ONEOK Partners LP - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 (SECTION 906 CERTIFICATION OF ROBERT F. MARTINOVICH) - ONEOK Partners LP	exhibit_32-2.htm
EX-31.2 - EXHIBIT 31.2 (SECTION 302 CERTIFICATION OF ROBERT F. MARTINOVICH) - ONEOK Partners LP	exhibit_31-2.htm
EX-32.1 - EXHIBIT 32.1 (SECTION 906 CERTIFICATION OF JOHN W. GIBSON) - ONEOK Partners LP	exhibit_32-1.htm
EX-31.1 - EXHIBIT 31.1 (SECTION 302 CERTIFICATION OF JOHN W. GIBSON) - ONEOK Partners LP	exhibit_31-1.htm
EXCEL - IDEA: XBRL DOCUMENT - ONEOK Partners LP	Financial_Report.xls

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2011

___ 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 Web site, if any, every

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

Yes X No __

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

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

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

Yes __ No X

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

Class		Outstanding at April 28, 2011
Common units Class B units		65,413,677 units 36,494,126 units

ONEOK PARTNERS, L.P.

TABLE OF CONTENTS

Part I.	Financial Information	Page No.
Item 1.	Financial Statements (Unaudited)
	Consolidated Statements of Income - Three Months Ended March 31, 2011 and 2010	5
	Consolidated Balance Sheets - March 31, 2011, and December 31, 2010	6
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2011 and 2010	7
	Consolidated Statement of Changes in Equity - Three Months Ended March 31, 2011	8-9
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2011 and 2010	10
	Notes to Consolidated Financial Statements	11-22
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23-41
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	41-42
Part II.	Other Information
Item 1.	Legal Proceedings	42
Item 1A.	Risk Factors	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 3.	Defaults Upon Senior Securities	42
Item 4.	(Removed and Reserved)	42
Item 5.	Other Information	42
Item 6.	Exhibits	42-43
Signature		44

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” and Part II, Item 1A, “Risk Factors” in this Quarterly Report and under Part I, Item 1A, “Risk Factors,” in our Annual Report.

INFORMATION AVAILABLE ON OUR WEBSITE

We make available on our website copies of our Annual Report, Quarterly Reports, 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. 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. In accordance with Rule 402 of Regulation S-T, the Interactive Data Files shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

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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, 2010

ASU	Accounting Standards Update

Bbl	Barrels, one 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(s)

British thermal units, a measure of the amount of heat required to raise the

temperature of one pound of water one degree Fahrenheit

Bushton Plant

Bushton Gas Processing Plant

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

EBITDA

Earnings before interest, 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

Guardian Pipeline

Guardian Pipeline, L.L.C.

Intermediate Partnership

ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary

of ONEOK Partners, L.P.

KCC

LIBOR

MBbl

Kansas Corporation Commission

London Interbank Offered Rate

Thousand barrels

MBbl/d

Thousand barrels per day

MDth/d

Thousand dekatherms per day

Midwestern Gas Transmission

Midwestern Gas Transmission Company

MMBbl

Million barrels

MMBtu

Million British thermal units

MMBtu/d

Million British thermal units per day

MMcf/d

Million cubic feet per day

Moody’s

Moody’s Investors Service, Inc.

NBP Services

NBP Services, LLC, a wholly owned subsidiary of ONEOK

NGL products

Marketable natural gas liquid purity products, such as ethane, ethane/propane

mix, propane, iso-butane, normal butane and natural gasoline

NGL(s)

Natural gas liquid(s)

Northern Border Pipeline

Northern Border Pipeline Company

NYMEX

New York Mercantile Exchange

OBPI	ONEOK Bushton Processing Inc.

OCC	Oklahoma Corporation Commission

ONEOK

ONEOK, Inc.

ONEOK Partners GP

ONEOK Partners GP, L.L.C., a wholly owned subsidiary of ONEOK and our sole general partner

OPIS	Oil Price Information Service

Overland Pass Pipeline Company

Overland Pass Pipeline Company LLC

Partnership Agreement

Third Amended and Restated Agreement of Limited Partnership of ONEOK

Partners, L.P., as amended

Partnership Credit Agreement

The Partnership’s $1.0 billion Amended and Restated Revolving Credit Agreement

dated March 30, 2007

POP	Percent of proceeds

Quarterly Report(s)

Quarterly Report(s) on Form 10-Q

S&P	Standard & Poor’s Financial Services LLC

SEC	Securities and Exchange Commission

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Securities Act

Securities Act of 1933, as amended

Viking Gas Transmission

Viking Gas Transmission Company

XBRL	eXtensible Business Reporting Language

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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
		Three Months Ended
		March 31,
(Unaudited)		2011			2010
	(Thousands of dollars, except per unit amounts)

Revenues		$	2,499,610		$	2,204,006
Cost of sales and fuel			2,170,056			1,942,881
Net margin			329,554			261,125
Operating expenses
Operations and maintenance			95,142			87,205
Depreciation and amortization			42,730			43,871
General taxes			13,601			9,101
Total operating expenses			151,473			140,177
Loss on sale of assets			(510	)		(786	)
Operating income			177,571			120,162
Equity earnings from investments (Note H)			32,092			21,116
Allowance for equity funds used during construction			466			247
Other income			2,385			1,850
Other expense			(614	)		(342	)
Interest expense			(57,268	)		(54,153	)
Income before income taxes			154,632			88,880
Income taxes			(3,575	)		(4,860	)
Net income			151,057			84,020
Less: Net income attributable to noncontrolling interests			147			152
Net income attributable to ONEOK Partners, L.P.		$	150,910		$	83,868

Limited partners' interest in net income:
Net income attributable to ONEOK Partners, L.P.		$	150,910		$	83,868
General partner's interest in net income			(32,642	)		(27,387	)
Limited partners' interest in net income		$	118,268		$	56,481

Limited partners' net income per unit, basic and diluted (Note G)		$	1.16		$	0.57

Number of units used in computation (thousands)			101,908			99,721
See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	March 31,			December 31,
(Unaudited)	2011			2010
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	617,403		$	898
Accounts receivable, net		759,246			815,141
Affiliate receivables		1,514			5,161
Gas and natural gas liquids in storage		232,219			317,159
Commodity imbalances		75,907			92,353
Other current assets		45,350			48,060
Total current assets		1,731,639			1,278,772

Property, plant and equipment
Property, plant and equipment		5,995,839			5,857,000
Accumulated depreciation and amortization		1,138,326			1,099,548
Net property, plant and equipment		4,857,513			4,757,452

Investments and other assets
Investments in unconsolidated affiliates (Note H)		1,186,588			1,188,124
Goodwill and intangible assets		659,287			661,204
Other assets		47,277			34,548
Total investments and other assets		1,893,152			1,883,876
Total assets	$	8,482,304		$	7,920,100

Liabilities and partners' equity
Current liabilities
Current maturities of long-term debt	$	11,931		$	236,931
Notes payable (Note D)		-			429,855
Accounts payable		810,487			852,330
Affiliate payables		25,921			29,765
Commodity imbalances		249,095			291,110
Accrued interest		77,716			49,606
Other current liabilities		85,827			84,545
Total current liabilities		1,260,977			1,974,142

Long-term debt, excluding current maturities (Note E)		3,873,234			2,581,572

Deferred credits and other liabilities		95,025			87,393

Commitments and contingencies (Note J)

Equity
ONEOK Partners, L.P. partners’ equity:
General partner		95,732			94,691
Common units: 65,413,677 units issued and outstanding at March 31, 2011 and December 31, 2010		1,826,864			1,825,521
Class B units: 36,494,126 units issued and outstanding at March 31, 2011 and December 31, 2010		1,346,072			1,345,322
Accumulated other comprehensive income (loss)		(20,728	)		6,283
Total ONEOK Partners, L.P. partners' equity		3,247,940			3,271,817

