ONEOK Partners LP (Form: 10-Q, Received: 05/07/2014 17:05:13)

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 March 31, 2014 .

___ 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 April 29, 2014
Common units		160,076,263 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 Months Ended March 31, 2014 and 2013	6
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2014 and 2013	7
	Consolidated Balance Sheets - March 31, 2014, and December 31, 2013	8
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2014 and 2013	9
	Consolidated Statement of Changes in Equity - Three Months Ended March 31, 2014	10
	Notes to Consolidated Financial Statements	12
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	55
Item 4.	Controls and Procedures	55
Part II.	Other Information
Item 1.	Legal Proceedings	55
Item 1A.	Risk Factors	55
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	55
Item 3.	Defaults Upon Senior Securities	55
Item 4.	Mine Safety Disclosures	55
Item 5.	Other Information	56
Item 6.	Exhibits	56
Signature		57

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, 2013
ASU	Accounting Standards Update
Bbl	Barrels, 1 barrel is equivalent to 42 United States gallons
Bbl/d	Barrels per day
BBtu/d	Billion British thermal units per day
Bcf	Billion cubic feet
Bighorn Gas Gathering	Bighorn Gas Gathering, L.L.C.
Btu	British thermal units, a measure of the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit
CFTC	Commodities 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
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
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
Fort Union Gas Gathering	Fort Union Gas Gathering, L.L.C.
GAAP	Accounting principles generally accepted in the United States of America
Guardian Pipeline	Guardian Pipeline, L.L.C.
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
Midwestern Gas Transmission	Midwestern Gas Transmission Company
MMBbl	Million barrels
MMBtu	Million British thermal units
MMBtu/d	Million British thermal units per day
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
Northern Border Pipeline	Northern Border Pipeline Company
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
Overland Pass Pipeline Company	Overland Pass Pipeline Company LLC
Partnership Agreement	Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P., as amended
Partnership Credit Agreement	The Partnership’s $1.7 billion Amended and Restated Revolving Credit Agreement dated January 31, 2014

Table of Contents



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
SEC	Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
Viking Gas Transmission	Viking Gas Transmission Company
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
	March 31,
( Unaudited )	2014			2013
	( Thousands of dollars, except per unit amounts )
Revenues
Commodity sales	$	2,806,729		$	2,198,794
Services	355,574			318,653
Total revenues	3,162,303			2,517,447
Cost of sales and fuel	2,652,669			2,146,848
Net margin	509,634			370,599
Operating expenses
Operations and maintenance	130,518			121,289
Depreciation and amortization	66,735			54,678
General taxes	19,665			16,975
Total operating expenses	216,918			192,942
Gain (loss) on sale of assets	15			41
Operating income	292,731			177,698
Equity earnings from investments (Note H)	33,659			25,855
Allowance for equity funds used during construction	10,971			9,087
Other income	1,333			3,705
Other expense	(769		)	(1,481		)
Interest expense (net of capitalized interest of $15,768 and $12,605, respectively)	(68,276		)	(55,872		)
Income before income taxes	269,649			158,992
Income taxes	(4,181		)	(2,307		)
Net income	265,468			156,685
Less: Net income attributable to noncontrolling interests	76			86
Net income attributable to ONEOK Partners, L.P.	$	265,392		$	156,599
Limited partners’ interest in net income:
Net income attributable to ONEOK Partners, L.P.	$	265,392		$	156,599
General partner’s interest in net income	(77,232		)	(64,708		)
Limited partners’ interest in net income	$	188,160		$	91,891
Limited partners’ net income per unit, basic and diluted (Note G)	$	0.81		$	0.42
Number of units used in computation ( thousands )	232,131			219,861

See accompanying Notes to Consolidated Financial Statements.

Table of Contents



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

	Three Months Ended
	March 31,
( Unaudited )	2014			2013
	( Thousands of dollars )
Net income	$	265,468		$	156,685
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	(56,455		)	(12,980		)
Realized (gains) losses on derivatives recognized in net income	29,008			(261		)
Total other comprehensive income (loss)	(27,447		)	(13,241		)
Comprehensive income	238,021			143,444
Less: Comprehensive income attributable to noncontrolling interests	76			86
Comprehensive income attributable to ONEOK Partners, L.P.	$	237,945		$	143,358

See accompanying Notes to Consolidated Financial Statements.

Table of Contents



ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	March 31,			December 31,
( Unaudited )	2014			2013
Assets	( Thousands of dollars )
Current assets
Cash and cash equivalents	$	115,386		$	134,530
Accounts receivable, net	869,255			1,103,130
Affiliate receivables	23,561			9,185
Natural gas and natural gas liquids in storage	231,237			188,286
Commodity imbalances	82,979			80,481
Other current assets	80,246			67,491
Total current assets	1,402,664			1,583,103
Property, plant and equipment
Property, plant and equipment	11,096,402			10,755,048
Accumulated depreciation and amortization	1,713,503			1,652,648
Net property, plant and equipment	9,382,899			9,102,400
Investments and other assets
Investments in unconsolidated affiliates (Note H)	1,229,054			1,229,838
Goodwill and intangible assets	829,238			832,180
Other assets	95,665			115,087
Total investments and other assets	2,153,957			2,177,105
Total assets	$	12,939,520		$	12,862,608
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	7,650		$	7,650
Notes payable (Note D)	125,000			—
Accounts payable	1,140,355			1,255,411
Affiliate payables	53,124			47,458
Commodity imbalances	216,750			213,577
Accrued interest	88,042			92,711
Other current liabilities	85,547			89,211
Total current liabilities	1,716,468			1,706,018
Long-term debt, excluding current maturities	6,043,240			6,044,867
Deferred credits and other liabilities	129,085			113,027
Commitments and contingencies (Note J)
Equity (Note E)
ONEOK Partners, L.P. partners’ equity:
General partner	175,673			170,561
Common units: 160,076,263 and 159,007,854 units issued and outstanding at March 31, 2014, and December 31, 2013, respectively	3,528,307			3,459,920
Class B units : 72,988,252 units issued and outstanding at March 31, 2014, and December 31, 2013	1,428,419			1,422,516
Accumulated other comprehensive loss (Note F)	(86,284		)	(58,837		)
Total ONEOK Partners, L.P. partners’ equity	5,046,115			4,994,160
Noncontrolling interests in consolidated subsidiaries	4,612			4,536
Total equity	5,050,727			4,998,696
Total liabilities and equity	$	12,939,520		$	12,862,608

See accompanying Notes to Consolidated Financial Statements.

Table of Contents



ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Three Months Ended
	March 31,
( Unaudited )	2014			2013
	( Thousands of dollars )
Operating activities
Net income	$	265,468		$	156,685
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	66,735			54,678
Allowance for equity funds used during construction	(10,971		)	(9,087		)
Gain on sale of assets	(15		)	(41		)
Deferred income taxes	2,376			1,502
Equity earnings from investments	(33,659		)	(25,855		)
Distributions received from unconsolidated affiliates	30,345			23,495
Changes in assets and liabilities:
Accounts receivable	237,752			139,043
Affiliate receivables	(14,376		)	(5,860		)
Natural gas and natural gas liquids in storage	(42,951		)	7,003
Accounts payable	(16,525		)	(62,293		)
Affiliate payables	5,666			(30,372		)
Commodity imbalances, net	675			(56,557		)
Accrued interest	(4,669		)	10,747
Other assets and liabilities, net	(26,695		)	(21,651		)
Cash provided by operating activities	459,156			181,437
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	(403,001		)	(443,464		)
Acquisition	(14,000		)	—
Contributions to unconsolidated affiliates	(627		)	(3,036		)
Distributions received from unconsolidated affiliates	4,725			6,698
Proceeds from sale of assets	93			47
Cash used in investing activities	(412,810		)	(439,755		)
Financing activities
Cash distributions:
General and limited partners	(242,496		)	(220,924		)
Noncontrolling interests	—			(147		)
Borrowing of notes payable, net	125,000			—
Repayment of long-term debt	(1,913		)	(1,913		)
Issuance of common units, net of issuance costs	52,839			12,819
Contribution from general partner	1,080			332
Cash used in financing activities	(65,490		)	(209,833		)
Change in cash and cash equivalents	(19,144		)	(468,151		)
Cash and cash equivalents at beginning of period	134,530			537,074
Cash and cash equivalents at end of period	$	115,386		$	68,923

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, 2014	159,007,854	72,988,252	$	170,561		$	3,459,920
Net income	—	—	77,232			128,975
Other comprehensive income (loss) (Note F)	—	—	—			—
Issuance of common units (Note E)	1,068,409	—	—			55,522
Contribution from general partner (Note E)	—	—	984			—
Distributions paid (Note E)	—	—	(73,104		)	(116,110		)
March 31, 2014	160,076,263	72,988,252	$	175,673		$	3,528,307

See accompanying Notes to Consolidated Financial Statements.

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, 2014		$	1,422,516		$	(58,837	)	$	4,536	$	4,998,696
Net income		59,185			—			76		265,468
Other comprehensive income (loss) (Note F)		—			(27,447		)	—		(27,447		)
Issuance of common units (Note E)		—			—			—		55,522
Contribution from general partner (Note E)		—			—			—		984
Distributions paid (Note E)		(53,282		)	—			—		(242,496		)
March 31, 2014		$	1,428,419		$	(86,284	)	$	4,612	$	5,050,727

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 2013 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.

Recently Issued Accounting Standards Update - 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 amendments also require 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 will adopt this guidance beginning in the first quarter 2015, and we are evaluating the impact on us.


B.	FAIR VALUE MEASUREMENTS

Determining Fair Value - We define fair value as the price that would be received from the sale of an asset or the transfer of a liability in an orderly transaction between market participants at the measurement date. We use market and income approaches to determine the fair value of our assets and liabilities and consider the markets in which the transactions are executed. We measure the fair value of groups 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, historical correlations of NGL product prices to crude oil prices and implied forward LIBOR curves. Inputs into our fair value estimates include commodity-exchange prices, over-the-counter quotes, historical correlations of pricing data and LIBOR and other liquid money-market instrument rates. We also utilize internally developed basis curves that incorporate observable and unobservable market data. We validate our valuation inputs with third-party information and settlement prices from other sources, where available.

In addition, as prescribed by the income approach, we compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets and liabilities to present value using interest-rate yields to calculate present-value discount factors derived from LIBOR, Eurodollar futures and 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-rate swap settlements.

Table of Contents

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


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

•

Level 3 - fair value measurements are based on inputs that may include one or more unobservable inputs, including internally developed basis curves that incorporate observable and unobservable market data, NGL price curves from broker quotes, 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 is not material.

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



	March 31, 2014
	Level 1			Level 2			Level 3			Total - Gross			Netting (a)			Total - Net (b)
	( Thousands of dollars )
Derivatives assets
Commodity contracts
Financial contracts	$	133		$	39		$	542		$	714		$	(573	)	$	141
Physical contracts	—			—			3,332			3,332			(926		)	2,406
Interest-rate contracts	—			38,384			—			38,384			—			38,384
Total derivative assets	$	133		$	38,423		$	3,874		$	42,430		$	(1,499	)	$	40,931
Derivatives liabilities
Commodity contracts
Financial contracts	$	(3,099	)	$	(1,722	)	$	(401	)	$	(5,222	)	$	3,326		$	(1,896	)
Physical contracts	—			—			(1,501		)	(1,501		)	926			(575		)
Interest-rate contracts	—			(4,574		)	—			(4,574		)	—			(4,574		)
Total derivative liabilities	$	(3,099	)	$	(6,296	)	$	(1,902	)	$	(11,297	)	$	4,252		$	(7,045	)

(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 March 31, 2014 , we held no cash collateral and posted $2.8 million of cash collateral with various counterparties.

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

Table of Contents



	December 31, 2013
	Level 1		Level 2			Level 3			Total - Gross			Netting (a)			Total - Net (b)
	( Thousands of dollars )
Derivatives assets
Commodity contracts
Financial contracts	$	—	$	3,657		$	2,812		$	6,469		$	(1,746	)	$	4,723
Physical contracts	—		—			2,023			2,023			(946		)	1,077
Interest-rate contracts	—		54,503			—			54,503			—			54,503
Total derivative assets	$	—	$	58,160		$	4,835		$	62,995		$	(2,692	)	$	60,303
Derivatives liabilities
Commodity contracts
Financial contracts	$	—	$	(2,953	)	$	(2,154	)	$	(5,107	)	$	1,746		$	(3,361	)
Physical contracts	—		—			(3,463		)	(3,463		)	946			(2,517		)
Total derivative liabilities	$	—	$	(2,953	)	$	(5,617	)	$	(8,570	)	$	2,692		$	(5,878	)

(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, 2013 , we had no cash collateral held or 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
	March 31,
Derivative Assets (Liabilities)	2014			2013
	( Thousands of dollars )
Net assets (liabilities) at beginning of period	$	(782	)	$	(2,423	)
Total realized/unrealized gains (losses):
Included in earnings (a)	(928		)	—
Included in other comprehensive income (loss)	(52		)	(2,432		)
Purchases, issuances and settlements	3,734			—
Net assets (liabilities) at end of period	$	1,972		$	(4,855	)

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

Realized/unrealized gains (losses) include the realization of our derivative contracts through maturity. During the three months ended March 31, 2014 and 2013 , 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 the period were not material.

We recognize transfers into and out of the levels in the fair value hierarchy as of the end of each reporting period. During the three months ended March 31, 2014 and 2013 , 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 $6.7 billion and $6.5 billion at March 31, 2014 , and December 31, 2013 , respectively. The book value of the aggregate of our senior notes outstanding, including current maturities, was $6.1 billion at March 31, 2014 , and December 31, 2013 . The estimated fair value of the aggregate of our senior notes outstanding was determined using quoted market prices for similar issues with similar terms and maturities. The estimated fair value of our long-term debt is classified as Level 2.


C.	RISK-MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

Risk-Management Activities - We are sensitive to changes in natural gas, crude oil and NGL prices, principally as a result of contractual terms under which these commodities are processed, purchased and sold. We use physical-forward sales and

Table of Contents

financial derivatives to secure a certain price for a portion of our natural gas, condensate and NGL products. 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 - We are exposed 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 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 typically are nontransferable and only can 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. This transfers 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.

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 are also 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 minimize the impact of price fluctuations related to natural gas, NGLs and condensate.

In our Natural Gas Liquids segment, we are exposed to basis risk primarily as a result of the relative value of NGL purchases at one location and sales at another location. To a lesser extent, we are 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 to reduce the impact of price fluctuations related to NGLs. At March 31, 2014 , and December 31, 2013 , there were no financial derivative instruments used in our natural gas liquids operations.

