ONEOK Partners LP - FORM 10-Q

Attached files

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EXCEL - IDEA: XBRL DOCUMENT - ONEOK Partners LP	Financial_Report.xls
EX-31.1 - CERTIFICATION OF TERRY K. SPENCER SECTION 302 - ONEOK Partners LP	oksq22014exhibit311.htm
EX-32.1 - CERTIFICATION OF TERRY K. SPENCER SECTION 906 - ONEOK Partners LP	oksq22014exhibit321.htm
EX-32.2 - CERTIFICATION OF DEREK S. REINERS SECTION 906 - ONEOK Partners LP	oksq22014exhibit322.htm
EX-31.2 - CERTIFICATION OF DEREK S. REINERS SECTION 302 - ONEOK Partners LP	oksq22014exhibit312.htm

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 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 July 29, 2014
Common units		175,910,629 units
Class B units		72,988,252 units

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ONEOK PARTNERS, L.P.

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Part I.	Financial Information	Page No.
Item 1.	Financial Statements (Unaudited)	6
	Consolidated Statements of Income - Three and Six Months Ended June 30, 2014 and 2013	6
	Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2014 and 2013	7
	Consolidated Balance Sheets - June 30, 2014, and December 31, 2013	8
	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2014 and 2013	9
	Consolidated Statement of Changes in Equity - Six Months Ended June 30, 2014	10
	Notes to Consolidated Financial Statements	12
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	60
Item 4.	Controls and Procedures	60
Part II.	Other Information
Item 1.	Legal Proceedings	60
Item 1A.	Risk Factors	60
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	60
Item 3.	Defaults Upon Senior Securities	61
Item 4.	Mine Safety Disclosures	61
Item 5.	Other Information	61
Item 6.	Exhibits	61
Signature		63

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

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

INFORMATION AVAILABLE ON OUR WEBSITE

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

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

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GLOSSARY

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



AFUDC	Allowance for funds used during construction
Annual Report	Annual Report on Form 10-K for the year ended December 31, 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
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
GAAP	Accounting principles generally accepted in the United States of America
Intermediate Partnership	ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary of ONEOK Partners, L.P.
LIBOR	London Interbank Offered Rate
MBbl/d	Thousand barrels per day
MDth/d	Thousand dekatherms per day
MMBbl	Million barrels
MMBtu	Million British thermal units
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
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
ONE Gas	ONE Gas, Inc.
ONEOK	ONEOK, Inc.
ONEOK Partners GP	ONEOK Partners GP, L.L.C., a wholly owned subsidiary of ONEOK and the sole general partner of ONEOK Partners
OPIS	Oil Price Information Service
Partnership Agreement	Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P., as amended
Partnership Credit Agreement	The Partnership’s $1.7 billion Amended and Restated Revolving Credit Agreement dated January 31, 2014
PHMSA	United States Department of Transportation Pipeline and Hazardous Materials Safety Administration
POP	Percent of Proceeds
Quarterly Report(s)	Quarterly Report(s) on Form 10-Q
S&P	Standard & Poor’s Ratings Services
SCOOP	South Central Oklahoma Oil Province

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SEC	Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
XBRL	eXtensible Business Reporting Language

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PART I - FINANCIAL INFORMATION



ITEM 1. FINANCIAL STATEMENTS



ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(Unaudited)	2014			2013			2014			2013
	(Thousands of dollars, except per unit amounts)
Revenues
Commodity sales	$	2,715,109		$	2,447,411		$	5,521,838		$	4,646,205
Services	350,626			320,768			706,200			639,421
Total revenues	3,065,735			2,768,179			6,228,038			5,285,626
Cost of sales and fuel	2,571,402			2,356,226			5,224,071			4,503,074
Net margin	494,333			411,953			1,003,967			782,552
Operating expenses
Operations and maintenance	142,664			108,086			273,182			229,375
Depreciation and amortization	71,447			58,226			138,182			112,904
General taxes	17,981			15,890			37,646			32,865
Total operating expenses	232,092			182,202			449,010			375,144
Gain (loss) on sale of assets	(16		)	279			(1		)	320
Operating income	262,225			230,030			554,956			407,728
Equity earnings from investments (Note H)	25,435			26,421			59,094			52,276
Allowance for equity funds used during construction	1,253			5,656			12,224			14,743
Other income	3,189			771			4,522			4,476
Other expense	(1,389		)	(377		)	(2,158		)	(1,858		)
Interest expense (net of capitalized interest of $11,375, $11,359, $27,143 and $23,964, respectively)	(73,008		)	(57,524		)	(141,284		)	(113,396		)
Income before income taxes	217,705			204,977			487,354			363,969
Income taxes	(3,194		)	(2,523		)	(7,375		)	(4,830		)
Net income	214,511			202,454			479,979			359,139
Less: Net income attributable to noncontrolling interests	77			87			153			173
Net income attributable to ONEOK Partners, L.P.	$	214,434		$	202,367		$	479,826		$	358,966
Limited partners’ interest in net income:
Net income attributable to ONEOK Partners, L.P.	$	214,434		$	202,367		$	479,826		$	358,966
General partner’s interest in net income	(84,669		)	(66,680		)	(161,901		)	(131,388		)
Limited partners’ interest in net income	$	129,765		$	135,687		$	317,925		$	227,578
Limited partners’ net income per unit, basic and diluted (Note G)	$	0.54		$	0.62		$	1.35		$	1.03
Number of units used in computation (thousands)	240,503			220,116			236,361			219,988

See accompanying Notes to Consolidated Financial Statements.

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
(Unaudited)	2014			2013		2014			2013
	(Thousands of dollars)
Net income	$	214,511		$	202,454	$	479,979		$	359,139
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	(32,515		)	55,362		(88,970		)	42,382
Realized (gains) losses on derivatives recognized in net income	7,834			1,330		36,842			1,069
Total other comprehensive income (loss)	(24,681		)	56,692		(52,128		)	43,451
Comprehensive income	189,830			259,146		427,851			402,590
Less: Comprehensive income attributable to noncontrolling interests	77			87		153			173
Comprehensive income attributable to ONEOK Partners, L.P.	$	189,753		$	259,059	$	427,698		$	402,417

See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	June 30,			December 31,
(Unaudited)	2014			2013
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	278,029		$	134,530
Accounts receivable, net	1,077,512			1,103,130
Affiliate receivables	8,340			9,185
Natural gas and natural gas liquids in storage	335,116			188,286
Commodity imbalances	93,070			80,481
Other current assets	92,339			67,491
Total current assets	1,884,406			1,583,103
Property, plant and equipment
Property, plant and equipment	11,516,931			10,755,048
Accumulated depreciation and amortization	1,774,798			1,652,648
Net property, plant and equipment	9,742,133			9,102,400
Investments and other assets
Investments in unconsolidated affiliates (Note H)	1,212,408			1,229,838
Goodwill and intangible assets	826,297			832,180
Other assets	83,271			115,087
Total investments and other assets	2,121,976			2,177,105
Total assets	$	13,748,515		$	12,862,608
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	7,650		$	7,650
Notes payable (Note D)	—			—
Accounts payable	1,260,334			1,255,411
Affiliate payables	39,780			47,458
Commodity imbalances	207,456			213,577
Accrued interest	92,214			92,711
Other current liabilities	142,935			89,211
Total current liabilities	1,750,369			1,706,018
Long-term debt, excluding current maturities	6,041,618			6,044,867
Deferred credits and other liabilities	129,614			113,027
Commitments and contingencies (Note J)
Equity (Note E)
ONEOK Partners, L.P. partners’ equity:
General partner	200,757			170,561
Common units: 175,910,629 and 159,007,854 units issued and outstanding at June 30, 2014, and December 31, 2013, respectively	4,318,705			3,459,920
Class B units: 72,988,252 units issued and outstanding at June 30, 2014, and December 31, 2013	1,413,909			1,422,516
Accumulated other comprehensive loss (Note F)	(110,965		)	(58,837		)
Total ONEOK Partners, L.P. partners’ equity	5,822,406			4,994,160
Noncontrolling interests in consolidated subsidiaries	4,508			4,536
Total equity	5,826,914			4,998,696
Total liabilities and equity	$	13,748,515		$	12,862,608

See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Six Months Ended
	June 30,
(Unaudited)	2014			2013
	(Thousands of dollars)
Operating activities
Net income	$	479,979		$	359,139
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	138,182			112,904
Allowance for equity funds used during construction	(12,224		)	(14,743		)
Loss (gain) on sale of assets	1			(320		)
Deferred income taxes	3,402			3,022
Equity earnings from investments	(59,094		)	(52,276		)
Distributions received from unconsolidated affiliates	61,200			51,546
Changes in assets and liabilities:
Accounts receivable	23,674			57,998
Affiliate receivables	845			2,953
Natural gas and natural gas liquids in storage	(146,830		)	(26,410		)
Accounts payable	68,045			(23,484		)
Affiliate payables	(7,678		)	(35,988		)
Commodity imbalances, net	(18,710		)	(59,621		)
Accrued interest	(497		)	(1,986		)
Other assets and liabilities, net	3,783			10,727
Cash provided by operating activities	534,078			383,461
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	(792,414		)	(924,832		)
Acquisition	(14,000		)	—
Contributions to unconsolidated affiliates	(1,063		)	(4,558		)
Distributions received from unconsolidated affiliates	16,449			17,958
Proceeds from sale of assets	319			324
Cash used in investing activities	(790,709		)	(911,108		)
Financing activities
Cash distributions:
General and limited partners	(493,049		)	(444,352		)
Noncontrolling interests	(181		)	(294		)
Borrowing of notes payable, net	—			429,000
Repayment of long-term debt	(3,825		)	(3,825		)
Issuance of common units, net of issuance costs	878,765			15,942
Contribution from general partner	18,420			332
Cash provided by (used in) financing activities	400,130			(3,197		)
Change in cash and cash equivalents	143,499			(530,844		)
Cash and cash equivalents at beginning of period	134,530			537,074
Cash and cash equivalents at end of period	$	278,029		$	6,230

See accompanying Notes to Consolidated Financial Statements.

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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	—	—	161,901			218,874
Other comprehensive income (loss) (Note F)	—	—	—			—
Issuance of common units (Note E)	16,902,775	—	—			875,276
Contribution from general partner (Note E)	—	—	18,321			—
Distributions paid (Note E)	—	—	(150,026		)	(235,365		)
June 30, 2014	175,910,629	72,988,252	$	200,757		$	4,318,705

See accompanying Notes to Consolidated Financial Statements.

