ONEOK Partners LP - FORM 10-Q

Attached files

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EX-32.1 - OKS CERTIFICATION OF SPENCER SECTION 906 - ONEOK Partners LP	oksq32016exhibit321.htm
EX-32.2 - OKS CERTIFICATION OF REINERS SECTION 906 - ONEOK Partners LP	oksq32016exhibit322.htm
EX-31.2 - OKS CERTIFICATION OF REINERS SECTION 302 - ONEOK Partners LP	oksq32016exhibit312.htm
EX-31.1 - OKS CERTIFICATION OF SPENCER SECTION 302 - ONEOK Partners LP	oksq32016exhibit311.htm

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2016.

___ 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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer X Accelerated filer __ Non-accelerated filer __ Smaller reporting company__

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 October 24, 2016
Common units		212,837,980 units
Class B units		72,988,252 units

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ONEOK PARTNERS, L.P.

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Part I.	Financial Information	Page No.
Item 1.	Financial Statements (Unaudited)	6
	Consolidated Statements of Income - Three and Nine Months Ended September 30, 2016 and 2015	6
	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2016 and 2015	7
	Consolidated Balance Sheets - September 30, 2016, and December 31, 2015	8
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2016 and 2015	9
	Consolidated Statements of Changes in Equity - Nine Months Ended September 30, 2016 and 2015	10
	Notes to Consolidated Financial Statements	12
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	59
Item 4.	Controls and Procedures	61
Part II.	Other Information	61
Item 1.	Legal Proceedings	61
Item 1A.	Risk Factors	61
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	61
Item 3.	Defaults Upon Senior Securities	61
Item 4.	Mine Safety Disclosures	62
Item 5.	Other Information	62
Item 6.	Exhibits	62
Signature		63

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:



AFUDC	Allowance for funds used during construction
Annual Report	Annual Report on Form 10-K for the year ended December 31, 2015
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
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
Intermediate Partnership	ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary of ONEOK Partners, L.P.
LIBOR	London Interbank Offered Rate
MBbl/d	Thousand barrels per day
MDth/d	Thousand dekatherms per day
MMBbl	Million barrels
MMBtu	Million British thermal units
MMcf/d	Million cubic feet per day
Moody’s	Moody’s Investors Service, Inc.
NGL(s)	Natural gas liquid(s)
NGL products	Marketable natural gas liquid purity products, such as ethane, ethane/propane mix, propane, iso-butane, normal butane and natural gasoline
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
ONEOK	ONEOK, Inc.
ONEOK Partners	ONEOK Partners, L.P.
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
Quarterly Report(s)	Quarterly Report(s) on Form 10-Q
Roadrunner	Roadrunner Gas Transmission, LLC
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
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						Nine Months Ended
	September 30,						September 30,
(Unaudited)	2016			2015			2016			2015
	(Thousands of dollars, except per unit amounts)
Revenues
Commodity sales	$	1,840,523		$	1,484,350		$	4,757,306		$	4,642,320
Services	516,868			414,068			1,507,624			1,188,364
Total revenues	2,357,391			1,898,418			6,264,930			5,830,684
Cost of sales and fuel (exclusive of items shown separately below)	1,751,593			1,360,809			4,474,654			4,307,766
Operations and maintenance	159,085			145,933			465,628			444,185
Depreciation and amortization	97,802			87,517			290,045			259,563
General taxes	18,314			16,158			63,889			62,677
(Gain) loss on sale of assets	(5,745		)	443			(9,476		)	327
Operating income	336,342			287,558			980,190			756,166
Equity in net earnings from investments (Note I)	35,155			32,244			100,441			93,205
Allowance for equity funds used during construction	—			177			208			1,718
Other income	825			41			1,522			106
Other expense	(709		)	(3,845		)	(2,282		)	(3,941		)
Interest expense (net of capitalized interest of $3,806, $8,851, $9,265 and $26,008, respectively)	(92,521		)	(86,666		)	(278,339		)	(253,867		)
Income before income taxes	279,092			229,509			801,740			593,387
Income tax (expense) benefit	(3,681		)	156			(8,079		)	(5,080		)
Net income	275,411			229,665			793,661			588,307
Less: Net income attributable to noncontrolling interests	1,103			2,704			4,368			5,982
Net income attributable to ONEOK Partners, L.P.	$	274,308		$	226,961		$	789,293		$	582,325
Limited partners’ interest in net income:
Net income attributable to ONEOK Partners, L.P.	$	274,308		$	226,961		$	789,293		$	582,325
General partner’s interest in net income	(106,024		)	(105,078		)	(317,400		)	(293,868		)
Limited partners’ interest in net income	$	168,284		$	121,883		$	471,893		$	288,457
Limited partners’ net income per unit, basic and diluted (Note H)	$	0.59		$	0.45		$	1.65		$	1.10
Number of units used in computation (thousands)	285,826			272,046			285,826			261,100

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						Nine Months Ended
	September 30,						September 30,
(Unaudited)	2016			2015			2016			2015
	(Thousands of dollars)
Net income	$	275,411		$	229,665		$	793,661		$	588,307
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	8,538			15,949			(98,613		)	21,373
Realized (gains) losses on derivatives recognized in net income	3,017			(19,094		)	(17,787		)	(43,785		)
Other comprehensive income (loss) on investments in unconsolidated affiliates	(708		)	—			(12,071		)	—
Total other comprehensive income (loss)	10,847			(3,145		)	(128,471		)	(22,412		)
Comprehensive income	286,258			226,520			665,190			565,895
Less: Comprehensive income attributable to noncontrolling interests	1,103			2,704			4,368			5,982
Comprehensive income attributable to ONEOK Partners, L.P.	$	285,155		$	223,816		$	660,822		$	559,913

See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	September 30,			December 31,
(Unaudited)	2016			2015
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	5,525		$	5,079
Accounts receivable, net	737,058			593,448
Affiliate receivables	299			7,969
Natural gas and natural gas liquids in storage	217,769			128,084
Commodity imbalances	43,770			38,681
Materials and supplies	81,701			76,696
Other current assets	42,672			33,207
Total current assets	1,128,794			883,164
Property, plant and equipment
Property, plant and equipment	14,718,554			14,307,546
Accumulated depreciation and amortization	2,302,779			2,050,755
Net property, plant and equipment	12,415,775			12,256,791
Investments and other assets
Investments in unconsolidated affiliates	943,390			948,221
Goodwill and intangible assets	815,952			824,877
Other assets	15,647			14,533
Total investments and other assets	1,774,989			1,787,631
Total assets	$	15,319,558		$	14,927,586
Liabilities and equity
Current liabilities
Current maturities of long-term debt (Note E)	$	457,650		$	107,650
Short-term borrowings (Note D)	693,500			546,340
Accounts payable	701,518			605,431
Affiliate payables	19,139			27,137
Commodity imbalances	134,658			74,460
Accrued interest	86,225			102,615
Other current liabilities	193,561			116,667
Total current liabilities	2,286,251			1,580,300
Long-term debt, excluding current maturities (Note E)	6,691,663			6,695,312
Deferred credits and other liabilities	188,254			154,631
Commitments and contingencies (Note K)
Equity (Note F)
ONEOK Partners, L.P. partners’ equity:
General partner	227,150			231,344
Common units: 212,837,980 units issued and outstanding at September 30, 2016, and December 31, 2015	4,861,917			5,014,952
Class B units: 72,988,252 units issued and outstanding at September 30, 2016, and December 31, 2015	1,147,724			1,200,204
Accumulated other comprehensive loss (Note G)	(241,753		)	(113,282		)
Total ONEOK Partners, L.P. partners’ equity	5,995,038			6,333,218
Noncontrolling interests in consolidated subsidiaries	158,352			164,125
Total equity	6,153,390			6,497,343
Total liabilities and equity	$	15,319,558		$	14,927,586

See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Nine Months Ended
	September 30,
(Unaudited)	2016			2015
	(Thousands of dollars)
Operating activities
Net income	$	793,661		$	588,307
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	290,045			259,563
Equity in net earnings from investments	(100,441		)	(93,205		)
Distributions received from unconsolidated affiliates	106,381			92,042
Deferred income taxes	7,573			4,309
Allowance for equity funds used during construction	(208		)	(1,718		)
(Gain) loss on sale of assets	(9,476		)	327
Changes in assets and liabilities:
Accounts receivable	(145,570		)	149,776
Affiliate receivables	7,670			3,789
Natural gas and natural gas liquids in storage	(89,685		)	(8,174		)
Accounts payable	138,450			(182,985		)
Affiliate payables	(7,998		)	(14,788		)
Commodity imbalances, net	55,109			25,728
Accrued interest	(16,390		)	(2,492		)
Risk-management assets and liabilities	(51,329		)	(46,267		)
Other assets and liabilities, net	21,583			(27,186		)
Cash provided by operating activities	999,375			747,026
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	(489,358		)	(928,870		)
Contributions to unconsolidated affiliates	(55,177		)	(27,540		)
Distributions received from unconsolidated affiliates in excess of cumulative earnings	43,018			25,111
Proceeds from sale of assets	19,038			3,171
Other	—			(12,607		)
Cash used in investing activities	(482,479		)	(940,735		)
Financing activities
Cash distributions:
General and limited partners	(999,002		)	(897,474		)
Noncontrolling interests	(6,100		)	(8,192		)
Borrowing (repayment) of short-term borrowings, net	147,160			(768,024		)
Issuance of long-term debt, net of discounts	1,000,000			798,896
Debt financing costs	(2,770		)	(7,676		)
Repayment of long-term debt	(655,738		)	(5,738		)
Issuance of common units, net of issuance costs	—			1,025,660
Contribution from general partner	—			20,990
Cash provided by (used in) financing activities	(516,450		)	158,442
Change in cash and cash equivalents	446			(35,267		)
Cash and cash equivalents at beginning of period	5,079			42,530
Cash and cash equivalents at end of period	$	5,525		$	7,263

See accompanying Notes to Consolidated Financial Statements.

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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, 2016	212,837,980	72,988,252	$	231,344		$	5,014,952
Net income	—	—	317,400			351,391
Other comprehensive income (loss) (Note G)	—	—	—			—
Distributions paid (Note F)	—	—	(321,594		)	(504,426		)
Other	—	—	—			—
September 30, 2016	212,837,980	72,988,252	$	227,150		$	4,861,917



	ONEOK Partners, L.P. Partners’ Equity
(Unaudited)	Common Units	Class B Units	General Partner			Common Units
	(Units)		(Thousands of dollars)
January 1, 2015	180,826,973	72,988,252	$	211,914		$	4,456,372
Net income	—	—	293,868			208,119
Other comprehensive income (loss) (Note G)	—	—	—			—
Issuance of common units (Note F)	32,011,007	—	—			1,023,915
Contribution from general partner (Note F)	—	—	20,990			—
Distributions paid (Note F)	—	—	(288,912		)	(435,580		)
Other	—	—	—			14
September 30, 2015	212,837,980	72,988,252	$	237,860		$	5,252,840

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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 Income (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		120,502			—			4,368			793,661
Other comprehensive income (loss) (Note G)		—			(128,471		)	—			(128,471		)
Distributions paid (Note F)		(172,982		)	—			(6,100		)	(1,005,102		)
Other		—			—			(4,041		)	(4,041		)
September 30, 2016		$	1,147,724		$	(241,753	)	$	158,352		$	6,153,390



	ONEOK Partners, L.P. Partners’ Equity
(Unaudited)		Class B Units			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests in Consolidated Subsidiaries			Total Equity
		(Thousands of dollars)
January 1, 2015		$	1,374,375		$	(91,823	)	$	167,937		$	6,118,775
Net income		80,338			—			5,982			588,307
Other comprehensive income (loss) (Note G)		—			(22,412		)	—			(22,412		)
Issuance of common units (Note F)		—			—			—			1,023,915
Contribution from general partner (Note F)		—			—			—			20,990
Distributions paid (Note F)		(172,982		)	—			(8,192		)	(905,666		)
Other		—			—			(451		)	(437		)
September 30, 2015		$	1,281,731		$	(114,235	)	$	165,276		$	6,823,472

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 2015 year-end consolidated balance sheet data was derived from our audited financial statements but does not include all disclosures required by GAAP. Certain reclassifications have been made in the prior-year financial statements to conform to the current-year presentation. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements in our Annual Report.

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

Goodwill Impairment Test - We assess our goodwill for impairment at least annually on July 1, unless events or changes in circumstances indicate an impairment may have occurred before that time. As the commodity price environment has remained relatively unchanged since 2015, we elected to perform a quantitative assessment, or Step 1 analysis, to test our goodwill for impairment. The assessment included our current commodity price assumptions, expected contractual terms, anticipated operating costs and volume estimates. Our goodwill impairment analysis performed as of July 1, 2016, did not result in an impairment charge nor did our analysis reflect any reporting units at risk. In each reporting unit, the fair value substantially exceeded the carrying value. Subsequent to that date, no event has occurred indicating that the implied fair value of each of our reporting units is less than the carrying value of its net assets.

Recently Issued Accounting Standards Update - 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 2015-16, “Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments”	The standard requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined.	First quarter 2016	There was no impact, but it could impact us in the future if we complete any acquisitions with subsequent measurement period adjustments.
ASU 2015-05, “Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement”	The standard clarifies whether a cloud computing arrangement includes a software license. If it does, the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses; if not, the customer should account for the arrangement as a service contract.	First quarter 2016	The impact of adopting this standard was not material.
ASU 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis”	The standard eliminates the presumption that a general partner should consolidate a limited partnership. It also modifies the evaluation of whether limited partnerships are variable interest entities or voting interest entities and adds requirements that limited partnerships must meet to qualify as voting interest entities.	First quarter 2016	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 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	We do not expect the adoption of this standard to materially impact us.
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	We do not expect the adoption of this standard to materially impact us.
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	We do not expect the adoption of this standard to materially impact us.
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.
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 the impact of this standard on us.
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.


