ONEOK Partners LP - FORM 10-Q

Attached files

file	filename
EX-32.2 - OKS CERTIFICATION OF REINERS SECTION 906 - ONEOK Partners LP	oksq32015exhibit322.htm
EX-32.1 - OKS CERTIFICATION OF SPENCER SECTION 906 - ONEOK Partners LP	oksq32015exhibit321.htm
EX-31.2 - OKS CERTIFICATION OF REINERS SECTION 302 - ONEOK Partners LP	oksq32015exhibit312.htm
EX-31.1 - OKS CERTIFICATION OF SPENCER SECTION 302 - ONEOK Partners LP	oksq32015exhibit311.htm

Table of Contents

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, 2015.

___ 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 26, 2015
Common units		212,837,980 units
Class B units		72,988,252 units

Table of Contents

This page intentionally left blank.

Table of Contents

ONEOK PARTNERS, L.P.

TABLE OF CONTENTS



Part I.	Financial Information	Page No.
Item 1.	Financial Statements (Unaudited)	6
	Consolidated Statements of Income - Three and Nine Months Ended September 30, 2015 and 2014	6
	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2015 and 2014	7
	Consolidated Balance Sheets - September 30, 2015 and December 31, 2014	8
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2015 and 2014	9
	Consolidated Statement of Changes in Equity - Nine Months Ended September 30, 2015 and 2014	10
	Notes to Consolidated Financial Statements	12
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	69
Item 4.	Controls and Procedures	70
Part II.	Other Information	70
Item 1.	Legal Proceedings	70
Item 1A.	Risk Factors	70
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	70
Item 3.	Defaults Upon Senior Securities	71
Item 4.	Mine Safety Disclosures	71
Item 5.	Other Information	71
Item 6.	Exhibits	71
Signature		73

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.

Table of Contents

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, 2014


ASU	Accounting Standards Update


Bbl	Barrels, 1 barrel is equivalent to 42 United States gallons


BBtu/d	Billion British thermal units per day


Bcf	Billion cubic feet


Bcf/d	Billion cubic feet per day


CFTC	U.S. Commodity Futures Trading Commission


Clean Air Act	Federal Clean Air Act, as amended


Clean Water Act	Federal Water Pollution Control Act Amendments of 1972, as amended


DOT	United States Department of Transportation


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


FASB	Financial Accounting Standards Board


FERC	Federal Energy Regulatory Commission


GAAP	Accounting principles generally accepted in the United States of America


GHG	Greenhouse gas


Intermediate Partnership	ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary of

ONEOK Partners, L.P.


LIBOR	London Interbank Offered Rate


MBbl/d	Thousand barrels per day


MDth/d	Thousand dekatherms per day


MMBbl	Million barrels


MMBtu	Million British thermal units


MMcf/d	Million cubic feet per day


Moody’s	Moody’s Investors Service, Inc.


Natural Gas Policy Act	Natural Gas Policy Act of 1978, as amended


NGL(s)	Natural gas liquid(s)


NGL products	Marketable natural gas liquids 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


ONE Gas	ONE Gas, Inc.


ONEOK	ONEOK, Inc.


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

dated 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


S&P	Standard & Poor’s Ratings Services


SCOOP	South Central Oklahoma Oil Province

Table of Contents


SEC	Securities and Exchange Commission


West Texas LPG	West Texas LPG Pipeline Limited Partnership and Mesquite Pipeline


WTI	West Texas Intermediate


XBRL	eXtensible Business Reporting Language

Table of Contents



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)	2015			2014			2015			2014
	(Thousands of dollars, except per unit amounts)
Revenues
Commodity sales	$	1,484,350		$	2,754,495		$	4,642,320		$	8,276,333
Services	414,068			364,874			1,188,364			1,071,074
Total revenues	1,898,418			3,119,369			5,830,684			9,347,407
Cost of sales and fuel	1,360,809			2,583,204			4,307,766			7,807,275
Net margin	537,609			536,165			1,522,918			1,540,132
Operating expenses
Operations and maintenance	145,933			152,533			444,185			425,715
Depreciation and amortization	87,517			73,901			259,563			212,083
General taxes	16,158			18,252			62,677			55,898
Total operating expenses	249,608			244,686			766,425			693,696
Gain (loss) on sale of assets	(443		)	1,534			(327		)	1,533
Operating income	287,558			293,013			756,166			847,969
Equity in net earnings (loss) from investments (Note J)	32,244			(52,347		)	93,205			6,747
Allowance for equity funds used during construction	177			1,723			1,718			13,947
Other income	41			79			106			3,003
Other expense	(3,845		)	(2,496		)	(3,941		)	(3,056		)
Interest expense (net of capitalized interest of $8,851, $14,303, $26,008 and $41,446, respectively)	(86,666		)	(70,060		)	(253,867		)	(211,344		)
Income before income taxes	229,509			169,912			593,387			657,266
Income tax (expense) benefit	156			(2,592		)	(5,080		)	(9,967		)
Net income	229,665			167,320			588,307			647,299
Less: Net income attributable to noncontrolling interests	2,704			73			5,982			226
Net income attributable to ONEOK Partners, L.P.	$	226,961		$	167,247		$	582,325		$	647,073
Limited partners’ interest in net income:
Net income attributable to ONEOK Partners, L.P.	$	226,961		$	167,247		$	582,325		$	647,073
General partner’s interest in net income	(105,078		)	(87,796		)	(293,868		)	(249,697		)
Limited partners’ interest in net income	$	121,883		$	79,451		$	288,457		$	397,376
Limited partners’ net income per unit, basic and diluted (Note I)	$	0.45		$	0.32		$	1.10		$	1.65
Number of units used in computation (thousands)	272,046			249,091			261,100			240,604

See accompanying Notes to Consolidated Financial Statements.

Table of Contents



ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(Unaudited)	2015			2014		2015			2014
	(Thousands of dollars)
Net income	$	229,665		$	167,320	$	588,307		$	647,299
Other comprehensive income (loss)
Unrealized gains (losses) on risk-management assets/liabilities	15,949			7,378		21,373			(81,592		)
Realized (gains) losses recognized in net income	(19,094		)	3,003		(43,785		)	39,845
Total other comprehensive income (loss)	(3,145		)	10,381		(22,412		)	(41,747		)
Comprehensive income	226,520			177,701		565,895			605,552
Less: Comprehensive income attributable to noncontrolling interests	2,704			73		5,982			226
Comprehensive income attributable to ONEOK Partners, L.P.	$	223,816		$	177,628	$	559,913		$	605,326

See accompanying Notes to Consolidated Financial Statements.

Table of Contents



ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	September 30,			December 31,
(Unaudited)	2015			2014
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	7,263		$	42,530
Accounts receivable, net	584,309			735,830
Affiliate receivables	4,764			8,553
Natural gas and natural gas liquids in storage	142,308			134,134
Commodity imbalances	30,602			64,788
Materials and supplies	62,604			55,833
Other current assets	53,261			44,385
Total current assets	885,111			1,086,053
Property, plant and equipment
Property, plant and equipment	14,234,678			13,377,617
Accumulated depreciation and amortization	2,075,061			1,842,084
Net property, plant and equipment	12,159,617			11,535,533
Investments and other assets
Investments in unconsolidated affiliates	1,137,059			1,132,653
Goodwill and intangible assets	827,852			822,358
Other assets	21,405			23,803
Total investments and other assets	1,986,316			1,978,814
Total assets	$	15,031,044		$	14,600,400
Liabilities and equity
Current liabilities
Current maturities of long-term debt (Note F)	$	657,650		$	7,650
Notes payable (Note E)	287,272			1,055,296
Accounts payable	612,939			874,692
Affiliate payables	21,318			36,106
Commodity imbalances	96,192			104,650
Accrued interest	89,498			91,990
Other current liabilities	141,493			165,672
Total current liabilities	1,906,362			2,336,056
Long-term debt, excluding current maturities	6,145,603			6,004,232
Deferred credits and other liabilities	155,607			141,337
Commitments and contingencies (Note L)
Equity (Note G)
ONEOK Partners, L.P. partners’ equity:
General partner	237,860			211,914
Common units: 212,837,980 and 180,826,973 units issued and outstanding at September 30, 2015, and December 31, 2014, respectively	5,252,840			4,456,372
Class B units: 72,988,252 units issued and outstanding at September 30, 2015, and December 31, 2014	1,281,731			1,374,375
Accumulated other comprehensive loss (Note H)	(114,235		)	(91,823		)
Total ONEOK Partners, L.P. partners’ equity	6,658,196			5,950,838
Noncontrolling interests in consolidated subsidiaries	165,276			167,937
Total equity	6,823,472			6,118,775
Total liabilities and equity	$	15,031,044		$	14,600,400

See accompanying Notes to Consolidated Financial Statements.

Table of Contents



ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Nine Months Ended
	September 30,
(Unaudited)	2015			2014
	(Thousands of dollars)
Operating activities
Net income	$	588,307		$	647,299
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	259,563			212,083
Allowance for equity funds used during construction	(1,718		)	(13,947		)
Loss (gain) on sale of assets	327			(1,533		)
Deferred income taxes	4,309			4,397
Equity in net earnings from investments	(93,205		)	(6,747		)
Distributions received from unconsolidated affiliates	92,042			84,298
Changes in assets and liabilities:
Accounts receivable	149,776			159,829
Affiliate receivables	3,789			3,256
Natural gas and natural gas liquids in storage	(8,174		)	(150,059		)
Accounts payable	(182,985		)	(33,945		)
Affiliate payables	(14,788		)	(18,076		)
Commodity imbalances, net	25,728			(36,094		)
Accrued interest	(2,492		)	(4,663		)
Risk-management assets and liabilities	(46,267		)	3,438
Other assets and liabilities, net	(27,186		)	37,519
Cash provided by operating activities	747,026			887,055
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	(928,870		)	(1,172,950		)
Cash paid for acquisitions	—			(14,000		)
Contributions to unconsolidated affiliates	(27,540		)	(1,063		)
Distributions received from unconsolidated affiliates in excess of cumulative earnings	25,111			24,925
Proceeds from sale of assets	3,171			2,388
Other	(12,607		)	—
Cash used in investing activities	(940,735		)	(1,160,700		)
Financing activities
Cash distributions:
General and limited partners	(897,474		)	(768,094		)
Noncontrolling interests	(8,192		)	(353		)
Borrowing (repayment) of notes payable, net	(768,024		)	—
Issuance of long-term debt, net of discounts	798,896			—
Debt financing costs	(7,676		)	—
Repayment of long-term debt	(5,738		)	(5,738		)
Issuance of common units, net of issuance costs	1,025,660			947,472
Contribution from general partner	20,990			19,857
Cash provided by financing activities	158,442			193,144
Change in cash and cash equivalents	(35,267		)	(80,501		)
Cash and cash equivalents at beginning of period	42,530			134,530
Cash and cash equivalents at end of period	$	7,263		$	54,029

See accompanying Notes to Consolidated Financial Statements.

Table of Contents



ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENT 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, 2015	180,826,973	72,988,252	$	211,914		$	4,456,372
Net income	—	—	293,868			208,119
Other comprehensive income (loss) (Note H)	—	—	—			—
Issuance of common units (Note G)	32,011,007	—	—			1,023,915
Contribution from general partner (Note G)	—	—	20,990			—
Distributions paid (Note G)	—	—	(288,912		)	(435,580		)
Other	—	—	—			14
September 30, 2015	212,837,980	72,988,252	$	237,860		$	5,252,840



	ONEOK Partners, L.P. Partners’ Equity
(Unaudited)	Common Units	Class B Units	General Partner			Common Units
	(Units)		(Thousands of dollars)
January 1, 2014	159,007,854	72,988,252	$	170,561		$	3,459,920
Net income	—	—	249,697			274,963
Other comprehensive income (loss) (Note H)	—	—	—			—
Issuance of common units (Note G)	18,346,627	—	—			955,108
Contribution from general partner (Note G)	—	—	19,760			—
Distributions paid (Note G)	—	—	(235,908		)	(369,057		)
September 30, 2014	177,354,481	72,988,252	$	204,110		$	4,320,934

Table of Contents



ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENT 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, 2015		$	1,374,375		$	(91,823	)	$	167,937		$	6,118,775
Net income		80,338			—			5,982			588,307
Other comprehensive income (loss) (Note H)		—			(22,412		)	—			(22,412		)
Issuance of common units (Note G)		—			—			—			1,023,915
Contribution from general partner (Note G)		—			—			—			20,990
Distributions paid (Note G)		(172,982		)	—			(8,192		)	(905,666		)
Other		—			—			(451		)	(437		)
September 30, 2015		$	1,281,731		$	(114,235	)	$	165,276		$	6,823,472



	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, 2014		$	1,422,516		$	(58,837	)	$	4,536		$	4,998,696
Net income		122,413			—			226			647,299
Other comprehensive income (loss) (Note H)		—			(41,747		)	—			(41,747		)
Issuance of common units (Note G)		—			—			—			955,108
Contribution from general partner (Note G)		—			—			—			19,760
Distributions paid (Note G)		(163,129		)	—			(353		)	(768,447		)
September 30, 2014		$	1,381,800		$	(100,584	)	$	4,409		$	5,810,669

See accompanying Notes to Consolidated Financial Statements.

Table of Contents

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 presentation of the results for the interim periods presented. All such adjustments are of a normal recurring nature. The 2014 year-end consolidated balance sheet data was derived from our audited financial statements but does not include all disclosures required by GAAP. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements in our Annual Report.

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

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. At July 1, 2015, we assessed qualitative factors to determine whether it was more likely than not that the fair value of each of our reporting units was less than its carrying amount. Due to the current commodity price environment, 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, 2015, 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 - In March 2015, the FASB issued ASU 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. In August 2015, the FASB issued ASU 2015-15, “Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements - Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting,” which amended the SEC paragraphs of ASC Subtopic 835-30 to include the language from the SEC Staff Announcement indicating that the SEC would not object to presenting deferred debt issuance costs related to line-of-credit agreements as assets and subsequently amortizing the deferred debt issuance costs ratably over the term of the agreement. This guidance is effective for public companies for fiscal years beginning after December 15, 2015, with early adoption permitted. We elected to adopt this guidance beginning in the second quarter 2015. Retrospective adjustment of prior periods presented was required. Therefore, the December 31, 2014, balance sheet was recast to reclassify $34.1 million of debt issuance costs from other assets to long-term debt. The impact of adopting this guidance was not material.

In April 2014, the FASB issued ASU 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity,” which alters the definition of a discontinued operation to include only asset disposals that represent a strategic shift with a major effect on an entity’s operations and financial results. The amendment also requires more extensive disclosures about a discontinued operation’s assets, liabilities, income, expenses and cash flows. This guidance will be effective for interim and annual periods for all assets that are disposed of or classified as being held for sale in fiscal years that begin on or after December 15, 2014. We adopted this guidance beginning in the first quarter 2015, and it could impact us in the future if we dispose of any individually significant components.

In September 2015, the FASB issued ASU 2015-16, “Business Combinations (Topic 805) - Simplifying the Accounting for Measurement-Period Adjustments,” which 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. The amendment also requires the acquirer to record the income statement effects of changes to provisional amounts in the financial statements in the period in which the adjustments occurred. This guidance is effective for public companies for fiscal years beginning after December 15, 2015, with early adoption permitted. We expect to adopt this guidance in the first quarter 2016, and it could impact us in the future if we complete any acquisitions with subsequent measurement period adjustments.

In April 2015, the FASB issued ASU 2015-05, “Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement,” which 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 not account for the

Table of Contents

arrangement as a service contract. This guidance is effective for public companies for fiscal years beginning after December 15, 2015. Early adoption is permitted. We expect to adopt this guidance in the first quarter 2016, and we do not expect it to materially impact us.

In February 2015, the FASB issued ASU 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” which 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. This guidance is effective for public companies for fiscal years beginning after December 15, 2015. We expect to adopt this guidance in the first quarter 2016, and we are evaluating the impact on us.

In August 2014, the FASB issued ASU 2014-15, “Going Concern,” which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The standard applies to all entities and is effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. We expect to adopt this guidance beginning in the fourth quarter 2016, and we do not expect it to materially impact us.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” which 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. In August 2015, the FASB issued ASU 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” that deferred the effective date of ASU 2014-09 by one year. This update is now effective for interim and annual periods that begin after December 15, 2017, with either retrospective application for all periods presented or retrospective application with a cumulative effect adjustment. We expect to adopt this guidance beginning in the first quarter 2018, and we are evaluating the impact on us.


B.	ACQUISITIONS

West Texas LPG Acquisition - In November 2014, we completed the acquisition of an 80 percent interest in the West Texas LPG Pipeline Limited Partnership and a 100 percent interest in the Mesquite Pipeline for approximately $800 million from affiliates of Chevron Corporation. We accounted for this acquisition as a business combination which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition-date fair values. See Note B in the Notes to Consolidated Financial Statements in our Annual Report for additional information on this acquisition.

Our consolidated balance sheet as of September 30, 2015, reflects the final purchase price allocation. Adjustments to the preliminary purchase price allocation reported in Note B in the Notes to the Consolidated Financial Statements in our Annual Report were not material. Therefore, prior period financial statements have not been recast.


C.	FAIR VALUE MEASUREMENTS

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

While many of the contracts in our 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.

Table of Contents

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 interest-rate swaps. 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 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 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.

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



	September 30, 2015
	Level 1			Level 2			Level 3			Total - Gross			Netting (a)			Total - Net (b)
	(Thousands of dollars)
Derivative assets
Commodity contracts
Financial contracts	$	40,799		$	—		$	5,756		$	46,555		$	(29,319	)	$	17,236
Physical contracts	—			—			4,866			4,866			—			4,866
Total derivative assets	$	40,799		$	—		$	10,622		$	51,421		$	(29,319	)	$	22,102
Derivative liabilities
Commodity contracts
Financial contracts	$	(573	)	$	—		$	(5,326	)	$	(5,899	)	$	5,899		$	—
Interest-rate contracts	—			(13,648		)	—			(13,648		)	—			(13,648		)
Total derivative liabilities	$	(573	)	$	(13,648	)	$	(5,326	)	$	(19,547	)	$	5,899		$	(13,648	)

(a) - Our 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, 2015, we held $23.4 million of cash from various counterparties and no cash collateral posted.

