derivatives, net of tax of $(9,857) and $31,705, respectively		32,998		(106,141)
Derivative amounts reclassified to net income (loss), net of tax of $(12,361) and $4,518, respectively		41,387		(15,164)
Change in retirement and other postretirement benefit plan obligations, net of tax of $(1,087) and $(1,064), respectively		3,638		3,562
Other comprehensive income (loss) of unconsolidated affiliates, net of tax of $(2,339) and $2,283, respectively		7,830		(7,643)
Total other comprehensive income (loss), net of tax		85,853		(125,386)
Comprehensive income (loss)		$	472,029	$	(267,243)

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS

	March 31,		December 31,
(Unaudited)	2021		2020
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	402,413	$	524,496
Accounts receivable, net	909,972		829,796
Materials and supplies	143,583		143,178
NGLs and natural gas in storage	369,604		227,810
Commodity imbalances	16,798		11,959
Other current assets	155,224		132,536
Total current assets	1,997,594		1,869,775
Property, plant and equipment
Property, plant and equipment	23,192,548		23,072,935
Accumulated depreciation and amortization	4,067,297		3,918,007
Net property, plant and equipment	19,125,251		19,154,928
Investments and other assets
Investments in unconsolidated affiliates	807,721		805,032
Goodwill and intangible assets	771,116		773,723

Other assets	478,247		475,296
Total investments and other assets	2,057,084		2,054,051
Total assets	$	23,179,929	$	23,078,754

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
(Continued)
	March 31,		December 31,
(Unaudited)	2021		2020
Liabilities and equity	(Thousands of dollars)
Current liabilities
Current maturities of long-term debt (Note D)	$	543,757	$	7,650

Accounts payable	929,771		719,302

Commodity imbalances	209,626		186,372
Accrued taxes	65,862		89,428
Accrued interest	140,281		245,153
Operating lease liability	13,408		13,610
Other current liabilities	145,249		83,032
Total current liabilities	2,047,954		1,344,547
Long-term debt, excluding current maturities (Note D)	13,638,767		14,228,421
Deferred credits and other liabilities
Deferred income taxes	814,528		669,697
Operating lease liability	85,295		87,610
Other deferred credits	496,420		706,081
Total deferred credits and other liabilities	1,396,243		1,463,388
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, 2021, and December 31, 2020	—		—
Common stock, $0.01 par value: authorized 1,200,000,000 shares; issued 474,916,234 shares and outstanding 445,534,180 shares at March 31, 2021; issued 474,916,234 shares and outstanding 444,872,383 shares at December 31, 2020	4,749		4,749
Paid-in capital	7,305,274		7,353,396
Accumulated other comprehensive loss (Note F)	(465,596)		(551,449)
Retained earnings	—		—
Treasury stock, at cost: 29,382,054 shares at March 31, 2021, and 30,043,851 shares at December 31, 2020	(747,462)		(764,298)
Total equity	6,096,965		6,042,398
Total liabilities and equity	$	23,179,929	$	23,078,754

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)	2021		2020
	(Thousands of dollars)
Operating activities
Net income (loss)	$	386,176	$	(141,857)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	157,120		132,353
Impairment charges	—		641,754
Equity in net earnings from investments	(33,320)		(44,627)
Distributions received from unconsolidated affiliates	30,862		41,577
Deferred income tax expense (benefit)	119,194		(55,949)



Other, net	11,672		(30,380)
Changes in assets and liabilities:
Accounts receivable	(85,212)		334,370
NGLs and natural gas in storage	(141,794)		173,885
Accounts payable	251,344		(350,701)
Commodity imbalances	18,415		(37,919)
Accrued interest	(104,872)		(68,918)
Risk-management assets and liabilities	(19,302)		(78,856)
Other assets and liabilities	(56,966)		(92,011)
Cash provided by operating activities	533,317		422,721
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	(176,734)		(949,679)

Distributions received from unconsolidated affiliates in excess of cumulative earnings	10,191		6,949
Other, net	(4,148)		(22,062)

Cash used in investing activities	(170,691)		(964,792)
Financing activities
Dividends paid	(416,229)		(386,667)
Repayment of short-term borrowings, net	—		(220,000)
Issuance of long-term debt, net of discounts	—		1,748,221
Debt financing costs	—		(15,444)
Repayment of long-term debt	(56,492)		(52,389)



Other, net	(11,988)		(20,978)
Cash provided by (used in) financing activities	(484,709)		1,052,743
Change in cash and cash equivalents	(122,083)		510,672
Cash and cash equivalents at beginning of period	524,496		20,958
Cash and cash equivalents at end of period	$	402,413	$	531,630

See accompanying Notes to Consolidated Financial Statements.

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

(Unaudited)	Preferred Stock Issued	Common Stock Issued	Preferred Stock		Common Stock		Paid-in Capital
	(Shares)				(Thousands of dollars)
January 1, 2021	20,000	474,916,234	$	—	$	4,749	$	7,353,396














Net income	—	—	—		—		—
Other comprehensive income (Note F)	—	—	—		—		—
Preferred stock dividends - $13.75 per share (Note E)	—	—	—		—		—
Common stock issued	—	—	—		—		(10,159)
Common stock dividends - $0.935 per share (Note E)	—	—	—		—		(30,234)
Other, net	—	—	—		—		(7,729)
March 31, 2021	20,000	474,916,234	$	—	$	4,749	$	7,305,274





(Unaudited)	Preferred Stock Issued	Common Stock Issued	Preferred Stock		Common Stock		Paid-in Capital
	(Shares)				(Thousands of dollars)
January 1, 2020	20,000	445,016,234	$	—	$	4,450	$	7,403,895

















Net loss	—	—	—		—		—
Other comprehensive loss	—	—	—		—		—
Preferred stock dividends - $13.75 per share	—	—	—		—		(275)
Common stock issued	—	—	—		—		(9,286)
Common stock dividends - $0.935 per share	—	—	—		—		(386,931)


Other, net	—	—	—		—		(17,950)
March 31, 2020	20,000	445,016,234	$	—	$	4,450	$	6,989,453

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

(Unaudited)	Accumulated Other Comprehensive Loss		Retained Earnings		Treasury Stock		Total Equity
	(Thousands of dollars)
January 1, 2021	$	(551,449)	$	—	$	(764,298)	$	6,042,398














Net income	—		386,176		—		386,176
Other comprehensive income (Note F)	85,853		—		—		85,853
Preferred stock dividends - $13.75 per share (Note E)	—		(275)		—		(275)
Common stock issued	—		—		16,836		6,677
Common stock dividends - $0.935 per share (Note E)	—		(385,901)		—		(416,135)
Other, net	—		—		—		(7,729)
March 31, 2021	$	(465,596)	$	—	$	(747,462)	$	6,096,965





(Unaudited)	Accumulated Other Comprehensive Loss		Retained Earnings (Accumulated Deficit)		Treasury Stock		Total Equity
	(Thousands of dollars)
January 1, 2020	$	(374,000)	$	—	$	(808,394)	$	6,225,951

















Net loss	—		(141,857)		—		(141,857)
Other comprehensive loss	(125,386)		—		—		(125,386)
Preferred stock dividends - $13.75 per share	—		—		—		(275)
Common stock issued	—		—		16,375		7,089
Common stock dividends - $0.935 per share	—		—		—		(386,931)


Other, net	—		—		—		(17,950)
March 31, 2020	$	(499,386)	$	(141,857)	$	(792,019)	$	5,560,641

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 2020 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 discussed below or in our Annual Report were assessed and determined to be either not applicable or clarifications of ASUs previously issued. Except as discussed below or in our Annual Report, there have been no new accounting pronouncements that have become effective or have been issued that are of significance or potential significance to us.

In January 2021, we adopted ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes,” which simplifies certain concepts in Topic 740, Income Taxes. The impact of adopting this standard was not material.

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.

Many of the contracts in our derivative portfolio are executed in liquid markets where price transparency exists. Our financial commodity derivatives are generally settled through a NYMEX or 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 composed 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 composed 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 commodity price curves that incorporate market data from broker quotes and third-party pricing services. These balances are composed predominantly of exchange-cleared and over-the-counter derivatives to hedge NGL price risk and natural gas basis risk between various transaction locations and the NYMEX Henry Hub. 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, 2021, is immaterial as our Level 3 fair value measurements are based on unadjusted pricing information from broker quotes and third-party

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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 primarily 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.

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


	March 31, 2021
	Level 1		Level 2		Level 3		Total - Gross		Netting (a)		Total - Net
	(Thousands of dollars)
Derivative assets
Commodity contracts
Financial contracts	$	6,380	$	—	$	113,776	$	120,156	$	(120,156)	$	—

Interest-rate contracts	—		241		—		241		—		241
Total derivative assets	$	6,380	$	241	$	113,776	$	120,397	$	(120,156)	$	241
Derivative liabilities
Commodity contracts
Financial contracts	$	(18,986)	$	—	$	(155,570)	$	(174,556)	$	174,556	$	—

Interest-rate contracts	—		(97,363)		—		(97,363)		—		(97,363)
Total derivative liabilities	$	(18,986)	$	(97,363)	$	(155,570)	$	(271,919)	$	174,556	$	(97,363)

(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheet 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, 2021, we held no cash and posted $108.0 million of cash with various counterparties, including $54.4 million of cash collateral that is offsetting derivative net liability positions under master-netting arrangements in the table above. The remaining $53.6 million of cash collateral in excess of derivative net liability positions is included in other current assets in our Consolidated Balance Sheet.