B.	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.

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While many of the contracts in our 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 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.

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



	September 30, 2016
	Level 1			Level 2			Level 3			Total - Gross			Netting (a)			Total - Net (b)
	(Thousands of dollars)
Derivative assets
Commodity contracts
Financial contracts	$	9,051		$	—		$	2,858		$	11,909		$	(7,389	)	$	4,520
Physical contracts	—			—			98			98			—			98
Total derivative assets	$	9,051		$	—		$	2,956		$	12,007		$	(7,389	)	$	4,618
Derivative liabilities
Commodity contracts
Financial contracts	$	(12,175	)	$	—		$	(9,846	)	$	(22,021	)	$	22,021		$	—
Physical contracts	—			—			(3,173		)	(3,173		)	—			(3,173		)
Interest-rate contracts	—			(69,103		)	—			(69,103		)	—			(69,103		)
Total derivative liabilities	$	(12,175	)	$	(69,103	)	$	(13,019	)	$	(94,297	)	$	22,021		$	(72,276	)

(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 September 30, 2016, we held no cash and posted $27.4 million of cash with various counterparties, including $14.6 million of cash collateral that is offsetting derivative net liability positions under master-netting arrangements in the table above. The remaining $12.8 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, other current liabilities or deferred credits and other liabilities in our Consolidated Balance Sheets.



	December 31, 2015
	Level 1			Level 2			Level 3			Total - Gross			Netting (a)			Total - Net (b)
	(Thousands of dollars)
Derivative assets
Commodity contracts
Financial contracts	$	38,921		$	—		$	7,253		$	46,174		$	(42,414	)	$	3,760
Physical contracts	—			—			3,591			3,591			—			3,591
Total derivative assets	$	38,921		$	—		$	10,844		$	49,765		$	(42,414	)	$	7,351
Derivative liabilities
Commodity contracts
Financial contracts	$	(4,513	)	$	—		$	(3,513	)	$	(8,026	)	$	8,026		$	—
Interest-rate contracts	—			(9,936		)	—			(9,936		)	—			(9,936		)
Total derivative liabilities	$	(4,513	)	$	(9,936	)	$	(3,513	)	$	(17,962	)	$	8,026		$	(9,936	)

(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, 2015, we held $34.4 million of cash from various counterparties that is offsetting derivative net asset positions in the table above under master-netting arrangements and had no cash collateral posted.

(b) - Included in other current 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						Nine Months Ended
	September 30,						September 30,
Derivative Assets (Liabilities)	2016			2015			2016			2015
	(Thousands of dollars)
Net assets (liabilities) at beginning of period	$	(14,021	)	$	10,387		$	7,331		$	9,285
Total realized/unrealized gains (losses):
Included in earnings (a)	920			(15		)	492			95
Included in other comprehensive income (loss)	3,038			(5,076		)	(17,886		)	(4,084		)
Net assets (liabilities) at end of period	$	(10,063	)	$	5,296		$	(10,063	)	$	5,296

(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 and nine months ended September 30, 2016 and 2015, 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 and nine months ended September 30, 2016 and 2015, 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 the aggregate of our long-term debt, including current maturities, was $7.6 billion and $6.2 billion at September 30, 2016, and December 31, 2015, respectively. The book value of the aggregate of our long-term debt, including current maturities, was $7.1 billion and $6.8 billion at September 30, 2016, and December 31, 2015, respectively. 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.


C.	RISK-MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

Risk-Management Activities - We are sensitive to changes in natural gas, crude oil and NGL prices, principally as a result of contractual terms under which these commodities are processed, purchased and sold. We 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 receiving commodities as a portion of our compensation for services 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 can expose us 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 use physical-forward sales or purchases to reduce the impact of price fluctuations related to natural gas. At September 30, 2016, and December 31, 2015, 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 September 30, 2016, we had interest-rate swaps with notional amounts totaling $1.0 billion to hedge the variability of our LIBOR-based interest payments. In addition, in June 2016, we entered into forward-starting interest-rate swaps with notional amounts totaling $750 million 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, resulting in total notional amounts of this type of interest-rate swap of $1.2 billion at September 30, 2016, compared with $400 million at December 31, 2015. All of our interest-rate swaps are designated as cash flow hedges.

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

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



	September 30, 2016					December 31, 2015
	Assets (a)		(Liabilities) (a)			Assets (b)		(Liabilities) (b)
	(Thousands of dollars)
Derivatives designated as hedging instruments
Commodity contracts
Financial contracts	$	9,525	$	(20,376	)	$	39,255	$	(1,440	)
Physical contracts	98		(3,173		)	3,591		—
Interest-rate contracts	—		(69,103		)	—		(9,936		)
Total derivatives designated as hedging instruments	9,623		(92,652		)	42,846		(11,376		)
Derivatives not designated as hedging instruments
Commodity contracts
Financial contracts	2,384		(1,645		)	6,919		(6,586		)
Total derivatives not designated as hedging instruments	2,384		(1,645		)	6,919		(6,586		)
Total derivatives	$	12,007	$	(94,297	)	$	49,765	$	(17,962	)

(a) - Included on a net basis in other current assets, other assets, other current liabilities or deferred credits and other liabilities in our Consolidated Balance Sheets.

(b) - Included on a net basis in other current assets or other current liabilities in our Consolidated Balance Sheets.

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



		September 30, 2016					December 31, 2015
	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	—		(43.3		)	—		(27.1		)
- Natural gas (Bcf)	Put options	68.3		—			—		—
- Crude oil and NGLs (MMBbl)	Futures, forwards and swaps	—		(4.6		)	—		(2.3		)
Basis
- Natural gas (Bcf)	Futures and swaps	—		(43.3		)	—		(27.1		)
Interest-rate contracts (Millions of dollars)	Swaps	$	2,150.0	$	—		$	400.0	$	—
Derivatives not designated as hedging instruments:
Fixed price
- NGLs (MMBbl)	Futures, forwards and swaps	1.1		(0.9		)	0.6		(0.6		)

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 September 30, 2016, our Consolidated Balance Sheet reflected a net loss of $241.8 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 $27.3 million, which will be realized within the next 27 months as the forecasted transactions affect earnings. If commodity prices remain at current levels, we will realize approximately $21.4 million in net losses over the next 12 months and approximately $5.9 million in net losses thereafter. The amount deferred in accumulated other comprehensive loss attributable to our settled interest-rate swaps is a loss of $130.0 million, which will be recognized over the life of the long-term, fixed-rate debt, including losses of $16.4 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 will 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					Nine Months Ended
Derivatives in Cash Flow Hedging Relationships	September 30,					September 30,
Derivatives in Cash Flow Hedging Relationships	2016		2015			2016			2015
	(Thousands of dollars)
Commodity contracts	$	7,580	$	36,559		$	(39,396	)	$	47,650
Interest-rate contracts	958		(20,610		)	(59,217		)	(26,277		)
Total unrealized gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	$	8,538	$	15,949		$	(98,613	)	$	21,373

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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						Nine Months Ended
		September 30,						September 30,
		2016			2015			2016			2015
		(Thousands of dollars)
Commodity contracts	Commodity sales revenues	$	908		$	22,770		$	29,456		$	54,020
Interest-rate contracts	Interest expense	(3,925		)	(3,676		)	(11,669		)	(10,235		)
Total gain (loss) reclassified from accumulated other comprehensive loss into net income on derivatives (effective portion)		$	(3,017	)	$	19,094		$	17,787		$	43,785

Ineffectiveness related to our cash flow hedges for the three and nine months ended September 30, 2016 and 2015, was not material. In the event that it becomes probable that a forecasted transaction will not occur, we would discontinue cash flow hedge treatment, which would affect earnings. For the three and nine months ended September 30, 2016 and 2015, there were no gains or losses due to the discontinuance of cash flow hedge treatment.

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 September 30, 2016.

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.

At September 30, 2016, the net credit exposure from our derivative assets is primarily with investment-grade companies in the financial services sector.


D.	SHORT-TERM BORROWINGS

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.

We had $14 million of letters of credit issued, no borrowings outstanding and approximately $1.7 billion capacity available at September 30, 2016, under our Partnership Credit Agreement.

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 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 our Intermediate Partnership. Borrowings under our Partnership Credit Agreement are 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

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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 immediately. At September 30, 2016, our ratio of indebtedness to adjusted EBITDA was 4.1 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.

Neither we nor ONEOK guarantees the debt or other similar commitments of unaffiliated parties. ONEOK does not guarantee the debt, commercial paper or other similar commitments of ONEOK Partners, and ONEOK Partners does not guarantee the debt or other similar commitments of ONEOK.

Commercial Paper Program - At September 30, 2016, we had $694 million of commercial paper outstanding under our $2.4 billion commercial paper program with a weighted-average interest rate of 1.15 percent. Amounts outstanding under our commercial paper program reduce the borrowing capacity under our Partnership Credit Agreement.


E.	LONG-TERM DEBT

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



	September 30,			December 31,
	2016			2015
	(Thousands of dollars)
ONEOK Partners
$650,000 at 3.25% due 2016	$	—		$	650,000
$450,000 at 6.15% due 2016	450,000			450,000
$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			—
$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
Average 7.85% due 2022	46,170			51,907
Total long-term debt	7,196,170			6,851,907
Unamortized debt issuance costs and discounts	(46,857		)	(48,945		)
Current maturities	(457,650		)	(107,650		)
Long-term debt, excluding current maturities	$	6,691,663		$	6,695,312

Debt Issuances and Maturities - In January 2016, we entered into the $1.0 billion senior unsecured delayed-draw Term Loan Agreement with a syndicate of banks. The Term Loan Agreement matures in January 2019 and bears interest at LIBOR plus a margin that is based on the credit ratings assigned to our senior, unsecured, long-term indebtedness. Based on our current applicable credit rating, borrowings on the Term Loan Agreement accrue at LIBOR plus 130 basis points. At September 30, 2016, the interest rate was 1.83 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 our $650 million, 3.25 percent senior notes, to repay amounts outstanding under our commercial paper program and for general partnership purposes.

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At September 30, 2016, our $450 million, 6.15 percent senior notes due October 1, 2016, are reflected in current maturities of long-term debt in our Consolidated Balance Sheet. In October 2016, we repaid our $450 million, 6.15 percent senior notes, with a combination of cash on hand and short-term borrowings.

In March 2015, we completed an underwritten public offering of $800 million of senior notes, consisting of $300 million, 3.8 percent senior notes due 2020, and $500 million, 4.9 percent senior notes due 2025. The net proceeds, after deducting underwriting discounts, commissions and other expenses, were approximately $792.3 million. We used the proceeds to repay amounts outstanding under our commercial paper program and for general partnership purposes.


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 September 30, 2016.

Equity Issuances - In August 2015, we completed a private placement of 21.5 million common units at a price of $30.17 per unit with ONEOK. Additionally, we completed a concurrent sale of approximately 3.3 million common units at a price of $30.17 per unit to funds managed by Kayne Anderson Capital Advisors in a registered direct offering, which were issued through our existing “at-the-market” equity program. The combined offerings generated net proceeds of approximately $749 million. In conjunction with these issuances, ONEOK Partners GP contributed approximately $15.3 million in order to maintain its 2 percent general partner interest in us. We used the proceeds for general partnership purposes, including capital expenditures and repayment of commercial paper borrowings. No other units were sold through the “at-the-market” program during the three months ended September 30, 2015.

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 September 30, 2016, we had approximately $138 million of registered common units available for issuance through our “at-the-market” equity program.

During the three and nine months ended September 30, 2016, no common units were sold through our “at-the-market” equity program.

During the nine months ended September 30, 2015, we sold 10.5 million common units through our “at-the-market” equity program, including the units sold to funds managed by Kayne Anderson Capital Advisors in the offering discussed above. The net proceeds, including ONEOK Partners GP’s contribution to maintain its 2 percent general partner interest in us, were approximately $381.6 million, which were used for general partnership purposes, including repayment of commercial paper borrowings.

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 October 2016, our general partner declared a cash distribution of $0.79 per unit ($3.16 per unit on an annualized basis) for the third quarter 2016, which will be paid on November 14, 2016, to unitholders of record at the close of business on October 31, 2016.