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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		99,051			—			153			479,979
Other comprehensive income (loss) (Note F)		—			(52,128		)	—			(52,128		)
Issuance of common units (Note E)		—			—			—			875,276
Contribution from general partner (Note E)		—			—			—			18,321
Distributions paid (Note E)		(107,658		)	—			(181		)	(493,230		)
June 30, 2014		$	1,413,909		$	(110,965	)	$	4,508		$	5,826,914

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ONEOK PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


A.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our accompanying unaudited consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. These statements have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair 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.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” which outlines the principles an entity must apply to measure and recognize revenue for entities that enter into contracts to provide goods or services to their customers. The core principle is that an entity should recognize revenue at an amount that reflects the consideration to which the entity expects to be entitled in exchange for transferring goods or services to a customer. The amendments also require more extensive disaggregated revenue disclosures in interim and annual financial statements. This update will be effective for interim and annual periods that begin on or after December 15, 2016, with either retrospective application for all periods presented or retrospective application with a cumulative effect adjustment. We will adopt this guidance beginning in the first quarter 2017, 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.

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

Fair Value Hierarchy - At each balance sheet date, we utilize a fair value hierarchy to classify fair value amounts recognized or disclosed in our financial statements based on the observability of inputs used to estimate such fair value. The levels of the hierarchy are described below:


•	Level 1 - fair value measurements are based on unadjusted quoted prices 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:



	June 30, 2014
	Level 1			Level 2			Level 3			Total - Gross			Netting (a)			Total - Net (b)
	(Thousands of dollars)
Derivatives assets
Commodity contracts
Financial contracts	$	945		$	—		$	506		$	1,451		$	(1,451	)	$	—
Physical contracts	—			—			1,526			1,526			(933		)	593
Interest-rate contracts	—			26,649			—			26,649			—			26,649
Total derivative assets	$	945		$	26,649		$	2,032		$	29,626		$	(2,384	)	$	27,242
Derivatives liabilities
Commodity contracts
Financial contracts	$	(3,814	)	$	(2,865	)	$	(1,120	)	$	(7,799	)	$	4,934		$	(2,865	)
Physical contracts	—			—			(2,225		)	(2,225		)	933			(1,292		)
Interest-rate contracts	—			(19,240		)	—			(19,240		)	—			(19,240		)
Total derivative liabilities	$	(3,814	)	$	(22,105	)	$	(3,345	)	$	(29,264	)	$	5,867		$	(23,397	)

(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 June 30, 2014, we held no cash collateral and posted $3.5 million of cash collateral with various counterparties.

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

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	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						Six Months Ended
	June 30,						June 30,
Derivative Assets (Liabilities)	2014			2013			2014			2013
	(Thousands of dollars)
Net assets (liabilities) at beginning of period	$	1,972		$	(4,855	)	$	(782	)	$	(2,423	)
Total realized/unrealized gains (losses):
Included in earnings (a)	33			—			(895		)	—
Included in other comprehensive income (loss)	(3,318		)	12,537			(3,370		)	10,105
Purchases, issuances and settlements	—			—			3,734			—
Net assets (liabilities) at end of period	$	(1,313	)	$	7,682		$	(1,313	)	$	7,682

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

Realized/unrealized gains (losses) include the realization of our derivative contracts through maturity. During the three and six months ended June 30, 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 and six months ended June 30, 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 $6.8 billion and $6.5 billion at June 30, 2014, and December 31, 2013, respectively. The book value of the aggregate of our senior notes outstanding, including current maturities, was $6.0 billion and $6.1 billion at June 30, 2014, and December 31, 2013, respectively. The estimated fair value of the aggregate of our senior notes outstanding was determined using quoted market prices for similar issues with similar terms and maturities. The estimated fair value of our long-term debt is classified as Level 2.

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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 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. These instruments transfer the financial risk associated with a future change in value between the counterparties of the transaction, without also conveying ownership interest in the asset or liability.

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 June 30, 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 as fuel 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 June 30, 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 June 30, 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 normal 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.

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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 in a cash flow hedge relationship. We assess the effectiveness of hedging relationships quarterly by performing an effectiveness analysis on our fair value and cash flow hedging relationships to determine whether the hedge relationships are highly effective on a retrospective and prospective basis. We also document our normal purchases and normal sales transactions that we expect to result in physical delivery and that we elect to exempt from derivative accounting treatment.

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

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

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:



	June 30, 2014					December 31, 2013
	Assets (a)		(Liabilities) (a)			Assets (a)		(Liabilities) (a)
	(Thousands of dollars)
Derivatives designated as hedging instruments
Commodity contracts
Financial contracts	$	1,451	$	(7,799	)	$	6,469	$	(5,107	)
Physical contracts	1,462		(2,225		)	1,064		(3,463		)
Interest-rate contracts	26,649		(19,240		)	54,503		—
Total derivatives designated as hedging instruments	$	29,562	$	(29,264	)	$	62,036	$	(8,570	)
Derivatives not designated as hedging instruments
Commodity contracts
Physical contracts	64		—			959		—
Total derivatives not designated as hedging instruments	64		—			959		—
Total derivatives	$	29,626	$	(29,264	)	$	62,995	$	(8,570	)

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

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



		June 30, 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	—		(38.8		)	—		(48.1		)
- Crude oil and NGLs (MMbbl)	Futures, forwards and swaps	0.1		(3.0		)	—		(4.0		)
Basis
- Natural gas (Bcf)	Futures and swaps	—		(38.8		)	—		(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 June 30, 2014, our Consolidated Balance Sheet reflected a net unrealized loss of $111.0 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 $11.9 million, which will be realized within the next 18 months as the forecasted transactions affect earnings. If commodity prices remain at the current levels, we will recognize $13.6 million in losses over the next 12 months and $1.7 million in gains thereafter. The amount deferred in accumulated other comprehensive income (loss) attributable to our settled interest-rate swaps is a loss of $104.6 million, which will be recognized over the life of the long-term, fixed-rate debt. We expect that losses of $10.5 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 with future settlement dates, which will be amortized to interest expense over the life of long-term, fixed-rate debt upon issuance of the debt.

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



	Three Months Ended					Six Months Ended
Derivatives in Cash Flow Hedging Relationships	June 30,					June 30,
Derivatives in Cash Flow Hedging Relationships	2014			2013		2014			2013
	(Thousands of dollars)
Commodity contracts	$	(6,114	)	$	33,145	$	(41,876	)	$	13,377
Interest-rate contracts	(26,401		)	22,217		(47,094		)	29,005
Total unrealized gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	$	(32,515	)	$	55,362	$	(88,970	)	$	42,382

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						Six Months Ended
		June 30,						June 30,
		2014			2013			2014			2013
		(Thousands of dollars)
Commodity contracts	Commodity sales revenues	$	(5,187	)	$	1,245		$	(31,606	)	$	3,811
Interest-rate contracts	Interest expense	(2,647		)	(2,575		)	(5,236		)	(4,880		)
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)		$	(7,834	)	$	(1,330	)	$	(36,842	)	$	(1,069	)

Ineffectiveness related to our cash flow hedges was not material for the three and six months ended June 30, 2014 and 2013. In the event that it becomes probable that a forecasted transaction will not occur, we would discontinue cash flow hedge treatment,

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which would affect earnings. There were no gains or losses due to the discontinuance of cash flow hedge treatment during the three and six months ended June 30, 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. Beginning in the second quarter 2014, we enter into all 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 financial derivative instruments contain provisions that require us to maintain an investment-grade credit rating from S&P and/or Moody’s. If our credit ratings on our senior unsecured long-term debt were to decline below investment grade, the counterparties to the derivative instruments could request collateralization on derivative instruments in net liability positions. There were no financial derivative instruments with contingent features related to credit risk that were in a net liability position at June 30, 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 June 30, 2014, we had no 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. During the second quarter 2014, we increased the size of our commercial paper program to $1.7 billion from $1.2 billion. Amounts outstanding under our commercial paper program reduce the borrowing capacity under our Partnership Credit Agreement.

Our Partnership Credit Agreement contains provisions for an applicable margin rate and an annual facility fee, both of which adjust with changes in our credit rating. 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

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Agreement, if any, may become due and payable immediately. At June 30, 2014, our ratio of indebtedness to adjusted EBITDA was 3.4 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.


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 38.5 percent ownership interest in us at June 30, 2014.

Equity Issuances - In May 2014, we completed an underwritten public offering of approximately 13.9 million common units at a public offering price of $52.94 per common unit, generating net proceeds of approximately $714.5 million. In conjunction with this issuance, ONEOK Partners GP contributed approximately $15.0 million in order to maintain its 2 percent general partner interest in us. We used the proceeds to repay commercial paper, fund our capital expenditures and for general partnership purposes.

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.

During the six months ended June 30, 2014, we sold approximately 3.0 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 $164.1 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 $16.3 million and used the proceeds for general partnership purposes. There were no common units sold through this program in the second quarter 2013.

As a result of these transactions, ONEOK’s aggregate ownership interest in us decreased to 38.5 percent at June 30, 2014, from 41.2 percent at December 31, 2013.

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 July 2014, our general partner declared a cash distribution of $0.76 per unit ($3.04 per unit on an annualized basis) for the second quarter 2014, an increase of 1.5 cents from the previous quarter, which will be paid on August 14, 2014, to unitholders of record at the close of business on August 4, 2014.

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



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
	(Thousands, except per unit amounts)
Distribution per unit	$	0.745	$	0.715	$	1.475	$	1.425

General partner distributions	$	5,011	$	4,469	$	9,860	$	8,887
Incentive distributions	71,911		61,576		140,166		122,013
Distributions to general partner	76,922		66,045		150,026		130,900
Limited partner distributions to ONEOK	69,125		66,344		136,862		132,224
Limited partner distributions to other unitholders	104,506		91,039		206,161		181,228
Total distributions paid	$	250,553	$	223,428	$	493,049	$	444,352

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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				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
	(Thousands, except per unit amounts)
Distribution per unit	$	0.760	$	0.720	$	1.505	$	1.435

General partner distributions	$	5,501	$	4,512	$	10,512	$	8,981
Incentive distributions	80,381		62,633		152,292		124,209
Distributions to general partner	85,882		67,145		162,804		133,190
Limited partner distributions to ONEOK	70,519		66,807		139,646		133,151
Limited partner distributions to other unitholders	118,644		91,676		223,150		182,715
Total distributions declared	$	275,045	$	225,628	$	525,600	$	449,056


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	(88,970		)
Amounts reclassified from accumulated other comprehensive income (loss)	36,842
Net current-period other comprehensive income (loss) attributable to ONEOK Partners	(52,128		)
June 30, 2014	$	(110,965	)

(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 June 30,					Six Months Ended June 30,					Affected Line Item in the Consolidated Statements of Income
	2014		2013			2014		2013			Affected Line Item in the Consolidated Statements of Income
	(Thousands of dollars)
Unrealized (gains) losses on risk-management assets/liabilities
Commodity contracts	$	5,187	$	(1,245	)	$	31,606	$	(3,811	)	Commodity sales revenues
Interest-rate contracts	2,647		2,575			5,236		4,880			Interest expense
Total reclassifications for the period attributable to ONEOK Partners	$	7,834	$	1,330		$	36,842	$	1,069		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

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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					Six Months Ended
	June 30,					June 30,
	2014			2013		2014			2013
	(Thousands of dollars)
Northern Border Pipeline	$	15,877		$	15,279	$	39,286		$	31,669
Overland Pass Pipeline Company	4,121			5,528		8,852			8,427
Fort Union Gas Gathering	4,280			3,080		8,409			6,949
Bighorn Gas Gathering	(873		)	626		(1,273		)	1,338
Other	2,030			1,908		3,820			3,893
Equity earnings from investments	$	25,435		$	26,421	$	59,094		$	52,276

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



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
	(Thousands of dollars)
Income Statement
Operating revenues	$	121,509	$	132,152	$	276,788	$	259,953
Operating expenses	$	51,870	$	61,124	$	123,549	$	125,395
Net income	$	60,878	$	65,746	$	139,551	$	123,950

Distributions paid to us	$	42,579	$	39,311	$	77,649	$	69,504

We incurred expenses in transactions with unconsolidated affiliates of $14.3 million and $12.6 million for the three months ended June 30, 2014 and 2013, respectively, and $28.4 million and $20.4 million for the six months ended June 30, 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 June 30, 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

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June 30, 2014, was $85.7 million, which includes $53.4 million in equity method goodwill.


