UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2017.

OR

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

For the transition period from __________ to __________.

Commission file number   1-12202

ONEOK PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware	93-1120873
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
100 West Fifth Street, Tulsa, OK	74103
(Address of principal executive offices)	(Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes X  No __

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every

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

Yes X  No __

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

Large accelerated filer X                         Accelerated filer __                         Non-accelerated filer __

Smaller reporting company__                 Emerging growth company__

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

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

Yes __ No X

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class	Outstanding at April 24, 2017
Common units	212,837,980 units
Class B units	72,988,252 units

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ONEOK PARTNERS, L.P.

TABLE OF CONTENTS

Part I.	Financial Information	Page No.
Item 1.	Financial Statements (Unaudited)	6
	Consolidated Statements of Income - Three Months Ended March 31, 2017 and 2016	6
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2017 and 2016	7
	Consolidated Balance Sheets - March 31, 2017, and December 31, 2016	8
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2017 and 2016	9
	Consolidated Statements of Changes in Equity - Three Months Ended March 31, 2017 and 2016	10
	Notes to Consolidated Financial Statements	12
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	54
Item 4.	Controls and Procedures	56
Part II.	Other Information	56
Item 1.	Legal Proceedings	56
Item 1A.	Risk Factors	56
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	56
Item 3.	Defaults Upon Senior Securities	56
Item 4.	Mine Safety Disclosures	56
Item 5.	Other Information	56
Item 6.	Exhibits	57
Signature		58

As used in this Quarterly Report, references to “we,” “our,” “us” or the “Partnership” refer to ONEOK Partners, L.P., its subsidiary, ONEOK Partners Intermediate Limited Partnership, and its subsidiaries, unless the context indicates otherwise.

The statements in this Quarterly Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” and other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that such expectations or assumptions will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations “Forward-Looking Statements,” in this Quarterly Report and under Part I, Item 1A, “Risk Factors,” in our Annual Report.

INFORMATION AVAILABLE ON OUR WEBSITE

We make available, free of charge, on our website (www.oneokpartners.com) copies of our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of our Code of Business Conduct and Ethics, Governance Guidelines, Partnership Agreement and the written charter of our Audit Committee are also available on our website, and we will provide copies of these documents upon request. Our website and any contents thereof are not incorporated by reference into this report.

We also make available on our website the Interactive Data Files required to be submitted and posted pursuant to Rule 405 of Regulation S-T.

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GLOSSARY

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

2017 Credit Agreement	ONEOK’s $2.5 billion revolving credit agreement effective upon the closing of the Merger Transaction and the terminations of the Partnership Credit Agreement and the existing ONEOK credit facility
AFUDC	Allowance for funds used during construction
Annual Report	Annual Report on Form 10-K for the year ended December 31, 2016
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
EBITDA	Earnings before interest expense, income taxes, depreciation and amortization
EPA	United States Environmental Protection Agency
Exchange Act	Securities Exchange Act of 1934, as amended
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States of America
GHG	Greenhouse gas
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
Merger Agreement	Agreement and Plan of Merger, dated as of January 31, 2017, by and among ONEOK, Merger Sub, ONEOK Partners and ONEOK Partners GP
Merger Sub	New Holdings Subsidiary, LLC, a wholly owned subsidiary of ONEOK
Merger Transaction	The transaction contemplated by the Merger Agreement pursuant to which ONEOK will acquire all of ONEOK Partners’ outstanding common units representing limited partner interests in ONEOK Partners not already directly or indirectly owned by ONEOK
MMBbl	Million barrels
MMBtu	Million British thermal units
MMcf/d	Million cubic feet per day
Moody’s	Moody’s Investors Service, Inc.
NGL(s)	Natural gas liquid(s)
NGL products	Marketable natural gas liquid purity products, such as ethane, ethane/propane mix, propane, iso-butane, normal butane and natural gasoline
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
ONEOK	ONEOK, Inc.
ONEOK Partners	ONEOK Partners, L.P.
ONEOK Partners GP	ONEOK Partners GP, L.L.C., a wholly owned subsidiary of ONEOK and the sole general partner of ONEOK Partners
OPIS	Oil Price Information Service
Partnership Agreement	Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P., as amended
Partnership Credit Agreement	The Partnership’s $2.4 billion amended and restated revolving credit agreement effective as of January 31, 2014, as amended
PHMSA	United States Department of Transportation Pipeline and Hazardous Materials Safety Administration
POP	Percent of Proceeds

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Quarterly Report(s)	Quarterly Report(s) on Form 10-Q
Roadrunner	Roadrunner Gas Transmission, LLC, a 50 percent owned joint venture
S&P	S&P Global Ratings
SCOOP	South Central Oklahoma Oil Province, an area in the Anadarko Basin in Oklahoma
SEC	Securities and Exchange Commission
STACK	Sooner Trend Anadarko Canadian Kingfisher, an area in the Anadarko Basin in Oklahoma
Term Loan Agreement	The Partnership’s senior unsecured delayed-draw three-year $1.0 billion term loan agreement dated January 8, 2016, as amended
West Texas LPG	West Texas LPG Pipeline Limited Partnership and Mesquite Pipeline
WTI	West Texas Intermediate
XBRL	eXtensible Business Reporting Language

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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
	Three Months Ended
	March 31,
(Unaudited)	2017			2016
	(Thousands of dollars, except per unit amounts)
Revenues
Commodity sales	$	2,216,717		$	1,283,511
Services	532,356			490,434
Total revenues	2,749,073			1,773,945
Cost of sales and fuel (exclusive of items shown separately below)	2,143,843			1,195,738
Operations and maintenance	155,282			148,740
Depreciation and amortization	98,626			93,736
General taxes	26,892			21,640
(Gain) loss on sale of assets	7			(4,145		)
Operating income	324,423			318,236
Equity in net earnings from investments (Note I)	39,564			32,914
Allowance for equity funds used during construction	13			208
Other income	1,253			145
Other expense	(683		)	(634		)
Interest expense (net of capitalized interest of $1,441 and $2,887, respectively)	(90,707		)	(92,555		)
Income before income taxes	273,863			258,314
Income taxes	(3,837		)	(2,028		)
Net income	270,026			256,286
Less: Net income attributable to noncontrolling interests	905			2,769
Net income attributable to ONEOK Partners, L.P.	$	269,121		$	253,517
Limited partners’ interest in net income:
Net income attributable to ONEOK Partners, L.P.	$	269,121		$	253,517
General partner’s interest in net income	(105,920		)	(105,608		)
Limited partners’ interest in net income	$	163,201		$	147,909
Limited partners’ net income per unit, basic and diluted (Note H)	$	0.57		$	0.52
Number of units used in computation (thousands)	285,826			285,826
Distributions declared per limited partner unit (Note F)	$	0.79		$	0.79

See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	Three Months Ended
	March 31,
(Unaudited)	2017		2016
	(Thousands of dollars)
Net income	$	270,026	$	256,286
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	28,857		(19,933		)
Realized (gains) losses on derivatives recognized in net income	19,770		(10,680		)
Other comprehensive income (loss) on investments in unconsolidated affiliates	383		(5,801		)
Total other comprehensive income (loss)	49,010		(36,414		)
Comprehensive income	319,036		219,872
Less: Comprehensive income attributable to noncontrolling interests	905		2,769
Comprehensive income attributable to ONEOK Partners, L.P.	$	318,131	$	217,103

See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	March 31,			December 31,
(Unaudited)	2017			2016
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	8,476		$	406
Accounts receivable, net	734,780			872,310
Affiliate receivables	152			984
Natural gas and natural gas liquids in storage	193,339			140,034
Commodity imbalances	30,904			60,896
Materials and supplies	59,726			60,912
Other current assets	38,368			38,703
Total current assets	1,065,745			1,174,245
Property, plant and equipment
Property, plant and equipment	14,930,541			14,854,696
Accumulated depreciation and amortization	2,482,974			2,392,004
Net property, plant and equipment	12,447,567			12,462,692
Investments and other assets
Investments in unconsolidated affiliates	956,388			958,807
Goodwill and intangible assets	810,003			812,977
Other assets	62,232			60,626
Total investments and other assets	1,828,623			1,832,410
Total assets	$	15,341,935		$	15,469,347
Liabilities and equity
Current liabilities
Current maturities of long-term debt (Note E)	$	407,650		$	407,650
Short-term borrowings (Note E)	1,290,729			1,110,277
Accounts payable	691,736			862,436
Affiliate payables	22,685			68,233
Commodity imbalances	114,542			142,646
Accrued interest	72,240			87,130
Other current liabilities	94,949			146,004
Total current liabilities	2,694,531			2,824,376
Long-term debt, excluding current maturities (Note E)	6,290,952			6,291,307
Deferred credits and other liabilities	193,797			175,844
Commitments and contingencies (Note K)
Equity (Note F)
ONEOK Partners, L.P. partners’ equity:
General partner	224,761			226,039
Common units: 212,837,980 units issued and outstanding at March 31, 2017, and December 31, 2016	4,774,781			4,821,397
Class B units: 72,988,252 units issued and outstanding at March 31, 2017, and December 31, 2016	1,117,842			1,133,828
Accumulated other comprehensive loss (Note G)	(112,516		)	(161,526		)
Total ONEOK Partners, L.P. partners’ equity	6,004,868			6,019,738
Noncontrolling interests in consolidated subsidiaries	157,787			158,082
Total equity	6,162,655			6,177,820
Total liabilities and equity	$	15,341,935		$	15,469,347

See accompanying Notes to Consolidated Financial Statements.

8

ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Three Months Ended
	March 31,
(Unaudited)	2017			2016
	(Thousands of dollars)
Operating activities
Net income	$	270,026		$	256,286
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	98,626			93,736
Equity in net earnings from investments	(39,564		)	(32,914		)
Distributions received from unconsolidated affiliates	39,520			34,789
Deferred income taxes	3,035			2,254
Allowance for equity funds used during construction	(13		)	(208		)
(Gain) loss on sale of assets	7			(4,145		)
Changes in assets and liabilities:
Accounts receivable	137,530			68,618
Affiliate receivables	832			4,406
Natural gas and natural gas liquids in storage	(53,305		)	(27,991		)
Accounts payable	(122,090		)	(62,401		)
Affiliate payables	(45,548		)	(7,067		)
Commodity imbalances, net	1,888			2,968
Accrued interest	(14,890		)	(15,897		)
Risk-management assets and liabilities	45,100			(24,691		)
Other assets and liabilities, net	(40,848		)	(21,490		)
Cash provided by operating activities	280,306			266,253
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	(112,584		)	(195,896		)
Contributions to unconsolidated affiliates	(4,422		)	(158		)
Distributions received from unconsolidated affiliates in excess of cumulative earnings	7,400			11,764
Proceeds from sale of assets	161			14,797
Cash used in investing activities	(109,445		)	(169,493		)
Financing activities
Cash distributions:
General and limited partners	(333,001		)	(333,001		)
Noncontrolling interests	(1,200		)	(2,500		)
Borrowing (repayment) of short-term borrowings, net	180,452			(101,773		)
Issuance of long-term debt, net of discounts	—			1,000,000
Debt financing costs	—			(2,770		)
Repayment of long-term debt	(1,912		)	(651,913		)
Other	(7,130		)	—
Cash used in financing activities	(162,791		)	(91,957		)
Change in cash and cash equivalents	8,070			4,803
Cash and cash equivalents at beginning of period	406			5,079
Cash and cash equivalents at end of period	$	8,476		$	9,882

See accompanying Notes to Consolidated Financial Statements.

9

ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
	ONEOK Partners, L.P. Partners’ Equity
(Unaudited)	Common Units	Class B Units	General Partner			Common Units
	(Units)		(Thousands of dollars)
January 1, 2017	212,837,980	72,988,252	$	226,039		$	4,821,397
Net income	—	—	105,920			121,526
Other comprehensive income (loss) (Note G)	—	—	—			—
Distributions paid (Note F)	—	—	(107,198		)	(168,142		)
March 31, 2017	212,837,980	72,988,252	$	224,761		$	4,774,781

	ONEOK Partners, L.P. Partners’ Equity
(Unaudited)	Common Units	Class B Units	General Partner			Common Units
	(Units)		(Thousands of dollars)
January 1, 2016	212,837,980	72,988,252	$	231,344		$	5,014,952
Net income	—	—	105,608			110,140
Other comprehensive income (loss)	—	—	—			—
Distributions paid (Note F)	—	—	(107,198		)	(168,143		)
Other	—	—	—			—
March 31, 2016	212,837,980	72,988,252	$	229,754		$	4,956,949

10

ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Continued)
	ONEOK Partners, L.P. Partners’ Equity
(Unaudited)	Class B Units			Accumulated Other Comprehensive Loss			Noncontrolling Interests in Consolidated Subsidiaries			Total Equity
	(Thousands of dollars)
January 1, 2017	$	1,133,828		$	(161,526	)	$	158,082		$	6,177,820
Net income	41,675			—			905			270,026
Other comprehensive income (loss) (Note G)	—			49,010			—			49,010
Distributions paid (Note F)	(57,661		)	—			(1,200		)	(334,201		)
March 31, 2017	$	1,117,842		$	(112,516	)	$	157,787		$	6,162,655

	ONEOK Partners, L.P. Partners’ Equity
(Unaudited)	Class B Units			Accumulated Other Comprehensive Loss			Noncontrolling Interests in Consolidated Subsidiaries			Total Equity
	(Thousands of dollars)
January 1, 2016	$	1,200,204		$	(113,282	)	$	164,125		$	6,497,343
Net income	37,769			—			2,769			256,286
Other comprehensive income (loss)	—			(36,414		)	—			(36,414		)
Distributions paid (Note F)	(57,660		)	—			(2,500		)	(335,501		)
Other	—			—			(4,040		)	(4,040		)
March 31, 2016	$	1,180,313		$	(149,696	)	$	160,354		$	6,377,674

See accompanying Notes to Consolidated Financial Statements.

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ONEOK PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our accompanying unaudited consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. These statements have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair statement of the results for the interim periods presented. All such adjustments are of a normal recurring nature. The 2016 year-end consolidated balance sheet data was derived from our audited financial statements but does not include all disclosures required by GAAP. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements in our Annual Report.

Our significant accounting policies are consistent with those disclosed in Note A of the Notes to Consolidated Financial Statements in our Annual Report, except as described below.

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

Standard	Description	Date of Adoption	Effect on the Financial Statements or Other Significant Matters
Standards that were adopted
ASU 2015-11, “Inventory (Topic 330): Simplifying the Measurement of Inventory”	The standard requires that inventory, excluding inventory measured using last-in, first-out (LIFO) or the retail inventory method, be measured at the lower of cost or net realizable value.	First quarter 2017	As a result of adopting this guidance, we updated our accounting policy for inventory valuation accordingly. The financial impact of adopting this guidance was not material.
ASU 2016-05, “Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships”	The standard clarifies that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument under Topic 815 does not, in and of itself, require dedesignation of that hedging relationship provided that all other hedge accounting criteria continue to be met.	First quarter 2017	The impact of adopting this standard was not material.
ASU 2016-06, “Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments”	The standard clarifies the requirements for assessing whether a contingent call (put) option that can accelerate the payment of principal on a debt instrument is clearly and closely related to its debt host.	First quarter 2017	The impact of adopting this standard was not material.