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



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(Thousands, except per unit amounts)
Distribution per unit	$	0.79	$	0.79	$	2.37	$	2.37

General partner distributions	$	6,660	$	6,081	$	19,980	$	17,950
Incentive distributions	100,538		91,794		301,614		270,962
Distributions to general partner	107,198		97,875		321,594		288,912
Limited partner distributions to ONEOK	90,323		73,302		270,969		219,907
Limited partner distributions to other unitholders	135,480		132,862		406,439		388,655
Total distributions paid	$	333,001	$	304,039	$	999,002	$	897,474

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				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(Thousands, except per unit amounts)
Distribution per unit	$	0.79	$	0.79	$	2.37	$	2.37

General partner distributions	$	6,660	$	6,660	$	19,980	$	18,696
Incentive distributions	100,538		100,538		301,614		282,221
Distributions to general partner	107,198		107,198		321,594		300,917
Limited partner distributions to ONEOK	90,323		90,323		270,969		236,927
Limited partner distributions to other unitholders	135,480		135,480		406,439		396,925
Total distributions declared	$	333,001	$	333,001	$	999,002	$	934,769


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, 2016	$	(111,357	)	$	(1,925	)	$	(113,282	)
Other comprehensive income (loss) before reclassifications	(98,613		)	(12,071		)	(110,684		)
Amounts reclassified from accumulated other comprehensive loss	(17,787		)	—			(17,787		)
Net current-period other comprehensive income (loss) attributable to ONEOK Partners	(116,400		)	(12,071		)	(128,471		)
September 30, 2016	$	(227,757	)	$	(13,996	)	$	(241,753	)

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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						Nine Months Ended						Affected Line Item in the Consolidated Statements of Income
	September 30,						September 30,
	2016			2015			2016			2015
	(Thousands of dollars)
Unrealized gains (losses) on risk-management assets/liabilities
Commodity contracts	$	908		$	22,770		$	29,456		$	54,020		Commodity sales revenues
Interest-rate contracts	(3,925		)	(3,676		)	(11,669		)	(10,235		)	Interest expense
Total reclassifications for the period attributable to ONEOK Partners	$	(3,017	)	$	19,094		$	17,787		$	43,785		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				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(Thousands of dollars)
Northern Border Pipeline	$	17,854	$	16,156	$	52,251	$	51,131
Overland Pass Pipeline Company	13,886		10,538		40,798		27,048
Other	3,415		5,550		7,392		15,026
Equity in net earnings from investments	$	35,155	$	32,244	$	100,441	$	93,205

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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				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(Thousands of dollars)
Income Statement
Operating revenues	$	143,967	$	135,474	$	423,170	$	390,793
Operating expenses	$	66,490	$	64,786	$	191,863	$	178,324
Net income	$	72,672	$	67,121	$	214,129	$	196,123

Distributions paid to us	$	40,822	$	36,370	$	149,399	$	117,153

We incurred expenses in transactions with unconsolidated affiliates of $36.4 million and $28.4 million for the three months ended September 30, 2016 and 2015, respectively, and $105.3 million and $74.2 million for the nine months ended September 30, 2016 and 2015, respectively, primarily related to Overland Pass Pipeline Company and Northern Border Pipeline. Accounts payable to our equity-method investees at September 30, 2016, and December 31, 2015, were $11.5 million and $8.0 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, the 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 - In March 2015, we entered into a 50-50 joint venture with a subsidiary of Fermaca Infrastructure B.V. (Fermaca), a Mexico City-based natural gas infrastructure company, to construct a pipeline to transport natural gas from the Permian Basin in West Texas to the Mexican border near El Paso, Texas. During the nine months ended September 30, 2016, we made contributions of approximately $55 million to Roadrunner, and we expect to contribute approximately $10 million to Roadrunner during the remainder of 2016.

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. The Roadrunner Management Committee determines the amount and timing of such distributions. Any changes to, or suspension of, the cash distributions from Roadrunner requires approval of the Roadrunner Management Committee. Voting rights for the Roadrunner Management Committee are allocated on a pro rata basis according to each member’s ownership interest. Cash distributions are equal to 100 percent of available cash, as defined in the limited liability company agreement.


J.	RELATED-PARTY TRANSACTIONS

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.

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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 us through a variety of methods, depending upon the nature of the expenses and activities. For the three months ended September 30, 2016 and 2015, $95.2 million and $89.3 million, respectively, of our operating expenses were incurred with ONEOK and its affiliates. For the nine months ended September 30, 2016 and 2015, $285.1 million and $265.6 million, respectively, of our operating expenses were incurred with ONEOK and its affiliates.

ONEOK Partners GP made additional general partner contributions to us of approximately $21.0 million during the nine months ended September 30, 2015. See Note F for additional information about cash distributions paid to ONEOK for its general partner and limited partner interests.

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 and nine months ended September 30, 2016, were $2.5 million and $6.9 million, respectively. Charges to Roadrunner for the three and nine months ended September 30, 2015, 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 - 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.


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. Beginning in 2016, adjusted EBITDA by segment, a non-GAAP financial measure, is utilized in this evaluation. We believe this non-GAAP financial measure is useful to investors because it is 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 our financial performance with the performance of other publicly traded partnerships within our industry. Adjusted EBITDA is defined as net income adjusted for interest expense, depreciation and amortization, noncash impairment charges, income taxes and AFUDC and other noncash items. 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

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comparable with similarly titled measures of other companies. Prior period segment disclosures have been recast to reflect this change.

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 and nine months ended September 30, 2016 and 2015, we had no single customer from which we received 10 percent or more 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 September 30, 2016	Natural Gas Gathering and Processing			Natural Gas Liquids (a)			Natural Gas Pipelines (b)			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	361,717		$	1,905,273		$	90,401		$	—		$	2,357,391
Intersegment revenues	150,501			133,984			1,676			(286,161		)	—
Total revenues	512,218			2,039,257			92,077			(286,161		)	2,357,391
Cost of sales and fuel (exclusive of items shown separately below)	336,456			1,694,161			6,870			(285,894		)	1,751,593
Operating costs	69,443			79,771			28,373			(188		)	177,399
Depreciation and amortization	44,994			40,751			12,057			—			97,802
(Gain) loss on sale of assets	(846		)	(5		)	(4,894		)	—			(5,745		)
Operating income	$	62,171		$	224,579		$	49,671		$	(79	)	$	336,342
Equity in net earnings from investments	$	2,596		$	13,960		$	18,599		$	—		$	35,155
Capital expenditures	$	99,649		$	30,533		$	24,495		$	2,405		$	157,082

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $299.2 million, of which $253.4 million related to sales within the segment, cost of sales and fuel of $119.6 million and operating income of $118.5 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $61.0 million, cost of sales and fuel of $7.8 million and operating income of $26.0 million.



Three Months Ended September 30, 2015	Natural Gas Gathering and Processing			Natural Gas Liquids (a)		Natural Gas Pipelines (b)		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	294,948		$	1,522,224	$	81,246	$	—		$	1,898,418
Intersegment revenues	139,388			89,230		1,751		(230,369		)	—
Total revenues	434,336			1,611,454		82,997		(230,369		)	1,898,418
Cost of sales and fuel (exclusive of items shown separately below)	293,681			1,289,682		7,628		(230,182		)	1,360,809
Operating costs	61,162			74,464		26,674		(209		)	162,091
Depreciation and amortization	37,286			39,317		10,914		—			87,517
(Gain) loss on sale of assets	(132		)	498		77		—			443
Operating income	$	42,339		$	207,493	$	37,704	$	22		$	287,558
Equity in net earnings from investments	$	4,350		$	10,912	$	16,982	$	—		$	32,244
Capital expenditures	$	231,835		$	52,807	$	14,718	$	1,114		$	300,474

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $252.8 million, of which $204.7 million related to sales within the segment, cost of sales and fuel of $112.7 million and operating income of $80.3 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $65.1 million, cost of sales and fuel of $7.2 million and operating income of $24.7 million.

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Nine Months Ended September 30, 2016	Natural Gas Gathering and Processing			Natural Gas Liquids (a)			Natural Gas Pipelines (b)			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	971,834		$	5,030,820		$	262,276		$	—		$	6,264,930
Intersegment revenues	449,154			367,820			3,843			(820,817		)	—
Total revenues	1,420,988			5,398,640			266,119			(820,817		)	6,264,930
Cost of sales and fuel (exclusive of items shown separately below)	902,747			4,376,345			15,914			(820,352		)	4,474,654
Operating costs	208,353			236,722			85,075			(633		)	529,517
Depreciation and amortization	133,258			122,153			34,634			—			290,045
(Gain) loss on sale of assets	(2,331		)	(12		)	(7,133		)	—			(9,476		)
Operating income	$	178,961		$	663,432		$	137,629		$	168		$	980,190
Equity in net earnings from investments	$	7,987		$	41,211		$	51,243		$	—		$	100,441
Investments in unconsolidated affiliates	$	68,735		$	470,635		$	404,020		$	—		$	943,390
Total assets	$	5,268,161		$	8,257,203		$	1,912,951		$	(118,757	)	$	15,319,558
Noncontrolling interests in consolidated subsidiaries	$	—		$	158,352		$	—		$	—		$	158,352
Capital expenditures	$	325,820		$	85,519		$	71,721		$	6,298		$	489,358

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $878.5 million, of which $742.6 million related to sales within the segment, cost of sales and fuel of $339.1 million and operating income of $354.9 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $172.4 million, cost of sales and fuel of $19.1 million and operating income of $72.9 million.



Nine Months Ended September 30, 2015	Natural Gas Gathering and Processing			Natural Gas Liquids (a)		Natural Gas Pipelines (b)		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	862,462		$	4,726,617	$	241,605	$	—		$	5,830,684
Intersegment revenues	487,559			229,804		5,053		(722,416		)	—
Total revenues	1,350,021			4,956,421		246,658		(722,416		)	5,830,684
Cost of sales and fuel (exclusive of items shown separately below)	947,539			4,054,039		28,059		(721,871		)	4,307,766
Operating costs	193,922			234,120		79,156		(336		)	506,862
Depreciation and amortization	109,035			118,044		32,484		—			259,563
(Gain) loss on sale of assets	(328		)	579		76		—			327
Operating income	$	99,853		$	549,639	$	106,883	$	(209	)	$	756,166
Equity in net earnings from investments	$	13,511		$	27,585	$	52,109	$	—		$	93,205
Investments in unconsolidated affiliates	$	253,548		$	484,403	$	399,108	$	—		$	1,137,059
Total assets	$	5,206,987		$	8,041,064	$	1,845,232	$	(62,239	)	$	15,031,044
Noncontrolling interests in consolidated subsidiaries	$	4,066		$	161,210	$	—	$	—		$	165,276
Capital expenditures	$	692,570		$	185,360	$	39,923	$	11,017		$	928,870

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $690.1 million, of which $556.4 million related to sales within the segment, cost of sales and fuel of $297.3 million and operating income of $218.8 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $198.5 million, cost of sales and fuel of $22.6 million and operating income of $77.8 million.

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	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Unaudited)	2016			2015			2016			2015
	(Thousands of dollars)
Segment Adjusted EBITDA:
Natural Gas Gathering and Processing	$	109,837		$	82,718		$	320,170		$	221,298
Natural Gas Liquids	279,256			255,745			826,036			692,991
Natural Gas Pipelines	80,304			65,166			223,185			201,112
Other	(42		)	53			358			(144		)
Depreciation and amortization	(97,802		)	(87,517		)	(290,045		)	(259,563		)
Interest expense, net of capitalized interest	(92,521		)	(86,666		)	(278,339		)	(253,867		)
Income tax (expense) benefit	(3,681		)	156			(8,079		)	(5,080		)
AFUDC and other	60			10			375			(8,440		)
Net income	$	275,411		$	229,665		$	793,661		$	588,307


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.

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Condensed Consolidating Statements of Income



	Three Months Ended September 30, 2016
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Revenues
Commodity sales	$	—		$	—		$	1,840.5		$	—		$	1,840.5
Services	—			—			516.9			—			516.9
Total revenues	—			—			2,357.4			—			2,357.4
Cost of sales and fuel (exclusive of items shown separately below)	—			—			1,751.6			—			1,751.6
Operating expenses	—			—			275.2			—			275.2
(Gain) loss on sale of assets	—			—			(5.7		)	—			(5.7		)
Operating income	—			—			336.3			—			336.3
Equity in net earnings from investments	274.3			274.3			17.3			(530.7		)	35.2
Other income (expense), net	95.3			95.3			0.1			(190.6		)	0.1
Interest expense, net	(95.3		)	(95.3		)	(92.5		)	190.6			(92.5		)
Income before income taxes	274.3			274.3			261.2			(530.7		)	279.1
Income taxes	—			—			(3.7		)	—			(3.7		)
Net income	274.3			274.3			257.5			(530.7		)	275.4
Less: Net income attributable to noncontrolling interests	—			—			1.1			—			1.1
Net income attributable to ONEOK Partners, L.P.	$	274.3		$	274.3		$	256.4		$	(530.7	)	$	274.3



	Three Months Ended September 30, 2015
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Revenues
Commodity sales	$	—		$	—		$	1,484.3		$	—		$	1,484.3
Services	—			—			414.1			—			414.1
Total revenues	—			—			1,898.4			—			1,898.4
Cost of sales and fuel (exclusive of items shown separately below)	—			—			1,360.8			—			1,360.8
Operating expenses	—			—			249.6			—			249.6
(Gain) loss on sale of assets	—			—			0.4			—			0.4
Operating income	—			—			287.6			—			287.6
Equity in net earnings from investments	227.0			227.0			16.1			(437.9		)	32.2
Other income (expense), net	94.4			94.4			(3.6		)	(188.8		)	(3.6		)
Interest expense, net	(94.4		)	(94.4		)	(86.7		)	188.8			(86.7		)
Income before income taxes	227.0			227.0			213.4			(437.9		)	229.5
Income tax (expense) benefit	—			—			0.2			—			0.2
Net income	227.0			227.0			213.6			(437.9		)	229.7
Less: Net income attributable to noncontrolling interests	—			—			2.7			—			2.7
Net income attributable to ONEOK Partners, L.P.	$	227.0		$	227.0		$	210.9		$	(437.9	)	$	227.0

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	Nine Months Ended September 30, 2016
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Revenues
Commodity sales	$	—		$	—		$	4,757.3		$	—		$	4,757.3
Services	—			—			1,507.6			—			1,507.6
Total revenues	—			—			6,264.9			—			6,264.9
Cost of sales and fuel (exclusive of items shown separately below)	—			—			4,474.7			—			4,474.7
Operating expenses	—			—			819.5			—			819.5
(Gain) loss on sale of assets	—			—			(9.5		)	—			(9.5		)
Operating income	—			—			980.2			—			980.2
Equity in net earnings from investments	789.3			789.3			48.2			(1,526.4		)	100.4
Other income (expense), net	284.6			284.6			(0.6		)	(569.2		)	(0.6		)
Interest expense, net	(284.6		)	(284.6		)	(278.3		)	569.2			(278.3		)
Income before income taxes	789.3			789.3			749.5			(1,526.4		)	801.7
Income taxes	—			—			(8.0		)	—			(8.0		)
Net income	789.3			789.3			741.5			(1,526.4		)	793.7
Less: Net income attributable to noncontrolling interests	—			—			4.4			—			4.4
Net income attributable to ONEOK Partners, L.P.	$	789.3		$	789.3		$	737.1		$	(1,526.4	)	$	789.3