	December 31, 2020
	Level 1		Level 2		Level 3		Total - Gross		Netting (a)		Total - Net
	(Thousands of dollars)
Derivative assets
Commodity contracts
Financial contracts	$	6,697	$	—	$	103,801	$	110,498	$	(110,498)	$	—


Total derivative assets	$	6,697	$	—	$	103,801	$	110,498	$	(110,498)	$	—
Derivative liabilities
Commodity contracts
Financial contracts	$	(10,489)	$	—	$	(135,122)	$	(145,611)	$	145,611	$	—

Interest-rate contracts	—		(203,407)		—		(203,407)		—		(203,407)
Total derivative liabilities	$	(10,489)	$	(203,407)	$	(135,122)	$	(349,018)	$	145,611	$	(203,407)

(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheet 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, 2020, we held no cash and posted $63.1 million of cash with various counterparties, including $35.1 million of cash collateral that is offsetting derivative net liability positions under master-netting arrangements in the table above. The remaining $28.0 million of cash collateral in excess of derivative net liability positions is included in other current assets in our Consolidated Balance Sheet.

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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)		2021		2020
		(Thousands of dollars)
Net assets (liabilities) at beginning of period		$	(31,321)	$	30,772
Total changes in fair value:

Settlements included in net income (loss) (a)		24,738		(16,146)
New Level 3 derivatives included in other comprehensive income (loss) (b)		(4,612)		20,993
Unrealized change included in other comprehensive income (loss) (b)		(30,599)		21,782
Net assets (liabilities) at end of period		$	(41,794)	$	57,401

(a) - Included in commodity sales revenues/cost of sales and fuel in our Consolidated Statements of Income.

(b) - Included in change in fair value of derivatives in our Consolidated Statements of Comprehensive Income.

During the three months ended March 31, 2021 and 2020, 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 composed 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 $15.8 billion and $16.3 billion at March 31, 2021, and December 31, 2020, respectively. The book value of our consolidated long-term debt, including current maturities, was $14.2 billion at March 31, 2021, and December 31, 2020. 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.

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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 fee with POP contracts. Under certain fee with POP contracts, our fees and POP percentage may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds. In certain commodity price environments, our contractual fees on these fee with POP contracts may decrease, which impacts the average fee rate in our Natural Gas Gathering and Processing segment. 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 primarily exposed to commodity price risk on our intrastate pipelines because they consume natural gas in operations and retain natural gas from our customers for operations or as part of our fee for services 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 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, 2021, and December 31, 2020, 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 and interest-rate swaps. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts.

At March 31, 2021, and December 31, 2020, we had forward-starting interest-rate swaps with notional amounts totaling $1.1 billion to hedge the variability of interest payments on a portion of our forecasted debt issuances. 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 - 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, 2021				December 31, 2020
	Location in our Consolidated Balance Sheets	Assets		(Liabilities)		Assets		(Liabilities)
Derivatives designated as hedging instruments		(Thousands of dollars)
Commodity contracts (a)
Financial contracts (b)		$	113,909	$	(168,369)	$	107,461	$	(142,573)


Interest-rate contracts	Other current assets/ liabilities	241		(65,329)		—		—
	Other deferred credits	—		(32,034)		—		(203,407)
Total derivatives designated as hedging instruments		114,150		(265,732)		107,461		(345,980)
Derivatives not designated as hedging instruments
Commodity contracts (a)
Financial contracts (b)		6,247		(6,187)		3,037		(3,038)
Total derivatives not designated as hedging instruments		6,247		(6,187)		3,037		(3,038)
Total derivatives		$	120,397	$	(271,919)	$	110,498	$	(349,018)

(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.

(b) - At March 31, 2021, and December 31, 2020, our derivative net liability positions under master-netting arrangements for financial contracts were fully offset by cash collateral of $54.4 million and $35.1 million, respectively.

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

March 31, 2021

December 31, 2020

Contract
Type

Net Purchased/Payor
(Sold/Receiver)

Derivatives designated as hedging instruments: (a)

Cash flow hedges

Fixed price

- Natural gas (Bcf)

Futures

(80.9)

(43.3)

- Crude oil and NGLs (MMBbl)

Futures

(10.9)

(4.6)

Basis

- Natural gas (Bcf)

Futures

(80.9)

(43.3)

Interest-rate contracts (Billions of dollars)

Swaps

1.1

(a) - Notional amounts for derivatives not designated as hedging instruments are excluded from the table above due to fully offsetting notional quantities of 0.5 MMBbl and 0.8 MMBbl for NGLs fixed priced derivative instruments at March 31, 2021, and December 31, 2020, respectively.

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


	Three Months Ended
	March 31,
		2021		2020
		(Thousands of dollars)
Commodity contracts		$	(63,430)	$	87,195
Interest-rate contracts		106,285		(225,041)
Total unrealized change in fair value of cash flow hedges in other comprehensive income (loss)		$	42,855	$	(137,846)

The following table sets forth the effect of cash flow hedges on net income (loss) for the periods indicated:


	Location of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Loss)	Three Months Ended
		March 31,
			2021		2020
			(Thousands of dollars)
Commodity contracts	Commodity sales revenues		$	(130,518)	$	44,999
	Cost of sales and fuel		86,436		(15,039)
Interest-rate contracts	Interest expense		(9,666)		(10,278)
Total change in fair value of cash flow hedges reclassified from accumulated other comprehensive loss into net income (loss) on derivatives			$	(53,748)	$	19,682

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 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, Fitch 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, 2021.

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

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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, 2021, the credit exposure from our derivative assets is with investment-grade companies in the financial services sector.

D. DEBT

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


	March 31, 2021		December 31, 2020
	(Thousands of dollars)
Commercial paper outstanding	$	—	$	—
Senior unsecured obligations:
$700,000 at 4.25% due February 2022	536,107		541,877
$900,000 at 3.375% due October 2022	895,814		895,814
$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 2.75% due September 2024	500,000		500,000
$500,000 at 4.9% due March 2025	500,000		500,000
$400,000 at 2.2% due September 2025	387,000		387,000
$600,000 at 5.85% due January 2026	600,000		600,000
$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		700,000
$750,000 at 3.4% due September 2029	714,251		714,251
$850,000 at 3.1% due March 2030	780,093		780,093
$600,000 at 6.35% due January 2031	600,000		600,000
$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	689,006		689,006
$1,000,000 at 5.2% due July 2048	1,000,000		1,000,000
$750,000 at 4.45% due September 2049	672,530		713,676
$500,000 at 4.5% due March 2050	443,015		451,270
$300,000 at 7.15% due January 2051	300,000		300,000
Guardian Pipeline
Weighted average 7.85% due December 2022	11,745		13,657
Total debt	14,304,561		14,361,644
Unamortized portion of terminated swaps	12,884		13,314
Unamortized debt issuance costs and discounts	(134,921)		(138,887)
Current maturities of long-term debt	(543,757)		(7,650)

Long-term debt	$	13,638,767	$	14,228,421

$2.5 Billion Credit Agreement - 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). In 2020, we acquired additional interest in one of our equity investments and a related asset for $27 million, which allowed us to elect an acquisition adjustment period under our $2.5 Billion Credit Agreement and, as a result, increased our leverage ratio covenant to 5.5 to 1 for the fourth quarter 2020 and the two following quarters. Thereafter, the covenant will decrease to 5.0 to 1. At March 31, 2021, we had no outstanding

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borrowings, our ratio of indebtedness to adjusted EBITDA was 4.6 to 1, and we were in compliance with all covenants under our $2.5 Billion Credit Agreement.

Debt Repurchases - During the three months ended March 31, 2021, we repurchased in the open market outstanding principal of certain of our senior notes in the amount of $55.2 million for an aggregate repurchase price of $54.6 million with cash on hand.

Debt Guarantees - We, ONEOK Partners and the Intermediate Partnership have cross guarantees in place for our and ONEOK Partners’ indebtedness.

E. EQUITY

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 Series E Preferred Stock. Dividends paid on our common stock in February 2021 were $0.935 per share. A dividend of $0.935 per share was declared for shareholders of record at the close of business on April 26, 2021, payable May 14, 2021.

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. We paid dividends for the Series E Preferred Stock of $0.3 million in February 2021. Dividends totaling $0.3 million were declared for the Series E Preferred Stock and are payable May 14, 2021.

F. ACCUMULATED OTHER COMPREHENSIVE LOSS

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


	Risk- Management Assets/Liabilities (a)		Retirement and Other Postretirement Benefit Plan Obligations (a) (b)		Risk- Management Assets/Liabilities of Unconsolidated Affiliates (a)		Accumulated Other Comprehensive Loss (a)
	(Thousands of dollars)
January 1, 2021	$	(377,446)	$	(157,635)	$	(16,368)	$	(551,449)
Other comprehensive income (loss) before reclassifications	32,998		(167)		7,372		40,203
Amounts reclassified to net income (c)	41,387		3,805		458		45,650
Other comprehensive income	74,385		3,638		7,830		85,853
March 31, 2021	$	(303,061)	$	(153,997)	$	(8,538)	$	(465,596)

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

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

(c) - See Note C for details of amounts reclassified to net income for risk-management assets/liabilities and Note H for retirement and other postretirement benefit plan obligations.