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Standard	Description	Date of Adoption	Effect on the Financial Statements or Other Significant Matters
Standards that are not yet adopted
ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)”	The standard outlines the principles an entity must apply to measure and recognize revenue for entities that enter into contracts to provide goods or services to their customers. The core principle is that an entity should recognize revenue at an amount that reflects the consideration to which the entity expects to be entitled in exchange for transferring goods or services to a customer. The amendment also requires more extensive disaggregated revenue disclosures in interim and annual financial statements.	First quarter 2018	We are evaluating the impact of this standard on us. Our evaluation process includes a review of our contracts and transaction types across all our business segments. In addition, we are currently evaluating methods of adoption and analyzing the impact of the standard on our internal controls, accounting policies and financial statements and disclosures. We expect to determine our method of adoption when we complete our evaluation of the impact of the standard and the implications of each adoption method.
ASU 2016-01, “Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities”	The standard requires all equity investments, other than those accounted for using the equity method of accounting or those that result in consolidation of the investee, to be measured at fair value with changes in fair value recognized in net income, eliminates the available-for-sale classification for equity securities with readily determinable fair values and eliminates the cost method for equity investments without readily determinable fair values.	First quarter 2018	We are evaluating the impact of this standard on us.
ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments”	The standard clarifies the classification of certain cash receipts and cash payments on the statement of cash flows where diversity in practice has been identified.	First quarter 2018	We are evaluating the impact of this standard on us.
ASU 2016-02, “Leases (Topic 842)”	The standard requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. It also requires qualitative disclosures along with specific quantitative disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing and uncertainty of cash flows arising from leases.	First quarter 2019	We are evaluating our current leases and the impact of the standard on our internal controls, accounting policies and financial statements and disclosures.
ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments”	The standard requires a financial asset (or a group of financial assets) measured at amortized cost basis to be presented net of the allowance for credit losses to reflect the net carrying value at the amount expected to be collected on the financial asset; and the initial allowance for credit losses for purchased financial assets, including available-for-sale debt securities, to be added to the purchase price rather than being reported as a credit loss expense.	First quarter 2020	We are evaluating the impact of this standard on us.
ASU 2017-04, “Intangibles- Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment”	The standard simplifies the subsequent measurement of goodwill by eliminating the requirement to calculate the implied fair value of goodwill under step 2. Instead, an entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value. The standard does not change step zero or step 1 assessments.	First quarter 2020	We are evaluating the impact of this standard on us.

B. ACQUISITION OF ONEOK PARTNERS

On January 31, 2017, we and ONEOK entered into the Merger Agreement pursuant to which ONEOK will acquire all of our outstanding common units representing limited partner interests in us not already directly or indirectly owned by ONEOK in an all stock-for-unit transaction at a ratio of 0.985 of a share of ONEOK common stock per common unit of ONEOK Partners, in a taxable transaction to our common unitholders. Following completion of the Merger Transaction, all of our outstanding common units will be directly or indirectly owned by ONEOK and will no longer be publicly traded. All of our outstanding debt is expected to remain outstanding. We, ONEOK and the Intermediate Partnership expect to issue, to the extent not already in place, guarantees of the indebtedness of ONEOK and ONEOK Partners.

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A Special Committee of the Board of Directors of ONEOK, the Conflicts Committee of the Board of Directors of our general partner and the Board of Directors of our general partner each unanimously approved the Merger Agreement. Subject to customary approvals and conditions, the Merger Transaction is expected to close late in the second quarter or early in the third quarter of 2017. The Merger Transaction is subject to the approval of our common unitholders and the approval by ONEOK shareholders of the issuance of ONEOK common shares in the Merger Transaction.

The Merger Agreement contains certain termination rights, including the right for either us or ONEOK, as applicable, to terminate the Merger Agreement if the closing of the transactions contemplated by the Merger Agreement has not occurred on or before September 30, 2017. In the event of termination of the Merger Agreement under certain circumstances, we may be required to pay ONEOK a termination fee of (up to, in certain instances, $300 million in cash) and, under other certain circumstances, ONEOK may be required to pay us a termination fee in the form of a temporary reduction in incentive distributions (up to, in certain instances, $300 million).

C. FAIR VALUE MEASUREMENTS

Determining Fair Value - We define fair value as the price that would be received from the sale of an asset or the transfer of a liability in an orderly transaction between market participants at the measurement date. We use market and income approaches to determine the fair value of our assets and liabilities and consider the markets in which the transactions are executed. We measure the fair value of a group of financial assets and liabilities consistent with how a market participant would price the net risk exposure at the measurement date.

While many of the contracts in our derivative portfolio are executed in liquid markets where price transparency exists, some contracts are executed in markets for which market prices may exist, but the market may be relatively inactive. This results in limited price transparency that requires management’s judgment and assumptions to estimate fair values. For certain transactions, we utilize modeling techniques using NYMEX-settled pricing data and implied forward LIBOR curves. Inputs into our fair value estimates include commodity-exchange prices, over-the-counter quotes, historical correlations of pricing data, data obtained from third-party pricing services and LIBOR and other liquid money-market instrument rates. We validate our valuation inputs with third-party information and settlement prices from other sources, where available.

In addition, as prescribed by the income approach, 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 LIBOR, Eurodollar futures and the LIBOR interest-rate swaps market. We also take into consideration the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions. We consider current market data in evaluating counterparties’, as well as our own, nonperformance risk, net of collateral, by using specific and sector bond yields and monitoring the credit default swap markets. 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 from our estimates, and the differences could be material.

The fair value of our forward-starting interest-rate swaps are determined using financial models that incorporate the implied forward LIBOR yield curve for the same period as the future interest-rate swap settlements.

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, including NYMEX-settled prices. These balances are comprised predominantly of exchange-traded derivative contracts for natural gas and crude oil.

• Level 2 - fair value measurements are based on significant observable pricing inputs, such as NYMEX-settled prices for natural gas and crude oil, and financial models that utilize implied forward LIBOR yield curves for interest-rate swaps.

• Level 3 - fair value measurements are based on inputs that may include one or more unobservable inputs, including internally developed natural gas basis and NGL price curves that incorporate observable and unobservable market data from broker quotes, third-party pricing services, market volatilities derived from the most recent NYMEX close spot prices and forward LIBOR curves, and adjustments for the credit risk of our counterparties. We corroborate the data on which our fair value estimates are based using our market knowledge of recent transactions, analysis of historical correlations and validation with independent broker quotes. These balances categorized as Level 3 are comprised of derivatives for natural gas and NGLs. We do not believe that our Level 3 fair value estimates have a material impact

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on our results of operations, as the majority of our derivatives are accounted for as hedges for which ineffectiveness has not been material.

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, 2017
	Level 1			Level 2			Level 3			Total - Gross			Netting (a)			Total - Net (b)
	(Thousands of dollars)
Derivative assets
Commodity contracts
Financial contracts	$	3,293		$	—		$	14,675		$	17,968		$	(17,217	)	$	751
Physical contracts	—			—			508			508			—			508
Interest-rate contracts	—			47,914			—			47,914			—			47,914
Total derivative assets	$	3,293		$	47,914		$	15,183		$	66,390		$	(17,217	)	$	49,173
Derivative liabilities
Commodity contracts
Financial contracts	$	(15,757	)	$	—		$	(14,562	)	$	(30,319	)	$	29,973		$	(346	)
Physical contracts	—			—			(1,393		)	(1,393		)	—			(1,393		)
Interest-rate contracts	—			(11,316		)	—			(11,316		)	—			(11,316		)
Total derivative liabilities	$	(15,757	)	$	(11,316	)	$	(15,955	)	$	(43,028	)	$	29,973		$	(13,055	)

(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At March 31, 2017, we held no cash and posted $30.6 million of cash with various counterparties, including $12.8 million of cash collateral that is offsetting derivative net liability positions under master-netting arrangements in the table above. The remaining $17.8 million of cash collateral in excess of derivative net liability positions is included in other current assets in our Consolidated Balance Sheets.

(b) - Included in other current assets, other assets or other current liabilities in our Consolidated Balance Sheets.

	December 31, 2016
	Level 1			Level 2			Level 3			Total - Gross			Netting (a)			Total - Net (b)
	(Thousands of dollars)
Derivative assets
Commodity contracts
Financial contracts	$	1,147		$	—		$	4,564		$	5,711		$	(4,760	)	$	951
Interest rate contracts	—			47,457			—			47,457			—			47,457
Total derivative assets	$	1,147		$	47,457		$	4,564		$	53,168		$	(4,760	)	$	48,408
Derivative liabilities
Commodity contracts
Financial contracts	$	(31,458	)	$	—		$	(24,861	)	$	(56,319	)	$	56,319		$	—
Physical contracts	—			—			(3,022		)	(3,022		)	—			(3,022		)
Interest-rate contracts	—			(12,795		)	—			(12,795		)	—			(12,795		)
Total derivative liabilities	$	(31,458	)	$	(12,795	)	$	(27,883	)	$	(72,136	)	$	56,319		$	(15,817	)

(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2016, we held no cash and posted $67.7 million of cash with various counterparties, including $51.6 million of cash collateral that is offsetting derivative net liability positions under master-netting arrangements in the table above. The remaining $16.1 million of cash collateral in excess of derivative net liability positions is included in other current assets in our Consolidated Balance Sheets.

(b) - Included in other current assets, other assets or other current liabilities in our Consolidated Balance Sheets.

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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)		2017			2016
	(Thousands of dollars)
Net assets (liabilities) at beginning of period		$	(23,319	)	$	7,331
Total realized/unrealized gains (losses):
Included in earnings (a)		913			(745		)
Included in other comprehensive income (loss)		21,634			(6,552		)
Net assets (liabilities) at end of period		$	(772	)	$	34

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

Realized/unrealized gains (losses) include the realization of our derivative contracts through maturity. During the three months ended March 31, 2017 and 2016, gains or losses included in earnings attributable to the change in unrealized gains or losses relating to assets and liabilities still held at the end of each reporting period were not material.

We recognize transfers into and out of the levels in the fair value hierarchy as of the end of each reporting period. During the three months ended March 31, 2017 and 2016, there were no transfers between levels.

Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable, accounts payable and short-term borrowings is equal to book value, due to the short-term nature of these items. Our cash and cash equivalents are comprised of bank and money market accounts and are classified as Level 1. Our short-term borrowings are classified as Level 2 since the estimated fair value of the short-term borrowings can be determined using information available in the commercial paper market.

The estimated fair value of our long-term debt, including current maturities, was $7.2 billion and $7.1 billion at March 31, 2017, and December 31, 2016, respectively. The book value of our long-term debt, including current maturities, was $6.7 billion at March 31, 2017, and December 31, 2016. The estimated fair value of the aggregate of our senior notes outstanding was determined using quoted market prices for similar issues with similar terms and maturities. The estimated fair value of our long-term debt is classified as Level 2.

D. 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 purchased, processed and sold. 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. We are also subject to the risk of interest-rate fluctuation in the normal course of business.

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 use the following commodity derivative instruments to mitigate 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.

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

In our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk as a result of retaining a portion of the commodity sales proceeds associated with our POP with fee contracts. Under certain POP with fee contracts, our fee revenues may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds. We also are exposed to basis risk between the various production and market locations where we receive 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 exposed to location price differential risk, primarily as a result of the relative value of NGL purchases at one location and sales at another location. We are also exposed to commodity price risk resulting from the relative values of the various NGL products to each other, NGLs in storage and the relative value of NGLs to natural gas. We utilize physical-forward contracts and commodity derivative financial instruments to reduce the impact of price fluctuations related to NGLs.

In our Natural Gas Pipelines segment, we are exposed to commodity price risk because our intrastate and interstate natural gas pipelines retain natural gas from our customers for operations or as part of our fee for services provided. When the amount of natural gas consumed in operations by these pipelines differs from the amount provided by our customers, our pipelines must buy or sell natural gas, or store or use natural gas from inventory, which may 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 price fluctuations related to natural gas. At March 31, 2017, and December 31, 2016, 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. As of March 31, 2017 and December 31, 2016, we had interest-rate swaps with notional amounts totaling $1 billion to hedge the variability of our LIBOR-based interest payments and forward-starting interest-rate swaps with notional amounts totaling $1.2 billion to hedge the variability of interest payments on a portion of our forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. 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.

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Fair Values of Derivative Instruments - See Note C for a discussion of the inputs associated with our fair value measurements. The following table sets forth the fair values of derivative instruments for the periods indicated:

		March 31, 2017					December 31, 2016
	Location in our Consolidated Balance Sheets	Assets		(Liabilities)			Assets		(Liabilities)
		(Thousands of dollars)
Derivatives designated as hedging instruments
Commodity contracts
Financial contracts	Other current assets/other current liabilities	$	6,154	$	(25,855	)	$	1,155	$	(49,938	)
	Other assets/deferred credits and other liabilities	6,683		—			210		(2,142		)
Physical contracts	Other current assets/other current liabilities	87		(1,393		)	—		(3,022		)
	Other assets	421		—			—		—
Interest-rate contracts	Other current assets/other current liabilities	90		(11,316		)	—		(12,795		)
	Other assets	47,824		—			47,457		—
Total derivatives designated as hedging instruments		61,259		(38,564		)	48,822		(67,897		)
Derivatives not designated as hedging instruments
Commodity contracts
Financial contracts	Other current assets/other current liabilities	4,451		(3,796		)	4,346		(4,239		)
	Other assets/deferred credits and other liabilities	680		(668		)	—		—
Total derivatives not designated as hedging instruments		5,131		(4,464		)	4,346		(4,239		)
Total derivatives		$	66,390	$	(43,028	)	$	53,168	$	(72,136	)

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

		March 31, 2017					December 31, 2016
	Contract Type	Purchased/ Payor		Sold/ Receiver			Purchased/ Payor		Sold/ Receiver
Derivatives designated as hedging instruments:
Cash flow hedges
Fixed price
- Natural gas (Bcf)	Futures and swaps	—		(38.2		)	—		(38.4		)
- Natural gas (Bcf)	Put options	36.0		—			49.5		—
- Crude oil and NGLs (MMBbl)	Futures, forwards and swaps	0.3		(4.5		)	—		(3.6		)
Basis
- Natural gas (Bcf)	Futures and swaps	—		(38.2		)	—		(38.4		)
Interest-rate contracts (Millions of dollars)	Swaps	$	2,150.0	$	—		$	2,150.0	$	—
Derivatives not designated as hedging instruments:
Fixed price
-Natural gas (Bcf)	Futures and swaps	3.5		—			0.4		—
- NGLs (MMBbl)	Futures, forwards and swaps	0.7		(2.6		)	0.5		(0.7		)
Basis
- Natural gas (Bcf)	Futures and swaps	3.5		—			0.4		—

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

Cash Flow Hedges - At March 31, 2017, our Consolidated Balance Sheet reflected a net loss of $112.5 million in accumulated other comprehensive loss. The portion of accumulated other comprehensive loss attributable to our commodity derivative financial instruments is an unrealized loss of $20.8 million, which is expected to be realized within the next 21 months as the forecasted transactions affect earnings. If commodity prices remain at current levels, we will realize approximately $27.9 million in net losses over the next 12 months and approximately $7.1 million in net gains thereafter. The amount deferred in accumulated other comprehensive loss attributable to our settled interest-rate swaps is a loss of $121.9 million, which will be recognized over the life of the long-term, fixed-rate debt, including losses of $16.8 million that will be reclassified into earnings during the next 12 months as the hedged items affect earnings. The remaining amounts in accumulated other comprehensive loss are attributable primarily to forward-starting interest-rate swaps with future settlement dates, which is expected to be amortized to interest expense over the life of long-term, fixed-rate debt upon issuance of the debt.

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

		Three Months Ended
Derivatives in Cash Flow Hedging Relationships		March 31,
		2017		2016
	(Thousands of dollars)
Commodity contracts		$	27,328	$	11,678
Interest-rate contracts		1,529		(31,611		)
Total unrealized gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)		$	28,857	$	(19,933	)

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

Derivatives in Cash Flow Hedging Relationships	Location of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Effective Portion)		Three Months Ended
			March 31,
			2017			2016
		(Thousands of dollars)
Commodity contracts	Commodity sales revenues		$	(15,319	)	$	14,499
Interest-rate contracts	Interest expense		(4,451		)	(3,819		)
Total gain (loss) reclassified from accumulated other comprehensive loss into net income on derivatives (effective portion)			$	(19,770	)	$	10,680

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 have counterparties whose credit is not rated, and for those customers, we use internally developed credit ratings.