	Nine Months Ended September 30, 2015
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Revenues
Commodity sales	$	—		$	—		$	4,642.3		$	—		$	4,642.3
Services	—			—			1,188.4			—			1,188.4
Total revenues	—			—			5,830.7			—			5,830.7
Cost of sales and fuel (exclusive of items shown separately below)	—			—			4,307.8			—			4,307.8
Operating expenses	—			—			766.4			—			766.4
(Gain) loss on sale of assets	—			—			0.3			—			0.3
Operating income	—			—			756.2			—			756.2
Equity in net earnings from investments	582.3			582.3			42.1			(1,113.5		)	93.2
Other income (expense), net	276.5			276.5			(2.1		)	(553.0		)	(2.1		)
Interest expense, net	(276.5		)	(276.5		)	(253.9		)	553.0			(253.9		)
Income before income taxes	582.3			582.3			542.3			(1,113.5		)	593.4
Income taxes	—			—			(5.1		)	—			(5.1		)
Net income	582.3			582.3			537.2			(1,113.5		)	588.3
Less: Net income attributable to noncontrolling interests	—			—			6.0			—			6.0
Net income attributable to ONEOK Partners, L.P.	$	582.3		$	582.3		$	531.2		$	(1,113.5	)	$	582.3

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Condensed Consolidating Statements of Comprehensive Income



	Three Months Ended September 30, 2016
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Net income	$	274.3		$	274.3		$	257.5		$	(530.7	)	$	275.4
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	8.6			7.6			7.6			(15.2		)	8.6
Realized (gains) losses on derivatives recognized in net income	3.0			(0.9		)	(0.9		)	1.8			3.0
Other comprehensive income (loss) on investments in unconsolidated affiliates	(0.7		)	(0.7		)	(0.7		)	1.4			(0.7		)
Total other comprehensive income (loss)	10.9			6.0			6.0			(12.0		)	10.9
Comprehensive income	285.2			280.3			263.5			(542.7		)	286.3
Less: Comprehensive income attributable to noncontrolling interests	—			—			1.1			—			1.1
Comprehensive income attributable to ONEOK Partners, L.P.	$	285.2		$	280.3		$	262.4		$	(542.7	)	$	285.2



	Three Months Ended September 30, 2015
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Net income	$	227.0		$	227.0		$	213.6		$	(437.9	)	$	229.7
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	15.9			36.6			36.6			(73.2		)	15.9
Realized (gains) losses on derivatives recognized in net income	(19.1		)	(22.8		)	(22.8		)	45.6			(19.1		)
Total other comprehensive income (loss)	(3.2		)	13.8			13.8			(27.6		)	(3.2		)
Comprehensive income	223.8			240.8			227.4			(465.5		)	226.5
Less: Comprehensive income attributable to noncontrolling interests	—			—			2.7			—			2.7
Comprehensive income attributable to ONEOK Partners, L.P.	$	223.8		$	240.8		$	224.7		$	(465.5	)	$	223.8

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	Nine Months Ended September 30, 2016
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Net income	$	789.3		$	789.3		$	741.5		$	(1,526.4	)	$	793.7
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	(98.6		)	(39.4		)	(39.4		)	78.8			(98.6		)
Realized (gains) losses on derivatives recognized in net income	(17.8		)	(29.5		)	(29.5		)	59.0			(17.8		)
Other comprehensive income (loss) on investments in unconsolidated affiliates	(12.1		)	(12.1		)	(12.1		)	24.2			(12.1		)
Total other comprehensive income (loss)	(128.5		)	(81.0		)	(81.0		)	162.0			(128.5		)
Comprehensive income	660.8			708.3			660.5			(1,364.4		)	665.2
Less: Comprehensive income attributable to noncontrolling interests	—			—			4.4			—			4.4
Comprehensive income attributable to ONEOK Partners, L.P.	$	660.8		$	708.3		$	656.1		$	(1,364.4	)	$	660.8



	Nine Months Ended September 30, 2015
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Net income	$	582.3		$	582.3		$	537.2		$	(1,113.5	)	$	588.3
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	21.4			47.7			47.7			(95.4		)	21.4
Realized (gains) losses on derivatives recognized in net income	(43.8		)	(54.0		)	(54.0		)	108.0			(43.8		)
Total other comprehensive income (loss)	(22.4		)	(6.3		)	(6.3		)	12.6			(22.4		)
Comprehensive income	559.9			576.0			530.9			(1,100.9		)	565.9
Less: Comprehensive income attributable to noncontrolling interests	—			—			6.0			—			6.0
Comprehensive income attributable to ONEOK Partners, L.P.	$	559.9		$	576.0		$	524.9		$	(1,100.9	)	$	559.9

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Condensed Consolidating Balance Sheets



	September 30, 2016
(Unaudited)	Parent		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidating Entries			Total
Assets	(Millions of dollars)
Current assets
Cash and cash equivalents	$	—	$	5.5	$	—	$	—		$	5.5
Accounts receivable, net	—		—		737.1		—			737.1
Affiliate receivables	—		—		0.3		—			0.3
Natural gas and natural gas liquids in storage	—		—		217.8		—			217.8
Other current assets	—		—		168.1		—			168.1
Total current assets	—		5.5		1,123.3		—			1,128.8
Property, plant and equipment
Property, plant and equipment	—		—		14,718.6		—			14,718.6
Accumulated depreciation and amortization	—		—		2,302.8		—			2,302.8
Net property, plant and equipment	—		—		12,415.8		—			12,415.8
Investments and other assets
Intercompany notes receivable	10,643.6		7,364.9		—		(18,008.5		)	—
Other assets	3,303.3		6,576.5		1,442.5		(9,547.3		)	1,775.0
Total investments and other assets	13,946.9		13,941.4		1,442.5		(27,555.8		)	1,775.0
Total assets	$	13,946.9	$	13,946.9	$	14,981.6	$	(27,555.8	)	$	15,319.6
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	450.0	$	—	$	7.7	$	—		$	457.7
Short-term borrowings	693.5		—		—		—			693.5
Accounts payable	—		—		701.5		—			701.5
Affiliate payables	—		—		19.1		—			19.1
Other current liabilities	134.0		—		280.5		—			414.5
Total current liabilities	1,277.5		—		1,008.8		—			2,286.3

Intercompany debt	—		10,643.6		7,364.9		(18,008.5		)	—

Long-term debt, excluding current maturities	6,653.1		—		38.5		—			6,691.6

Deferred credits and other liabilities	21.3		—		167.0		—			188.3

Commitments and contingencies

Equity
Equity excluding noncontrolling interests in consolidated subsidiaries	5,995.0		3,303.3		6,244.0		(9,547.3		)	5,995.0
Noncontrolling interests in consolidated subsidiaries	—		—		158.4		—			158.4
Total equity	5,995.0		3,303.3		6,402.4		(9,547.3		)	6,153.4
Total liabilities and equity	$	13,946.9	$	13,946.9	$	14,981.6	$	(27,555.8	)	$	15,319.6

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	December 31, 2015
(Unaudited)	Parent		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidating Entries			Total
Assets	(Millions of dollars)
Current assets
Cash and cash equivalents	$	—	$	5.1	$	—	$	—		$	5.1
Accounts receivable, net	—		—		593.4		—			593.4
Affiliate receivables	—		—		8.0		—			8.0
Natural gas and natural gas liquids in storage	—		—		128.1		—			128.1
Other current assets	4.1		—		144.5		—			148.6
Total current assets	4.1		5.1		874.0		—			883.2
Property, plant and equipment
Property, plant and equipment	—		—		14,307.5		—			14,307.5
Accumulated depreciation and amortization	—		—		2,050.7		—			2,050.7
Net property, plant and equipment	—		—		12,256.8		—			12,256.8
Investments and other assets
Intercompany notes receivable	10,144.9		7,781.8		—		(17,926.7		)	—
Other assets	3,594.0		5,952.0		1,425.2		(9,183.6		)	1,787.6
Total investments and other assets	13,738.9		13,733.8		1,425.2		(27,110.3		)	1,787.6
Total assets	$	13,743.0	$	13,738.9	$	14,556.0	$	(27,110.3	)	$	14,927.6
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	100.0	$	—	$	7.7	$	—		$	107.7
Short-term borrowings	546.3		—		—		—			546.3
Accounts payable	—		—		605.4		—			605.4
Affiliate payables	—		—		27.1		—			27.1
Other current liabilities	112.5		—		181.4		—			293.9
Total current liabilities	758.8		—		821.6		—			1,580.4

Intercompany debt	—		10,144.9		7,781.8		(17,926.7		)	—

Long-term debt, excluding current maturities	6,651.0		—		44.3		—			6,695.3

Deferred credits and other liabilities	—		—		154.6		—			154.6

Commitments and contingencies

Equity
Equity excluding noncontrolling interests in consolidated subsidiaries	6,333.2		3,594.0		5,589.6		(9,183.6		)	6,333.2
Noncontrolling interests in consolidated subsidiaries	—		—		164.1		—			164.1
Total equity	6,333.2		3,594.0		5,753.7		(9,183.6		)	6,497.3
Total liabilities and equity	$	13,743.0	$	13,738.9	$	14,556.0	$	(27,110.3	)	$	14,927.6

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Condensed Consolidating Statements of Cash Flows



	Nine Months Ended September 30, 2016
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Operating activities
Cash provided by operating activities	$	998.3		$	52.3		$	947.8		$	(999.0	)	$	999.4
Investing activities
Capital expenditures	—			—			(489.4		)	—			(489.4		)
Other investing activities	—			30.0			(23.1		)	—			6.9
Cash provided by (used in) investing activities	—			30.0			(512.5		)	—			(482.5		)
Financing activities
Cash distributions:
General and limited partners	(999.0		)	(999.0		)	—			999.0			(999.0		)
Noncontrolling interests	—			—			(6.1		)	—			(6.1		)
Intercompany borrowings (advances), net	(493.7		)	917.1			(423.4		)	—			—
Borrowing (repayment) of short-term borrowings, net	147.2			—			—			—			147.2
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		)	—			(5.8		)	—			(655.8		)
Cash provided by (used in) financing activities	(998.3		)	(81.9		)	(435.3		)	999.0			(516.5		)
Change in cash and cash equivalents	—			0.4			—			—			0.4
Cash and cash equivalents at beginning of period	—			5.1			—			—			5.1
Cash and cash equivalents at end of period	$	—		$	5.5		$	—		$	—		$	5.5

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	Nine Months Ended September 30, 2015
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Operating activities
Cash provided by operating activities	$	853.0		$	51.1		$	740.5		$	(897.5	)	$	747.1
Investing activities
Capital expenditures	—			—			(928.9		)	—			(928.9		)
Other investing activities	—			17.4			(29.2		)	—			(11.8		)
Cash provided by (used in) investing activities	—			17.4			(958.1		)	—			(940.7		)
Financing activities
Cash distributions:
General and limited partners	(897.5		)	(897.5		)	—			897.5			(897.5		)
Noncontrolling interests	—			—			(8.2		)	—			(8.2		)
Intercompany borrowings (advances), net	(1,025.4		)	793.8			231.6			—			—
Borrowing (repayment) of short-term borrowings, net	(768.0		)	—			—			—			(768.0		)
Issuance of long-term debt, net of discounts	798.9			—			—			—			798.9
Debt financing costs	(7.7		)	—			—			—			(7.7		)
Repayment of long-term debt	—			—			(5.8		)	—			(5.8		)
Issuance of common units, net of issuance costs	1,025.7			—			—			—			1,025.7
Contribution from general partner	21.0			—			—			—			21.0
Cash provided by (used in) financing activities	(853.0		)	(103.7		)	217.6			897.5			158.4
Change in cash and cash equivalents	—			(35.2		)	—			—			(35.2		)
Cash and cash equivalents at beginning of period	—			42.5			—			—			42.5
Cash and cash equivalents at end of period	$	—		$	7.3		$	—		$	—		$	7.3

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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.

We have a predominantly fee-based business in each of our three reportable segments and expect our consolidated earnings to be approximately 85 percent fee-based in 2016. We continue to expect demand for midstream nondiscretionary services and infrastructure development to be primarily driven by producers who need to connect production with end-use markets where current infrastructure is insufficient or nonexistent. 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 to Mexico.

We expect our Natural Gas Liquids segment’s earnings to be approximately 90 percent fee-based in 2016. We connected seven third-party natural gas processing plants and our Lonesome Creek processing plant to our natural gas liquids system in 2015 and five third-party natural gas processing plants and our Bear Creek processing plant in the first nine months of 2016, favorably impacting our Natural Gas Liquids segment’s fee-based volume growth. In this segment, we are well-positioned to capture future increases in NGL transportation and fractionation volumes due to increased demand in the petrochemical industry from the expected completion of ethylene production projects and NGL export activity without significant additional infrastructure needs or capital spending on our system.

Ethane rejection levels by natural gas processors delivering to our natural gas liquids gathering system have continued to fluctuate and averaged more than 175 MBbl/d during the first nine months of 2016, primarily in the Mid-Continent region. While the volume of ethane recovered increased modestly during the nine months ended September 30, 2016, compared with the same period in 2015, 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 rejection levels to continue to fluctuate for the remainder of 2016 and into 2017 as the market begins to balance ethane supply and demand and with changes in the price differentials between ethane and natural gas. We expect ethane recovery levels to increase as ethylene producers and NGL exporters increase their capacity to consume and export additional ethane feedstock volumes. Ethane demand is expected to ramp up as new world-scale ethylene production projects, petrochemical plant modifications, plant expansions and export facilities near completion and begin coming on line in 2017. We expect increases in future ethane recoveries to have a favorable impact on our financial results, beginning primarily in the second half of 2017.