Noncontrolling interests in consolidated subsidiaries		5,128			5,176

Total equity		3,253,068			3,276,993
Total liabilities and equity	$	8,482,304		$	7,920,100
See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS	Three Months Ended
	March 31,
(Unaudited)	2011			2010
	(Thousands of dollars)
Operating activities
Net income	$	151,057		$	84,020
Depreciation and amortization		42,730			43,871
Allowance for equity funds used during construction		(466	)		(247	)
Loss on sale of assets		510			786
Deferred income taxes		1,940			1,239
Equity earnings from investments		(32,092	)		(21,116	)
Distributions received from unconsolidated affiliates		27,607			21,998
Changes in assets and liabilities:
Accounts receivable		55,895			172,824
Affiliate receivables		3,647			(1,538	)
Gas and natural gas liquids in storage		84,940			(1,764	)
Accounts payable		(36,141	)		(168,406	)
Affiliate payables		(3,844	)		(4,883	)
Commodity imbalances, net		(25,569	)		(56,558	)
Accrued interest		28,110			23,045
Other assets and liabilities		(20,818	)		(37,792	)
Cash provided by operating activities		277,506			55,479

Investing activities
Capital expenditures (less allowance for equity funds used during construction)		(144,826	)		(35,827	)
Contributions to unconsolidated affiliates		(250	)		(197	)
Distributions received from unconsolidated affiliates		4,904			1,531
Proceeds from sale of assets		516			138
Cash used in investing activities		(139,656	)		(34,355	)

Financing activities
Cash distributions:
General and limited partners		(147,776	)		(132,086	)
Noncontrolling interests		(195	)		(368	)
Borrowing (repayment) of notes payable, net		(429,855	)		(213,000	)
Issuance of long-term debt, net of discounts		1,295,450			-
Long-term debt financing costs		(10,986	)		-
Repayment of long-term debt		(227,983	)		(2,983	)
Issuance of common units, net of discounts		-			322,721
Contribution from general partner		-			6,820
Cash provided by (used in) financing activities		478,655			(18,896	)
Change in cash and cash equivalents		616,505			2,228
Cash and cash equivalents at beginning of period		898			3,151
Cash and cash equivalents at end of period	$	617,403		$	5,379
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)

December 31, 2010		65,413,677		36,494,126	$	94,691		$	1,825,521
Net income		-		-		32,642			75,915
Other comprehensive income		-		-		-			-
Distributions paid (Note F)		-		-		(31,601	)		(74,572	)
March 31, 2011		65,413,677		36,494,126	$	95,732		$	1,826,864
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)

December 31, 2010	$	1,345,322		$	6,283		$	5,176		$	3,276,993
Net income		42,353			-			147			151,057
Other comprehensive income		-			(27,011	)		-			(27,011	)
Distributions paid (Note F)		(41,603	)		-			(195	)		(147,971	)
March 31, 2011	$	1,346,072		$	(20,728	)	$	5,128		$	3,253,068

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

	Three Months Ended
	March 31,
(Unaudited)	2011			2010
	(Thousands of dollars)

Net income	$	151,057		$	84,020
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives		(25,753	)		24,707
Less: Realized gains (losses) on derivatives recognized in net income		1,258			(4,648	)
Total other comprehensive income (loss)		(27,011	)		29,355
Comprehensive income		124,046			113,375
Less: Comprehensive income attributable to noncontrolling interests		147			152
Comprehensive income attributable to ONEOK Partners, L.P.	$	123,899		$	113,223
See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

A. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our accompanying unaudited consolidated financial 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 2010 year-end consolidated balance sheet data was derived from 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. We have reclassified certain prior-period amounts to conform to current-period classifications.

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 January 2010, the FASB issued ASU 2010-06, “Improving Disclosures about Fair Value Measurements,” which requires separate disclosure of purchases, sales, issuances and settlements in the reconciliation of our Level 3 fair value measurements. We adopted this guidance with this Quarterly Report, and the impact was not material. Other provisions of ASU 2010-06 were adopted in 2010. See Note B for more discussion of our fair value measurements.

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 the income approach to determine the fair value of our derivative assets and liabilities and consider the markets in which the transactions are executed. While many of the contracts in our portfolio are executed in liquid markets where price transparency exists, some contracts are executed in markets for which market prices may exist, but the market may be relatively inactive. This results in limited price transparency that requires management’s judgment and assumptions to estimate fair values. For certain transactions, we utilize modeling techniques using NYMEX-settled pricing data and historical correlations of NGL product prices to crude oil prices. 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 the interest-rate yields to calculate present-value discount factors derived from LIBOR, Eurodollar futures and interest-rate swaps. Finally, we consider the credit risk of our counterparties with whom our derivative assets and liabilities are executed. 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 significant.

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

	March 31, 2011

	Level 1		Level 2			Level 3			Total - Gross			Netting (a)			Total - Net (b)
	(Thousands of dollars)
Derivatives - commodity
Assets	$	-	$	11,572		$	2,589		$	14,161		$	(12,520	)	$	1,641
Liabilities	$	-	$	(16,823	)	$	(13,285	)	$	(30,108	)	$	12,520		$	(17,588	)

	December 31, 2010

	Level 1		Level 2			Level 3			Total - Gross			Netting (a)			Total - Net (b)
	(Thousands of dollars)
Derivatives - commodity
Assets	$	-	$	15,305		$	2,311		$	17,616		$	(6,516	)	$	11,100
Liabilities	$	-	$	(5,361	)	$	(1,155	)	$	(6,516	)	$	6,516		$	-
(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.
(b) - Included in other current assets, or other current liabilities and other liabilities in our Consolidated Balance Sheets.

At March 31, 2011, and December 31, 2010, we had no cash collateral held or posted under our mater-netting arrangements.

Derivative instruments categorized as Level 1 normally would include exchange-traded contracts that are valued using unadjusted quoted prices in active markets.

Our derivative instruments categorized as Level 2 include non-exchange-traded fixed-price swaps for natural gas and condensate that are valued based on NYMEX-settled prices for natural gas and crude oil, respectively.

Our derivative instruments categorized as Level 3 include over-the-counter fixed-price swaps for NGL products, natural gas basis swaps and certain physical forward contracts for NGL products. These instruments are valued based on information from a pricing service, the forward NYMEX curve for crude oil, correlations of specific NGL purity products to crude oil and internally developed natural gas basis curves incorporating observable and unobservable market data. We corroborate the data on which our fair value estimates are based using our market knowledge of recent transactions and day-to-day pricing fluctuations and analysis of historical relationships of data from the pricing service compared with actual settlements and correlations.

The following table sets forth a reconciliation of our Level 3 fair value measurements for the periods indicated:

	Three Months Ended
	March 31,
Derivative Assets (Liabilities)	2011			2010
	(Thousands of dollars)
Net assets (liabilities) at beginning of period	$	1,156		$	(13,052	)
Total realized/unrealized gains (losses):
Included in earnings (a)		172			-
Included in other comprehensive income (loss)		(12,024	)		10,720
Net liabilities at end of period	$	(10,696	)	$	(2,332	)

Total gains for the period included in earnings
attributable to the change in unrealized gains (losses)
relating to assets and liabilities still held as of the end
of the period (a)	$	808		$	-
(a) - Included in revenues in our Consolidated Statements of Income.

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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.

The estimated fair value of the aggregate of our senior notes outstanding, including current maturities, was $4.2 billion and $3.1 billion at March 31, 2011, and December 31, 2010, respectively. The book value of the aggregate of our senior notes outstanding, including current maturities, was $3.9 billion and $2.8 billion at March 31, 2011, and December 31, 2010, respectively. The estimated fair value of the aggregate of our senior notes outstanding was determined using quoted market prices for our senior notes or similar issues with similar terms and maturities.