I.	RELATED-PARTY TRANSACTIONS

Intersegment and affiliate sales are recorded on the same basis as sales to unaffiliated customers. Prior to March 31, 2014, our Natural Gas Gathering and Processing segment sold natural gas to ONEOK and its subsidiaries, and our Natural Gas Pipelines segment provided transportation and storage services to ONEOK and its subsidiaries. Additionally, our Natural Gas Gathering and Processing segment and Natural Gas Liquids segment purchased a portion of the natural gas used in their operations from ONEOK and its subsidiaries.

On January 31, 2014, ONEOK completed the separation of its former natural gas distribution business into ONE Gas. ONE Gas was an affiliate prior to this separation. Commodity sales and services revenues in the Consolidated Statements of Income for the one month ended January 31, 2014 and for the six months ended June 30, 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 first quarter 2014 and the three and six months ended June 30, 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 Company and Midwestern Gas Transmission Company 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. Beginning in the second quarter 2014, ONEOK allocates substantially all of its general overhead costs to us as a result of ONEOK’s separation of its natural gas distribution business and the wind down of its energy services business in the first quarter 2014. For the first quarter 2014 and the three and six months ended June 30, 2013, it is not practicable to determine what these general overhead costs would have been on a stand-alone basis. All costs directly charged or allocated to us are included in our Consolidated Statements of Income.

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



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
	(Thousands of dollars)
Revenues	$	—	$	91,340	$	53,526	$	173,974
Expenses
Cost of sales and fuel	$	—	$	8,742	$	10,835	$	18,293
Administrative and general expenses	78,705		61,861		155,951		134,357
Total expenses	$	78,705	$	70,603	$	166,786	$	152,650

ONEOK Partners GP made additional general partner contributions to us of approximately $18.3 million and $0.3 million during the six months ended June 30, 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.

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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 and six months ended June 30, 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 (BACT), conduct air-quality and conduct 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. In addition, on June 23, 2014, the Supreme Court of the United States, in a case styled, Utility Air Regulatory Group v. EPA, 530 U.S. (2014), held that an industrial facility’s potential to emit greenhouse gas (GHG) emissions alone cannot subject a facility to the permitting requirements for major stationary source provisions of the Clean Air Act. The decision invalidated the EPA’s current Triggering and Tailoring Rule for GHG Prevention of Significant Deterioration (PSD) and Title V requirements. However, the Court also ruled that to the extent a source pursues a capital project (new construction or expansion of existing facility), which otherwise subjects the source to major source PSD permitting for conventional criteria pollutants, the permitting authorities may impose BACT analysis and emission limits for GHGs from those sources. We are in the process of evaluating the effects the decision may have on our existing operations, and the opportunities it creates for design decisions for new project applications.

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.

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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.

The rule was most recently amended in September 2013, and a further proposed rulemaking was published in July 2014. The EPA has indicated that further amendments may be issued in 2014. Based on the amendments, our understanding of pending stakeholder responses to the NSPS rule and the proposed rulemaking, 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 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.

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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 distributors, ethanol producers and petrochemical, refining and NGL marketing companies. Natural Gas Pipelines segment customers include natural gas distribution, electric-generation, natural gas marketing, industrial and major and independent crude oil and natural gas production companies.

For the three and six months ended June 30, 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	Natural Gas Gathering and Processing			Natural Gas Liquids (a)		Natural Gas Pipelines (b)		Other and Eliminations			Total
June 30, 2014	Natural Gas Gathering and Processing			Natural Gas Liquids (a)		Natural Gas Pipelines (b)		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	374,112		$	2,612,336	$	79,287	$	—		$	3,065,735
Intersegment revenues	349,253			52,974		2,698		(404,925		)	—
Total revenues	$	723,365		$	2,665,310	$	81,985	$	(404,925	)	$	3,065,735
Net margin	$	154,970		$	266,145	$	75,471	$	(2,253	)	$	494,333
Operating costs	59,386			76,081		27,287		(2,109		)	160,645
Depreciation and amortization	29,443			31,109		10,895		—			71,447
Gain (loss) on sale of assets	(28		)	11		—		1			(16		)
Operating income	$	66,113		$	158,966	$	37,289	$	(143	)	$	262,225
Equity earnings from investments	$	5,099		$	4,459	$	15,877	$	—		$	25,435
Capital expenditures	$	168,208		$	210,676	$	8,710	$	1,819		$	389,413

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $153.3 million, of which $135.3 million related to sales within the segment, net margin of $84.4 million and operating income of $34.5 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $68.3 million, net margin of $59.5 million and operating income of $26.1 million.

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Three Months Ended	Natural Gas Gathering and Processing		Natural Gas Liquids (a)			Natural Gas Pipelines (b)		Other and Eliminations			Total
June 30, 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	$	166,709	$	2,461,119		$	49,011	$	—		$	2,676,839
Sales to affiliated customers	66,578		—			24,762		—			91,340
Intersegment revenues	248,972		29,996			1,269		(280,237		)	—
Total revenues	$	482,259	$	2,491,115		$	75,042	$	(280,237	)	$	2,768,179
Net margin	$	125,269	$	219,225		$	67,695	$	(236	)	$	411,953
Operating costs	44,975		54,264			24,985		(248		)	123,976
Depreciation and amortization	25,106		22,302			10,818		—			58,226
Gain (loss) on sale of assets	285		(6		)	—		—			279
Operating income	$	55,473	$	142,653		$	31,892	$	12		$	230,030
Equity earnings from investments	$	5,229	$	5,912		$	15,280	$	—		$	26,421
Capital expenditures	$	206,019	$	269,339		$	6,007	$	3		$	481,368

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $121.6 million, of which $106.5 million related to sales within the segment, net margin of $76.8 million and operating income of $44.3 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $56.1 million, net margin of $52.0 million and operating income of $20.6 million.



Six Months Ended	Natural Gas Gathering and Processing			Natural Gas Liquids (a)			Natural Gas Pipelines (b)			Other and Eliminations			Total
June 30, 2014	Natural Gas Gathering and Processing			Natural Gas Liquids (a)			Natural Gas Pipelines (b)			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	721,128		$	5,282,991		$	170,393		$	—		$	6,174,512
Sales to affiliated customers	41,214			—			12,312			—			53,526
Intersegment revenues	723,148			94,131			4,073			(821,352		)	—
Total revenues	$	1,485,490		$	5,377,122		$	186,778		$	(821,352	)	$	6,228,038
Net margin	$	308,524		$	535,123		$	168,960		$	(8,640	)	$	1,003,967
Operating costs	124,210			141,183			54,749			(9,314		)	310,828
Depreciation and amortization	58,285			58,187			21,710			—			138,182
Gain (loss) on sale of assets	(47		)	(37		)	(83		)	166			(1		)
Operating income	$	125,982		$	335,716		$	92,418		$	840		$	554,956
Equity earnings from investments	$	10,585		$	9,223		$	39,286		$	—		$	59,094
Investments in unconsolidated affiliates	$	329,726		$	485,960		$	396,722		$	—		$	1,212,408
Total assets	$	4,276,593		$	7,363,417		$	1,852,901		$	255,604		$	13,748,515
Noncontrolling interests in consolidated subsidiaries	$	4,493		$	—		$	—		$	15		$	4,508
Capital expenditures	$	291,099		$	483,739		$	15,337		$	2,239		$	792,414

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $289.1 million, of which $246.9 million related to sales within the segment, net margin of $169.1 million and operating income of $79.6 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $149.6 million, net margin of $128.1 million and operating income of $61.2 million.

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Six Months Ended	Natural Gas Gathering and Processing		Natural Gas Liquids (a)		Natural Gas Pipelines (b)		Other and Eliminations			Total
June 30, 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	$	303,954	$	4,699,362	$	108,336	$	—		$	5,111,652
Sales to affiliated customers	122,236		—		51,738		—			173,974
Intersegment revenues	493,583		56,421		997		(551,001		)	—
Total revenues	$	919,773	$	4,755,783	$	161,071	$	(551,001	)	$	5,285,626
Net margin	$	234,554	$	405,845	$	141,767	$	386		$	782,552
Operating costs	96,663		114,066		52,151		(640		)	262,240
Depreciation and amortization	49,010		42,040		21,854		—			112,904
Gain (loss) on sale of assets	313		3		4		—			320
Operating income	$	89,194	$	249,742	$	67,766	$	1,026		$	407,728
Equity earnings from investments	$	11,560	$	9,047	$	31,669	$	—		$	52,276
Investments in unconsolidated affiliates	$	332,458	$	494,964	$	381,365	$	—		$	1,208,787
Total assets	$	3,346,874	$	6,008,574	$	1,792,343	$	32,030		$	11,179,821
Noncontrolling interests in consolidated subsidiaries	$	4,631	$	—	$	—	$	15		$	4,646
Capital expenditures	$	369,967	$	543,504	$	11,349	$	12		$	924,832

(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $229.8 million, of which $191.1 million related to sales within the segment, net margin of $138.3 million and operating income of $75.6 million.

(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $124.5 million, net margin of $109.7 million and operating income of $44.4 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.