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 March 31, 2014 , and December 31, 2013 , there were no financial derivative instruments used in our natural gas pipeline operations.

Interest-rate risk - We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts. At March 31, 2014 , we had forward-starting interest-rate swaps with notional amounts totaling $900 million 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, of which $400 million have settlement dates greater than 12 months.

Accounting Treatment - We record all derivative instruments at fair value, with the exception of normal purchases and sales that are expected to result in physical delivery. 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.

Table of Contents

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

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, 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 with a cash flow hedge. 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.

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



	March 31, 2014					December 31, 2013
	Assets (a)		(Liabilities) (a)			Assets (a)		(Liabilities) (a)
	( Thousands of dollars )
Derivatives designated as hedging instruments
Commodity contracts
Financial contracts	$	714	$	(5,222	)	$	6,469	$	(5,107	)
Physical contracts	3,301		(1,501		)	1,064		(3,463		)
Interest-rate contracts	38,384		(4,574		)	54,503		—
Total derivatives designated as hedging instruments	$	42,399	$	(11,297	)	$	62,036	$	(8,570	)
Derivatives not designated as hedging instruments
Commodity contracts
Physical contracts	31		—			959		—
Total derivatives not designated as hedging instruments	31		—			959		—
Total derivatives	$	42,430	$	(11,297	)	$	62,995	$	(8,570	)

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

Table of Contents

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



		March 31, 2014					December 31, 2013
	Contract Type	Purchased/ Payor		Sold/ Receiver			Purchased/ Payor		Sold/ Receiver
Derivatives designated as hedging instruments:
Cash flow hedges
Fixed price
- Natural gas ( Bcf )	Futures and swaps	—		(41.6		)	—		(48.1		)
- Crude oil and NGLs ( MMbbl )	Futures, forwards and swaps	—		(3.7		)	—		(4.0		)
Basis
- Natural gas ( Bcf )	Futures and swaps	—		(41.6		)	—		(48.1		)
Interest-rate contracts ( Millions of dollars )	Forward-starting swaps	$	900.0	$	—		$	400.0	$	—

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

Cash Flow Hedges - At March 31, 2014 , our Consolidated Balance Sheet reflected a net unrealized loss of $86.3 million in accumulated other comprehensive income (loss). The portion of accumulated other comprehensive income (loss) attributable to our commodity derivative instruments is a loss of $10.5 million , which will be realized within the next 21 months as the forecasted transactions affect earnings. If commodity prices remain at the current levels, we will recognize $14.1 million in losses over the next 12 months and $3.6 million in gains thereafter. The amount deferred in accumulated other comprehensive income (loss) attributable to our settled interest-rate swaps is a loss of $107.1 million , which will be recognized over the life of the long-term, fixed-rate debt. We expect that losses of $10.3 million will be reclassified into earnings during the next 12 months as the hedged items affect earnings. The remaining amounts in accumulated other comprehensive income (loss) are attributable primarily to forward-starting interest-rate swaps, which will be amortized to interest expense over the life of long-term, fixed-rate debt upon issuance of the debt.

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



	Three Months Ended
Derivatives in Cash Flow Hedging Relationships	March 31,
Derivatives in Cash Flow Hedging Relationships	2014			2013
	( Thousands of dollars )
Commodity contracts	$	(35,762	)	$	(19,768	)
Interest-rate contracts	(20,693		)	6,788
Total unrealized gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	$	(56,455	)	$	(12,980	)

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
		March 31,
		2014			2013
		( Thousands of dollars )
Commodity contracts	Commodity sales revenues	$	(26,419	)	$	2,566
Interest-rate contracts	Interest expense	(2,589		)	(2,305		)
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)		$	(29,008	)	$	261

Ineffectiveness related to our cash flow hedges was not material for the three months ended March 31, 2014 and 2013 . In the event that it becomes probable that a forecasted transaction will not occur, we would discontinue cash flow hedge treatment,

Table of Contents

which would affect earnings. There were no gains or losses due to the discontinuance of cash flow hedge treatment during the three months ended March 31, 2014 and 2013 .

Credit Risk - Prior to March 31, 2014, all of our commodity derivative financial contracts were with our affiliate ONEOK Energy Services Company, a subsidiary of ONEOK. ONEOK Energy Services Company entered into similar commodity derivative financial contracts with third parties at our direction and on our behalf. On March 31, 2014, ONEOK completed the accelerated wind down of ONEOK Energy Services Company. In the first quarter 2014, outstanding commodity derivative positions with third parties entered into by ONEOK Energy Services Company on our behalf were transferred to us. In the future, we expect to enter into commodity derivative financial contracts directly with unaffiliated third parties.

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 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 March 31, 2014 .

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.


D.	CREDIT FACILITY AND SHORT-TERM NOTES PAYABLE

Partnership Credit Agreement - The amount of short-term borrowings authorized by our general partner’s Board of Directors is $2.5 billion . At March 31, 2014 , we had $125.0 million in commercial paper outstanding, $14.0 million in letters of credit issued and no borrowings under our Partnership Credit Agreement.

Our Partnership Credit Agreement, which was amended and restated effective on January 31, 2014, and expires in January 2019, is a $1.7 billion revolving credit facility and includes a $100 million sublimit for the issuance of standby letters of credit, a $150 million swingline sublimit and an option to request an increase in the size of the facility to an aggregate of $2.4 billion by either commitments from new lenders or increased commitments from existing lenders. Our Partnership Credit Agreement is available for general partnership purposes. 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. 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, and ONEOK does not guarantee our debt, commercial paper or other similar commitments.

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 a pipeline acquisition we completed in the first quarter 2014, the allowable ratio of indebtedness to adjusted EBITDA increased to 5.5 to 1 through the third quarter 2014. Upon breach of certain covenants by us in our Partnership Credit Agreement, amounts outstanding under our Partnership Credit Agreement, if any, may become due and payable immediately. At March 31, 2014 , our ratio of indebtedness to adjusted EBITDA was 3.7 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.

Table of Contents


E.	EQUITY

ONEOK - ONEOK and its affiliates own all of the Class B units, 19.8 million common units and the entire 2 percent general partner interest in us, which together constituted a 41.0 percent ownership interest in us at March 31, 2014 .

Equity Issuances - We have an “at-the-market” equity program for the offer and sale from time to time of our common units up to an aggregate amount of $300 million . The program allows us to offer and sell our common units at prices we deem appropriate through a sales agent. Sales of common units are made by means of ordinary brokers’ transactions on the NYSE, in block transactions, or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common units under the program. At March 31, 2014, we had $207.3 million available for issuance under the program.

During the three months ended March 31, 2014 , we sold approximately 1.1 million common units through this program. The net proceeds, including ONEOK Partners GP’s contribution to maintain its 2 percent general partner interest in us, were approximately $56.5 million which were used for general partnership purposes. During the three months ended March 31, 2013, we sold 300,000 common units through this program that resulted in net proceeds, including ONEOK Partners GP’s contribution to maintain its 2 percent general partner interest in us of approximately $16.5 million , and used the proceeds 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 April 2014, our general partner declared a cash distribution of $ 0.745 per unit ($ 2.98 per unit on an annualized basis) for the first quarter 2014, an increase of 1.5 cent s from the previous quarter, which will be paid on May 15, 2014 , to unitholders of record at the close of business on April 30, 2014 .

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



	Three Months Ended
	March 31,
	2014		2013
	( Thousands, except per unit amounts )
Distribution per unit	$	0.73	$	0.71

General partner distributions	$	4,849	$	4,418
Incentive distributions	68,255		60,437
Distributions to general partner	73,104		64,855
Limited partner distributions to ONEOK	67,737		65,880
Limited partner distributions to other unitholders	101,655		90,189
Total distributions paid	$	242,496	$	220,924

Table of Contents

The following table shows our distributions declared for the periods indicated and paid within 45 days of the end of the period:



	Three Months Ended
	March 31,
	2014		2013
	( Thousands, except per unit amounts )
Distribution per unit	$	0.745	$	0.715

General partner distributions	$	5,011	$	4,469
Incentive distributions	71,911		61,576
Distributions to general partner	76,922		66,045
Limited partner distributions to ONEOK	69,127		66,344
Limited partner distributions to other unitholders	104,506		91,039
Total distributions declared	$	250,555	$	223,428


F.	ACCUMULATED OTHER COMPREHENSIVE LOSS

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



	Accumulated Other Comprehensive Loss (a)
	( Thousands of dollars )
January 1, 2014	$	(58,837	)
Other comprehensive income (loss) before reclassifications	(56,455		)
Amounts reclassified from accumulated other comprehensive income (loss)	29,008
Net current-period other comprehensive income (loss) attributable to ONEOK Partners	(27,447		)
March 31, 2014	$	(86,284	)

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

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 March 31,					Affected Line Item in the Consolidated Statements of Income
	2014		2013			Affected Line Item in the Consolidated Statements of Income
	( Thousands of dollars )
Unrealized (gains) losses on risk-management assets/liabilities
Commodity contracts	$	26,419	$	(2,566	)	Commodity sales revenues
Interest-rate contracts	2,589		2,305			Interest expense
Total reclassifications for the period attributable to ONEOK Partners	$	29,008	$	(261	)	Net income attributable to ONEOK Partners


G.	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 waived conditionally its right to increased quarterly distributions, until it gives 90 days notice of the withdrawal of the waiver, each Class B unit and common unit currently 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

Table of Contents

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 or distributions in excess of earnings. For additional information regarding our general partner’s incentive distribution rights, see “Partnership Agreement” in Note I of the Notes to Consolidated Financial Statements in our Annual Report.


H.	UNCONSOLIDATED AFFILIATES

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



	Three Months Ended
	March 31,
	2014			2013
	( Thousands of dollars )
Northern Border Pipeline	$	23,409		$	16,390
Overland Pass Pipeline Company	4,731			2,899
Fort Union Gas Gathering	4,129			3,869
Bighorn Gas Gathering	(400		)	712
Other	1,790			1,985
Equity earnings from investments	$	33,659		$	25,855

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



	Three Months Ended
	March 31,
	2014		2013
	( Thousands of dollars )
Income Statement
Operating revenues	$	155,279	$	127,801
Operating expenses	$	71,679	$	64,271
Net income	$	78,673	$	58,204

Distributions paid to us	$	35,070	$	30,193

We incurred expenses in transactions with unconsolidated affiliates of $14.2 million and $7.8 million for the three months ended March 31, 2014 and 2013 , respectively, primarily related to Overland Pass Pipeline Company, which are included in cost of sales and fuel in our Consolidated Statements of Income. Accounts payable to our equity method investees at March 31, 2014 , and December 31, 2013 , were not material.

Low natural gas prices and the relatively higher crude oil and NGL prices, compared with natural gas on a heating-value basis, have caused producers primarily to focus 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 will be affected by commodity prices and producers’ alternative prospects.

Due to recent reductions in producer activity and declines in natural gas volumes gathered in the dry natural gas area of the Powder River Basin on the Bighorn Gas Gathering system, in which we own a 49 percent equity interest, we tested our investment for impairment at December 31, 2013. The estimated fair value exceeded the carrying value; however, a decline of 10 percent or more in the fair value of our investment in Bighorn Gas Gathering would result in a noncash impairment charge. We were not able to reasonably estimate a range of potential future impairment charges, as many of the assumptions that would be used in our estimate of fair value are dependent upon events beyond our control. The carrying amount of our investment at March 31, 2014 , was $86.6 million , which includes $53.4 million in equity method goodwill.

Table of Contents


I.	RELATED-PARTY TRANSACTIONS

Intersegment and affiliate sales are recorded on the same basis as sales to unaffiliated customers. Our Natural Gas Gathering and Processing segment sold natural gas to ONEOK and its subsidiaries. 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 three months ended March 31, 2014 and 2013, 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 accelerated wind down of ONEOK Energy Services Company, a subsidiary of ONEOK. For the three months ended March 31, 2014 and 2013, we had transactions with ONEOK Energy Services Company, which are reflected as affiliate transactions.

Under the Services Agreement with ONEOK and ONEOK Partners GP (the Services Agreement), our operations and the operations of ONEOK and its affiliates can combine or share certain common services in order to operate more efficiently and cost effectively. Under the Services Agreement, ONEOK provides to us similar services that it provides to its affiliates, including those services required to be provided pursuant to our Partnership Agreement. ONEOK Partners GP 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 and ONEOK Services Company 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. For example, a service that applies equally to all employees is allocated based upon the number of employees; however, an expense benefiting the consolidated company but having no direct basis for allocation is allocated by the modified Distrigas method, a method using a combination of ratios that includes gross plant and investment, operating income and payroll expense. For the three months ended March 31, 2014 and 2013, it is not practicable to determine what these general overhead costs would be on a stand-alone basis. All costs directly charged or allocated to us are included in our Consolidated Statements of Income. 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, general overhead costs incurred by ONEOK will be allocated primarily to us beginning in the second quarter 2014.

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



	Three Months Ended
	March 31,
	2014		2013
	( Thousands of dollars )
Revenues	$	53,526	$	82,634
Expenses
Cost of sales and fuel	$	10,835	$	9,551
Administrative and general expenses	77,246		72,496
Total expenses	$	88,081	$	82,047

ONEOK Partners GP made additional general partner contributions to us of approximately $1.0 million and $0.3 million during the three months ended March 31, 2014 and 2013 , respectively, to maintain its 2 percent general partner interest in connection with the issuances of common units. See Note E for additional information about our equity issuances and cash distributions paid to ONEOK for its general partner and limited partner interests.

Table of Contents


J.	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, wetland 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, emission 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 that 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 proposed regulatory actions on our facilities and operations is unknown. We continue to monitor these proposed regulations 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 months ended March 31, 2014 and 2013 .

The EPA’s “Tailoring Rule” regulates greenhouse gas emissions at new or modified facilities that meet certain criteria. Affected facilities are required to review best available control technology, 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. The EPA has stated it will consider lowering the threshold levels over the next five years, which could increase the impact on our existing facilities; however, potential costs, fees or expenses associated with the potential adjustments are unknown.

The EPA’s rule on air-quality standards, National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines (RICE NESHAP), initially included a compliance date in 2013, and has since become effective. While the rule could require capital expenditures for the purchase and installation of new emissions-control equipment, we do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.

In July 2011, the EPA issued a proposed rule that would change the air emission 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 EPA’s final rule reflects significant changes from the proposal issued in 2011 and allows for more manageable compliance options. 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.

Table of Contents

regulation. However, the EPA may issue additional responses, amendments and/or policy guidance on the final rule, which could alter our present expectations. Generally, the NSPS rule will require expenditures for updated emissions controls, monitoring and record-keeping requirements at affected facilities in the crude oil and natural gas industry. 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 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.