The following table sets forth information about the balance of accumulated other comprehensive loss at March 31, 2021, 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 33 months (b)	$	(42,201)
Settled interest-rate swaps to be recognized over the life of the long-term, fixed-rate debt (c)	(186,076)
Interest-rate swaps with future settlement dates expected to be amortized over the life of long-term debt	(74,784)
Accumulated other comprehensive loss at March 31, 2021	$	(303,061)

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

(b) - Based on commodity prices on March 31, 2021, we expect $47.7 million in net losses, net of tax, over the next 12 months and $5.5 million in net gains, net of tax, thereafter.

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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.

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, 2021
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS
Net income available for common stock	$	385,901	445,894	$	0.87
Diluted EPS
Effect of dilutive securities	—		991
Net income available for common stock and common stock equivalents	$	385,901	446,885	$	0.86


	Three Months Ended March 31, 2020
	Loss		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS
Net loss available for common stock	$	(142,132)	414,282	$	(0.34)
Diluted EPS
Effect of dilutive securities	—		—
Net loss available for common stock and common stock equivalents (a)	$	(142,132)	414,282	$	(0.34)

(a) - For the three months ended March 31, 2020, 1,065,880 weighted-average shares have been excluded from the calculation of diluted loss per share as their inclusion would have been anti-dilutive due to our net loss available for common stock.

H. EMPLOYEE BENEFIT PLANS

The following table sets forth the components of net periodic benefit cost 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,
	2021		2020		2021		2020
	(Thousands of dollars)
Components of net periodic benefit cost (income)
Service cost	$	2,076	$	2,036	$	115	$	115
Interest cost	4,220		4,574		442		442
Expected return on plan assets	(6,269)		(6,232)		(722)		(722)
Amortization of prior service cost (a)	28		28		—		—
Amortization of net loss (a)	4,913		4,571		1		1
Net periodic benefit cost (income)	$	4,968	$	4,977	$	(164)	$	(164)

(a) - These components of net periodic benefit cost (income) are recognized in accumulated other comprehensive loss and are reclassified to other expense in our Consolidated Statements of Income, with related income tax benefits of $1.1 million reclassified to income tax (expense) benefit for both the three months ended March 31, 2021 and 2020.

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I. UNCONSOLIDATED AFFILIATES

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


	Three Months Ended
	March 31,
		2021		2020
		(Thousands of dollars)
Northern Border Pipeline		$	20,239	$	22,120
Overland Pass Pipeline		2,972		14,111
Roadrunner		7,749		6,433
Other		2,360		1,963
Equity in net earnings from investments		$	33,320	$	44,627
Impairment of equity investments		$	—	$	(37,730)

Equity in net earnings from Overland Pass Pipeline decreased for the three months ended March 31, 2021, compared with the same period in 2020, due primarily to lower volumes.

For the three months ended March 31, 2020, we incurred a noncash impairment charge of $30.5 million related to our 10.2% investment in Venice Energy Services Company in our Natural Gas Gathering and Processing segment, which includes $22.3 million related to equity-method goodwill, and a $7.2 million noncash impairment charge related to our 50% investment in Chisholm Pipeline Company in our Natural Gas Liquids segment.

We incurred expenses in transactions with unconsolidated affiliates of $15.6 million and $45.3 million for the three months ended March 31, 2021 and 2020, respectively, primarily related to Northern Border Pipeline and Overland Pass Pipeline. Accounts payable to our equity-method investees at March 31, 2021, and December 31, 2020, were $5.2 million and $8.4 million, respectively.

We have an operating agreement with Roadrunner that provides for reimbursement or payment to us for management services and certain operating costs, which are included in operating income (loss) in our Consolidated Statements of Income.

J. COMMITMENTS AND CONTINGENCIES

Environmental Matters and Pipeline Safety - The operation of pipelines, plants and other facilities for the gathering, processing, fractionation, 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 air and water quality, hazardous and solid waste management and disposal, cultural resource protection and other environmental and safety matters. The cost of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with these laws, 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 does not believe that, based on currently known information, a material risk of noncompliance with these laws and regulations exists that will affect adversely our consolidated results of operations, financial condition or cash flows.

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.

K. REVENUES

Accounting Policies - Many of the contract types described within Note A of the Notes to Consolidated Financial Statement in our Annual Report contain additional fees or charges payable by customers for nonperformance (e.g., minimum volume commitments or product specifications), which are considered to be variable consideration. These fees and charges are not recorded until it is probable that a significant reversal of the associated revenue will not occur.

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Contract Assets and Contract Liabilities - Our contract asset balances at the beginning and end of the period primarily relate to our firm service transportation contracts with tiered rates, which are not material. The following table sets forth the balances in contract liabilities for the periods indicated:


Contract Liabilities	(Millions of dollars)
Balance at December 31, 2020 (a)	$	41.4
Revenue recognized included in beginning balance	(20.4)
Net additions	12.3
Balance at March 31, 2021 (b)	$	33.3

(a) - Contract liabilities of $23.7 million and $17.7 million are included in other current liabilities and other deferred credits, respectively, in our Consolidated Balance Sheet.

(b) - Contract liabilities of $15.9 million and $17.4 million are included in other current liabilities and other deferred credits, respectively, in our Consolidated Balance Sheet.

Receivables from Customers and Revenue Disaggregation - Substantially all of the balances in accounts receivable on our Consolidated Balance Sheets at March 31, 2021, and December 31, 2020, relate to customer receivables. Revenues sources are disaggregated in Note L.

Transaction Price Allocated to Unsatisfied Performance Obligations - 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.

The following table presents aggregate value allocated to unsatisfied performance obligations as of March 31, 2021, 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 23 years:


Expected Period of Recognition in Revenue	(Millions of dollars)
Remainder of 2021	$	247.6
2022	273.4
2023	244.3
2024	204.1
2025 and beyond	796.1
Total estimated transaction price allocated to unsatisfied performance obligations	$	1,765.5

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.

L. 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;

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

• our Natural Gas Pipelines segment transports and stores natural gas via regulated intrastate and interstate 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.

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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, 2021	Natural Gas Gathering and Processing		Natural Gas Liquids (a)		Natural Gas Pipelines (b)		Total Segments
	(Thousands of dollars)
NGL and condensate sales	$	491,807	$	2,414,830	$	—	$	2,906,637
Residue natural gas sales	312,247		—		115,455		427,702
Gathering, processing and exchange services revenue	31,687		113,231		—		144,918
Transportation and storage revenue	—		48,728		132,947		181,675
Other	4,000		33,276		412		37,688
Total revenues (c)	839,741		2,610,065		248,814		3,698,620

Cost of sales and fuel (exclusive of depreciation and operating costs)	(555,306)		(2,060,319)		(10,013)		(2,625,638)
Operating costs	(84,598)		(124,369)		(42,317)		(251,284)
Equity in net earnings from investments	1,728		3,604		27,988		33,320
Noncash compensation expense and other	3,151		6,647		1,703		11,501
Segment adjusted EBITDA	$	204,716	$	435,628	$	226,175	$	866,519

Depreciation and amortization	$	(67,032)	$	(74,542)	$	(14,476)	$	(156,050)
Investments in unconsolidated affiliates	$	24,584	$	420,614	$	362,523	$	807,721
Total assets	$	6,535,260	$	13,944,887	$	2,096,459	$	22,576,606
Capital expenditures	$	39,651	$	112,021	$	21,157	$	172,829

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $570.6 million, of which $516.1 million related to revenues within the segment, and cost of sales and fuel of $135.8 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $181.4 million and cost of sales and fuel of $12.8 million.

(c) - Intersegment revenues are primarily commodity sales which are based on the contracted selling price that is generally index-based and settled monthly, and for the Natural Gas Gathering and Processing segment totaled $481.6 million. Intersegment revenues for the Natural Gas Liquids and Natural Gas Pipelines segments were not material.


Three Months Ended March 31, 2021	Total Segments		Other and Eliminations		Total
	(Thousands of dollars)
Reconciliations of total segments to consolidated
NGL and condensate sales	$	2,906,637	$	(500,064)	$	2,406,573
Residue natural gas sales	427,702		—		427,702
Gathering, processing and exchange services revenue	144,918		—		144,918
Transportation and storage revenue	181,675		(3,535)		178,140
Other	37,688		(342)		37,346
Total revenues (a)	$	3,698,620	$	(503,941)	$	3,194,679

Cost of sales and fuel (exclusive of depreciation and operating costs)	$	(2,625,638)	$	504,128	$	(2,121,510)
Operating costs	$	(251,284)	$	(313)	$	(251,597)
Depreciation and amortization	$	(156,050)	$	(1,070)	$	(157,120)
Equity in net earnings from investments	$	33,320	$	—	$	33,320
Investments in unconsolidated affiliates	$	807,721	$	—	$	807,721
Total assets	$	22,576,606	$	603,323	$	23,179,929
Capital expenditures	$	172,829	$	3,905	$	176,734

(a) - Noncustomer revenue for the three months ended March 31, 2021, totaled $(132.2) million related primarily to losses from derivatives on commodity contracts.