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

Table of Contents



	December 31, 2014
	Level 1			Level 2			Level 3			Total - Gross			Netting (a)			Total - Net (b)
	(Thousands of dollars)
Derivative assets
Commodity contracts
Financial contracts	$	42,880		$	—		$	354		$	43,234		$	(25,979	)	$	17,255
Physical contracts	—			—			9,922			9,922			—			9,922
Interest-rate contracts	—			2,288			—			2,288			—			2,288
Total derivative assets	$	42,880		$	2,288		$	10,276		$	55,444		$	(25,979	)	$	29,465
Derivative liabilities
Commodity contracts
Financial contracts	$	(169	)	$	—		$	(968	)	$	(1,137	)	$	1,137		$	—
Physical contracts	—			—			(23		)	(23		)	—			(23		)
Interest-rate contracts	—			(44,843		)	—			(44,843		)	—			(44,843		)
Total derivative liabilities	$	(169	)	$	(44,843	)	$	(991	)	$	(46,003	)	$	1,137		$	(44,866	)

(a) - Our 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, 2014, we held $24.8 million of cash from various counterparties and no cash collateral posted.

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

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)	2015			2014			2015			2014
	(Thousands of dollars)
Net assets (liabilities) at beginning of period	$	10,387		$	(1,313	)	$	9,285		$	(782	)
Total realized/unrealized gains (losses):
Included in earnings (a)	(15		)	207			95			(688		)
Included in other comprehensive income (loss)	(5,076		)	402			(4,084		)	(2,968		)
Purchases, issuances and settlements	—			—			—			3,734
Net assets (liabilities) at end of period	$	5,296		$	(704	)	$	5,296		$	(704	)

(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, 2015 and 2014, 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, 2015 and 2014, there were no transfers between levels.

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

The estimated fair value of the aggregate of our senior notes outstanding, including current maturities, was $6.6 billion and $6.4 billion at September 30, 2015, and December 31, 2014, respectively. The book value of the aggregate of our senior notes outstanding, including current maturities, was $6.8 billion and $6.0 billion at September 30, 2015, and December 31, 2014, 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.

Table of Contents


D.	RISK-MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

Risk-Management Activities - We are sensitive to changes in natural gas, crude oil and NGL prices, principally as a result of contractual terms under which these commodities are 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 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; and


•	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.

We may also use other instruments including options or collars to mitigate commodity price risk. Options are 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. 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 in exchange for services associated with our POP contracts. 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, 2015, and December 31, 2014, there were no financial derivative instruments with respect to our natural gas pipeline operations.

Interest-rate risk - We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts. At December 31, 2014, we had forward-starting interest-rate swaps with notional amounts totaling $900 million that were designated as cash flow hedges of the variability of interest payments on a portion of forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. Upon our debt issuance in March 2015, we settled $500 million of our interest-rate swaps and realized a loss of $55.1 million, which is included in accumulated other comprehensive loss and will be amortized to interest expense over the term of the related debt. At September 30, 2015, our remaining interest-rate swaps with notional amounts totaling $400 million have settlement dates of less than 12 months.

Table of Contents

Accounting Treatment - We record all derivative instruments at fair value, with the exception of normal purchases and normal sales transactions that are expected to result in physical delivery. Commodity price and interest-rate volatility may have a significant impact on the fair value of derivative instruments as of a given date. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it.

The table below summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements:



		Recognition and Measurement
Accounting Treatment		Balance Sheet		Income Statement
Normal purchases and normal sales	-	Fair value not recorded	-	Change in fair value not recognized in earnings
Mark-to-market	-	Recorded at fair value	-	Change in fair value recognized in earnings
Cash flow hedge	-	Recorded at fair value	-	Ineffective portion of the gain or loss on the derivative instrument is recognized in earnings
	-	Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated other comprehensive income (loss)	-	Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated other comprehensive income (loss) into earnings when the forecasted transaction affects earnings
Fair value hedge	-	Recorded at fair value	-	The gain or loss on the derivative instrument is recognized in earnings
	-	Change in fair value of the hedged item is recorded as an adjustment to book value	-	Change in fair value of the hedged item is recognized in earnings

To reduce our exposure to fluctuations in natural gas, NGLs and condensate prices, we periodically enter into futures, forward purchases and sales, options or swap transactions in order to hedge anticipated purchases and sales of natural gas, NGLs and condensate. Interest-rate swaps are used from time to time to manage interest-rate risk. Under certain conditions, we designate our derivative instruments as a hedge of exposure to changes in fair values or cash flows. We formally document all relationships between hedging instruments and hedged items, as well as risk-management objectives and strategies for undertaking various hedge transactions, and methods for assessing and testing correlation and hedge ineffectiveness. We specifically identify the forecasted transaction that has been designated as the hedged item in a cash flow hedge relationship. We assess the effectiveness of hedging relationships quarterly by performing an effectiveness analysis on our fair value and cash flow hedging relationships to determine whether the hedge relationships are highly effective on a retrospective and prospective basis. We also document our normal purchases and normal sales transactions that we expect to result in physical delivery and that we elect to exempt from derivative accounting treatment.

The realized revenues and purchase costs of our derivative instruments not considered held for trading purposes and derivatives that qualify as normal purchases or normal sales that are expected to result in physical delivery are reported on a gross basis.

Cash flows from futures, forwards and swaps that are accounted for as hedges are included in the same category as the cash flows from the related hedged items in our Consolidated Statements of Cash Flows.

Table of Contents

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



	September 30, 2015					December 31, 2014
	Assets (a)		(Liabilities) (a)			Assets (a)		(Liabilities) (a)
	(Thousands of dollars)
Derivatives designated as hedging instruments
Commodity contracts
Financial contracts	$	45,534	$	(5,108	)	$	43,234	$	(1,137	)
Physical contracts	4,866		—			9,922		—
Interest-rate contracts	—		(13,648		)	2,288		(44,843		)
Total derivatives designated as hedging instruments	50,400		(18,756		)	55,444		(45,980		)
Derivatives not designated as hedging instruments
Commodity contracts
Financial contracts	1,021		(791		)	—		—
Physical contracts	—		—			—		(23		)
Total derivatives not designated as hedging instruments	1,021		(791		)	—		(23		)
Total derivatives	$	51,421	$	(19,547	)	$	55,444	$	(46,003	)

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

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



		September 30, 2015					December 31, 2014
	Contract Type	Purchased/ Payor		Sold/ Receiver			Purchased/ Payor		Sold/ Receiver
Derivatives designated as hedging instruments:
Cash flow hedges
Fixed price
- Natural gas (Bcf)	Futures and swaps	—		(38.7		)	—		(41.2		)
- Crude oil and NGLs (MMBbl)	Futures, forwards and swaps	—		(3.5		)	—		(0.5		)
Basis
- Natural gas (Bcf)	Futures and swaps	—		(38.7		)	—		(41.2		)
Interest-rate contracts (Millions of dollars)	Forward-starting swaps	$	400.0	$	—		$	900.0	$	—
Derivatives not designated as hedging instruments:
Fixed price
- Crude oil and NGLs (MMBbl)	Futures, forwards and swaps	0.5		(0.5		)	—		—

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, 2015, our Consolidated Balance Sheet reflected a net loss of $114.2 million in accumulated other comprehensive loss. The portion of accumulated other comprehensive loss attributable to our commodity derivative financial instruments is an unrealized gain of $46.2 million, which will be realized within the next 15 months as the forecasted transactions affect earnings. If commodity prices remain at the current levels, we will realize $41.2 million in net gains over the next 12 months and $5.0 million in net gains thereafter. The amount deferred in accumulated other comprehensive loss attributable to our settled interest-rate swaps is a loss of $145.5 million, which will be recognized over the life of the long-term, fixed-rate debt, including losses of $15.5 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.

Table of Contents

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	2015			2014			2015			2014
	(Thousands of dollars)
Commodity contracts	$	36,559		$	17,133		$	47,650		$	(24,743	)
Interest-rate contracts	(20,610		)	(9,755		)	(26,277		)	(56,849		)
Total unrealized gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	$	15,949		$	7,378		$	21,373		$	(81,592	)

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 Income (Loss) into Net Income (Effective Portion)	Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2015			2014			2015			2014
		(Thousands of dollars)
Commodity contracts	Commodity sales revenues	$	22,770		$	(355	)	$	54,020		$	(31,961	)
Interest-rate contracts	Interest expense	(3,676		)	(2,648		)	(10,235		)	(7,884		)
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)		$	19,094		$	(3,003	)	$	43,785		$	(39,845	)

Ineffectiveness related to our cash flow hedges was not material for the three and nine months ended September 30, 2015 and 2014. 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. There were no gains or losses due to the discontinuance of cash flow hedge treatment during the three and nine months ended September 30, 2015 and 2014.

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.

Some of our financial derivative instruments 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 that were in a net liability position at September 30, 2015.

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, 2015, the net credit exposure from our derivative assets is primarily with investment-grade companies in the financial services sector.


E.	CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE

Partnership Credit Agreement - At September 30, 2015, we had $287.3 million of commercial paper outstanding, $14.0 million in letters of credit issued and no borrowings under our Partnership Credit Agreement.

Table of Contents

Our Partnership Credit Agreement, which is scheduled to expire in January 2019, 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. During the first quarter 2015, we increased the size of our Partnership Credit Agreement to $2.4 billion from $1.7 billion by exercising our option to increase the capacity of the facility through increased commitments from existing lenders and a commitment from one new lender. During the first quarter 2015, we also increased the size of our commercial paper program to $2.4 billion from $1.7 billion. Amounts outstanding under our commercial paper program reduce the borrowing capacity 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 the 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 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. As a result of the West Texas LPG acquisition we completed in the fourth quarter 2014, the allowable ratio of indebtedness to adjusted EBITDA increased to 5.5 to 1 through the second quarter 2015. 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, 2015, our ratio of indebtedness to adjusted EBITDA was 4.3 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.


F.	LONG-TERM DEBT

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.

These notes are governed by an indenture, dated September 25, 2006, between us and Wells Fargo Bank, N.A., the trustee, as supplemented. The indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The indenture contains covenants including, among other provisions, limitations on our ability to place liens on our property or assets and to sell and lease back our property. The indenture includes an event of default upon acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of any of our outstanding senior notes to declare those notes immediately due and payable in full.

We may redeem our 3.8 percent senior notes due 2020 and our 4.9 percent senior notes due 2025 from the March 2015 offering at par, plus accrued and unpaid interest to the redemption date, starting one month and three months, respectively, before their maturity dates. Prior to these dates, we may redeem these notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. Our senior notes are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness, and structurally subordinate to any of the existing and future debt and other liabilities of any nonguarantor subsidiaries.

Our $650 million, 3.25 percent senior notes mature on February 1, 2016. The carrying amount of these notes is reflected in current portion of long-term debt in our Consolidated Balance Sheet as of September 30, 2015.

Table of Contents


G.	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, 2015.

Equity Issuances - In August 2015, we completed a private placement of approximately 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 cash 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, 2015, we had approximately $138 million of registered common units available for issuance through our “at-the-market” equity program.

During the nine months ended September 30, 2015, we sold approximately 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 registered direct 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.

In May 2014, we completed an underwritten public offering of approximately 13.9 million common units at a public offering price of $52.94 per common unit, generating net proceeds of approximately $714.5 million. In conjunction with this issuance, ONEOK Partners GP contributed approximately $15.0 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.

During the three months ended September 30, 2014, we sold approximately 1.4 million common units through our “at-the-market” equity program. The net proceeds, including ONEOK Partners GP’s contribution to maintain its 2 percent general partner interest in us, were approximately $81.3 million, which were used for general partnership purposes.

During the nine months ended September 30, 2014, we sold approximately 4.4 million common units through our “at-the-market” equity program. The net proceeds, including ONEOK Partners GP’s contribution to maintain its 2 percent general partner interest in us, were approximately $245.4 million, which were used for general partnership purposes.

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 2015, our general partner declared a cash distribution of $0.79 per unit ($3.16 per unit on an annualized basis) for the third quarter 2015, which will be paid on November 13, 2015, to unitholders of record at the close of business on November 2, 2015.

Table of Contents

The following table shows our distributions paid during the periods indicated:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
	(Thousands, except per unit amounts)
Distribution per unit	$	0.79	$	0.76	$	2.37	$	2.235

General partner distributions	$	6,081	$	5,501	$	17,950	$	15,361
Incentive distributions	91,794		80,381		270,962		220,547
Distributions to general partner	97,875		85,882		288,912		235,908
Limited partner distributions to ONEOK	73,302		70,519		219,907		207,381
Limited partner distributions to other unitholders	132,862		118,644		388,655		324,805
Total distributions paid	$	304,039	$	275,045	$	897,474	$	768,094

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



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
	(Thousands, except per unit amounts)
Distribution per unit	$	0.79	$	0.775	$	2.37	$	2.280

General partner distributions	$	6,660	$	5,683	$	18,696	$	16,195
Incentive distributions	100,538		84,452		282,221		236,744
Distributions to general partner	107,198		90,135		300,917		252,939
Limited partner distributions to ONEOK	90,323		71,911		236,927		211,557
Limited partner distributions to other unitholders	135,480		122,105		396,925		345,255
Total distributions declared	$	333,001	$	284,151	$	934,769	$	809,751

Noncontrolling Interest - In November 2014, we completed the acquisition of an 80 percent interest in the West Texas LPG Pipeline Limited Partnership (WTLPG). We consolidate WTLPG as we control the system. We have recorded noncontrolling interests in consolidated subsidiaries on our consolidated financial statements to recognize the portion of WTLPG that we do not own. Prior to November 2014, our noncontrolling interests in consolidated subsidiaries were not material.


H.	ACCUMULATED OTHER COMPREHENSIVE LOSS

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



	Accumulated Other Comprehensive Loss (a)
	(Thousands of dollars)
January 1, 2015	$	(91,823	)
Other comprehensive loss before reclassifications	21,373
Amounts reclassified from accumulated other comprehensive loss	(43,785		)
Net current-period other comprehensive loss attributable to ONEOK Partners	(22,412		)
September 30, 2015	$	(114,235	)

(a) - All amounts are attributable to unrealized losses in risk-management assets/liabilities.

Table of Contents

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



Details about Accumulated Other Comprehensive Income (Loss) Components	Three Months Ended					Nine Months Ended					Affected Line Item in the Consolidated Statements of Income
	September 30,					September 30,
	2015			2014		2015			2014
	(Thousands of dollars)
Unrealized (gains) losses on risk-management assets/liabilities
Commodity contracts	$	(22,770	)	$	355	$	(54,020	)	$	31,961	Commodity sales revenues
Interest-rate contracts	3,676			2,648		10,235			7,884		Interest expense
Total reclassifications for the period attributable to ONEOK Partners	$	(19,094	)	$	3,003	$	(43,785	)	$	39,845	Net income attributable to ONEOK Partners


I.	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 G.


J.	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,
	2015		2014			2015		2014
	(Thousands of dollars)
Share of investee earnings
Northern Border Pipeline	$	16,156	$	14,371		$	51,131	$	53,657
Overland Pass Pipeline Company	10,538		3,856			27,048		12,708
Other (a)	5,550		(17,153		)	15,026		(6,197		)
Total share of investee earnings	32,244		1,074			93,205		60,168
Impairment of investment in Bighorn Gas Gathering	—		(53,421		)	—		(53,421		)
Equity in net earnings (loss) from investments	$	32,244	$	(52,347	)	$	93,205	$	6,747

(a) - Includes proportionate share of investee impairment of long-lived assets charge on Bighorn Gas Gathering of $23.0 million for the three and nine months ended September 30, 2014.

Table of Contents

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,
	2015		2014			2015		2014
	(Thousands of dollars)
Income Statement
Operating revenues	$	135,474	$	126,218		$	390,793	$	403,006
Operating expenses (a)	$	64,786	$	123,620		$	178,324	$	247,169
Net income (loss) (a)	$	67,121	$	(5,119	)	$	196,123	$	134,432

Distributions paid to us	$	36,370	$	31,574		$	117,153	$	109,223

(a) - Includes long-lived asset impairment charge on Bighorn Gas Gathering for the three and nine months ended September 30, 2014.

We incurred expenses in transactions with unconsolidated affiliates of $28.4 million and $15.0 million for the three months ended September 30, 2015 and 2014, respectively, and $74.2 million and $43.5 million for the nine months ended September 30, 2015 and 2014, respectively, primarily related to Overland Pass Pipeline Company and Northern Border Pipeline Company. Accounts payable to our equity method investees at September 30, 2015, and December 31, 2014, were $9.4 million and $20.5 million, respectively.

Roadrunner Gas Transmission - In March 2015, we entered into a 50-50 joint venture named Roadrunner Gas Transmission (Roadrunner) 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, 2015, we contributed approximately $30 million to Roadrunner.

Powder River Basin Equity Method Investments - Crude oil and natural gas producers have primarily focused their development efforts on crude oil and NGL-rich supply basins rather than areas with dry natural gas production, such as the coal-bed methane areas in the Powder River Basin. The reduced coal-bed methane development activities and natural production declines in the dry natural gas formations of the Powder River Basin have resulted in lower natural gas volumes available to be gathered. While the reserve potential in the dry natural gas formations of the Powder River Basin still exists, future drilling and development in this area will be affected by commodity prices and producers’ alternative prospects.

The current commodity price environment has caused natural gas producers to reduce drilling for natural gas, which we expect will slow volume growth or reduce volumes of natural gas delivered to systems owned by our Powder River Basin equity method investments. A continued decline in volumes gathered in the coal-bed methane area of the Powder River Basin may reduce our ability to recover the carrying value of our equity investments in this area and could result in noncash charges to earnings. The net book value of our equity method investments in this dry natural gas area is $214.2 million, which includes $130.5 million of equity method goodwill.


K.	RELATED-PARTY TRANSACTIONS

Intersegment and affiliate sales are recorded on the same basis as sales to unaffiliated customers. Prior to April 1, 2014, our Natural Gas Gathering and Processing segment sold natural gas to ONEOK and its subsidiaries, and our Natural Gas Pipelines segment provided transportation and storage services to ONEOK and its subsidiaries. Additionally, our Natural Gas Gathering and Processing segment and Natural Gas Liquids segment purchased a portion of the natural gas used in their operations from ONEOK and its subsidiaries.

On January 31, 2014, ONEOK completed the separation of its former natural gas distribution business into ONE Gas. ONE Gas was an affiliate prior to this separation. Commodity sales and services revenues in the Consolidated Statements of Income for the one month ended January 31, 2014, for transactions with ONE Gas prior to the separation are reflected as affiliate transactions. Transactions with ONE Gas that occurred after the separation are reflected as unaffiliated, third-party transactions.