The potential capital and operating expenditures related to this legislation, the associated regulations or other new pipeline safety regulations are unknown.

Financial Markets Legislation - The Dodd-Frank Act represents a far-reaching overhaul of the framework for regulation of United States financial markets. The CFTC has issued final regulations for most of the provisions of the Dodd-Frank Act, and we have implemented measures to comply with the regulations that are applicable to our businesses. We continue to participate in financial markets for hedging certain risks inherent in our business, including commodity-price and interest-rate risks. Although the impact to date has not been material, we continue to monitor proposed regulations and the impact the regulations may have on our business and our risk-management strategies in the future.

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 litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses of such matters, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.


K.	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. Affiliate and intersegment 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 called 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 of 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 gathering and processing companies, major and independent crude oil and natural gas production companies, propane

Table of Contents

distributors, ethanol producers and petrochemical, refining and NGL marketing companies. Natural Gas Pipelines segment customers include natural gas distribution, electric-generation, natural gas marketing and petrochemical companies.

For the three months ended March 31, 2014 and 2013 , 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 March 31, 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	$	347,016		$	2,670,655		$	91,106		$	—		$	3,108,777
Sales to affiliated customers	41,214			—			12,312			—			53,526
Intersegment revenues	373,895			41,157			1,375			(416,427		)	—
Total revenues	$	762,125		$	2,711,812		$	104,793		$	(416,427	)	$	3,162,303
Net margin	$	153,554		$	268,978		$	93,489		$	(6,387	)	$	509,634
Operating costs	64,824			65,102			27,462			(7,205		)	150,183
Depreciation and amortization	28,842			27,078			10,815			—			66,735
Gain (loss) on sale of assets	(19		)	(48		)	(83		)	165			15
Operating income	$	59,869		$	176,750		$	55,129		$	983		$	292,731
Equity earnings from investments	$	5,486		$	4,764		$	23,409		$	—		$	33,659
Investments in unconsolidated affiliates	$	333,054		$	489,120		$	406,880		$	—		$	1,229,054
Total assets	$	4,048,332		$	6,861,829		$	1,848,594		$	180,765		$	12,939,520
Noncontrolling interests in consolidated subsidiaries	$	4,597		$	—		$	—		$	15		$	4,612
Capital expenditures	$	122,891		$	273,063		$	6,627		$	420		$	403,001

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $135.8 million , of which $111.6 million related to sales within the segment, net margin of $84.7 million and operating income of $45.1 million .

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $81.3 million , net margin of $68.6 million and operating income of $35.1 million .

Table of Contents



Three Months Ended March 31, 2013	Natural Gas Gathering and Processing		Natural Gas Liquids (a)		Natural Gas Pipelines (b)			Other and Eliminations			Total
	( Thousands of dollars )
Sales to unaffiliated customers	$	137,245	$	2,238,243	$	59,325		$	—		$	2,434,813
Sales to affiliated customers	55,658		—		26,976			—			82,634
Intersegment revenues	244,611		26,425		(272		)	(270,764		)	—
Total revenues	$	437,514	$	2,264,668	$	86,029		$	(270,764	)	$	2,517,447
Net margin	$	109,285	$	186,620	$	74,072		$	622		$	370,599
Operating costs	51,688		59,802		27,166			(392		)	138,264
Depreciation and amortization	23,904		19,738		11,036			—			54,678
Gain (loss) on sale of assets	28		9		4			—			41
Operating income	$	33,721	$	107,089	$	35,874		$	1,014		$	177,698
Equity earnings from investments	$	6,331	$	3,135	$	16,389		$	—		$	25,855
Investments in unconsolidated affiliates	$	335,140	$	496,800	$	388,189		$	—		$	1,220,129
Total assets	$	3,146,236	$	5,647,351	$	1,799,121		$	103,299		$	10,696,007
Noncontrolling interests in consolidated subsidiaries	$	4,691	$	—	$	—		$	15		$	4,706
Capital expenditures	$	163,948	$	274,165	$	5,342		$	9		$	443,464

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $108.2 million , of which $84.6 million related to sales within the segment, net margin of $61.5 million and operating income of $31.3 million .

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $68.4 million , net margin of $57.7 million and operating income of $23.8 million .


L.	SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

We have no significant assets or operations other than our investment in our wholly owned subsidiary, the Intermediate Partnership. The Intermediate Partnership holds all our partnership interests and equity in our subsidiaries, as well as a 50 percent interest in Northern Border Pipeline. Our 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 March 31, 2014
( Unaudited )	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	( Millions of dollars )
Revenues
Commodity sales	$	—		$	—		$	2,806.7		$	—		$	2,806.7
Services	—			—			355.6			—			355.6
Total revenues	—			—			3,162.3			—			3,162.3
Cost of sales and fuel	—			—			2,652.7			—			2,652.7
Net margin	—			—			509.6			—			509.6
Operating expenses
Operations and maintenance	—			—			130.5			—			130.5
Depreciation and amortization	—			—			66.7			—			66.7
General taxes	—			—			19.7			—			19.7
Total operating expenses	—			—			216.9			—			216.9
Gain (loss) on sale of assets	—			—			—			—			—
Operating income	—			—			292.7			—			292.7
Equity earnings from investments	265.4			265.4			10.3			(507.4		)	33.7
Allowance for equity funds used during construction	—			—			11.0			—			11.0
Other income (expense), net	82.7			82.7			0.6			(165.4		)	0.6
Interest expense	(82.7		)	(82.7		)	(68.3		)	165.4			(68.3		)
Income before income taxes	265.4			265.4			246.3			(507.4		)	269.7
Income taxes	—			—			(4.2		)	—			(4.2		)
Net income	265.4			265.4			242.1			(507.4		)	265.5
Less: Net income attributable to noncontrolling interests	—			—			0.1			—			0.1
Net income attributable to ONEOK Partners, L.P.	$	265.4		$	265.4		$	242.0		$	(507.4	)	$	265.4



	Three Months Ended March 31, 2013
( Unaudited )	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	( Millions of dollars )
Revenues
Commodity sales	$	—		$	—		$	2,198.8		$	—		$	2,198.8
Services	—			—			318.6			—			318.6
Total revenues	—			—			2,517.4			—			2,517.4
Cost of sales and fuel	—			—			2,146.8			—			2,146.8
Net margin	—			—			370.6			—			370.6
Operating expenses
Operations and maintenance	—			—			121.3			—			121.3
Depreciation and amortization	—			—			54.7			—			54.7
General taxes	—			—			17.0			—			17.0
Total operating expenses	—			—			193.0			—			193.0
Gain (loss) on sale of assets	—			—			0.1			—			0.1
Operating income	—			—			177.7			—			177.7
Equity earnings from investments	156.6			156.6			9.5			(296.8		)	25.9
Allowance for equity funds used during construction	—			—			9.1			—			9.1
Other income (expense), net	67.0			67.0			2.2			(134.0		)	2.2
Interest expense	(67.0		)	(67.0		)	(55.9		)	134.0			(55.9		)
Income before income taxes	156.6			156.6			142.6			(296.8		)	159.0
Income taxes	—			—			(2.3		)	—			(2.3		)
Net income	156.6			156.6			140.3			(296.8		)	156.7
Less: Net income attributable to noncontrolling interests	—			—			0.1			—			0.1
Net income attributable to ONEOK Partners, L.P.	$	156.6		$	156.6		$	140.2		$	(296.8	)	$	156.6

Table of Contents

Condensed Consolidating Statements of Comprehensive Income



	Three Months Ended March 31, 2014
( Unaudited )	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	( Millions of dollars )
Net income	$	265.4		$	265.4		$	242.1		$	(507.4	)	$	265.5
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	(56.5		)	(35.8		)	(35.8		)	71.6			(56.5		)
Realized (gains) losses on derivatives recognized in net income	29.0			26.4			26.4			(52.8		)	29.0
Total other comprehensive income (loss)	(27.5		)	(9.4		)	(9.4		)	18.8			(27.5		)
Comprehensive income	237.9			256.0			232.7			(488.6		)	238.0
Less: Comprehensive income attributable to noncontrolling interests	—			—			0.1			—			0.1
Comprehensive income attributable to ONEOK Partners, L.P.	$	237.9		$	256.0		$	232.6		$	(488.6	)	$	237.9



	Three Months Ended March 31, 2013
( Unaudited )	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	( Millions of dollars )
Net income	$	156.6		$	156.6		$	140.3		$	(296.8	)	$	156.7
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	(13.0		)	(19.8		)	(19.8		)	39.6			(13.0		)
Realized (gains) losses on derivatives recognized in net income	(0.2		)	(2.6		)	(2.6		)	5.2			(0.2		)
Total other comprehensive income (loss)	(13.2		)	(22.4		)	(22.4		)	44.8			(13.2		)
Comprehensive income	143.4			134.2			117.9			(252.0		)	143.5
Less: Comprehensive income attributable to noncontrolling interests	—			—			0.1			—			0.1
Comprehensive income attributable to ONEOK Partners, L.P.	$	143.4		$	134.2		$	117.8		$	(252.0	)	$	143.4

Table of Contents

Condensed Consolidating Balance Sheets



	March 31, 2014
( Unaudited )	Parent		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidating Entries			Total
Assets	( Millions of dollars )
Current assets
Cash and cash equivalents	$	—	$	115.4	$	—	$	—		$	115.4
Accounts receivable, net	—		—		869.3		—			869.3
Affiliate receivables	—		—		23.6		—			23.6
Natural gas and natural gas liquids in storage	—		—		231.2		—			231.2
Commodity imbalances	—		—		83.0		—			83.0
Other current assets	8.7		—		71.5		—			80.2
Total current assets	8.7		115.4		1,278.6		—			1,402.7
Property, plant and equipment
Property, plant and equipment	—		—		11,096.4		—			11,096.4
Accumulated depreciation and amortization	—		—		1,713.5		—			1,713.5
Net property, plant and equipment	—		—		9,382.9		—			9,382.9
Investments and other assets
Investments in unconsolidated affiliates	4,349.9		4,827.9		822.8		(8,771.5		)	1,229.1
Intercompany notes receivable	6,815.1		6,221.7		—		(13,036.8		)	—
Goodwill and intangible assets	—		—		829.2		—			829.2
Other assets	75.6		—		20.0		—			95.6
Total investments and other assets	11,240.6		11,049.6		1,672.0		(21,808.3		)	2,153.9
Total assets	$	11,249.3	$	11,165.0	$	12,333.5	$	(21,808.3	)	$	12,939.5
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	—	$	—	$	7.7	$	—		$	7.7
Notes payable	125.0		—		—		—			125.0
Accounts payable	—		—		1,140.4		—			1,140.4
Affiliate payables	—		—		53.1		—			53.1
Commodity imbalances	—		—		216.8		—			216.8
Accrued interest	88.0		—		—		—			88.0
Other current liabilities	4.6		—		80.9		—			85.5
Total current liabilities	217.6		—		1,498.9		—			1,716.5
Intercompany debt	—		6,815.1		6,221.7		(13,036.8		)	—
Long-term debt, excluding current maturities	5,985.6		—		57.6		—			6,043.2
Deferred credits and other liabilities	—		—		129.1		—			129.1
Commitments and contingencies
Equity
Equity excluding noncontrolling interests in consolidated subsidiaries	5,046.1		4,349.9		4,421.6		(8,771.5		)	5,046.1
Noncontrolling interests in consolidated subsidiaries	—		—		4.6		—			4.6
Total equity	5,046.1		4,349.9		4,426.2		(8,771.5		)	5,050.7
Total liabilities and equity	$	11,249.3	$	11,165.0	$	12,333.5	$	(21,808.3	)	$	12,939.5

Table of Contents



	December 31, 2013
( Unaudited )	Parent		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidating Entries			Total
Assets	( Millions of dollars )
Current assets
Cash and cash equivalents	$	—	$	134.5	$	—	$	—		$	134.5
Accounts receivable, net	—		—		1,103.1		—			1,103.1
Affiliate receivables	—		—		9.2		—			9.2
Natural gas and natural gas liquids in storage	—		—		188.3		—			188.3
Commodity imbalances	—		—		80.5		—			80.5
Other current assets	4.8		—		62.7		—			67.5
Total current assets	4.8		134.5		1,443.8		—			1,583.1
Property, plant and equipment
Property, plant and equipment	—		—		10,755.0		—			10,755.0
Accumulated depreciation and amortization	—		—		1,652.6		—			1,652.6
Net property, plant and equipment	—		—		9,102.4		—			9,102.4
Investments and other assets
Investments in unconsolidated affiliates	4,336.4		4,593.1		825.6		(8,525.3		)	1,229.8
Intercompany notes receivable	6,638.3		6,247.1		—		(12,885.4		)	—
Goodwill and intangible assets	—		—		832.2		—			832.2
Other assets	92.7		—		22.4		—			115.1
Total investments and other assets	11,067.4		10,840.2		1,680.2		(21,410.7		)	2,177.1
Total assets	$	11,072.2	$	10,974.7	$	12,226.4	$	(21,410.7	)	$	12,862.6
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	—	$	—	$	7.7	$	—		$	7.7
Accounts payable	—		—		1,255.4		—			1,255.4
Affiliate payables	—		—		47.5		—			47.5
Commodity imbalances	—		—		213.6		—			213.6
Accrued interest	92.7		—		—		—			92.7
Other current liabilities	—		—		89.1		—			89.1
Total current liabilities	92.7		—		1,613.3		—			1,706.0
Intercompany debt	—		6,638.3		6,247.1		(12,885.4		)	—
Long-term debt, excluding current maturities	5,985.3		—		59.6		—			6,044.9
Deferred credits and other liabilities	—		—		113.0		—			113.0
Commitments and contingencies
Equity
Equity excluding noncontrolling interests in consolidated subsidiaries	4,994.2		4,336.4		4,188.9		(8,525.3		)	4,994.2
Noncontrolling interests in consolidated subsidiaries	—		—		4.5		—			4.5
Total equity	4,994.2		4,336.4		4,193.4		(8,525.3		)	4,998.7
Total liabilities and equity	$	11,072.2	$	10,974.7	$	12,226.4	$	(21,410.7	)	$	12,862.6