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 share of 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 - Commodity price risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in the price of natural gas, NGLs and condensate. We use the following commodity derivative instruments to mitigate the commodity price risk associated with a portion of the forecasted sales of these commodities:

·	Futures contracts - Standardized exchange-traded contracts to purchase or sell natural gas or crude oil at a specified price, requiring delivery on, or settlement through, the sale or purchase of an offsetting contract by a specified future date under the provisions of exchange regulations;

·	Forward contracts - Commitments to purchase or sell natural gas, crude oil or NGLs for physical delivery at some specified time in the future. Forward contracts are different from futures in that forwards are customized and non-exchange traded; and

Swaps - Financial trades involving the exchange of payments based on two different pricing structures for a commodity. In a typical commodity swap, parties exchange payments based on changes in the price of a commodity or a market index, while fixing the price they effectively pay or receive for the physical commodity. As a result, one party assumes the risks and benefits of the movements in market prices, while the other party assumes the risks and benefits of a fixed price for the commodity.

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. To a lesser extent, exposures arise from the relative price differential between NGLs and natural gas, or the gross processing spread, with respect to our keep-whole contracts. We are also exposed to basis risk between the various production and market locations where we buy and sell commodities. As part of our hedging strategy, we use the previously described commodity derivative instruments to minimize the impact of price fluctuations related to natural gas, NGLs and condensate. We reduce our gross processing spread exposure through a combination of physical and financial hedges. We utilize a portion of our POP equity natural gas production as an offset, or natural hedge, to an equivalent portion of our keep-whole shrink requirements. This has the effect of converting our gross processing spread risk to NGL commodity price risk. We hedge a portion of the forecasted sales of the commodities we retain, including NGLs, natural gas and condensate.

In our Natural Gas Pipelines segment, we are exposed to commodity price risk because our intrastate and interstate natural gas pipelines retain natural gas from our customers for operations or as part of our fee for services provided. When the amount of natural gas consumed in operations by these pipelines differs from the amount provided by our customers, our pipelines must buy or sell natural gas, or store or use natural gas from inventory, which can expose us to commodity price risk depending on the regulatory treatment for this activity. We use physical forward sales or purchases to reduce the impact of price fluctuations related to natural gas. At March 31, 2011, and December 31, 2010, there were no financial derivative instruments with respect to our natural gas pipeline operations.

In our Natural Gas Liquids segment, we are exposed to basis risk primarily as a result of the relative value of NGL purchases at one location and sales at another location. To a lesser extent, we are exposed to commodity price risk resulting from the relative values of the various NGL products to each other, NGLs in storage and the relative value of NGLs to natural gas. We utilize physical forward contracts to reduce the impact of price fluctuations related to NGLs. At March 31, 2011, and December 31, 2010, there were no financial derivative instruments with respect to our NGL operations.

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Interest-rate risk - We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps. Interest-rate swaps are agreements to exchange an interest payment at some future point based on the differential between two interest rates. At March 31, 2011, and December 31, 2010, we did not have any interest-rate swap agreements.

Accounting Treatment - We record 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 cash flow hedging relationship and, if so, the reason for holding it.

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

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

Under certain conditions, we designate our derivative instruments as a hedge of exposure to changes in fair values or cash flows. We formally document all relationships between hedging instruments and hedged items, as well as risk management objectives and strategies for undertaking various hedge transactions and methods for assessing and testing correlation and hedge ineffectiveness. We specifically identify the forecasted transaction that has been designated as the hedged item with a cash flow hedge. We assess the effectiveness of hedging relationships quarterly by performing an effectiveness analysis on our fair value and cash flow hedging relationships to determine whether the hedge relationships are highly effective on a retrospective and prospective basis. We also document our normal purchases and normal sales transactions that we expect to result in physical delivery and that we elect to exempt from derivative accounting treatment.

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

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

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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 for the periods indicated:

	March 31, 2011					December 31, 2010
	Assets (a)		(Liabilities) (b)			Assets (a)		(Liabilities) (b)
	(Thousands of dollars)

Commodity derivatives designated as hedging instruments - financial	$	10,260	$	(27,283	)	$	13,782	$	(3,556	)

Commodity derivatives not designated as hedging instruments
Financial		2,260		(2,825	)		2,218		(2,960	)
Physical		1,641		-			1,616		-
Total derivatives not designated as hedging instruments		3,901		(2,825	)		3,834		(2,960	)
Total derivatives	$	14,161	$	(30,108	)	$	17,616	$	(6,516	)
(a) - Included on a net basis in other current assets on our Consolidated Balance Sheets.
(b) - Included on a net basis in other current liabilities and other liabilities on our Consolidated Balance Sheets.

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

		March 31, 2011		December 31, 2010

	Contract Type	Purchased/ Payor	Sold/ Receiver	Purchased/ Payor	Sold/ Receiver
Derivatives designated as hedging instruments:
Cash flow hedges
Fixed price
- Natural gas (Bcf)	Swaps	-	(6.9)	-	(8.2)
- Crude oil and NGLs (MMBbl)	Swaps	-	(3.1)	-	(1.5)
Basis
- Natural gas (Bcf)	Swaps	-	(6.9)	-	(8.2)

Derivatives not designated as hedging instruments:
Fixed price
- Natural gas (Bcf)	Swaps	2.0	(2.0)	2.6	(2.6)
- Crude oil and NGLs (MMBbl)	Forwards and Swaps	0.3	(0.3)	0.6	(0.6)
Basis
- Natural gas (Bcf)	Swaps	2.0	(2.0)	2.6	(2.6)

Cash Flow Hedges - At March 31, 2011, our Consolidated Balance Sheet reflected a net unrealized loss of $17.0 million in accumulated other comprehensive income (loss), with a corresponding offset in derivative financial instrument assets and liabilities that will be realized within the next 21 months as the forecasted transactions affect earnings. If prices remain at the current levels, we will recognize $11.6 million in losses over the next 12 months, and we will recognize $5.4 million in losses thereafter.

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

	Location of Gain (Loss) Reclassified from	Three Months Ended
Derivatives in Cash Flow	Accumulated Other Comprehensive Income	March 31,
Hedging Relationships	(Loss) into Net Income (Effective Portion)	2011			2010
		(Thousands of dollars)
Commodity contracts	Revenues	$	1,466		$	(4,869	)
Interest-rate contracts	Interest expense		(208	)		221
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income (effective portion)		$	1,258		$	(4,648	)

Ineffectiveness related to our cash flow hedges was not material for the three months ended March 31, 2011 and 2010. In the event that it becomes probable that a forecasted transaction will not occur, we would discontinue cash flow hedge treatment, which would affect earnings. There were no gains or losses due to the discontinuance of cash flow hedge treatment during the three months ended March 31, 2011 and 2010.

The balance in accumulated other comprehensive income in our Consolidated Balance Sheets at March 31, 2011, and December 31, 2010, was attributable to unrealized gains and losses on derivatives.

Credit Risk - All of our commodity derivative financial contracts are with ONEOK Energy Services Company, L.P. (OES), a subsidiary of ONEOK. OES has entered into similar commodity derivative financial contracts with third parties at our direction and on our behalf. We have an indemnification agreement with OES that indemnifies and holds OES harmless from any liability it may incur solely as a result of its entering into commodity derivative financial contracts on our behalf. At March 31, 2011, there were no derivative assets for which we would indemnify OES in the event of a default by the counterparty. Derivative assets for which we would indemnify OES in the event of a default by the counterparty totaled $9.5 million at December 31, 2010, and were with investment-grade counterparties that are primarily in the oil and gas and financial services sectors.

D. CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

Our Partnership Credit Agreement, which expires in March 2012, 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 non-cash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5 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 three calendar quarters following the acquisitions. At March 31, 2011, our ratio of indebtedness to adjusted EBITDA was 4.17 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement. Upon breach of certain covenants by us in our Partnership Credit Agreement, amounts outstanding under our Partnership Credit Agreement may become due and payable immediately.

Our Partnership Credit Agreement is available to repay our commercial paper notes, if necessary. Amounts outstanding under our commercial paper program reduce the borrowing capacity under our Partnership Credit Agreement.

A portion of the proceeds from our January 2011 debt issuance, discussed in Note E, was used to repay the outstanding balance of our commercial paper. At March 31, 2011, we had no commercial paper outstanding and no borrowings under our Partnership Credit Agreement. As a result of our January 2011 debt offering, available borrowings are limited by the ratio of indebtedness to adjusted EBITDA covenant under our Partnership Credit Agreement. However, we had approximately $617.4 million of cash at March 31, 2011, and $772.0 million of available borrowings to meet our liquidity needs.

At March 31, 2011, we had no letters of credit issued outside of the Partnership Credit Agreement. Borrowings under our Partnership Credit Agreement are nonrecourse to our general partner.

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E. LONG-TERM DEBT

Debt Issuance and Maturity - In January 2011, we completed an underwritten public offering of $1.3 billion of senior notes, consisting of $650 million of 3.25-percent senior notes due 2016 and $650 million of 6.125-percent senior notes due 2041. The net proceeds from the offering of approximately $1.28 billion were used to repay amounts outstanding under our commercial paper program, to repay the $225 million principal amount of senior notes due March 2011 and for general partnership purposes, including capital expenditures.

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

We may redeem our 3.25-percent senior notes due 2016 and our 6.125-percent senior notes due 2041 at par starting one month and six months, respectively, before their maturities. Prior to these dates, we may redeem these notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. Our senior notes are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness, and structurally subordinate to any of the existing and future debt and other liabilities of any non-guarantor subsidiaries.

F. EQUITY

ONEOK - ONEOK and its subsidiaries owned all of the Class B units, 5.9 million common units and the entire 2-percent general partner interest in us, which together constituted a 42.8-percent ownership interest in us at March 31, 2011.

Cash Distributions - Cash distributions paid to our general partner of $31.6 million and $26.0 million in the three months ended March 31, 2011 and 2010, respectively, included incentive distributions of $28.6 million and $23.4 million, respectively.

In April 2011, our general partner declared a cash distribution of $1.15 per unit ($4.60 per unit on an annualized basis) for the first quarter of 2011, an increase of 1 cent from the previous quarter, which will be paid on May 13, 2011, to unitholders of record at the close of business on April 29, 2011.

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 its right to increased quarterly distributions, currently each Class B unit and common unit share equally in the earnings of the partnership, and neither has any liquidation or other preferences. ONEOK Partners GP owns the entire 2-percent general partnership interest in us, which entitles it to incentive distribution rights that provide for an increasing proportion of cash distributions from the partnership as the distributions made to limited partners increase above specified levels.

For purposes of our calculation of limited partners’ net income per unit, net income attributable to ONEOK Partners, L.P. is generally allocated to the general partner as follows: (i) an amount based upon the 2-percent general partner interest in net income attributable to ONEOK Partners, L.P.; and (ii) the amount of the general partner’s incentive distribution rights based on the total cash distributions declared for the period. The amount of incentive distribution allocated to our general partner totaled $29.6 million and $25.7 million for the three months ended March 31, 2011 and 2010, respectively.

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 H of the Notes to Consolidated Financial Statements in our Annual Report.

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H. UNCONSOLIDATED AFFILIATES

Northern Border Pipeline - Northern Border Pipeline anticipates requiring additional equity contributions of approximately $100 million to $120 million from its partners in 2011, of which our share will be approximately $50 million to $60 million based on our 50-percent equity interest.

Overland Pass Pipeline Company - We expect to make contributions in 2011 and 2012 totaling approximately $35 million to $40 million to Overland Pass Pipeline Company to install additional pump stations and to expand existing pump stations.

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

	Three Months Ended
	March 31,
	2011		2010
	(Thousands of dollars)
Northern Border Pipeline	$	20,852	$	14,846
Overland Pass Pipeline Company		4,376		-
Fort Union Gas Gathering, L.L.C.		2,965		3,558
Bighorn Gas Gathering, L.L.C.		1,493		237
Lost Creek Gathering Company, L.L.C.		417		1,402
Other		1,989		1,073
Equity earnings from investments	$	32,092	$	21,116

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

	Three Months Ended
	March 31,
		2011		2010
	(Thousands of dollars)
Income Statement (a)
Operating revenues	$	123,301	$	99,231
Operating expenses	$	54,236	$	44,715
Net income	$	63,165	$	46,911

Distributions paid to us	$	32,511	$	23,529
(a) - Financial information for 2011 is not directly comparable with 2010 due to the deconsolidation of Overland Pass Pipeline Company in September 2010.

I. RELATED-PARTY TRANSACTIONS

Intersegment and affiliate sales are recorded on the same basis as sales to unaffiliated customers. Our Natural Gas Gathering and Processing segment sells natural gas to ONEOK and its subsidiaries. A portion of our Natural Gas Pipelines segment’s revenues are from ONEOK and its subsidiaries. Additionally, our Natural Gas Gathering and Processing segment and Natural Gas Liquids segment purchase a portion of the natural gas used in their operations from ONEOK and its subsidiaries.

We have certain contractual rights to the Bushton Plant. Our Processing and Services Agreement with ONEOK and OBPI sets out the terms by which OBPI provides services to us at the Bushton Plant through May 2012. We have contracted for all of the capacity of the Bushton Plant from OBPI. In exchange, we pay OBPI for all costs and expenses necessary for operation and maintenance of the Bushton Plant, and we reimburse ONEOK for OBPI’s obligations under equipment leases covering portions of the Bushton Plant. Pursuant to our rights under the Processing and Services Agreement, on April 22, 2011, we directed OBPI to exercise its purchase option for the original leased equipment (or any replacement parts) pursuant to the terms of the equipment leases. Our Processing and Services Agreement provides that we will reimburse OBPI for amounts incurred in connection with the exercised option, and upon reimbursement, we will become the owner of the purchased equipment.

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

ONEOK and its affiliates provide a variety of services to us under the Services Agreement, including cash management and financial services, employee benefits provided through ONEOK’s benefit plans, legal and administrative services, insurance and office space leased in ONEOK’s headquarters building and other field locations. Where costs are incurred specifically on behalf of one of our affiliates, the costs are billed directly to us by ONEOK. In other situations, the costs may be allocated to us through a variety of methods, depending upon the nature of the expense and activities. For example, a service that applies equally to all employees is allocated based upon the number of employees; however, an expense benefiting the consolidated company but having no direct basis for allocation is allocated by the modified Distrigas method, a method using a combination of ratios that includes gross plant and investment, operating income and payroll expense. It is not practicable to determine what these general overhead costs would be on a stand-alone basis. All costs directly charged or allocated to us are included in our Consolidated Statements of Income.

Our derivative financial contracts with OES are discussed under “Credit Risk” in Note C.

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

	Three Months Ended
	March 31,
	2011		2010
	(Thousands of dollars)
Revenues	$	96,793	$	136,931

Expenses
Cost of sales and fuel	$	10,731	$	17,759
Administrative and general expenses		56,295		51,025
Total expenses	$	67,026	$	68,784

Cash Distributions to ONEOK - We paid cash distributions to ONEOK and its subsidiaries related to its general and limited partner interests of $79.9 million and $72.7 million for the three months ended March 31, 2011 and 2010, respectively.