On March 31, 2014, ONEOK completed the wind down of ONEOK Energy Services Company, a subsidiary of ONEOK. For the first quarter 2014, we had transactions with ONEOK Energy Services Company, which are reflected as affiliate transactions.

Table of Contents

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 operates Guardian Pipeline, Viking Gas Transmission and Midwestern Gas Transmission according to each pipeline’s operating agreement. ONEOK Partners GP may purchase services from ONEOK and its affiliates pursuant to the terms of the Services Agreement. ONEOK Partners GP has no employees and utilizes the services of ONEOK to fulfill its operating obligations.

ONEOK and its affiliates provide a variety of services to us under the Services Agreement, including cash management and financial services, employee benefits provided through ONEOK’s benefit plans, legal and administrative services, insurance and office space leased in ONEOK’s headquarters building and other field locations. Where costs are incurred specifically on behalf of one of our affiliates, the costs are billed directly to us by ONEOK. In other situations, the costs may be allocated to us through a variety of methods, depending upon the nature of the expense and activities. Beginning in the second quarter 2014, ONEOK allocates substantially all of its general overhead costs to us as a result of ONEOK’s separation of its natural gas distribution business and the wind down of its energy services business in the first quarter 2014. For the first quarter 2014, it is not practicable to determine what these general overhead costs would have been on a stand-alone basis. All costs directly charged or allocated to us are included in our Consolidated Statements of Income.

The following table sets forth the transactions with related parties for the periods indicated:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
	(Thousands of dollars)
Revenues	$	—	$	—	$	—	$	53,526
Expenses
Cost of sales and fuel	$	—	$	—	$	—	$	10,835
Operating expenses	89,342		84,221		265,611		240,172
Total expenses	$	89,342	$	84,221	$	265,611	$	251,007

ONEOK Partners GP made additional general partner contributions to us of approximately $21.0 million and $19.8 million during the nine months ended September 30, 2015 and 2014, respectively, to maintain its 2 percent general partner interest in connection with the issuances of common units. See Note G for additional information about cash distributions paid to ONEOK for its general partner and limited partner interests.


L.	COMMITMENTS AND CONTINGENCIES

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

Table of Contents

minimize natural gas venting and flaring on public lands; policy recommendations for reducing emissions from energy infrastructure to increase the performance of the nation’s energy transmission, storage and distribution systems; and continued efforts by PHMSA to require pipeline operators to take steps to eliminate leaks and prevent accidental methane releases and evaluate the progress of states in replacing cast-iron pipelines. The impact of any such regulatory actions on our facilities and operations is unknown. We continue to monitor these developments and the impact they may have on our businesses. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a significant impact on our business, financial position, results of operations and cash flows.

Our expenditures for environmental assessment, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters have had no material effects on earnings or cash flows during the three and nine months ended September 30, 2015 and 2014.

In April 2014, the EPA and the United States Army Corps of Engineers proposed a joint rule-making to redefine the definition of “Waters of the United States” under the Clean Water Act. The final rule was published on June 29, 2015, and became effective on August 28, 2015. The final rule is not expected to result in material impacts on our projects, facilities and operations.

The EPA’s “Triggering and Tailoring Rules” regulate GHG emissions at new or modified facilities that meet certain criteria. Affected facilities are required to review best available control technology (BACT), conduct air-quality analysis, impact analysis and public reviews with respect to such emissions. At current emission threshold levels, this rule has had a minimal impact on our existing facilities. In addition, on June 23, 2014, the Supreme Court of the United States (Supreme Court), in a case styled, Utility Air Regulatory Group v. EPA, 530 U.S. (2014), held that an industrial facility’s potential to emit GHG emissions alone cannot subject a facility to the permitting requirements for major stationary source provisions of the Clean Air Act. The decision invalidated the EPA’s current Triggering and Tailoring Rule for GHG Prevention of Significant Deterioration (PSD) and Title V requirements as applied to facilities considered major sources only for GHGs (referred to as Step 2 sources). However, the Supreme Court also ruled that to the extent a source pursues a capital project (new construction or expansion of existing facility), which otherwise subjects the source to major source PSD permitting for conventional criteria pollutants, the permitting authorities may impose BACT analysis and emission limits for GHGs from those sources.

In April 2015, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), on remand from the Supreme Court, issued its further Order following the Supreme Court’s decision in Utility Air Regulatory Group v. EPA. The D.C. Circuit’s Order included the following: (1) it formally vacated EPA regulations implementing the Tailoring Rule to the extent that they require a stationary source to obtain a PSD or Title V permit based solely on the source’s GHG emissions; and (2) ordered the EPA to consider whether any further revisions to its regulations are appropriate in light of the Supreme Court’s decision. On April 30, 2015, the EPA issued a direct final rule to allow for the rescission of Clean Air Act PSD permits issued by the EPA or delegated state and local permitting authorities under Step 2 of the GHG Tailoring Rule. The direct final rule was to become effective unless adverse comments were received by the EPA. On August 19, 2015, the EPA published the direct final rule in the Federal Register to confirm that no adverse comments were received and that the rule was now in effect. We do not expect the direct final rule to have a material impact on our existing operations or design decisions for new project applications.

In July 2011, the EPA issued a proposed rule that would change the air emissions New Source Performance Standards, also known as NSPS, and Maximum Achievable Control Technology requirements applicable to the oil and natural gas industry, including natural gas production, processing, transmission and underground storage sectors. In April 2012, the EPA released the final rule, which includes new NSPS and air toxic standards for a variety of sources within natural gas processing plants, oil and natural gas production facilities and natural gas transmission stations. The rule also regulates emissions from the hydraulic fracturing of wells for the first time. The NSPS final rule became effective in October 2012, but the dates for compliance vary and depend in part upon the type of affected facility and the date of construction, reconstruction or modification.

In September 2015, the EPA published several proposed rule-makings in the Federal Register that affect the oil and gas industry. The rule-makings included, but were not limited to, proposed amendments to the NSPS rule. The proposed amendments to the NSPS rule included, in part, the proposed direct regulation of methane emissions for the first time as an individual air pollutant from oil and gas sources, as part of the President’s Methane Strategy. Comments on the proposed rule-makings remain ongoing.

In October 2015, the EPA issued a prepublication version of a final rule-making to amend downward the National Ambient Air Quality Standards (NAAQS) for ground level ozone. The final rule requires revised designations of the areas in the various states for classification as in attainment or nonattainment for the new ozone NAAQS. Any areas determined to not attain the

Table of Contents

ozone NAAQS will implicate more strict air permitting requirements for new or modified sources that emit pollutants that contribute to ground level ozone.

At this time we do not anticipate a material impact to our planned capital, operations and maintenance costs resulting from compliance with the current or pending regulations outlined above. However, the EPA may issue additional responses, amendments and/or policy guidance on the final rules, which could alter our present expectations. Generally, the EPA rule-makings will require expenditures for updated emissions controls, monitoring and record-keeping requirements at affected facilities. We do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.

Pipeline Safety - We are subject to PHMSA regulations, including pipeline asset integrity-management regulations. The Pipeline Safety Improvement Act of 2002 requires pipeline companies operating high-pressure pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. In January 2012, The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law. The law increased maximum penalties for violating federal pipeline safety regulations and directs the DOT and Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us. These issues include, but are not limited to, the following:


•	an evaluation on whether hazardous natural gas liquids and natural gas pipeline integrity-management requirements should be expanded beyond current high-consequence areas;


•	a review of all natural gas and hazardous natural gas liquids gathering pipeline exemptions;


•	a verification of records for pipelines in Class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and


•	a requirement to test previously untested pipelines operating above 30 percent yield strength in high-consequence areas.

In October 2015, PHMSA issued a notice of proposed rule-making to its hazardous liquid pipeline safety regulations. Among other things, the proposed regulations would expand the current leak-detection requirements, apply new, more conservative repair criteria and establish timelines for inspecting pipeline facilities potentially affected by an extreme weather event or natural disaster. The proposal would also increase the stringency of integrity management program requirements and set deadlines for the use of internal inspection tools on certain systems. Comments on the proposed rule-making are currently due by January 2016. The potential capital and operating expenditures related to the referenced legislation and regulations are unknown, but we do not anticipate a material impact to our planned capital, operations and maintenance costs resulting from compliance with the current or pending regulations.

Legal Proceedings - We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of 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.


M.	SEGMENTS

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


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


•	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 - We evaluate performance based principally on each segment’s operating income and equity earnings. The accounting policies of the segments are described in Note A of the Notes to Consolidated Financial Statements in our Annual Report. Intersegment and affiliate sales are recorded on the same basis as sales to unaffiliated customers. Net margin is comprised of total revenues less cost of sales and fuel. Cost of sales and fuel includes commodity purchases, fuel, storage and transportation costs. As a result of ONEOK’s separation of its natural gas distribution business into a stand-alone publicly traded company, ONE Gas, on January 31, 2014, transactions with ONE Gas subsequent to the separation are reflected as sales to unaffiliated customers.

Customers - The primary customers for our Natural Gas Gathering and Processing segment are major and independent crude oil and natural gas production companies. Our Natural Gas Liquids segment’s customers are primarily NGL and natural gas

Table of Contents

gathering and processing companies, major 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 include natural gas distribution, electric-generation, natural gas marketing, industrial and major and independent crude oil and natural gas production companies.

For the three and nine months ended September 30, 2015 and 2014, 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, 2015	Natural Gas Gathering and Processing		Natural Gas Liquids (a)			Natural Gas Pipelines (b)			Other and Eliminations			Total
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
Net margin	$	140,655	$	321,772		$	75,369		$	(187	)	$	537,609
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 was related to sales within the segment, net margin of $140.1 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, net margin of $57.9 million and operating income of $24.7 million.



Three Months Ended September 30, 2014	Natural Gas Gathering and Processing			Natural Gas Liquids (a)			Natural Gas Pipelines (b)		Other and Eliminations			Total
Three Months Ended September 30, 2014	Natural Gas Gathering and Processing			Natural Gas Liquids (a)			Natural Gas Pipelines (b)		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	374,403		$	2,667,939		$	77,027	$	—		$	3,119,369
Intersegment revenues	403,399			66,581			2,133		(472,113		)	—
Total revenues	$	777,802		$	2,734,520		$	79,160	$	(472,113	)	$	3,119,369
Net margin	$	178,171		$	282,963		$	73,399	$	1,632		$	536,165
Operating costs	64,279			76,946			27,998		1,562			170,785
Depreciation and amortization	31,327			31,661			10,913		—			73,901
Gain (loss) on sale of assets	324			(535		)	1,746		(1		)	1,534
Operating income	$	82,889		$	173,821		$	36,234	$	69		$	293,013
Equity in net earnings (loss) from investments	$	(71,069	)	$	4,351		$	14,371	$	—		$	(52,347	)
Capital expenditures	$	214,917		$	153,785		$	10,650	$	1,184		$	380,536

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $190.3 million, of which $170.1 million was related to sales within the segment, net margin of $94.3 million and operating income of $46.4 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $65.2 million, net margin of $57.4 million and operating income of $23.4 million.

Table of Contents



Nine Months Ended September 30, 2015	Natural Gas Gathering and Processing		Natural Gas Liquids (a)			Natural Gas Pipelines (b)			Other and Eliminations			Total
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
Net margin	$	402,482	$	902,382		$	218,599		$	(545	)	$	1,522,918
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		$	1,837,776		$	(54,783	)	$	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 was related to sales within the segment, net margin of $392.7 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, net margin of $175.9 million and operating income of $77.8 million.



Nine Months Ended September 30, 2014	Natural Gas Gathering and Processing			Natural Gas Liquids (a)			Natural Gas Pipelines (b)		Other and Eliminations			Total
Nine Months Ended September 30, 2014	Natural Gas Gathering and Processing			Natural Gas Liquids (a)			Natural Gas Pipelines (b)		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	1,095,531		$	7,950,930		$	247,420	$	—		$	9,293,881
Sales to affiliated customers	41,214			—			12,312		—			53,526
Intersegment revenues	1,126,547			160,712			6,206		(1,293,465		)	—
Total revenues	$	2,263,292		$	8,111,642		$	265,938	$	(1,293,465	)	$	9,347,407
Net margin	$	486,695		$	818,086		$	242,359	$	(7,008	)	$	1,540,132
Operating costs	188,489			218,129			82,747		(7,752		)	481,613
Depreciation and amortization	89,612			89,848			32,623		—			212,083
Gain (loss) on sale of assets	277			(572		)	1,663		165			1,533
Operating income	$	208,871		$	509,537		$	128,652	$	909		$	847,969
Equity in net earnings (loss) from investments	$	(60,484	)	$	13,574		$	53,657	$	—		$	6,747
Investments in unconsolidated affiliates	$	253,930		$	484,238		$	390,341	$	—		$	1,128,509
Total assets	$	4,415,814		$	7,337,688		$	1,832,368	$	68,372		$	13,654,242
Noncontrolling interests in consolidated subsidiaries	$	4,394		$	—		$	—	$	15		$	4,409
Capital expenditures	$	506,016		$	637,524		$	25,987	$	3,423		$	1,172,950

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $479.4 million, of which $417.0 million was related to sales within the segment, net margin of $263.4 million and operating income of $126.0 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $214.8 million, net margin of $185.5 million and operating income of $84.6 million.

Table of Contents


N.	SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

We have no significant assets or operations other than our investment in our 100 percent-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.

Table of Contents

Condensed Consolidating Statements of Income



	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	—			—			1,360.8			—			1,360.8
Net margin	—			—			537.6			—			537.6
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



	Three Months Ended September 30, 2014
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Revenues
Commodity sales	$	—		$	—		$	2,754.5		$	—		$	2,754.5
Services	—			—			364.9			—			364.9
Total revenues	—			—			3,119.4			—			3,119.4
Cost of sales and fuel	—			—			2,583.2			—			2,583.2
Net margin	—			—			536.2			—			536.2
Operating expenses	—			—			244.7			—			244.7
Gain (loss) on sale of assets	—			—			1.5			—			1.5
Operating income	—			—			293.0			—			293.0
Equity in net earnings (loss) from investments	167.2			167.2			(66.7		)	(320.0		)	(52.3		)
Other income (expense), net	83.1			83.1			(0.7		)	(166.2		)	(0.7		)
Interest expense, net	(83.1		)	(83.1		)	(70.1		)	166.2			(70.1		)
Income before income taxes	167.2			167.2			155.5			(320.0		)	169.9
Income taxes	—			—			(2.6		)	—			(2.6		)
Net income	167.2			167.2			152.9			(320.0		)	167.3
Less: Net income attributable to noncontrolling interests	—			—			0.1			—			0.1
Net income attributable to ONEOK Partners, L.P.	$	167.2		$	167.2		$	152.8		$	(320.0	)	$	167.2

Table of Contents



	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	—			—			4,307.8			—			4,307.8
Net margin	—			—			1,522.9			—			1,522.9
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



	Nine Months Ended September 30, 2014
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Revenues
Commodity sales	$	—		$	—		$	8,276.3		$	—		$	8,276.3
Services	—			—			1,071.1			—			1,071.1
Total revenues	—			—			9,347.4			—			9,347.4
Cost of sales and fuel	—			—			7,807.3			—			7,807.3
Net margin	—			—			1,540.1			—			1,540.1
Operating expenses	—			—			693.6			—			693.6
Gain (loss) on sale of assets	—			—			1.5			—			1.5
Operating income (loss)	—			—			848.0			—			848.0
Equity in net earnings (loss) from investments	647.1			647.1			(46.9		)	(1,240.6		)	6.7
Other income (expense), net	248.9			248.9			13.9			(497.8		)	13.9
Interest expense, net	(248.9		)	(248.9		)	(211.3		)	497.8			(211.3		)
Income before income taxes	647.1			647.1			603.7			(1,240.6		)	657.3
Income taxes	—			—			(10.0		)	—			(10.0		)
Net income	647.1			647.1			593.7			(1,240.6		)	647.3
Less: Net income attributable to noncontrolling interests	—			—			0.2			—			0.2
Net income attributable to ONEOK Partners, L.P.	$	647.1		$	647.1		$	593.5		$	(1,240.6	)	$	647.1

Table of Contents

Condensed Consolidating Statements of Comprehensive Income



	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



	Three Months Ended September 30, 2014
(Unaudited)	Parent		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidating Entries			Total
	(Millions of dollars)
Net income	$	167.2	$	167.2	$	152.9	$	(320.0	)	$	167.3
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	7.4		17.1		17.1		(34.2		)	7.4
Realized (gains) losses on derivatives recognized in net income	3.0		0.4		0.4		(0.8		)	3.0
Total other comprehensive income (loss)	10.4		17.5		17.5		(35.0		)	10.4
Comprehensive income	177.6		184.7		170.4		(355.0		)	177.7
Less: Comprehensive income attributable to noncontrolling interests	—		—		0.1		—			0.1
Comprehensive income attributable to ONEOK Partners, L.P.	$	177.6	$	184.7	$	170.3	$	(355.0	)	$	177.6

Table of Contents



	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



	Nine Months Ended September 30, 2014
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Net income	$	647.1		$	647.1		$	593.7		$	(1,240.6	)	$	647.3
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	(81.6		)	(24.7		)	(24.7		)	49.4			(81.6		)
Realized (gains) losses on derivatives recognized in net income	39.8			32.0			32.0			(64.0		)	39.8
Total other comprehensive income (loss)	(41.8		)	7.3			7.3			(14.6		)	(41.8		)
Comprehensive income	605.3			654.4			601.0			(1,255.2		)	605.5
Less: Comprehensive income attributable to noncontrolling interests	—			—			0.2			—			0.2
Comprehensive income attributable to ONEOK Partners, L.P.	$	605.3		$	654.4		$	600.8		$	(1,255.2	)	$	605.3