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Condensed Consolidating Statements of Income



	Three Months Ended June 30, 2014
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Revenues
Commodity sales	$	—		$	—		$	2,715.1		$	—		$	2,715.1
Services	—			—			350.6			—			350.6
Total revenues	—			—			3,065.7			—			3,065.7
Cost of sales and fuel	—			—			2,571.4			—			2,571.4
Net margin	—			—			494.3			—			494.3
Operating expenses
Operations and maintenance	—			—			142.7			—			142.7
Depreciation and amortization	—			—			71.4			—			71.4
General taxes	—			—			18.0			—			18.0
Total operating expenses	—			—			232.1			—			232.1
Gain (loss) on sale of assets	—			—			—			—			—
Operating income	—			—			262.2			—			262.2
Equity earnings from investments	214.4			214.4			9.6			(413.0		)	25.4
Allowance for equity funds used during construction	—			—			1.3			—			1.3
Other income (expense), net	83.1			83.1			1.8			(166.2		)	1.8
Interest expense, net	(83.1		)	(83.1		)	(73.0		)	166.2			(73.0		)
Income before income taxes	214.4			214.4			201.9			(413.0		)	217.7
Income taxes	—			—			(3.2		)	—			(3.2		)
Net income	214.4			214.4			198.7			(413.0		)	214.5
Less: Net income attributable to noncontrolling interests	—			—			0.1			—			0.1
Net income attributable to ONEOK Partners, L.P.	$	214.4		$	214.4		$	198.6		$	(413.0	)	$	214.4



	Three Months Ended June 30, 2013
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Revenues
Commodity sales	$	—		$	—		$	2,447.4		$	—		$	2,447.4
Services	—			—			320.8			—			320.8
Total revenues	—			—			2,768.2			—			2,768.2
Cost of sales and fuel	—			—			2,356.2			—			2,356.2
Net margin	—			—			412.0			—			412.0
Operating expenses
Operations and maintenance	—			—			108.1			—			108.1
Depreciation and amortization	—			—			58.2			—			58.2
General taxes	—			—			15.9			—			15.9
Total operating expenses	—			—			182.2			—			182.2
Gain (loss) on sale of assets	—			—			0.2			—			0.2
Operating income	—			—			230.0			—			230.0
Equity earnings from investments	202.4			202.4			11.1			(389.5		)	26.4
Allowance for equity funds used during construction	—			—			5.7			—			5.7
Other income (expense), net	67.5			67.5			0.4			(135.0		)	0.4
Interest expense, net	(67.5		)	(67.5		)	(57.5		)	135.0			(57.5		)
Income before income taxes	202.4			202.4			189.7			(389.5		)	205.0
Income taxes	—			—			(2.5		)	—			(2.5		)
Net income	202.4			202.4			187.2			(389.5		)	202.5
Less: Net income attributable to noncontrolling interests	—			—			0.1			—			0.1
Net income attributable to ONEOK Partners, L.P.	$	202.4		$	202.4		$	187.1		$	(389.5	)	$	202.4

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	Six Months Ended June 30, 2014
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Revenues
Commodity sales	$	—		$	—		$	5,521.8		$	—		$	5,521.8
Services	—			—			706.2			—			706.2
Total revenues	—			—			6,228.0			—			6,228.0
Cost of sales and fuel	—			—			5,224.0			—			5,224.0
Net margin	—			—			1,004.0			—			1,004.0
Operating expenses
Operations and maintenance	—			—			273.2			—			273.2
Depreciation and amortization	—			—			138.2			—			138.2
General taxes	—			—			37.6			—			37.6
Total operating expenses	—			—			449.0			—			449.0
Gain (loss) on sale of assets	—			—			—			—			—
Operating income	—			—			555.0			—			555.0
Equity earnings from investments	479.8			479.8			19.8			(920.3		)	59.1
Allowance for equity funds used during construction	—			—			12.2			—			12.2
Other income (expense), net	165.8			165.8			2.4			(331.6		)	2.4
Interest expense, net	(165.8		)	(165.8		)	(141.3		)	331.6			(141.3		)
Income before income taxes	479.8			479.8			448.1			(920.3		)	487.4
Income taxes	—			—			(7.4		)	—			(7.4		)
Net income	479.8			479.8			440.7			(920.3		)	480.0
Less: Net income attributable to noncontrolling interests	—			—			0.2			—			0.2
Net income attributable to ONEOK Partners, L.P.	$	479.8		$	479.8		$	440.5		$	(920.3	)	$	479.8



	Six Months Ended June 30, 2013
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Revenues
Commodity sales	$	—		$	—		$	4,646.2		$	—		$	4,646.2
Services	—			—			639.4			—			639.4
Total revenues	—			—			5,285.6			—			5,285.6
Cost of sales and fuel	—			—			4,503.0			—			4,503.0
Net margin	—			—			782.6			—			782.6
Operating expenses
Operations and maintenance	—			—			229.4			—			229.4
Depreciation and amortization	—			—			112.9			—			112.9
General taxes	—			—			32.8			—			32.8
Total operating expenses	—			—			375.1			—			375.1
Gain (loss) on sale of assets	—			—			0.2			—			0.2
Operating income	—			—			407.7			—			407.7
Equity earnings from investments	359.0			359.0			20.6			(686.3		)	52.3
Allowance for equity funds used during construction	—			—			14.8			—			14.8
Other income (expense), net	134.5			134.5			2.6			(269.0		)	2.6
Interest expense, net	(134.5		)	(134.5		)	(113.4		)	269.0			(113.4		)
Income before income taxes	359.0			359.0			332.3			(686.3		)	364.0
Income taxes	—			—			(4.9		)	—			(4.9		)
Net income	359.0			359.0			327.4			(686.3		)	359.1
Less: Net income attributable to noncontrolling interests	—			—			0.1			—			0.1
Net income attributable to ONEOK Partners, L.P.	$	359.0		$	359.0		$	327.3		$	(686.3	)	$	359.0

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Condensed Consolidating Statements of Comprehensive Income



	Three Months Ended June 30, 2014
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Net income	$	214.4		$	214.4		$	198.7		$	(413.0	)	$	214.5
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	(32.5		)	(6.1		)	(6.1		)	12.2			(32.5		)
Realized (gains) losses on derivatives recognized in net income	7.8			5.2			5.2			(10.4		)	7.8
Total other comprehensive income (loss)	(24.7		)	(0.9		)	(0.9		)	1.8			(24.7		)
Comprehensive income	189.7			213.5			197.8			(411.2		)	189.8
Less: Comprehensive income attributable to noncontrolling interests	—			—			0.1			—			0.1
Comprehensive income attributable to ONEOK Partners, L.P.	$	189.7		$	213.5		$	197.7		$	(411.2	)	$	189.7



	Three Months Ended June 30, 2013
(Unaudited)	Parent		Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Net income	$	202.4	$	202.4		$	187.2		$	(389.5	)	$	202.5
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	55.4		33.1			33.1			(66.2		)	55.4
Realized (gains) losses on derivatives recognized in net income	1.3		(1.2		)	(1.2		)	2.4			1.3
Total other comprehensive income (loss)	56.7		31.9			31.9			(63.8		)	56.7
Comprehensive income	259.1		234.3			219.1			(453.3		)	259.2
Less: Comprehensive income attributable to noncontrolling interests	—		—			0.1			—			0.1
Comprehensive income attributable to ONEOK Partners, L.P.	$	259.1	$	234.3		$	219.0		$	(453.3	)	$	259.1

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	Six Months Ended June 30, 2014
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Net income	$	479.8		$	479.8		$	440.7		$	(920.3	)	$	480.0
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	(89.0		)	(41.9		)	(41.9		)	83.8			(89.0		)
Realized (gains) losses on derivatives recognized in net income	36.9			31.6			31.6			(63.2		)	36.9
Total other comprehensive income (loss)	(52.1		)	(10.3		)	(10.3		)	20.6			(52.1		)
Comprehensive income	427.7			469.5			430.4			(899.7		)	427.9
Less: Comprehensive income attributable to noncontrolling interests	—			—			0.2			—			0.2
Comprehensive income attributable to ONEOK Partners, L.P.	$	427.7		$	469.5		$	430.2		$	(899.7	)	$	427.7



	Six Months Ended June 30, 2013
(Unaudited)	Parent		Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Net income	$	359.0	$	359.0		$	327.4		$	(686.3	)	$	359.1
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives	42.4		13.4			13.4			(26.8		)	42.4
Realized (gains) losses on derivatives recognized in net income	1.1		(3.8		)	(3.8		)	7.6			1.1
Total other comprehensive income (loss)	43.5		9.6			9.6			(19.2		)	43.5
Comprehensive income	402.5		368.6			337.0			(705.5		)	402.6
Less: Comprehensive income attributable to noncontrolling interests	—		—			0.1			—			0.1
Comprehensive income attributable to ONEOK Partners, L.P.	$	402.5	$	368.6		$	336.9		$	(705.5	)	$	402.5

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Condensed Consolidating Balance Sheets



	June 30, 2014
(Unaudited)	Parent		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidating Entries			Total
Assets	(Millions of dollars)
Current assets
Cash and cash equivalents	$	—	$	278.0	$	—	$	—		$	278.0
Accounts receivable, net	—		—		1,077.5		—			1,077.5
Affiliate receivables	—		—		8.3		—			8.3
Natural gas and natural gas liquids in storage	—		—		335.1		—			335.1
Commodity imbalances	—		—		93.1		—			93.1
Other current assets	2.8		—		89.6		—			92.4
Total current assets	2.8		278.0		1,603.6		—			1,884.4
Property, plant and equipment
Property, plant and equipment	—		—		11,516.9		—			11,516.9
Accumulated depreciation and amortization	—		—		1,774.8		—			1,774.8
Net property, plant and equipment	—		—		9,742.1		—			9,742.1
Investments and other assets
Investments in unconsolidated affiliates	4,312.9		5,075.3		816.4		(8,992.2		)	1,212.4
Intercompany notes receivable	7,601.2		6,560.8		—		(14,162.0		)	—
Goodwill and intangible assets	—		—		826.3		—			826.3
Other assets	62.8		—		20.5		—			83.3
Total investments and other assets	11,976.9		11,636.1		1,663.2		(23,154.2		)	2,122.0
Total assets	$	11,979.7	$	11,914.1	$	13,008.9	$	(23,154.2	)	$	13,748.5
Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	—	$	—	$	7.7	$	—		$	7.7
Accounts payable	—		—		1,260.3		—			1,260.3
Affiliate payables	—		—		39.7		—			39.7
Commodity imbalances	—		—		207.5		—			207.5
Accrued interest	92.2		—		—		—			92.2
Other current liabilities	19.2		—		123.8		—			143.0
Total current liabilities	111.4		—		1,639.0		—			1,750.4
Intercompany debt	—		7,601.2		6,560.8		(14,162.0		)	—
Long-term debt, excluding current maturities	5,985.9		—		55.7		—			6,041.6
Deferred credits and other liabilities	—		—		129.6		—			129.6
Commitments and contingencies
Equity
Equity excluding noncontrolling interests in consolidated subsidiaries	5,882.4		4,312.9		4,619.3		(8,992.2		)	5,822.4
Noncontrolling interests in consolidated subsidiaries	—		—		4.5		—			4.5
Total equity	5,882.4		4,312.9		4,623.8		(8,992.2		)	5,826.9
Total liabilities and equity	$	11,979.7	$	11,914.1	$	13,008.9	$	(23,154.2	)	$	13,748.5