In 2015, our Natural Gas Gathering and Processing segment restructured many POP with fee contracts associated with a significant amount of our gathered volumes to increase the fee component in the contracts. These restructured contracts and increased natural gas gathered and processed volumes favorably impacted our results in the first nine months of 2016, and we expect to continue to receive the benefit of the improved earnings from these contracts and volumes. In the first nine months of 2016, our Natural Gas Gathering and Processing segment’s fee revenues averaged 73 cents per MMBtu, compared with an average of 39 cents per MMBtu in the same period in 2015. As a result of these restructured contracts, we expect our Natural Gas Gathering and Processing segment’s earnings to be more than 75 percent fee-based in 2016. 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 2016 and 2017 and have begun hedging commodity price risk for 2018.

With the emerging STACK and SCOOP areas in Oklahoma, we expect increasing producer activity in the Mid-Continent. We have a strong presence in the region, with our Natural Gas Liquids segment’s gathering system connected to more than 100 third-party natural gas processing plants, our Natural Gas Gathering and Processing segment’s substantial acreage dedications in some of the most productive areas and our Natural Gas Pipelines segment’s broad footprint. We expect well completions in these areas to begin to ramp up in late 2016 and early 2017. As producers continue to develop the STACK and SCOOP areas, we expect natural gas and NGL volumes to increase in 2017, compared with expected 2016 volumes, and increased demand for our services from producers that need incremental takeaway capacity for natural gas and NGLs out of the region.

Many of our producer customers continue to drill and complete new wells in the most productive areas of the Williston Basin. A significant portion of our Williston Basin gathering and processing assets are located in these areas, which typically produce

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at higher initial production rates compared with other areas and have higher natural gas to oil ratios. Our natural gas volumes gathered and processed and NGL volumes gathered and fractionated increased in the first nine months of 2016, compared with the same period in 2015, due primarily to the completion of six compressor stations during 2015, the addition of the 200 MMcf/d Lonesome Creek plant in the fourth quarter 2015 and our 80 MMcf/d Bear Creek plant in the third quarter 2016, which allowed us to capture a significant portion of natural gas volumes previously being flared by producers in the Williston Basin. Additionally, we expect to benefit from production from new wells drilled on our dedicated acreage in the Williston Basin and wells that have been drilled previously but have not yet been completed. In 2017, we expect volume growth in the Williston Basin from the projects and production activities discussed above to be offset by natural production declines, which may cause our natural gas and NGL volumes from this basin to be relatively unchanged in 2017, compared with expected 2016 volumes in our Natural Gas Gathering and Processing and Natural Gas Liquids segments.

We expect our Natural Gas Pipelines segment’s earnings to be approximately 96 percent fee-based in 2016. This segment continues to develop new projects to grow our fee-based earnings, such as our Roadrunner joint venture and WesTex expansion project, both of which are fully subscribed with 25-year firm, fee-based agreements. We expect additional demand for our services to deliver natural gas to power plants previously fueled by coal and to support increased demand for natural gas exports to Mexico. Our Natural Gas Pipelines segment’s contracts are primarily with large creditworthy companies and include fixed fee or firm demand charge agreements that provide a minimum level of revenues regardless of commodity prices or volumetric throughput.

We expect the current lower commodity price environment to continue throughout 2016 and into 2017, impacting our net realized prices for natural gas, NGLs and condensate, and our financial results. If the low commodity price environment persists for a prolonged period or prices decline further, volumes across our assets may grow more slowly than in the past or decline.

Growth Projects - Crude oil and natural gas producers continue to drill for crude oil and NGL-rich natural gas in many regions where we have operations, including in the Bakken Shale and Three Forks formations in the Williston Basin; in the STACK and SCOOP areas, Cana-Woodford Shale, Woodford Shale and Springer Shale in the Mid-Continent region; and in the Permian Basin. We completed our Bear Creek processing plant and infrastructure project and our Stateline de-ethanizers project in August and September 2016, respectively. These projects expand our natural gas gathering and processing and natural gas liquids gathering infrastructure in the Williston Basin to capture natural gas from new wells and natural gas currently being flared by producers, and supply ethane produced by our Stateline de-ethanizers to customers exporting to Canada. In our Natural Gas Pipelines segment, Phase II of the Roadrunner pipeline and the WesTex pipeline expansion project were completed in October 2016, ahead of original schedule and below cost estimates. Both projects are fully subscribed with 25-year firm, fee-based agreements. Through our Roadrunner joint venture, the Roadrunner pipeline transports natural gas from the Permian Basin in West Texas to the Mexican border near El Paso, Texas, and together with our WesTex intrastate natural gas transmission pipeline, creates a platform for future opportunities to deliver natural gas supply to Mexico. Phase I of the Roadrunner pipeline was completed in March 2016. The execution of these capital investments aligns with our strategy to generate consistent growth and sustainable earnings through long-term fee-based projects. Our contractual commitments from crude oil and natural gas producers, natural gas processors and electric generators are expected to provide incremental cash flows and long-term fee-based earnings.

See additional discussion of our other growth projects in the “Financial Results and Operating Information” section in our Natural Gas Gathering and Processing, Natural Gas Liquids and Natural Gas Pipelines segments.

In addition to our growth projects, we have available capacity on our integrated system to grow fee-based earnings with minimal capital investment, particularly in our Natural Gas Liquids segment. Our Natural Gas Gathering and Processing and Natural Gas Liquids segments are well-positioned to capture future increases in volumes from the highly productive STACK and SCOOP areas in Oklahoma, where we expect an increase in producer activity in the remainder of 2016 and into 2017. Our Natural Gas Liquids segment is connected to more than 100 third-party natural gas processing plants in the Mid-Continent and is one of the primary NGL takeaway providers for these emerging areas. Additionally, in our Natural Gas Liquids segment, we expect approximately 175 MBbl/d to 200 MBbl/d of future ethane recoveries that can be brought onto our system with no additional capital expenditures required. In our Natural Gas Gathering and Processing segment, we have approximately 200 MMcf/d and 150 MMcf/d of available processing capacity in the Williston Basin and Mid-Continent region, respectively.

Change in Presentation of Financial Results - Beginning in 2016, we present financial results using adjusted EBITDA by segment, a non-GAAP financial measure. We believe this non-GAAP financial measure is useful to investors because it aids in comparing our financial performance with that of other companies with similar operations and is commonly employed to evaluate our financial performance. We have added adjusted EBITDA to the presentation of consolidated financial results and the financial results of each reporting segment. See additional discussion in the “Adjusted EBITDA” section.

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Debt Issuance - In January 2016, we entered into the $1.0 billion senior unsecured Term Loan Agreement with a syndicate of banks that matures in January 2019 and drew the full $1.0 billion available in the first quarter 2016. See Note E of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.

Goodwill Impairment Test - As the commodity price environment has remained relatively unchanged since 2015, we elected to perform a quantitative assessment, or Step 1 analysis, to test our goodwill for impairment. The assessment included our current commodity price assumptions, expected contractual terms, anticipated operating costs and volume estimates. Our goodwill impairment analysis performed as of July 1, 2016, did not result in an impairment charge nor did our analysis reflect any reporting units at risk. In each reporting unit, the fair value substantially exceeded the carrying value. Subsequent to that date, no event has occurred indicating that the implied fair value of each of our reporting units is less than the carrying value of its net assets.

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						Nine Months Ended						Three Months					Nine Months
	September 30,						September 30,						2016 vs. 2015					2016 vs. 2015
Financial Results	2016			2015			2016			2015			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Revenues
Commodity sales	$	1,840.5		$	1,484.3		$	4,757.3		$	4,642.3		$	356.2		24	%	$	115.0		2	%
Services	516.9			414.1			1,507.6			1,188.4			102.8			25	%	319.2			27	%
Total revenues	2,357.4			1,898.4			6,264.9			5,830.7			459.0			24	%	434.2			7	%
Cost of sales and fuel (exclusive of items shown separately below)	1,751.6			1,360.8			4,474.7			4,307.8			390.8			29	%	166.9			4	%
Operating costs	177.4			162.1			529.5			506.9			15.3			9	%	22.6			4	%
Depreciation and amortization	97.8			87.5			290.0			259.5			10.3			12	%	30.5			12	%
(Gain) loss on sale of assets	(5.7		)	0.4			(9.5		)	0.3			6.1			*		9.8			*
Operating income	$	336.3		$	287.6		$	980.2		$	756.2		$	48.7		17	%	$	224.0		30	%
Equity in net earnings from investments	$	35.2		$	32.2		$	100.4		$	93.2		$	3.0		9	%	$	7.2		8	%
Interest expense, net of capitalized interest	$	(92.5	)	$	(86.7	)	$	(278.3	)	$	(253.9	)	$	5.8		7	%	$	24.4		10	%
Adjusted EBITDA	$	469.4		$	403.7		$	1,369.7		$	1,115.3		$	65.7		16	%	$	254.4		23	%
Capital expenditures	$	157.1		$	300.5		$	489.4		$	928.9		$	(143.4	)	(48	%)	$	(439.5	)	(47	%)

* Percentage change is greater than 100 percent.

See Reconciliation of Adjusted EBITDA to Net Income 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 increased for the three and nine months ended September 30, 2016, compared with the same periods in 2015, due primarily to higher natural gas and NGL volumes from our completed capital-growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments, new plant connections and increased ethane recovery in our Natural Gas Liquids segment, and higher fees resulting from contract restructuring in our Natural Gas Gathering and Processing segment. These increases were offset partially by lower net realized NGL and natural gas prices in our Natural Gas Gathering and Processing segment, higher depreciation expense due to projects completed in 2015, higher costs associated with the growth of our operations in the Natural Gas Gathering and Processing segment and higher employee-related costs associated with incentive and medical benefit plans in all three of our segments.

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Equity in net earnings from investments increased for the three and nine months ended September 30, 2016, compared with the same periods in 2015, due primarily to higher volumes delivered to Overland Pass Pipeline from our Bakken NGL Pipeline, offset partially by lower equity earnings from our Powder River Basin equity investments.

Interest expense increased for the three months ended September 30, 2016, compared with the same period in 2015, primarily as a result of higher interest costs incurred associated with our borrowing under the Term Loan Agreement during the first quarter 2016, higher short-term borrowing rates and lower capitalized interest due to lower spending on capital-growth projects. Interest expense increased for the nine months ended September 30, 2016, compared with the same period in 2015, primarily as a result of the items discussed above and higher interest costs incurred associated with our issuance of $800 million of senior notes in March 2015.

Adjusted EBITDA increased for the three and nine months ended September 30, 2016, compared with the same periods in 2015, due primarily to higher natural gas gathered and NGL volumes from our completed capital-growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments, new plant connections and increased ethane recovery in our Natural Gas Liquids segment, and higher fees resulting from contract restructuring in our Natural Gas Gathering and Processing segment. These increases were offset partially by lower net realized NGL and natural gas prices in our Natural Gas Gathering and Processing segment, higher costs associated with the growth of our operations in the Natural Gas Gathering and Processing segment and higher employee-related costs associated with incentive and medical benefit plans in all three of our segments.

Capital expenditures decreased for the three and nine months ended September 30, 2016, compared with the same periods in 2015, due to projects placed in service in 2015, spending reductions to align with customer needs and lower well connect activities in our Natural Gas Gathering and Processing segment due to a reduction in drilling and completion activity.

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 nondiscretionary services to contracted producers in North Dakota, Montana, Wyoming, Kansas and Oklahoma. We provide exploration and production companies with gathering and processing services that allow them to move their raw (unprocessed) natural gas to market. Raw natural gas is gathered, compressed and transported through pipelines to our processing facilities. In order for the raw natural gas to be accepted by the downstream market, it must have contaminants removed, such as water, nitrogen and carbon dioxide, as well as NGLs separated for further processing. Processed natural gas, usually referred to as residue natural gas, is then recompressed and delivered to natural gas pipelines 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 formation, and is our most active region with continued volume growth and additional gathering and processing infrastructure needs. Our Mid-Continent region consists of Western Oklahoma, which includes the NGL-rich STACK and SCOOP areas, Cana-Woodford Shale, Woodford Shale, Springer Shale and the Mississippian Lime; and Southwest Kansas, which includes the Hugoton Basin, Central Kansas Uplift Basin and the Mississippian Lime. The Powder River Basin is primarily located in Wyoming, which includes the NGL-rich Niobrara Shale and Frontier, Turner and Sussex formations where our Sage Creek system provides gathering and processing services to customers in the southeast portion of Wyoming.

Revenues for this segment are derived primarily from POP contracts with fee components and fee-only contracts. Under a POP contract with fee components, we charge fees for gathering, treating, compressing and processing the producer’s natural gas, and retain a percentage of the proceeds from the sale of residue natural gas, condensate and/or NGLs. Over time as these contracts are renewed or restructured, we have generally increased the fee components and reduced the percent of proceeds retained from the sale of the commodities. 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, we expect our Natural Gas Gathering and Processing segment’s earnings to be more than 75 percent fee-based in 2016. These restructured contracts favorably impacted our results for the three and nine months ended September 30, 2016, and we expect

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to continue to receive the benefit of improved earnings from these contracts. Our NGLs, natural gas and crude oil commodity price sensitivity in this segment has continued to decrease in 2016 as a result of these restructured contracts. Additionally, we use commodity derivative instruments and physical-forward contracts to reduce our near-term sensitivity to fluctuations in the natural gas, crude oil and NGL commodity prices under POP with fee contracts. We will continue to seek opportunities to increase our fee-based earnings and reduce our commodity price exposure.