Table of Contents

Condensed Consolidating Balance Sheets



	September 30, 2015
(Unaudited)	Parent		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidating Entries			Total
Assets	(Millions of dollars)
Current assets
Cash and cash equivalents	$	—	$	7.3	$	—	$	—		$	7.3
Accounts receivable, net	—		—		584.3		—			584.3
Affiliate receivables	—		—		4.8		—			4.8
Natural gas and natural gas liquids in storage	—		—		142.3		—			142.3
Other current assets	—		—		146.4		—			146.4
Total current assets	—		7.3		877.8		—			885.1
Property, plant and equipment
Property, plant and equipment	—		—		14,234.7		—			14,234.7
Accumulated depreciation and amortization	—		—		2,075.1		—			2,075.1
Net property, plant and equipment	—		—		12,159.6		—			12,159.6
Investments and other assets
Intercompany notes receivable	9,871.5		7,815.5		—		(17,687.0		)	—
Other assets	3,926.5		5,975.2		1,617.1		(9,532.5		)	1,986.3
Total investments and other assets	13,798.0		13,790.7		1,617.1		(27,219.5		)	1,986.3
Total assets	$	13,798.0	$	13,798.0	$	14,654.5	$	(27,219.5	)	$	15,031.0
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	650.0	$	—	$	7.7	$	—		$	657.7
Notes payable	287.3		—		—		—			287.3
Accounts payable	—		—		612.9		—			612.9
Affiliate payables	—		—		21.3		—			21.3
Other current liabilities	103.1		—		224.0		—			327.1
Total current liabilities	1,040.4		—		865.9		—			1,906.3
Intercompany debt	—		9,871.5		7,815.5		(17,687.0		)	—
Long-term debt, excluding current maturities	6,099.4		—		46.2		—			6,145.6
Deferred credits and other liabilities	—		—		155.6		—			155.6
Commitments and contingencies
Equity
Equity excluding noncontrolling interests in consolidated subsidiaries	6,658.2		3,926.5		5,606.0		(9,532.5		)	6,658.2
Noncontrolling interests in consolidated subsidiaries	—		—		165.3		—			165.3
Total equity	6,658.2		3,926.5		5,771.3		(9,532.5		)	6,823.5
Total liabilities and equity	$	13,798.0	$	13,798.0	$	14,654.5	$	(27,219.5	)	$	15,031.0

Table of Contents



	December 31, 2014
(Unaudited)	Parent		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidating Entries			Total
Assets	(Millions of dollars)
Current assets
Cash and cash equivalents	$	—	$	42.5	$	—	$	—		$	42.5
Accounts receivable, net	—		—		735.8		—			735.8
Affiliate receivables	—		—		8.6		—			8.6
Natural gas and natural gas liquids in storage	—		—		134.1		—			134.1
Other current assets	1.9		—		163.1		—			165.0
Total current assets	1.9		42.5		1,041.6		—			1,086.0
Property, plant and equipment
Property, plant and equipment	—		—		13,377.6		—			13,377.6
Accumulated depreciation and amortization	—		—		1,842.1		—			1,842.1
Net property, plant and equipment	—		—		11,535.5		—			11,535.5
Investments and other assets
Intercompany notes receivable	8,843.3		7,579.0		—		(16,422.3		)	—
Other assets	4,250.1		5,469.8		1,590.3		(9,331.3		)	1,978.9
Total investments and other assets	13,093.4		13,048.8		1,590.3		(25,753.6		)	1,978.9
Total assets	$	13,095.3	$	13,091.3	$	14,167.4	$	(25,753.6	)	$	14,600.4
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	—	$	—	$	7.7	$	—		$	7.7
Notes payable	1,055.3		—		—		—			1,055.3
Accounts payable	—		—		874.7		—			874.7
Affiliate payables	—		—		36.1		—			36.1
Other current liabilities	136.8		—		225.5		—			362.3
Total current liabilities	1,192.1		—		1,144.0		—			2,336.1
Intercompany debt	—		8,843.3		7,579.0		(16,422.3		)	—
Long-term debt, excluding current maturities	5,952.4		—		51.9		—			6,004.3
Deferred credits and other liabilities	—		—		141.3		—			141.3
Commitments and contingencies
Equity
Equity excluding noncontrolling interests in consolidated subsidiaries	5,950.8		4,248.0		5,083.3		(9,331.3		)	5,950.8
Noncontrolling interests in consolidated subsidiaries	—		—		167.9		—			167.9
Total equity	5,950.8		4,248.0		5,251.2		(9,331.3		)	6,118.7
Total liabilities and equity	$	13,095.3	$	13,091.3	$	14,167.4	$	(25,753.6	)	$	14,600.4

Table of Contents

Condensed Consolidating Statements of Cash Flows



	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		)
Borrowing (repayment) of notes payable, net	(768.0		)	—			—			—			(768.0		)
Issuance of long-term debt, net of discounts	798.9			—			—			—			798.9
Debt financing costs	(7.7		)	—			—			—			(7.7		)
Intercompany borrowings (advances), net	(1,025.4		)	793.8			231.6			—			—
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

Table of Contents



	Nine Months Ended September 30, 2014
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Operating activities
Cash provided by operating activities	$	815.1		$	53.7		$	786.4		$	(768.1	)	$	887.1
Investing activities
Capital expenditures	—			—			(1,173.0		)	—			(1,173.0		)
Other investing activities	—			14.5			(2.2		)	—			12.3
Cash provided by (used in) investing activities	—			14.5			(1,175.2		)	—			(1,160.7		)
Financing activities
Cash distributions:
General and limited partners	(768.1		)	(768.1		)	—			768.1			(768.1		)
Noncontrolling interests	—			—			(0.4		)	—			(0.4		)
Borrowing (repayment) of notes payable, net	—			—			—			—			—
Intercompany borrowings (advances), net	(1,014.3		)	619.4			394.9			—			—
Repayment of long-term debt	—			—			(5.7		)	—			(5.7		)
Issuance of common units, net of issuance costs	947.5			—			—			—			947.5
Contribution from general partner	19.8			—			—			—			19.8
Cash provided by (used in) financing activities	(815.1		)	(148.7		)	388.8			768.1			193.1
Change in cash and cash equivalents	—			(80.5		)	—			—			(80.5		)
Cash and cash equivalents at beginning of period	—			134.5			—			—			134.5
Cash and cash equivalents at end of period	$	—		$	54.0		$	—		$	—		$	54.0

Table of Contents


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

Market Conditions - Due in part to the rapid growth in crude oil production in the United States through 2014, the global supply of crude oil exceeded demand and led to a dramatic fall in crude oil prices in the fourth quarter 2014. Lower prices continued into 2015. The production growth and decline in crude oil prices have also contributed to lower NGL product prices, as well as narrow NGL product price differentials. Similarly, the rapid growth in domestic natural gas production has led to a decline in natural gas prices. This weakened commodity price environment, which is due to factors beyond our control, is creating challenges for our crude oil and natural gas producer customers and has resulted in decreased drilling activity in the first nine months of 2015, compared with the same period in 2014. Despite the decrease in overall drilling activity, producers are focusing their drilling in high-return areas and are using more efficient drilling and completion techniques that are contributing to an increase in natural gas and NGL volumes, particularly in the Williston and Permian Basins. The energy industry has periodically experienced similar down cycles in the past. We expect this lower commodity price environment to continue through the remainder of 2015, with a modest recovery in 2016, which will impact our net realized prices for natural gas, NGLs and condensate, as well as our financial results.

As a result of lower commodity prices, crude oil and natural gas producers have significantly decreased their capital investments, which, combined with production declines, has begun to slow natural gas and NGL supply growth. Lower commodity prices and slower volume growth have significantly impacted our 2015 results of operations and cash flows, particularly in our Natural Gas Gathering and Processing segment where revenues have been historically derived from primarily POP commodity-based contracts with fee components. Many contracts in our Natural Gas Gathering and Processing and Natural Gas Liquids segments include fixed fee, minimum volume or firm demand charge agreements that ensure a minimum level of revenues regardless of commodity prices. Additionally, we have renegotiated many Natural Gas Gathering and Processing segment contracts to significantly increase our fee-based earnings and continue to actively work with our producer customers to similarly restructure additional contracts. We expect to substantially complete our negotiations on Williston Basin contracts in 2015 and receive the full benefit of the improved margins in 2016.

We also expect relatively narrow NGL location price differentials to continue, with periods of volatility for certain NGL products, between the Conway, Kansas, and Mont Belvieu, Texas, market centers. We expect this to persist as NGL production continues to increase and new fractionators and pipelines from various NGL-rich shale areas throughout the country, including our growth projects discussed below, alleviate constraints affecting NGL prices and location price differentials between the two market centers.

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, Permian and Rocky Mountain regions during 2014 and the first nine months of 2015. 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. We expect ethane rejection to persist at current levels until ethylene producers increase their capacity to consume additional ethane feedstock volumes through plant modifications, plant expansions and the completion of announced new world-scale ethylene production projects beginning in 2017. Ethane rejection is expected to continue to have a significant impact on our financial results through 2017. However, beginning in June 2015, our Natural Gas Gathering and Processing segment reduced its level of ethane rejection in the Rocky Mountain region to alleviate downstream NGL product specification issues, which offsets partially this financial impact. We expect this decreased ethane rejection to continue into 2016. 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. See additional discussion in the “Financial Results and Operating Information” section.

Commodity Prices - Sharp declines in commodity prices negatively affected our financial results for the three and nine months ended September 30, 2015, compared with the same periods in 2014. WTI crude oil prices declined to below $50.00 per barrel in the first nine months of 2015, compared with prices averaging approximately $100.00 in the first nine months of 2014. NYMEX natural gas prices also declined to less than $3.00 per MMBtu in the first nine months of 2015, compared with prices averaging approximately $4.50 per MMBtu in the first nine months of 2014. OPIS Conway propane prices averaged less than

Table of Contents

$0.50 per gallon in the first nine months of 2015, compared with prices averaging more than $1.00 per gallon in the first nine months of 2014. We expect lower commodity prices to persist throughout the remainder of 2015, with a modest recovery in 2016.

We experienced significantly higher prices in the first quarter 2014 due to severely cold weather, compared with the first quarter 2015. In response to increased heating demand, propane prices increased significantly at the Mid-Continent market center at Conway, Kansas, compared with the Gulf Coast market center at Mont Belvieu, Texas, in the first quarter 2014. The price of propane in the Mid-Continent market and the wider location price differentials between the Mid-Continent and Gulf Coast market centers peaked in late January 2014 and returned to historical levels by the end of February 2014 as supply and demand balanced.

Financial Outlook - We have substantial fee-based businesses in our Natural Gas Liquids and Natural Gas Pipelines segments. However, our results of operations, primarily in our Natural Gas Gathering and Processing segment, are impacted significantly by the commodity price environment. To mitigate partially the impact of lower commodities prices, we have hedged a significant portion of our Natural Gas Gathering and Processing segment equity volumes for the remainder of 2015 and in 2016. Also, many contracts in our Natural Gas Gathering and Processing and Natural Gas Liquids segments include fixed fee, minimum volume or firm demand charge agreements that ensure a minimum level of revenues regardless of commodity prices or volumetric throughput. Our Natural Gas Gathering and Processing segment continues to seek opportunities to increase the fee-based component in our POP contracts. We expect to renegotiate contracts associated with a significant amount of our gathered volume in the Williston Basin by the end of 2015. We expect these contracts to favorably impact our fourth quarter 2015 and full year 2016 financial results. Our Natural Gas Pipelines segment also provides primarily fee-based firm natural gas transportation and storage services primarily to natural gas and electric utilities.

Despite the decline in commodity prices, we expect the growth of our operations to continue, which we expect to favorably impact our financial results in the fourth quarter 2015, compared with the first nine months of 2015, due to a number of factors. We completed a significant number of capital-growth projects in 2014 that we expect will continue to increase volumes in our Natural Gas Gathering and Processing and Natural Gas Liquids segments in the fourth quarter 2015. We are also constructing additional natural gas gathering pipelines, compression and processing plants, and natural gas liquids pipeline capacity in the Rocky Mountain region that are expected to help alleviate current capacity constraints primarily existing in the Williston Basin. In the Williston Basin, we expect to capture a substantial amount of natural gas currently being flared by producers, production from wells that have been drilled but not yet completed or connected to our system, and production from new wells that are expected to be drilled. We expect additional volume from new wells focused in high-return areas of the basin, which remain economical even at current prices and typically produce at higher initial production rates compared with other areas. We also expect additional wells to be completed and connected to our system in the Mid-Continent region. We expect supply growth to continue in 2016 and 2017, although not as rapidly as the growth experienced in 2014. We also expect our fee-based business to continue to increase as we complete our capital-growth projects and complete additional contract renegotiations.

Growth Projects - Through the first nine months of 2015, crude oil and natural gas producers continued 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 Powder River Basin; in the Cana-Woodford Shale, Woodford Shale, Springer Shale, Stack and SCOOP areas in the Mid-Continent region and in the Permian Basin. In response to this continued production of crude oil, natural gas and NGLs, and higher demand for NGL products from the petrochemical industry, we have completed growth projects and acquisitions and also have projects in various stages of construction to meet the needs of crude oil and natural gas producers and processors in these regions. In addition, our projects are expected to enhance our natural gas liquids fractionation, distribution and storage infrastructure in the Gulf Coast region and expand our natural gas pipeline services in the Permian Basin. The execution of these capital investments aligns with our strategy to generate consistent growth and sustainable earnings. Our contractual commitments from crude oil and natural gas producers, natural gas processors and electric generators in regions associated with our growth projects are expected to provide incremental cash flows and long-term fee-based earnings.

While reduced crude oil and natural gas producer drilling activity is slowing supply growth, we expect to complete our previously announced projects to meet crude oil and natural gas producers’ demand for our gathering, processing, fractionation and transportation services. However, we have suspended capital expenditures for certain natural gas processing plants and related infrastructure to align with the needs of our customers. We expect to resume our suspended capital-growth projects as soon as market conditions improve. If the current commodity price environment persists for a prolonged period, it may further impact the timing or demand for additional infrastructure projects or growth opportunities in the future.

WesTex Transmission Pipeline Expansion - In July 2015, we announced plans to invest $70 million to $100 million to expand our ONEOK WesTex Transmission (WesTex) intrastate natural gas pipeline system in the Permian Basin in our Natural Gas

Table of Contents

Pipelines segment. WesTex, which had qualifying open season bids in excess of 500 MMcf/d, plans to utilize 240 MMcf/d of existing capacity and create additional capacity by expanding its system by 260 MMcf/d by the first quarter 2017. This expansion project is supported by firm demand charge transportation agreements and is complementary to our recently announced Roadrunner Gas Transmission (Roadrunner) joint venture pipeline project discussed below.

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

Roadrunner - In March 2015, we entered into a 50-50 joint venture with a subsidiary of 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. The pipeline will connect with our existing natural gas pipeline and storage infrastructure in Texas and is expected to create a platform for future cross-border development opportunities. These integrated assets are also expected to provide markets in Mexico access to upstream supply basins in West Texas and the Mid-Continent region, which adds location and price diversity to their supply mix and supports the plan of Mexico’s national electric utility, Comisión Federal de Electricidad, to replace fuel oil-based power plants with natural gas-fueled power plants, which are more economical and produce fewer GHG emissions. The estimated total cost of the project is approximately $450 million to $500 million. We contributed approximately $30 million to Roadrunner in the nine months ended September 30, 2015, and do not expect to make any further contributions in 2015. We expect to contribute approximately $65 million to Roadrunner during 2016. The FERC approved Roadrunner’s request for a Presidential Permit and authorization in October 2015, and construction has commenced.

Roadrunner entered into a $230 million senior secured credit facility for the construction and operation of the pipeline. The senior secured credit facility expires 7 years after the Roadrunner in-service date of Phase II, which is expected to be completed in the first quarter 2017. In addition, Roadrunner executed interest-rate swaps to hedge the variability of its interest payments during the term of the credit facility.

See additional discussion in the “Financial Results and Operating Information” section in our Natural Gas Pipelines segment.

Debt Issuance - In March 2015, we completed an underwritten public offering of $800 million of senior notes, generating net proceeds of approximately $792.3 million. We used the proceeds to repay amounts outstanding under our commercial paper program and for general partnership purposes.

Equity Issuances - In August 2015, we completed a private placement of approximately 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. The combined offerings generated net cash 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.

During the nine months ended September 30, 2015, we sold approximately 10.5 million common units through our “at-the-market” equity program, which includes the units sold to funds managed by Kayne Anderson Capital Advisors in the registered direct 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.

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. While there have been sharp declines in commodity prices over the past year, we are responding to the low commodity price environment by suspending certain capital-growth projects, aligning operating costs with the needs of our crude oil and natural gas producer customers, utilizing hedging to partially mitigate the low commodity prices and actively working to increase the fee-based component in the POP contracts in our Natural Gas Gathering and Processing segment, which is the segment with the most commodity price exposure. Each reporting period, we assess these qualitative factors to determine whether it is more likely than not that the fair value of each of our reporting units is less than its carrying amount. At July 1, 2015, we assessed qualitative factors to determine whether it was more likely than not that the fair value of each of our reporting units was less than its carrying amount. Due to the current commodity price environment, we elected to perform a quantitative assessment, or Step 1 analysis, to test our goodwill for

Table of Contents

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, 2015, 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 its 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,						2015 vs. 2014					2015 vs. 2014
Financial Results	2015			2014			2015			2014			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Revenues
Commodity sales	$	1,484.3		$	2,754.5		$	4,642.3		$	8,276.3		$	(1,270.2	)	(46	%)	$	(3,634.0	)	(44	%)
Services	414.1			364.9			1,188.4			1,071.1			49.2			13	%	117.3			11	%
Total revenues	1,898.4			3,119.4			5,830.7			9,347.4			(1,221.0		)	(39	%)	(3,516.7		)	(38	%)
Cost of sales and fuel	1,360.8			2,583.2			4,307.8			7,807.3			(1,222.4		)	(47	%)	(3,499.5		)	(45	%)
Net margin	537.6			536.2			1,522.9			1,540.1			1.4			—	%	(17.2		)	(1	%)
Operating costs	162.1			170.8			506.9			481.5			(8.7		)	(5	%)	25.4			5	%
Depreciation and amortization	87.5			73.9			259.5			212.1			13.6			18	%	47.4			22	%
Gain (loss) on sale of assets	(0.4		)	1.5			(0.3		)	1.5			(1.9		)	*		(1.8		)	*
Operating income	$	287.6		$	293.0		$	756.2		$	848.0		$	(5.4	)	(2	%)	$	(91.8	)	(11	%)
Equity in net earnings (loss)from investments	$	32.2		$	(52.3	)	$	93.2		$	6.7		$	84.5		*		$	86.5		*
Interest expense	$	(86.7	)	$	(70.1	)	$	(253.9	)	$	(211.3	)	$	16.6		24	%	$	42.6		20	%
Capital expenditures	$	300.5		$	380.5		$	928.9		$	1,173.0		$	(80.0	)	(21	%)	$	(244.1	)	(21	%)

* Percentage change is greater than 100 percent.