From time to time, we may enter into financial derivative instruments that contain provisions that require us to maintain an investment-grade credit rating from S&P and/or Moody’s. If our credit ratings on our senior unsecured long-term debt were to decline below investment grade, the counterparties to the derivative instruments could request collateralization on derivative instruments in net liability positions. There were no financial derivative instruments with contingent features related to credit risk at March 31, 2017.

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

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At March 31, 2017, the net credit exposure from our derivative assets is with investment-grade companies in the financial services sector.

E. DEBT

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

	March 31, 2017			December 31, 2016
	(Thousands of dollars)
ONEOK Partners
Commercial paper outstanding, bearing a weighted-average interest rate of 1.51% and 1.27% respectively	$	1,290,729		$	1,110,277
Senior unsecured obligations:
$400,000 at 2.0% due 2017	400,000			400,000
$425,000 at 3.2% due 2018	425,000			425,000
$1,000,000 term loan, variable rate, due 2019	1,000,000			1,000,000
$500,000 at 8.625% due 2019	500,000			500,000
$300,000 at 3.8% due 2020	300,000			300,000
$900,000 at 3.375 % due 2022	900,000			900,000
$425,000 at 5.0 % due 2023	425,000			425,000
$500,000 at 4.9 % due 2025	500,000			500,000
$600,000 at 6.65% due 2036	600,000			600,000
$600,000 at 6.85% due 2037	600,000			600,000
$650,000 at 6.125% due 2041	650,000			650,000
$400,000 at 6.2% due 2043	400,000			400,000
Guardian Pipeline
Weighted average 7.85% due 2022	42,345			44,257
Total debt	8,033,074			7,854,534
Unamortized debt issuance costs and discounts	(43,743		)	(45,300		)
Current maturities of long-term debt	(407,650		)	(407,650		)
Short-term borrowings (a)	(1,290,729		)	(1,110,277		)
Long-term debt	$	6,290,952		$	6,291,307

(a) - Individual issuances of commercial paper under our $2.4 billion commercial paper program generally mature in 90 days or less. However, these issuances are supported by and reduce the borrowing capacity under our Partnership Credit Agreement.

Partnership Credit Agreement - In January 2016, we extended the term of our Partnership Credit Agreement by one year to January 2020. Our Partnership Credit Agreement is a $2.4 billion revolving credit facility and includes a $100 million sublimit for the issuance of standby letters of credit and a $150 million swingline sublimit. At March 31, 2017, and December 31, 2016, we had $14 million in letters of credit issued and no borrowings under the Partnership Credit Agreement. Our Partnership Credit Agreement is available for general partnership purposes and had available capacity of approximately $1.1 billion at March 31, 2017.

Our Partnership Credit Agreement contains provisions for an applicable margin rate and an annual facility fee, both of which adjust with changes in our credit rating. Under the terms of the Partnership Credit Agreement, based on our current credit ratings, borrowings, if any, will accrue interest at LIBOR plus 117.5 basis points, and the annual facility fee is 20 basis points. Our Partnership Credit Agreement is guaranteed fully and unconditionally by the Intermediate Partnership. Borrowings under our Partnership Credit Agreement are currently nonrecourse to ONEOK.

Our Partnership Credit Agreement 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 Partnership Credit Agreement, adjusted for all noncash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5.0 to 1. If we consummate one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will increase to 5.5 to 1 for the quarter in which the acquisition was completed and the two following quarters. If we were to breach certain covenants in our Partnership Credit Agreement, amounts outstanding under our Partnership Credit Agreement, if any, may become due and payable

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immediately. At March 31, 2017, our ratio of indebtedness to adjusted EBITDA was 4.2 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.

In April 2017, ONEOK entered into the 2017 Credit Agreement with a syndicate of banks, to replace the existing ONEOK credit facility and the Partnership Credit Agreement, effective upon the closing of the Merger Transaction described in Note B and the termination of the existing ONEOK credit facility and the Partnership Credit Agreement. ONEOK’s obligations under the 2017 Credit Agreement will be guaranteed by ONEOK Partners and the Intermediate Partnership.

Senior Unsecured Obligations - All notes are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness, and are structurally subordinate to any of the existing and future debt and other liabilities of any nonguarantor subsidiaries.

Issuances and maturities - In January 2016, we entered into the $1.0 billion senior unsecured Term Loan Agreement with a syndicate of banks. The Term Loan Agreement matures in January 2019 and bears interest at LIBOR plus 130 basis points based on our current credit ratings. At March 31, 2017, the interest rate was 2.28 percent. The Term Loan Agreement contains an option, which may be exercised up to two times, to extend the term of the loan, in each case, for an additional one-year term, subject to approval of the banks. The Term Loan Agreement allows prepayment of all or any portion outstanding without penalty or premium and contains substantially the same covenants as our Partnership Credit Agreement. During the first quarter 2016, we drew the full $1.0 billion available under the agreement and used the proceeds to repay $650 million of senior notes at maturity, to repay amounts outstanding under our commercial paper program and for general partnership purposes.

In April 2017, we entered into the first amendment to the Term Loan Agreement which, among other things, will add ONEOK as a guarantor to the Term Loan Agreement effective upon the closing of the Merger Transaction described in Note B.

Debt Guarantees - Neither we nor ONEOK guarantee the debt or other similar commitments of unaffiliated parties. ONEOK currently does not guarantee the debt, commercial paper, borrowings under the Partnership Credit Agreement or other similar commitments of ONEOK Partners, and ONEOK Partners currently does not guarantee the debt or other similar commitments of ONEOK. Following the completion of the Merger Transaction described in Note B, we, ONEOK and the Intermediate Partnership expect to issue, to the extent not already in place, guarantees of the indebtedness of ONEOK and ONEOK Partners.

F. EQUITY

ONEOK - ONEOK and its affiliates owned all of the Class B units, 41.3 million common units and the entire 2 percent general partner interest in us, which together constituted a 41.2 percent ownership interest in us at March 31, 2017.

Equity Issuances - We have an “at-the-market” equity program for the offer and sale from time to time of our common units, up to an aggregate amount of $650 million. The program allows us to offer and sell our common units at prices we deem appropriate through a sales agent. Sales of common units are made by means of ordinary brokers’ transactions on the NYSE, in block transactions or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common units under the program. At March 31, 2017, we had approximately $138 million of registered common units available for issuance through our “at-the-market” equity program.

During the three months ended March 31, 2017, and the year ended December 31, 2016, no common units were sold through our “at-the-market” equity program.

Partnership Agreement - Available cash, as defined in our Partnership Agreement, generally will be distributed to our general partner and limited partners according to their partnership percentages of 2 percent and 98 percent, respectively. Our general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met during the quarter. Under the incentive distribution provisions, as set forth in our Partnership Agreement, our general partner receives:

• 15 percent of amounts distributed in excess of $0.3025 per unit;

• 25 percent of amounts distributed in excess of $0.3575 per unit; and

• 50 percent of amounts distributed in excess of $0.4675 per unit.

Cash Distributions - In April 2017, our general partner declared a cash distribution of $0.79 per unit ($3.16 per unit on an annualized basis) for the first quarter 2017, which will be paid on May 15, 2017, to unitholders of record at the close of business on May 1, 2017.

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The following table sets forth our distributions paid during the periods indicated:

		Three Months Ended
		March 31,
		2017		2016
	(Thousands, except per unit amounts)
Distribution per unit		$	0.79	$	0.79
General partner distributions		$	6,660	$	6,660
Incentive distributions		100,538		100,538
Distributions to general partner		107,198		107,198
Limited partner distributions to ONEOK		90,323		90,323
Limited partner distributions to other unitholders		135,480		135,480
Total distributions paid		$	333,001	$	333,001

Distributions are declared and paid within 45 days of the completion of each quarter. The following table sets forth our distributions declared for the periods indicated:

		Three Months Ended
		March 31,
		2017		2016
	(Thousands, except per unit amounts)
Distribution per unit		$	0.79	$	0.79
General partner distributions		$	6,660	$	6,660
Incentive distributions		100,538		100,538
Distributions to general partner		107,198		107,198
Limited partner distributions to ONEOK		90,323		90,323
Limited partner distributions to other unitholders		135,480		135,480
Total distributions declared		$	333,001	$	333,001

G. ACCUMULATED OTHER COMPREHENSIVE LOSS

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

	Unrealized Gains (Losses) on Risk- Management Assets/Liabilities			Unrealized Gains (Losses) on Risk- Management Assets/Liabilities of Unconsolidated Affiliates			Accumulated Other Comprehensive Loss
	(Thousands of dollars)
January 1, 2017	$	(157,826	)	$	(3,700	)	$	(161,526	)
Other comprehensive income (loss) before reclassifications	28,857			287			29,144
Amounts reclassified from accumulated other comprehensive loss	19,770			96			19,866
Net current-period other comprehensive income (loss) attributable to ONEOK Partners	48,627			383			49,010
March 31, 2017	$	(109,199	)	$	(3,317	)	$	(112,516	)

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

Details about Accumulated Other Comprehensive Loss Components	Three Months Ended						Affected Line Item in the Consolidated Statements of Income
	March 31,
	2017			2016
	(Thousands of dollars)
Unrealized gains (losses) on risk-management assets/liabilities
Commodity contracts	$	(15,319	)	$	14,499		Commodity sales revenues
Interest-rate contracts	(4,451		)	(3,819		)	Interest expense
	$	(19,770	)	$	10,680		Net income attributable to ONEOK Partners
Unrealized gains (losses) on risk-management assets/liabilities of unconsolidated affiliates
Interest-rate contracts	$	(96	)	$	—		Equity in net earnings from investments
Total reclassifications for the period attributable to ONEOK Partners	$	(19,866	)	$	10,680		Net income attributable to ONEOK Partners

H. LIMITED PARTNERS’ NET INCOME PER UNIT

Limited partners’ net income per unit is computed by dividing net income attributable to ONEOK Partners, L.P., after deducting the general partner’s allocation as discussed below, by the weighted-average number of outstanding limited partner units, which includes our common and Class B limited partner units. Because ONEOK has conditionally waived its right to increased quarterly distributions, until it gives 90 days notice of the withdrawal of the waiver, currently each Class B and common unit share equally in the earnings of the Partnership, and neither has any liquidation or other preferences.

ONEOK Partners GP owns the entire 2 percent general partnership interest in us, which entitles it to incentive distribution rights that provide for an increasing proportion of cash distributions from the Partnership as the distributions made to limited partners increase above specified levels. For purposes of our calculation of limited partners’ net income per unit, net income attributable to ONEOK Partners, L.P. is allocated to the general partner as follows: (i) an amount based upon the 2 percent general partner interest in net income attributable to ONEOK Partners, L.P.; and (ii) the amount of the general partner’s incentive distribution rights based on the total cash distributions declared for the period.

The terms of our Partnership Agreement limit the general partner’s incentive distribution to the amount of available cash calculated for the period. As such, incentive distribution rights are not allocated on undistributed earnings. For additional information regarding our general partner’s incentive distribution rights, see “Partnership Agreement” in Note F.

I. UNCONSOLIDATED AFFILIATES

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

		Three Months Ended
		March 31,
		2017		2016
	(Thousands of dollars)
Northern Border Pipeline		$	18,817	$	18,674
Overland Pass Pipeline Company		13,566		13,304
Other		7,181		936
Equity in net earnings from investments		$	39,564	$	32,914

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

		Three Months Ended
		March 31,
		2017		2016
	(Thousands of dollars)
Income Statement
Operating revenues		$	154,280	$	136,572
Operating expenses		$	66,936	$	58,699
Net income		$	81,131	$	72,037
Distributions paid to us		$	46,920	$	46,553

We incurred expenses in transactions with unconsolidated affiliates of $36.7 million and $33.6 million for the three months ended March 31, 2017 and 2016, respectively, primarily related to Overland Pass Pipeline Company and Northern Border Pipeline. Accounts payable to our equity-method investees at March 31, 2017, and December 31, 2016, were $13.1 million and $11.1 million, respectively.

Northern Border Pipeline -The Northern Border Pipeline partnership agreement provides that distributions to Northern Border Pipeline’s partners are to be made on a pro rata basis according to each partner’s percentage interest. The Northern Border Pipeline Management Committee determines the amount and timing of such distributions. Any changes to, or suspension of, the cash distribution policy of Northern Border Pipeline requires the unanimous approval of the Northern Border Pipeline Management Committee. Cash distributions are equal to 100 percent of distributable cash flow as determined from Northern Border Pipeline’s financial statements based upon EBITDA less interest expense and maintenance capital expenditures. Loans or other advances from Northern Border Pipeline to its partners or affiliates are prohibited under its credit agreement.

Overland Pass Pipeline Company - The Overland Pass Pipeline Company limited liability company agreement provides that distributions to Overland Pass Pipeline Company’s members are to be made on a pro rata basis according to each member’s percentage interest. The Overland Pass Pipeline Company Management Committee determines the amount and timing of such distributions. Any changes to, or suspension of, cash distributions from Overland Pass Pipeline Company requires the unanimous approval of the Overland Pass Pipeline Company Management Committee. Cash distributions are equal to 100 percent of available cash as defined in the limited liability company agreement.

Roadrunner Gas Transmission - The Roadrunner limited liability company agreement provides that distributions to members are made on a pro rata basis according to each member’s ownership interest. As the operator, we have been delegated the authority to determine such distributions in accordance with, and on the frequency set forth in, the Roadrunner limited liability company agreement. Cash distributions are equal to 100 percent of available cash, as defined in the limited liability company agreement.

J. RELATED-PARTY TRANSACTIONS

On January 31, 2017, we and ONEOK entered into the Merger Agreement pursuant to which ONEOK will acquire all of our outstanding common units representing limited partner interests in us not already directly or indirectly owned by ONEOK. For additional information on this transaction, see Note B.

Under the Services Agreement with ONEOK and ONEOK Partners GP (the Services Agreement), our operations and the operations of ONEOK and its affiliates can combine or share certain common services in order to operate more efficiently and cost effectively. Under the Services Agreement, ONEOK provides to us similar services that it provides to its affiliates, including those services required to be provided pursuant to our Partnership Agreement. ONEOK Partners GP may purchase services from ONEOK and its affiliates pursuant to the terms of the Services Agreement. ONEOK Partners GP has no employees and utilizes the services of ONEOK to fulfill its operating obligations.

ONEOK and its affiliates provide a variety of services to us under the Services Agreement, including cash management and financial services, employee benefits provided through ONEOK’s benefit plans, legal and administrative services, insurance and office space leased in ONEOK’s headquarters building and other field locations. Where costs are incurred specifically on behalf of one of our affiliates, the costs are billed directly to us by ONEOK. In other situations, the costs may be allocated to

24

us through a variety of methods, depending upon the nature of the expenses and activities. For the three months ended March 31, 2017 and 2016, $100.8 million and $87.7 million, respectively, of our operating expenses were incurred with ONEOK and its affiliates.

We have an operating agreement with Roadrunner that provides for reimbursement or payment to us for management services and certain operating costs. Charges to Roadrunner included in operating income in our Consolidated Statements of Income for the three months ended March 31, 2017 and 2016, were not material.

K. COMMITMENTS AND CONTINGENCIES

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

Legal Proceedings - Class Action Litigation - On March 28, 2017, and April 7, 2017, two putative class action lawsuits captioned Juergen Krueger, Individually And On Behalf Of All Others Similarly Situated v. ONEOK Partners, L.P., et al (the First Complaint) and Max Federman, On Behalf of Himself and All Others Similarly Situated v. ONEOK Partners, L.P., et al (the Second Complaint, together with the First Complaint, the Complaints) were filed in the United States District Court for the Northern District of Oklahoma against us and each of the members of the ONEOK Partners GP board of directors as defendants.  The Complaints allege that the defendants violated Sections 14(a) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 14a-9 promulgated thereunder, by causing a materially incomplete and misleading preliminary proxy statement to be filed with the SEC on March 7, 2017.  Both Complaints seek various forms of relief, including injunctive relief and an award of attorneys’ fees and expenses.  Each of the defendants believes the claims asserted in the Complaints are without merit and intends to vigorously defend against this lawsuit. At this time, however, it is not possible to predict the outcome of the proceedings or their impact on us or the Merger Transaction.