Table of Contents

Condensed Consolidating Statements of Cash Flows



	Three Months Ended March 31, 2014
( Unaudited )	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	( Millions of dollars )
Operating activities
Cash provided by operating activities	$	255.6		$	21.3		$	424.8		$	(242.5	)	$	459.2
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	—			—			(403.0		)	—			(403.0		)
Acquisition	—			—			(14.0		)	—			(14.0		)
Contributions to unconsolidated affiliates	—			—			(0.6		)	—			(0.6		)
Distributions received from unconsolidated affiliates	—			—			4.7			—			4.7
Proceeds from sale of assets	—			—			0.1			—			0.1
Cash used in investing activities	—			—			(412.8		)	—			(412.8		)
Financing activities
Cash distributions:
General and limited partners	(242.5		)	(242.5		)	—			242.5			(242.5		)
Noncontrolling interests	—			—			—			—			—
Borrowing of notes payable, net	125.0			—			—			—			125.0
Intercompany borrowings (advances), net	(192.0		)	202.1			(10.1		)	—			—
Repayment of long-term debt	—			—			(1.9		)	—			(1.9		)
Issuance of common units, net of issuance costs	52.8			—			—			—			52.8
Contribution from general partner	1.1			—			—			—			1.1
Cash provided by (used in) financing activities	(255.6		)	(40.4		)	(12.0		)	242.5			(65.5		)
Change in cash and cash equivalents	—			(19.1		)	—			—			(19.1		)
Cash and cash equivalents at beginning of period	—			134.5			—			—			134.5
Cash and cash equivalents at end of period	$	—		$	115.4		$	—		$	—		$	115.4

Table of Contents



	Three Months Ended March 31, 2013
( Unaudited )	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	( Millions of dollars )
Operating activities
Cash provided by operating activities	$	225.7		$	16.4		$	160.2		$	(220.9	)	$	181.4
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	—			—			(443.5		)	—			(443.5		)
Contributions to unconsolidated affiliates	—			—			(3.0		)	—			(3.0		)
Distributions received from unconsolidated affiliates	—			5.1			1.6			—			6.7
Proceeds from sale of assets	—			—			—			—			—
Cash provided by (used in) investing activities	—			5.1			(444.9		)	—			(439.8		)
Financing activities
Cash distributions:
General and limited partners	(220.9		)	(220.9		)	—			220.9			(220.9		)
Noncontrolling interests	—			—			(0.1		)	—			(0.1		)
Intercompany borrowings (advances), net	(17.9		)	(268.8		)	286.7			—			—
Repayment of long-term debt	—			—			(1.9		)	—			(1.9		)
Issuance of common units, net of issuance costs	12.8			—			—			—			12.8
Contribution from general partner	0.3			—			—			—			0.3
Cash provided by (used in) financing activities	(225.7		)	(489.7		)	284.7			220.9			(209.8		)
Change in cash and cash equivalents	—			(468.2		)	—			—			(468.2		)
Cash and cash equivalents at beginning of period	—			537.1			—			—			537.1
Cash and cash equivalents at end of period	$	—		$	68.9		$	—		$	—		$	68.9

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 - Domestic supplies of natural gas, natural gas liquids and crude oil continue to increase from drilling activities in crude oil and NGL-rich resource areas. North American natural gas production continues to increase at a faster rate than demand, primarily as a result of increased production from nonconventional resource areas such as shale areas. We expect continued demand for midstream infrastructure development to be driven by producers who need to connect emerging natural gas and natural gas liquids production with end-use markets where current infrastructure is insufficient or nonexistent.

When economic conditions warrant, certain natural gas processors elect not to recover the ethane component of the natural gas stream, also known as ethane rejection, and instead leave the ethane component in the natural gas stream sold at the tailgate of natural gas processing plants. Price differentials between ethane and natural gas resulted in ethane rejection at most of our natural gas processing plants and some of our customers’ natural gas processing plants connected to our natural gas liquids gathering system in the Mid-Continent and Rocky Mountain regions during 2013 and the first quarter 2014, which reduced natural gas liquids volumes gathered and fractionated in our Natural Gas Liquids segment and reduced our results of operations.

We expect ethane rejection will persist at least through much of 2016, after which new world-scale ethylene production capacity is forecasted to begin coming on line, although market conditions may result in periods where it is economical to recover the ethane component in the natural gas stream. Ethane rejection is expected to have a significant impact on our financial results over this period. However, new NGL supply commitments are expected to increase volumes in 2014 through 2016 to mitigate partially the impact of ethane rejection on our Natural Gas Liquids segment. In addition, our Natural Gas Liquids segment’s integrated assets enable it to mitigate further the impact of ethane rejection through minimum volume commitments 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. Beginning in the fourth quarter 2013, we experienced high propane demand for crop drying and increased heating due to much colder than normal weather that continued into the first quarter 2014. In response to this increased 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, for the three months ended March 31, 2014, compared with the same period in 2013. 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. See additional discussion in the “Financial Results and Operating Information” section.

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

New natural gas liquids pipeline projects are expected to bring incremental NGL supply from the Rocky Mountain, Marcellus and Utica basins 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 projects are backed by fee-based supply commitments that we expect will fill much of our optimization capacity used historically to capture NGL location price differentials between the Mid-Continent and Gulf Coast market centers.

Growth Projects - Crude oil and natural gas producers continue to drill aggressively for crude oil and NGL-rich natural gas in many regions where we have operations. We expect continued development of the crude oil and NGL-rich natural gas reserves in the Bakken Shale and Three Forks formations in the Williston Basin, the Niobrara Shale and other formations in the Powder River Basin and in the Cana-Woodford Shale, Woodford Shale, Granite Wash and Mississippian Lime areas in the Mid-Continent region. In response to this increased production of crude oil, natural gas and NGLs, and higher demand for NGL products from the petrochemical industry, we are investing approximately $6.0 billion to $6.4 billion in new capital projects and acquisitions from 2010 through 2016 to meet the needs of natural gas producers and processors in these regions, as well as enhance our natural gas liquids fractionation, distribution and storage infrastructure in the Gulf Coast region. The execution of these capital investments aligns with our goal to grow fee-based earnings. Our acreage dedications and supply commitments

Table of Contents

from producers and natural gas processors in regions associated with our growth projects are expected to provide incremental cash flows and long-term fee-based earnings.

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

Cash Distributions - In April 2014, our general partner declared a cash distribution of $0.745 per unit ( $2.98 per unit on an annualized basis) for the first quarter 2014, an increase of 1.5 cent s from the previous quarter, which will be paid on May 15, 2014 , to unitholders of record as of the close of business on April 30, 2014 .

Transactions with Affiliates - For the three months ended March 31, 2014 and 2013, we had transactions with our affiliate ONEOK Energy Services Company, a subsidiary of ONEOK. Our Natural Gas Gathering and Processing segment sold natural gas to ONEOK Energy Services Company, and our Natural Gas Pipelines segment provided transportation and storage services to ONEOK Energy Services Company. Additionally, our Natural Gas Gathering and Processing and Natural Gas Liquids segments purchased a portion of the natural gas used in their operations from ONEOK Energy Services Company. All of our Natural Gas Gathering and Processing segment’s commodity derivative financial contracts were with ONEOK Energy Services Company, and it entered into similar commodity derivative financial contracts with third parties at our direction and on our behalf. On March 31, 2014, ONEOK completed the accelerated wind down of ONEOK Energy Services Company. In the first quarter 2014, outstanding commodity derivative positions with third parties entered into by ONEOK Energy Services Company on our behalf were transferred to us. In the future, we expect to enter into commodity derivative financial contracts directly with unaffiliated third parties.

On January 31, 2014, ONEOK completed the separation of its former natural gas distribution business into ONE Gas. We continue to enter into commodity sales and transportation and storage services transactions with ONE Gas after the separation, and these transactions are reflected as unaffiliated, third-party transactions beginning in February 2014.

ONEOK and its subsidiaries continue to be our sole general partner and to own limited partners units, which together at March 31, 2014, represented a 41.0 percent interest in us.

FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

The following table sets forth certain selected consolidated financial results for the periods indicated:



	Three Months Ended						Three Months
	March 31,						2014 vs. 2013
Financial Results	2014			2013			Increase (Decrease)
	( Millions of dollars )
Commodity sales	$	2,806.7		$	2,198.7		$	608.0		28	%
Services	355.6			318.7			36.9			12	%
Total revenues	3,162.3			2,517.4			644.9			26	%
Cost of sales and fuel	2,652.7			2,146.8			505.9			24	%
Net margin	509.6			370.6			139.0			38	%
Operating costs	150.2			138.3			11.9			9	%
Depreciation and amortization	66.7			54.7			12.0			22	%
Gain (loss) on sale of assets	—			0.1			(0.1		)	(100	%)
Operating income	$	292.7		$	177.7		$	115.0		65	%
Equity earnings from investments	$	33.7		$	25.9		$	7.8		30	%
Interest expense	$	(68.3	)	$	(55.9	)	$	12.4		22	%
Capital expenditures	$	403.0		$	443.5		$	(40.5	)	(9	%)

Commodity sales revenues increased for the three months ended March 31, 2014 , compared with the same period in 2013, due to wider NGL location and product price differentials, related primarily to propane in the Mid-Continent region, in our Natural Gas Liquids and Natural Gas Gathering and Processing segments, and higher natural gas and NGL sales volumes from our recently completed capital projects in our Natural Gas Gathering and Processing segment.

Table of Contents

Services revenues increased due to higher natural gas and NGL volumes from our recently completed capital projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments, and higher transportation revenues due to increased rates and park-and-loan services in our Natural Gas Pipelines segment. These increases were offset partially by severely cold weather that affected our Natural Gas Gathering and Processing and Natural Gas Liquids segments; the termination of a contract; and the impact of ethane rejection in our Natural Gas Liquids segment.

Operating costs and depreciation and amortization increased for the three months ended March 31, 2014 , compared with the same period in 2013, due primarily to the growth of our operations related to our completed capital projects. Equity earnings from investments increased due to increased park-and-loan services on Northern Border Pipeline and higher volumes on Overland Pass Pipeline, delivered from our Bakken NGL Pipeline.

Interest expense increased for the three months ended March 31, 2014 , compared with the same period in 2013, due primarily to interest costs from our $1.25 billion debt issuance in September 2013, offset partially by higher capitalized interest associated with investments in our growth projects.

Capital expenditures decreased for the three months ended March 31, 2014 , compared with the same period in 2013, due to the timing of expenditures on 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 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 gas. The residue 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 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, Granite Wash area 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 a fee-based component and fee-based contracts. Under a POP contract with a fee-based component, we retain a percentage of the proceeds from the sale of residue natural gas, condensate and/or NGLs and charge fees for gathering, treating, compressing and processing the producer’s natural gas. With a fee-based contract, we are paid a fee for the services we provide, based on volumes gathered, processed, treated and/or compressed.

We expect our capital projects will continue to generate additional revenues, earnings and cash flows as they are completed. We expect our natural gas liquids and natural gas commodity price sensitivity within this segment to increase in the future as our capital projects are completed and volumes increase under POP contracts with a fee based component with our customers. We use commodity derivative instruments and physical-forward contracts to mitigate our sensitivity to fluctuations in the natural gas, crude oil and NGL prices received for our share of volumes.

Growth Projects - Our Natural Gas Gathering and Processing segment is investing approximately $3.0 billion to $3.3 billion from 2010 through 2016 in growth projects in NGL-rich areas in the Williston Basin, the Cana-Woodford Shale and the Powder River Basin areas that we expect will enable us to meet the rapidly growing needs of crude oil and natural gas producers in those areas.

Table of Contents

Williston Basin Processing Plants and related projects - Our projects in this basin include five 100 MMcf/d natural gas processing facilities: the Garden Creek, Garden Creek II and Garden Creek III plants located in McKenzie County, North Dakota, and the Stateline I and Stateline II plants located in Williams County, North Dakota. We also plan to construct a 200 MMcf/d processing facility, the Lonesome Creek plant, located in McKenzie County, North Dakota. We have acreage dedications of approximately 3 million acres supporting these plants. In addition, we are expanding and upgrading our existing natural gas gathering and compression infrastructure and adding new well connections associated with these plants.

We placed the Garden Creek, Stateline I and Stateline II natural gas processing plants in service in December 2011, September 2012 and April 2013, respectively. Collectively, the plants and related infrastructure cost approximately $925 million, excluding AFUDC. We expect construction costs, excluding AFUDC, for the Garden Creek II plant and related infrastructure will be approximately $310 million to $345 million , and for the Garden Creek III plant and related infrastructure will be approximately $325 million to $360 million . The Garden Creek II and Garden Creek III plants are expected to be completed during the third quarter 2014 and the first quarter 2015 , respectively. We expect construction costs, excluding AFUDC, for the Lonesome Creek natural gas gathering plant and related infrastructure will be approximately $550 million to $680 million . The Lonesome Creek natural gas processing plant is expected to be completed in the fourth quarter 2015 .

We are investing approximately $150 million , excluding AFUDC, to construct a 270-mile natural gas gathering system and related infrastructure in Divide County, North Dakota. The system gathers and transports natural gas from producers in the Bakken Shale and Three Forks formations in the Williston Basin to our Stateline natural gas processing facilities in Williams County, North Dakota. We have secured long-term acreage dedications from producers for this new system, which are structured with POP and fee-based contractual terms. Portions of the system were placed in service during the second quarter 2013, and the remaining system expansion is expected to be completed by the end of 2014 .

Sage Creek acquisition and related projects - On September 30, 2013, we completed the acquisition of natural gas gathering and processing and natural gas liquids facilities in the NGL-rich areas of the Powder River Basin that include a 50 MMcf/d natural gas processing facility, the Sage Creek plant, and related natural gas gathering infrastructure. Included in the acquisition were supply contracts providing for long-term acreage dedications from producers in the area, which are structured with POP and fee-based contractual terms. We plan to invest approximately $50 million , excluding AFUDC, through 2015 to upgrade existing natural gas processing infrastructure and construct new natural gas gathering infrastructure.

Cana-Woodford Shale projects - We are investing approximately $340 million to $360 million to construct a new 200 MMcf/d natural gas processing facility, the Canadian Valley plant, and related infrastructure in the Cana-Woodford Shale in Canadian County, Oklahoma, in close proximity to our existing natural gas transportation and natural gas liquids gathering pipelines. The additional natural gas processing infrastructure is necessary to accommodate increased production of NGL-rich natural gas in the Cana-Woodford Shale where we have substantial acreage dedications from active producers. The Canadian Valley plant was completed in March 2014 . Together with related additional infrastructure, our capacity to gather and process natural gas will be approximately 390 MMcf/d in the Cana-Woodford Shale.

In all of our growth project areas, nearly all of the new natural gas production is from horizontally drilled and completed wells in nonconventional resource areas. These wells tend to produce volumes at higher initial 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. The capital needed to connect to new wells and expand our infrastructure is expected to increase compared with our historical levels of routine growth capital.