Our natural gas gathered and processed volumes in the Williston Basin increased for the nine months ended September 30, 2016, compared with the same period in 2015, despite the reductions in producer drilling activity, due to the following:


•	the opportunity to capture additional natural gas currently being flared by producers through natural gas compression and processing capacity placed in service in late 2015 and projects completed in 2016;


•	producers focusing their drilling and completion in the most productive areas in which we have significant gathering and processing assets, which typically produce at higher initial production rates compared with other areas and have higher natural gas to oil ratios; and


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

In the Mid-Continent region, our producer customers continue to focus their drilling and completion activities in the core STACK, SCOOP and Cana-Woodford areas of Oklahoma, and recent wells have shown strong results; however, several large multi-well pads previously scheduled to be completed in late 2015 and early 2016 have been delayed until fourth quarter 2016 or early 2017.

Growth Projects - Our Natural Gas Gathering and Processing segment invested in growth projects in NGL-rich areas in the Williston Basin, STACK and SCOOP areas, Cana-Woodford Shale, Woodford Shale and Springer Shale 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 in these areas 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.

In 2015 and 2016, we completed the following projects:



Completed Projects	Location	Capacity	Approximate Costs (a)	Completion Date
			(In millions)
Rocky Mountain Region
Lonesome Creek processing plant and infrastructure	Williston Basin	200 MMcf/d	$600	November 2015
Sage Creek infrastructure	Powder River Basin	Various	$35	December 2015
Natural gas compression	Williston Basin	100 MMcf/d	$75	December 2015
Bear Creek processing plant and infrastructure	Williston Basin	80 MMcf/d	$230-$250	August 2016
Stateline de-ethanizers	Williston Basin	26 MBbl/d	$85	September 2016

(a) - Excludes AFUDC.

We have the following natural gas processing plants and related infrastructure suspended:



Projects in Progress	Location	Capacity	Approximate Costs (a)	Expected Completion Date
			(In millions)
Rocky Mountain Region
Bronco processing plant and infrastructure	Powder River Basin	50 MMcf/d	$130-$200	Suspended
Demicks Lake processing plant and infrastructure	Williston Basin	200 MMcf/d	$475-$670	Suspended
Mid-Continent Region
Knox processing plant and infrastructure	SCOOP	200 MMcf/d	$240-$470	Suspended
Total			$845-$1,340

(a) - Excludes AFUDC.

As a result of reductions in crude oil and natural gas drilling by producers due to the decline in crude oil, natural gas and NGL prices and our expectation of slower supply growth or declines, in 2015 we suspended capital expenditures for certain natural gas processing plants and field infrastructure. We could resume our suspended capital-growth projects when market conditions

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improve and our customers’ needs change. If the current commodity price environment persists for a prolonged period, it may further impact the timing or demand for these projects and additional infrastructure projects or growth opportunities in the future.

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

Selected Financial Results - Our Natural Gas Gathering and Processing segment’s financial results for the three and nine months ended September 30, 2016, reflect the benefits from the completed projects in the table above. The lower commodity price environment continues to impact our 2016 financial results but the impact has been mitigated partially by restructured contracts, which became effective primarily in the fourth quarter 2015 and first quarter 2016. Additionally, with current market conditions, crude oil and natural gas producers are focusing their drilling activities in the most productive areas that are most economical to develop and have higher production volumes, which offsets partially the reduction in drilling activity.

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



	Three Months Ended						Nine Months Ended						Three Months					Nine Months
	September 30,						September 30,						2016 vs. 2015					2016 vs. 2015
Financial Results	2016			2015			2016			2015			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
NGL sales	$	134.9		$	118.7		$	381.9		$	423.1		$	16.2		14	%	$	(41.2	)	(10	%)
Condensate sales	13.8			12.3			41.4			39.9			1.5			12	%	1.5			4	%
Residue natural gas sales	186.8			211.2			481.1			635.6			(24.4		)	(12	%)	(154.5		)	(24	%)
Gathering, compression, dehydration and processing fees and other revenue	176.7			92.1			516.6			251.4			84.6			92	%	265.2			*
Cost of sales and fuel (exclusive of depreciation and items shown separately below)	(336.5		)	(293.6		)	(902.7		)	(947.5		)	42.9			15	%	(44.8		)	(5	%)
Operating costs	(69.4		)	(61.2		)	(208.4		)	(193.9		)	8.2			13	%	14.5			7	%
Equity in net earnings from investments	2.6			4.4			8.0			13.5			(1.8		)	(41	%)	(5.5		)	(41	%)
Other	0.9			(1.2		)	2.3			(0.8		)	2.1			*		3.1			*
Adjusted EBITDA	$	109.8		$	82.7		$	320.2		$	221.3		$	27.1		33	%	$	98.9		45	%
Capital expenditures	$	99.6		$	231.8		$	325.8		$	692.6		$	(132.2	)	(57	%)	$	(366.8	)	(53	%)

* Percentage change is greater than 100 percent.

See Reconciliation of Adjusted EBITDA to Net Income 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 $27.1 million for the three months ended September 30, 2016, compared with the same period in 2015, primarily as a result of the following:


•	an increase of $28.8 million due primarily to natural gas volume growth in the Williston Basin, offset partially by volume declines in the Mid-Continent region; and


•	an increase of $27.9 million due primarily to restructured contracts resulting in higher average fee rates, offset partially by a lower percentage of proceeds retained from the sale of commodities under our POP with fee contracts; offset partially by


•	a decrease of $21.7 million due primarily to lower net realized NGL, natural gas and condensate prices; and


•	an increase of $8.2 million in operating costs due primarily to increased labor and materials and supplies related to the growth of our operations resulting from completed capital-growth projects and higher employee-related costs associated with incentive and medical benefit plans.

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Adjusted EBITDA increased $98.9 million for the nine months ended September 30, 2016, compared with the same period in 2015, primarily as a result of the following:


•	an increase of $106.4 million due primarily to restructured contracts resulting in higher average fee rates, offset partially by a lower percentage of proceeds retained from the sale of commodities under our POP with fee contracts; and


•	an increase of $93.5 million due primarily to natural gas volume growth in the Williston Basin, offset partially by volume declines in the Mid-Continent region; offset partially by


•	a decrease of $80.2 million due primarily to lower net realized NGL and natural gas prices;


•	an increase of $14.5 million in operating costs due primarily to increased labor and materials and supplies related to the growth of our operations resulting from completed capital-growth projects and higher employee-related costs associated with incentive and medical benefit plans;


•	a decrease of $5.5 million due to lower equity earnings primarily related to our Powder River Basin equity investments; and


•	a decrease of $4.0 million due primarily to increased ethane recovery to maintain downstream NGL product specifications.

Capital expenditures decreased for the three and nine months ended September 30, 2016, compared with the same periods in 2015, due to projects placed in service in 2015, spending reductions to align with customer needs and lower well connect activities due to a reduction in drilling and completion activity.

See “Capital Expenditures” in “Liquidity and Capital Resources” for additional detail of our projected capital expenditures.

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				Nine Months Ended
	September 30,				September 30,
Operating Information (a)	2016		2015		2016		2015
Natural gas gathered (BBtu/d)	1,977		1,897		2,047		1,877
Natural gas processed (BBtu/d) (b)	1,829		1,617		1,886		1,640
NGL sales (MBbl/d)	153		134		155		123
Residue natural gas sales (BBtu/d)	837		837		877		828
Realized composite NGL net sales price ($/gallon) (c) (d)	$	0.23	$	0.31	$	0.22	$	0.35
Realized condensate net sales price ($/Bbl) (c) (e)	$	41.13	$	42.32	$	36.91	$	35.80
Realized residue natural gas net sales price ($/MMBtu) (c) (e)	$	2.84	$	3.62	$	2.76	$	3.64
Average fee rate ($/MMBtu)	$	0.76	$	0.43	$	0.73	$	0.39

(a) - Includes volumes for consolidated entities only.

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

(d) - Net of transportation and fractionation costs.

(e) - Net of transportation costs.

Natural gas gathered, natural gas processed and NGL sales increased during the three months ended September 30, 2016, compared with the same period in 2015, due to the completion of capital-growth projects in the Williston Basin, offset partially by natural gas volume declines in the Mid-Continent region.

Natural gas gathered, natural gas processed, NGL sales and residue natural gas sales increased during the nine months ended September 30, 2016, compared with the same period in 2015, due to the completion of capital-growth projects in the Williston Basin, offset partially by weather events in the Williston Basin and natural gas volume declines in the Mid-Continent region.

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. Beginning in June 2015, we increased the level of ethane recovery in the Rocky Mountain region to address downstream NGL product specifications.

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	Three Months Ended		Nine Months Ended
	September 30,		September 30,
Equity Volume Information (a)	2016	2015	2016	2015

NGL sales - including ethane (MBbl/d)	13.6	24.9	15.3	21.0
Condensate sales (MBbl/d)	2.2	2.7	2.5	3.0
Residue natural gas sales (BBtu/d)	82.3	136.3	81.3	141.6

(a) - Includes volumes for consolidated entities only.

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 nondiscretionary 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, which extract unfractionated NGLs from unprocessed natural gas, are connected to our gathering systems. We own and operate truck- and rail-loading and -unloading facilities connected to our natural gas liquids fractionation, storage and pipeline assets.

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.

Earnings for our Natural Gas Liquids segment are derived primarily from nondiscretionary 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 and storage services, transportation services, and optimization and marketing, which are defined as follows:

•

Our exchange and storage services utilize our assets to gather, fractionate and/or treat, and transport unfractionated NGLs, thereby converting them into marketable NGL products that are stored and 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. Although our exchange services activities are primarily fee-based, we capture certain product price differentials as volumes are fractionated. Our storage activities consist primarily of fee-based NGL storage services at our Mid-Continent and Gulf Coast storage facilities.


•	Our transportation services transport, primarily by pipeline, NGL products and refined petroleum products, primarily under FERC-regulated tariffs. Tariffs specify the maximum rates we charge our customers and the general terms and conditions for NGL transportation service on our pipelines.

•

Our optimization and marketing activities 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.

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Excess NGL supply continues to result in narrow NGL location price differentials between the Mid-Continent and Gulf Coast market centers. We expect these narrow price differentials to persist between the Conway, Kansas, and Mont Belvieu, Texas, market centers, as a result of NGL production from various NGL-rich shale areas throughout the country, until demand for NGLs increases from petrochemicals and exporters, which we anticipate to begin in 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 natural gas liquids gathering system in the Mid-Continent and Rocky Mountain regions during 2015 and 2016, which reduced natural gas liquids volumes gathered, fractionated, transported and sold across our assets. Through ethane rejection, natural gas processors leave much of the ethane component in the natural gas stream sold at the tailgate of natural gas processing plants. Ethane rejection levels by natural gas processors delivering to our natural gas liquids gathering system have continued to fluctuate and have averaged more than 175 MBbl/d during the first nine months of 2016, primarily in the Mid-Continent region. While the volume of ethane recovered increased modestly during the three and nine months ended September 30, 2016, compared with the same periods in 2015, 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 rejection levels to continue to fluctuate for the remainder of 2016 as the market begins to balance ethane supply and demand and with changes in the price differentials between ethane and natural gas. We expect ethane recovery levels to increase as ethylene producers and NGL exporters increase their capacity to consume and export additional ethane feedstock volumes. Ethane demand is expected to ramp up as new world-scale ethylene production projects, petrochemical plant modifications, plant expansions and export facilities near completion and begin coming on line in 2017.

Despite the ethane rejection across our system, beginning in June 2015, our Natural Gas Gathering and Processing segment increased its level of ethane recovery in the Williston Basin to alleviate downstream NGL product specification issues, which offsets partially the financial impact of ethane rejection. We expect this increased ethane recovery to continue throughout 2016 and 2017. In addition, 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 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. Expansion of the petrochemical industry in the United States is expected to increase ethane demand significantly beginning in 2017, and international demand for NGLs, particularly ethane and propane, also is increasing.

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

In April 2015, we completed the NGL Pipeline and Hutchinson Fractionator infrastructure project for approximately $120 million, excluding AFUDC.

We have the following projects in various stages of construction:



Projects in Progress	Location	Capacity	Approximate Costs (a)	Expected Completion Date
			(In millions)
Bakken NGL Pipeline expansion - Phase II	Rocky Mountain Region	25 MBbl/d	$100	Third quarter 2018
Bronco NGL infrastructure	Powder River Basin	65 miles	$45-$60	Suspended
Demicks Lake NGL infrastructure	Williston Basin	12 miles	$10-$15	Suspended
Total			$155-$175

(a) - Excludes AFUDC.

As a result of reductions in crude oil and natural gas drilling activities and our expectation of continued slower supply growth or declines due to the lower crude oil, natural gas and NGL prices, we have suspended capital expenditures for certain natural gas liquids infrastructure projects related to planned natural gas processing plants. We could resume our suspended capital-

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growth projects when market conditions improve and our customers’ needs change. If the current commodity price environment persists for a prolonged period, it may further impact the timing or demand for these projects and additional infrastructure projects or growth opportunities in the future.