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	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

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Condensed Consolidating Statements of Cash Flows



	Six Months Ended June 30, 2014
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Operating activities
Cash provided by operating activities	$	505.3		$	39.3		$	482.6		$	(493.1	)	$	534.1
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	—			—			(792.4		)	—			(792.4		)
Acquisition	—			—			(14.0		)	—			(14.0		)
Contributions to unconsolidated affiliates	—			—			(1.1		)	—			(1.1		)
Distributions received from unconsolidated affiliates	—			8.1			8.4			—			16.5
Proceeds from sale of assets	—			—			0.3			—			0.3
Cash provided by (used in) investing activities	—			8.1			(798.8		)	—			(790.7		)
Financing activities
Cash distributions:
General and limited partners	(493.1		)	(493.1		)	—			493.1			(493.1		)
Noncontrolling interests	—			—			(0.2		)	—			(0.2		)
Borrowing of notes payable, net	—			—			—			—			—
Intercompany borrowings (advances), net	(909.4		)	589.2			320.2			—			—
Repayment of long-term debt	—			—			(3.8		)	—			(3.8		)
Issuance of common units, net of issuance costs	878.8			—			—			—			878.8
Contribution from general partner	18.4			—			—			—			18.4
Cash provided by (used in) financing activities	(505.3		)	96.1			316.2			493.1			400.1
Change in cash and cash equivalents	—			143.5			—			—			143.5
Cash and cash equivalents at beginning of period	—			134.5			—			—			134.5
Cash and cash equivalents at end of period	$	—		$	278.0		$	—		$	—		$	278.0

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	Six Months Ended June 30, 2013
(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Operating activities
Cash provided by operating activities	$	417.0		$	31.7		$	379.0		$	(444.3	)	$	383.4
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	—			—			(924.8		)	—			(924.8		)
Contributions to unconsolidated affiliates	—			—			(4.6		)	—			(4.6		)
Distributions received from unconsolidated affiliates	—			12.0			6.0			—			18.0
Proceeds from sale of assets	—			—			0.3			—			0.3
Cash provided by (used in) investing activities	—			12.0			(923.1		)	—			(911.1		)
Financing activities
Cash distributions:
General and limited partners	(444.3		)	(444.3		)	—			444.3			(444.3		)
Noncontrolling interests	—			—			(0.3		)	—			(0.3		)
Borrowings of notes payable, net	429.0			—			—			—			429.0
Intercompany borrowings (advances), net	(417.9		)	(130.3		)	548.2			—			—
Repayment of long-term debt	—			—			(3.8		)	—			(3.8		)
Issuance of common units, net of issuance costs	15.9			—			—			—			15.9
Contribution from general partner	0.3			—			—			—			0.3
Cash provided by (used in) financing activities	(417.0		)	(574.6		)	544.1			444.3			(3.2		)
Change in cash and cash equivalents	—			(530.9		)	—			—			(530.9		)
Cash and cash equivalents at beginning of period	—			537.1			—			—			537.1
Cash and cash equivalents at end of period	$	—		$	6.2		$	—		$	—		$	6.2

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

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

RECENT DEVELOPMENTS

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 shale and other nonconventional resource 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. Natural gas prices were favorable to ethane prices on a Btu basis, which 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 six months of 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 demand 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 constructed by third parties are expected to bring incremental NGL supply from the Rocky Mountain, Marcellus and Utica regions to the Mont Belvieu, Texas, market center that may affect NGL prices, as well as compete with or displace NGL supply volumes from the Mid-Continent and Rocky Mountain regions where our assets are located. Our Natural Gas Liquids segment’s capital 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, Mississippian Lime and SCOOP 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 $7.0 billion to $7.5 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 strategy to grow fee-based earnings. Our acreage dedications and supply

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commitments 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.

Transactions with Affiliates - For the three months ended March 31, 2014 and the three and six months ended June 30, 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. Prior to March 31, 2014, 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. Beginning in the second quarter 2014, we enter into all 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 own limited partners units, which together at June 30, 2014, represented a 38.5 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						Six Months Ended						Three Months					Six Months
	June 30,						June 30,						2014 vs. 2013					2014 vs. 2013
Financial Results	2014			2013			2014			2013			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Commodity sales	$	2,715.1		$	2,447.4		$	5,521.8		$	4,646.2		$	267.7		11	%	$	875.6		19	%
Services	350.6			320.8			706.2			639.4			29.8			9	%	66.8			10	%
Total revenues	3,065.7			2,768.2			6,228.0			5,285.6			297.5			11	%	942.4			18	%
Cost of sales and fuel	2,571.4			2,356.2			5,224.0			4,503.0			215.2			9	%	721.0			16	%
Net margin	494.3			412.0			1,004.0			782.6			82.3			20	%	221.4			28	%
Operating costs	160.7			124.0			310.8			262.3			36.7			30	%	48.5			18	%
Depreciation and amortization	71.4			58.2			138.2			112.9			13.2			23	%	25.3			22	%
Gain (loss) on sale of assets	—			0.2			—			0.3			(0.2		)	(100	%)	(0.3		)	(100	%)
Operating income	$	262.2		$	230.0		$	555.0		$	407.7		$	32.2		14	%	$	147.3		36	%
Equity earnings from investments	$	25.4		$	26.4		$	59.1		$	52.3		$	(1.0	)	(4	%)	$	6.8		13	%
Interest expense	$	(73.0	)	$	(57.5	)	$	(141.3	)	$	(113.4	)	$	15.5		27	%	$	27.9		25	%
Capital expenditures	$	389.4		$	481.4		$	792.4		$	924.8		$	(92.0	)	(19	%)	$	(132.4	)	(14	%)

Commodity sales revenues increased for the three and six months ended June 30, 2014, compared with the same periods in 2013, due to higher natural gas and NGL volumes from our recently completed capital projects, wider NGL product price differentials and higher realized prices in our Natural Gas Gathering and Processing and Natural Gas Liquids segments. In addition, the six months ended June 30, 2014, benefited from wider location price differentials experienced in the first quarter 2014 related primarily to propane due to lower propane inventory levels from crop drying and increased heating demand due to

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colder than normal weather in late 2013 that continued into the first quarter 2014 in the Mid-Continent region in our Natural Gas Liquids segment.

Services revenues increased for the three and six months ended June 30, 2014, compared with the same periods in 2013, 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, volumes and park-and-loan services as a result of weather-related seasonal demand in our Natural Gas Pipelines segment. These increases were offset partially by lower operational measurement gains in our Natural Gas Liquids segment and lower storage revenues from lower contracted capacity in our Natural Gas Pipelines segment.

Operating costs and depreciation and amortization increased for the three and six months ended June 30, 2014, compared with the same periods in 2013, due primarily to the growth of our operations related to our completed capital projects.

Equity earnings from investments increased for the six months ended June 30, 2014, compared with the same period in 2013, due to increased park-and-loan services on Northern Border Pipeline in the first quarter 2014 as a result of weather-related seasonal demand and higher volumes on Overland Pass Pipeline delivered from our Bakken NGL Pipeline as a result of increased volumes from our recently completed capital projects, offset partially by increased ethane rejection and higher operating costs.

Interest expense increased for the three and six months ended June 30, 2014, compared with the same periods 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 and six months ended June 30, 2014, compared with the same periods 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, SCOOP 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.

The significant growth in the development of crude oil and NGL-rich natural gas in the Williston Basin has caused natural gas production to exceed the capacity of existing natural gas gathering and processing infrastructure, which results in the flaring of natural gas (the controlled burning of natural gas at the wellhead). In July 2014, the North Dakota Industrial Commission approved a policy designed to limit flaring at existing and future crude oil wells in the Bakken and Three Forks formations in the Williston Basin. The policy establishes crude oil production limits that will take effect if a producer fails to meet requirements to capture natural gas at the wellhead. We are constructing additional natural gas gathering pipelines, compression and processing plants and natural gas liquids pipeline capacity that are expected to help alleviate capacity constraints. We are evaluating the potential impact the new regulation might have on future crude oil and natural gas production and the natural gas volumes we gather and process in the Williston Basin.

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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 $3.8 billion to $4.3 billion from 2010 through 2016 in growth projects in NGL-rich areas in the Williston Basin, the Powder River Basin, the Cana-Woodford Shale and the SCOOP areas that we expect will enable us to meet the rapidly growing needs of crude oil and natural gas producers in those areas. Nearly all of the new natural gas production is from horizontally drilled and completed wells in 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.

We have completed approximately $1.6 billion in growth projects and acquisitions in this segment through July 2014, which include the following:



Completed Project	Location	Capacity	Approximate Costs (a)	Completion Date
			(In millions)
Rocky Mountain Region
Garden Creek processing plant and infrastructure	Williston Basin	100 MMcf/d	$360	December 2011
Stateline I & II processing plants and infrastructure	Williston Basin	200 MMcf/d	$565	September 2012/April 2013
Divide County gathering system	Williston Basin	270 miles	$125	June 2013
Sage Creek processing plant and infrastructure (b)	Powder River Basin	50 MMcf/d	$152	September 2013
30 percent interest in Maysville processing plant (b)	Cana-Woodford Shale	40 MMcf/d	$90	December 2013
Mid-Continent Region
Canadian Valley processing plant and infrastructure	Cana-Woodford Shale	200 MMcf/d	$300	March 2014

(a) Excludes AFUDC.

(b) Acquisition.

We are also constructing or plan to construct the following natural gas processing plants and related infrastructure through 2016:



Projects in Progress	Location	Capacity	Approximate Costs (a)	Expected Completion Date
			(In millions)
Rocky Mountain Region
Garden Creek II processing plant and infrastructure	Williston Basin	100 MMcf/d	$310-$345	Third quarter 2014
Garden Creek III processing plant and infrastructure	Williston Basin	100 MMcf/d	$325-$360	Fourth quarter 2014
Lonesome Creek processing plant and infrastructure	Williston Basin	200 MMcf/d	$550-$680	Fourth quarter 2015
Sage Creek infrastructure	Powder River Basin	n/a	$50	Fourth quarter 2015
Natural gas compression	Williston Basin	100 MMcf/d	$80-$100	Fourth quarter 2015
Demicks Lake processing plant and infrastructure	Williston Basin	200 MMcf/d	$515-$670	Third quarter 2016
Mid-Continent Region
Knox processing plant and infrastructure	SCOOP	200 MMcf/d	$365-$470	Fourth quarter 2016

(a) Excludes AFUDC.