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

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 operates regulated interstate and intrastate natural gas transmission pipelines and natural gas storage facilities.

Accounting Policies - The accounting policies of the segments are described in Note A of the Notes to Consolidated Financial Statements in our Annual Report. Our chief operating decision-maker reviews the financial performance of each of our three segments, as well as the financial performance of the Partnership as a whole, on a regular basis. Adjusted EBITDA by segment is utilized in this evaluation. We believe this financial measure is useful to investors because it and similar measures are used by many companies in our industry as a measurement of financial performance and 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 for each segment is defined as net income adjusted for interest expense, depreciation and amortization, noncash impairment charges, income taxes, allowance for equity funds used during construction and other noncash items. This calculation may not be comparable with similarly titled measures of other companies.

25

Customers - The primary customers of our Natural Gas Gathering and Processing segment are crude oil and natural gas producers, which include both large integrated and independent exploration and production companies. Our Natural Gas Liquids segment’s customers are primarily NGL and natural gas gathering and processing companies; large integrated and independent crude oil and natural gas production companies; propane distributors; ethanol producers; and petrochemical, refining and NGL marketing companies. Our Natural Gas Pipelines segment’s customers are primarily local natural gas distribution companies, electric-generation companies, large industrial companies, municipalities, irrigation customers and marketing companies.

For the three months ended March 31, 2017, we had no single customer from which we received 10 percent or more of our consolidated revenues. For the three months ended March 31, 2016, we had one customer, BP p.l.c. or its affiliates, from which we received approximately 12 percent of our consolidated revenues.

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, 2017	Natural Gas Gathering and Processing			Natural Gas Liquids (a)			Natural Gas Pipelines (b)			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	400,149		$	2,244,000		$	104,924		$	2,749,073
Intersegment revenues	261,127			147,984			1,894			411,005
Total revenues	661,276			2,391,984			106,818			3,160,078
Cost of sales and fuel (exclusive of depreciation and items shown separately below)	(488,384		)	(2,048,693		)	(16,603		)	(2,553,680		)
Operating costs	(71,789		)	(78,743		)	(31,753		)	(182,285		)
Equity in net earnings from investments	2,630			13,722			23,212			39,564
Other	234			(41		)	1,284			1,477
Segment adjusted EBITDA	$	103,967		$	278,229		$	82,958		$	465,154
Depreciation and amortization	$	(44,968	)	$	(41,115	)	$	(12,543	)	$	(98,626	)
Total assets	$	5,296,359		$	8,194,835		$	1,945,407		$	15,436,601
Capital expenditures	$	63,151		$	20,453		$	25,014		$	108,618

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $296.3 million, of which $252.9 million related to sales within the segment and cost of sales and fuel of $116.5 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $68.9 million and cost of sales and fuel of $14.1 million.

Three Months Ended March 31, 2017	Total Segments			Other and Eliminations			Total
	(Thousands of dollars)
Reconciliations of total segments to consolidated
Sales to unaffiliated customers	$	2,749,073		$	—		$	2,749,073
Intersegment revenues	411,005			(411,005		)	—
Total revenues	$	3,160,078		$	(411,005	)	$	2,749,073
Cost of sales and fuel (exclusive of depreciation and operating costs)	$	(2,553,680	)	$	409,837		$	(2,143,843	)
Operating costs	$	(182,285	)	$	111		$	(182,174	)
Depreciation and amortization	$	(98,626	)	$	—		$	(98,626	)
Equity in net earnings from investments	$	39,564		$	—		$	39,564
Total assets	$	15,436,601		$	(94,666	)	$	15,341,935
Capital expenditures	$	108,618		$	3,966		$	112,584

26

Three Months Ended March 31, 2016	Natural Gas Gathering and Processing			Natural Gas Liquids (a)			Natural Gas Pipelines (b)			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	317,046		$	1,371,425		$	85,474		$	1,773,945
Intersegment revenues	114,965			115,965			499			231,429
Total revenues	432,011			1,487,390			85,973			2,005,374
Cost of sales and fuel (exclusive of depreciation and items shown separately below)	(266,300		)	(1,156,950		)	(3,932		)	(1,427,182		)
Operating costs	(69,606		)	(73,182		)	(27,513		)	(170,301		)
Equity in net earnings from investments	2,815			13,347			16,752			32,914
Other	1,115			(436		)	3,059			3,738
Segment adjusted EBITDA	$	100,035		$	270,169		$	74,339		$	444,543
Depreciation and amortization	$	(41,851	)	$	(40,706	)	$	(11,179	)	$	(93,736	)
Total assets	$	5,196,190		$	8,016,245		$	1,847,352		$	15,059,787
Capital expenditures	$	141,497		$	34,207		$	17,948		$	193,652

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $281.8 million, of which $230.8 million related to sales within the segment and cost of sales and fuel of $106.8 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $54.8 million and cost of sales and fuel of $5.6 million.

Three Months Ended March 31, 2016	Total Segments			Other and Eliminations			Total
	(Thousands of dollars)
Reconciliations of total segments to consolidated
Sales to unaffiliated customers	$	1,773,945		$	—		$	1,773,945
Intersegment revenues	231,429			(231,429		)	—
Total revenues	$	2,005,374		$	(231,429	)	$	1,773,945
Cost of sales and fuel (exclusive of depreciation and operating costs)	$	(1,427,182	)	$	231,444		$	(1,195,738	)
Operating costs	$	(170,301	)	$	(79	)	$	(170,380	)
Depreciation and amortization	$	(93,736	)	$	—		$	(93,736	)
Equity in net earnings from investments	$	32,914		$	—		$	32,914
Total assets	$	15,059,787		$	(115,065	)	$	14,944,722
Capital expenditures	$	193,652		$	2,244		$	195,896

		Three Months Ended
		March 31,
		2017		2016
Reconciliation of net income to total segment adjusted EBITDA	(Thousands of dollars)
Net income		$	270,026	$	256,286
Add:
Interest expense, net of capitalized interest		90,707		92,555
Depreciation and amortization		98,626		93,736
Income taxes		3,837		2,028
Other noncash items and equity AFUDC		1,958		(62		)
Total segment adjusted EBITDA		$	465,154	$	444,543

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M. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

We have no significant assets or operations other than our investment in our wholly owned subsidiary, the Intermediate Partnership. The Intermediate Partnership holds all our partnership interests and equity in our subsidiaries, as well as a 50 percent interest in Northern Border Pipeline. The Intermediate Partnership guarantees our senior notes and borrowings, if any, under the Partnership Credit Agreement. The Intermediate Partnership’s guarantees of our senior notes and of any borrowings under the Partnership Credit Agreement are full and unconditional, subject to certain customary automatic release provisions.

For purposes of the following footnote:

• we are referred to as “Parent”;

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

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

The following unaudited supplemental condensed consolidating financial information is presented on an equity-method basis reflecting the Parent’s separate accounts, the Guarantor Subsidiary’s separate accounts, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations, and the Parent’s consolidated amounts for the periods indicated.

28

Condensed Consolidating Statements of Income

	Three Months Ended March 31, 2017
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Revenues
Commodity sales	$	—		$	—		$	2,216.7		$	—		$	2,216.7
Services	—			—			532.4			—			532.4
Total revenues	—			—			2,749.1			—			2,749.1
Cost of sales and fuel (exclusive of items shown separately below)	—			—			2,143.8			—			2,143.8
Operating expenses	—			—			280.9			—			280.9
(Gain) loss on sale of assets	—			—			—			—			—
Operating income	—			—			324.4			—			324.4
Equity in net earnings from investments	269.1			269.1			20.7			(519.3		)	39.6
Other income (expense), net	91.3			91.3			0.6			(182.6		)	0.6
Interest expense, net	(91.3		)	(91.3		)	(90.7		)	182.6			(90.7		)
Income before income taxes	269.1			269.1			255.0			(519.3		)	273.9
Income taxes	—			—			(3.9		)	—			(3.9		)
Net income	269.1			269.1			251.1			(519.3		)	270.0
Less: Net income attributable to noncontrolling interests	—			—			0.9			—			0.9
Net income attributable to ONEOK Partners, L.P.	$	269.1		$	269.1		$	250.2		$	(519.3	)	$	269.1

	Three Months Ended March 31, 2016
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Revenues
Commodity sales	$	—		$	—		$	1,283.5		$	—		$	1,283.5
Services	—			—			490.4			—			490.4
Total revenues	—			—			1,773.9			—			1,773.9
Cost of sales and fuel (exclusive of items shown separately below)	—			—			1,195.7			—			1,195.7
Operating expenses	—			—			264.1			—			264.1
(Gain) loss on sale of assets	—			—			(4.1		)	—			(4.1		)
Operating income	—			—			318.2			—			318.2
Equity in net earnings from investments	253.5			253.5			14.2			(488.3		)	32.9
Other income (expense), net	94.4			94.4			(0.2		)	(188.8		)	(0.2		)
Interest expense, net	(94.4		)	(94.4		)	(92.6		)	188.8			(92.6		)
Income before income taxes	253.5			253.5			239.6			(488.3		)	258.3
Income taxes	—			—			(2.0		)	—			(2.0		)
Net income	253.5			253.5			237.6			(488.3		)	256.3
Less: Net income attributable to noncontrolling interests	—			—			2.8			—			2.8
Net income attributable to ONEOK Partners, L.P.	$	253.5		$	253.5		$	234.8		$	(488.3	)	$	253.5

29

Condensed Consolidating Statements of Comprehensive Income

	Three Months Ended March 31, 2017
(Unaudited)	Parent		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidating Entries			Total
	(Millions of dollars)
Net income	$	269.1	$	269.1	$	251.1	$	(519.3	)	$	270.0
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	28.8		27.3		27.3		(54.6		)	28.8
Realized (gains) losses on derivatives recognized in net income	19.8		15.3		15.3		(30.6		)	19.8
Other comprehensive income (loss) on investments in unconsolidated affiliates	0.4		0.4		0.4		(0.8		)	0.4
Total other comprehensive income (loss)	49.0		43.0		43.0		(86.0		)	49.0
Comprehensive income	318.1		312.1		294.1		(605.3		)	319.0
Less: Comprehensive income attributable to noncontrolling interests	—		—		0.9		—			0.9
Comprehensive income attributable to ONEOK Partners, L.P.	$	318.1	$	312.1	$	293.2	$	(605.3	)	$	318.1

	Three Months Ended March 31, 2016
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Net income	$	253.5		$	253.5		$	237.6		$	(488.3	)	$	256.3
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	(19.9		)	11.7			11.7			(23.4		)	(19.9		)
Realized (gains) losses on derivatives recognized in net income	(10.7		)	(14.5		)	(14.5		)	29.0			(10.7		)
Other comprehensive income (loss) on investments in unconsolidated affiliates	(5.8		)	(5.8		)	(5.8		)	11.6			(5.8		)
Total other comprehensive income (loss)	(36.4		)	(8.6		)	(8.6		)	17.2			(36.4		)
Comprehensive income	217.1			244.9			229.0			(471.1		)	219.9
Less: Comprehensive income attributable to noncontrolling interests	—			—			2.8			—			2.8
Comprehensive income attributable to ONEOK Partners, L.P.	$	217.1		$	244.9		$	226.2		$	(471.1	)	$	217.1

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Condensed Consolidating Balance Sheets

	March 31, 2017
(Unaudited)	Parent		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidating Entries			Total
Assets	(Millions of dollars)
Current assets
Cash and cash equivalents	$	—	$	8.5	$	—	$	—		$	8.5
Accounts receivable, net	—		—		734.8		—			734.8
Affiliate receivables	—		—		0.2		—			0.2
Natural gas and natural gas liquids in storage	—		—		193.3		—			193.3
Other current assets	0.1		—		128.8		—			128.9
Total current assets	0.1		8.5		1,057.1		—			1,065.7
Property, plant and equipment
Property, plant and equipment	—		—		14,930.5		—			14,930.5
Accumulated depreciation and amortization	—		—		2,482.9		—			2,482.9
Net property, plant and equipment	—		—		12,447.6		—			12,447.6
Investments and other assets
Intercompany notes receivable	10,786.3		6,881.6		—		(17,667.9		)	—
Other assets	3,249.0		7,097.4		1,455.2		(9,973.0		)	1,828.6
Total investments and other assets	14,035.3		13,979.0		1,455.2		(27,640.9		)	1,828.6
Total assets	$	14,035.4	$	13,987.5	$	14,959.9	$	(27,640.9	)	$	15,341.9
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	400.0	$	—	$	7.7	$	—		$	407.7
Short-term borrowings	1,290.7		—		—		—			1,290.7
Accounts payable	—		—		691.7		—			691.7
Affiliate payables	—		—		22.7		—			22.7
Other current liabilities	83.5		—		198.1		—			281.6
Total current liabilities	1,774.2		—		920.2		—			2,694.4
Intercompany debt	—		10,786.3		6,881.6		(17,667.9		)	—
Long-term debt, excluding current maturities	6,256.3		—		34.7		—			6,291.0
Deferred credits and other liabilities	—		—		193.8		—			193.8
Commitments and contingencies
Equity
Equity excluding noncontrolling interests in consolidated subsidiaries	6,004.9		3,201.2		6,771.8		(9,973.0		)	6,004.9
Noncontrolling interests in consolidated subsidiaries	—		—		157.8		—			157.8
Total equity	6,004.9		3,201.2		6,929.6		(9,973.0		)	6,162.7
Total liabilities and equity	$	14,035.4	$	13,987.5	$	14,959.9	$	(27,640.9	)	$	15,341.9

31

	December 31, 2016
(Unaudited)	Parent		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidating Entries			Total
Assets	(Millions of dollars)
Current assets
Cash and cash equivalents	$	—	$	0.4	$	—	$	—		$	0.4
Accounts receivable, net	—		—		872.3		—			872.3
Affiliate receivables	—		—		1.0		—			1.0
Natural gas and natural gas liquids in storage	—		—		140.0		—			140.0
Materials and supplies	—		—		60.9		—			60.9
Other current assets	—		—		99.6		—			99.6
Total current assets	—		0.4		1,173.8		—			1,174.2
Property, plant and equipment
Property, plant and equipment	—		—		14,854.7		—			14,854.7
Accumulated depreciation and amortization	—		—		2,392.0		—			2,392.0
Net property, plant and equipment	—		—		12,462.7		—			12,462.7
Investments and other assets
Intercompany notes receivable	10,615.0		7,031.3		—		(17,646.3		)	—
Other assets	3,269.6		6,805.4		1,457.2		(9,699.8		)	1,832.4
Total investments and other assets	13,884.6		13,836.7		1,457.2		(27,346.1		)	1,832.4
Total assets	$	13,884.6	$	13,837.1	$	15,093.7	$	(27,346.1	)	$	15,469.3
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	400.0	$	—	$	7.7	$	—		$	407.7
Short-term borrowings	1,110.3		—		—		—			1,110.3
Accounts payable	—		—		862.4		—			862.4
Affiliate payables	—		—		68.2		—			68.2
Other current liabilities	99.9		—		275.9		—			375.8
Total current liabilities	1,610.2		—		1,214.2		—			2,824.4
Intercompany debt	—		10,615.0		7,031.3		(17,646.3		)	—
Long-term debt, excluding current maturities	6,254.7		—		36.6		—			6,291.3
Deferred credits and other liabilities	—		—		175.8		—			175.8
Commitments and contingencies
Equity
Equity excluding noncontrolling interests in consolidated subsidiaries	6,019.7		3,222.1		6,477.7		(9,699.8		)	6,019.7
Noncontrolling interests in consolidated subsidiaries	—		—		158.1		—			158.1
Total equity	6,019.7		3,222.1		6,635.8		(9,699.8		)	6,177.8
Total liabilities and equity	$	13,884.6	$	13,837.1	$	15,093.7	$	(27,346.1	)	$	15,469.3

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Condensed Consolidating Statements of Cash Flows