Commodity sales revenues and costs of sales and fuel decreased for the three and nine months ended September 30, 2015, compared with the same periods in 2014, due to higher propane and natural gas prices as well as wider NGL location and product price differentials experienced in the first quarter 2014 as a result of unusually high weather-related seasonal demand and a sharp decline in commodity prices that began in the fourth quarter 2014 and continued into 2015. The impact from the price decrease was offset partially by higher gathered and processed volumes and an improved contract mix in our Natural Gas Gathering and Processing segment and higher NGL volumes transported on gathering lines and fractionated in our Natural Gas Liquids segment for the three and nine months ended September 30, 2015, compared with the same periods in 2014.

Services revenues increased for the three and nine months ended September 30, 2015, compared with the same periods in 2014, due to higher natural gas and NGL volumes from our recently completed capital projects, including acquisitions, in our Natural Gas Gathering and Processing and Natural Gas Liquids segments and higher fees resulting from contract restructuring efforts in our Natural Gas Gathering and Processing segment.

Operating costs decreased for the three months ended September 30, 2015, compared with the same period in 2014, due primarily to higher scheduled maintenance and chemicals costs in the prior year, offset partially by increased employee costs from the growth of our operations related to our completed capital projects and acquisitions. Operating costs increased for the nine months ended September 30, 2015, compared with the same period in 2014, due primarily to increased employee costs from the growth of our operations related to our completed capital projects and acquisitions.

Depreciation and amortization expense increased for the three and nine months ended September 30, 2015, compared with the same periods in 2014, due primarily to the growth of our operations related to our completed capital projects and acquisitions.

Equity in net earnings from investments increased for the three and nine months ended September 30, 2015, compared with the same periods in 2014, due to an impairment charge in September 2014 of $76.4 million related to our equity method investment in Bighorn Gas Gathering in our Natural Gas Gathering and Processing segment and due to higher volumes in 2015 delivered to Overland Pass Pipeline from our Bakken NGL Pipeline in our Natural Gas Liquids segment.

Table of Contents

Interest expense increased for the three and nine months ended September 30, 2015, compared with the same periods in 2014, due primarily to higher short-term borrowings and rates, lower capitalized interest due to capital-growth projects completed and placed in service in 2014, and interest costs from our $800 million debt issuance in March 2015.

Capital expenditures decreased for the three and nine months ended September 30, 2015, compared with the same periods in 2014, due to the completion of several large projects in 2014 and the timing of expenditures for our growth projects.

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

Natural Gas Gathering and Processing

Overview - Our Natural Gas Gathering and Processing segment provides nondiscretionary services to crude oil and natural gas producers that include gathering and processing of natural gas produced from crude oil and natural gas wells. Unprocessed natural gas is compressed and gathered through pipelines and transported to processing facilities where volumes are aggregated, treated and processed to remove water vapor, solids and other contaminants, and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue natural gas. The residue natural gas, which consists primarily of methane, is compressed and delivered to natural gas pipelines for transportation to end users. When the NGLs are separated from the unprocessed natural gas at the processing plants, the NGLs are typically in the form of a mixed, unfractionated NGL stream that is delivered to natural gas liquids gathering pipelines for transportation to natural gas liquids fractionators.

We gather and process natural gas in the Mid-Continent region, which includes the NGL-rich Cana-Woodford Shale, Woodford Shale, Stack, SCOOP, Springer Shale and the Mississippian Lime formation of Oklahoma and Kansas, and the Hugoton and Central Kansas Uplift Basins of Kansas. We also gather and/or process natural gas in two producing basins in the Rocky Mountain region: the Williston Basin, which spans portions of Montana and North Dakota and includes the oil-producing, NGL-rich Bakken Shale and Three Forks formations; and the Powder River Basin of Wyoming, which includes the NGL-rich Frontier, Turner, Sussex and Niobrara Shale formations. Coal-bed methane, or dry natural gas, in the Powder River Basin does not require processing or NGL extraction in order to be marketable; dry natural gas is gathered, compressed and delivered into a downstream pipeline or marketed for a fee.

Revenues for this segment are derived primarily from POP contracts with fee-based components and fee-based contracts. Under a POP contract with fee-based 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. With a fee-based contract, we are paid a fee for the services we provide, based on volumes gathered, processed, treated and/or compressed. Many of our contracts contain provisions such as a minimum margin or fixed fees that ensures a minimum level of revenues regardless of commodity prices or volumetric throughput.

We expect our capital projects will continue to generate additional revenues, earnings and cash flows as they are completed. 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 prices received for our share of volumes. We have renegotiated many Natural Gas Gathering and Processing segment contracts to significantly increase our fee-based earnings and continue to actively work with our producer customers to similarly restructure additional contracts. We expect to substantially complete our negotiations on Williston Basin contracts in 2015 and receive the full benefit of the improved margins in 2016. Our NGLs, natural gas and crude oil commodity price sensitivity in this segment is expected to decrease in 2016 as contracts are renegotiated.

The significant growth in the development of crude oil and NGL-rich natural gas in the Williston Basin has caused natural gas production to exceed the capacity of existing natural gas gathering and processing infrastructure, which results in the flaring of natural gas (the controlled burning of natural gas at the wellhead) by many crude oil and natural gas producers. In July 2014, the North Dakota Industrial Commission (NDIC) approved a policy designed to limit flaring at existing and future crude oil wells in the Williston Basin. The policy establishes crude oil production limits that will take effect if a producer fails to meet requirements to capture natural gas at the wellhead. We continue to actively participate on the Flaring Task Force, which provides recommendations to the NDIC on policies and targets. The NDIC recently passed updated natural gas capture percentages and associated timelines. None of these changes are expected to have a material impact on volume. We are constructing additional natural gas gathering pipelines, compression and processing plants, and natural gas liquids pipeline capacity that are expected to help alleviate capacity constraints. We have completed three of six compressor stations expected to be constructed in 2015. Together, the six compression stations will add 300 MMcf/d of natural gas gathering capacity to our system in the Williston Basin.

Table of Contents

We expect our natural gas gathered and processed volumes to continue to grow in 2016, despite reductions in crude oil and natural gas producer drilling activity. Volumes are expected to increase in the Williston Basin due to the following:


•	the opportunity to capture additional natural gas currently being flared by producers as we add additional natural gas compression and processing capacity on our systems;


•	the connection of wells that have been drilled but not yet completed or connected to our systems;


•	producers focusing their drilling in high-return areas, in which we have significant gathering and processing assets, which typically produce at higher initial production rates compared with other areas;


•	the use by producers of more efficient rigs, which are capable of drilling faster; and


•	continued improvements in production results by producers due to enhanced completion techniques.

In the Mid-Continent region, a large customer drilled wells in the first half of 2015 with well completions beginning in the third quarter 2015 and expected to continue through the fourth quarter 2015. The additional volumes from these new wells are expected to offset the natural declines of existing production in this region.

Growth Projects - Our Natural Gas Gathering and Processing segment is investing in growth projects in NGL-rich areas in the Williston Basin, the Powder River Basin, the Cana-Woodford Shale, the Springer Shale, the Stack and the SCOOP areas that we expect will enable us to meet the growing needs of crude oil and natural gas producers in those areas. Nearly all of the new natural gas production is from horizontally drilled and completed wells in unconventional 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 2014 and through the third quarter 2015, we have completed the following projects:



Completed Projects	Location	Capacity	Approximate Costs (a)	Completion Date
			(In millions)
Rocky Mountain Region
Garden Creek II processing plant and infrastructure	Williston Basin	100 MMcf/d	$310	August 2014
Garden Creek III processing plant and infrastructure	Williston Basin	100 MMcf/d	$310	October 2014
Mid-Continent Region
Canadian Valley processing plant and infrastructure	Cana-Woodford Shale	200 MMcf/d	$255	March 2014

(a) - Excludes AFUDC.

We have the following natural gas processing plants and related infrastructure in various stages of construction:



Projects in Progress	Location	Capacity	Approximate Costs (a)	Expected Completion Date
			(In millions)
Rocky Mountain Region
Sage Creek infrastructure	Powder River Basin	Various	$35	Fourth quarter 2015
Natural gas compression	Williston Basin	100 MMcf/d	$80-$90	Fourth quarter 2015
Lonesome Creek processing plant and infrastructure	Williston Basin	200 MMcf/d	$550-$680	Fourth quarter 2015
Stateline de-ethanizers	Williston Basin	26 MBbl/d	$60-$80	Third quarter 2016
Bear Creek processing plant and infrastructure	Williston Basin	80 MMcf/d	$230-$330	Third quarter 2016
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			$1,800-$2,555

(a) - Excludes AFUDC.

As a result of reductions in crude oil and natural gas drilling activities by producers due to the decline in crude oil, natural gas and NGL prices and our expectation of continued slower supply growth, we have suspended capital expenditures for certain natural gas processing plants and field infrastructure. We are in a position to quickly resume our suspended capital-growth projects as soon as 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.

Table of Contents

Rocky Mountain Region:

Williston Basin Processing Plants and related projects - We are constructing natural gas gathering and processing assets in the Williston Basin to meet the growing needs of crude oil and natural gas producers. When our announced projects are completed, we will have natural gas processing capacity of approximately 1.2 Bcf/d in the basin. We have acreage dedications of approximately 3 million net acres supporting these projects.

Natural Gas Compression - In July 2014, we announced we will construct additional natural gas compressor stations across our Williston Basin system to take advantage of additional natural gas processing capacity at our Garden Creek and Stateline facilities by a total of 100 MMcf/d.

Lonesome Creek Plant - In November 2013, we announced we will construct the Lonesome Creek natural gas processing plant and related infrastructure, which will be located in McKenzie County, North Dakota. The plant and infrastructure will help address natural gas gathering and processing constraints in the region.

Stateline De-ethanizers - In December 2014, we announced we will construct de-ethanizers at our Stateline natural gas processing plants, which are located in Williams County, North Dakota. Once completed, the de-ethanizers will remove ethane from the natural gas liquids stream, which we expect to then be sold under a long-term contract to a customer who plans to transport the ethane on a third-party pipeline.

Bear Creek Plant - In September 2014, we announced we will construct the Bear Creek natural gas processing plant and related infrastructure, which will be located in Dunn County, North Dakota. The plant and infrastructure will help alleviate pipeline inefficiencies in an area challenged by geographical constraints and severe terrain.

Demicks Lake Plant - In July 2014, we announced the Demicks Lake natural gas processing plant and related infrastructure, which will be located in northeast McKenzie County, North Dakota, to help further address natural gas gathering and processing constraints in the region. The Demicks Lake Plant is currently suspended but can be quickly resumed as market conditions improve.

Powder River Basin - We have announced natural gas gathering and processing projects in the NGL-rich areas of the Powder River Basin, a region with the potential for significant growth in natural gas and NGL production volumes. We have acreage dedications of approximately 130,000 net acres supporting these projects.

Sage Creek Infrastructure - We plan to construct new natural gas gathering infrastructure at our Sage Creek plant to meet the growing production of NGL-rich natural gas in this area. We have supply contracts providing for long-term acreage dedications from crude oil and natural gas producers in the area supporting this project.

Bronco Plant - In September 2014, we announced the Bronco natural gas processing plant and related natural gas gathering and natural gas liquids infrastructure in Campbell and Converse counties, Wyoming. The plant was originally announced as a 100 MMcf/d facility, but was reduced to 50 MMcf/d due to slower growth in the current low commodity price environment. The Bronco Plant is currently suspended but can be quickly resumed as market conditions improve.

Mid-Continent Region:

Cana-Woodford Shale, Woodford Shale, Springer Shale, Stack and SCOOP areas - We have announced natural gas gathering and processing projects to meet the growing production of NGL-rich natural gas in the Cana-Woodford Shale, Woodford Shale, Springer Shale, Stack and SCOOP areas. When our announced projects are completed, our Oklahoma natural gas processing capacity will be approximately 900 MMcf/d. We have substantial acreage dedications from crude oil and natural gas producers supporting these projects.

Knox Plant - In July 2014, we announced the Knox natural gas processing plant and related infrastructure, which will be located in Grady and Stephens Counties, Oklahoma. The plant and related infrastructure will gather and process liquids-rich natural gas from the Cana-Woodford Shale and the emerging SCOOP area and will be located in close proximity to our existing natural gas gathering and processing assets and natural gas and natural gas liquids pipelines. The Knox Plant is currently suspended but can be quickly resumed as market conditions improve.

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

Table of Contents

Selected Financial Results - Our Natural Gas Gathering and Processing segment’s financial results for the three and nine months ended September 30, 2015, reflect the benefits from additional natural gas compression projects completed in 2015; the Garden Creek III natural gas processing plant, which was completed in October 2014; and the Garden Creek II natural gas processing plant, which was completed in August 2014. Additionally, financial results for the nine months ended September 30, 2015, reflect the benefits of the Canadian Valley natural gas processing plant, which was completed in March 2014.

The completion of the natural gas compression projects and Garden Creek II and Garden Creek III natural gas processing plants resulted in increased natural gas volumes gathered and processed in the Williston Basin, and completion of the Canadian Valley natural gas processing plant resulted in increased natural gas volumes gathered in Oklahoma.

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,					2015 vs. 2014					2015 vs. 2014
Financial Results	2015		2014			2015		2014			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
NGL sales	$	118.7	$	394.1		$	423.1	$	1,128.8		$	(275.4	)	(70	%)	$	(705.7	)	(63	%)
Condensate sales	12.3		24.5			39.9		82.0			(12.2		)	(50	%)	(42.1		)	(51	%)
Residue natural gas sales	211.2		284.0			635.6		849.4			(72.8		)	(26	%)	(213.8		)	(25	%)
Gathering, compression, dehydration and processing fees and other revenue	92.1		75.2			251.4		203.1			16.9			22	%	48.3			24	%
Cost of sales and fuel	293.6		599.6			947.5		1,776.6			(306.0		)	(51	%)	(829.1		)	(47	%)
Net margin	140.7		178.2			402.5		486.7			(37.5		)	(21	%)	(84.2		)	(17	%)
Operating costs	61.2		64.3			193.9		188.5			(3.1		)	(5	%)	5.4			3	%
Depreciation and amortization	37.3		31.3			109.0		89.6			6.0			19	%	19.4			22	%
Gain (loss) on sale of assets	0.1		0.3			0.3		0.3			(0.2		)	(67	%)	—			—	%
Operating income	$	42.3	$	82.9		$	99.9	$	208.9		$	(40.6	)	(49	%)	$	(109.0	)	(52	%)
Equity in net earnings (loss) from investments	$	4.4	$	(71.1	)	$	13.5	$	(60.5	)	$	75.5		*		$	74.0		*
Capital expenditures	$	231.8	$	214.9		$	692.6	$	506.0		$	16.9		8	%	$	186.6		37	%

* Percentage change is greater than 100 percent.

Commodity prices declined sharply in the fourth quarter 2014 and remained at relatively lower levels throughout the first nine months of 2015. We expect lower commodity prices to persist throughout the remainder of 2015, with a modest recovery in 2016. Therefore, we expect crude oil, natural gas and NGL supply growth to continue to slow. As crude oil and natural gas exploration and production capital investment has decreased due to market conditions, crude oil and natural gas producers are focusing their drilling activities in high-return areas that are most economical to develop and have higher production volumes, which offsets partially the reduction in drilling. The lower commodity price environment is having a significant impact on our Natural Gas Gathering and Processing segment’s financial results in 2015 compared with 2014.

Net margin decreased for the three months ended September 30, 2015, compared with the same period in 2014, primarily as a result of the following:


•	a decrease of $53.9 million due primarily to lower net realized NGL, natural gas and condensate prices;


•	a decrease of $7.0 million due primarily to unplanned operational outages in the Williston Basin and decreased natural gas processed volumes in the Cana-Woodford Shale, offset partially by natural gas volume growth in the Williston Basin; and


•	a decrease of $3.7 million due primarily to decreased ethane rejection to maintain downstream NGL product specifications; offset partially by


•	an increase of $27.1 million due primarily to changes in contract mix resulting from higher fee rates.

Net margin decreased for the nine months ended September 30, 2015, compared with the same period in 2014, primarily as a result of the following:


•	a decrease of $153.3 million due primarily to lower net realized NGL, natural gas and condensate prices; and


•	a decrease of $4.6 million due primarily to decreased ethane rejection to maintain downstream NGL product specifications; offset partially by

Table of Contents


•	an increase of $47.9 million due primarily to changes in contract mix resulting from higher fee rates; and


•	an increase of $25.8 million due primarily to natural gas volume growth in the Williston Basin, offset partially by unplanned operational outages in the Williston Basin and decreased natural gas volumes in the Cana-Woodford Shale.

Operating costs decreased for the three months ended September 30, 2015, compared with the same period in 2014, primarily as a result of the following:


•	a decrease of $4.1 million in materials and supplies due primarily to higher chemicals costs in the prior year; and


•	a decrease of $2.4 million in ad valorem taxes due to the timing of ad valorem tax estimates; offset partially by


•	an increase of $2.3 million in employee-related costs due to higher labor and employee benefit costs resulting from the completion of our growth projects; and


•	an increase of $1.1 million in outside services expense due primarily to the completion of our growth projects.

Operating costs increased for the nine months ended September 30, 2015, compared with the same period in 2014, primarily as a result of the completion of our growth projects, which include the following:


•	an increase of $7.9 million in employee-related costs due to higher labor and employee benefit costs; and


•	an increase of $6.3 million in outside services expense; offset partially by


•	a decrease of $8.4 million in materials and supplies due primarily to higher chemicals costs in the prior year.

Depreciation and amortization expense increased for the three and nine months ended September 30, 2015, compared with the same periods in 2014, due to the completion of growth projects.

Equity in net earnings from investments increased for the three and nine months ended September 30, 2015, compared with the same periods in 2014, due to $76.4 million in impairment charges in the third quarter 2014 related to our investment in Bighorn Gas Gathering.

Capital expenditures increased for the three and nine months ended September 30, 2015, compared with the same periods in 2014, due primarily to the timing of expenditures for our growth projects discussed above.