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

Selected Financial Results - Our Natural Gas Gathering and Processing segment’s operating results for the three months ended March 31, 2014, reflect the completion of our Stateline II natural gas processing plant, which was placed in service in April 2013, and the acquisition of the remaining 30 percent undivided interest in our Maysville, Oklahoma, natural gas processing facility, which was acquired in December 2013. The completion of Stateline II natural gas processing plant resulted in increased natural gas volumes gathered and processed in the Williston Basin. We expect drilling activities and development of the reserves to continue in the Williston Basin and NGL-rich areas of the Powder River Basin in the Rocky Mountain region and the Cana-Woodford Shale and Granite Wash areas in Oklahoma and Texas.

Table of Contents

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



	Three Months Ended				Variances
	March 31,				2014 vs. 2013
Financial Results	2014		2013		Increase (Decrease)
	( Millions of dollars )
NGL sales	$	379.9	$	233.5	$	146.4		63	%
Condensate sales	29.0		26.9		2.1			8	%
Residue natural gas sales	290.1		127.5		162.6			*
Gathering, compression, dehydration and processing fees and other revenue	63.2		49.6		13.6			27	%
Cost of sales and fuel	608.6		328.2		280.4			85	%
Net margin	153.6		109.3		44.3			41	%
Operating costs	64.9		51.7		13.2			26	%
Depreciation and amortization	28.8		23.9		4.9			21	%
Operating income	$	59.9	$	33.7	$	26.2		78	%
Equity earnings from investments	$	5.5	$	6.3	$	(0.8	)	(13	%)
Capital expenditures	$	122.9	$	163.9	$	(41.0	)	(25	%)

* Percentage change is greater than 100 percent.

Net margin increased for the three months ended March 31, 2014 , compared with the same period in 2013, primarily as a result of the following:

•

an increase of $36.6 million due primarily to natural gas volume growth in the Williston Basin from our Stateline II natural gas processing plant; the increase in our ownership of our Maysville, Oklahoma, natural gas processing plant; and additional well connections resulting in higher natural gas volumes gathered, compressed, processed, transported and sold, higher NGL volumes sold, and higher fees, offset partially by freeze-offs due to severely cold weather;


•	an increase of $5.8 million due primarily to higher net realized propane prices; and


•	an increase of $1.9 million due primarily to changes in contract mix.

Operating costs increased for the three months ended March 31, 2014 , compared with the same period in 2013, primarily as a result of the growth of our operations, which reflects the completion of our Stateline II natural gas processing plant and related infrastructure that were placed in service in April 2013; and costs associated with owning the remaining 30 percent undivided interest in our Maysville, Oklahoma, natural gas processing facility that was acquired in December 2013; which include the following:


•	an increase of $10.6 million due to higher materials and supplies, and outside services expenses; and


•	an increase of $2.7 million in employee-related costs due to higher labor and employee benefit costs.

Depreciation and amortization expense increased for the three months ended March 31, 2014 , compared with the same period in 2013, due to the completion of our Stateline II natural gas processing plant in the Williston Basin, the completion of well connections and infrastructure projects supporting our volume growth in the Williston Basin and the acquisition of the Sage Creek natural gas processing plant in Wyoming.

Capital expenditures decreased for the three months ended March 31, 2014 , compared with the same period in 2013, due primarily to the timing of expenditures for our growth projects discussed above. During the first quarter 2014, we connected approximately 230 new wells to our systems compared with approximately 270 in the same period in 2013. This decrease was due to much colder than normal weather in the Williston Basin in 2014.

Table of Contents

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



	Three Months Ended
	March 31,
Operating Information (a)	2014		2013
Natural gas gathered ( BBtu/d )	1,499		1,215
Natural gas processed ( BBtu/d ) (b)	1,268		989
NGL sales ( MBbl/d )	90		72
Residue natural gas sales ( BBtu/d )	567		436
Realized composite NGL net sales price ( $/gallon ) (c)	$	1.05	$	0.85
Realized condensate net sales price ( $/Bbl ) (c)	$	76.07	$	88.28
Realized residue gas net sales price ( $/MMBtu ) (c)	$	3.60	$	3.57
Average fee rate ( $/MMBtu )	$	0.38	$	0.36

(a) - Includes volumes for consolidated entities only.

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

Natural gas volumes gathered and processed, and NGL and residue natural gas sold, increased for the three months ended March 31, 2014 , compared with the same period in 2013, due to volume growth in the Williston Basin from our Stateline II natural gas processing plant and increased ownership of our Maysville, Oklahoma, natural gas processing plant, offset partially by continued declines in coal-bed methane production in the Powder River Basin in Wyoming and natural gas production declines in Kansas. The realized composite NGL net sales price increased for the three months ended March 31, 2014 , compared with the same period in 2013, due primarily to higher prices from increased demand associated with lower propane storage levels and severely cold weather.

The quantity and composition of NGLs and natural gas continues to change as our new natural gas processing plants in the Williston Basin and Mid-Continent are placed in service. Our Garden Creek, Stateline I and Stateline II plants have the capability to recover ethane when economic conditions warrant but did not do so during the first three months of 2014. Our equity NGL volumes also are expected to be weighted more toward propane, iso-butane, normal butane and natural gasoline, compared with the prior year.



	Three Months Ended
	March 31,
Equity Volume Information (a)	2014	2013

NGL sales ( MBbl/d )	18	12
Condensate sales ( MBbl/d )	3	3
Residue natural gas sales ( BBtu/d )	88	56

(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 for our equity volumes for the periods indicated:



	Nine Months Ending December 31, 2014
	Volumes Hedged	Average Price			Percentage Hedged
NGLs ( MBbl/d )	11.0	$	1.18	/ gallon	83%
Condensate ( MBbl/d )	2.5	$	2.23	/ gallon	75%
Total ( MBbl/d )	13.5	$	1.37	/ gallon	81%
Natural gas ( BBtu/d )	86.5	$	4.06	/ MMBtu	75%



	Year Ending December 31, 2015
	Volumes Hedged	Average Price			Percentage Hedged
NGLs ( MBbl/d )	1.2	$	1.07	/ gallon	5%
Natural gas ( BBtu/d )	48.9	$	4.19	/ MMBtu	41%

Table of Contents

We expect our natural gas liquids and natural gas commodity-price sensitivity within this segment to increase in the future as our capital projects are completed and volumes increase under POP contracts with our customers. Our Natural Gas Gathering and Processing segment’s commodity-price sensitivity is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at March 31, 2014 , 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:


•	a $0.01 per-gallon change in the composite price of NGLs would change annual net margin by approximately $2.3 million;


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


•	a $0.10 per-MMBtu change in the price of residue natural gas would change annual net margin by approximately $4.1 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 C of the Notes to Consolidated Financial Statements in this Quarterly Report for more information on our hedging activities.

Equity Investments - Low natural gas prices and the relatively higher crude oil and NGL prices, compared with natural gas on a heating-value basis, have caused producers primarily to focus 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 will be affected by commodity prices and producers’ alternative prospects. In the near term, a continued decline in volumes gathered in this area may reduce our ability to recover the carrying value of our assets and equity investments in this area and could result in noncash charges to earnings.

Due to recent reductions in producer activity and declines in natural gas volumes gathered in the dry natural gas area of the Powder River Basin on the Bighorn Gas Gathering system, in which we own a 49 percent equity interest, we tested our investment for impairment at December 31, 2013. The estimated fair value exceeded the carrying value; however, a decline of 10 percent or more in the fair value of our investment in Bighorn Gas Gathering would result in a noncash impairment charge. We were not able to reasonably estimate a range of potential future impairment charges, as many of the assumptions that would be used in our estimate of fair value are dependent upon events beyond our control. The carrying amount of our investment at March 31, 2014, was $86.6 million , which includes $53.4 million in equity method goodwill.

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 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, 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 that connect with our NGL fractionation and pipeline assets. In April 2013, we began transporting unfractionated NGLs from natural gas processing plants in the Williston Basin on our Bakken NGL Pipeline. These unfractionated NGLs previously were transported by rail to our Mid-Continent natural gas liquids fractionation facilities. We continue to use our rail-terminal facilities in our NGL marketing activities.

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

Table of Contents

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 our previously completed capital projects, including our Bakken NGL Pipeline, Cana-Woodford Shale and Granite Wash projects, and expansion of our NGL fractionation capacity, including the completion of our MB-2 fractionator in December 2013. Our sources of revenue are categorized as exchange services, optimization and marketing, pipeline transportation, isomerization and storage, which are defined as follows:


•	Our exchange-services activities utilize our assets to gather, fractionate and 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.

•

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 are also 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.

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. Increasing crude oil, natural gas and NGL production resulting from this activity and higher petrochemical industry demand for NGL products 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 in the next three to five years, 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 approximately $3.0 billion to $3.1 billion in NGL-related projects from 2010 through 2016. These investments will accommodate the transportation and fractionation of growing NGL supply from shale and other resource development areas across our asset base and alleviate 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.

Since late 2012, NGL location price differentials have generally remained narrow between the Mid-Continent and Gulf Coast market centers. We expect these narrower NGL price differentials, with periods of volatility for certain NGL products, to continue as new fractionators and pipelines, including our growth projects discussed below, continue to alleviate constraints between the Conway, Kansas, and Mont Belvieu, Texas, natural gas liquids market centers. In addition, new natural gas liquids pipeline projects are expected to bring incremental NGL supply from the Rocky Mountain, Marcellus and Utica basins 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 projects are backed by fee-based supply commitments that we expect will fill much of our optimization capacity used historically to capture NGL location price differentials between the two market centers.

Sterling III Pipeline - In March 2014, we completed a 550-mile natural gas liquids pipeline, the Sterling III Pipeline, which has the flexibility to transport either unfractionated NGLs or NGL products from the Mid-Continent to the Gulf Coast. The Sterling III Pipeline traverses the NGL-rich Woodford Shale that is currently under development and provides transportation capacity for the growing NGL production from the Cana-Woodford Shale and Granite Wash areas, where the pipeline gathers unfractionated NGLs from the new natural gas processing plants that are being built as a result of NGL supply growth in these areas. The Sterling III Pipeline is designed to transport up to 193 MBbl/d of NGL production from our natural gas liquids infrastructure at Medford, Oklahoma, to our storage and fractionation facilities in Mont Belvieu, Texas. We have multi-year

Table of Contents

supply commitments from producers and natural gas processors for approximately 75 percent of the pipeline’s capacity. Installation of additional pump stations could expand the capacity of the pipeline to 260 MBbl/d.

The project also includes reconfiguration of our existing Sterling I and Sterling II pipelines, expected to be completed in the second quarter 2014, which currently distribute NGL products between the Mid-Continent and Gulf Coast natural gas liquids market centers, to transport either unfractionated NGLs or NGL products. The new pipeline and reconfiguration projects cost $760 million to $790 million , excluding AFUDC.

MB-2 Fractionator - In December 2013 , we placed in service a 75 MBbl/d fractionator, MB-2, near our storage facility in Mont Belvieu, Texas. We have multi-year supply commitments from producers and natural gas processors for all of the fractionator’s capacity. The project cost approximately $375 million , excluding AFUDC.

MB-3 Fractionator - We are constructing an additional 75 MBbl/d fractionator, MB-3, near our storage facility in Mont Belvieu, Texas. In addition, we plan to expand and upgrade our existing natural gas liquids gathering and pipeline infrastructure, including new connections to natural gas processing facilities and increasing the capacity of the Arbuckle and Sterling II natural gas liquids pipelines. The MB-3 fractionator and related infrastructure are expected to cost approximately $525 million to $575 million , excluding AFUDC. The MB-3 fractionator is expected to be completed in the fourth quarter 2014 . We have multi-year supply commitments from producers and natural gas processors for approximately 80 percent of the fractionator’s capacity.

Ethane Header Pipeline - In April 2013 , we placed in service a 12-inch diameter ethane header pipeline that creates a new point of connection between our Mont Belvieu, Texas, NGL fractionation and storage assets, and several petrochemical customers. The new pipeline was designed to transport up to 400 MBbl/d from our 80 percent-owned, 160 MBbl/d MB-1 fractionator and our wholly owned 75 MBbl/d MB-2 and MB-3 fractionators and our ethane/propane splitter. The ethane header pipeline project cost approximately $23 million , excluding AFUDC.

Ethane/Propane Splitter - In March 2014, we placed in service a new 40 MBbl/d ethane/propane splitter at our Mont Belvieu storage facility to split ethane/propane mix into purity ethane in order to meet the needs of petrochemical customers, which we expect will grow over the long term. The facility will be capable of producing 32 MBbl/d of purity ethane and 8 MBbl/d of propane. The ethane/propane splitter project cost approximately $46 million , excluding AFUDC.

Bakken NGL Pipeline and related projects - The Bakken NGL Pipeline, a 600-mile natural gas liquids pipeline with capacity to transport 60 MBbl/d of unfractionated NGLs from the Williston Basin to the Overland Pass Pipeline, was placed in service in April 2013. The unfractionated NGLs then are delivered to our existing natural gas liquids fractionation and distribution infrastructure in the Mid-Continent. NGL supply commitments for the Bakken NGL Pipeline are anchored by NGL production from our natural gas processing plants. The pipeline cost approximately $455 million , excluding AFUDC.

We are investing an additional $100 million to install additional pump stations on the Bakken NGL Pipeline to increase its capacity to 135 MBbl/d from the original capacity of 60 MBbl/d. The expansion is expected to be completed in the third quarter 2014 . We also plan to invest approximately $100 million to complete a second expansion of the Bakken NGL Pipeline to increase its capacity to 160 MBbl/d. This expansion is expected to be completed in the second quarter 2016 .

The unfractionated NGLs from the Bakken NGL Pipeline and other supply sources under development in the Rocky Mountain region required installing additional pump stations and expanding existing pump stations on the Overland Pass Pipeline in which we own a 50 percent equity interest. These additions and expansions were placed in service in the second quarter 2013 and increased the capacity of the Overland Pass Pipeline to 255 MBbl/d. Our share of the costs for this project was approximately $36 million , excluding AFUDC.

Sage Creek-related infrastructure - On September 30, 2013, we acquired certain natural gas gathering and processing and natural gas liquids facilities serving the NGL-rich Niobrara Shale and other formations in the Powder River Basin, which includes a natural gas liquids pipeline. The acquired natural gas liquids pipeline will be integrated into our natural gas liquids system and used as a platform for future growth opportunities. We plan to invest approximately $85 million , excluding AFUDC, to build new natural gas liquids pipeline infrastructure and connect the Sage Creek natural gas processing plant to our Bakken NGL Pipeline. These projects are expected to be completed in the fourth quarter 2014 .

Bushton Fractionator expansion - In September 2012, we placed in service an expansion and upgrade to our existing NGL fractionation capacity at Bushton, Kansas, increasing capacity to 210 MBbl/d from 150 MBbl/d. This additional capacity is

Table of Contents

necessary to accommodate the volume growth from the Mid-Continent and Williston Basin. These projects cost approximately $117 million, excluding AFUDC.