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Three Months Ended March 31, 2020	Natural Gas Gathering and Processing		Natural Gas Liquids (a)		Natural Gas Pipelines (b)		Total Segments
	(Thousands of dollars)
NGL and condensate sales	$	219,917	$	1,596,711	$	—	$	1,816,628
Residue natural gas sales	189,051		—		2,035		191,086
Gathering, processing and exchange services revenue	37,937		120,536		—		158,473
Transportation and storage revenue	—		50,755		118,364		169,119
Other	3,075		2,590		384		6,049
Total revenues (c)	449,980		1,770,592		120,783		2,341,355

Cost of sales and fuel (exclusive of depreciation and operating costs)	(202,170)		(1,278,754)		(1,539)		(1,482,463)
Operating costs	(84,470)		(89,571)		(33,307)		(207,348)
Equity in net earnings from investments	806		15,268		28,553		44,627
Noncash compensation expense and other	(4,498)		(6,619)		(1,966)		(13,083)
Segment adjusted EBITDA	$	159,648	$	410,916	$	112,524	$	683,088

Depreciation and amortization	$	(58,756)	$	(57,841)	$	(14,769)	$	(131,366)
Impairment charges (d)	$	(564,353)	$	(77,401)	$	—	$	(641,754)
Investments in unconsolidated affiliates	$	4,276	$	435,024	$	371,179	$	810,479
Total assets	$	6,374,552	$	12,682,807	$	2,089,362	$	21,146,721
Capital expenditures	$	181,610	$	746,183	$	16,590	$	944,383

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $435.1 million, of which $378.2 million related to revenues within the segment, and cost of sales and fuel of $120.4 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $73.9 million and cost of sales and fuel of $6.1 million.

(c) - Intersegment revenues are primarily commodity sales, which are based on the contracted selling price that is generally index-based and settled monthly, and for the Natural Gas Gathering and Processing segment totaled $213.3 million. Intersegment revenues for the Natural Gas Liquids and Natural Gas Pipelines segments were not material.

(d) - Includes noncash impairment charges of $380.5 million related primarily to long-lived assets, $153.4 million related to goodwill and $30.5 million related to an investment in an unconsolidated affiliate in our Natural Gas Gathering and Processing segment; and $70.2 million related to long-lived assets and $7.2 million related to an investment in an unconsolidated affiliate in our Natural Gas Liquids segment.


Three Months Ended March 31, 2020	Total Segments		Other and Eliminations		Total
	(Thousands of dollars)
Reconciliations of total segments to consolidated
NGL and condensate sales	$	1,816,628	$	(199,472)	$	1,617,156
Residue natural gas sales	191,086		(1,032)		190,054
Gathering, processing and exchange services revenue	158,473		—		158,473
Transportation and storage revenue	169,119		(3,809)		165,310
Other	6,049		(370)		5,679
Total revenues (a)	$	2,341,355	$	(204,683)	$	2,136,672

Cost of sales and fuel (exclusive of depreciation and operating costs)	$	(1,482,463)	$	205,535	$	(1,276,928)
Operating costs	$	(207,348)	$	308	$	(207,040)
Depreciation and amortization	$	(131,366)	$	(987)	$	(132,353)
Impairment charges	$	(641,754)	$	—	$	(641,754)
Equity in net earnings from investments	$	44,627	$	—	$	44,627
Investments in unconsolidated affiliates	$	810,479	$	—	$	810,479
Total assets	$	21,146,721	$	822,719	$	21,969,440
Capital expenditures	$	944,383	$	5,296	$	949,679

(a) - Noncustomer revenue for the three months ended March 31, 2020, totaled $80.2 million related primarily to gains from derivatives on commodity contracts.

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	Three Months Ended
	March 31,
		2021		2020
		(Thousands of dollars)
Reconciliation of net income (loss) to total segment adjusted EBITDA
Net income (loss)		$	386,176	$	(141,857)
Add:
Interest expense, net of capitalized interest		185,523		140,616
Depreciation and amortization		157,120		132,353
Income tax expense (benefit)		122,132		(55,395)
Impairment charges		—		641,754
Noncash compensation expense		16,283		(1,302)
Other corporate costs and equity AFUDC (a)		(715)		(33,081)
Total segment adjusted EBITDA		$	866,519	$	683,088

(a) - The three months ended March 31, 2020, includes corporate gains of $15.8 million on extinguishment of debt related to open market repurchases.

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.

Market Conditions, COVID-19 and Business Update - Despite the COVID-19 pandemic, we expect earnings growth in 2021 due primarily to increasing volumes, available capacity and efficiency gains from recently completed capital-growth projects, continued flared natural gas capture and rising gas-to-oil ratios in the Williston Basin. Although the energy industry has experienced many up and down cycles, we have positioned ourselves to reduce exposure to direct commodity price volatility. Each of our three reportable segments are primarily fee-based, and we expect our consolidated earnings to be approximately 90% fee-based in 2021. While our Natural Gas Gathering and Processing segment’s earnings are primarily fee-based, we have direct commodity price exposure related primarily to fee with POP contracts. In addition, our Natural Gas Gathering and Processing and Natural Gas Liquids segments are exposed to volumetric risk as a result of reduced drilling and completion activity, declining well productivity, severe weather disruption, operational outages and crude oil, NGL and natural gas demand. Our Natural Gas Pipelines segment is not exposed to significant volumetric risk due to nearly all of our capacity being subscribed under long-term firm fee-based contracts.

In continued response to COVID-19, we remain committed to managing the impact of the pandemic on our employees. We continue to protect our workforce and, as always, we remain focused on operating our assets safely, reliably and in an environmentally responsible manner. We continue to monitor the COVID-19 outbreak and have previously implemented our business continuity plans. ONEOK is a critical infrastructure business as defined by the United States Department of Homeland Security and, therefore, our workforce has remained fully engaged within federal, state and local government issued guidelines and safety-related ordinances. We continue to practice remote work procedures when possible to protect the safety of our employees and their families and continue to take precautions for our employees who work in the field or need to report to a ONEOK facility, such as facility access restrictions, workspace modifications, social distancing, face covering protocols and sanitation procedures. As COVID-19 vaccinations are becoming more readily available, we anticipate implementing a return to office plan later this year. We continue to apply risk-management and cybersecurity measures designed so that our systems remain functional in order to both serve our operational needs and to provide service to our customers.

In February 2021, Winter Storm Uri brought significant challenges to the energy industry and our operating areas. Our employees were proactive in preparing for the severe winter weather, made the necessary operational adjustments to keep our assets running and provided exceptional service to meet the needs of our customers during the difficult weather conditions as demand for natural gas, propane and electricity soared. This increased demand, coupled with supply reductions from wellhead freeze-offs and power outages to processing plants in the Mid-Continent and Rocky Mountain regions and the Permian Basin

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and fractionators in the Mid-Continent region, resulted in record high commodity prices at certain market hubs, particularly in the Mid-Continent region and in Texas. Commodity prices quickly returned to previous levels as the weather improved and natural gas supply returned.

Winter Storm Uri impacted all three of our operating segments, resulting in a net positive impact to our financial results, as our ability to meet increased demand for natural gas and NGLs during the period more than offset the unfavorable volume impacts. Our well-positioned natural gas storage assets and market connected pipelines in our Natural Gas Pipelines segment were able to meet critical needs during this period of severe winter weather. The reliability of our interstate and intrastate assets enabled us to continue to provide our customers access to transportation services, park-and-loan services and additional natural gas supply if available, which improved our financial results. However, wellhead freeze-offs reduced February volumes in our Natural Gas Gathering and Processing and Natural Gas Liquids segments, which negatively impacted our financial results.

We expect to maintain sufficient liquidity and financial stability in 2021 due to cash flows from operations, our undrawn $2.5 Billion Credit Agreement, $402.4 million in cash and cash equivalents and no debt maturities until 2022.

See Part I, Item 3, Quantitative and Qualitative Disclosures About Market Risk, in this Quarterly Report for more information on our exposure to market risk.

Sustainability - We continue to look for ways to reduce our environmental impact and utilize more efficient technologies. In 2021, we qualified for inclusion in the S&P Global Sustainability Yearbook and received Industry Mover status, which is awarded to a company that recorded the strongest year-over-year improvement in its industry. In addition, we received a perfect score of 100 in the Human Rights Campaign 2021 Corporate Equality Index. We have a stand-alone environmental sustainability team, formed in 2017, that accelerated our ongoing environmental stewardship efforts and is exploring ways to lower our greenhouse gas emissions. We are actively researching opportunities that will complement our extensive midstream assets and help enhance the vital role we expect to play in a future transition to a low-carbon economy.