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Rocky Mountain Region:

Williston Basin Processing Plants and related projects - We are constructing natural gas gathering and processing assets in the Williston Basin to meet the growing needs of crude oil and natural gas producers. When our announced projects are completed, we will have natural gas processing capacity of approximately 1.1 Bcf/d in the basin. We have acreage dedications of approximately 3 million acres supporting these projects.

Garden Creek II and III Plants - The Garden Creek II plant is expected to be completed during the third quarter 2014. The Garden Creek III plant, originally scheduled for completion in the first quarter 2015, is now scheduled for completion in the fourth quarter 2014.

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

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

Demicks Lake - In July 2014, we announced we will construct the Demicks Lake natural gas processing plant and related infrastructure, which will be located in northeast McKenzie County, North Dakota, to help further address natural gas gathering and processing constraints in the region.

Powder River Basin - On September 30, 2013, we completed the acquisition of a 50 MMcf/d natural gas processing facility, the Sage Creek plant, and related natural gas gathering and natural gas liquids infrastructure. We plan to upgrade existing natural gas processing infrastructure and construct new natural gas gathering infrastructure to meet the growing production of NGL-rich natural gas in this area. We have supply contracts providing for long-term acreage dedications from producers in the area supporting this project.

Mid-Continent Region:

Cana-Woodford Shale and SCOOP areas - We are constructing natural gas gathering and processing assets to meet the growing production of NGL-rich natural gas in the Cana-Woodford Shale and SCOOP areas. In March 2014, we completed the Canadian Valley natural gas processing plant, which is located in the Cana-Woodford Shale. When our announced projects are completed, our Oklahoma natural gas processing capacity will be approximately 900 MMcf/d. We have substantial acreage dedications from crude oil and natural gas producers supporting these plants.

Knox Plant - In July 2014, we announced we will construct the Knox natural gas processing plant and related infrastructure, which will be located in Grady and Stephens Counties, Oklahoma. The plant and related infrastructure will gather and process liquids-rich natural gas from the emerging SCOOP area and will be located in close proximity to our existing natural gas and natural gas liquids pipelines.

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 and six months ended June 30, 2014, reflect the benefits from the Canadian Valley natural gas processing plant, which was completed in March 2014; the acquisition of the Sage Creek natural gas processing plant in Wyoming in September 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. Additionally, operating results for the six months ended June 30, 2014, reflect the benefits of the Stateline II natural gas processing plant, which was placed in service in April 2013.

The completion of the Stateline II and Canadian Valley natural gas processing plants resulted in increased natural gas volumes gathered and processed in the Williston Basin and Oklahoma, respectively. 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, Granite Wash and SCOOP areas in Oklahoma and Texas.

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



	Three Months Ended				Six Months Ended				Three Months					Six Months
	June 30,				June 30,				2014 vs. 2013					2014 vs. 2013
Financial Results	2014		2013		2014		2013		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
NGL sales	$	354.8	$	230.6	$	734.7	$	464.0	$	124.2		54	%	$	270.7		58	%
Condensate sales	28.5		33.9		57.5		60.9		(5.4		)	(16	%)	(3.4		)	(6	%)
Residue natural gas sales	275.3		162.3		565.4		289.8		113.0			70	%	275.6			95	%
Gathering, compression, dehydration and processing fees and other revenue	64.7		55.5		127.9		105.1		9.2			17	%	22.8			22	%
Cost of sales and fuel	568.4		357.0		1,177.0		685.2		211.4			59	%	491.8			72	%
Net margin	154.9		125.3		308.5		234.6		29.6			24	%	73.9			32	%
Operating costs	59.4		45.0		124.2		96.7		14.4			32	%	27.5			28	%
Depreciation and amortization	29.4		25.1		58.3		49.0		4.3			17	%	9.3			19	%
Gain on sale of assets	—		0.3		—		0.3		(0.3		)	(100	%)	(0.3		)	(100	%)
Operating income	$	66.1	$	55.5	$	126.0	$	89.2	$	10.6		19	%	$	36.8		41	%
Equity earnings from investments	$	5.1	$	5.2	$	10.6	$	11.6	$	(0.1	)	(2	%)	$	(1.0	)	(9	%)
Capital expenditures	$	168.2	$	206.0	$	291.1	$	370.0	$	(37.8	)	(18	%)	$	(78.9	)	(21	%)

Net margin increased for the three months ended June 30, 2014, compared with the same period in 2013, primarily as a result of the following:


•	an increase of $24.6 million due primarily to natural gas volume growth in the Williston Basin and Cana-Woodford Shale and increased ownership of the Maysville, Oklahoma, natural gas processing plant resulting in higher natural gas volumes gathered, compressed, processed, transported and sold, and higher NGL volumes sold;


•	an increase of $8.1 million due primarily to higher net realized prices; and


•	an increase of $3.4 million due primarily to changes in contract mix; offset partially by


•	a decrease of $6.4 million due to a condensate contract settlement in 2013.

Net margin increased for the six months ended June 30, 2014, compared with the same period in 2013, primarily as a result of the following:

•

an increase of $61.4 million due primarily to natural gas volume growth in the Williston Basin and Cana-Woodford Shale and increased ownership of the Maysville, Oklahoma, natural gas processing plant resulting in higher natural gas volumes gathered, compressed, processed, transported and sold, higher NGL volumes sold, and higher fees, offset partially by wellhead freeze-offs due to severely cold weather in the first quarter 2014;


•	an increase of $13.9 million due primarily to higher net realized prices; and


•	an increase of $5.1 million due primarily to changes in contract mix; offset partially by


•	a decrease of $6.4 million due to a condensate contract settlement in 2013.

Operating costs increased for the three and six months ended June 30, 2014, compared with the same periods in 2013, primarily as a result of the completion of our growth projects and acquisitions, which include the following:


•	an increase of $9.4 million and $21.4 million, respectively, due to higher materials and supplies, and outside services expenses; and


•	an increase of $7.6 million and $8.8 million, respectively, in employee-related costs due to higher labor and employee benefit costs; offset partially by


•	a decrease of $2.6 million and $2.7 million, respectively, due to the timing of ad valorem tax estimates in 2014.

Depreciation and amortization expense increased for the three and six months ended June 30, 2014, compared with the same periods in 2013, due to the completion of growth projects and acquisitions.

Capital expenditures decreased for the three and six months ended June 30, 2014, compared with the same periods in 2013, due primarily to the timing of expenditures for our growth projects discussed above. During the second quarter 2014, we connected approximately 360 new wells to our systems compared with approximately 350 in the same period in 2013. For the six months

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ended June 30, 2014, we connected approximately 590 wells to our system compared with approximately 600 in the same period in 2013. The decrease for the six-month period was due to much colder than normal weather, which impacted construction activities in the Williston Basin in the first quarter 2014.

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				Six Months Ended
	June 30,				June 30,
Operating Information (a)	2014		2013		2014		2013
Natural gas gathered (BBtu/d)	1,646		1,326		1,573		1,271
Natural gas processed (BBtu/d) (b)	1,447		1,055		1,358		1,022
NGL sales (MBbl/d)	98		75		94		73
Residue natural gas sales (BBtu/d)	683		467		626		451
Realized composite NGL net sales price ($/gallon) (c)	$	0.96	$	0.85	$	1.00	$	0.85
Realized condensate net sales price ($/Bbl) (c)	$	77.46	$	83.86	$	76.80	$	86.06
Realized residue gas net sales price ($/MMBtu) (c)	$	4.07	$	3.57	$	3.85	$	3.55
Average fee rate ($/MMBtu)	$	0.34	$	0.34	$	0.36	$	0.35

(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 and six months ended June 30, 2014, compared with the same periods in 2013, due to new processing plants placed in service 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 and six months ended June 30, 2014, compared with the same periods in 2013, due primarily to higher prices from increased demand associated with colder than normal weather and lower propane storage levels in the first quarter 2014.

The quantity and composition of NGLs and natural gas continue to change as our new natural gas processing plants in the Williston Basin and Mid-Continent are placed in service. In March 2014, our Canadian Valley plant in Oklahoma was completed, which has better ethane rejection capabilities than our other processing plants in the Mid-Continent region. Our Garden Creek, Stateline I and Stateline II plants in the Williston Basin have the capability to recover ethane when economic conditions warrant but did not do so during the first six months of 2014. Our equity NGL volumes also are expected to be weighted more toward propane, iso-butane, normal butane and natural gasoline due to expected ethane rejection through much of 2016.



	Three Months Ended		Six Months Ended
	June 30,		June 30,
Equity Volume Information (a)	2014	2013	2014	2013

NGL sales (MBbl/d)	15.9	13.9	16.8	13.4
Condensate sales (MBbl/d)	3.1	2.5	3.3	2.6
Residue natural gas sales (BBtu/d)	105.3	68.8	96.9	63.1

(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:



	Six Months Ending December 31, 2014
	Volumes Hedged	Average Price			Percentage Hedged
NGLs (MBbl/d)	11.1	$	1.17	/ gallon	57%
Condensate (MBbl/d)	2.5	$	2.22	/ gallon	73%
Total (MBbl/d)	13.6	$	1.36	/ gallon	60%
Natural gas (BBtu/d)	89.2	$	4.06	/ MMBtu	76%

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	Year Ending December 31, 2015
	Volumes Hedged	Average Price			Percentage Hedged
NGLs (MBbl/d)	1.2	$	1.07	/ gallon	7%
Natural gas (BBtu/d)	61.3	$	4.34	/ MMBtu	44%

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 June 30, 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 $2.7 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 $4.6 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 dry natural gas assets and equity investments in this area and could result in noncash charges to earnings.

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

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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 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, Sterling III 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.

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 constructed by third parties are expected to bring incremental NGL supply from the Rocky Mountain, Marcellus and Utica regions to the Mont Belvieu, Texas, market center that may affect NGL prices, as well as compete with or displace NGL supply volumes from the Mid-Continent and Rocky Mountain regions where our assets are located. Our Natural Gas Liquids segment’s capital growth projects are 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.

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 $3.2 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.