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)	2015		2014		2015		2014
Natural gas gathered (BBtu/d)	1,897		1,847		1,877		1,665
Natural gas processed (BBtu/d) (b)	1,617		1,666		1,640		1,462
NGL sales (MBbl/d)	134		111		123		100
Residue natural gas sales (BBtu/d)	837		792		828		682
Realized composite NGL net sales price ($/gallon) (c) (d)	$	0.31	$	0.93	$	0.35	$	0.97
Realized condensate net sales price ($/Bbl) (c) (e)	$	42.32	$	81.02	$	35.80	$	78.00
Realized residue natural gas net sales price ($/MMBtu) (c) (e)	$	3.62	$	3.92	$	3.64	$	3.91
Average fee rate ($/MMBtu)	$	0.43	$	0.36	$	0.39	$	0.36

(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 volumes, NGL sales volumes and residue natural gas sales volumes increased during the three months ended September 30, 2015, compared with the same period in 2014, due to the completion of growth projects in the Williston Basin. Natural gas processed volumes decreased during the three months ended September 2015, compared with the same period in 2014, due to unplanned operational outages in the Williston Basin, natural declines in the Cana-Woodford Shale and minor timing delays in well connections in the Mid-Continent. We expect volumes to increase in the fourth quarter 2015 as unplanned operational outages from the third quarter in the Williston Basin have been resolved, a large producer continues to complete wells in the Cana-Woodford Shale that were drilled earlier in 2015, and our remaining compression projects are completed.

Table of Contents

Natural gas gathered and processed volumes, NGL sales volumes and residue natural gas sales volumes increased during the nine months ended September 30, 2015, compared with the same period in 2014, due to the completion of growth projects in the Williston Basin and in the Mid-Continent area.

In March 2014, our Canadian Valley plant in Oklahoma was completed, which has better ethane rejection capabilities than our other processing plants in the Mid-Continent region. Beginning in June 2015, we reduced the level of ethane rejection in the Rocky Mountain region to address downstream NGL product specifications. We expect the decreased level of ethane rejection to continue into 2016. We expect the quantity and composition of NGLs and natural gas will continue to change as our new natural gas processing plants in the Williston Basin are placed in service.



	Three Months Ended		Nine Months Ended
	September 30,		September 30,
Equity Volume Information (a)	2015	2014	2015	2014

NGL sales (MBbl/d)	24.9	16.0	21.0	16.6
Condensate sales (MBbl/d)	2.7	2.6	3.0	3.1
Residue natural gas sales (BBtu/d)	136.3	134.5	141.6	109.6

(a) - Includes volumes for consolidated entities only.

Commodity Price Risk - The following tables set forth our Natural Gas Gathering and Processing segment’s hedging information. The tables below reflect the NGLs for propane, normal butane, iso-butane and natural gasoline only since the ethane component of our equity NGL volume is not hedged and is not expected to be material to our results of operations. The segment’s hedging information as of October 2015 for our equity volumes is as follows for the periods indicated:



	Three Months Ending December 31, 2015
	Volumes Hedged	Average Price			Percentage Hedged
NGLs - excluding ethane (MBbl/d) - Conway/Mont Belvieu	13.6	$	0.64	/ gallon	84%
Condensate (MBbl/d) - WTI-NYMEX	2.6	$	54.69	/ Bbl	96%
Natural gas (BBtu/d) - NYMEX and basis	122.8	$	3.64	/ MMBtu	97%



	Year Ending December 31, 2016
	Volumes Hedged	Average Price			Percentage Hedged
NGLs - excluding ethane (MBbl/d) - Conway/Mont Belvieu	4.9	$	0.54	/ gallon	49%
Condensate (MBbl/d) - WTI-NYMEX	1.5	$	62.65	/ Bbl	48%
Natural gas (BBtu/d) - NYMEX and basis	74.1	$	2.96	/ MMBtu	83%

We have renegotiated many Natural Gas Gathering and Processing segment contracts to significantly increase our fee-based earnings and continue to actively work with our producer customers to similarly restructure additional contracts. Our NGLs, natural gas and crude oil commodity price sensitivity in this segment is expected to decrease in 2016 as contracts are renegotiated. 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, 2015, excluding the effects of hedging and assuming normal operating conditions. Our condensate sales are based on the price of crude oil. We estimate the following for the three months ending December 31, 2015:


•	a $0.01 per-gallon change in the composite price of NGLs would change three-month net margin by approximately $0.8 million;


•	a $1.00 per-barrel change in the price of crude oil would change three-month net margin by approximately $0.3 million; and


•	a $0.10 per-MMBtu change in the price of residue natural gas would change three-month net margin by approximately $1.2 million.

We estimate the following for the year ending December 31, 2016:


•	a $0.01 per-gallon change in the composite price of NGLs would change 12-month net margin by approximately $1.8 million;

Table of Contents


•	a $1.00 per-barrel change in the price of crude oil would change 12-month net margin by approximately $1.3 million; and


•	a $0.10 per-MMBtu change in the price of residue natural gas would change 12-month net margin by approximately $3.3 million.

These estimates do not include any effects on demand for our services or 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, affecting natural gas gathering and processing margins for certain contracts.

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

Powder River Basin - Crude oil and natural gas producers have primarily focused their development efforts on crude oil and NGL-rich supply basins rather than in areas with dry natural gas production, such as the coal-bed methane production areas in the Powder River Basin. The reduced coal-bed methane development activities and production declines in the dry natural gas formations of the Powder River Basin have resulted in lower natural gas volumes available to be gathered. While the reserve potential in the dry natural gas formations of the Powder River Basin still exists, future drilling and development in this area will be affected by commodity prices and producers’ alternative prospects.

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. 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 with our natural gas liquids fractionation and pipeline assets and utilized in our NGL marketing activities. In November 2014, we began transporting unfractionated NGLs from natural gas processing plants in the Permian Basin after completion of the West Texas LPG acquisition.

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 the 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 and propane distributors. We also purchase NGLs and condensate from third parties, as well as from our Natural Gas Gathering and Processing segment.

Revenues 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. Our fee-based services have increased due primarily to new supply connections; expansion of existing connections; and the completion of capital projects, including our Bakken NGL Pipeline and Sterling III Pipeline; the West Texas LPG acquisition; and expansion of our NGL fractionation capacity, including the completion of our MB-2 and MB-3 fractionators. Our sources of revenue are categorized as exchange services, optimization and marketing, pipeline transportation, and isomerization and storage, which are defined as follows:


•	Our exchange-services activities utilize our assets to gather, fractionate and/or treat unfractionated NGLs for a fee, 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.

Table of Contents

•

Our optimization and marketing activities utilize our assets, contract portfolio and market knowledge to capture location, product and seasonal price differentials. We transport NGL products between Conway, Kansas, and Mont Belvieu, Texas, to capture the location price differentials between the two market centers. Our natural gas liquids storage facilities also are utilized to capture seasonal price variances. A growing portion of our marketing activities serves truck and rail markets.


•	Our pipeline transportation services transport unfractionated NGLs, 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 isomerization activities capture the price differential when normal butane is converted into the more valuable iso-butane at our isomerization unit in Conway, Kansas. Iso-butane is used in the refining industry to increase the octane of motor gasoline.


•	Our storage activities consist primarily of fee-based NGL storage services at our Mid-Continent and Gulf Coast storage facilities.

NGL location price differentials have generally remained narrow between the Mid-Continent and Gulf Coast market centers. We expect these narrow NGL price differentials, with periods of volatility for certain NGL products, to continue as new fractionators and pipelines, including our growth projects discussed below, help alleviate constraints that have historically existed between the Conway, Kansas, and Mont Belvieu, Texas, natural gas liquids market centers. In addition, new natural gas liquids pipeline projects constructed by third parties have started to bring incremental NGL supply from the Rocky Mountain, Marcellus and Utica regions to the Mont Belvieu, Texas, market center that may affect NGL prices, as well as compete with or displace NGL supply volumes from the Mid-Continent and Rocky Mountain regions where our assets are located. Our Natural Gas Liquids segment’s capital-growth projects are supported by fee-based contractual commitments that we expect will fill much of our optimization capacity used historically to capture NGL location price differentials between the two market centers.

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, Permian and Rocky Mountain regions during 2014 and the first nine months of 2015. 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. We expect ethane rejection to persist at current levels until ethylene producers increase their capacity to consume additional ethane feedstock volumes through plant modifications, plant expansions and the completion of announced new world-scale ethylene production projects beginning in 2017. Ethane rejection is expected to continue to have a significant impact on our financial results through 2017. However, beginning in June 2015, our Natural Gas Gathering and Processing segment reduced its level of ethane rejection in the Rocky Mountain region to alleviate downstream NGL product specification issues, which offsets partially this financial impact. We expect this decreased ethane rejection to continue into 2016. In addition, our Natural Gas Liquids segment’s integrated assets enable it 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. See additional discussion in the “Financial Results and Operating Information” section.

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 propane, also is increasing and is expected to continue to do so in the future.

Our Natural Gas Liquids segment is investing in NGL-related projects to accommodate the transportation and fractionation of NGL supply from shale and other resource development areas across our asset base and alleviate expected infrastructure constraints between the Mid-Continent and Gulf Coast market centers to meet increasing petrochemical industry and NGL export demand in the Gulf Coast. Over time, these growing fee-based NGL volumes are expected to fill much of our natural gas liquids pipeline capacity used historically to capture the NGL location price differentials between the two market centers.

Table of Contents

We have completed the following growth projects in this segment in 2014 and through the third quarter 2015:



Completed Projects	Location	Capacity	Approximate Costs (a)	Completion Date
			(In millions)
Ethane/Propane Splitter	Texas Gulf Coast	40 MBbl/d	$46	March 2014
Sterling III Pipeline and reconfigure Sterling I and II	Mid-Continent Region	193 MBbl/d	$808	March 2014
Bakken NGL Pipeline expansion - Phase I	Rocky Mountain Region	75 MBbl/d	$90	September 2014
Niobrara NGL Lateral	Powder River Basin	90 miles	$65	September 2014
West Texas LPG (b)	Permian Basin	2,600 miles	$800	November 2014
MB-3 Fractionator	Texas Gulf Coast	75 MBbl/d	$520-$540	December 2014
NGL Pipeline and Hutchinson Fractionator infrastructure	Mid-Continent Region	95 miles	$115-$120	April 2015

(a) - Excludes AFUDC.

(b) - Acquisition.

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 2016
Bear Creek NGL infrastructure	Williston Basin	40 miles	$35-$45	Third quarter 2016
Bronco NGL infrastructure	Powder River Basin	65 miles	$45-$60	Suspended
Demicks Lake NGL infrastructure	Williston Basin	12 miles	$10-$15	Suspended
Total			$190-$220

(a) - Excludes AFUDC.

As a result of reductions in crude oil and natural gas drilling activities and our expectation of continued slower supply growth due to the declines in 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 expect to resume our suspended capital-growth projects as soon as market conditions improve. 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.

Natural gas liquids pipeline and modification of Hutchinson fractionation infrastructure - In April 2015, we completed a new 95-mile natural gas liquids pipeline that connects our existing natural gas liquids fractionation and storage facilities in Hutchinson, Kansas, to similar facilities in Medford, Oklahoma. The project also included modifications to existing natural gas liquids fractionation infrastructure at Hutchinson, Kansas, increasing fractionation capacity by 20 MBbl/d to accommodate additional unfractionated NGLs produced in the Williston Basin.

Bakken NGL Pipeline expansion, Phase II - The second expansion will increase the pipeline’s capacity to 160 MBbl/d from the current capacity of 135 MBbl/d.

Bear Creek natural gas liquids infrastructure - We announced in September 2014 our plan to build new natural gas liquids pipeline infrastructure to connect the Bear Creek natural gas processing plant to our Bakken NGL Pipeline.

Bronco natural gas liquids infrastructure - We announced in September 2014 our plan to build new natural gas liquids pipeline infrastructure to connect the Bronco natural gas processing plant to our Bakken NGL Pipeline. Due to the suspension of the Bronco Plant, the Bronco natural gas liquids infrastructure is currently suspended but can be quickly resumed as market conditions improve.

Demicks Lake natural gas liquids infrastructure - We announced in July 2014 our plan to build new natural gas liquids pipeline infrastructure to connect the Demicks Lake natural gas processing plant to our Bakken NGL Pipeline. Due to the suspension of the Demicks Lake Plant, the Demicks Lake natural gas liquids infrastructure is currently suspended but can be quickly resumed as market conditions improve.

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

Table of Contents

Selected Financial Results - Our Natural Gas Liquids segment’s financial results for the three and nine months ended September 30, 2015, reflect the benefits from the following projects and acquisition:


•	the NGL Pipeline and Hutchinson Fractionator infrastructure, which was completed in April 2015;


•	the MB-3 Fractionator, which was completed in December 2014;


•	the West Texas LPG acquisition, which was completed in November 2014;


•	the Bakken NGL Pipeline expansion Phase I, which was completed in September 2014; and


•	the Niobrara NGL Lateral, which was completed in September 2014.

Additionally, the financial results for the nine months ended September 30, 2015, reflect the benefits from the following projects:


•	the Ethane/propane splitter, which was completed in March 2014; and


•	the Sterling III Pipeline and reconfiguration of the Sterling II Pipeline, which were completed in March 2014.

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,						2015 vs. 2014					2015 vs. 2014
Financial Results	2015			2014			2015			2014			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	1,253.1		$	2,450.2		$	3,965.2		$	7,341.0		$	(1,197.1	)	(49	%)	$	(3,375.8	)	(46	%)
Exchange service and storage revenues	313.2			265.0			861.8			710.9			48.2			18	%	150.9			21	%
Transportation revenues	45.1			19.3			129.4			59.7			25.8			*		69.7			*
Cost of sales and fuel	1,289.6			2,451.5			4,054.0			7,293.5			(1,161.9		)	(47	%)	(3,239.5		)	(44	%)
Net margin	321.8			283.0			902.4			818.1			38.8			14	%	84.3			10	%
Operating costs	74.5			77.0			234.1			218.2			(2.5		)	(3	%)	15.9			7	%
Depreciation and amortization	39.3			31.7			118.1			89.8			7.6			24	%	28.3			32	%
Gain (loss) on sale of assets	(0.5		)	(0.5		)	(0.6		)	(0.6		)	—			—	%	—			—	%
Operating income	$	207.5		$	173.8		$	549.6		$	509.5		$	33.7		19	%	$	40.1		8	%
Equity in net earnings from investments	$	10.9		$	4.4		$	27.6		$	13.6		$	6.5		*		$	14.0		*
Capital expenditures	$	52.8		$	153.8		$	185.4		$	637.5		$	(101.0	)	(66	%)	$	(452.1	)	(71	%)

* Percentage change is greater than 100 percent.

Crude prices declined sharply in the fourth quarter 2014 and remained relatively low during the first nine months of 2015, which impacted NGL prices as NGL prices generally are linked to crude oil prices. These price decreases affected our NGL and condensate sales revenue and cost of sales and fuel in our Consolidated Statements of Income.

In the first quarter 2014, we experienced increased propane demand and prices, which impacted our results of operations for the three and nine months ended September 30, 2014, due to colder than normal weather. The price of propane in the Mid-Continent market and the wider location price differentials between the Mid-Continent and Gulf Coast market centers peaked in late January 2014 and returned to historical levels by the end of February 2014 as supply and demand balanced.

Net margin increased for the three months ended September 30, 2015, compared with the same period in 2014, primarily as a result of the following:


•	an increase of $27.5 million in exchange-services margins, which resulted primarily from increased volumes from new plant connections in the Williston Basin, Powder River Basin and Mid-Continent region, offset partially by unplanned operational outages at our natural gas processing plants in the Williston Basin;


•	an increase of $26.1 million in transportation margins due primarily to volumes from the Permian Basin from the West Texas LPG system, which was acquired in November 2014;


•	an increase of $12.5 million resulting from decreased ethane rejection in the Williston Basin, offset partially by higher ethane rejection in the Mid-Continent region; and


•	an increase of $1.1 million in higher storage margin; offset partially by


•	a decrease of $17.2 million in optimization and marketing margins, which resulted from an $18.4 million decrease due primarily to narrower NGL product price differentials and a $3.6 million decrease in marketing margins, offset

Table of Contents

partially by a $4.8 million increase due primarily to wider NGL location price differentials;


•	a decrease of $6.2 million related to lower isomerization volumes, resulting from the narrower NGL product price differentials between normal butane and iso-butane; and


•	a decrease of $5.0 million due to the impact of operational measurement gains in 2014 and operational measurement losses in 2015.

Net margin increased for the nine months ended September 30, 2015, compared with the same period in 2014, primarily as a result of the following:

•

an increase of $149.7 million in exchange-services margins, which resulted primarily from increased volumes from new plant connections in the Williston Basin, Powder River Basin and Mid-Continent region, higher fees for exchange-services activities resulting from contract negotiations, and higher revenues from customers with minimum volume obligations, offset partially by unplanned operational outages at our natural gas processing plants in the Williston Basin during the third quarter 2015;


•	an increase of $67.1 million in transportation margins due primarily to volumes from the Permian Basin from the West Texas LPG system, which was acquired in November 2014; and


•	an increase of $2.0 million resulting from decreased ethane rejection in the Williston Basin, offset partially by higher ethane rejection in the Mid-Continent region; offset partially by

•

a decrease of $100.2 million in optimization and marketing margins, which resulted from a $55.7 million decrease due primarily to narrower NGL product price differentials, a $25.8 million decrease due primarily to significantly narrower NGL location price differentials and an $18.7 million decrease in marketing margins. These decreases relate primarily to the increased demand for propane we experienced during the first quarter 2014;


•	a decrease of $26.6 million related to lower isomerization volumes, resulting from the narrower NGL product price differential between normal butane and iso-butane; and


•	a decrease of $8.8 million due to the impact of operational measurement gains in 2014 and operational measurement losses in 2015.

Operating costs decreased for the three months ended September 30, 2015, compared with the same period in 2014, primarily as a result of the following:


•	a decrease of $3.9 million due to lower outside services expense and miscellaneous supplies and expenses due primarily to scheduled maintenance in the prior year; offset partially by


•	an increase of $1.4 million due to higher employee-related costs due primarily to higher labor and employee benefit costs as a result of the completion of our growth projects and acquisitions.

Operating costs increased for the nine months ended September 30, 2015, compared with the same period in 2014, primarily as a result of the completion of our growth projects and acquisitions, and include the following:


•	an increase of $8.6 million due to higher employee-related costs due primarily to higher labor and employee benefit costs; and


•	an increase of $6.9 million due to higher ad valorem taxes.

Depreciation and amortization expense increased for the three and nine months ended September 30, 2015, compared with the same periods in 2014, due to depreciation associated with completed capital projects, including acquisitions.

Equity in net earnings from investments increased for the three and nine months ended September 30, 2015, compared with the same periods in 2014, due primarily to higher volumes delivered to Overland Pass Pipeline from our Bakken NGL Pipeline.