Natural Gas - In our Natural Gas Gathering and Processing segment, gathered and processed volumes in the Rocky Mountain region increased in the three months ended March 31, 2021, compared with the same period in 2020, due primarily to the completion of capital-growth projects and the capture of natural gas previously flared. In February 2021, we experienced severe winter weather as a result of Winter Storm Uri that reduced volumes across our operating system. However, volume levels quickly returned and exceeded 1.2 Bcf/d in the Rocky Mountain region in March 2021. We expect these Rocky Mountain region volumes to be sustainable for the remainder of 2021, even with no increase in producer activity, due to the completion of previously drilled but uncompleted wells, the capture of natural gas previously flared and rising gas-to-oil ratios in the Williston Basin. In addition, as prices and volumes continue to strengthen, we currently have the processing capacity to benefit from production growth. Our Bear Creek plant expansion, which was previously paused, is expected to be completed later this year, which will increase our total processing capacity to approximately 1.7 Bcf/d in the Williston Basin.

In our Natural Gas Pipelines segment, our assets are connected to key supply areas and demand centers, including export markets in Mexico via our Roadrunner joint venture and supply areas in Canada and the United States via our interstate and intrastate natural gas pipelines and our Northern Border Pipeline joint venture, which enable us to provide essential natural gas transportation and storage services. Continued demand from local distribution companies, electric-generation facilities and large industrial companies resulted in low-cost expansions in 2019 and 2020 that position us well to provide additional expansions for our customers when needed. In February 2021, severe winter weather impacted our operations. Due to the reliability of our pipeline and storage assets, we were able to continue to provide services to customers serving critical needs during the winter storm. Our natural gas transportation capacity contracted is not significantly impacted by market conditions, as our end users rely on natural gas to support their business regardless of commodity price fluctuations. We continue to experience stable fee-based earnings with transportation capacity more than 95% contracted with firm commitments, and we expect these stable fee-based earnings to continue throughout 2021 at similarly contracted levels. In addition, during the first quarter 2021, we sold natural gas that we owned and held in storage, which benefited our segment’s financial results. During the extreme winter weather periods, we maximized natural gas storage withdrawals for firm service customers serving critical needs.

NGLs - In our Natural Gas Liquids segment, NGL volumes decreased for the three months ended March 31, 2021, compared with the same period in 2020, due primarily to the unfavorable impact of Winter Storm Uri in February 2021 across our operations, offset partially by increased volumes in the Rocky Mountain region. Volumes quickly returned, and our average daily raw feed throughput volumes in March 2021 increased, compared with both the first and fourth quarters 2020, and we expect these improved NGL volumes to continue. We expect to benefit from increasing volumes, without significant capital investment, on our integrated assets, which were strengthened through our recently completed capital-growth projects.

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Growth Projects - We operate an integrated, reliable and diversified network of NGL and natural gas gathering, processing, fractionation, storage and transportation assets connecting supply in the Rocky Mountain, Mid-Continent and Permian regions with key market centers. We have completed significant capital-growth projects that include NGL pipelines, NGL fractionators, natural gas processing plants and related natural gas and NGL infrastructure. These projects provide us the capacity to benefit from future supply growth without significant capital investment. In the first quarter 2020, due to the decline in commodity prices and economic demand disruption caused by COVID-19, we paused various projects, which can be restarted quickly when producer activity warrants additional infrastructure. Our announced capital-growth projects are outlined in the table below:


Project	Scope	Approximate Costs (a)	Expected Completion
Natural Gas Gathering and Processing		(In millions)




Bear Creek plant expansion and related infrastructure	200 MMcf/d processing plant expansion and related gathering infrastructure in the Williston Basin	$405	Q4 2021
	Supported by acreage dedications with long-term primarily fee-based contracts
Natural Gas Liquids















Arbuckle II pipeline expansion	Increasing mainline capacity with additional pump facilities	$60	Q2 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	Paused (c)
	Fully contracted with long-term contracts
West Texas LPG pipeline expansion	Increasing mainline capacity by 40 MBbl/d	$145	Paused (b)
	Supported by long-term dedicated production from third-party processing plants expected to produce up to 45 MBbl/d
Mid-Continent fractionation facility expansions	65 MBbl/d of expansions at our Mid-Continent NGL facilities	$150	Paused (c)

(a) - Excludes capitalized interest/AFUDC.

(b) - We do not expect to complete construction by the original target completion date.

(c) - While many of the construction activities on these projects were paused in 2020, some activity continued in order to complete the infrastructure necessary to support volumes until market conditions warrant full project completion.

Ethane Production - Price differentials between ethane and natural gas can cause natural gas processors to process ethane as an NGL or leave some of the ethane component in the natural gas stream. As a result of these ethane economics, ethane volumes on our system can also fluctuate period to period. Ethane volumes under long-term contracts delivered to our NGL system averaged 355 MBbl/d in the first quarter 2021, compared with 370 MBbl/d in the first quarter 2020, due primarily to decreased volumes related to Winter Storm Uri in February 2021 across our operations. We expect ethane production to increase from the first quarter 2021 volumes and continue to fluctuate throughout 2021. We estimate that there are ethane volumes of approximately 100 MBbl/d in both the Rocky Mountain and Mid-Continent regions that represent potential ethane opportunity for our Natural Gas Liquids segment.

Dividends - In February 2021, we maintained and paid a quarterly dividend of $0.935 per share ($3.74 per share on an annualized basis), which is consistent with the same quarter in the prior year. We declared a quarterly dividend of $0.935 per share ($3.74 per share on an annualized basis) in April 2021. The quarterly dividend will be paid May 14, 2021, to shareholders of record at the close of business on April 26, 2021.

FINANCIAL RESULTS AND OPERATING INFORMATION

How We Evaluate Our Operations

Management uses a variety of financial and operating metrics to analyze our performance. Our consolidated financial metrics include: (1) operating income (loss); (2) net income (loss); (3) diluted EPS; and (4) the following non-GAAP financial measures: adjusted EBITDA and distributable cash flow. We evaluate segment operating results using adjusted EBITDA and our operating metrics, which include various volume and rate statistics that are relevant for the respective segment. These operating metrics allow investors to analyze the various components of segment financial results in terms of volumes and rate/

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price. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results. For additional information on our operating metrics, see the respective segment subsections of this “Financial Results and Operating Information” section.

Non-GAAP Financial Measures - Adjusted EBITDA, distributable cash flow and dividend coverage ratio are non-GAAP measures 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 certain other noncash items. Distributable cash flow is defined as adjusted EBITDA, computed as described above, less interest expense, maintenance capital expenditures and equity earnings from investments, excluding noncash impairment charges, adjusted for net cash distributions received from unconsolidated affiliates and certain other items. Dividend coverage ratio is defined as distributable cash flow to common shareholders divided by the dividends paid in the period. We believe these non-GAAP financial measures are useful to investors because they and similar measures are used by many companies in our industry as a measurement of financial performance and are commonly employed by financial analysts and others to evaluate our financial performance and to compare financial performance among companies in our industry. Adjusted EBITDA, distributable cash flow and dividend coverage ratio should not be considered alternatives to net income, EPS or any other measure of financial performance presented in accordance with GAAP. Additionally, these calculations may not be comparable with similarly titled measures of other companies.

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,					2021 vs. 2020
Financial Results		2021		2020			$ Increase (Decrease)
		(Millions of dollars, except per share amounts)
Revenues
Commodity sales		$	2,836.1	$	1,808.6		1,027.5
Services		358.6		328.1			30.5
Total revenues		3,194.7		2,136.7			1,058.0
Cost of sales and fuel (exclusive of items shown separately below)		2,121.5		1,276.9			844.6
Operating costs		251.7		207.1			44.6
Depreciation and amortization		157.1		132.4			24.7
Impairment charges		—		604.0			(604.0)
Gain on sale of assets		(0.3)		(0.2)			0.1
Operating income (loss)		$	664.7	$	(83.5)		748.2
Equity in net earnings from investments		$	33.3	$	44.6		(11.3)
Impairment of equity investments		$	—	$	(37.7)		(37.7)
Interest expense, net of capitalized interest		$	(185.5)	$	(140.6)		44.9
Net income (loss)		$	386.2	$	(141.9)		528.1
Diluted EPS		$	0.86	$	(0.34)		1.20
Adjusted EBITDA		$	866.4	$	700.8		165.6
Distributable cash flow		$	661.9	$	522.3		139.6
Capital expenditures		$	176.7	$	949.7		(773.0)

See reconciliation of net income (loss) to adjusted EBITDA and distributable cash flow in the “Non-GAAP Financial Measures” 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 these line items, except where noted.

Operating income increased $748.2 million for the three months ended March 31, 2021, compared with the same period in 2020, primarily as a result of the following:

•an increase of $604.0 million due to noncash impairment charges in our Natural Gas Gathering and Processing and Natural Gas Liquids segments in the three months ended March 31, 2020;

•Natural Gas Pipelines - an increase of $104.9 million due primarily to increased natural gas sales;

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•Natural Gas Liquids - increases of $63.8 million in exchange services related primarily to higher volumes in the Rocky Mountain region and $38.8 million in optimization and marketing, offset by a $46.2 million decrease from the impact of Winter Storm Uri in exchange services; and

•Natural Gas Gathering and Processing - an increase of $45.6 million due primarily to lower realized prices in the prior year impacting our fee with POP contracts; offset by

•an increase of $44.6 million in operating costs due primarily to a benefit related to the mark-to-market of our share-based deferred compensation plan in the prior year, higher employee-related costs, ad valorem taxes and supplies expense; and

•an increase of $24.7 million in depreciation expense due to capital projects placed in service.