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We have completed approximately $2.2 billion in growth projects in this segment through July 2014, which include the following:



Completed Project	Capacity	Approximate Costs	Completion Date
		(In millions)
Sterling I expansion	15 MBbl/d	$30	November 2011
Cana-Woodford/Granite Wash NGL plant connections	60 MBbl/d	$220	April 2012
Bushton fractionator expansion	60 MBbl/d	$117	September 2012
Bakken NGL Pipeline	60 MBbl/d	$455	April 2013
Overland Pass Pipeline expansion	45 MBbl/d	$36	April 2013
Ethane Header pipeline	250 MBbl/d	$23	April 2013
Sage Creek NGL infrastructure (a)	n/a	$153	September 2013
MB-2 Fractionator	75 MBbl/d	$375	December 2013
Ethane/Propane Splitter	40 MBbl/d	$46	March 2014
Sterling III Pipeline and reconfigure Sterling I and II	193 MBbl/d	$767	March 2014

(a) Acquisition

We are also constructing, or plan to construct, the following projects through 2016:



Projects in Progress	Capacity	Approximate Costs	Completion Date
		(In millions)
Bakken NGL Pipeline expansion - Phase I	75 MBbl/d	$100	Third quarter 2014
MB-3 Fractionator	75 MBbl/d	$525-$575	Fourth quarter 2014
Sage Creek NGL infrastructure expansion	90 miles	$85	Fourth quarter 2014
NGL pipeline and Hutchinson Fractionator infrastructure	95 miles	$140	First quarter 2015
Bakken NGL Pipeline expansion - Phase II	25 MBbl/d	$100	Second quarter 2016
Demicks Lake infrastructure	12 miles	$10-$15	Fourth quarter 2016

Sterling III Pipeline - In March 2014, we completed a 550-mile natural gas liquids pipeline, which has the flexibility to transport either unfractionated NGLs or NGL products from the Mid-Continent to the Gulf Coast. The pipeline is designed to transport up to 193 MBbl/d of NGL production from Medford, Oklahoma, to our storage and fractionation facilities in Mont Belvieu, Texas. We have multi-year 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. This project also included the reconfiguration of our existing Sterling I and Sterling II pipelines to transport either unfractionated NGLs or NGL products. The reconfiguration was completed in July 2014.

Ethane/Propane Splitter - In March 2014, we placed in service an 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 is capable of producing 32 MBbl/d of purity ethane and 8 MBbl/d of propane.

Bakken NGL Pipeline expansions - The first expansion increases the pipeline’s capacity to 135 MBbl/d from the original capacity of 60 MBbl/d, with the second expansion bringing the pipeline’s capacity to 160 MBbl/d. These expansions will accommodate the growing NGL supply from the Williston and Powder River Basins.

MB-3 Fractionator - We are constructing the MB-3 fractionator 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 our Arbuckle and Sterling II natural gas liquids pipelines. We have multi-year supply commitments from producers and natural gas processors for approximately 80 percent of the fractionator’s capacity.

Sage Creek related infrastructure - We are constructing new natural gas liquids pipeline infrastructure to connect the Sage Creek natural gas processing plant to our Bakken NGL Pipeline.

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New natural gas liquids pipeline and modification of Hutchinson fractionation infrastructure - We are constructing 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. The project also includes modifications to existing natural gas liquids fractionation infrastructure at Hutchinson, Kansas, to accommodate additional unfractionated NGLs produced in the Williston Basin.

Demicks Lake natural gas liquids infrastructure - We announced in July 2014 our plan to build new natural gas liquids pipeline infrastructure to connect the Demicks Lake natural gas processing plant to our Bakken NGL Pipeline.

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

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



	Three Months Ended				Six Months Ended				Three months					Six Months
	June 30,				June 30,				2014 vs. 2013					2014 vs. 2013
Financial Results	2014		2013		2014		2013		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	2,405.0	$	2,267.7	$	4,890.8	$	4,317.7	$	137.3		6	%	$	573.1		13	%
Exchange service and storage revenues	243.3		209.0		445.9		401.3		34.3			16	%	44.6			11	%
Transportation revenues	17.0		14.4		40.4		36.8		2.6			18	%	3.6			10	%
Cost of sales and fuel	2,399.2		2,271.9		4,842.0		4,350.0		127.3			6	%	492.0			11	%
Net margin	266.1		219.2		535.1		405.8		46.9			21	%	129.3			32	%
Operating costs	76.0		54.2		141.2		114.1		21.8			40	%	27.1			24	%
Depreciation and amortization	31.1		22.3		58.2		42.0		8.8			39	%	16.2			39	%
Operating income	$	159.0	$	142.7	$	335.7	$	249.7	$	16.3		11	%	$	86.0		34	%
Equity earnings from investments	$	4.5	$	5.9	$	9.2	$	9.0	$	(1.4	)	(24	%)	$	0.2		2	%
Capital expenditures	$	210.7	$	269.3	$	483.7	$	543.5	$	(58.6	)	(22	%)	$	(59.8	)	(11	%)

Several factors contributed to increased propane demand and price in the first quarter 2014, which impacted our results of operations for the six-months ended 2014. 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 second quarter 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 during the first quarter 2014. Severely cold weather in the first quarter 2014 caused wellhead freeze-offs, which also reduced volumes.

Net margin increased for the three months ended June 30, 2014, compared with the same period in 2013, primarily as a result of the following:


•	an increase of $31.4 million in exchange-services margins, which resulted primarily from higher NGL volumes delivered from the Bakken NGL Pipeline, volumes from new plants connected in the Mid-Continent region, and higher fees for exchange-services activities resulting from contract renegotiations, offset partially by lower volumes from the termination of a contract;


•	an increase of $17.3 million related to higher isomerization volumes, resulting from the wider NGL product price differential between normal butane and iso-butane; and


•	an increase of $1.3 million in storage margins due primarily to contract renegotiations; offset partially by


•	a decrease of $2.7 million due to the impact of lower operational measurement gains.


•	Optimization and marketing margins were relatively unchanged, primarily due to a $12.5 million decrease from

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narrower NGL location price differentials and lower volumes, offset partially by an $8.0 million increase due primarily to wider NGL product price differentials; and a $4.4 million increase in marketing margins.

Net margin increased for the six months ended June 30, 2014, compared with the same period in 2013, primarily as a result of the following:

•

an increase of $72.4 million in optimization and marketing margins, which resulted from a $28.2 million increase due primarily to significantly wider NGL location price differentials, primarily related to increased weather-related seasonal demand for propane during the first quarter 2014; a $26.2 million increase due primarily to wider NGL product price differentials; and a $18.0 million increase in marketing margins related primarily to increased weather-related seasonal demand for propane during the first quarter 2014;


•	an increase of $39.4 million in exchange-services margins, which resulted primarily from higher NGL volumes delivered from the Bakken NGL Pipeline, volumes from new plants connected in the Mid-Continent region, and higher fees for exchange-services activities resulting from contract renegotiations, offset partially by lower volumes from the termination of a contract;


•	an increase of $20.6 million related to higher isomerization volumes, resulting from the wider NGL product price differential between normal butane and iso-butane; and


•	an increase of $4.7 million in storage margins due primarily to contract renegotiations; offset partially by


•	a decrease of $4.1 million due to the impact of lower operational measurement gains, and


•	a decrease of $3.8 million resulting from the impact of ethane rejection, which resulted in lower NGL volumes.

Operating costs increased for the three months ended June 30, 2014, compared with the same period in 2013, primarily as a result of the following:


•	an increase of $8.7 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 $4.5 million due to higher ad valorem taxes related to completed capital projects; and


•	an increase of $4.0 million due to higher employee-related expenses due primarily to recently completed capital projects and the growth of our operations.

Operating costs increased for the six months ended June 30, 2014, compared with the same period in 2013, primarily as a result of the following:


•	an increase of $11.0 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 $6.6 million due to higher ad valorem taxes related to completed capital projects;


•	an increase of $5.0 million due to higher employee-related expenses due primarily to recently completed capital projects and the growth of our operations; and


•	an increase of $1.4 million due to higher chemical, materials and supplies expense.

Depreciation and amortization expense increased for the three and six months ended June 30, 2014, compared with the same periods in 2013, due to depreciation associated with completed capital projects.

Equity earnings decreased for the three months ended June 30, 2014, compared with the same period in 2013, due primarily to increased ethane rejection and higher operating costs, offset partially by higher volumes delivered to Overland Pass Pipeline from our Bakken NGL Pipeline, which was placed in service in April 2013.

Equity earnings were relatively unchanged for the six months ended June 30, 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, offset partially by increased ethane rejection.

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



	Three Months Ended				Six Months Ended
	June 30,				June 30,
Operating Information	2014		2013		2014		2013
NGL sales (MBbl/d)	603		677		583		628
NGLs transported-gathering lines (MBbl/d) (a)	520		554		498		526
NGLs fractionated (MBbl/d) (b)	520		537		496		525
NGLs transported-distribution lines (MBbl/d) (a)	431		432		430		413
Average Conway-to-Mont Belvieu OPIS price differential - ethane in ethane/propane mix ($/gallon)	$	0.03	$	0.06	$	0.08	$	0.04

(a) - Includes volumes for consolidated entities only.

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

NGLs transported on gathering lines and NGLs fractionated decreased for the three and six months ended June 30, 2014, compared with the same periods in 2013, due primarily to the termination of a contract and increased ethane rejection in the Mid-Continent region, offset partially by increased volumes from the Williston Basin on our completed Bakken NGL Pipeline and volume from new plants connected in the Mid-Continent region.

NGLs transported on distribution lines increased for the six months ended June 30, 2014, compared with the same period in 2013, due primarily to higher NGL volumes, primarily propane during the first quarter 2014, 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.

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

We 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

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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 - 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. The operating results from this acquisition are included in the results for the three and six months ended June 30, 2014.

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



	Three Months Ended				Six Months Ended					Three Months					Six Months
	June 30,				June 30,					2014 vs. 2013					2014 vs. 2013
Financial Results	2014		2013		2014			2013		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Transportation revenues	$	66.4	$	54.8	$	140.4		$	115.5	$	11.6		21	%	$	24.9		22	%
Storage revenues	12.6		17.6		36.0			35.0		(5.0		)	(28	%)	1.0			3	%
Gas sales and other revenues	3.0		2.6		10.4			10.6		0.4			15	%	(0.2		)	(2	%)
Cost of sales	6.5		7.3		17.8			19.3		(0.8		)	(11	%)	(1.5		)	(8	%)
Net margin	75.5		67.7		169.0			141.8		7.8			12	%	27.2			19	%
Operating costs	27.3		25.0		54.8			52.1		2.3			9	%	2.7			5	%
Depreciation and amortization	10.9		10.8		21.7			21.9		0.1			1	%	(0.2		)	(1	%)
Loss on sale of assets	—		—		(0.1		)	—		—			—	%	(0.1		)	*
Operating income	$	37.3	$	31.9	$	92.4		$	67.8	$	5.4		17	%	$	24.6		36	%
Equity earnings from investments	$	15.9	$	15.3	$	39.3		$	31.7	$	0.6		4	%	$	7.6		24	%
Capital expenditures	$	8.7	$	6.0	$	15.3		$	11.3	$	2.7		45	%	$	4.0		35	%
Cash paid for acquisitions	$	—	$	—	$	14.0		$	—	$	—		—	%	$	14.0		*

* Percentage change is greater than 100 percent.