Capital expenditures decreased for the three and nine months ended September 30, 2015, compared with the same periods in 2014, due primarily to the timing of expenditures for our growth projects discussed above.

Table of Contents

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	2015		2014		2015		2014
NGL sales (MBbl/d)	683		626		657		598
NGLs transported-gathering lines (MBbl/d) (a)	786		529		759		508
NGLs fractionated (MBbl/d) (b)	591		553		540		515
NGLs transported-distribution lines (MBbl/d) (a)	456		377		422		412
Average Conway-to-Mont Belvieu OPIS price differential - ethane in ethane/propane mix ($/gallon)	$	0.02	$	0.03	$	0.02	$	0.06

(a) - Includes volumes for consolidated entities only.

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

NGLs transported on gathering lines and NGLs fractionated increased for the three and nine months ended September 30, 2015, compared with the same periods in 2014, due to increased volumes from new plant connections in the Williston Basin, Powder River Basin and Mid-Continent region, and decreased ethane rejection in the Rocky Mountain region beginning in June 2015 due to downstream NGL product specifications, offset partially by increased ethane rejection in the Mid-Continent region and unplanned operational outages at our natural gas processing plants in the Williston Basin during the third quarter 2015. Gathered volumes increased approximately 20 MBbl/d in the Rocky Mountain region due to decreased ethane rejection in the third quarter 2015, and we expect this decreased level of rejection to continue into 2016. NGLs transported on gathering lines also increased significantly for the three and nine months ended September 30, 2015, compared with the same periods in 2014, due to volumes from the Permian Basin transported on the West Texas LPG system, which was acquired in November 2014.

NGLs transported on distribution lines increased for the three and nine months ended September 30, 2015, compared with the same periods in 2014, due primarily to higher gathered and fractionated volumes as discussed above.

Natural Gas Pipelines

Overview - Our Natural Gas Pipelines segment owns and operates regulated natural gas transmission pipelines and natural gas storage facilities. We also provide interstate natural gas transportation and storage service in accordance with Section 311(a) of the Natural Gas Policy Act.

Our FERC-regulated interstate natural gas pipeline assets transport natural gas through pipelines 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 bi-directional 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;


•	Viking Gas Transmission, which is a bi-directional system, interconnects with a TransCanada Corporation pipeline near Emerson, Manitoba, 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 interconnects in Oklahoma, Texas and New Mexico.

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 Cana-Woodford Shale, Woodford Shale, Springer Shale, Granite Wash, Stack, SCOOP and Mississippian Lime. In Texas, our intrastate natural gas pipelines are connected to the major natural gas producing formations in the Texas Panhandle, including the Granite Wash formation and Delaware and Cline producing formations in the Permian Basin; and transport natural gas throughout the western portion of Texas, including the Waha Hub where other pipelines may be accessed for transportation to western markets, the Houston Ship Channel market to the east and the Mid-Continent market to the north. We also have access to the natural gas producing formations in south central Kansas.

We own underground natural gas storage facilities in Oklahoma and Texas that are connected to our intrastate natural gas pipeline assets. We also have underground natural gas storage facilities in Kansas.

Table of Contents

Our transportation contracts for our regulated natural gas activities are based upon rates stated in our tariffs. Tariffs specify the maximum rates that customers may be charged, which may be discounted to meet competition if necessary, and the general terms and conditions for pipeline transportation service, which are established at FERC or appropriate state jurisdictional agency proceedings known as rate cases. In Texas and Kansas, natural gas storage service is a fee business that 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 also a fee business but are not subject to rate regulation by the state and have market-based rate authority from the FERC for certain types of services.

Our Natural Gas Pipelines segment’s revenues are derived primarily from fee-based services. Revenues are generated from the following types of fee-based contracts:

•

Firm service - Customers can reserve a fixed quantity of pipeline or storage capacity for the term of their contract. Under this type of contract, the customer pays a fixed fee for a specified quantity regardless of their actual usage. The customer then typically pays incremental fees, known as commodity charges, that are based upon the actual volume of natural gas they transport or store, and/or we may retain a specified volume of natural gas in-kind for fuel. Under the firm-service contract, the customer generally is guaranteed access to the capacity they reserve; and

•

Interruptible service - Customers with interruptible service transportation and storage agreements may utilize available capacity after firm-service requests are satisfied or on an as-available basis. Interruptible service customers typically are assessed fees, such as a commodity charge, based on their actual usage, and/or we may retain a specified volume of natural gas in-kind for fuel. Under the interruptible service contract, the customer is not guaranteed use of our pipelines and storage facilities unless excess 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. WesTex is a wholly owned project.



Projects in Progress	Location	Capacity	Approximate Costs (a)	Expected Completion Date
			(In millions)
WesTex Transmission Pipeline Expansion	Permian Basin	260 MMcf/d	$70-$100	First quarter 2017
Roadrunner Gas Transmission Pipeline - Equity Method Investment
Phase I (b)	Permian Basin	170 MMcf/d	$200-$220	First quarter 2016
Phase II (b)	Permian Basin	400 MMcf/d	$220-$240	First quarter 2017
Phase III (b)	Permian Basin	70 MMcf/d	$30-$40	2019
Roadrunner Gas Transmission Pipeline Total			$450-$500

(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.

Roadrunner was fully subscribed for its initial design through an open season process held in December 2014. Precedent agreements representing the initial design capacity have been executed with the Comisión Federal de Electricidad and a Fermaca subsidiary. All transportation agreements will be firm demand charge and will have a term of 25 years. Additional capacity could become available through future expansions depending on the demands of the market.

We will manage the construction of the project and will be the operator of the pipeline upon its completion. The estimated total cost of the project is approximately $450 million to $500 million. We contributed approximately $30 million to Roadrunner in the nine months ended September 30, 2015, and do not expect to make any further contributions in 2015. These contributions are generally being used for acquisition of right of way, pipe and materials. We expect to contribute approximately $65 million

Table of Contents

to Roadrunner during 2016. Roadrunner entered into a $230 million senior secured credit facility for the construction and operation of the pipeline. The senior secured credit facility expires 7 years after the Roadrunner in-service date of Phase II, which is expected to be completed in the first quarter 2017. In addition, Roadrunner executed interest-rate swaps to hedge the variability of its interest payments during the term of the credit facility.

The FERC approved Roadrunner’s request for a Presidential Permit and authorization in October 2015, and construction has commenced.

WesTex Pipeline Expansion - In July 2015, we announced we plan to expand the capacity of the WesTex intrastate natural gas pipeline by constructing two new compressor stations and upgrading or expanding three existing compressor stations. The expansion project is approximately 90 percent subscribed with long-term firm demand charge transportation contracts and will complement the Roadrunner pipeline project. Together, these projects provide markets in Mexico access to upstream supply basins in West Texas and the Mid-Continent region.

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



	Three Months Ended					Nine Months Ended					Three Months					Nine Months
	September 30,					September 30,					2015 vs. 2014					2015 vs. 2014
Financial Results	2015			2014		2015			2014		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Transportation revenues	$	63.7		$	64.3	$	193.5		$	204.7	$	(0.6	)	(1	%)	$	(11.2	)	(5	%)
Storage revenues	14.2			12.6		42.4			48.6		1.6			13	%	(6.2		)	(13	%)
Natural gas sales and other revenues	5.1			2.2		10.8			12.6		2.9			*		(1.8		)	(14	%)
Cost of sales and fuel	7.6			5.7		28.1			23.5		1.9			33	%	4.6			20	%
Net margin	75.4			73.4		218.6			242.4		2.0			3	%	(23.8		)	(10	%)
Operating costs	26.7			28.0		79.1			82.8		(1.3		)	(5	%)	(3.7		)	(4	%)
Depreciation and amortization	10.9			10.9		32.5			32.6		—			—	%	(0.1		)	—	%
Gain (loss) on sale of assets	(0.1		)	1.7		(0.1		)	1.7		(1.8		)	*		(1.8		)	*
Operating income	$	37.7		$	36.2	$	106.9		$	128.7	$	1.5		4	%	$	(21.8	)	(17	%)
Equity in net earnings from investments	$	17.0		$	14.4	$	52.1		$	53.7	$	2.6		18	%	$	(1.6	)	(3	%)
Capital expenditures	$	14.7		$	10.7	$	39.9		$	26.0	$	4.0		37	%	$	13.9		53	%
Cash paid for acquisitions	$	—		$	—	$	—		$	14.0	$	—		—	%	$	(14.0	)	(100	%)

* Percentage change is greater than 100 percent.

Net margin increased for the three months ended September 30, 2015, compared with the same period in 2014, primarily as a result of the following:


•	an increase of $1.3 million due to higher storage revenues from increased rates; and


•	an increase of $1.2 million due to higher transportation revenues, primarily from higher rates on Viking Gas Transmission Company.

Net margin decreased for the nine months ended September 30, 2015, compared with the same period in 2014, primarily as a result of the following:


•	a decrease of $12.6 million from lower short-term natural gas storage services due primarily to increased weather-related seasonal demand associated with severely cold weather in the first quarter 2014;


•	a decrease of $9.4 million from lower net retained fuel due to lower natural gas prices and lower natural gas volumes retained;


•	a decrease of $4.8 million due to decreased park-and-loan services on our interstate pipelines as a result of increased weather-related seasonal demand due to severely cold weather in the first quarter 2014; and


•	a decrease of $1.9 million due to lower storage revenues from lower contracted firm capacity, offset partially by increased rates; offset partially by


•	an increase of $5.8 million due to higher transportation revenues, primarily from increased rates on intrastate pipelines and higher rates on Viking Gas Transmission Company.

Table of Contents

Operating costs decreased for the three and nine months ended September 30, 2015, compared with the same periods in 2014, primarily as a result of lower materials and supplies expense.

Gain on sale of assets decreased for the three and nine months ended September 30, 2015, compared with the same period in 2014, as a result of an excess pad gas sale in 2014.

Equity in net earnings from investments increased for the three months ended September 30, 2015, compared with the same period in 2014, due primarily to an increase in firm transportation on Northern Border Pipeline.

Equity in net earnings from investments decreased for the nine months ended September 30, 2015, compared with the same period in 2014, due primarily to decreased park-and-loan services on Northern Border Pipeline resulting from increased weather-related seasonal demand due to severely cold weather in the first quarter 2014, offset partially by an increase in firm transportation.

Capital expenditures increased for the three and nine months ended September 30, 2015, compared with the same periods in 2014, due primarily to an increase in routine growth 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)	2015			2014			2015			2014
Natural gas transportation capacity contracted (MDth/d)	5,739			5,725			5,797			5,760
Transportation capacity contracted	90		%	90		%	91		%	91		%
Average natural gas price
Mid-Continent region ($/MMBtu)	$	2.59		$	3.77		$	2.56		$	4.58

(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 shale 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. Conversely, contracted capacity by certain customers that are focused on capturing location or seasonal price differentials may decrease in the future due to narrowing price differentials. Overall, we expect our fee-based earnings to remain relatively stable with growth in certain market areas as the development of shale and other resource areas continues.

In August 2014, Viking Gas Transmission Company filed a “Stipulation and Agreement in Resolutions of All Issues Concerning Adjustment in Rates of Viking Gas Transmission Company” (settlement) with the FERC. The settlement was approved on October 1, 2014, and became final on October 31, 2014. Rates under the settlement became effective January 1, 2015.

Northern Border Pipeline, in which we have a 50 percent ownership interest, has contracted substantially all of its long-haul transportation capacity through September 2016.

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, impairment charges, income taxes and allowance for equity funds used during construction and other certain 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 traded partnerships within our industry. Management also uses Adjusted EBITDA to evaluate the performance of the partnership as a whole. Adjusted EBITDA should not be considered an alternative to net

Table of Contents

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, 2015 and 2014, 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)	2015			2014			2015		2014
Reconciliation of Net Income to Adjusted EBITDA	(Thousands of dollars)
Net income	$	229,665		$	167,320		$	588,307	$	647,299
Interest expense	86,666			70,060			253,867		211,344
Depreciation and amortization	87,517			73,901			259,563		212,083
Impairment charges (a)	—			76,412			—		76,412
Income tax (benefit) expense	(156		)	2,592			5,080		9,967
Allowance for equity funds used during construction and other noncash items	(10		)	(1,723		)	8,440		(13,947		)
Adjusted EBITDA	$	403,682		$	388,562		$	1,115,257	$	1,143,158

(a) - Amount includes $23.0 million for our proportionate share of the long-lived asset impairment charge of our equity method investee Bighorn Gas Gathering and $53.4 million impairment charge for our investment in Bighorn Gas Gathering for the three and nine months ended September 30, 2014.

Adjusted EBITDA increased for the three months ended September 30, 2015, and decreased for the nine months ended September 30, 2015, compared with the same periods in 2014, due primarily to changes in operating income. Operating costs decreased for the three months ended September 30, 2015, but increased overall for the nine months ended September 30, 2015, compared with the same periods in 2014, due primarily to the growth of our operations related to our completed capital projects and acquisitions. See also the discussion in “Financial Results and Operating Information.”

CONTINGENCIES

LIQUIDITY AND CAPITAL RESOURCES

General - Part of our strategy is to grow through internally generated growth projects and acquisitions that strengthen and complement our existing assets. We rely primarily on operating cash flows, commercial paper, bank credit facilities, debt issuances and the issuance of common units for our liquidity and capital resources requirements. We fund our operating expenses, debt service and cash distributions to our limited partners and general partner primarily with operating cash flows. To the extent operating cash flows are not sufficient to fund our cash distributions, we may utilize short- and long-term debt and issuances of common units, as necessary. Capital expenditures are funded by operating cash flows, short- and long-term debt and issuances of equity. We expect to continue to use these sources for liquidity and capital resource needs on both a short- and long-term basis. We have no guarantees of debt or other similar commitments to unaffiliated parties.

While our net margin is primarily derived from fee-based contracts, a portion of our net margin is dependent upon the prevailing and future prices for NGLs, crude oil and natural gas. Commodity prices are dependent on numerous factors beyond our control, such as overall crude oil and natural gas supply and demand, and inventories in relevant markets, economic conditions, the domestic and global political environments, regulatory developments and competition from other energy sources. Commodity prices historically have been volatile and may be subject to significant fluctuations in the future.

We use hedges to partially mitigate our near-term sensitivity to fluctuations in the natural gas, crude oil and NGL prices received for our equity volumes. See further discussion of our hedged volumes in the “Commodity Price Risk” section in our Natural Gas Gathering and Processing segment.

Table of Contents

We expect the energy commodity price environment to remain depressed for at least the near term, including through the remainder of 2015, with a modest recovery in 2016. The current commodity price environment has caused crude oil and natural gas producers to reduce drilling for crude oil and natural gas, which we expect will continue to slow volume growth, or reduce the volumes of natural gas and NGLs delivered on to our systems. These conditions are expected to significantly impact our results of operations and cash flows. We have minimum volume or firm demand charge agreements that mitigate partially our volumetric risk; however, if the current energy commodity price environment persists for a prolonged period or declines further, it could have a material adverse effect on our financial position, results of operations and cash flows.

We continue to have access to our commercial paper program and our Partnership Credit Agreement, which we expect to be adequate to fund short-term liquidity needs. In the first quarter 2015, we increased the capacity of our Partnership Credit Agreement to an aggregate of $2.4 billion from $1.7 billion. We also increased the size of our commercial paper program to $2.4 billion from $1.7 billion during the first quarter 2015. The facility is available to provide liquidity for working capital, capital expenditures and other general partnership purposes.

We expect the low commodity prices to continue to impact our volumes and margins in the fourth quarter 2015 and into 2016, and we are responding by aligning our operating costs and capital-growth projects with the needs of crude oil and natural gas producers, which includes suspending, reducing or eliminating certain capital-growth projects, limiting increases of distributions to our limited partners and negotiating various contract enhancements. Many contracts in our Natural Gas Gathering and Processing and Natural Gas Liquids segments include fixed fee, minimum volume or firm demand charge agreements that ensure a minimum level of revenues regardless of commodity prices. Additionally, we have renegotiated many Natural Gas Gathering and Processing segment contracts to significantly increase fee-based earnings and continue to actively work with our producer customers to similarly restructure additional contracts. We expect to substantially complete our negotiations on Williston Basin contracts in 2015 and receive the full benefit of the improved margins in 2016.

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. The decline in commodity prices and reductions in our volume growth outlook have resulted in a decrease in our common unit price, which is expected to increase our debt and equity financing costs. While lower commodity prices and industry uncertainty may result in increased financing costs, we believe we have sufficient access to the financial resources and liquidity, including access to public or private markets for equity and/or debt, necessary to meet our requirements for working capital, debt service payments and capital expenditures.

In the second and third quarters of 2015, our cash flow from operations exceeded our cash distributions. However, for the nine months ended September 30, 2015, our cash distributions exceeded our cash flow from operations. As a result, we utilized cash from operations, our commercial paper program and distributions received from our equity-method investments to fund our cash distributions, short-term liquidity needs and capital projects. We subsequently financed our capital-growth projects and repaid amounts outstanding under our commercial paper program with proceeds from our March 2015 senior notes offering, our August 2015 equity issuance and our “at-the-market” equity program. We expect increases in cash flows from operations in the fourth quarter 2015, compared with the first, second and third quarters of 2015, and in 2016 compared with 2015, due primarily to completion of our growth projects that we expect will provide increasing volumes in our Natural Gas Gathering and Processing and Natural Gas Liquids segments and contract renegotiations that we expect will provide increasing margins in our Natural Gas Gathering and Processing segment. See discussion under “Short-term Liquidity” and “Long-term Financing” for more information.

Capital Structure - The following table sets forth our capitalization structure at the dates indicated:



	September 30,	December 31,
	2015	2014
Long-term debt	50%	50%
Equity	50%	50%
Debt (including notes payable)	51%	54%
Equity	49%	46%

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 our operating agreement. Under the cash management program, depending on whether a participating subsidiary

Table of Contents

has short-term cash surpluses or cash requirements, the Intermediate Partnership provides cash to the subsidiary or the subsidiary provides cash to the Intermediate Partnership.

Short-term Liquidity - Our principal sources of short-term liquidity consist of cash generated from operating activities, distributions received from our equity method investments and proceeds from our commercial paper program and our “at-the-market” equity program. To the extent commercial paper is unavailable, our Partnership Credit Agreement may be used.