J. COMMITMENTS AND CONTINGENCIES

Environmental Matters - We are subject to multiple historical and wildlife preservation laws and environmental regulations affecting many aspects of our present and future operations. Regulated activities include those involving air emissions, stormwater and wastewater discharges, handling and disposal of solid and hazardous wastes, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. 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 clean-up costs, which could affect materially our results of operations and cash flows. In addition, emission controls required 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 regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations.

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Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position or results of operations, and our expenditures related to environmental matters had no material effect upon earnings or cash flows during the three months ended March 31, 2011 and 2010.

In May 2010, the EPA finalized the “Tailoring Rule” that will regulate greenhouse gas emissions at new or modified facilities that meet certain criteria. Affected facilities will be required to review best available control technology, conduct air-quality analysis, impact analysis and public reviews with respect to such emissions. The rule was phased in beginning January 2011 and, at current emission threshold levels, we believe it will have 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, the EPA has issued a rule on air-quality standards, “National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines,” also known as RICE NESHAP, scheduled to be adopted in 2013. The rule will require capital expenditures over the next three years for the purchase and installation of new emissions-control equipment. We do not expect these expenditures to have a material impact on our results of operations, financial position or cash flows.

Pipeline Safety - We are subject to Pipeline and Hazardous Materials Safety Administration regulations, including 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. Currently, Congress is reauthorizing existing pipeline safety legislation, and there are also a number of new bills addressing pipeline safety being considered. Recently, the Pipeline and Hazardous Materials Safety Administration issued an “Advisory Bulletin” regarding maximum allowable operating pressures for natural gas and hazardous liquids pipelines. This bulletin requests all operators review pipeline records and data to validate existing maximum pressure determinations. We are monitoring activity concerning reauthorization, proposed new legislation and potential changes in the Pipeline and Hazardous Materials Safety Administration’s regulations to assess the potential impact on our operations. At this time, our review of records relating to maximum pressure determinations is ongoing, and no revised or new legislation has been enacted resulting in any potential cost, fees or expenses associated with these issues. We cannot provide assurance that existing pipeline safety regulations will not be revised or interpreted in a different manner or that new regulations will not be adopted that could result in increased compliance costs or additional operating restrictions.

Financial Markets Legislation - The Dodd-Frank Act represents a far-reaching overhaul of the framework for regulation of United States financial markets. Various regulatory agencies, including the SEC and the CFTC, have proposed regulations for implementation of many of the provisions of the Dodd-Frank Act and are currently seeking comments on the more recent proposals. There may be additional proposed regulations as the remaining provisions of the Dodd-Frank Act are implemented. Until the final regulations are established, we are unable to ascertain how we may be affected. Based on our assessment of the proposed regulations issued to date, we expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest-rate risks; however, the costs of doing so may increase as a result of the new legislation. We may also incur additional costs associated with our compliance with the new regulations and anticipated additional record-keeping, reporting and disclosure obligations.

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 final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or liquidity.

K. SEGMENTS

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

·	our Natural Gas Gathering and Processing segment primarily gathers and processes natural gas;

·	our Natural Gas Pipelines segment primarily operates regulated interstate and intrastate natural gas transmission pipelines and natural gas storage facilities; and

·	our Natural Gas Liquids segment primarily gathers, treats, fractionates and transports NGLs and stores, markets and distributes NGL products.

Accounting Policies - The accounting policies of the segments are described in Note A and Note N of the Notes to Consolidated Financial Statements in our Annual Report. Intersegment and affiliate sales are recorded on the same basis as sales to unaffiliated customers. Net margin is comprised of total revenues less cost of sales and fuel. Cost of sales and fuel includes commodity purchases, fuel and transportation costs.

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Customers - The primary customers for our Natural Gas Gathering and Processing segment are major and independent oil and gas production companies. Our Natural Gas Liquids segment’s customers are primarily NGL and natural gas gathering and processing companies, propane distributors, ethanol producers and petrochemical, refining and NGL marketing companies. Customers served by our Natural Gas Pipelines segment include local distribution companies, power generating companies, natural gas marketing companies and petrochemical companies.

For the three months ended March 31, 2011, our Natural Gas Liquids segment had one customer from which we received 12 percent of our consolidated revenues. For the three months ended March 31, 2010, we had no customers from which we received 10 percent or more of our consolidated revenues.

See Note I for additional information about our sales to affiliated customers.

Operating Segment Information - The following tables set forth certain selected financial information for our operating segments for the periods indicated:

Three Months Ended March 31, 2011	Natural Gas Gathering and Processing			Natural Gas Pipelines (a)			Natural Gas Liquids (b)			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	65,298		$	58,716		$	2,278,803		$	-		$	2,402,817
Sales to affiliated customers		71,826			24,967			-			-			96,793
Intersegment revenues		203,451			203			7,238			(210,892	)		-
Total revenues	$	340,575		$	83,886		$	2,286,041		$	(210,892	)	$	2,499,610

Net margin	$	93,689		$	75,114		$	160,255		$	496		$	329,554
Operating costs		38,027			26,958			43,925			(167	)		108,743
Depreciation and amortization		16,162			11,262			15,306			-			42,730
Loss on sale of assets		(80	)		(62	)		(368	)		-			(510	)
Operating income	$	39,420		$	36,832		$	100,656		$	663		$	177,571

Equity earnings from investments	$	6,222		$	21,038		$	4,832		$	-		$	32,092
Investments in unconsolidated affiliates	$	323,500		$	387,147		$	475,941		$	-		$	1,186,588
Total assets	$	1,904,737		$	1,876,235		$	4,076,794		$	624,538		$	8,482,304
Noncontrolling interests in consolidated subsidiaries	$	-		$	5,113		$	-		$	15		$	5,128
Capital expenditures	$	109,523		$	7,582		$	27,621		$	100		$	144,826
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $66.1 million, net margin of $57.9 million and operating income of $25.5 million.
(b) - Our Natural Gas Liquids segment has regulated and non-regulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $89.4 million, of which $59.9 million related to sales within the segment, net margin of $58.0 million and operating income of $34.1 million.

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Three Months Ended March 31, 2010	Natural Gas Gathering and Processing			Natural Gas Pipelines (a)		Natural Gas Liquids (b)			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	114,196		$	57,452	$	1,895,428		$	(1	)	$	2,067,075
Sales to affiliated customers		107,177			29,754		-			-			136,931
Intersegment revenues		133,815			384		7,054			(141,253	)		-
Total revenues	$	355,188		$	87,590	$	1,902,482		$	(141,254	)	$	2,204,006

Net margin	$	81,315		$	78,565	$	104,014		$	(2,769	)	$	261,125
Operating costs		34,456			22,776		41,001			(1,927	)		96,306
Depreciation and amortization		14,652			10,882		18,336			1			43,871
Gain (loss) on sale of assets		(28	)		1		(758	)		(1	)		(786	)
Operating income	$	32,179		$	44,908	$	43,919		$	(844	)	$	120,162

Equity earnings from investments	$	5,687		$	15,075	$	354		$	-		$	21,116
Investments in unconsolidated affiliates	$	324,830		$	408,585	$	29,020		$	-		$	762,435
Total assets	$	1,628,369		$	1,887,322	$	4,233,887		$	(52,209	)	$	7,697,369
Noncontrolling interests in consolidated subsidiaries	$	-		$	5,328	$	44		$	15		$	5,387
Capital expenditures	$	19,147		$	3,235	$	15,819		$	(2,374	)	$	35,827
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $70.5 million, net margin of $62.2 million and operating income of $34.1 million.
(b) - Our Natural Gas Liquids segment has regulated and non-regulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $81.6 million, of which $48.8 million related to sales within the segment, net margin of $63.4 million and operating income of $35.3 million.