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						Nine Months Ended						Three Months					Nine Months
	September 30,						September 30,						2016 vs. 2015					2016 vs. 2015
Financial Results	2016			2015			2016			2015			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	1,649.6		$	1,253.1		$	4,264.1		$	3,965.2		$	396.5		32	%	$	298.9		8	%
Exchange service and storage revenues	346.4			313.2			1,004.0			861.8			33.2			11	%	142.2			17	%
Transportation revenues	43.3			45.1			130.5			129.4			(1.8		)	(4	%)	1.1			1	%
Cost of sales and fuel (exclusive of depreciation and items shown separately below)	(1,694.2		)	(1,289.6		)	(4,376.3		)	(4,054.0		)	404.6			31	%	322.3			8	%
Operating costs	(79.8		)	(74.5		)	(236.7		)	(234.1		)	5.3			7	%	2.6			1	%
Equity in net earnings from investments	14.0			10.9			41.2			27.6			3.1			28	%	13.6			49	%
Other	—			(2.5		)	(0.8		)	(2.9		)	2.5			100	%	2.1			72	%
Adjusted EBITDA	$	279.3		$	255.7		$	826.0		$	693.0		$	23.6		9	%	$	133.0		19	%
Capital expenditures	$	30.5		$	52.8		$	85.5		$	185.4		$	(22.3	)	(42	%)	$	(99.9	)	(54	%)

See Reconciliation of Adjusted EBITDA to Net Income in the “Adjusted EBITDA” section.

Adjusted EBITDA increased $23.6 million for the three months ended September 30, 2016, compared with the same period in 2015, primarily as a result of the following:


•	an increase of $22.9 million in exchange, transportation and storage services, which includes:


◦	a $10.4 million increase due to increased exchange service volumes from recently connected natural gas processing plants primarily in the Williston Basin, offset partially by decreased Mid-Continent volumes gathered from the Barnett Shale and lower short-term contracted volumes;


◦	a $10.3 million increase from increased ethane recovery, which increased NGL exchange service volumes gathered and fractionated; and


◦	a $4.2 million increase related to higher storage activities; offset partially by


◦	a $1.8 million decrease in transportation revenues due primarily to lower volumes on West Texas Pipeline;


•	an increase of $3.2 million related to higher isomerization volumes, resulting from wider NGL product price differentials between normal butane and iso-butane; and


•	an increase of $3.1 million in equity in net earnings from investments due primarily to higher volumes delivered to Overland Pass Pipeline from our Bakken NGL Pipeline; offset partially by


•	an increase of $5.3 million in operating costs due primarily to higher employee-related costs associated with incentive and medical benefit plans; and


•	a decrease of $4.8 million in optimization and marketing activities, which resulted from a $5.9 million decrease due primarily to narrower marketing product price differentials, offset partially by a $1.1 million increase due primarily to higher optimization volumes.

Adjusted EBITDA increased $133.0 million for the nine months ended September 30, 2016, compared with the same period in 2015, primarily as a result of the following:


•	an increase of $114.9 million in exchange, transportation and storage services, which includes:


◦	a $53.8 million increase due to increased exchange service volumes from recently connected natural gas processing plants primarily in the Williston Basin, offset partially by decreased Mid-Continent volumes gathered from the Barnett Shale and lower short-term contracted volumes;

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◦	a $49.0 million increase from increased ethane recovery, which increased NGL exchange service volumes gathered and fractionated; and


◦	a $7.2 million increase related to higher storage activities;


•	an increase of $13.6 million in equity in net earnings from investments due primarily to higher volumes delivered to Overland Pass Pipeline from our Bakken NGL Pipeline; and


•	an increase of $4.0 million related to higher isomerization volumes, resulting from wider NGL product price differentials between normal butane and iso-butane; offset partially by


•	an increase of $2.6 million in operating costs due primarily to higher employee-related costs primarily associated with incentive and medical benefit plans, offset partially by lower outside services costs due to lower rates charged by service providers and timing of ad valorem tax accruals.

Capital expenditures decreased for the three and nine months ended September 30, 2016, compared with the same periods in 2015, due primarily to spending reductions to align with customer needs.

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



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Operating Information	2016		2015		2016		2015
NGL sales (MBbl/d)	852		683		778		657
NGLs transported-gathering lines (MBbl/d) (a)	775		786		778		759
NGLs fractionated (MBbl/d) (b)	606		591		588		540
NGLs transported-distribution lines (MBbl/d) (a)	521		456		504		422
Average Conway-to-Mont Belvieu OPIS price differential - ethane in ethane/propane mix ($/gallon)	$	0.03	$	0.02	$	0.03	$	0.02

(a) - Includes volumes for consolidated entities only.

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

NGLs transported on gathering lines decreased for the three months ended September 30, 2016, compared with the same period in 2015, due to decreased volumes on the West Texas LPG system, decreased Mid-Continent volumes gathered from the Barnett Shale and lower short-term contracted volumes, offset partially by increased volumes from new plant connections primarily in the Williston Basin and increased ethane recovery.

NGLs transported on gathering lines increased for the nine months ended September 30, 2016, compared with the same period in 2015, due to increased volumes from new plant connections primarily in the Williston Basin and increased ethane recovery, offset partially by decreased volumes on the West Texas LPG system, decreased Mid-Continent volumes gathered from the Barnett Shale and lower short-term contracted volumes.

NGLs fractionated increased for the three and nine months ended September 30, 2016, compared with the same periods in 2015, due primarily to increased volumes from new plant connections in the Williston Basin and increased ethane recovery.

While the volume of ethane recovered increased for the three and nine months ended September 30, 2016, compared with the same periods in 2015, 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 and nine months ended September 30, 2016, compared with the same periods in 2015, 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, its 50 percent ownership in Northern Border Pipeline and its 50 percent ownership in Roadrunner. Phase I and Phase II of the Roadrunner pipeline were completed in March and October 2016, respectively.

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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 at the Chicago Hub near Joliet, Illinois, that have access to both the Utica Shale and Marcellus Shale;


•	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 producing formations, including the STACK and SCOOP areas, Cana-Woodford Shale, Woodford Shale, Springer Shale, Granite Wash and Mississippian Lime. 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 the Delaware and Cline 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 natural gas producing formations in south central Kansas.

Through our Roadrunner joint venture, Roadrunner 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, 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. Phase II of the Roadrunner pipeline, which was completed in October 2016, provides additional delivery capacity to these markets in Mexico.

Transportation Rates - 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 for services regardless of usage. Under this type of contract, the customer pays a 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 storage, typically for monthly or seasonal terms. Customers reserve the right to

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park or loan natural gas based on a specified quantity, including injection and withdrawal rights when capacity is available.

Growth Projects - The following projects are in various stages of construction. Roadrunner is a 50 percent-owned joint venture equity-method investment project. The WesTex pipeline expansion is a wholly owned project.



Growth Projects	Location	Capacity	Approximate Costs (a)	Completion Date (c)
			(In millions)
WesTex pipeline expansion - Completed	Permian Basin	260 MMcf/d	$55	October 2016
Roadrunner Gas Transmission Pipeline - Equity-Method Investment
Phase I - Completed (b)	Permian Basin	170 MMcf/d	$200	March 2016
Phase II - Completed (b)	Permian Basin	400 MMcf/d	$210	October 2016
Phase III (b)	Permian Basin	70 MMcf/d	$30-$40	2019
Roadrunner Gas Transmission Pipeline Total			$440-$450

(a) - Excludes AFUDC.

(b) - 50-50 joint venture equity-method investment. Approximate costs represents total project costs, which are expected to be financed with approximately 50 percent equity contributions and 50 percent debt issued by Roadrunner. We expect to make equity contributions for approximately 25 percent of the total project costs.

WesTex pipeline expansion - In October 2016, the WesTex pipeline expansion was completed ahead of original schedule and below cost estimates. This expansion increased the pipeline capacity by 260 MMcf/d.

Roadrunner - In October 2016, Phase II of the Roadrunner pipeline was completed ahead of original schedule and below cost estimates. This phase increased the pipeline’s capacity by 400 MMcf/d to 570 MMcf/d. In 2015, Roadrunner entered into a $230 million senior secured credit facility for the construction and operation of the pipeline. The senior secured credit facility expires in the fourth quarter 2023. In addition, Roadrunner executed interest-rate swaps to hedge the variability of its interest payments during the term of the credit facility. Roadrunner’s credit facility is nonrecourse to ONEOK and ONEOK Partners, and neither ONEOK nor ONEOK Partners guarantees Roadrunner’s debts or obligations under the credit facility. We contributed approximately $55 million to Roadrunner in the nine months ended September 30, 2016, and approximately $30 million in the year ended December 31, 2015. We expect to contribute an additional $10 million to Roadrunner during the remainder of 2016.

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						Nine Months Ended						Three Months					Nine Months
	September 30,						September 30,						2016 vs. 2015					2016 vs. 2015
Financial Results	2016			2015			2016			2015			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Transportation revenues	$	71.9		$	63.7		$	208.5		$	193.5		$	8.2		13	%	$	15.0		8	%
Storage revenues	13.3			14.2			44.0			42.4			(0.9		)	(6	%)	1.6			4	%
Natural gas sales and other revenues	6.9			5.1			13.6			10.8			1.8			35	%	2.8			26	%
Cost of sales and fuel (exclusive of depreciation and items shown separately below)	(6.9		)	(7.6		)	(15.9		)	(28.1		)	(0.7		)	(9	%)	(12.2		)	(43	%)
Operating costs	(28.4		)	(26.7		)	(85.1		)	(79.1		)	1.7			6	%	6.0			8	%
Equity in net earnings from investments	18.6			17.0			51.2			52.1			1.6			9	%	(0.9		)	(2	%)
Other	4.9			(0.5		)	6.9			9.5			5.4			*		(2.6		)	(27	%)
Adjusted EBITDA	$	80.3		$	65.2		$	223.2		$	201.1		$	15.1		23	%	$	22.1		11	%
Capital expenditures	$	24.5		$	14.7		$	71.7		$	39.9		$	9.8		67	%	$	31.8		80	%

* Percentage change is greater than 100 percent.

See Reconciliation of Adjusted EBITDA to Net Income in the “Adjusted EBITDA” section.

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Adjusted EBITDA increased $15.1 million for the three months ended September 30, 2016, compared with the same period in 2015, primarily as a result of the following:


•	an increase of $8.0 million from higher transportation services due primarily to increased firm demand charge volumes contracted;


•	an increase of $4.0 million due to higher natural gas storage services primarily as a result of the sale of excess natural gas in storage in 2016; and


•	an increase of $2.5 million from higher net retained fuel due primarily to higher throughput and the associated natural gas volumes retained; offset partially by


•	an increase of $1.7 million in operating costs due primarily to increased employee-related costs associated with incentive and medical benefit plans.

Adjusted EBITDA increased $22.1 million for the nine months ended September 30, 2016, compared with the same period in 2015, primarily as a result of the following:


•	an increase of $17.1 million from higher transportation services due primarily to increased firm demand charge volumes contracted;


•	an increase of $10.0 million due to higher natural gas storage services as a result of increased rates and the sale of excess natural gas in storage in 2016; and


•	an increase of $2.3 million from higher net retained fuel due to higher throughput and the associated natural gas volumes retained, offset partially by lower natural gas prices; offset partially by


•	an increase of $6.0 million in operating costs due primarily to increased employee-related costs associated with incentive and medical benefit plans.

Capital expenditures increased for the three and nine months ended September 30, 2016, compared with the same periods in 2015, due primarily to our WesTex pipeline expansion and other expansion 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						Nine Months Ended
	September 30,						September 30,
Operating Information (a)	2016			2015			2016			2015
Natural gas transportation capacity contracted (MDth/d)	6,300			5,739			6,240			5,797
Transportation capacity contracted	95		%	90		%	94		%	91		%
Average natural gas price
Mid-Continent region ($/MMBtu)	$	2.60		$	2.59		$	2.12		$	2.56

(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 resulting in narrower location and seasonal price differentials. As additional supply is developed, we expect crude oil and natural gas producers to demand incremental services in the future to transport their production to market. The abundance of natural gas supply and new 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, we expect our fee-based earnings in this segment to increase 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. Roadrunner, in which we have a 50 percent ownership interest, has contracted all of its capacity for both Phase I and Phase II through the first quarter 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 and AFUDC and other noncash items. We believe this non-GAAP financial measure is useful to investors because it is 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 our financial performance with the performance of other publicly

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traded partnerships within 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 Adjusted EBITDA for the three and nine months ended September 30, 2016 and 2015, to net income, which is the nearest comparable GAAP financial measure, is as follows:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Unaudited)	2016			2015			2016			2015
Reconciliation of Adjusted EBITDA to Net Income	(Thousands of dollars)
Segment Adjusted EBITDA:
Natural Gas Gathering and Processing	$	109,837		$	82,718		$	320,170		$	221,298
Natural Gas Liquids	279,256			255,745			826,036			692,991
Natural Gas Pipelines	80,304			65,166			223,185			201,112
Other	(42		)	53			358			(144		)
Total	469,355			403,682			1,369,749			1,115,257
Depreciation and amortization	(97,802		)	(87,517		)	(290,045		)	(259,563		)
Interest expense, net of capitalized interest	(92,521		)	(86,666		)	(278,339		)	(253,867		)
Income tax (expense) benefit	(3,681		)	156			(8,079		)	(5,080		)
AFUDC and other	60			10			375			(8,440		)
Net income	$	275,411		$	229,665		$	793,661		$	588,307

CONTINGENCIES

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. As of September 30, 2016, we had $5.5 million of cash on hand and available capacity under our Partnership Credit Agreement of $1.7 billion. In addition, in the first quarter 2016, we drew the full $1.0 billion available under our Term Loan Agreement that matures in January 2019.

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 expect to utilize our commercial paper program, Partnership Credit Agreement, Term Loan Agreement and cash from operations to fund our announced capital-growth expenditures, refinance our senior notes maturities and meet our working capital needs through 2016 and well into 2017. However, we may access the capital markets to issue debt or equity securities prior to that time as we consider prudent to provide liquidity for new capital projects, to maintain investment-grade credit ratings or for other partnership purposes.

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

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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, Partnership Credit Agreement and our “at-the-market” equity program.