New natural gas liquids pipeline and modification of Hutchinson fractionation infrastructure - We plan to invest approximately $140 million , excluding AFUDC, to construct a new 95-mile natural gas liquids pipeline that will connect our existing natural gas liquids fractionation and storage facilities in Hutchinson, Kansas, to similar facilities in Medford, Oklahoma. These projects also include related modifications to existing natural gas liquids fractionation infrastructure at Hutchinson, Kansas, to accommodate additional unfractionated NGLs produced in the Williston Basin. The pipeline and related modifications are expected to be completed during the first quarter 2015 .

Cana-Woodford Shale and Granite Wash projects - We constructed approximately 230 miles of natural gas liquids pipelines that expanded our existing Mid-Continent natural gas liquids gathering system in the Cana-Woodford Shale and Granite Wash areas. These pipelines expanded our capacity to transport unfractionated NGLs from these Mid-Continent supply areas to fractionation facilities in Oklahoma and Texas, and distribute NGL products to the Mid-Continent, Gulf Coast and upper Midwest market centers. We installed additional pump stations and pipeline looping on our Arbuckle Pipeline to increase its capacity to 260 MBbl/d. These projects have added, through multi-year supply contracts, approximately 75 to 80 MBbl/d of unfractionated NGLs to our existing natural gas liquids gathering systems. These projects were placed in service in April 2012 and cost approximately $220 million, excluding AFUDC.

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

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



	Three Months Ended				Variances
	March 31,				2014 vs. 2013
Financial Results	2014		2013		Increase (Decrease)
	( Millions of dollars )
NGL and condensate sales	$	2,485.8	$	2,049.8	$	436.0		21	%
Exchange service and storage revenues	202.6		192.4		10.2			5	%
Transportation revenues	23.4		22.5		0.9			4	%
Cost of sales and fuel	2,442.8		2,078.1		364.7			18	%
Net margin	269.0		186.6		82.4			44	%
Operating costs	65.1		59.8		5.3			9	%
Depreciation and amortization	27.1		19.7		7.4			38	%
Operating income	$	176.8	$	107.1	$	69.7		65	%
Equity earnings from investments	$	4.8	$	3.1	$	1.7		55	%
Capital expenditures	$	273.1	$	274.2	$	(1.1	)	—	%

In the fourth quarter 2013, we experienced high propane demand for crop drying and increased heating demand due to colder than normal weather that continued into the first quarter 2014. In response to increased demand, propane prices at the Mid-Continent market center at Conway, Kansas, increased significantly, compared with propane prices at the Gulf Coast market center at Mont Belvieu, Texas. To help meet the demand and capture the wider location price differentials between these two markets, we utilized our assets to deliver more propane into the Mid-Continent region from the Gulf Coast region. 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.

Ethane rejection in the Rocky Mountain and Mid-Continent regions continued in 2014 as expected, resulting in capacity being available on our pipelines that connect the Mid-Continent and Gulf Coast market centers, a portion of which we were able to utilize for optimization activities, including the delivery of propane into the Mid-Continent region. Severely cold weather in the first quarter 2014 caused freeze-offs, which also affected volumes.

Table of Contents

Net margin increased for the three months ended March 31, 2014 , compared with the same period in 2013, primarily as a result of the following:

•

an increase of $72.5 million in optimization and marketing margins, which resulted from a $40.7 million increase due primarily to significantly wider NGL location price differentials, primarily related to increased weather-related seasonal demand for propane, a $18.2 million increase due primarily to wider NGL product price differentials; and a $13.6 million increase in marketing margins related primarily to increased weather-related seasonal demand for propane;


•	an increase of $8.0 million in exchange-services margins, which resulted primarily from higher NGL volumes from the Bakken NGL Pipeline, and higher fees for exchange-services activities resulting from contract renegotiations, offset partially by lower volumes from severely cold weather and the termination of a contract;


•	an increase of $3.4 million in storage margins due primarily to contract renegotiations;


•	an increase of $3.3 million related to higher isomerization volumes, resulting from the wider NGL product price differential between normal butane and iso-butane; offset partially by


•	a decrease of $3.5 million resulting from the impact of ethane rejection, which resulted in lower NGL volumes; and


•	a decrease of $1.4 million due to the impact of operational measurement losses of approximately $0.9 million in the first quarter 2014, compared with measurement gains of approximately $0.5 million in the same period last year.

Operating costs increased for the three months ended March 31, 2014 , compared with the same period in 2013, primarily as a result of the following:


•	an increase of $2.3 million due to higher outside services expenses associated primarily with scheduled maintenance and the growth of operations related to completed capital projects;


•	an increase of $2.1 million due to higher ad valorem taxes related to completed capital projects; and


•	an increase of $1.0 million due to higher employee-related expenses due to recently completed capital projects and the growth of our operations .

Depreciation and amortization expense increased for the three months ended March 31, 2014 , compared with the same period in 2013, due primarily to the higher depreciation associated with completed capital projects.

Equity earnings increased for the three months ended March 31, 2014 , compared with the same period in 2013, due primarily to higher volumes delivered to Overland Pass Pipeline from our Bakken NGL Pipeline, which was placed in service in April 2013.



	Three Months Ended
	March 31,
Operating Information	2014		2013
NGL sales ( MBbl/d )	563		578
NGLs transported-gathering lines ( MBbl/d ) (b)	475		498
NGLs fractionated ( MBbl/d ) (a)	472		512
NGLs transported-distribution lines ( MBbl/d ) (b)	430		394
Average Conway-to-Mont Belvieu OPIS price differential - ethane in ethane/propane mix ( $/gallon )	$	0.12	$	0.01

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

(b) - Includes volumes for consolidated entities only.

NGLs transported on gathering lines and NGLs fractionated decreased for the three months ended March 31, 2014 , compared with the same period in 2013, due primarily to the termination of a contract, the impact of severely cold weather across our system and increased ethane rejection in the Mid-Continent region, offset partially by increased volumes from the Williston Basin on our completed Bakken NGL Pipeline.

NGLs transported on distribution lines increased for the three months ended March 31, 2014 , compared with the same period in 2013, due primarily to higher NGL volumes, primarily propane, transported to the Mid-Continent region due to increased demand.

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.

Table of Contents

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 transports natural gas from an interconnection with TransCanada pipeline near Emerson, Manitoba, to serve local natural gas distribution companies in Minnesota, North Dakota and Wisconsin, and terminates at a connection with 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 Company, 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 areas, including the Cana-Woodford Shale, Woodford Shale, Granite Wash and Mississippian Lime. We also have access to the major natural gas producing areas, including the Mississippian Lime formation in south central Kansas. In Texas, our intrastate natural gas pipelines are connected to the major natural gas producing areas in the Texas Panhandle, including the Granite Wash area and Delaware and Cline producing areas 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 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.

Our transportation contracts for our regulated natural gas storage 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.

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



	Three Months Ended					Variances
	March 31,					2014 vs. 2013
Financial Results	2014			2013		Increase (Decrease)
	( Millions of dollars )
Transportation revenues	$	74.0		$	60.5	$	13.5		22	%
Storage revenues	23.4			17.4		6.0			34	%
Gas sales and other revenues	7.4			8.1		(0.7		)	(9	%)
Cost of sales	11.3			11.9		(0.6		)	(5	%)
Net margin	93.5			74.1		19.4			26	%
Operating costs	27.5			27.2		0.3			1	%
Depreciation and amortization	10.8			11.0		(0.2		)	(2	%)
Loss on sale of assets	(0.1		)	—		(0.1		)	—	%
Operating income	$	55.1		$	35.9	$	19.2		53	%
Equity earnings from investments	$	23.4		$	16.4	$	7.0		43	%
Capital expenditures	$	6.6		$	5.3	$	1.3		25	%
Cash paid for acquisitions	$	14.0		$	—	$	14.0		*

* Percentage change is greater than 100 percent.

Table of Contents

Net margin increased for the three months ended March 31, 2014, compared with the same period in 2013, primarily as a result of the following:


•	an increase of $4.9 million due to higher firm transportation revenues primarily from increased rates on our intrastate pipelines and higher contracted capacity on Midwestern Gas Transmission;


•	an increase of $4.9 million due to increased park-and-loan services on our interstate pipelines as a result of weather-related seasonal demand;


•	an increase of $4.7 million from increased short-term natural gas storage services due to increased park-and-loan services; and


•	an increase of $4.7 million from higher net retained fuel due to higher natural gas prices and additional natural gas volumes retained.

Equity earnings from our investments increased $7.0 million for the three months ended March 31, 2014 , compared with the same period in 2013, primarily due to increased park-and-loan services on Northern Border Pipeline as a result of increased weather-related seasonal demand.

In the first quarter 2014, we acquired a 130-mile natural gas pipeline in western Oklahoma for $28 million, of which $14 million will be paid in 2018, that provides service to two natural gas-fired electric power plants and is connected to our existing intrastate natural gas pipeline in the state.



	Three Months Ended
	March 31,
Operating Information (a)	2014			2013
Natural gas transportation capacity contracted ( MDth/d )	5,866			5,670
Transportation capacity subscribed	93		%	93		%
Average natural gas price
Mid-Continent region ( $/MMBtu )	$	5.60		$	3.42

(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 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 in the future as the development of shale and other resource areas continues.

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, income taxes and allowance for equity funds used during construction. 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 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.

Table of Contents

A reconciliation of Adjusted EBITDA for the three months ended March 31, 2014 and 2013, to net income, which is the nearest comparable GAAP financial measure, is as follows:



	Three Months Ended
	March 31,
( Unaudited )	2014			2013
Reconciliation of Net Income to Adjusted EBITDA	( Thousands of dollars )
Net income	$	265,468		$	156,685
Interest expense	68,276			55,872
Depreciation and amortization	66,735			54,678
Income taxes	4,181			2,307
Allowance for equity funds used during construction	(10,971		)	(9,087		)
Adjusted EBITDA	$	393,689		$	260,455

Adjusted EBITDA increased $133.2 million for the three months ended March 31, 2014, compared with the same period in 2013. The changes in operating income and equity earnings from investments are discussed in “Financial Results and Operating Information.”

CONTINGENCIES

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

LIQUIDITY AND CAPITAL RESOURCES

General - Part of our strategy is to grow through internally generated growth projects and acquisitions that strengthen and complement our existing assets. We have relied primarily on operating cash flow, 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 flow. Capital expenditures are funded by operating cash flow, 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.

In the first three months of 2014 , we utilized cash from operations, our commercial paper program and proceeds from our equity issuances under our “at-the-market” equity program to fund our short-term liquidity needs and our capital projects. See discussion under “Short-term Liquidity” and “Long-term Financing” for more information.

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. We expect to fund our future capital expenditures with short- and long-term debt, the issuance of equity and operating cash flows.

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



	March 31,	December 31,
	2014	2013
Long-term debt	55%	55%
Equity	45%	45%
Debt (including notes payable)	55%	55%
Equity	45%	45%

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. To the extent commercial paper is unavailable, our revolving credit agreement may be used.

Table of Contents

The total amount of short-term borrowings authorized by our general partner’s Board of Directors is $2.5 billion . At March 31, 2014 , we had $125 million in commercial paper outstanding, $14 million in letters of credit issued and no borrowings outstanding under our Partnership Credit Agreement. At March 31, 2014 , we had approximately $115.4 million of cash and approximately $1.6 billion of credit available under the Partnership Credit Agreement. At March 31, 2014 , we could have issued $2.9 billion of short- and long-term debt to meet our liquidity needs under the most restrictive provisions contained in our various borrowing agreements. Based on the forward LIBOR curve, we expect interest rates to increase in the next year, compared with interest rates on amounts outstanding during the previous 24 months.

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 and asset securitization and the sale and leaseback of facilities.

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

Equity Issuances - We have an “at-the-market” equity program for the offer and sale from time to time of our common units up to an aggregate amount of $300 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. ONEOK Partners is under no obligation to offer and sell common units under the program. At March 31, 2014, we had $207.3 million available for issuance under the program.

During the three months ended March 31, 2014 , we sold approximately 1.1 million common units through this program. The net proceeds, including ONEOK Partners GP’s contribution to maintain its 2 percent general partner interest in us, were approximately $56.5 million . We used the proceeds for general partnership purposes. During the three months ended March 31, 2013, we sold 300,000 common units through this program that resulted in net proceeds, including ONEOK Partners GP’s contribution to maintain its 2 percent general partner interest in us, of approximately $16.5 million and used the proceeds for general partnership purposes.

As a result of these transactions, ONEOK’s aggregate ownership interest in us decreased to 41.0 percent at March 31, 2014 , from 41.2 percent at December 31, 2013 .

Table of Contents

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. At December 31, 2013 , we had forward-starting interest-rate swaps with notional amounts totaling $400 million , which had settlement dates greater than 12 months and are designated as cash flow hedges. In February 2014, we entered into forward-starting interest-rate swaps with notional amounts totaling $500 million with settlement dates of less than 12 months that were designated as cash flow hedges.

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 required to maintain existing operations and do not generate additional revenues. Our capital expenditures are financed typically through operating cash flows, short- and long-term debt and the issuance of equity.

Capital expenditures were $403.0 million and $443.5 million for the three months ended March 31, 2014 and 2013 , respectively.

The following table summarizes our 2014 projected growth and maintenance capital expenditures, excluding AFUDC:



	Growth		Maintenance		Total
	( Millions of dollars )
Natural Gas Gathering and Processing	$	1,010	$	29	$	1,039
Natural Gas Liquids	820		63		883
Natural Gas Pipelines	50		29		79
Other	—		23		23
Total projected capital expenditures	$	1,880	$	144	$	2,024

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



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

Our commercial paper program is rated Prime-2 by Moody’s and A-2 by S&P. 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. The most common criteria for assessment of our credit ratings are the debt-to-EBITDA ratio, interest coverage, business risk profile and liquidity.

If our credit ratings were downgraded, our cost to borrow funds under our 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 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 March 31, 2014 .

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 interests, during the periods indicated:



	Three Months Ended
	March 31,
	2014		2013
	( Millions of dollars )
Common unitholders	$	116.1	$	104.2
Class B unitholders	53.3		51.8
General partner	73.1		64.9
Noncontrolling interests	—		0.2
Total cash distributions paid	$	242.5	$	221.1

In the three months ended March 31, 2014 and 2013 , cash distributions paid to our general partner included incentive distributions of $68.3 million and $60.4 million, respectively.

In April 2014, our general partner declared a cash distribution of $0.745 per unit ( $2.98 per unit on an annualized basis) for the first quarter 2014, which will be paid on May 15, 2014 , to unitholders of record as of April 30, 2014 .