	Three Months Ended March 31, 2017
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Operating activities
Cash provided by operating activities	$	322.1		$	18.8		$	272.4		$	(333.0	)	$	280.3
Investing activities
Capital expenditures	—			—			(112.6		)	—			(112.6		)
Other investing activities	—			2.9			0.3			—			3.2
Cash provided by (used in) investing activities	—			2.9			(112.3		)	—			(109.4		)
Financing activities
Cash distributions:
General and limited partners	(333.0		)	(333.0		)	—			333.0			(333.0		)
Noncontrolling interests	—			—			(1.2		)	—			(1.2		)
Intercompany borrowings (advances), net	(162.4		)	319.4			(157.0		)	—			—
Borrowing (repayment) of short-term borrowings, net	180.5			—			—			—			180.5
Repayment of long-term debt	—			—			(1.9		)	—			(1.9		)
Other	(7.2		)	—			—			—			(7.2		)
Cash used in financing activities	(322.1		)	(13.6		)	(160.1		)	333.0			(162.8		)
Change in cash and cash equivalents	—			8.1			—			—			8.1
Cash and cash equivalents at beginning of period	—			0.4			—			—			0.4
Cash and cash equivalents at end of period	$	—		$	8.5		$	—		$	—		$	8.5

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	Three Months Ended March 31, 2016
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Operating activities
Cash provided by operating activities	$	318.8		$	18.7		$	261.8		$	(333.0	)	$	266.3
Investing activities
Capital expenditures	—			—			(195.9		)	—			(195.9		)
Other investing activities	—			3.2			23.2			—			26.4
Cash provided by (used in) investing activities	—			3.2			(172.7		)	—			(169.5		)
Financing activities
Cash distributions:
General and limited partners	(333.0		)	(333.0		)	—			333.0			(333.0		)
Noncontrolling interests	—			—			(2.5		)	—			(2.5		)
Intercompany borrowings (advances), net	(231.2		)	315.9			(84.7		)	—			—
Borrowing (repayment) of short-term borrowings, net	(101.8		)	—			—			—			(101.8		)
Issuance of long-term debt, net of discounts	1,000.0			—			—			—			1,000.0
Debt financing costs	(2.8		)	—			—			—			(2.8		)
Repayment of long-term debt	(650.0		)	—			(1.9		)	—			(651.9		)
Cash used in financing activities	(318.8		)	(17.1		)	(89.1		)	333.0			(92.0		)
Change in cash and cash equivalents	—			4.8			—			—			4.8
Cash and cash equivalents at beginning of period	—			5.1			—			—			5.1
Cash and cash equivalents at end of period	$	—		$	9.9		$	—		$	—		$	9.9

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

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

RECENT DEVELOPMENTS

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

Merger Transaction - On January 31, 2017, we and ONEOK entered into the Merger Agreement pursuant to which ONEOK will acquire all of our outstanding common units representing limited partner interests in us not already directly or indirectly owned by ONEOK in an all stock-for-unit transaction at a ratio of 0.985 of a share of ONEOK common stock per common unit of ONEOK Partners, in a taxable transaction to our common unitholders. Following completion of the Merger Transaction, all of our outstanding common units will be directly or indirectly owned by ONEOK and will no longer be publicly traded. All of our outstanding debt is expected to remain outstanding. We, ONEOK and the Intermediate Partnership expect to issue, to the extent not already in place, guarantees of the indebtedness of ONEOK and ONEOK Partners.

For additional information on this transaction, see Note B of the Notes to Consolidated Financial Statements in this Quarterly Report.

Business Update and Market Conditions - We operate predominantly fee-based businesses in each of our three reportable segments and expect our consolidated earnings to be approximately 90 percent fee-based in 2017. In the first quarter 2017, our Natural Gas Gathering and Processing segment’s fee revenues averaged 83 cents per MMBtu, compared with an average of 68 cents per MMBtu in the same period in 2016, due to our contract restructuring efforts to address commodity price risk. We connected three third-party natural gas processing plants in our Natural Gas Liquids segment in the first quarter 2017, and our fee-based transportation services increased in our Natural Gas Pipelines segment, compared with the first quarter 2016. We continue to expect demand for midstream services and infrastructure development to be primarily driven by producers who need to connect production with end-use markets where current infrastructure is insufficient. We also expect additional demand for our services to support increased demand for NGL products from the petrochemical industry and NGL exporters, and increased demand for natural gas from power plants previously fueled by coal and natural gas exports.

We have available capacity on our integrated network of assets to grow fee-based earnings with minimal capital investments. We are connected to supply in attractive, productive basins and have significant basin diversification across our asset footprint from the Williston, Permian and Powder River Basins to the STACK and SCOOP areas of the Anadarko Basin in Oklahoma. In addition, we are connected to major market centers for natural gas and NGL products. While our Natural Gas Gathering and Processing and Natural Gas Liquids segments generate predominately fee-based earnings, those segments’ results of operations are exposed to volumetric risk. Our exposure to volumetric risk can result from reduced drilling activity, severe weather disruptions, operational outages and ethane rejection.

STACK and SCOOP -We expect each of our business segments to benefit from increasing production activity in the Mid-Continent region from the highly productive STACK and SCOOP areas, where there was an increase in producer activity in late 2016 and early 2017, which we expect to continue throughout 2017. As producers continue to develop the STACK and SCOOP areas, we expect natural gas and NGL volumes on our systems to increase primarily in the second half of 2017, compared with 2016 volumes, and expect increased demand for our services from producers that need incremental takeaway capacity for natural gas and NGLs out of the region. We anticipate NGL volume growth in the Mid-Continent region will also be driven by expected increases in ethane recovery in the second half of 2017 as new world-scale ethylene production projects, petrochemical plant modifications, plant expansions and export facilities near completion and begin coming on line.

In our Natural Gas Gathering and Processing segment, we have more than 200,000 acres dedicated to us in the STACK and SCOOP areas. In our Natural Gas Liquids segment, we are the largest NGL takeaway provider in the STACK and SCOOP areas through connections to more than 100 third-party natural gas processing plants in the Mid-Continent region. In the STACK and SCOOP areas, we connected one third-party natural gas processing plant in the first quarter 2017 and expect to connect two additional third-party natural gas processing plants to our NGL system in the remainder of 2017. In our Natural Gas Pipelines segment, we are connected to more than 30 natural gas processing plants in Oklahoma, which have a total processing capacity of approximately 1.8 Bcf/d, and are expanding the ONEOK Gas Transmission Pipeline, with additional

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compression, to serve a firm commitment for the westbound transportation of 100 MMcf/d of natural gas out of the STACK and SCOOP areas.

Williston Basin -We expect each of our business segments to benefit from increasing production activity in the Williston Basin, where there was an increase in producer activity in late 2016 and early 2017, which we expect to continue throughout 2017. In our Natural Gas Gathering and Processing segment, our completed growth projects, including our Bear Creek natural gas processing plant and infrastructure project that was completed in August 2016, have increased our gathering and processing capacity and allowed us to capture natural gas from new wells being drilled and natural gas from wells that previously flared natural gas production. We have available natural gas processing capacity in this basin of approximately 175 MMcf/d. In our Natural Gas Liquids segment, we are the largest NGL takeaway provider in the basin through connections to more than 10 natural gas processing plants, both third-party and our own, and we connected one new third-party natural gas processing plant in the Rocky Mountain region in the first quarter 2017. Volumes being flared on our dedicated acreage averaged approximately 60-80 MMcf/d in the first quarter 2017 and represent future volume growth opportunities in our Natural Gas Liquids and Natural Gas Gathering and Processing segments.

In this region, we experienced severe winter weather during the first quarter of 2017 that temporarily reduced our natural gas volumes in our Natural Gas Gathering and Processing segment, which had an unfavorable impact on our financial results.

Permian Basin -We expect our Natural Gas Liquids and Natural Gas Pipelines business segments to benefit from increasing production activity in the Permian Basin from the highly productive Delaware and Midland Basins, where there was an increase in producer activity in late 2016 and early 2017, which we expect to continue throughout 2017.

In our Natural Gas Liquids segment, we are well-positioned in the Permian Basin and are connected to nearly 40 third-party natural gas processing plants through our West Texas LPG joint venture. In the Permian Basin, we connected one third-party natural gas processing plant in the first quarter 2017 and expect to connect one additional third-party natural gas processing plant in the remainder of 2017. In our Natural Gas Pipelines segment, we believe we are well-positioned in the Delaware Basin and have a significant position in the Midland Basin. We are connected to more than 25 natural gas processing plants serving the Permian Basin, which have a total processing capacity of approximately 1.9 Bcf/d. The Roadrunner pipeline transports natural gas from the Permian Basin in West Texas to the Mexican border near El Paso, Texas, and is fully subscribed with 25-year firm demand charge, fee-based agreements. The Roadrunner pipeline connects with our existing natural gas pipeline and storage infrastructure in Texas and, together with our WesTex intrastate natural gas pipeline expansion project, creates a platform for future opportunities to deliver natural gas supply to Mexico. Roadrunner’s long-term firm demand transportation service contracts provide markets in Mexico access to upstream supply basins in West Texas and the Mid-Continent region, which adds location and price diversity to their supply mix and supports the plan of Mexico’s national electric utility, Comisión Federal de Electricidad, to replace oil-fueled power plants with natural gas-fueled power plants, which are more economical and produce fewer GHG emissions.

Ethane Opportunity -Ethane recovery levels by natural gas processors delivering to our NGL system have recently increased, primarily in the Mid-Continent region. Ethane rejection levels across our system averaged more than 150 MBbl/d in the first three months of 2017, compared with an average of more than 175 MBbl/d in the same period in 2016. While the volume of ethane recovered increased during the three months ended March 31, 2017, compared with the same period in 2016, a portion of the fees associated with those volumes gathered and fractionated was previously being earned under contracts with minimum volume obligations. We expect ethane recovery levels to fluctuate for the remainder of 2017 as ethane supply and demand begin to balance and as the price differentials between ethane and natural gas change. We expect ethane recovery levels to increase, first in regions closest to market centers, as ethylene producers and NGL exporters increase their capacity to consume and export additional ethane volumes in the second half of 2017. We expect the future ethane recoveries to have a favorable impact on our financial results, primarily in the second half of 2017.

Cash Distributions - In April 2017, our general partner declared a cash distribution of $0.79 per unit ($3.16 per unit on an annualized basis) for the first quarter 2017, which will be paid on May 15, 2017, to unitholders of record as of the close of business on May 1, 2017.

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FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

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

		Three Months Ended						Three Months
		March 31,						2017 vs. 2016
Financial Results		2017			2016			Increase (Decrease)
	(Millions of dollars)
Revenues
Commodity sales		$	2,216.7		$	1,283.5		$	933.2		73	%
Services		532.4			490.4			42.0			9	%
Total revenues		2,749.1			1,773.9			975.2			55	%
Cost of sales and fuel (exclusive of items shown separately below)		2,143.8			1,195.7			948.1			79	%
Operating costs		182.3			170.4			11.9			7	%
Depreciation and amortization		98.6			93.7			4.9			5	%
(Gain) loss on sale of assets		—			(4.1		)	(4.1		)	(100	%)
Operating income		$	324.4		$	318.2		$	6.2		2	%
Equity in net earnings from investments		$	39.6		$	32.9		$	6.7		20	%
Interest expense, net of capitalized interest		$	(90.7	)	$	(92.6	)	$	(1.9	)	(2	%)
Net income		$	270.0		$	256.3		$	13.7		5	%
Adjusted EBITDA		$	464.2		$	444.6		$	19.6		4	%
Capital expenditures		$	112.6		$	195.9		$	(83.3	)	(43	%)

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

Due to the nature of our contracts, changes in commodity prices and sales volumes affect both commodity sales and cost of sales and fuel in our Consolidated Statements of Income and therefore the impact is largely offset between the two line items.

Operating income and adjusted EBITDA increased for the three months ended March 31, 2017, compared with the same period in 2016, due primarily to higher fees resulting from contract restructuring in our Natural Gas Gathering and Processing segment, higher transportation services due to increased firm demand charge contracted capacity in our Natural Gas Pipelines segment and increased optimization and marketing activities in our Natural Gas Liquids segment resulting primarily from wider location price differentials. These increases were offset partially by lower volumes due to severe winter weather in our Natural Gas Gathering and Processing segment, higher operating costs related to increased ad valorem taxes in our Natural Gas Liquids and Natural Gas Pipelines segments and higher labor and employee-related costs. Operating income was also impacted by higher depreciation expense in the three months ended March 31, 2017, compared with the same period in 2016, due to projects completed in 2016. In the three months ended March 31, 2017, we incurred operating costs related to the Merger Transaction of approximately $1.1 million.

Equity in net earnings from investments increased for the three months ended March 31, 2017, compared with the same period in 2016, due primarily to higher firm transportation revenues on Roadrunner, which added capacity in October 2016 that is fully subscribed under long-term firm demand charge contracts.

Capital expenditures decreased for the three months ended March 31, 2017, compared with the same period in 2016, due to projects placed in service in 2016 and fewer well connections in our Natural Gas Gathering and Processing segment due to the impact of severe winter weather in the Williston Basin in the first quarter 2017.

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 contracted producers in North Dakota, Montana, Wyoming, Kansas and Oklahoma. Raw natural gas is gathered, compressed and transported through pipelines to our processing facilities. In order for the natural gas to be accepted by the downstream market, it must have contaminants, such as water, nitrogen and carbon dioxide, removed and NGLs separated for further processing. Processed

37

natural gas, usually referred to as residue natural gas, is then recompressed and delivered to natural gas pipelines, storage facilities and end users. The separated NGLs are in a mixed, unfractionated form and are sold and delivered through natural gas liquids pipelines to fractionation facilities for further separation.

We gather and process natural gas in the Williston Basin, which is located in portions of North Dakota and Montana, including the oil-producing, NGL-rich Bakken Shale and Three Forks formations, and is an active drilling region. Our completed growth projects, including our Bear Creek natural gas processing plant and infrastructure project that was completed in August 2016, have increased our gathering and processing capacity and allowed us to capture natural gas from new wells being drilled and from wells that previously flared natural gas production. Our Mid-Continent region is an active drilling region and includes the NGL-rich STACK and SCOOP areas in the Anadarko Basin and the Cana-Woodford Shale, Woodford Shale, Springer Shale, Meramec, Granite Wash and Mississippian Lime formation of Oklahoma and Kansas; and the Hugoton and Central Kansas Uplift Basins of Kansas. The Powder River Basin is primarily located in Wyoming, which includes the NGL-rich Niobrara Shale and Frontier, Turner and Sussex formations where we provide gathering and processing services to customers in the southeast portion of Wyoming.

Revenues for this segment are derived primarily from POP with fee contracts and fee-only contracts. Under a POP with fee contract, we charge fees for gathering, treating, compressing and processing the producer’s natural gas. We also generally purchase the producer’s raw natural gas, which we process into residue natural gas and NGLs, then we sell these commodities and associated condensate to downstream customers. We remit sales proceeds to the producer according to the contractual terms and retain our portion. Over time as these contracts are renewed or restructured, we have generally increased the fee components. Additionally, under certain POP with fee contracts our fee revenues may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds. With a fee-only contract, we are paid a fee for the services we provide, based on volumes gathered, processed, treated and/or compressed.

We have restructured many of our contracts to significantly increase our fees, and as a result of these restructured contracts, our Natural Gas Gathering and Processing segment’s earnings are primarily fee-based. These restructured contracts favorably impacted our results for the three months ended March 31, 2017, and we expect to continue to receive the benefit of improved earnings from these contracts. Our direct commodity price sensitivity in this segment has decreased as a result of these restructured contracts. To mitigate the impact of our remaining commodity price exposure, we have hedged a significant portion of our Natural Gas Gathering and Processing segment’s commodity price risk for 2017 and 2018. This segment has substantial acreage dedications in some of the most productive areas of the Williston Basin and Mid-Continent region, specifically the STACK and SCOOP, which helps to mitigate volumetric risk.