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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

Growth Projects - In May 2011, we announced plans to invest approximately $910 million to $1.2 billion in our Natural Gas Liquids segment to accommodate growing NGL supplies and alleviate infrastructure constraints between the Mid-Continent and Texas Gulf Coast regions.

Sterling III Pipeline and reconfiguring Sterling I and II Pipelines - We plan to build a 570-plus-mile natural gas liquids pipeline, the Sterling III Pipeline, which will have the flexibility to transport either unfractionated NGLs or NGL purity products from the Mid-Continent to the Texas Gulf Coast. The Sterling III Pipeline will traverse the NGL-rich Woodford Shale that is currently under development, as well as provide transportation capacity for NGL production from the growing Cana-Woodford Shale and Granite Wash, where the pipeline can gather unfractionated NGLs from the new natural gas processing plants that are being built as a result of increased drilling activity in these areas. The Sterling III Pipeline will have an initial capacity to transport up to 193 MBbl/d of production from our natural gas liquids infrastructure at Medford, Oklahoma, to our storage and fractionation facilities in Mont Belvieu, Texas. Additional pump stations could expand the capacity of the pipeline to 250 MBbl/d. Following the receipt of all necessary permits and the acquisition of rights-of-way, construction is scheduled to begin in 2013, with an expected completion late the same year.

The investment also includes reconfiguring our existing Sterling I and II Pipelines, which currently distributes NGL products between the Mid-Continent and Gulf Coast NGL market centers, to transport either unfractionated NGLs or NGL products.

The project costs for the new pipeline and reconfiguring projects are estimated to be $610 million to $810 million, excluding AFUDC.

MB-2 fractionator - We plan to construct a new 75-MBbl/d fractionator, MB-2, in Mont Belvieu, Texas. We recently submitted a permit application to the Texas Commission on Environmental Quality (TCEQ) to build this fractionator. Following the receipt of all necessary permits, construction of the MB-2 fractionator is scheduled to begin in 2011 and is expected to be completed in mid-2013. The cost of the MB-2 fractionator is estimated to be $300 million to $390 million, excluding AFUDC. The fractionator can be expanded to 125 MBbl/d to accommodate additional volumes as they are added to the Arbuckle Pipeline, Sterling III Pipeline, and the Sterling I and II reconfiguration.

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

Cash Distributions - In April 2011, our general partner declared a cash distribution of $1.15 per unit ($4.60 per unit on an annualized basis) for the first quarter of 2011, an increase of 1 cent from the previous quarter, which will be paid May 13, 2011, to unitholders of record at the close of business on April 29, 2011.

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FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

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

	Three Months Ended						Variances
	March 31,						2011 vs. 2010
Financial Results	2011			2010			Increase (Decrease)
	(Millions of dollars)
Revenues	$	2,499.6		$	2,204.0		$	295.6		13%
Cost of sales and fuel		2,170.1			1,942.9			227.2		12%
Net margin		329.5			261.1			68.4		26%
Operating costs		108.7			96.2			12.5		13%
Depreciation and amortization		42.7			43.9			(1.2	)	(3%)
Loss on sale of assets		(0.5	)		(0.8	)		(0.3	)	(38%)
Operating income	$	177.6		$	120.2		$	57.4		48%

Equity earnings from investments	$	32.1		$	21.1		$	11.0		52%
Interest expense	$	(57.3	)	$	(54.2	)	$	3.1		6%
Capital expenditures	$	144.8		$	35.8		$	109.0		*
* Percentage change is greater than 100 percent.

Operating income increased approximately 48 percent for the three months ended March 31, 2011, compared with the same period last year. The increase in operating income reflects higher net margin in our Natural Gas Liquids segment resulting from the following:

·	higher optimization margins due primarily to more favorable NGL price differentials, additional fractionation and transportation capacity available for optimization activities between the Mid-Continent and Gulf-Coast markets; and

·	higher gathered volumes, excluding the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company, and contract renegotiations associated with our natural gas liquids exchange services.

Additionally, our Natural Gas Gathering and Processing segment benefited from higher realized commodity prices and changes in contract terms.

These increases were offset partially by the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method in our Natural Gas Liquids segment following the sale of a 49-percent ownership interest in Overland Pass Pipeline Company.

Operating costs increased for the three months ended March 31, 2011, compared with the same period last year, due primarily to higher employee-related costs associated with incentive and benefit plans administered by ONEOK and higher ad valorem taxes.

Equity earnings from investments increased for the three months ended March 31, 2011, compared with the same period last year, due to increased contracted capacity on Northern Border Pipeline in our Natural Gas Pipeline segment from wider natural gas price differentials between the markets it serves, driven by strong Midwest market demand; and the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company.

Capital expenditures increased for the three months ended March 31, 2011, compared with the same period last year, due primarily to growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments.

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

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Natural Gas Gathering and Processing

Overview - Our Natural Gas Gathering and Processing segment’s operations include gathering and processing of natural gas produced from crude oil and natural gas wells. We gather and process natural gas in the Mid-Continent region, which includes the Anadarko Basin of Oklahoma that contains the NGL-rich Cana-Woodford formation 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. The natural gas we gather in the Powder River Basin of Wyoming is coal-bed methane, or dry natural gas, that 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.

In the Mid-Continent region and the Williston Basin, unprocessed natural gas is compressed and transported through pipelines 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 generally in the form of a mixed, unfractionated NGL stream. This unfractionated NGL stream is shipped to fractionators where, through the application of heat and pressure, the unfractionated NGL stream is separated into NGL products. Revenues for this segment are derived primarily from POP, fee and keep-whole contracts. Under a POP contract, we retain a portion of sales proceeds from the commodity sales for our services. With a fee-based contract, we charge a fee for our services, and with a keep-whole contract, we retain the NGLs as our fee for service and return to the producer an equivalent quantity of or payment for residue gas containing the same amount of Btus as the unprocessed natural gas that was delivered to us. Our natural gas and NGL products are sold to affiliates and also to a diverse customer base.

Growth Projects - We announced in 2010 and early 2011 approximately $950 million to $1.1 billion in growth projects in the Williston Basin and Cana-Woodford Shale area that will enable us to meet the rapidly growing needs of crude oil and natural gas producers in those areas.

Williston Basin Processing Plants and related projects - We are constructing three new 100 MMcf/d natural gas processing facilities, the Garden Creek plant in eastern McKenzie County, North Dakota, and the Stateline I and II plants in western Williams County, North Dakota. In addition, we will expand and upgrade our existing gathering and compression infrastructure and add new well connections associated with these plants. The Garden Creek plant, which is expected to be in service by the end of 2011, and related infrastructure projects are expected to cost approximately $350 million to $415 million, excluding AFUDC. The Stateline I plant, which is expected to be in service by the third quarter of 2012, and related infrastructure projects are expected to cost approximately $300 million to $355 million, excluding AFUDC. The Stateline II plant, which is expected to be in service during the first half of 2013, and related infrastructure projects are expected to cost approximately $260 million to $305 million, excluding AFUDC.

Cana-Woodford Shale projects - In 2010, we completed projects totaling approximately $38 million in the Cana-Woodford Shale development in Oklahoma, which included the connection of our western Oklahoma natural gas gathering system to our Maysville natural gas processing facility in central Oklahoma, as well as new well connections to gather and process additional Cana-Woodford Shale volumes.

For a discussion of our capital expenditure financing, see “Capital Expenditures” in “Liquidity and Capital Resources” on page 34.