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.

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. We believe that our available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity-price volatility. See Note C of the Notes to Consolidated Financial Statements and the discussion under 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 impact net income but do not result in actual cash receipts or payments during the period and for operating cash items that do not affect 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 earnings from investments, distributions received from unconsolidated affiliates and changes in our assets and liabilities not classified as investing or financing activities.

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



							Variances
	Three Months Ended						2014 vs. 2013
	March 31,						Increase (Decrease)
	2014			2013			Increase (Decrease)
	( Millions of dollars )
Total cash provided by (used in):
Operating activities	$	459.2		$	181.4		$	277.8
Investing activities	(412.8		)	(439.8		)	27.0
Financing activities	(65.5		)	(209.8		)	144.3
Change in cash and cash equivalents	(19.1		)	(468.2		)	449.1
Cash and cash equivalents at beginning of period	134.5			537.1			(402.6		)
Cash and cash equivalents at end of period	$	115.4		$	68.9		$	46.5

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

Table of Contents

in demand for the end products that are made with our products or 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 $320.3 million for the three months ended March 31, 2014 , compared with $201.4 million for the same period in 2013 . The increase was due primarily to an increase in net margin offset partially by increases in operating and interest expenses, as discussed in “Financial Results and Operating Information.” Distributions received from unconsolidated affiliates also increased due to higher equity earnings.

The changes in operating assets and liabilities increased operating cash flows $138.9 million for the three months ended March 31, 2014 , compared with a decrease of $20.0 million for the same period in 2013 . This change is due primarily to the the change in accounts receivable, accounts payable and affiliate payables resulting from the timing of receipt of cash from customers and payments to vendors and suppliers, which vary from period to period. This change also is due to the change in NGL volumes in storage and commodity imbalances.

Investing Cash Flows - Cash used in investing activities decreased for the three months ended March 31, 2014 , compared with the same period in 2013 , due primarily to decreased capital expenditures on our growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments due to the timing of expenditures for our capital projects.

Financing Cash Flows - Cash used in financing activities decreased for the three months ended March 31, 2014 , compared with the same period in 2013 , due primarily to borrowings of notes payable and issuance of common units offset partially by higher distributions paid.

REGULATORY

ENVIRONMENTAL AND SAFETY MATTERS

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

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, emission 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

evaluate the progress of states in replacing cast iron pipelines. The impact of any such proposed regulatory actions on our facilities and operations is unknown. We continue to monitor these proposed regulations and the impact they may have on our business. 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.


•	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.

The potential capital and operating expenditures related to this legislation, the associated regulations or other new pipeline safety regulations are unknown.

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 greenhouse gas 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 greenhouse gas 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.

Our 2013 total reported emissions were approximately 46.7 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 greenhouse gas emissions, including carbon dioxide and methane. Likewise, the EPA may institute additional regulatory rulemaking associated with greenhouse gas emissions from the oil and 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 rule on air-quality standards, titled RICE NESHAP, initially included a compliance date in 2013, and has since become effective. While the rule could require capital expenditures for the purchase and installation of new emissions-control equipment, we do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.

Table of Contents

The rule was most recently amended in September 2013, and the EPA has indicated that further amendments may be issued in 2014. Based on the amendments and our understanding of pending stakeholder responses to the NSPS rule, we do not anticipate a material impact to our anticipated capital, operations and maintenance costs resulting from compliance with the regulation. However, the EPA may issue additional responses, amendments and/or policy guidance on the final rule, which could alter our present expectations. Generally, the NSPS rule will require expenditures for updated emissions controls, monitoring and record-keeping requirements at affected facilities in the crude oil and natural gas industry. 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 an interim rule in April 2007 that requires companies to provide reports on sites where certain chemicals, including many hydrocarbon products, are stored. We completed the Homeland Security assessments, 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 greenhouse gas 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 for discussion of new accounting standards.

Table of Contents

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 critical accounting policies and estimates 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 within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. The forward-looking statements relate to our anticipated financial performance (including projected operating income, net income, capital expenditures, cash flows and distributions), liquidity, management’s plans and objectives for our future growth projects and other future operations (including plans to construct additional natural gas and natural gas liquids pipelines and processing facilities and related cost estimates), our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. 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, which are applicable only as of the date of this Quarterly Report. 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 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 global warming;


•	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;

Table of Contents


•	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 a local, state or federal regulatory body, including the FERC, the National Transportation Safety Board, the PHSMA, 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 control over financial reporting could emerge or that minor problems could become significant;


•	the impact and outcome of pending and future litigation;


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

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

– competitive conditions in the overall energy market;

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

– availability of additional storage capacity;


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


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


•	our ability to acquire all necessary permits, consents and 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 Annual Report. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. 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.

Table of Contents


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 C 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.

INTEREST-RATE RISK

We are subject to the risk of interest-rate fluctuation in the normal course of business. We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts. At March 31, 2014 , and December 31, 2013 , we had forward-starting interest-rate swaps with notional amounts totaling $900 million and $400 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. The interest rate on all of our long-term debt was fixed. Future issuances of long-term debt could be affected by changes in interest rates, which could result in higher interest costs.


ITEM 4.	CONTROLS AND PROCEDURES

Quarterly Evaluation of Disclosure Controls and Procedures - The Chief Executive Officer and the Chief Financial Officer of ONEOK Partners GP, our general partner, who are the equivalent of our principal executive and principal financial officers, 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 first quarter ended March 31, 2014 , 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

Not Applicable.


ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

Not Applicable.


ITEM 4.	MINE SAFETY DISCLOSURES

Not Applicable.

Table of Contents


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	Amended and Restated Credit Agreement, effective as of January 31, 2014, among ONEOK Partners, L.P., Citibank, N.A., as administrative agent, swing-line lender, a letter of credit issuer and a lender, and the other lenders and letter of credit issuers parties thereto, attached as an annex to that certain Amendment Agreement, dated as of December 20, 2013 (incorporated by reference to Exhibit 10.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on December 23, 2013 (File No. 1-12202)).

	10.2	Guaranty Agreement, dated as of January 31, 2014, by ONEOK Partners Intermediate Limited Partnership in favor of the Citibank, N.A., as administrative agent, under the above-referenced Amended and Restated Credit Agreement.

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

	31.2	Certification of Derek S. Reiners pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

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

	101.INS	XBRL Instance Document.

	101.SCH	XBRL Taxonomy Extension Schema Document.

	101.CAL	XBRL Taxonomy Calculation Linkbase Document.

	101.DEF	XBRL Taxonomy Extension Definitions Document.

	101.LAB	XBRL Taxonomy Label Linkbase Document.

	101.PRE	XBRL Taxonomy Presentation Linkbase Document.

Attached as Exhibit 101 to this Quarterly Report are the following XBRL-related documents: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three months ended March 31, 2014 and 2013 ; (iii) Consolidated Statements of Comprehensive Income for the three months ended March 31, 2014 and 2013 ; (iv) Consolidated Balance Sheets at March 31, 2014 , and December 31, 2013 ; (v) Consolidated Statements of Cash Flows for the three months ended March 31, 2014 and 2013 ; (vi) Consolidated Statement of Changes in Equity for the three months ended March 31, 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: May 7, 2014		By:	/s/ Derek S. Reiners
			Derek S. Reiners
			Senior Vice President,
			Chief Financial Officer and Treasurer
			(Signing on behalf of the Registrant)

Exhibit 10.2

GUARANTY AGREEMENT

THIS GUARANTY AGREEMENT (the “Agreement”), dated as of January 31, 2014 is made by ONEOK PARTNERS INTERMEDIATE LIMITED PARTNERSHIP, a Delaware limited partnership (the “ Guarantor” ) in favor of CITIDANK, N.A., a national banking association, as administrative agent (the “ Administrative Agent ”) for the several banks and other financial institutions (the “ Lenders” ) from time to time party to the Amended and Restated Credit Agreement, dated as of the date hereof, by and among and ONEOK PARTNERS, L.P. (the “ Borrower” ), the Lenders, the Administrative Agent, Citibank, N.A., as an L/C Issuer and as Swing Line Lender, and the other L/C Issuers named therein (as further amended, restated, supplemented or otherwise modified from time to time, the “Credit Agreement” ; capitalized terms used herein and not otherwise defined herein shall have the meanings assigned to such terms in the Credit Agreement).

WITNESSETH:

WHEREAS, pursuant to the Credit Agreement, the Lenders have agreed to establish a revolving credit facility for the Borrower;

WHEREAS, the Guarantor is a direct Subsidiary of the Borrower and will derive substantial benefit from the making of Loans by the Lenders and the issuance of Letters of Credit by the L/C Issuers; and

WHEREAS, it is a condition precedent to the obligations of the Administrative Agent, the L/C Issuers, the Swing Line Lender, and the Lenders under the Credit Agreement that the Guarantor execute and deliver to the Administrative Agent this Agreement and the Guarantor wishes to fulfill said condition precedent;

NOW, THEREFORE, in order to induce Lenders to extend the Loans and the L/C Issuers to issue Letters of Credit and to make the financial accommodations as provided for in the Credit Agreement and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1. Guarantee . The Guarantor unconditionally guarantees, jointly with any other guarantors from time to time and severally, as a primary obligor and not merely as a surety, the due and punctual payment and performance of all Obligations, whether at stated maturity, by required prepayment, upon acceleration, demand or otherwise and whether recovery upon such indebtedness and liabilities may be or hereafter become unenforceable or shall be an allowed or disallowed claim under any proceeding or case commenced by or against any Loan Party under Debtor Relief Laws, and including interest that accrues after the commencement by or against any Loan Party of any proceeding under any Debtor Relief Laws whether or not the claim for such interest is allowed in such proceeding, including, without limitation, (i) the due and punctual payment of (A) the principal of and premium, if any, and interest (including interest accruing during the pendency of any proceeding or case under any Debtor Relief Law, regardless of whether allowed or allowable in such proceeding or case) on the Loans, when and as due, whether at maturity, by acceleration, upon one or more dates set for prepayment or otherwise, (B) each payment required to be made by the Borrower under the Credit Agreement in respect of any Letter of Credit, when and as due, including payments in respect of reimbursement or disbursements, interest thereon and obligations to provide cash collateral, and (C) all other monetary obligations, including fees, costs, expenses and indemnities, whether primary, secondary, direct, contingent, fixed or otherwise of the Borrower and other Loan Parties to the Administrative Agent and the Lenders under the Credit Agreement and the other Loan Documents, and (ii) the due and punctual performance of all covenants, agreements, obligations and liabilities of the Borrower and other Loan Parties under or

pursuant to the Credit Agreement and the other Loan Documents (collectively, the “Guaranteed Obligations” ). The Guarantor further agrees that the Guaranteed Obligations may be amended, extended, refinanced, modified or renewed, in whole or in part, without notice to or further assent from the Guarantor, and that the Guarantor will remain bound upon its guarantee notwithstanding any amendment, extension, refinancing, modification or renewal of any Guaranteed Obligations. All payments made by the Guarantor under this Agreement shall be made to the Administrative Agent at the Administrative Agent’s Office in Dollars.

Anything contained herein to the contrary notwithstanding, to the extent that the obligations of the Guarantor hereunder would be subject to avoidance as a fraudulent transfer or conveyance under Section 548 of the Bankruptcy Code (Title 11, United States Code) or any comparable provisions of any similar federal or state law, the obligations of the Guarantor hereunder shall be limited to an aggregate amount equal to the largest amount that would not render its obligations hereunder subject to such avoidance provisions.

Section 2. Obligations Not Waived . To the fullest extent permitted by applicable law, the Guarantor waives presentment or protest to, demand of or payment from the Borrower or any other guarantor of any of the Guaranteed Obligations, and also waives notice of acceptance of its guarantee and notice of protest for nonpayment. To the fullest extent permitted by applicable law, the obligations of the Guarantor hereunder shall not be affected by (i) the failure of the Administrative Agent or any Lender to assert any claim or demand or to enforce or exercise any right or remedy against the Borrower or any other guarantor under the provisions of the Credit Agreement, any other Loan Document or otherwise, (ii) any rescission, waiver, amendment or modification of, or any release from any of the terms or provisions of, this Agreement, any other Loan Document, any guarantee or any other agreement, or (iii) the failure to perfect any security interest in, or the release of, any of the security held by or on behalf of the Administrative Agent or any Lender.

Section 3. Guarantee of Payment . The Guarantor further agrees that its guarantee constitutes a guarantee of payment when due and not of collection, and waives any right to require that any resort be had by the Administrative Agent or any Lender to any security held for payment of the Guaranteed Obligations or to any balance of any deposit account or credit on the books of the Administrative Agent or any Lender in favor of the Borrower or any other Person.

Section 4. No Discharge or Diminishment of Guarantee . The obligations of the Guarantor hereunder shall not be subject to any reduction, limitation, impairment or termination for any reason (other than the indefeasible payment in full in cash of the Guaranteed Obligations), including any claim of waiver, release, surrender, alteration, or compromise of any of the Guaranteed Obligations with respect to any other obligor, and shall not be subject to any defense or setoff, counterclaim, recoupment or termination whatsoever by reason of the invalidity, illegality or unenforceability of the Guaranteed Obligations or otherwise. Without limiting the generality of the foregoing, the obligations of the Guarantor hereunder shall not be discharged or impaired or otherwise affected by the failure of the Administrative Agent or any Lender to assert any claim or demand or to enforce any remedy under the Credit Agreement, any other Loan Document or any other agreement, by any waiver or modification of any provision of any thereof, by any default, failure or delay, willful or otherwise, in the performance of the Guaranteed Obligations, or by any other act or omission that may or might in any manner or to any extent vary the risk of the Guarantor or that would otherwise operate as a discharge of the Guarantor as a matter of law or equity (other than the indefeasible payment in cash of the Obligations).

Section 5. Defenses of Borrower Waived . To the fullest extent permitted by applicable law, the Guarantor waives any defense based on or arising out of any defense of any Loan Party or the unenforceability of the Guaranteed Obligations or any part thereof from any cause, or the cessation from

any cause of the liability of any Loan Party, other than the final and indefeasible payment in full in cash of the Guaranteed Obligations. The Administrative Agent and the Lenders may, at their election, foreclose on any security held by one or more of them by one or more judicial or nonjudicial sales, accept an assignment of any such security in lieu of foreclosure, compromise or adjust any part of the Guaranteed Obligations, make any other accommodation with any other Loan Party or any other guarantor, without affecting or impairing in any way the liability of the Guarantor hereunder except to the extent the Guaranteed Obligations have been finally and indefeasibly paid in cash. Pursuant to applicable law, the Guarantor waives any defense arising out of any such election even though such election operates, pursuant to applicable law, to impair or to extinguish any right of reimbursement or subrogation or other right or remedy of the Guarantor against the Borrower or any other guarantor, as the case may be, or any security.