We had working capital (defined as current assets less current liabilities) deficits of $1.2 billion and $697 million as of September 30, 2016, and December 31, 2015, 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 September 30, 2016, was driven primarily by our current maturities of long-term debt and capital-growth projects. Our working capital deficit at December 31, 2015, was driven primarily by our capital-growth projects. 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 September 30, 2016, we had $694 million commercial paper outstanding, $14 million of letters of credit issued and no borrowings outstanding under our Partnership Credit Agreement. At September 30, 2016, we had approximately $5.5 million of cash and cash equivalents and approximately $1.7 billion of credit available under the 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 borrowings 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.

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

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.

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 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 January 2016, we entered into the $1.0 billion senior unsecured delayed-draw Term Loan Agreement with a syndicate of banks. During the first quarter 2016, we drew the full $1.0 billion available under the agreement and used the proceeds to repay our $650 million, 3.25 percent 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 a margin that is based on the credit ratings assigned to our senior, unsecured, long-term indebtedness. Based on our current applicable credit rating, borrowings on the Term Loan Agreement will accrue at LIBOR plus 130 basis points. 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.

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In October 2016, we repaid our $450 million, 6.15 percent senior notes due October 1, 2016, 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 September 30, 2016, we had approximately $138 million of registered common units available for issuance through our “at-the-market” equity program.

During the three and nine months ended September 30, 2016, no common units were sold through our “at-the-market” equity program.

During the three months ended September 30, 2015, we completed a private placement of 21.5 million common units at a price of $30.17 per unit with ONEOK. Additionally, we completed a concurrent sale of approximately 3.3 million common units at a price of $30.17 per unit to funds managed by Kayne Anderson Capital Advisors in a registered direct offering, which were issued through our existing “at-the-market” equity program. The combined offerings generated net proceeds of approximately $749 million. In conjunction with these issuances, ONEOK Partners GP contributed approximately $15.3 million in order to maintain its 2 percent general partner interest in us. We used the proceeds for general partnership purposes, including capital expenditures and repayment of commercial paper borrowings. No other units were sold through the “at-the-market” program during the three months ended September 30, 2015.

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

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 were $489.4 million and $928.9 million for the nine months ended September 30, 2016 and 2015, respectively.

The following table sets forth our 2016 projected growth and maintenance capital expenditures, excluding acquisitions, contributions to our equity-method investments and AFUDC:



	Growth		Maintenance		Total
	(Millions of dollars)
Natural Gas Gathering and Processing	$	310	$	30	$	340
Natural Gas Liquids	70		40		110
Natural Gas Pipelines	80		30		110
Other	—		10		10
Total projected capital expenditures	$	460	$	110	$	570

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We expect our maintenance capital expenditures for 2016 to be approximately $110 million, compared with approximately $140 million disclosed in our Annual Report. The update primarily reflects lower than expected vendor and contractor costs, the delay of an NGL pipeline relocation project and the timing of discretionary information technology application upgrades.

Credit Ratings - Our long-term debt credit ratings are shown in the table below:



Rating Agency	Rating	Outlook
Moody’s	Baa2	Stable
S&P	BBB	Negative

Our commercial paper program is rated Prime-2 by Moody’s and A-2 by S&P. In October 2016, Moody’s affirmed our current credit ratings and revised our outlook to stable from negative, citing our considerable reduction of commodity price risk and focus on growth opportunities within our operating footprint. 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.

Declines in the energy commodity price environment and its impact on our results of operations and cash flows could cause the credit rating agencies to downgrade our credit ratings. If our credit ratings were downgraded, our cost to borrow funds under our commercial paper program or Partnership Credit Agreement would increase, and a potential loss of access to the commercial paper market could occur. In the event that we are unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we would continue to have access to our 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 and nine months ended September 30, 2016, and the three months ended September 30, 2015, our cash flow from operations exceeded our cash distributions to our general partner and limited partners. Our cash flow from operations increased in the first nine months of 2016, compared with the same period in 2015, due primarily to our contract restructuring in our Natural Gas Gathering and Processing segment and increased volumes in our Natural Gas Gathering and Processing and Natural Gas Liquids segments due to the completion of our capital-growth projects and new plant connections. For the nine months ended September 30, 2015, our cash distributions exceeded our cash flow 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.

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



	Nine Months Ended
	September 30,
	2016		2015
	(Millions of dollars)
Common unitholders	$	504.4	$	435.6
Class B unitholders	173.0		173.0
General partner	321.6		288.9
Noncontrolling interests	6.1		8.2
Total cash distributions paid	$	1,005.1	$	905.7

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In the nine months ended September 30, 2016 and 2015, cash distributions paid to our general partner included incentive distributions of $301.6 million and $271.0 million, respectively.

In October 2016, our general partner declared a cash distribution of $0.79 per unit ($3.16 per unit on an annualized basis) for the third quarter 2016, which will be paid on November 14, 2016, to unitholders of record at the close of business on October 31, 2016.

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.

Energy Commodity Prices - Although we are subject to some commodity price volatility, our commodity price exposure has been reduced due primarily to contract restructuring in our Natural Gas Gathering and Processing segment. We have also hedged a significant portion of our Natural Gas Gathering and Processing segment’s commodity price risk for 2016 and 2017 and have begun hedging commodity price risk for 2018. Significant fluctuations in commodity prices will affect our overall liquidity due to the impact commodity price changes have on our cash flows from operating activities, including the impact on working capital for NGLs and natural gas held in storage, margin requirements and certain energy-related receivables. 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 through 2016 and well into 2017. We believe that our available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity price volatility. See Note C of the Notes to Consolidated Financial Statements and the discussion under “Commodity Price Risk” in Part I, Item 3, Quantitative and Qualitative Disclosures About Market Risk, in this Quarterly Report for information on our hedging activities.

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
	Nine Months Ended						2016 vs. 2015
	September 30,						Increase (Decrease)
	2016			2015			Increase (Decrease)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	999.4		$	747.1		$	252.3
Investing activities	(482.5		)	(940.7		)	458.2
Financing activities	(516.5		)	158.4			(674.9		)
Change in cash and cash equivalents	0.4			(35.2		)	35.6
Cash and cash equivalents at beginning of period	5.1			42.5			(37.4		)
Cash and cash equivalents at end of period	$	5.5		$	7.3		$	(1.8	)

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 $1.1 billion for the nine months ended September 30, 2016, compared with $849.7 million for the same period in 2015. The increase is due primarily to higher natural gas gathered and NGL volumes from our completed capital-growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments and higher fees resulting from contract restructuring in our Natural Gas

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Gathering and Processing segment, offset partially by lower commodity prices, as discussed in “Financial Results and Operating Information.”

The changes in operating assets and liabilities decreased operating cash flows $88.2 million for the nine months ended September 30, 2016, compared with a decrease of $102.6 million for the same period in 2015. 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; and the change in natural gas and NGLs in storage, which vary from period to period and vary with changes in commodity prices.

Investing Cash Flows - Cash used in investing activities decreased to $482.5 million for the nine months ended September 30, 2016, compared with $940.7 million for the same period in 2015, due primarily to lower capital spending as a result of spending reductions to align with customer needs and projects placed in service, higher proceeds received from sale of assets and higher distributions received from unconsolidated affiliates, offset partially by higher contributions to our Roadrunner joint venture.

Financing Cash Flows - Cash used in financing activities was $516.5 million for the nine months ended September 30, 2016, compared with cash provided by financing activities of $158.4 million for the nine months ended September 30, 2015, a decrease of approximately $675 million. The decrease was due primarily to repayment of our $650 million, 3.25 percent senior notes, which matured February 1, 2016. The remaining difference primarily relates to the net impact of changes in short-term borrowings, long-term debt and equity issuances for the nine months ended September 30, 2016, compared with the same period in 2015, as described below.

During the nine months ended September 30, 2016, we received long-term debt proceeds of $1.0 billion related to our Term Loan Agreement. During the nine months ended September 30, 2015, we raised capital through debt and equity issuances related to our $800 million senior notes offering and approximately $1.0 billion from equity issuances, respectively. This decrease in financing cash inflow was offset by an increase of approximately $900 million in short-term borrowings due to the net impact of borrowing and repayment activity in our commercial paper program.

REGULATORY, ENVIRONMENTAL AND SAFETY MATTERS

Environmental Matters - We are subject to multiple environmental, historical preservation and wildlife preservation 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 materially affect 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.

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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 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 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, equity markets, inflation rates, economic recession and other external factors over which we have no control;


•	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;

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

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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 “Financial Results and Operating Information” under the Natural Gas Gathering and Processing segment section in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, to minimize the impact of near-term price fluctuations related to 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 receiving commodities as a portion of our compensation for services 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:



	Three Months Ending December 31, 2016
	Volumes Hedged	Average Price			Percentage Hedged
NGLs - excluding ethane (MBbl/d) - Conway/Mont Belvieu	8.8	$	0.48	/ gallon	83%
Condensate (MBbl/d) - WTI-NYMEX	1.8	$	58.68	/ Bbl	79%
Natural gas (BBtu/d) - NYMEX and basis	77.8	$	2.82	/ MMBtu	93%



	Year Ending December 31, 2017
	Volumes Hedged	Average Price			Percentage Hedged
NGLs - excluding ethane (MBbl/d) - Conway/Mont Belvieu	8.0	$	0.51	/ gallon	67%
Condensate (MBbl/d) - WTI-NYMEX	1.8	$	44.88	/ Bbl	74%
Natural gas (BBtu/d) - NYMEX and basis	73.1	$	2.66	/ MMBtu	74%



	Year Ending December 31, 2018
	Volumes Hedged	Average Price			Percentage Hedged
Natural gas (BBtu/d) - NYMEX and basis	25.9	$	2.83	/ MMBtu	32%

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 September 30, 2016. 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 three months ending December 31, 2016, and for the year ending December 31, 2017, by approximately $0.2 million and $1.0 million, respectively;


•	a $1.00 per-barrel change in the price of crude oil would change adjusted EBITDA for the three months ending December 31, 2016, and for the year ending December 31, 2017, by approximately $0.1 million and $0.4 million, respectively; and


•	a $0.10 per-MMBtu change in the price of residue natural gas would change adjusted EBITDA for the three months ending December 31, 2016, for the year ending December 31, 2017, and for the year ending December 31, 2018, by approximately $0.1 million, $0.9 million and $2.0 million, respectively.

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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.

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



	Three Months Ending December 31, 2016
	Volumes Hedged	Average Strike Price			Fair Value Asset at September 30, 2016
					(Millions of dollars)
Natural gas (BBtu/d) - NYMEX	232.8	$	2.35	/ MMBtu	$	0.1



	Year Ending December 31, 2017
	Volumes Hedged	Average Strike Price			Fair Value Asset at September 30, 2016
					(Millions of dollars)
Natural gas (BBtu/d) - NYMEX	147.9	$	2.47	/ MMBtu	$	4.5

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

INTEREST-RATE RISK

We are exposed to interest-rate risk through our Partnership Credit Agreement, commercial paper program 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 September 30, 2016, we had interest-rate swaps with notional amounts totaling $1.0 billion to hedge the variability of our LIBOR-based interest payments. In addition, in June 2016, we entered into forward-starting interest-rate swaps with notional amounts totaling $750 million 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, resulting in total notional amounts of this type of interest-rate swap of $1.2 billion at September 30, 2016, compared with $400 million at December 31, 2015. All of our interest-rate swaps are designated as cash flow hedges. At September 30, 2016, we had $69.1 million of derivative liabilities related to these interest-rate swaps. At December 31, 2015, we had derivative liabilities of $9.9 million related to these interest-rate swaps.

See Note C of the Notes to Consolidated Financial Statements in this Quarterly Report for 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 depressed 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 and nine months ended September 30, 2016 and 2015, we had no single customer from which we received 10 percent or more of our consolidated revenues, and only 23 customers individually represented 1 percent or more of our consolidated revenues, the majority of which are investment-grade customers, as rated by S&P or 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 exploration and production customers under POP with fee contracts as we receive

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proceeds from the sale of commodities and remit a portion of those proceeds back to the crude oil and natural gas producers. For the nine months ended September 30, 2016, 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 or Moody’s, or our comparable internal ratings, or 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 nine months ended September 30, 2016, approximately 81 percent of our commodity sales were made to investment-grade customers, as rated by S&P or Moody’s, or our comparable internal ratings, or secured by 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 nine months ended September 30, 2016, approximately 87 percent of our revenues in this segment were from investment-grade customers, as rated by S&P or Moody’s, or our comparable internal ratings, or secured by letters of credit or other collateral. In addition, the majority of our Natural Gas Pipeline 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 September 30, 2016, 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

Information about our legal proceedings is provided in Note K of the Notes to Consolidated Financial Statements under Part I, Item 1 of this Quarterly Report. Additional information about our legal proceedings is included 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.

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ITEM 4.	MINE SAFETY DISCLOSURES

Not applicable.


ITEM 5.	OTHER INFORMATION

Not applicable.


ITEM 6.	EXHIBITS

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

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


Exhibit No.	Exhibit Description


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 and nine months ended September 30, 2016 and 2015; (iii) Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2016 and 2015; (iv) Consolidated Balance Sheets at September 30, 2016, and December 31, 2015; (v) Consolidated Statements of Cash Flows for the nine months ended September 30, 2016 and 2015; (vi) Consolidated Statements of Changes in Equity for the nine months ended September 30, 2016 and 2015; 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: November 2, 2016		By:	/s/ Derek S. Reiners
			Derek S. Reiners
			Senior Vice President,
			Chief Financial Officer and Treasurer
			(Signing on behalf of the Registrant)

ONEOK Partners LP - FORM 10-Q - November 2, 2016

Attached files

ONEOK Partners LP Reports