Our natural gas gathered and processed volumes in the Williston Basin decreased for the three months ended March 31, 2017, compared with the same period in 2016, due primarily to severe winter weather in the first quarter 2017. We expect that Williston Basin volumes for 2017 will increase slightly compared with 2016 due to the following:

• producers focusing their drilling and completion in the most productive areas in which we have substantial acreage dedications and significant gathering and processing assets;

• continued improvements in production by producers due to enhanced completion techniques and more efficient drilling rigs; and

• the opportunity to capture additional natural gas from wells that currently flare natural gas production; offset partially by

• natural production declines.

In the Mid-Continent region, we have significant natural gas gathering and processing assets in Oklahoma and Kansas. With the emerging STACK and SCOOP areas, we anticipate increased producer activity, where we have substantial acreage dedications in these productive areas. Although volumes decreased for the three months ended March 31, 2017, compared with the same period in 2016, we expect our average natural gas volumes to grow in 2017 due to continued drilling and completion activity, offset partially by the natural production declines from existing wells connected to our system.

Growth Projects - Our Natural Gas Gathering and Processing segment is investing in growth projects in NGL-rich areas, including the Bakken Shale and Three Forks formation in the Williston Basin and STACK and SCOOP areas of the Anadarko Basin, that we expect will enable us to meet the needs of crude oil and natural gas producers in those areas. Nearly all of the new natural gas production is from horizontally drilled wells in nonconventional resource areas. These wells tend to produce volumes at higher initial production rates resulting generally in higher initial decline rates than conventional vertical wells; however, the decline rates flatten out over time. These wells are expected to have long productive lives.

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In August 2016, we completed the 80 MMcf/d Bear Creek processing plant and infrastructure project in the Williston Basin for approximately $240 million, excluding capitalized interest.

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

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

		Three Months Ended						Three Months
		March 31,						2017 vs. 2016
Financial Results		2017			2016			Increase (Decrease)
	(Millions of dollars)
NGL sales		$	245.5		$	94.6		$	150.9		*
Condensate sales		19.0			12.7			6.3			50	%
Residue natural gas sales		210.5			157.7			52.8			33	%
Gathering, compression, dehydration and processing fees and other revenue		186.3			167.0			19.3			12	%
Cost of sales and fuel (exclusive of depreciation and items shown separately below)		(488.4		)	(266.3		)	222.1			83	%
Operating costs		(71.8		)	(69.6		)	2.2			3	%
Equity in net earnings from investments		2.6			2.8			(0.2		)	(7	%)
Other		0.3			1.1			(0.8		)	(73	%)
Adjusted EBITDA		$	104.0		$	100.0		$	4.0		4	%
Capital expenditures		$	63.2		$	141.5		$	(78.3	)	(55	%)

* Percentage change is greater than 100 percent.

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

Due to the nature of our contracts, changes in commodity prices and sales volumes affect commodity sales and cost of sales and fuel and therefore the impact is largely offset between these line items.

Adjusted EBITDA increased $4.0 million for the three months ended March 31, 2017, compared with the same period in 2016, primarily as a result of the following:

• an increase of $19.8 million due primarily to restructured contracts resulting in higher fee revenues from increased average fee rates, offset partially by a lower percentage of proceeds retained from the sale of commodities purchased under our POP with fee contracts; offset partially by

• a decrease of $10.2 million due primarily to lower volumes as a result of severe winter weather in the first quarter of 2017;

• a decrease of $2.4 million due primarily to lower realized natural gas prices; and

• an increase of $2.2 million in operating costs due primarily to increased labor and higher employee-related costs, partially offset by lower outside service expenses.

Capital expenditures decreased for the three months ended March 31, 2017, compared with the same period in 2016, due to projects placed in service in 2016 and fewer well connections due to the impact of severe winter weather in the Williston Basin in the first quarter 2017.

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

	Three Months Ended
	March 31,
Operating Information (a)	2017		2016
Natural gas gathered (BBtu/d)	1,985		2,128
Natural gas processed (BBtu/d) (b)	1,863		1,948
NGL sales (MBbl/d)	172		155
Residue natural gas sales (BBtu/d)	793		941
Realized composite NGL net sales price ($/gallon) (c) (d)	$	0.19	$	0.20
Realized condensate net sales price ($/Bbl) (c) (e)	$	32.32	$	33.72
Realized residue natural gas net sales price ($/MMBtu) (c) (e)	$	2.38	$	2.62
Average fee rate ($/MMBtu)	$	0.83	$	0.68

(a) - Includes volumes for consolidated entities only.

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

(c) - Includes the impact of hedging activities on our equity volumes.

(d) - Net of transportation and fractionation costs.

(e) - Net of transportation costs.

Natural gas gathered and natural gas processed decreased during the three months ended March 31, 2017, compared with the same period in 2016, due to the impact of severe winter weather in the first quarter 2017 and natural production declines on existing wells. NGL sales increased and residue natural gas sales decreased due primarily to increased ethane recovery.

The quantity and composition of NGLs and natural gas have varied as new plants were placed in service and to ensure natural gas and natural gas liquids pipeline specifications were met.

	Three Months Ended
	March 31,
Equity Volume Information (a)	2017	2016
NGL sales - including ethane (MBbl/d)	9.8	16.4
Condensate sales (MBbl/d)	3.1	2.7
Residue natural gas sales (BBtu/d)	71.1	83.8

(a) - Includes volumes for consolidated entities only.

Our equity NGL and natural gas volumes decreased during the three months ended March 31, 2017, compared with the same period in 2016, due to our contract restructuring efforts and the impact of severe winter weather in the first quarter 2017. As contracts are renewed or restructured, we have generally increased the fee component and lowered the percentage of proceeds that we retain from the sale of commodities.

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 where we provide midstream services to producers of NGLs and deliver those products to the two primary market centers, one in the Mid-Continent in Conway, Kansas, and the other in the Gulf Coast in Mont Belvieu, Texas. We own or have an ownership interest in FERC-regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas, Texas, New Mexico, Montana, North Dakota, Wyoming and Colorado, and terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois. We also own FERC-regulated natural gas liquids distribution and refined petroleum products pipelines in Kansas, Missouri, Nebraska, Iowa, Illinois and Indiana that connect our Mid-Continent assets with Midwest markets, including Chicago, Illinois. The majority of the pipeline-connected natural gas processing plants in Oklahoma, Kansas and the Texas Panhandle are connected to our gathering systems. We own and operate truck- and rail-loading and -unloading facilities connected to our natural gas liquids fractionation and pipeline assets.

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Most natural gas produced at the wellhead contains a mixture of NGL components, such as ethane, propane, iso-butane, normal butane and natural gasoline. The NGLs that are separated from the natural gas stream at natural gas processing plants remain in a mixed, unfractionated form until they are gathered, primarily by pipeline, and delivered to fractionators where the NGLs are separated into NGL products. These NGL products are then stored or distributed to our customers, such as petrochemical manufacturers, heating fuel users, ethanol producers, refineries, exporters and propane distributors.

Revenues for our Natural Gas Liquids segment are derived primarily from fee-based services that we provide to our customers and from the physical optimization of our assets. We also purchase NGLs and condensate from third parties, as well as from our Natural Gas Gathering and Processing segment. Our fee-based services have increased due primarily to new supply connections, expansion of existing connections and the completion of capital-growth projects. Our business activities are categorized as exchange services, transportation and storage services, and optimization and marketing, which are defined as follows:

• Exchange services - we utilize our assets to gather, fractionate and/or treat, and transport unfractionated NGLs, thereby converting them into marketable NGL products shipped to a market center or customer-designated location. Many of these exchange volumes are under contracts with minimum volume commitments that provide a minimum level of revenues regardless of volumetric throughput. Our exchange services activities are primarily fee-based and include some rate-regulated tariffs; however, we also capture certain product price differentials through the fractionation process.

• Transportation and storage services - we transport NGL products and refined petroleum products, primarily under FERC-regulated tariffs. Tariffs specify the maximum rates we may charge our customers and the general terms and conditions for NGL transportation service on our pipelines. Our storage activities consist primarily of fee-based NGL storage services at our Mid-Continent and Gulf Coast storage facilities.

• Optimization and marketing - we utilize our assets, contract portfolio and market knowledge to capture location, product and seasonal price differentials. We primarily transport NGL products between Conway, Kansas, and Mont Belvieu, Texas, to capture the location price differentials between the two market centers. Our marketing activities also include utilizing our natural gas liquids storage facilities to capture seasonal price differentials. A growing portion of our marketing activities serves truck and rail markets. Our isomerization activities capture the price differential when normal butane is converted into the more valuable iso-butane at our isomerization unit in Conway, Kansas.

Supply growth from the development of NGL-rich areas and capacity available on pipelines that connect the Mid-Continent and Gulf Coast resulted in NGL price differentials remaining narrow between the Mid-Continent market center at Conway, Kansas, and the Gulf Coast market center at Mont Belvieu, Texas. We expect these narrow price differentials to persist between these two market centers until demand for NGLs increases from petrochemical companies and exporters, which we anticipate to begin in the second half of 2017.

Supply growth has resulted in available ethane supplies that are greater than the petrochemical industry’s current demand. As a result, low or unprofitable price differentials between ethane and natural gas have resulted in ethane rejection at most of our and our customers’ natural gas processing plants connected to our NGL system in the Mid-Continent and Rocky Mountain regions, which reduced the ethane component of natural gas liquids volumes gathered, fractionated, transported and sold across our assets. Through ethane rejection, natural gas processors leave some of the ethane component in the natural gas stream sold at the tailgate of natural gas processing plants. Ethane recovery levels by natural gas processors delivering to our NGL system have increased, primarily in the Mid-Continent region. Ethane rejection levels across our system averaged more than 150 MBbl/d in the first three months of 2017, compared with an average of more than 175 MBbl/d in the same period in 2016. While the volume of ethane recovered increased during the three months ended March 31, 2017, compared with the same period in 2016, a portion of the fees associated with those volumes gathered and fractionated was previously being earned under contracts with minimum volume obligations. We expect ethane recovery levels to fluctuate for the remainder of 2017 as ethane supply and demand begin to balance and as the price differentials between ethane and natural gas change. We expect ethane recovery levels to increase, first in regions closest to market centers, as ethylene producers and NGL exporters increase their capacity to consume and export additional ethane volumes in the second half of 2017.

Our Natural Gas Liquids segment’s integrated assets enable us to mitigate partially the impact of ethane rejection through minimum volume commitments, contract modifications that vary fees for ethane and other NGL products, and our ability to utilize the transportation capacity made available due to ethane rejection to capture additional NGL location price differentials, when they exist, in our optimization activities.

Growth Projects - Our growth strategy in our Natural Gas Liquids segment is focused around the crude oil and NGL-rich natural gas drilling activity in shale and other nonconventional resource areas from the Rocky Mountain region through the Mid-Continent region into Texas and New Mexico. Crude oil, natural gas and NGL production from this activity; higher

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petrochemical industry demand for NGL products; and increased exports have resulted in our making additional capital investments to expand our infrastructure to bring these commodities from supply basins to market.

Our Natural Gas Liquids segment invests in NGL-related projects to accommodate the transportation, fractionation and storage of NGL supply from shale and other resource development areas across our asset base, to alleviate expected infrastructure constraints between the Mid-Continent and Gulf Coast market centers and to meet increasing petrochemical industry and NGL export demand in the Gulf Coast.

We connected three third-party natural gas processing plants to our NGL system in the first quarter 2017, one each in the Mid-Continent and Rocky Mountain regions and the Permian Basin. We expect to connect two additional third-party natural gas processing plants in the Mid-Continent region and one additional third-party natural gas processing plant in the Permian Basin in the remainder of 2017.

In August 2016, we completed the Bear Creek NGL infrastructure project in the Williston Basin, for approximately $45 million, excluding AFUDC.

Construction of Phase II of the Bakken NGL Pipeline expansion is planned for completion in the third quarter 2018, which is expected to increase capacity by 25 MBbl/d and cost approximately $100 million, excluding AFUDC.

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

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

		Three Months Ended						Three Months
		March 31,						2017 vs. 2016
Financial Results		2017			2016			Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales		$	2,008.0		$	1,117.1		$	890.9		80	%
Exchange service revenues		333.3			322.9			10.4			3	%
Transportation and storage revenues		50.7			47.4			3.3			7	%
Cost of sales and fuel (exclusive of depreciation and items shown separately below)		(2,048.7		)	(1,157.0		)	891.7			77	%
Operating costs		(78.7		)	(73.2		)	5.5			8	%
Equity in net earnings from investments		13.7			13.3			0.4			3	%
Other		(0.1		)	(0.3		)	0.2			67	%
Adjusted EBITDA		$	278.2		$	270.2		$	8.0		3	%
Capital expenditures		$	20.5		$	34.2		$	(13.7	)	(40	%)

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

Due to the nature of our contracts, changes in commodity prices and sales volumes generally affect both NGL and condensate sales, and cost of sales and fuel, and the impact is largely offset between these line items.

Adjusted EBITDA increased $8.0 million for the three months ended March 31, 2017, compared with the same period in 2016, primarily as a result of the following:

• an increase of $5.3 million in optimization and marketing due primarily to wider location price differentials;

• an increase of $3.9 million in transportation and storage services due to higher volumes on our distribution pipelines and higher storage and terminaling revenue in the Gulf Coast region;

• an increase of $3.6 million due to wider product price differentials, increased exchange service volumes from recently connected natural gas processing plants primarily in the Williston Basin, increased ethane recovery and increased volumes gathered in the STACK and SCOOP areas, offset partially by decreased volumes gathered from the Barnett Shale and lower rates on the West Texas LPG system; offset partially by

• an increase of $5.5 million in operating costs due primarily to higher ad valorem taxes and higher employee-related costs.

Capital expenditures decreased for the three months ended March 31, 2017, compared with the same period in 2016, due primarily to completed capital projects.

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

	Three Months Ended
	March 31,
Operating Information	2017		2016
NGLs transported-gathering lines (MBbl/d) (a)	764		751
NGLs fractionated (MBbl/d) (b)	574		550
NGLs transported-distribution lines (MBbl/d) (a)	550		474
Average Conway-to-Mont Belvieu OPIS price differential - ethane in ethane/propane mix ($/gallon)	$	0.03	$	0.03

(a) - Includes volumes for consolidated entities only.

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

NGLs transported on gathering lines and NGLs fractionated increased for the three months ended March 31, 2017, compared with the same period in 2016, due to increased volumes from new plant connections primarily in the Williston Basin, increased ethane recovery and increased Mid-Continent volumes gathered from the STACK and SCOOP areas. The increase in NGLs transported on gathering lines was offset partially by decreased volumes gathered from the Barnett Shale.

While the volume of ethane recovered increased for the three months ended March 31, 2017, compared with the same period in 2016, a portion of the fees associated with those volumes gathered and fractionated was previously being earned under contracts with minimum volume obligations.

NGLs transported on distribution lines increased for the three months ended March 31, 2017, compared with the same period in 2016, due primarily to higher fractionated volumes as discussed above and due to increased volumes transported for our optimization activities.

Natural Gas Pipelines

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

Interstate Pipelines - Our interstate pipelines are regulated by the FERC and are located in North Dakota, Minnesota, Wisconsin, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New Mexico. Our interstate pipeline companies include:

• Midwestern Gas Transmission, which is a bidirectional system that interconnects with Tennessee Gas Transmission Company’s pipeline near Portland, Tennessee, and with several interstate pipelines that have access to both the Utica Shale and the Marcellus Shale at the Chicago Hub near Joliet, Illinois;

• Viking Gas Transmission, which is a bidirectional system that interconnects with a TransCanada Corporation pipeline at the United States border near Emerson, Canada, and ANR Pipeline Company near Marshfield, Wisconsin;

• Guardian Pipeline, which interconnects with several pipelines at the Chicago Hub near Joliet, Illinois, and with local natural gas distribution companies in Wisconsin; and

• OkTex Pipeline, which has interconnections with several pipelines in Oklahoma, Texas and New Mexico.