Net income and diluted EPS increased for the three months ended March 31, 2021, compared with the same period in 2020, due primarily to the items discussed above and noncash impairment charges related to equity investments in our Natural Gas Gathering and Processing and Natural Gas Liquids segments in the prior year. These increases were offset partially by higher interest expense related to higher debt balances and lower capitalized interest, and lower equity AFUDC due to completed projects.

Capital expenditures decreased for the three months ended March 31, 2021, compared with the same period in 2020, due primarily to our previously completed and paused capital-growth projects.

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

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 NGL 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 fee with POP contracts. Under certain fee with POP contracts, our contractual fees and POP percentage may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds. To mitigate the impact of this commodity price exposure, we have hedged a portion of our Natural Gas Gathering and Processing segment’s commodity price risk for the remainder of 2021 and into 2022. This segment has substantial long-term acreage dedications in some of the most productive areas of the Williston Basin, which helps to mitigate volumetric risk.

Growth Projects - Our Natural Gas Gathering and Processing segment has invested in growth projects in NGL-rich areas in the Williston Basin. See “Growth Projects” in the “Recent Developments” section for discussion of our capital-growth project.

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 and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Gathering and Processing segment for the periods indicated:


	Three Months Ended					Three Months
	March 31,					2021 vs. 2020
Financial Results		2021		2020			$ Increase (Decrease)
		(Millions of dollars)
NGL sales		$	457.6	$	178.4		279.2
Condensate sales		34.2		41.5			(7.3)
Residue natural gas sales		312.2		189.1			123.1
Gathering, compression, dehydration and processing fees and other revenue		35.7		41.0			(5.3)
Cost of sales and fuel (exclusive of depreciation and operating costs)		(555.3)		(202.2)			353.1
Operating costs, excluding noncash compensation adjustments		(80.7)		(87.8)			(7.1)
Equity in net earnings from investments		1.7		0.8			0.9
Other		(0.7)		(1.2)			0.5
Adjusted EBITDA		$	204.7	$	159.6		45.1
Impairment charges		$	—	$	564.4		(564.4)
Capital expenditures		$	39.7	$	181.6		(141.9)

See reconciliation of net income (loss) to adjusted EBITDA in the “Non-GAAP Financial Measures” 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 $45.1 million for the three months ended March 31, 2021, compared with the same period in 2020, primarily as a result of the following:

•an increase of $45.6 million due primarily to lower realized prices in the prior year impacting our fee with POP contracts; and

•a decrease of $7.1 million in operating costs due primarily to lower materials and supplies and outside services; offset by

•a decrease of $9.0 million due primarily to lower volumes in the Mid-Continent region related to Winter Storm Uri and natural production declines, offset partially by higher volumes in the Rocky Mountain region.

The three months ended March 31, 2020, includes $380.5 million of noncash impairment charges related primarily to certain long-lived asset groups in the Powder River Basin, western Oklahoma and Kansas that were not recoverable, a $153.4 million noncash impairment charge related to goodwill and a $30.5 million noncash impairment charge related to our 10.2% investment in Venice Energy Services Company.

Capital expenditures decreased for the three months ended March 31, 2021, compared with the same period in 2020, due primarily to capital-growth projects completed in 2020, as well as our paused capital-growth project in 2020.


	Three Months Ended
	March 31,
Operating Information (a)		2021		2020
Natural gas gathered (BBtu/d)		2,589		2,769
Natural gas processed (BBtu/d) (b)		2,380		2,568





Average fee rate ($/MMBtu)		$	1.04	$	0.85

(a) - Includes volumes for consolidated entities only.

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

Our natural gas gathered and natural gas processed volumes decreased for the three months ended March 31, 2021, compared with the same period in 2020, due primarily to the impact of Winter Storm Uri and natural production declines in the Mid-Continent region, offset partially by increased production in the Rocky Mountain region.

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Our average fee rate increased for the three months ended March 31, 2021, compared with the same period in 2020, due primarily to an increase in the Rocky Mountain region’s contribution to our average fee rate and was also impacted by decreased volumes in the Mid-Continent region due to Winter Storm Uri.

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. 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 NGL gathering and distribution pipelines in Oklahoma, Kansas, Texas, New Mexico, Montana, North Dakota, Wyoming and Colorado, and terminal and storage facilities in Kansas, Missouri, Nebraska, Iowa and Illinois. We have a 50% ownership interest in Overland Pass Pipeline Company, which operates an interstate NGL pipeline originating in Wyoming and Colorado and terminating in Kansas. The majority of the pipeline-connected natural gas processing plants in the Williston Basin, Oklahoma, Kansas and the Texas Panhandle are connected to our NGL gathering systems. We lease rail cars and own and operate truck- and rail-loading and -unloading facilities connected to our NGL fractionation, storage and pipeline assets. We also own FERC-regulated NGL 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.

Growth Projects - Our Natural Gas Liquids segment invests in projects to transport, fractionate, store and deliver to market centers NGL supply from shale and other resource development areas. Our growth strategy is focused around connecting diversified supply basins from the Rocky Mountain region through the Mid-Continent region and the Permian Basin with NGL product demand from the petrochemical and refining industries and NGL export demand in the Gulf Coast. See “Growth Projects” in the “Recent Developments” section for discussion of our capital-growth projects.

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

Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Liquids segment for the periods indicated:


	Three Months Ended					Three Months
	March 31,					2021 vs. 2020
Financial Results		2021		2020			$ Increase (Decrease)
		(Millions of dollars)
NGL and condensate sales		$	2,414.8	$	1,596.7		818.1
Exchange service revenues and other		146.5		123.1			23.4
Transportation and storage revenues		48.7		50.8			(2.1)
Cost of sales and fuel (exclusive of depreciation and operating costs)		(2,060.3)		(1,278.8)			781.5
Operating costs, excluding noncash compensation adjustments		(116.0)		(94.4)			21.6
Equity in net earnings from investments		3.6		15.3			(11.7)
Other		(1.7)		(1.8)			0.1
Adjusted EBITDA		$	435.6	$	410.9		24.7
Impairment charges		$	—	$	77.4		(77.4)
Capital expenditures		$	112.0	$	746.2		(634.2)

See reconciliation of net income (loss) to adjusted EBITDA in the “Non-GAAP Financial Measures” 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.

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Adjusted EBITDA increased $24.7 million for the three months ended March 31, 2021, compared with the same period in 2020, primarily as a result of the following:

•an increase of $63.8 million in exchange services (excluding the impact of Winter Storm Uri discussed below) due primarily to:

◦$51.8 million in higher volumes in the Rocky Mountain region,

◦$32.9 million in lower transportation costs,

◦$15.8 million related to wider commodity price differentials, offset by

◦$19.0 million in lower average fee rates,

◦$13.2 million in lower volumes in the Permian Basin due to short-term contracts and increased ethane rejection, and

◦$9.5 million related to lower earnings on unfractionated NGLs held in inventory; and

•an increase of $38.8 million in optimization and marketing due primarily to increased activities during Winter Storm Uri and unfavorable changes in the value of NGLs held in inventory in 2020; offset by

•the negative impact of Winter Storm Uri of $46.2 million in exchange services due primarily to decreased volumes across our operations and increased electricity costs;

•an increase of $21.6 million in operating costs due primarily to higher employee-related costs and increased ad valorem taxes associated with our completed capital-growth projects; and

•a decrease of $11.7 million from lower equity in net earnings from investments due primarily to lower volumes on Overland Pass Pipeline.

The three months ended March 31, 2020, includes $70.2 million of noncash impairment charges related to certain inactive assets and a $7.2 million noncash impairment charge related to our 50% investment in Chisholm Pipeline Company.

Capital expenditures decreased for the three months ended March 31, 2021, compared with the same period in 2020, due primarily to completed and paused capital-growth projects.


	Three Months Ended
	March 31,
Operating Information		2021		2020
Raw feed throughput (MBbl/d) (a)		1,036		1,091


Average Conway-to-Mont Belvieu OPIS price differential - ethane in ethane/propane mix ($/gallon)		$	(0.02)	$	0.01

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

Volumes decreased for the three months ended March 31, 2021, compared with the same period in 2020, due primarily to the unfavorable impact of Winter Storm Uri across our operations, offset partially by increased production at new and existing processing plants in the Rocky Mountain region.

Natural Gas Pipelines

Overview - Our Natural Gas Pipelines segment, through its wholly owned assets primarily in Oklahoma, Texas and the upper Midwest, provides transportation and storage services to end users, such as natural gas distribution and electric-generation companies, that require natural gas to operate their businesses regardless of location price differentials. We have 50% ownership interests in Northern Border Pipeline and Roadrunner, which provide transportation services to various end users.

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Selected Financial Results and Operating Information - The following tables set 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,					2021 vs. 2020
Financial Results		2021		2020			$ Increase (Decrease)
		(Millions of dollars)
Transportation revenues		$	117.1	$	101.9		15.2
Storage revenues		15.8		16.5			(0.7)
Residue natural gas sales and other revenues		115.9		2.4			113.5
Cost of sales and fuel (exclusive of depreciation and operating costs)		(10.0)		(1.5)			8.5
Operating costs, excluding noncash compensation adjustments		(40.1)		(34.7)			5.4
Equity in net earnings from investments		28.0		28.6			(0.6)
Other		(0.5)		(0.7)			0.2
Adjusted EBITDA		$	226.2	$	112.5		113.7

Capital expenditures		$	21.2	$	16.6		4.6

See reconciliation of net income (loss) to adjusted EBITDA in the “Non-GAAP Financial Measures” section.