Net margin increased for the three months ended June 30, 2014, compared with the same period in 2013, primarily as a result of the following:


•	an increase of $9.4 million due to higher transportation revenues primarily from increased rates on intrastate pipelines, higher rates and contracted capacity on Midwestern Gas Transmission Company and increased interruptible transportation revenues from higher natural gas volumes transported;


•	an increase of $1.4 million from additional storage services to meet utility customers’ peak-day demand; and


•	an increase of $1.3 million from higher net retained fuel due primarily to additional natural gas volumes retained; offset partially by


•	a decrease of $4.3 million due to lower storage revenues from lower contracted capacity.

Net margin increased for the six months ended June 30, 2014, compared with the same period in 2013, primarily as a result of the following:


•	an increase of $13.8 million due to higher transportation revenues primarily from increased rates on intrastate pipelines, higher contracted capacity and rates on Midwestern Gas Transmission Company and increased interruptible transportation revenues from higher natural gas volumes transported;


•	an increase of $6.1 million from increased short-term natural gas storage services due to increased park-and-loan services as a result of weather-related seasonal demand primarily in the first quarter 2014;


•	an increase of $6.0 million from higher net retained fuel due to higher natural gas prices and additional natural gas volumes retained;


•	an increase of $5.3 million due to increased park-and-loan services on our interstate pipelines as a result of weather-related seasonal demand in the first quarter 2014; and


•	an increase of $1.6 million primarily from additional storage services to meet utility customers’ peak-day demand; offset partially by


•	a decrease of $5.7 million due to lower storage revenues from lower contracted capacity.

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Operating costs increased for the three and six months ended June 30, 2014, compared with the same periods in 2013, as a result of increased employee-related costs due to higher labor and employee benefit costs. The six month period was also impacted by higher materials and supplies expenses.

Equity earnings from our investments increased $7.6 million for the six months ended June 30, 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.

Capital expenditures increased for the three and six months ended June 30, 2014, compared with the same periods in 2013, due primarily to expenditures for system improvements.

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
Operating Information (a)	2014			2013			2014			2013
Natural gas transportation capacity contracted (MDth/d)	5,691			5,362			5,778			5,515
Transportation capacity subscribed	90		%	88		%	91		%	90		%
Average natural gas price
Mid-Continent region ($/MMBtu)	$	4.36		$	3.85		$	4.98		$	3.63

(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.

A reconciliation of Adjusted EBITDA for the three and six months ended June 30, 2014 and 2013, to net income, which is the nearest comparable GAAP financial measure, is as follows:



	Three Months Ended						Six Months Ended
	June 30,						June 30,
(Unaudited)	2014			2013			2014			2013
Reconciliation of Net Income to Adjusted EBITDA	(Thousands of dollars)
Net income	$	214,511		$	202,454		$	479,979		$	359,139
Interest expense	73,008			57,524			141,284			113,396
Depreciation and amortization	71,447			58,226			138,182			112,904
Income taxes	3,194			2,523			7,375			4,830
Allowance for equity funds used during construction	(1,253		)	(5,656		)	(12,224		)	(14,743		)
Adjusted EBITDA	$	360,907		$	315,071		$	754,596		$	575,526

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Adjusted EBITDA increased for the three and six months ended June 30, 2014, compared with the same periods 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 rely primarily on operating cash flows, commercial paper, bank credit facilities, debt issuances and the issuance of common units for our liquidity and capital resources requirements. We fund our operating expenses, debt service and cash distributions to our limited partners and general partner primarily with operating cash flows. Capital expenditures are funded by operating cash flows, short- and long-term debt and issuances of equity. We expect to continue to use these sources for liquidity and capital resource needs on both a short- and long-term basis. We have no guarantees of debt or other similar commitments to unaffiliated parties.

In the first six months of 2014, we utilized cash from operations, our commercial paper program and proceeds from our equity issuances, including our May 2014 equity offering and 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. We anticipate that these sources of funds will enable us to maintain our current and planned level of operations.

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



	June 30,	December 31,
	2014	2013
Long-term debt	51%	55%
Equity	49%	45%
Debt (including notes payable)	51%	55%
Equity	49%	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.

The total amount of short-term borrowings authorized by our general partner’s Board of Directors is $2.5 billion. At June 30, 2014, we had no commercial paper outstanding, $14 million in letters of credit issued and no borrowings outstanding under our Partnership Credit Agreement. At June 30, 2014, we had approximately $278.0 million of cash and approximately $1.7 billion of credit available under the Partnership Credit Agreement. At June 30, 2014, we could have issued $3.6 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.

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program to $1.7 billion from $1.2 billion. Amounts outstanding under our commercial paper program reduce the borrowing capacity under our Partnership Credit Agreement.

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 - In May 2014, we completed an underwritten public offering of approximately 13.9 million common units at a public offering price of $52.94 per common unit, generating net proceeds of approximately $714.5 million. In conjunction with this issuance, ONEOK Partners GP contributed approximately $15.0 million in order to maintain its 2 percent general partner interest in us. We used the proceeds to repay commercial paper outstanding, fund our capital expenditures and for general partnership purposes.

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 June 30, 2014, we had approximately $100.1 million available for issuance under the program.

As a result of these transactions, ONEOK’s aggregate ownership interest in us decreased to 38.5 percent at June 30, 2014, from 41.2 percent at December 31, 2013.

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 the first quarter 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.

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

Capital expenditures were $792.4 million and $924.8 million for the six months ended June 30, 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	$	1,185	$	29	$	1,214
Natural Gas Liquids	735		63		798
Natural Gas Pipelines	45		29		74
Other	—		23		23
Total projected capital expenditures	$	1,965	$	144	$	2,109

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 June 30, 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.

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



	Six Months Ended
	June 30,
	2014		2013
	(Millions of dollars)
Common unitholders	$	235.4	$	209.4
Class B unitholders	107.7		104.0
General partner	150.0		130.9
Noncontrolling interests	0.1		0.3
Total cash distributions paid	$	493.2	$	444.6

In the six months ended June 30, 2014 and 2013, cash distributions paid to our general partner included incentive distributions of $140.2 million and $122.0 million, respectively.

In July 2014, our general partner declared a cash distribution of $0.76 per unit ($3.04 per unit on an annualized basis) for the second quarter 2014, which will be paid on August 14, 2014, to unitholders of record at the close of business on August 4, 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
	Six Months Ended						2014 vs. 2013
	June 30,						Increase (Decrease)
	2014			2013			Increase (Decrease)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	534.1		$	383.4		$	150.7
Investing activities	(790.7		)	(911.1		)	120.4
Financing activities	400.1			(3.2		)	403.3
Change in cash and cash equivalents	143.5			(530.9		)	674.4
Cash and cash equivalents at beginning of period	134.5			537.1			(402.6		)
Cash and cash equivalents at end of period	$	278.0		$	6.2		$	271.8

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Operating Cash Flows - Operating cash flows are affected by earnings from our business activities. Changes in commodity prices and demand for our services or products—whether because of general economic conditions, changes in supply, changes in demand for the end products that are made with our products or 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 $611.4 million for the six months ended June 30, 2014, compared with $459.2 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.”

The changes in operating assets and liabilities decreased operating cash flows $77.3 million for the six months ended June 30, 2014, compared with a decrease of $75.8 million for the same period in 2013. This change is due primarily to the the change in NGL volumes in storage and commodity imbalances. This change also is due to 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.

Investing Cash Flows - Cash used in investing activities decreased for the six months ended June 30, 2014, compared with the same period in 2013, due primarily to timing of capital expenditures for our growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments.

Financing Cash Flows - Cash provided by financing activities increased for the six months ended June 30, 2014, compared with the same period in 2013, due primarily to our issuance of common units in May 2014, offset partially by the repayment of borrowings under our commercial paper program and 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.

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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 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 “Tailoring Rule” regulates greenhouse gas emissions at new or modified facilities that meet certain criteria. Affected facilities are required to review BACT, conduct air-quality and conduct 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. In addition, on June 23, 2014, the Supreme Court of the United States, in a case styled, Utility Air Regulatory Group v. EPA, 530 U.S. (2014), held that an industrial facility’s potential to emit GHG emissions alone cannot subject a facility to the permitting requirements for major stationary source provisions of the Clean Air Act. The decision invalidated the EPA’s current Triggering and Tailoring Rule for GHG Prevention of Significant Deterioration (PSD) and Title V requirements. However, the Court also ruled that to the extent a source pursues a capital project (new construction or expansion of existing facility), which otherwise subjects the source to major source PSD permitting for conventional criteria pollutants, the permitting authorities

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may impose BACT analysis and emission limits for GHGs from those sources. We are in the process of evaluating the effects the decision may have on our existing operations, and the opportunities it creates for design decisions for new project applications.

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.

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.

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.

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

IMPACT OF NEW ACCOUNTING STANDARDS

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

ESTIMATES AND CRITICAL ACCOUNTING POLICIES

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

Information about our 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, as amended, and Section 21E of the Exchange Act, as amended. The forward-looking statements relate to our anticipated financial performance (including projected operating income, net income, capital expenditures, cash flow and projected levels of distributions), liquidity, management’s plans and objectives for our future growth projects and other future operations (including plans to construct additional natural gas and natural gas liquids pipelines and processing facilities and related cost estimates), our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under 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;

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•	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;


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


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


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

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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.


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 June 30, 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 second quarter ended June 30, 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.

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ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

Not Applicable.


ITEM 4.	MINE SAFETY DISCLOSURES

Not Applicable.


ITEM 5.	OTHER INFORMATION

Not Applicable.


ITEM 6.	EXHIBITS

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

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



Exhibit No.		Exhibit Description

	10.1	Underwriting Agreement, dated as of May 13, 2014, among ONEOK Partners, L.P., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., Morgan Stanley & Co. LLC, UBS Securities LLC and Wells Fargo Securities,LLC, as representatives of several underwriters named therein (incorporated by reference to Exhibit 1.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on May 16, 2014 (File No. 1-12202)).

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

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

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

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

	101.INS	XBRL Instance Document.

	101.SCH	XBRL Taxonomy Extension Schema Document.

	101.CAL	XBRL Taxonomy Calculation Linkbase Document.

	101.DEF	XBRL Taxonomy Extension Definitions Document.

	101.LAB	XBRL Taxonomy Label Linkbase Document.

	101.PRE	XBRL Taxonomy Presentation Linkbase Document.

Attached as Exhibit 101 to this Quarterly Report are the following XBRL-related documents: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three and six months ended June 30, 2014 and 2013; (iii) Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2014 and 2013; (iv) Consolidated Balance Sheets at June 30, 2014, and December 31, 2013; (v) Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013; (vi) Consolidated Statement of Changes in Equity for the six months ended June 30, 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.

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

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SIGNATURE

Pursuant to the requirements of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.



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

Date: August 6, 2014		By:	/s/ Derek S. Reiners
			Derek S. Reiners
			Senior Vice President,
			Chief Financial Officer and Treasurer
			(Signing on behalf of the Registrant)

ONEOK Partners LP - FORM 10-Q - August 6, 2014

Attached files

ONEOK Partners LP Reports