Intrastate Pipelines - Our intrastate natural gas pipeline assets in Oklahoma transport natural gas through the state and have access to the major natural gas production areas in the Mid-Continent region, which include the STACK and SCOOP areas in the Anadarko Basin and the Cana-Woodford Shale, Woodford Shale, Springer Shale, Meramec, Granite Wash and Mississippian Lime formations. Our intrastate natural gas pipeline assets in Oklahoma serve end-use markets, such as local distribution companies and power generation companies. In Texas, our intrastate natural gas pipelines are connected to the major natural gas producing formations in the Texas Panhandle, including the Granite Wash formation and Delaware, Cline and Midland producing formations in the Permian Basin. These pipelines are capable of transporting natural gas throughout the western portion of Texas, including the Waha Hub where other pipelines may be accessed for transportation to western markets, exports to Mexico, the Houston Ship Channel market to the east and the Mid-Continent market to the north. Our intrastate natural gas pipeline assets also have access to the Hugoton and Central Kansas Uplift Basins in Kansas.

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Transportation Rates - Our transportation contracts for our regulated natural gas services are based upon rates stated in the respective tariffs. The tariffs provide both the general terms and conditions for the facilities and the maximum allowed rates customers can be charged by type of service, which may be discounted to meet competition if necessary. The rates are established at FERC or the appropriate state jurisdictional agencies. Our earnings are primarily fee-based from the following types of services:

• Firm service - Customers reserve a fixed quantity of pipeline capacity for a specified period of time, which obligates the customer to pay regardless of usage. Under this type of contract, the customer pays a monthly fixed fee and incremental fees, known as commodity charges, which are based on the actual volumes of natural gas they transport or store. In addition, we may retain a percentage of fuel in-kind based on the volumes of natural gas transported. Under the firm service contract, the customer generally is guaranteed access to the capacity they reserve.

• Interruptible service - Under interruptible service transportation agreements, the customer may utilize available capacity after firm service requests are satisfied. The customer is not guaranteed use of our pipelines unless excess capacity is available. Customers typically are assessed fees, such as a commodity charge, and we may retain a specified volume of natural gas in-kind based on their actual usage.

Storage - We own natural gas storage facilities located in Texas and Oklahoma that are connected to our intrastate natural gas pipelines. We also have underground natural gas storage facilities in Kansas. In Texas and Kansas, natural gas storage operations may be regulated by the state in which the facility operates and by the FERC for certain types of services. In Oklahoma, natural gas storage operations are not subject to rate regulation by the state and have market-based rate authority from the FERC for certain types of services.

Storage Rates - Our earnings are primarily fee-based from the following types of services:

• Firm service - Customers reserve a specific quantity of storage capacity, including injection and withdrawal rights, and generally pay fixed fees based on the quantity of capacity reserved plus an injection and withdrawal fee. Firm storage contracts typically have terms longer than one year.

• Park-and-loan service - An interruptible service offered to customers providing the ability to park (inject) or loan (withdraw) natural gas into or out of our storage, typically for monthly or seasonal terms. Customers reserve the right to park or loan natural gas based on a specified quantity, including injection and withdrawal rights when capacity is available.

Growth Projects - The WesTex pipeline expansion is a wholly owned project. Roadrunner is a 50 percent-owned joint venture equity-method investment project.

WesTex Pipeline Expansion - In October 2016, the WesTex pipeline expansion was completed for approximately $55 million, excluding capitalized interest, ahead of original schedule and below cost estimates. This expansion increased the pipeline capacity by 260 MMcf/d.

Roadrunner - Phase I and Phase II of the Roadrunner pipeline were completed in March and October 2016, respectively, for total project costs of approximately $200 million and $210 million, respectively, excluding capitalized interest. Phase II of Roadrunner was completed ahead of original schedule and below cost estimates. The current capacity of Roadrunner is 570 MMcf/d. Construction of Phase III of Roadrunner is planned for completion in 2019, which is expected to increase capacity by 70 MMcf/d and have total project costs of approximately $30 million to $40 million.

We made contributions of approximately $4.4 million to Roadrunner in the three months ended March 31, 2017. During the three months ended March 31, 2016, we made no contributions to Roadrunner.

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

		Three Months Ended						Three Months
		March 31,						2017 vs. 2016
Financial Results		2017			2016			Increase (Decrease)
	(Millions of dollars)
Transportation revenues		$	82.0		$	67.8		$	14.2		21	%
Storage revenues		14.2			15.5			(1.3		)	(8	%)
Natural gas sales and other revenues		10.6			2.7			7.9			*
Cost of sales and fuel (exclusive of depreciation and items shown separately below)		(16.6		)	(3.9		)	12.7			*
Operating costs		(31.8		)	(27.5		)	4.3			16	%
Equity in net earnings from investments		23.2			16.8			6.4			38	%
Other		1.4			2.9			(1.5		)	(52	%)
Adjusted EBITDA		$	83.0		$	74.3		$	8.7		12	%
Capital expenditures		$	25.0		$	17.9		$	7.1		40	%

* Percentage change is greater than 100 percent.

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

Due to the nature of our business, changes in commodity prices and sales volumes affect natural gas sales and cost of sales and fuel and therefore the impact is largely offset between these line items.

Adjusted EBITDA increased $8.7 million for the three months ended March 31, 2017, compared with the same period in 2016, primarily as a result of the following:

• an increase of $9.9 million from higher transportation services due primarily to increased firm demand charge contracted capacity; and

• an increase of $6.4 million in equity earnings due primarily to higher firm transportation revenues on Roadrunner; offset partially by

• an increase of $4.3 million in operating costs due primarily to higher ad valorem taxes and employee-related costs; and

• a decrease of $3.0 million due to gains on sales of excess natural gas in storage in the first quarter 2016.

Capital expenditures increased for the three months ended March 31, 2017, compared with the same period in 2016, due primarily to the timing of maintenance projects.

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

	Three Months Ended
	March 31,
Operating Information (a)	2017			2016
Natural gas transportation capacity contracted (MDth/d)	6,757			6,156
Transportation capacity subscribed	97		%	93		%
Average natural gas price
Mid-Continent region ($/MMBtu)	$	2.76		$	1.82

(a) - Includes volumes for consolidated entities only.

Our natural gas pipelines primarily serve end users, such as natural gas distribution and electric-generation companies, that require natural gas to operate their businesses regardless of location price differentials. The development of shale and other resource areas has continued to increase available natural gas supply, and we expect producers to demand incremental transportation services in the future as additional supply is developed. The abundance of natural gas supply and regulations on emissions from coal-fired electric-generation plants may also increase the demand for our services from electric-generation companies as they convert to a natural gas fuel source. Overall, our contracted transportation capacity and fee-based earnings in this segment increased in connection with the October 2016 completion of our WesTex pipeline expansion.

Northern Border Pipeline, in which we have a 50 percent ownership interest, has contracted substantially all of its long-haul transportation capacity through the first quarter 2018.

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

Adjusted EBITDA

Adjusted EBITDA is a non-GAAP measure of the Partnership’s 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 and other noncash items. We believe this non-GAAP financial measure is useful to investors because it and similar measures are used by many companies in our industry as a measurement of financial performance and is commonly employed by financial analysts and others to evaluate our financial performance and to compare financial performance among companies in our industry. Adjusted EBITDA should not be considered an alternative to net income, earnings per unit or any other measure of financial performance presented in accordance with GAAP. Additionally, this calculation may not be comparable with similarly titled measures of other companies.

A reconciliation of net income, the nearest comparable GAAP financial performance measure, to adjusted EBITDA for the three months ended March 31, 2017 and 2016, is as follows:

	Three Months Ended
	March 31,
	2017			2016
Reconciliation of net income to adjusted EBITDA	(Thousands of dollars)
Net income	$	270,026		$	256,286
Add:
Interest expense, net of capitalized interest	90,707			92,555
Depreciation and amortization	98,626			93,736
Income taxes	3,837			2,028
Other noncash items and equity AFUDC	958			(19		)
Adjusted EBITDA	$	464,154		$	444,586
Reconciliation of segment adjusted EBITDA to adjusted EBITDA
Segment adjusted EBITDA:
Natural Gas Gathering and Processing	$	103,967		$	100,035
Natural Gas Liquids	278,229			270,169
Natural Gas Pipelines	82,958			74,339
Total segment adjusted EBITDA	465,154			444,543
Other	(1,000		)	43
Adjusted EBITDA	$	464,154		$	444,586

CONTINGENCIES

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

LIQUIDITY AND CAPITAL RESOURCES

General -We rely primarily on operating cash flows, commercial paper, bank credit facilities, debt issuances and the issuance of common units for our liquidity and capital resources requirements. We fund our operating expenses, debt service and cash distributions to our limited partners and general partner primarily with operating cash flows. To the extent operating cash flows are not sufficient to fund our cash distributions, we may utilize short- and long-term debt and issuances of equity, as necessary. Capital expenditures are funded by operating cash flows, short- and long-term debt and issuances of equity. Our ability to continue to access capital markets for debt and equity financing under reasonable terms depends on our financial condition, credit ratings and market conditions. While lower commodity prices and industry uncertainty may result in increased financing costs, we believe we have secured sufficient access to the financial resources and liquidity necessary to meet our requirements for working capital, debt service payments and capital expenditures. We believe that our available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity price volatility. We may access the capital

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markets to issue debt or equity securities in 2017 as we consider prudent to provide liquidity for new capital projects, to refinance existing debt, to maintain investment-grade credit ratings or for other partnership purposes.

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 D of the Notes to Consolidated Financial Statements in this Quarterly Report.

We have no guarantees of debt or other similar commitments to unaffiliated parties.

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

Short-term Liquidity - Our principal sources of short-term liquidity consist of cash generated from operating activities, distributions received from our equity-method investments and proceeds from our commercial paper program and our Partnership Credit Agreement.

In January 2016, we extended the term of our Partnership Credit Agreement by one year to January 2020. Our Partnership Credit Agreement is a $2.4 billion revolving credit facility and includes a $100 million sublimit for the issuance of standby letters of credit and a $150 million swingline sublimit. Our Partnership Credit Agreement is available for general partnership purposes, and based on our current credit ratings, borrowings, if any, will accrue interest at LIBOR plus 117.5 basis points. Amounts outstanding under our commercial paper program reduce the borrowing capacity under our Partnership Credit Agreement. Our Partnership Credit Agreement is guaranteed fully and unconditionally by the Intermediate Partnership.

We had working capital (defined as current assets less current liabilities) deficits of $1.6 billion and $1.7 billion as of March 31, 2017, and December 31, 2016, respectively. Although working capital is influenced by several factors, including, among other things, (i) the timing of (a) scheduled debt payments, (b) the collection and payment of accounts receivable and payable, and (c) equity and debt issuances, and (ii) the volume and cost of inventory and commodity imbalances, our working capital deficit at March 31, 2017, and at December 31, 2016, was driven primarily by current maturities of long-term debt and short-term borrowings. We may have working capital deficits in future periods as we continue to finance our capital-growth projects and repay long-term debt, often initially with short-term borrowings. Our decision to utilize short-term borrowings rather than long-term debt, due to more favorable interest rates, contributes to our working capital deficit. We do not expect this working capital deficit to have an adverse impact to our cash flows or operations.

At March 31, 2017, we had $1.3 billion of commercial paper outstanding, $14 million of letters of credit issued and no borrowings outstanding under our Partnership Credit Agreement. At March 31, 2017, we had approximately $8.5 million of cash and cash equivalents and approximately $1.1 billion of borrowing capacity under the Partnership Credit Agreement.

For additional information on our Partnership Credit Agreement, see Note E of the Notes to Consolidated Financial Statements in this Quarterly Report.

Currently, borrowings under our Partnership Credit Agreement, Term Loan Agreement and our senior notes are nonrecourse to ONEOK, and ONEOK does not guarantee our debt, commercial paper or other similar commitments. Following the completion of the Merger Transaction described in Note B of the Notes to Consolidated Financial Statements in this Quarterly Report, we, ONEOK and the Intermediate Partnership expect to issue, to the extent not already in place, guarantees of the indebtedness of ONEOK and ONEOK Partners.

In April 2017, ONEOK entered into the 2017 Credit Agreement with a syndicate of banks, to replace the existing ONEOK credit facility and the Partnership Credit Agreement, effective upon the closing of the Merger Transaction described in Note B and the termination of the existing ONEOK credit facility and the Partnership Credit Agreement. ONEOK’s obligations under the 2017 Credit Agreement will be guaranteed by ONEOK Partners and the Intermediate Partnership.

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 common units or long-term notes. Other options to obtain financing include, but

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are not limited to, loans from financial institutions, issuance of convertible debt securities, asset securitization and the sale and lease-back of facilities.

Our ability to obtain financing is subject to changes in the debt and equity markets, and there is no assurance we will be able or willing to access the public or private markets in the future. We may choose to meet our cash requirements by utilizing some combination of cash flows from operations, borrowing under our commercial paper program or our Partnership Credit Agreement, altering the timing of controllable expenditures, restricting future acquisitions and capital projects, selling assets or pursuing other debt or equity financing alternatives. Some of these alternatives could result in higher costs or negatively affect our credit ratings, among other factors. Based on our investment-grade credit ratings, general financial condition and expectations regarding our future earnings and projected cash flows, we expect to be able to meet our cash requirements and maintain investment-grade credit ratings.

Debt issuances and maturities - In the first quarter 2016, we entered into the $1.0 billion Term Loan Agreement with a syndicate of banks and drew the full $1.0 billion available under the agreement. We used the proceeds to repay $650 million of senior notes, which matured in February 2016, to repay amounts outstanding under our commercial paper program and for general partnership purposes. The Term Loan Agreement matures in January 2019 and bears interest at LIBOR plus 130 basis points based on our current credit ratings. The Term Loan Agreement contains an option, which may be exercised up to two times, to extend the term of the loan, in each case, for an additional one-year term subject to approval of the banks. The Term Loan Agreement allows prepayment of all or any portion outstanding, without penalty or premium, and contains substantially the same covenants as those contained in our Partnership Credit Agreement. In April 2017, we entered into the first amendment to the Term Loan Agreement which, among other things, will add ONEOK as a guarantor to the Term Loan Agreement effective upon the closing of the Merger Transaction described in Note B.

We expect to repay our $400 million, 2.0 percent senior notes due October 1, 2017, with a combination of cash on hand and short-term borrowings.

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

Equity issuances - We have an “at-the-market” equity program for the offer and sale from time to time of our common units, up to an aggregate amount of $650 million. The program allows us to offer and sell our common units at prices we deem appropriate through a sales agent. Sales of common units are made by means of ordinary brokers’ transactions on the NYSE, in block transactions or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common units under the program. At March 31, 2017, we had approximately $138 million of registered common units available for issuance through our “at-the-market” equity program.

During the three months ended March 31, 2017, and the year ended December 31, 2016, no common units were sold through our “at-the-market” equity program.

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

Capital expenditures, excluding AFUDC and capitalized interest, were $112.6 million and $195.9 million for the three months ended March 31, 2017 and 2016, respectively.

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The following table sets forth our 2017 projected growth and maintenance capital expenditures, excluding AFUDC and capitalized interest:

2017 Projected Capital Expenditures	Growth	Maintenance	Total
	(Millions of dollars)
Natural Gas Gathering and Processing	$170-$210	$45-$50	$215-$260
Natural Gas Liquids	$160-$200	$55-$60	$215-$260
Natural Gas Pipelines	$50-$70	$30-$35	$80-$105
Other	—	$10-$15	$10-$15
Total projected capital expenditures	$380-$480	$140-$160	$520-$640

Credit Ratings - Our long-term debt credit ratings as of April 24, 2017, are shown in the table below:

Rating Agency	Rating
Moody’s	Baa2
S&P	BBB

Our commercial paper program is rated Prime-2 by Moody’s and A-2 by S&P. Moody’s and S&P affirmed our current credit ratings and revised our outlook to stable from negative in October and December 2016, respectively, citing our considerable reduction of commodity price risk and focus on growth opportunities within our operating footprint. In February 2017, in conjunction with the announcement of the Merger Transaction, S&P affirmed our credit ratings and outlook, and Moody’s placed our credit ratings under review for downgrade.