Adjusted EBITDA increased $113.7 million for the three months ended March 31, 2021, compared with the same period in 2020, primarily as a result of the following:

•an increase of $104.9 million due primarily to higher average natural gas prices on 5.2 Bcf of natural gas sales in the first quarter 2021 of volumes previously held in inventory, compared with 1.2 Bcf in the first quarter 2020; and

•an increase of $15.4 million in transportation services due primarily to higher park-and-loan revenue and higher interruptible transportation revenue; offset by

•an increase of $5.4 million in operating costs due primarily to higher employee-related costs and supplies expenses.

Capital expenditures increased for the three months ended March 31, 2021, compared with the same period in 2020, due primarily to capital-growth projects.


	Three Months Ended
	March 31,
Operating Information (a)		2021		2020
Natural gas transportation capacity contracted (MDth/d)		7,423		7,791
Transportation capacity contracted		95	%	100	%

(a) - Includes volumes for consolidated entities only.

Natural gas transportation capacity contracted decreased for the three months ended March 31, 2021, compared with the same period in 2020, due primarily to a contract settlement in the second quarter 2020.

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 2021.

In February 2021, our subsidiary, Midwestern Gas Transmission Company, filed a proposed change in rates pursuant to Section 4 of the Natural Gas Act with the FERC. The FERC is currently reviewing the filing. While the ultimate outcome of the filing cannot be predicted, we do not expect the ultimate outcome to impact materially our results of operations.

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Non-GAAP Financial Measures

The following table sets forth a reconciliation of net income (loss), the nearest comparable GAAP financial performance measure, to adjusted EBITDA, distributable cash flow and dividend coverage for the periods indicated:


	Three Months Ended
	March 31,
		2021		2020
Reconciliation of net income (loss) to adjusted EBITDA, distributable cash flow and dividend coverage		(Thousands of dollars, except per share amounts and coverage ratios)
Net income (loss)		$	386,176	$	(141,857)
Add:
Interest expense, net of capitalized interest		185,523		140,616
Depreciation and amortization		157,120		132,353
Income tax expense (benefit)		122,132		(55,395)
Impairment charges		—		641,754
Noncash compensation expense (a)		16,283		(1,302)
Equity AFUDC and other noncash items		(813)		(15,409)
Adjusted EBITDA (b)		866,421		700,760
Interest expense, net of capitalized interest		(185,523)		(140,616)
Maintenance capital		(23,690)		(25,189)
Equity in net earnings from investments		(33,320)		(44,627)
Distributions received from unconsolidated affiliates		41,053		48,526
Other (b)		(3,080)		(16,524)
Distributable cash flow		661,861		522,330
Dividends paid to preferred shareholders		(275)		(275)
Distributable cash flow to shareholders		661,586		522,055
Dividends paid		(415,954)		(386,392)
Distributable cash flow in excess of dividends paid		$	245,632	$	135,663
Dividends paid per share		$	0.935	$	0.935
Dividend coverage ratio		1.59		1.35
Number of shares used in computation (thousands)		444,871		413,253

(a) - Includes a loss of $3.9 million and a benefit of $18.8 million related to the mark-to-market of our share-based deferred compensation plan for the three months ended March 31, 2021 and 2020, respectively.

(b) - Three months ended March 31, 2020, includes gains of $15.8 million on extinguishment of debt related to open market repurchases.


	Three Months Ended
	March 31,
	2021		2020
Reconciliation of segment adjusted EBITDA to adjusted EBITDA
Segment adjusted EBITDA:
Natural Gas Gathering and Processing	$	204,716	$	159,648
Natural Gas Liquids	435,628		410,916
Natural Gas Pipelines	226,175		112,524
Other (a)	(98)		17,672
Adjusted EBITDA	$	866,421	$	700,760

(a) - Three months ended March 31, 2020, includes corporate gains of $15.8 million on extinguishment of debt related to open market repurchases.

CONTINGENCIES

See Note J of the Notes to Consolidated Financial Statements in this Quarterly Report for discussion of our legal proceedings.

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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 for the remainder of 2021 to be primarily related to dividends paid to shareholders and capital expenditures.

We expect our sources of cash inflows to provide sufficient resources to finance our operations and quarterly cash dividends. We believe we have sufficient liquidity due to our $2.5 Billion Credit Agreement, which expires in June 2024 and access to $1.0 billion available through our “at-the-market” equity program. As of the date of this report, we had no borrowings under our $2.5 Billion Credit Agreement, and no shares have been sold through our “at-the-market” equity program.

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

Guarantees and Cash Management - We and ONEOK Partners are issuers of certain public debt securities. We guarantee certain indebtedness of ONEOK Partners, and ONEOK Partners and the Intermediate Partnership guarantee certain of our indebtedness. The guarantees in place for our and ONEOK Partners’ indebtedness are full, irrevocable, unconditional and absolute joint and several guarantees to the holders of each series of outstanding securities. Liabilities under the guarantees rank equally in right of payment with all existing and future senior unsecured indebtedness. As ONEOK Partners and the Intermediate Partnership are consolidated subsidiaries of ONEOK, separate financial statements for the guarantors are not required as long as the alternative disclosure required by Rule 13-01 is provided, which includes narrative disclosure and summarized financial information. The Intermediate Partnership holds all of ONEOK Partners’ interests and equity in its subsidiaries, which are non-guarantors, and substantially all the assets and operations reside with non-guarantor operating subsidiaries. Therefore, as allowed under Rule 13-01, we have excluded the summarized financial information for each issuer and guarantor as the combined financial information of the subsidiary issuer and parent guarantor, excluding our ownership of all the interests in ONEOK Partners, reflect no material assets, liabilities or results of operations, apart from the guaranteed indebtedness. For additional information on our and ONEOK Partners’ indebtedness, see Note D of the Notes to Consolidated Financial Statements in this Quarterly Report.

We use a centralized cash management program that concentrates the cash assets of our non-guarantor 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 and our $2.5 Billion Credit Agreement. As of March 31, 2021, we are in compliance with all covenants of the $2.5 Billion Credit Agreement.

At March 31, 2021, we had no borrowings under our $2.5 Billion Credit Agreement and $402.4 million of cash and cash equivalents.

As of March 31, 2021, we had a working capital deficit of $50.4 million (defined as current assets less current liabilities). Although working capital is influenced by several factors, including, among other things: (i) the timing of (a) debt and equity issuances, (b) the funding of capital expenditures, (c) scheduled debt payments, and (d) accounts receivable and payable; and (ii) the volume and cost of inventory and commodity imbalances, our working capital deficit at March 31, 2021, was driven primarily by current maturities of long-term debt. We may have working capital deficits in future periods as we continue to repay long-term debt. 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, 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, issuing 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.

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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 and short- and long-term debt.

Capital expenditures, excluding AFUDC and capitalized interest, were $176.7 million and $949.7 million for the three months ended March 31, 2021 and 2020, respectively.

We expect total capital expenditures, excluding AFUDC and capitalized interest, of $525-$675 million in 2021.

Credit Ratings - Our long-term debt credit ratings as of April 19, 2021, 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
Fitch	BBB	F2	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. Although we are in the midst of a challenging market environment, our credit ratings remained stable. 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 could 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 $2.5 Billion Credit Agreement, which expires in 2024. An adverse credit rating change alone is not a default under our $2.5 Billion Credit Agreement.

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 common stock dividends declared by our Board of Directors, subject to the rights of the holders of outstanding preferred stock. In February 2021, we paid a dividend of $0.935 per share ($3.74 per share on an annualized basis). A dividend of $0.935 per share was declared for the shareholders of record at the close of business on April 26, 2021, payable May 14, 2021.

For the three months ended March 31, 2021, our cash flows from operations exceeded dividends paid by $117.1 million. We expect our cash flows from operations to continue to sufficiently fund our cash dividends. To the extent operating cash flows are not sufficient to fund our dividends, we may utilize cash on hand from other sources of short- and long-term liquidity to fund a portion of our dividends.

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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				2021 vs. 2020
	March 31,				Favorable (Unfavorable)
	2021		2020
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	533.3	$	422.7	$	110.6
Investing activities	(170.7)		(964.8)		794.1
Financing activities	(484.7)		1,052.7		(1,537.4)
Change in cash and cash equivalents	(122.1)		510.6		(632.7)
Cash and cash equivalents at beginning of period	524.5		21.0		503.5
Cash and cash equivalents at end of period	$	402.4	$	531.6	$	(129.2)

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 NGLs and natural gas 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, 2021, increased $128.8 million compared with the same period in 2020. This increase is due primarily to natural gas sales in our Natural Gas Pipelines segment, as discussed in “Financial Results and Operating Information.”