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

	Three Months Ended				Variances
	March 31,				2011 vs. 2010
Financial Results	2011		2010		Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	205.2	$	187.1	$	18.1		10%
Residue gas sales		100.3		131.9		(31.6	)	(24%)
Gathering, compression, dehydration and processing fees and other revenue		35.1		36.2		(1.1	)	(3%)
Cost of sales and fuel		246.9		273.9		(27.0	)	(10%)
Net margin		93.7		81.3		12.4		15%
Operating costs		38.1		34.4		3.7		11%
Depreciation and amortization		16.2		14.7		1.5		10%
Operating income	$	39.4	$	32.2	$	7.2		22%

Equity earnings from investments	$	6.2	$	5.7	$	0.5		9%
Capital expenditures	$	109.5	$	19.1	$	90.4		*
* Percentage change is greater than 100 percent.

Net margin increased for the three months ended March 31, 2011, compared with the same period last year, primarily as result of the following:

·	an increase of $7.9 million due to higher net realized commodity prices;

·	an increase of $4.1 million due to changes in contract terms; and

·	an increase of $2.8 million due to higher volumes processed in the Williston Basin from increased drilling activity in the Bakken Shale, offsetting reduced drilling activity in certain parts of western Oklahoma and Kansas and weather-related outages; offset partially by

·	a decrease of $2.2 million due to lower volumes gathered as a result of continued production declines and reduced drilling activity by our customers in the Powder River Basin.

Depreciation and amortization increased for the three months ended March 31, 2011, compared with the same period last year, due primarily to the completion of the connection of our western Oklahoma natural gas gathering system to our Maysville natural gas processing facility in central Oklahoma and the completion of well connections and certain infrastructure projects supporting our volume growth in the Williston Basin.

Capital expenditures increased for the three months ended March 31, 2011, compared with the same period last year, due primarily to our growth projects discussed above.

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

	Three Months Ended
	March 31,
Operating Information (a)	2011		2010
Natural gas gathered (BBtu/d)		992		1,092
Natural gas processed (BBtu/d)		641		664
NGL sales (MBbl/d)		44		43
Residue gas sales (BBtu/d)		274		275
Realized composite NGL net sales price ($/gallon) (b)	$	1.09	$	0.99
Realized condensate net sales price ($/Bbl) (b)	$	76.25	$	62.39
Realized residue gas net sales price ($/MMBtu) (b)	$	6.06	$	5.20
Realized gross processing spread ($/MMBtu) (b)	$	8.33	$	6.37
(a) - Includes volumes for consolidated entities only.
(b) - Presented net of the impact of hedging activities and includes equity volumes only.

	Three Months Ended
	March 31,
Operating Information (a)	2011		2010
Percent of proceeds
NGL sales (Bbl/d)		5,759		5,014
Residue gas sales (MMBtu/d)		41,207		38,395
Condensate sales (Bbl/d)		1,953		1,918
Percentage of total net margin		58%		53%
Fee-based
Wellhead volumes (MMBtu/d)		991,778		1,092,061
Average rate ($/MMBtu)	$	0.33	$	0.30
Percentage of total net margin		33%		36%
Keep-whole
NGL shrink (MMBtu/d) (b)		11,971		13,819
Plant fuel (MMBtu/d) (b)		1,347		1,714
Condensate shrink (MMBtu/d) (b)		1,336		1,579
Condensate sales (Bbl/d)		270		320
Percentage of total net margin		9%		11%
(a) - Includes volumes for consolidated entities only.
(b) - Refers to the Btus that are removed from natural gas through processing.

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Commodity Price Risk - The following tables set forth our Natural Gas Gathering and Processing segment’s hedging information for the periods indicated as of May 3, 2011:

	Nine Months Ending
	December 31, 2011
		Volumes Hedged	Average Price			Percentage Hedged
NGLs (Bbl/d) (a)		5,488	$	1.18	/ gallon	66%
Condensate (Bbl/d) (a)		1,648	$	2.14	/ gallon	77%
Total (Bbl/d)		7,136	$	1.40	/ gallon	68%
Natural gas (MMBtu/d)		25,118	$	5.60	/ MMBtu	78%
(a) - Hedged with fixed-price swaps.

	Year Ending
	December 31, 2012
		Volumes Hedged	Average Price			Percentage Hedged
NGLs (Bbl/d) (a)		5,169	$	1.61	/ gallon	47%
Condensate (Bbl/d) (a)		1,819	$	2.43	/ gallon	75%
Total (Bbl/d)		6,988	$	1.82	/ gallon	52%
(a) - Hedged with fixed-price swaps.

	Year Ending
	December 31, 2013
		Volumes Hedged	Average Price			Percentage Hedged
NGLs (Bbl/d) (a)		367	$	2.55	/ gallon	2%
Condensate (Bbl/d) (a)		649	$	2.55	/ gallon	25%
Total (Bbl/d)		1,016	$	2.55	/ gallon	5%
(a) - Hedged with fixed-price swaps.

Our Natural Gas Gathering and Processing segment’s commodity price risk is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at March 31, 2011, 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 $1.3 million;

·	a $1.00 per barrel change in the price of crude oil would change annual net margin by approximately $1.1 million; and

·	a $0.10 per MMBtu change in the price of natural gas would change annual net margin by approximately $1.4 million.

These estimates do not include any effects on demand for our services or changes in operations that we may undertake to compensate for or improve our ability to realize market advantages from periodic price changes. For example, a change in the gross processing spread may cause us to change the amount of ethane we extract from the natural gas stream, impacting 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.

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Natural Gas Pipelines

Overview - Our Natural Gas Pipelines segment primarily owns and operates regulated natural gas transmission pipelines, natural gas storage facilities and natural gas gathering systems for non-processed gas. We also provide interstate natural gas transportation and storage service in accordance with Section 311(a) of the Natural Gas Policy Act of 1978, as amended.

Our FERC-regulated interstate natural gas pipeline assets transport natural gas through pipelines in North Dakota, Minnesota, Wisconsin, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New Mexico. Our interstate pipeline companies include:

·	Midwestern Gas Transmission, which is a bi-directional system that interconnects with Tennessee Gas Transmission Company’s pipeline near Portland, Tennessee, and with several interstate pipelines near Joliet, Illinois;

·	Viking Gas Transmission, which transports natural gas from an interconnection with TransCanada Corporation’s pipeline near Emerson, Manitoba, to an interconnection with ANR Pipeline Company near Marshfield, Wisconsin;

·	Guardian Pipeline, which interconnects with several pipelines near Joliet, Illinois, and with local distribution companies in Wisconsin; and

·	OkTex Pipeline Company, which has interconnects in Oklahoma, New Mexico and Texas.

Our intrastate natural gas pipeline assets in Oklahoma have access to the major natural gas producing areas and transport natural gas throughout the state. We also have access to the major natural gas producing area in south central Kansas. In Texas, our intrastate natural gas pipelines are connected to the major natural gas producing areas in the Texas panhandle and the Permian Basin and transport natural gas to 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, Kansas and Texas, which are connected to our intrastate natural gas pipeline assets.

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

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

	Three Months Ended				Variances
	March 31,				2011 vs. 2010
Financial Results	2011		2010		Increase (Decrease)
	(Millions of dollars)
Transportation revenues	$	62.5	$	65.9	$	(3.4	)	(5%)
Storage revenues		17.4		16.7		0.7		4%
Gas sales and other revenues		4.0		5.0		(1.0	)	(20%)
Cost of sales		8.8		9.0		(0.2	)	(2%)
Net margin		75.1		78.6		(3.5	)	(4%)
Operating costs		27.0		22.8		4.2		18%
Depreciation and amortization		11.3		10.9		0.4		4%
Operating income	$	36.8	$	44.9	$	(8.1	)	(18%)

Equity earnings from investments	$	21.0	$	15.1	$	5.9		39%
Capital expenditures	$	7.6	$	3.2	$	4.4		*
* Percentage change is greater than 100 percent.