Our credit ratings, which are investment-grade, may be affected by a material change in our financial ratios or a material event affecting our business and industry. The most common criteria for assessment of our credit ratings are the debt-to-EBITDA ratio, interest coverage, business risk profile and liquidity. If our credit ratings were downgraded, our cost to borrow funds under the Term Loan Agreement, our Partnership Credit Agreement and our commercial paper program would increase, and a potential loss of access to the commercial paper market could occur. In the event that we are unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we would continue to have access to our Partnership Credit Agreement, which expires in January 2020. An adverse credit rating change alone is not a default under our Partnership 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.

Cash Distributions - We distribute 100 percent of our available cash, as defined in our Partnership Agreement, that generally consists of all cash receipts less adjustments for cash disbursements and net change to reserves, to our general and limited partners. Distributions are allocated to our general partner and limited partners according to their partnership percentages of 2 percent and 98 percent, respectively. The effect of any incremental allocations for incentive distributions to our general partner is calculated after the allocation to the general partner’s partnership interest and before the allocation to the limited partners.

For the three months ended March 31, 2017 and 2016, our cash distributions exceeded our cash flows from operations and, as a result, we utilized cash from operations, our commercial paper program and distributions received from our equity-method investments to fund our cash distributions, short-term liquidity needs and capital projects. We expect increases in cash flows from operations in the remainder of 2017, compared with the first quarter of 2017, due primarily to new plant connections, increased ethane recovery and new well connections that we expect will provide higher volumes in our Natural Gas Gathering and Processing and Natural Gas Liquids segments. We also experienced severe winter weather in the Williston Basin in the first quarter 2017, which had an unfavorable impact on our volumes and cash flows from operations.

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The following table sets forth cash distributions paid, including our general partner’s incentive distribution rights, during the periods indicated:

	Three Months Ended
	March 31,
	2017		2016
	(Millions of dollars)
Common unitholders	$	168.1	$	168.1
Class B unitholders	57.7		57.7
General partner	107.2		107.2
Noncontrolling interests	1.2		2.5
Total cash distributions paid	$	334.2	$	335.5

In the three months ended March 31, 2017 and 2016, cash distributions paid to our general partner included incentive distributions of $100.5 million and $100.5 million, respectively.

In April 2017, our general partner declared a cash distribution of $0.79 per unit ($3.16 per unit on an annualized basis) for the first quarter 2017, which will be paid on May 15, 2017, to unitholders of record at the close of business on May 1, 2017.

Additional information about our cash distributions is included in “Cash Distribution Policy” under Part II, Item 5, Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities, in our Annual Report.

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 include depreciation and amortization, allowance for equity funds used during construction, gain or loss on sale of assets, deferred income taxes, equity in net earnings from investments, distributions received from unconsolidated affiliates, 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						2017 vs. 2016
	March 31,						Favorable (Unfavorable)
	2017			2016
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	280.3		$	266.3		$	14.0
Investing activities	(109.4		)	(169.5		)	60.1
Financing activities	(162.8		)	(92.0		)	(70.8		)
Change in cash and cash equivalents	8.1			4.8			3.3
Cash and cash equivalents at beginning of period	0.4			5.1			(4.7		)
Cash and cash equivalents at end of period	$	8.5		$	9.9		$	(1.4	)

Operating Cash Flows - Operating cash flows are affected by earnings from our business activities. 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.

Cash flows from operating activities, before changes in operating assets and liabilities, were $371.6 million for the three months ended March 31, 2017, compared with $349.8 million for the same period in 2016. The increase is due primarily to higher fees resulting from contract restructuring in our Natural Gas Gathering and Processing segment, higher transportation services due to increased firm demand charge contracted capacity in our Natural Gas Pipelines segment and increased optimization and marketing activities in our Natural Gas Liquids segment resulting from wider location price differentials,

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offset partially by lower volumes due to severe winter weather in our Natural Gas Gathering and Processing segment as discussed in “Financial Results and Operating Information.”

The changes in operating assets and liabilities decreased operating cash flows $91.3 million for the three months ended March 31, 2017, compared with a decrease of $83.5 million for the same period in 2016. This change is due primarily to the change in accounts receivable, accounts payable, and other accruals and deferrals resulting from the timing of receipt of cash from customers and payments to vendors, suppliers and other third parties, the change in natural gas and NGLs in storage, which vary from period to period and vary with changes in commodity prices, and the change in risk-management assets and liabilities related to our interest-rate swaps.

Investing Cash Flows - Cash used in investing activities decreased to $109.4 million for the three months ended March 31, 2017, compared with $169.5 million for the same period in 2016, due primarily to projects placed in service in 2016 and fewer well connections in our Natural Gas Gathering and Processing segment due to the impact of severe winter weather in the Williston Basin in the first quarter 2017.

Financing Cash Flows - Cash used in financing activities increased to $162.8 million for the three months ended March 31, 2017, compared with $92.0 million for the same period in 2016, due primarily to the impact of drawing on our Term Loan Agreement in the first quarter 2016 to repay long-term debt and borrowings under our commercial paper program.

REGULATORY, ENVIRONMENTAL AND SAFETY MATTERS

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

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

IMPACT OF NEW ACCOUNTING STANDARDS

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

ESTIMATES AND CRITICAL ACCOUNTING POLICIES

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

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

FORWARD-LOOKING STATEMENTS

Some of the statements contained and incorporated in this Quarterly Report are forward-looking statements as defined under federal securities laws. The forward-looking statements relate to our anticipated financial performance (including projected operating income, net income, capital expenditures, cash flow and projected levels of distributions), liquidity, management’s

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plans and objectives for our future growth projects and other future operations (including plans to construct additional natural gas and natural gas liquids pipelines and processing facilities and related cost estimates), our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under federal securities legislation and other applicable laws. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

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

One should not place undue reliance on forward-looking statements. 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 ability to obtain the requisite approvals from our unitholders and ONEOK’s shareholders relating to the Merger Transaction;

• the risk that we or ONEOK may be unable to obtain governmental and regulatory approvals required for the Merger Transaction, if any, or required governmental and regulatory approvals, if any, may delay the Merger Transaction or result in the imposition of conditions that could cause the parties to abandon the Merger Transaction;

• the risk that a condition to closing of the Merger Transaction may not be satisfied;

• the timing to consummate the Merger Transaction;

• the risk that cost savings, tax benefits and any other synergies from the Merger Transaction may not be fully realized or may take longer to realize than expected;

• disruption from the Merger Transaction may make it more difficult to maintain relationships with customers, employees or suppliers;

• the possible diversion of management time on Merger Transaction-related issues;

• the impact and outcome of pending and future litigation, including litigation, if any, relating to the Merger Transaction;

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

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

• the capital intensive nature of our businesses;

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

• our ability to make cost-saving changes in operations;

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

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

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

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

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

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

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

• conflicts of interest between us, our general partner, ONEOK Partners GP, and related parties of ONEOK Partners GP;

• 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;

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

• actions by rating agencies concerning the credit ratings of us or the parent of our general partner;

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

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

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

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

• the impact and outcome of pending and future litigation;

• the 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 Canadian and United States natural gas and crude oil; and

– availability of additional storage capacity;

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

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

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

• the mechanical integrity of facilities operated;

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

• our ability to control operating costs;

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

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

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

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

• the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions in the Middle East and elsewhere;

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

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

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

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

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

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

• the impact of potential impairment charges;

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

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

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

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future results. These and other risks are described in greater detail in Part I, Item 1A, Risk Factors, in our most recent Annual Report on Form 10-K 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.oneokpartners.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

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any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

COMMODITY PRICE RISK

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

We are exposed to basis risk between the various production and market locations where we receive and sell commodities. Although our businesses are predominately fee-based, in our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk as a result of retaining a portion of the commodity sales proceeds associated with our POP with fee contracts. We have restructured a portion of our POP with fee contracts to include significantly higher fees, which reduces our equity volumes and the related commodity price exposure. However, under certain POP with fee contracts, our fee revenues may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds.

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, 2017
	Volumes Hedged	Average Price			Percentage Hedged
NGLs - excluding ethane (MBbl/d) - Conway/Mont Belvieu	8.0	$	0.51	/ gallon	89%
Condensate (MBbl/d) - WTI-NYMEX	1.8	$	44.88	/ Bbl	78%
Natural gas (BBtu/d) - NYMEX and basis	73.0	$	2.63	/ MMBtu	97%

	Year Ending December 31, 2018
	Volumes Hedged	Average Price			Percentage Hedged
NGLs - excluding ethane (MBbl/d) - Conway/Mont Belvieu	1.9	$	0.68	/ gallon	22%
Condensate (MBbl/d) - WTI-NYMEX	0.6	$	56.80	/ Bbl	25%
Natural gas (BBtu/d) - NYMEX and basis	49.7	$	2.80	/ MMBtu	74%

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, 2017. Condensate sales are typically based on the price of crude oil. We estimate the following for our forecasted equity volumes, including the effects of hedging information set forth above, and assuming normal operating conditions:

• a $0.01 per-gallon change in the composite price of NGLs would change adjusted EBITDA for the nine months ending December 31, 2017, and for the year ending December 31, 2018, by approximately $0.3 million and $1.9 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, 2017, and for the year ending December 31, 2018, by approximately $0.3 million and $0.8 million, respectively; and

• a $0.10 per-MMBtu change in the price of residue natural gas would change adjusted EBITDA for the nine months ending December 31, 2017, and for the year ending December 31, 2018, by approximately $0.1 million and $0.6 million, respectively.

These estimates do not include any 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.

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The following tables set forth hedging information related to purchased put options to reduce commodity price sensitivity associated with certain POP with fee contracts:

	Nine Months Ending December 31, 2017
	Volumes Hedged	Average Strike Price			Fair Value Asset at March 31, 2017
					(Millions of dollars)
Natural gas (BBtu/d) - NYMEX	147.3	$	2.47	/ MMBtu	$	0.8

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

INTEREST-RATE RISK

We are exposed to interest-rate risk through our Partnership Credit Agreement, commercial paper program, Term Loan Agreement and long-term debt issuances. Future increases in LIBOR, corporate commercial paper rates or investment-grade corporate bond rates could expose us to increased interest costs on future borrowings. We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts. As of March 31, 2017, and December 31, 2016, we had interest-rate swaps with notional amounts totaling $1 billion to hedge the variability of our LIBOR-based interest payments and forward-starting interest-rate swaps with notional amounts totaling $1.2 billion to hedge the variability of interest payments on a portion of our forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. All of our interest-rate swaps are designated as cash flow hedges. At March 31, 2017, we had derivative assets of $47.9 million and derivative liabilities of $11.3 million related to these interest-rate swaps. At December 31, 2016, we had derivative assets of $47.5 million and derivative liabilities of $12.8 million related to these interest-rate swaps.

See Note D 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 to our Natural Gas Gathering and Processing segment’s commodity sales, our Natural Gas Liquids segment’s marketing activities and our Natural Gas Pipelines segment’s storage activities may be impacted by the low commodity price environment and could experience financial problems, which could result in nonpayment and/or nonperformance, which could adversely impact our results of operations.

Customer concentration - For the three months ended March 31, 2017, no single customer represented more than 10 percent of our consolidated revenues and only 24 customers individually represented one percent or more of our consolidated revenues, the majority of which are investment-grade customers, as rated by S&P, Moody’s or our comparable internal ratings, or secured by letters of credit or other collateral.

Natural Gas Gathering and Processing - Our Natural Gas Gathering and Processing segment’s customers are crude oil and natural gas producers, which include both large integrated and independent exploration and production companies. We are not typically exposed to material credit risk with producers under POP with fee contracts as we sell the commodities and remit a portion of the sales proceeds back to the producer customer. For the three months ended March 31, 2017 and 2016, approximately 99 percent of the downstream commodity sales in our Natural Gas Gathering and Processing segment were made to investment-grade customers, as rated by S&P, Moody’s or our comparable internal ratings, or were secured by letters of credit or other collateral.

Natural Gas Liquids - Our Natural Gas Liquids segment’s customers are primarily NGL and natural gas gathering and processing companies; large integrated and independent crude oil and natural gas production companies; propane distributors; ethanol producers; and petrochemical, refining and NGL marketing companies. We earn fee-based revenue from NGL and natural gas gathering and processing customers and natural gas liquids pipeline transportation customers. We are not typically exposed to material credit risk on the majority of our exchange services fee revenues, as we purchase NGLs from our gathering and processing customers and deduct our fee from the amounts we remit. We also earn sales revenue on the downstream sales of NGL products. For the three months ended March 31, 2017 and 2016, approximately 80 percent of our commodity sales were made to investment-grade customers, as rated by S&P, Moody’s or our comparable internal ratings, or were secured by

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letters of credit or other collateral. In addition, the majority of our Natural Gas Liquids segment’s pipeline tariffs provide us the ability to require security from shippers.

Natural Gas Pipelines - Our Natural Gas Pipelines segment’s customers are primarily local natural gas distribution companies, electric-generation facilities, large industrial companies, municipalities, irrigation customers and marketing companies. For the three months ended March 31, 2017 and 2016, approximately 85 percent of our revenues in this segment were from investment-grade customers, as rated by S&P, Moody’s or our comparable internal ratings, or were secured by letters of credit or other collateral. In addition, the majority of our Natural Gas Pipelines segment’s pipeline tariffs provide us the ability to require security from shippers.

ITEM 4. CONTROLS AND PROCEDURES

Quarterly Evaluation of Disclosure Controls and Procedures - The Chief Executive Officer (Principal Executive Officer) and the Chief Financial Officer (Principal Financial Officer) of ONEOK Partners GP, our general partner, who are the equivalent of our principal executive and principal financial officers, respectively, have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report based on the evaluation of the controls and procedures required by Rule 13a-15(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, 2017, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Additional information about our legal proceedings is included in Note K of the Notes to Consolidated Financial Statements in this Quarterly Report and under Part I, Item 3, Legal Proceedings, 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 carefully consider the discussion of risks and the other information included or incorporated by reference in this Quarterly Report, including “Forward-Looking Statements,” which are included in Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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

Not applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

Not applicable.

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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

2.0 Agreement and Plan of Merger, dated as of January 31, 2017, by and among ONEOK, Inc., New Holdings Subsidiary, LLC, ONEOK Partners, L.P. and ONEOK Partners GP, L.L.C. (incorporated by reference from Exhibit 2.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed February 1, 2017 (File No. 1-12202)).

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

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

101.INS XBRL Instance Document.

101.SCH XBRL Taxonomy Extension Schema Document.

101.CAL XBRL Taxonomy Calculation Linkbase Document.

101.DEF XBRL Taxonomy Extension Definitions Document.

101.LAB XBRL Taxonomy Label Linkbase Document.

101.PRE XBRL Taxonomy Presentation Linkbase Document.

Attached as Exhibit 101 to this Quarterly Report are the following XBRL-related documents: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three months ended March 31, 2017 and 2016; (iii) Consolidated Statements of Comprehensive Income for the three months ended March 31, 2017 and 2016; (iv) Consolidated Balance Sheets at March 31, 2017, and December 31, 2016; (v) Consolidated Statements of Cash Flows for the three months ended March 31, 2017 and 2016; (vi) Consolidated Statements of Changes in Equity for the three months ended March 31, 2017 and 2016; and (vii) Notes to Consolidated Financial Statements. We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report.

The total amount of securities of the Partnership authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10 percent of the total assets of the Partnership and its subsidiaries on a consolidated basis. The Partnership agrees, upon request of the SEC, to furnish copies of any or all of such instruments to the SEC.

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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 Partners, L.P.
	By:	ONEOK Partners GP, L.L.C., its General Partner
Date: May 3, 2017		By:	/s/ Derek S. Reiners
			Derek S. Reiners
			Senior Vice President,
			Chief Financial Officer and Treasurer
			(Signing on behalf of the Registrant)

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