The changes in operating assets and liabilities decreased operating cash flows $138.4 million for the three months ended March 31, 2021, compared with a decrease of $120.2 million for the same period in 2020. This change is due primarily to changes in accounts receivable resulting from the timing of receipt of cash from customers and NGLs and natural gas in storage, which varies from period to period and with changes in commodity prices; offset partially by changes in accounts payable resulting from the timing of payments to vendors, suppliers and other third parties; and changes in risk-management assets and liabilities and commodity imbalances, which vary from period to period and with changes in commodity prices and interest rates.

Investing Cash Flows - Cash used in investing activities for the three months ended March 31, 2021, decreased $794.1 million, compared with the same period in 2020, due primarily to reduced capital expenditures related to our completed and paused capital-growth projects.

Financing Cash Flows - Cash from financing activities for the three months ended March 31, 2021, decreased $1.5 billion, compared with the same period in 2020, due primarily to the issuance of $1.75 billion in long-term debt in March 2020, offset partially by the repayment of short-term borrowings in the first quarter 2020.

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, wildlife conservation, cultural resources protection, hazardous materials transportation, and pipeline

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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, reputational harm and/or interruptions in our operations that could be material to our results of operations or financial condition. 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 adversely 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. We also cannot assure that existing permits will not be revised or cancelled, potentially impacting facility construction activities or ongoing operations.

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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of our Consolidated Financial Statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported 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 critical accounting policies and estimates is included under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Critical Accounting Policies and Estimates,” 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 natural gas and NGL pipelines, processing and fractionation 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,” “outlook,” “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:

•the length, severity and reemergence of a pandemic or other health crisis, such as the outbreak of COVID-19 and the measures that international, federal, state and local governments, agencies, law enforcement and/or health authorities

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implement to address it, which may (as with COVID-19) precipitate or exacerbate one or more of the factors herein, reduce the demand for natural gas, NGLs and crude oil and significantly disrupt or prevent us and our customers and counterparties from operating in the ordinary course for an extended period and increase the cost of operating our business;

•operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruption;

•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; regulatory compliance; reserve performance; and capacity constraints and/or shut downs on the pipelines that transport crude oil, natural gas and NGLs from producing areas and our facilities;

•risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines that outpace new drilling, the shutting-in of production by producers, actions taken by federal, state or local governments to require producers to prorate or to cut their production levels as a way to address any excess market supply situations or extended periods of ethane rejection;

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

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

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

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

•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, production limits and authorized rates of recovery of natural gas and natural gas transportation costs;

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

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

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

•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;

•the timing and extent of changes in energy commodity prices, including changes due to production decisions by other countries, such as the failure of countries to abide by agreements to reduce production volumes;

•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 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;

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

– availability of additional storage capacity;

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

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

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

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

•the risk inherent in the use of information systems in our respective businesses and those of our counterparties and service providers, including cyber-attacks, which, according to experts, have increased in volume and sophistication since the beginning of the COVID-19 pandemic; implementation of new software and hardware; and the impact on the timeliness of information for financial reporting;

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

•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 results of administrative proceedings and litigation, regulatory actions, executive orders, 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 the CFTC;

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•the mechanical integrity of facilities and pipelines operated;

•the capital-intensive nature of our businesses;

•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;

•actions by rating agencies concerning our credit;

•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;

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

•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;

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

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

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

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

•the impact of potential impairment charges;

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

•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 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 impact of recently issued and future accounting updates and other changes in accounting policies; 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 affect adversely 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 exposure to market risk discussed below includes forward-looking statements and represents an estimate of possible changes in future earnings that could occur assuming hypothetical future movements in interest rates or commodity prices. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur since actual gains and losses will differ from those estimated based on actual fluctuations in interest rates or commodity prices and the timing of transactions.

We are exposed to market risk due to commodity price and interest-rate volatility. Market risk is the risk of loss arising from adverse changes in market rates and prices. We may use financial instruments, including forward sales, swaps, options and futures, to manage the risks of certain identifiable or anticipated transactions and achieve more predictable cash flows. Our risk-management function follows policies and procedures established by our Risk Oversight and Strategy Committee to monitor our natural gas, condensate and NGL marketing activities and interest rates to ensure our hedging activities mitigate market risks and comply with approved thresholds or limits. We do not use financial instruments for trading purposes.

We utilize a sensitivity analysis model to assess the risk associated with our derivative portfolio. The sensitivity analysis measures the potential change in fair value of our derivative instruments based upon a hypothetical 10% movement in the underlying commodity prices or interest rates. In addition to these variables, the fair value of our derivative portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. Because we enter into these derivative instruments for the purpose of mitigating the risks that accompany certain of our

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business activities, as described below, the change in the market value of our derivative portfolio would typically be offset largely by a corresponding gain or loss on the hedged item.

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 fee with POP contracts. Under certain fee with POP contracts, our contractual fees and POP percentage may increase or decrease if 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 table presents the effect a hypothetical 10% change in the underlying commodity prices would have on the estimated fair value of our commodity derivative instruments for the periods indicated:


Commodity Contracts	March 31, 2021		December 31, 2020
	(Millions of dollars)
Crude oil and NGLs	$	44.3	$	20.0
Natural gas	20.9		10.6
Total change in estimated fair value of commodity contracts	$	65.2	$	30.6

Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on our commodity derivative contracts assuming hypothetical movements in future market prices and is not necessarily indicative of actual results that may occur. Actual gains and losses may differ from estimates due to actual fluctuations in market prices, as well as changes in our commodity derivative portfolio during the year.

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, 2021
	Volumes Hedged	Average Price			Percentage Hedged
NGLs - excluding ethane (MBbl/d) - Conway/Mont Belvieu	10.3	$	0.51	/ gallon	59%
Condensate (MBbl/d) - WTI-NYMEX	2.8	$	42.87	/ Bbl	78%

Natural gas (BBtu/d) - NYMEX and basis	118.7	$	2.57	/ MMBtu	75%


	Year Ending December 31, 2022
	Volumes Hedged	Average Price			Percentage Hedged
NGLs - excluding ethane (MBbl/d) - Conway/Mont Belvieu	4.0	$	0.67	/ gallon	21%
Condensate (MBbl/d) - WTI-NYMEX	1.0	$	57.15	/ Bbl	24%
Natural gas (BBtu/d) - NYMEX and basis	42.0	$	2.60	/ MMBtu	24%

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, 2021. 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, 2021, and for the year ending December 31, 2022, by approximately $2.0 million and $3.0 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, 2021, and for the year ending December 31, 2022, by approximately $1.0 million and $1.5 million, respectively; and

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•a $0.10 per-MMBtu change in the price of residue natural gas would change adjusted EBITDA for the nine months ending December 31, 2021, and for the year ending December 31, 2022, by approximately $4.4 million and $6.4 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 borrowings under our $2.5 Billion Credit Agreement, commercial paper program and long-term debt issuances. Future increases in commercial paper rates or 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 and interest-rate swaps. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts.

The following table presents the effect of a 10% hypothetical change in interest rates on the estimated fair value of our interest- rate derivative instruments for the periods indicated:


	March 31, 2021		December 31, 2020
	(Millions of dollars)
Forward-starting interest-rate swaps	$	22.6	$	12.9

Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on our interest-rate derivative contracts assuming hypothetical movements in future interest rates and is not necessarily indicative of actual results that may occur. Actual gains and losses may differ from estimates due to actual fluctuations in interest rates, as well as changes in our interest-rate derivative portfolio during the year.

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

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, which are primarily investment grade, is consistent with that 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 Rules 13a-15(b) and 15d-15(b) of the Exchange Act.

Changes in Internal Control Over Financial Reporting - There have been no changes in our internal control over financial reporting during the quarter ended March 31, 2021, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

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 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)).

10.1			Form of 2021 Restricted Unit Award Agreement (incorporated by reference from Exhibit 10.33 to ONEOK, Inc.’s Annual Report on Form 10-K, filed February 23, 2021 (File No. 1-13643)).

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10.2			Form of 2021 Performance Unit Award Agreement (incorporated by reference from Exhibit 10.34 to ONEOK, Inc.’s Annual Report on Form 10-K, filed February 23, 2021 (File No. 1-13643)).

22.1			List of subsidiary guarantors and issuers of guaranteed securities.

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			Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH			Inline XBRL Taxonomy Extension Schema Document.

101.CAL			Inline XBRL Taxonomy Calculation Linkbase Document.

101.DEF			Inline XBRL Taxonomy Extension Definitions Document.

101.LAB			Inline XBRL Taxonomy Label Linkbase Document.

101.PRE			Inline XBRL Taxonomy Presentation Linkbase Document.

104			Cover Page Interactive Data File (embedded within the Inline XBRL document and contained in Exhibit 101).

Attached as Exhibit 101 to this Quarterly Report are the following Inline XBRL-related documents: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three months ended March 31, 2021 and 2020; (iii) Consolidated Statements of Comprehensive Income for the three months ended March 31, 2021 and 2020; (iv) Consolidated Balance Sheets at March 31, 2021, and December 31, 2020; (v) Consolidated Statements of Cash Flows for the three months ended March 31, 2021 and 2020; (vi) Consolidated Statements of Changes in Equity for the three months ended March 31, 2021 and 2020; 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: April 28, 2021	By:	/s/ Walter S. Hulse III
		Walter S. Hulse III
		Chief Financial Officer, Treasurer and
		Executive Vice President, Strategy
		and Corporate Affairs
		(Principal Financial Officer)