We had working capital (defined as current assets less current liabilities) deficits of $1.0 billion and $1.3 billion as of September 30, 2015, and December 31, 2014, 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, the consolidated working capital deficit at December 31, 2014, was driven primarily by our capital-growth projects and our November 2014 $800 million acquisition of West Texas LPG, which were initially funded with short-term borrowings under our commercial paper program. We repaid these amounts outstanding with cash from operations, our March 2015 debt issuance and our August 2015 equity issuances. The consolidated working capital deficit at September 30, 2015, was driven primarily by our capital-growth projects and current maturities of our long-term debt. We may have working capital deficits in future periods as we continue to finance our capital-growth projects, often initially with short-term borrowings, which we expect to repay with proceeds from future issuances of long-term debt, common units or other debt or equity securities. We do not expect this working capital deficit to have an adverse impact to our cash flows or operations.

At September 30, 2015, we had $287.3 million in commercial paper outstanding, $14.0 million in letters of credit issued and no borrowings outstanding under our Partnership Credit Agreement. At September 30, 2015, we had approximately $7.3 million of cash and cash equivalents and approximately $2.1 billion of credit available under the Partnership Credit Agreement.

Our Partnership Credit Agreement, which is scheduled to expire in January 2019, 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. During the first quarter 2015, we increased the size of our Partnership Credit Agreement and commercial paper program each to $2.4 billion from $1.7 billion. Amounts outstanding under our commercial paper program reduce the borrowing capacity 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 rating, 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 the Intermediate Partnership.

At September 30, 2015, we could have issued $1.2 billion of short- and long-term debt to meet our liquidity needs under the most restrictive provisions contained in our various borrowing agreements.

Borrowings under our Partnership Credit 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 cash requirements by issuing common units or long-term notes. Other options to obtain financing include, but are not limited to, 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

Table of Contents

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 believe that we will be able to meet our cash requirements and maintain investment-grade credit ratings.

Debt Issuance - 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 offering expenses, were approximately $792.3 million. We used the proceeds to repay amounts outstanding under our commercial paper program and for general partnership purposes.

Debt Maturity - Our $650 million, 3.25 percent senior notes mature on February 1, 2016. The carrying amount of these notes is reflected in the current portion of long-term debt on our Consolidated Balance Sheet as of September 30, 2015. We expect to refinance this debt.

During the nine months ended September 30, 2015, we sold approximately 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 registered direct offering discussed above. The gross proceeds, including ONEOK Partners GP’s contribution to maintain its 2 percent general partner interest in us, were approximately $384.4 million. Net cash proceeds, after deducting agent commissions and other related costs, were approximately $381.6 million, which were used for general partnership purposes, including repayment of commercial paper borrowings.

As a result of these transactions, ONEOK’s aggregate ownership interest in us increased to 41.2 percent at September 30, 2015, from 37.8 percent at December 31, 2014.

During the nine months ended September 30, 2014, we sold approximately 4.4 million common units through our “at-the-market” equity program. Net cash proceeds, including ONEOK Partners GP’s contribution to maintain its 2 percent general partner interest in us, were approximately $245.4 million, which were used for general partnership purposes.

Interest-rate Swaps - We have entered into forward-starting interest-rate swaps to hedge the variability of interest payments on a portion of forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. Upon our debt issuance in March 2015, we paid $55.1 million to settle $500 million of our interest-rate swaps. At

Table of Contents

September 30, 2015, we had forward-starting interest-rate swaps with notional amounts totaling $400 million that were designated as cash flow hedges and have settlement dates of less than 12 months.

Capital Expenditures - We classify expenditures that are expected to generate additional revenue, return on investment or significant operating efficiencies as growth capital 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 $928.9 million and $1.2 billion for the nine months ended September 30, 2015 and 2014, respectively.

The following table summarizes our 2015 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	$	780	$	40	$	820
Natural Gas Liquids	195		50		245
Natural Gas Pipelines	50		25		75
Other	—		15		15
Total projected capital expenditures	$	1,025	$	130	$	1,155

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



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

Our commercial paper program is rated Prime-2 by Moody’s and A-2 by S&P. In August 2015, Moody’s and S&P affirmed our current credit ratings and revised our outlook to negative from stable. Our credit ratings, which are currently 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.

Recent 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 2019. 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. There were no financial derivative instruments with contingent features related to credit risk that were in a net liability position at September 30, 2015.

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.

Table of Contents

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,
	2015		2014
	(Millions of dollars)
Common unitholders	$	435.6	$	369.1
Class B unitholders	173.0		163.1
General partner	288.9		235.9
Noncontrolling interests	8.2		0.4
Total cash distributions paid	$	905.7	$	768.5

In the nine months ended September 30, 2015 and 2014, cash distributions paid to our general partner included incentive distributions of $271.0 million and $220.5 million, respectively.

In October 2015, our general partner declared a cash distribution of $0.79 per unit ($3.16 per unit on an annualized basis) for the third quarter 2015, which will be paid on November 13, 2015, to unitholders of record at the close of business on November 2, 2015.

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 - We are subject to commodity price volatility. 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. The decline in commodity prices and reductions in our volume growth outlook have contributed to a decrease in our unit price. While lower commodity prices and industry uncertainty may increase debt and equity financing costs, we expect to have sufficient liquidity to finance our announced capital-growth projects. We believe that our available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity price volatility. See Note D of the Notes to Consolidated Financial Statements and the discussion under Natural Gas Gathering and Processing’s “Commodity Price Risk” in Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, 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.

Table of Contents

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



							Variances
	Nine Months Ended						2015 vs. 2014
	September 30,						Increase (Decrease)
	2015			2014			Increase (Decrease)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	747.1		$	887.1		$	(140.0	)
Investing activities	(940.7		)	(1,160.7		)	220.0
Financing activities	158.4			193.1			(34.7		)
Change in cash and cash equivalents	(35.2		)	(80.5		)	45.3
Cash and cash equivalents at beginning of period	42.5			134.5			(92.0		)
Cash and cash equivalents at end of period	$	7.3		$	54.0		$	(46.7	)

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 $849.7 million for the nine months ended September 30, 2015, compared with $925.9 million for the same period in 2014. The decrease is due primarily to a decrease in net margin attributable to lower commodity prices in 2015 and increases in operating costs and interest expense, as discussed in “Financial Results and Operating Information.”

The changes in operating assets and liabilities decreased operating cash flows $102.6 million for the nine months ended September 30, 2015, compared with a decrease of $38.8 million for the same period in 2014. This change is due primarily to the change in accounts receivable and accounts payable resulting from the timing of receipt of cash from customers and payments to vendors and suppliers, which vary from period to period and vary with changes in commodities prices. In the first quarter 2015, we also paid $55.1 million to settle forward-starting interest-rate swaps in connection with our March 2015 debt offering.

Investing Cash Flows - Cash used in investing activities decreased to $940.7 million for the nine months ended September 30, 2015, compared with $1.2 billion for the same period in 2014, due primarily to the completion of growth projects in 2014 and the timing of capital expenditures for our growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments, offset partially by contributions made to Roadrunner in 2015. We also had an acquisition in the first quarter 2014 in our Natural Gas Pipelines segment.

Financing Cash Flows - Cash provided by financing activities was $158.4 million for the nine months ended September 30, 2015, compared with cash provided by financing activities of $193.1 million for the nine months ended September 30, 2014. During the nine months ended September 30, 2015, we raised additional capital of approximately $1.8 billion through both debt and equity issuances, and during the nine months ended September 30, 2014, we raised additional capital of approximately $947 million through equity issuances. These increases in financing cash inflows for the nine months ended September 30, 2015, compared with the same period in 2014, were offset partially by repayment of notes payable and increased distributions paid due to a higher number of units outstanding for the period and a higher distribution per unit.

REGULATORY, ENVIRONMENTAL AND SAFETY MATTERS

Table of Contents

materially our results of operations and cash flows. In addition, emissions controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us.

In June 2013, the Executive Office of the President of the United States (the President) issued the President’s Climate Action Plan, which includes, among other things, plans for further regulatory actions to reduce carbon emissions from various sources. On March 28, 2014, the President released the Climate Action Plan - Strategy to Reduce Methane Emissions (Methane Strategy) that lists a number of actions the federal agencies will undertake to continue to reduce above-ground methane emissions from several industries, including the oil and natural gas sectors. The proposed measures outlined in the Methane Strategy include, without limitation, the following: collaboration with the states to encourage emission reductions; standards to minimize natural gas venting and flaring on public lands; policy recommendations for reducing emissions from energy infrastructure to increase the performance of the nation’s energy transmission, storage and distribution systems; and continued efforts by PHMSA to require pipeline operators to take steps to eliminate leaks and prevent accidental methane releases and evaluate the progress of states in replacing cast-iron pipelines. The impact of any such regulatory actions on our facilities and operations is unknown. We continue to monitor these developments and the impact they may have on our businesses. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a significant impact on our business, financial position, results of operations and cash flows.

Additional information about environmental matters is included in Note L of the Notes to Consolidated Financial Statements in this Quarterly Report.


•	an evaluation on whether hazardous natural gas liquids and natural gas pipeline integrity-management requirements should be expanded beyond current high-consequence areas;


•	a review of all natural gas and hazardous natural gas liquids gathering pipeline exemptions;


•	a verification of records for pipelines in Class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and


•	a requirement to test previously untested pipelines operating above 30 percent yield strength in high-consequence areas.

Air and Water Emissions - The Clean Air Act, the Clean Water Act, analogous state laws and/or regulations promulgated thereunder impose restrictions and controls regarding the discharge of pollutants into the air and water in the United States. Under the Clean Air Act, a federally enforceable operating permit is required for sources of significant air emissions. We may be required to incur certain capital expenditures for air pollution-control equipment in connection with obtaining or maintaining permits and approvals for sources of air emissions. The Clean Water Act imposes substantial potential liability for the removal of pollutants discharged to waters of the United States and remediation of waters affected by such discharge.

Federal, state and regional initiatives to measure and regulate GHG emissions are underway. We monitor all relevant federal and state legislation to assess the potential impact on our operations. The EPA’s Mandatory Greenhouse Gas Reporting Rule requires annual GHG emissions reporting from affected facilities and the carbon dioxide emission equivalents for the natural gas delivered by us and the emission equivalents for all NGLs produced by us as if all of these products were combusted, even if they are used otherwise.

Table of Contents

Our 2014 total reported emissions were approximately 45.7 million metric tons of carbon dioxide equivalents. This total includes direct emissions from the combustion of fuel in our equipment, such as compressor engines and heaters, as well as carbon dioxide equivalents from natural gas and NGL products delivered to customers and produced as if all such fuel and NGL products were combusted. The additional cost to gather and report this emission data did not have, and we do not expect it to have, a material impact on our results of operations, financial position or cash flows. In addition, Congress has considered, and may consider in the future, legislation to reduce GHG emissions, including carbon dioxide and methane. Likewise, the EPA may institute additional regulatory rule-making associated with GHG emissions from the oil and natural gas industry. At this time, no rule or legislation has been enacted that assesses any costs, fees or expenses on any of these emissions.

The EPA’s “Triggering and Tailoring Rules” regulate GHG emissions at new or modified facilities that meet certain criteria. Affected facilities are required to review BACT, conduct air-quality analysis, impact analysis and public reviews with respect to such emissions. At current emission threshold levels, this rule has had a minimal impact on our existing facilities. In addition, on June 23, 2014, the Supreme Court, in a case styled, Utility Air Regulatory Group v. EPA, 530 U.S. (2014), held that an industrial facility’s potential to emit GHG emissions alone cannot subject a facility to the permitting requirements for major stationary source provisions of the Clean Air Act. The decision invalidated the EPA’s current Triggering and Tailoring Rule for GHG PSD and Title V requirements as applied to facilities considered major sources only for GHGs (referred to as Step 2 sources). However, the Supreme Court also ruled that to the extent a source pursues a capital project (new construction or expansion of existing facility), which otherwise subjects the source to major source PSD permitting for conventional criteria pollutants, the permitting authorities may impose BACT analysis and emission limits for GHGs from those sources.

In October 2015, the EPA issued a prepublication version of a final rule-making to amend downward the NAAQS for ground level ozone. The final rule requires revised designations of the areas in the various states for classification as in attainment or nonattainment for the new ozone NAAQS. Any areas determined to not attain the ozone NAAQS will implicate more strict air permitting requirements for new or modified sources that emit pollutants that contribute to ground level ozone.

Table of Contents

makings will require expenditures for updated emissions controls, monitoring and record-keeping requirements at affected facilities. We do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.

CERCLA - The federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also commonly known as Superfund, imposes strict, joint and several liability, without regard to fault or the legality of the original act, on certain classes of “persons” (defined under CERCLA) who caused and/or contributed to the release of a hazardous substance into the environment. These persons include, but are not limited to, the owner or operator of a facility where the release occurred and/or companies that disposed or arranged for the disposal of the hazardous substances found at the facility. Under CERCLA, these persons may be liable for the costs of cleaning up the hazardous substances released into the environment, damages to natural resources and the costs of certain health studies. We do not expect our responsibilities under CERCLA will have a material impact on our results of operations, financial position or cash flows.

Chemical Site Security - The United States Department of Homeland Security (Homeland Security) released the Chemical Facility Anti-Terrorism Standards in 2007, and the new final rule associated with these regulations was issued in December 2014. We provided information regarding our chemicals via Top-Screens submitted to Homeland Security, and our facilities subsequently were assigned one of four risk-based tiers ranging from high (Tier 1) to low (Tier 4) risk, or not tiered at all due to low risk. To date, four of our facilities have been given a Tier 4 rating. Facilities receiving a Tier 4 rating are required to complete Site Security Plans and possible physical security enhancements. We do not expect the Site Security Plans and possible security enhancement costs to have a material impact on our results of operations, financial position or cash flows.

Pipeline Security - The United States Department of Homeland Security’s Transportation Security Administration and the DOT have completed a review and inspection of our “critical facilities” and identified no material security issues. Also, the Transportation Security Administration has released new pipeline security guidelines that include broader definitions for the determination of pipeline “critical facilities.” We have reviewed our pipeline facilities according to the new guideline requirements, and there have been no material changes required to date.

Environmental Footprint - Our environmental and climate change strategy focuses on minimizing the impact of our operations on the environment. These strategies include: (i) developing and maintaining an accurate GHG emissions inventory according to current rules issued by the EPA; (ii) improving the efficiency of our various pipelines, natural gas processing facilities and natural gas liquids fractionation facilities; (iii) following developing technologies for emissions control and the capture of carbon dioxide to keep it from reaching the atmosphere; and (iv) utilizing practices to reduce the loss of methane from our facilities.

We participate in the EPA’s Natural Gas STAR Program to reduce voluntarily methane emissions. We continue to focus on maintaining low rates of lost-and-unaccounted-for methane gas through expanded implementation of best practices to limit the release of natural gas during pipeline and facility maintenance and operations.

IMPACT OF NEW ACCOUNTING STANDARDS

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

ESTIMATES AND CRITICAL ACCOUNTING POLICIES

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

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

FORWARD-LOOKING STATEMENTS

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

Table of Contents

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;


•	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;

Table of Contents


–	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.


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

See Note D of the Notes to Consolidated Financial Statements and the discussion under Natural Gas Gathering and Processing’s “Commodity Price Risk” in Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Quarterly Report for information on our hedging activities.

Table of Contents

INTEREST-RATE RISK

We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts. At September 30, 2015, and December 31, 2014, we had forward-starting interest-rate swaps with notional amounts totaling $400 million and $900 million, respectively, that have been designated as cash flow hedges of the variability of interest payments on a portion of forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. Future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher interest costs. At September 30, 2015, we had no derivative assets and $13.6 million of derivative liabilities related to these interest-rate swaps. At December 31, 2014, we had derivative assets of $2.3 million and derivative liabilities of $44.8 million related to these interest-rate swaps.

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. We are not exposed to material credit risk with exploration and production customers under POP contracts in our Natural Gas Gathering and Processing segment due to the nature of the POP contracts whereby we receive proceeds from the sale of commodities and remit a portion of those proceeds back to the crude oil and natural gas producers. Certain of our counterparties to our Natural Gas Gathering and Processing segment’s natural gas 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. The majority of our Natural Gas Liquids segment’s and Natural Gas Pipeline segment’s pipeline tariffs provide us the ability to require security from shippers. Our remaining customers are primarily large local distribution, power generation and petrochemical companies.


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, 2015, 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 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

See our Current Report on Form 8-K dated August 17, 2015, and Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations “Recent Developments” and “Liquidity and Capital Resources” in this Quarterly Report for information concerning our recent private placement of our common units with ONEOK.

Table of Contents


ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

Not Applicable.


ITEM 4.	MINE SAFETY DISCLOSURES

Not Applicable.


ITEM 5.	OTHER INFORMATION

Not Applicable.


ITEM 6.	EXHIBITS

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

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


Exhibit No.	Exhibit Description


10.1	Common Unit Purchase Agreement dated August 11, 2015, between ONEOK Partners, L.P. and ONEOK, Inc. (incorporated by reference to Exhibit 1.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on August 17, 2015).


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)).

99.1

Common Unit Purchase Agreement dated August 11, 2015, between ONEOK Partners, L.P. and Kayne Anderson MLP Investment Company, Kayne Anderson Energy Total Return Fund, Inc., Kayne Anderson Midstream/Energy Fund, Inc., Kayne Anderson Energy Development Company, KA First Reserve, LLC, Nationwide Mutual Insurance Company, Massachusetts Mutual Life Insurance Company, Kayne Anderson MLP Fund, L.P., Kayne Anderson Midstream Institutional Fund, L.P., Kayne Anderson Real Assets Fund, L.P., Kayne Institutional Energy Growth & Income Fund, L.P., Kayne Anderson Capital Income Partners (QP), L.P., Kayne Anderson Income Partners, L.P., KANTI (QP), L.P., Kayne Anderson Non-Traditional Investments, L.P., KARBO, L.P. and Kaiser Foundation Hospitals (incorporated by reference to Exhibit 99.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on August 17, 2015).


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.

Table of Contents

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, 2015 and 2014; (iii) Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2015 and 2014; (iv) Consolidated Balance Sheets at September 30, 2015, and December 31, 2014; (v) Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 and 2014; (vi) Consolidated Statement of Changes in Equity for the nine months ended September 30, 2015 and 2014; 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.

Table of Contents

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 hereunto duly authorized.



	ONEOK Partners, L.P.
	By:	ONEOK Partners GP, L.L.C., its General Partner

Date: November 4, 2015		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 4, 2015

Attached files

ONEOK Partners LP Reports