Section 6. No Setoff or Deductions. The Guarantor shall make all payments hereunder without setoff or counterclaim. The Guarantor agrees to the provisions of Section 3.01 of the Credit Agreement that are applicable to the Guarantor, and such provisions are hereby incorporated by reference herein. The obligations of the Guarantor under this paragraph shall survive the payment in full of the Guaranteed Obligations and termination of this Agreement.

Section 7. Information . The Guarantor assumes all responsibility for being and keeping itself informed of other Loan Parties’ financial condition and assets, and of all other circumstances bearing upon the risk of nonpayment of the Guaranteed Obligations and the nature, scope and extent of the risks that the Guarantor assumes and incurs hereunder, and agrees that none of the Administrative Agent or the Lenders will have any duty to advise the Guarantor of information known to it or any of them regarding such circumstances or risks.

Section 8. Indemnity and Subrogation . In addition to all such rights of indemnity and subrogation as the Guarantor may have under applicable law (but subject to Section 9 ), the Borrower agrees that (a) in the event a payment shall be made by the Guarantor under this Agreement, the Borrower shall indemnify the Guarantor for the full amount of such payment and the Guarantor shall be subrogated to the rights of the person to whom such payment shall have been made to the extent of such payment and (b) in the event any assets of the Guarantor shall be sold to satisfy a claim of any Lender under this Agreement, the Borrower shall indemnify the Guarantor in an amount equal to the greater of the book value or the fair market value of the assets so sold.

Section 9. Subordination . Notwithstanding any prov1s1on of this Agreement to the contrary, all rights of the Guarantor against the Borrower or any other Loan Party under Section 8 and all other rights of indemnity, contribution, reimbursement or subrogation under applicable law or otherwise shall be fully subordinated and junior to the indefeasible prior payment in full in cash of the Guaranteed Obligations. No failure on the part of the Borrower to make the payments required under applicable law or otherwise shall in any respect limit the obligations and liabilities of the Guarantor with respect to its obligations hereunder, and the Guarantor shall remain liable for the full amount of the obligations of the Guarantor hereunder. In addition, all Indebtedness and other obligations of the Borrower, and all Indebtedness and other obligations of any other Loan Party, in each case now or hereafter owing to the Guarantor is hereby subordinated in right of payment to the prior indefeasible payment in full in cash of the Guaranteed Obligations. If any amount shall be paid to the Guarantor on account of (i) such subrogation, contribution, reimbursement, indemnity or similar right or (ii) any such Indebtedness or obligations of any Loan Party, such amount shall be held in trust for the benefit of the Administrative Agent and the Lenders and shall forthwith be paid to the Administrative Agent to be credited against the payment of the Guaranteed Obligations, but without reducing or affecting in any manner the liability of the Guarantor under this Guaranty; provided that payments of Indebtedness and other obligations owing

by the Borrower or other Loan Party to the Guarantor at a time when there does not exist a Default or Event of Default shall not be held in trust or paid to the Administrative Agent.

Section 10. Representations and Warranties . The Guarantor represents and warrants as to itself that all representations and warranties relating to it (as a Subsidiary of the Borrower) contained in the Credit Agreement are true and correct in all material respects, except that such materiality qualifier shall not apply to the extent that any such representation and warranty is qualified by materiality.

Section 11. Termination; Reinstatement . This Guaranty is a continuing and irrevocable guaranty of all Guaranteed Obligations now or hereafter existing and shall remain in full force and effect until the Guaranteed Obligations have been indefeasibly paid in full in cash, all other amounts payable under this Guaranty have been indefeasibly paid in full in cash, the Lenders have no further commitment to lend under the Credit Agreement, the Fronting Exposure has been reduced to zero and no L/C Issuer has any further obligation to issue Letters of Credit under the Credit Agreement. Notwithstanding the foregoing, this Agreement shall continue to be effective or be reinstated, as the case may be, if at any time payment, or any part thereof, of any Obligation is rescinded or must otherwise be restored by any Lender or the Guarantor upon the bankruptcy or reorganization of the Borrower, the Guarantor or otherwise. The obligations of the Guarantor under this paragraph shall survive termination of this Agreement.

Section 12. Stay of Acceleration . In the event that acceleration of the time for payment of any of the Guaranteed Obligations is stayed, in connection with any case commenced by or against the Guarantor or the Borrower under any Debtor Relief Laws, or otherwise, all such amounts shall nonetheless be payable by the Guarantor immediately upon demand by the Administrative Agent, on behalf of the Lenders.

Section 13. Expenses . The Guarantor shall pay on demand all out-of-pocket expenses in any way relating to the enforcement or protection of the rights of the Administrative Agent and the Lenders under this Agreement or in respect of the Guaranteed Obligations, including any incurred during any “workout” or restructuring in respect of the Guaranteed Obligations and any incurred in the preservation, protection or enforcement of any rights of the Administrative Agent and the Lenders in any proceeding any Debtor Relief Laws. The obligations of the Guarantor under this paragraph shall survive the payment in full of the Guaranteed Obligations and termination of this Agreement.

Section 14. Binding Effect; Several Agreement; Assignments . Whenever in this Agreement any of the parties hereto is referred to, such reference shall be deemed to include the successors and assigns of such party; and all covenants, promises and agreements by or on behalf of the Guarantor that are contained in this Agreement shall bind the Guarantor and its successors and assigns and inure to the benefit of the Administrative Agent, the Lenders and their respective successors and assigns, and the Lenders may, without notice to the Guarantor and without affecting the Guarantor’s obligations hereunder, assign, sell or grant participations in the Guaranteed Obligations and this Guaranty, in whole or in part. This Agreement shall become effetive as to the Guarantor when a counterpart hereof is executed on behalf of the Guarantor. The Guarantor shall not have the right to assign its rights or obligations hereunder or any interest herein (and any such attempted assignment shall be void).

Section 15. Waivers; Amendment .

(a) No failure or delay of the Administrative Agent of any kind in exercising any power or right hereunder shall operate as a waiver thereof, nor shall any single or partial exercise of any such right or power, or any abandonment or discontinuance of steps to enforce such a right or power, preclude any other or further exercise thereof or the exercise of any other right or power. The rights of the Administrative Agent hereunder and of the Lenders under the other Loan Documents are cumulative and

are not exclusive of any rights or remedies that they would otherwise have. No waiver of any provision of this Agreement or consent to any departure by the Guarantor therefrom shall in any event be effective unless the same shall be permitted by subsection (b) below, and then such waiver and consent shall be effective only in the specific instance and for the purpose for which given. No notice or demand on the Guarantor in any case shall entitle the Guarantor to any other or further notice in similar or other circumstances.

(b) Neither this Agreement nor any provision hereof may be waived, amended or modified except pursuant to a written agreement entered into between the Guarantor with respect to which such waiver, amendment or modification relates and the Administrative Agent in accordance with Section 10.01 of the Credit Agreement.

Section 16. Notices . All communications and notices hereunder shall be in writing and given as provided in Section 10.02 of the Credit Agreement. All communications and notices hereunder to the Guarantor shall be given to it at its address set forth on Schedule I attached hereto or such other address as shall be designated by notice given by the Guarantor.

Section 17. Severability . Any provision of this Agreement held to be illegal, invalid or unenforceable in any jurisdiction, shall, as to such jurisdiction, be ineffective to the extent of such illegality, invalidity or unenforceability without affecting the legality, validity or enforceability of the remaining provisions hereof or thereof; and the illegality, invalidity or unenforceability of a particular provision in a particular jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

Section 18. Counterparts; Integration . This Agreement may be executed in counterparts, each of which shall constitute an original, but all of which when taken together shall constitute a single contract (subject to Section 14 ), and shall become effective as provided in Section 14. Delivery of an executed signature page to this Agreement by facsimile transmission shall be as effective as delivery of a manually executed counterpart of this Agreement. This Agreement constitutes the entire agreement among the parties hereto regarding the subject matters hereof and supersedes all prior agreements and understandings, oral or written, regarding such subject matter.

Section 19. Rules of Interpretation . The rules of interpretation specified in Section 1.02 of the Credit Agreement shall be applicable to this Agreement.

Section 20. Governing Law; Jurisdiction; Consent to Service of Process .

(a) This Agreement shall be governed by, and construed in accordance with, the internal laws of the State of New York.

(b) THE GUARANTOR (i) IRREVOCABLY AND UNCONDITIONALLY AGREES THAT IT WILL NOT COMMENCE ANY ACTION, LITIGATION OR PROCEEDING OF ANY KIND OR DESCRIPTION, WHETHER IN LAW OR EQUITY, WHETHER IN CONTRACT OR IN TORT OR OTHERWISE, AGAINST THE ADMINISTRATIVE AGENT, ANY LENDER, ANY L/C ISSUER, OR ANY RELATED PARTY OF THE FOREGOING IN ANY WAY RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT OR THE TRANSACTIONS RELATING HERETO OR THERETO, IN ANY FORUM OTHER THAN THE COURTS OF THE STATE OF NEW YORK OR FEDERAL COURT SITTING IN THE BOROUGH OF MANHATTAN IN NEW YORK CITY, AND IRREVOCABLY AND UNCONDITIONALLY SUBMITS TO THE JURISDICTION OF SUCH COURTS AND AGREES THAT ALL CLAIMS IN RESPECT OF ANY SUCH ACTION, LITIGATION OR PROCEEDING MAY BE HEARD AND DETERMINED IN SUCH NEW YORK

STATE COURT OR, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, IN SUCH FEDERAL COURT and (ii) AGREES THAT A FINAL JUDGMENT IN ANY SUCH ACTION OR PROCEEDING SHALL BE CONCLUSIVE AND MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY LAW. NOTHING IN THIS AGREEMENT OR IN ANY OTHER LOAN DOCUMENT SHALL AFFECT ANY RIGHT THAT THE ADMINISTRA TNE AGENT, ANY LENDER OR THE LIC ISSUER MAY OTHERWISE HAVE TO BRING ANY ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT AGAINST THE GUARANTOR OR ITS PROPERTIES IN THE COURTS OF ANY JURISDICTION.

(c) TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, THE GUARANTOR HEREBY (i) IRREVOCABLY AND UNCONDITIONALLY WANES ANY OBJECTION THAT IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF VENUE OF ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT IN ANY COURT REFERRED TO IN PARAGRAPH (B) OF THIS SECTION AND THE DEFENSE OF AN INCONVENIENT FORUM TO THE MAINTENANCE OF SUCH ACTION OR PROCEEDING IN ANY SUCH COURT, AND (ii) IRREVOCABLY CONSENTS TO SERVICE OF PROCESS IN THE MANNER PROVIDED FOR NOTICES IN SECTION 10.02 OF THE CREDIT AGREEMENT. NOTHING IN THIS AGREEMENT WILL AFFECT THE RIGHT OF ANY PARTY HERETO TO SERVE PROCESS IN ANY OTHER MANNER PERMITTED BY APPLICABLE LAW.

Section 21. Waiver of Jury Trial . THE GUARANTOR IRREVOCABLY WANES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY OR THEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY), AND CERTIFIES THAT NO REPRESENTATNE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER.

Section 22. Right of Setoff . If an Event of Default shall have occurred and be continuing, each Lender and its Affiliates is hereby authorized at any time and from time to time, without prior notice to the Guarantor, such notice being waived by the Guarantor to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other Indebtedness at any time owing by such Lender or such Affiliate to or for the credit or the account of the Guarantor against any or all the obligations of the Guarantor now or hereafter existing under this Agreement and the other Loan Documents, irrespective of whether or not such Person shall have made any demand under this Agreement or any other Loan Document and although such obligations may be unmatured. The rights of each Lender under this Section 22 are in addition to other rights and remedies (including other rights of setoff) that such Lender may have.

Section 23. Entire Agreement. This Agreement and the other Loan Documents represent the final agreement among the parties and may not be contradicted by evidence of prior, contemporaneous, or subsequent oral agreements of the parties. There are no unwritten oral agreements among the parties.

[Remainder of Page is Intentionally Blank]

IN WITNESS WHEREOF, the undersigned has duly executed this Agreement as of the day and year first above written.



		GUARANTOR:

		ONEOK PARTNERS INTERMEDIATE LIMITED PARTNERSHIP

		By:	ONEOK ILP GP, L.L.C., its sole General Partner

		By:	/s/ Derek S. Reiners
		Name:	Derek S. Reiners
		Title:	Senior Vice President, Chief Financial Officer and Treasurer

[Signature Page to Guaranty Agreement]

SCHEDULE I TO THE

GUARANTY AGREEMENT



ONEOK Partners Intermediate Limited Partnership
ONEOK Partners, L.P.
c/o ONEOK Partners GP, L.L.C.
100 West Fifth Street
Tulsa, OK 74102-0871
Attn:
Phone:
Fax:
Electronic Mail:
Website: http://www.oneokpartners.com/

Schedule 1 to the Guaranty Agreement

Exhibit 31.1

Certification

I, Terry K. Spencer, certify that:

I have reviewed this quarterly report on Form 10-Q of ONEOK Partners, L.P.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2014



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

	/s/ Terry K. Spencer
	Terry K. Spencer
	Chief Executive Officer
	(Signing on behalf of the Registrant and as
	Principal Executive Officer)

Exhibit 31.2

Certification

I, Derek S. Reiners, certify that:

I have reviewed this quarterly report on Form 10-Q of ONEOK Partners, L.P.;


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2014



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

	/s/ Derek S. Reiners
	Derek S. Reiners
	Chief Financial Officer
	(Signing on behalf of the Registrant and as
	Principle Financial Officer)

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of ONEOK Partners, L.P. (the “Registrant”) for the period ending March 31, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Terry K. Spencer, Chief Executive Officer of ONEOK Partners GP, L.L.C., the General Partner of the Registrant, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:


(1)	the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


(2)	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

ONEOK Partners, L.P.

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

/s/ Terry K. Spencer

Terry K. Spencer

Chief Executive Officer

(Signing on behalf of the Registrant and as Principal Executive Officer)

May 7, 2014

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to ONEOK Partners, L.P. and will be retained by ONEOK Partners, L.P. and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of ONEOK Partners, L.P. (the “Registrant”) for the period ending March 31, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Derek S. Reiners, Chief Financial Officer of ONEOK Partners GP, L.L.C., the General Partner of the Registrant, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:


(1)	the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


(2)	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

ONEOK Partners, L.P.

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

/s/ Derek S. Reiners

Derek S. Reiners

Chief Financial Officer

(Signing on behalf of the Registrant and as Principal Financial Officer)

May 7, 2014