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	Three Months Ended
	March 31,
Operating Information (a)	2011		2010
Natural gas transportation capacity contracted (MDth/d) (b)		5,608		5,906
Transportation capacity subscribed		87%		91%
Average natural gas price
Mid-Continent region ($/MMBtu)	$	4.10	$	5.03
(a) - Includes volumes for consolidated entities only.
(b) - Unit of measure converted from MMcf/d in the third quarter of 2010. Prior periods have been recast to reflect this change.

Net margin decreased for the three months ended March 31, 2011, compared with the same period last year, primarily as a result of the following:

·	a decrease of $2.8 million from lower natural gas transportation margins, primarily as a result of lower contracted transportation capacity on Midwestern Gas Transmission and lower interruptible transportation volumes due to narrower natural gas price differentials between the markets we serve; and

·	a decrease of $2.0 million from the impact of lower natural gas prices on our retained fuel positions; offset partially by

·	an increase of $1.4 million due to higher natural gas storage margins, primarily as a result of higher park-and-loan activity due to periods of higher heating and electric demand.

Operating costs increased for the three months ended March 31, 2011, due primarily to higher ad valorem taxes associated with our previously completed capital projects and higher employee-related costs associated with incentive and benefit plans administered by ONEOK.

Equity earnings from investments increased for the three months ended March 31, 2011, compared with the same periods last year, due to increased contracted capacity on Northern Border Pipeline from wider natural gas price differentials between the markets it serves due to strong Midwest market demand.

Natural Gas Liquids

Overview - Our assets consist of facilities that gather, fractionate and treat NGLs and store NGL products primarily in Oklahoma, Kansas and Texas. We own or have an ownership interest in FERC-regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas, Texas, 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 NGLs from unprocessed natural gas, are connected to our gathering systems.

Most natural gas produced at the wellhead contains a mixture of NGL components, such as ethane, propane, iso-butane, normal butane and natural gasoline. Natural gas processing plants remove the NGLs from the natural gas stream to realize the higher economic value of the NGLs and to meet natural gas pipeline-quality specifications, which limit NGLs in the natural gas stream due to liquid and Btu content. 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 fee-based services provided to our customers and physical optimization of our assets. 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 business primarily collects fees to gather, fractionate and treat unfractionated NGLs, thereby converting them into marketable NGL products that are stored and shipped to a market center or customer-designated location;

·	Our optimization and marketing business utilizes our assets, contract portfolio and market knowledge to capture location and seasonal price differentials. We transport NGL products between the Mid-Continent and Gulf Coast

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in order to capture the price differentials between the two market centers. Our natural gas liquids storage facilities are also utilized to capture seasonal price variances;

·	Our pipeline transportation business transports raw NGLs, finished NGL products and refined petroleum products primarily under our FERC-regulated tariffs. Tariffs specify the rates we charge our customers and the general terms and conditions for NGL transportation service on our pipelines;

·	Our isomerization business captures the price differential when normal butane is converted into the more valuable iso-butane at an isomerization unit in Conway, Kansas. Iso-butane is used in the refining industry to increase the octane of motor gasoline; and

·	Our storage business collects fees to store NGLs at our Mid-Continent and Mont Belvieu facilities.

Growth Projects - In addition to the projects announced in May 2011, we announced in 2010 and early 2011 approximately $830 million to $1.0 billion in NGL-related growth projects, primarily in the Williston Basin, Cana-Woodford Shale and Granite Wash areas.

Bakken Pipeline and related projects - We plan to build a 525- to 615-mile natural gas liquids pipeline, the Bakken Pipeline, which will transport unfractionated NGLs from the Bakken Shale to the Overland Pass Pipeline. The Bakken Pipeline will initially have capacity to transport up to 60 MBbl/d of unfractionated NGL production. The unfractionated NGLs will then be delivered to our existing natural gas liquids fractionation and distribution infrastructure in the Mid-Continent. Project costs for the new pipeline are estimated to be $450 million to $550 million, excluding AFUDC.

Supply commitments for the Bakken Pipeline will be anchored by NGL production from our natural gas processing plants. Following receipt of all necessary permits, construction of the 12-inch diameter pipeline is expected to begin in the second quarter of 2012 and be in service during the first half of 2013.

The unfractionated NGLs from the Bakken Pipeline and other supply sources under development in the Rockies will require installing additional pump stations and expanding existing pump stations on the Overland Pass Pipeline. These additions and expansions will increase the capacity of Overland Pass Pipeline to 255 MBbl/d. Our anticipated share of the costs for this project is estimated to be $35 million to $40 million, excluding AFUDC.

Bushton Fractionator Expansion - To accommodate the additional volume from the Bakken Pipeline, we will invest $110 million to $140 million, excluding AFUDC, to expand and upgrade our existing fractionation capacity at Bushton, Kansas, increasing our capacity to 210 MBbl/d from 150 MBbl/d. This project is expected to be in service during the first half of 2013.

Cana-Woodford Shale and Granite Wash projects - We plan to invest approximately $197 million to $257 million, excluding AFUDC, in our existing Mid-Continent infrastructure, primarily in the Cana-Woodford Shale and Granite Wash areas. These investments will expand our ability to transport unfractionated NGLs from these Mid-Continent supply areas to fractionation facilities in Oklahoma and Texas and distribute purity NGL products to the Mid-Continent, Gulf Coast and upper Midwest market centers.

These investments include constructing more than 230 miles of natural gas liquids pipeline that will expand our existing Mid-Continent natural gas liquids gathering system in the Cana-Woodford Shale and Granite Wash areas. The pipeline will connect to three new third-party natural gas processing facilities that are under construction and to three existing third-party natural gas processing facilities that are being expanded. Additionally, we will install additional pump stations on our Arbuckle Pipeline to increase its capacity to 240 MBbl/d. When completed, these projects are expected to add approximately 75 to 80 MBbl/d of unfractionated NGLs to our existing natural gas liquids gathering systems. These projects are expected to be in service during the first half of 2012 and cost approximately $180 million to $240 million, excluding AFUDC.

We invested approximately $17 million to increase the accessibility of new supply to our Arbuckle Pipeline and Mont Belvieu fractionation facilities.

Sterling I Pipeline Expansion - We are installing seven additional pump stations for approximately $36 million, excluding AFUDC, along our existing Sterling I natural gas liquids distribution pipeline, increasing its capacity by 15 MBbl/d, which will be supplied by our Mid-Continent natural gas liquids infrastructure. The Sterling I pipeline transports purity NGL products from our fractionator in Medford, Oklahoma, to the Mont Belvieu, Texas, market center. The pump stations are expected to be in service in the second half of 2011.

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For a discussion of our capital expenditure financing, see “Capital Expenditures” in “Liquidity and Capital Resources” on page 34.

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

	Three Months Ended						Variances
	March 31,						2011 vs. 2010
Financial Results	2011			2010			Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	2,151.9		$	1,770.2		$	381.7		22%
Exchange service and storage revenues		116.9			105.1			11.8		11%
Transportation revenues		17.3			27.2			(9.9	)	(36%)
Cost of sales and fuel		2,125.8			1,798.5			327.3		18%
Net margin		160.3			104.0			56.3		54%
Operating costs		43.9			41.0			2.9		7%
Depreciation and amortization		15.3			18.3			(3.0	)	(16%)
Loss on sale of assets		(0.4	)		(0.8	)		(0.4	)	(50%)
Operating income	$	100.7		$	43.9		$	56.8		*

Equity earnings from investments	$	4.8		$	0.4		$	4.4		*
Capital expenditures	$	27.6		$	15.8		$	11.8		75%
* Percentage change is greater than 100 percent.

	Three Months Ended
	March 31,
Operating Information	2011		2010
NGL sales (MBbl/d) (a)		478		427
NGLs fractionated (MBbl/d) (a)		488		492
NGLs transported-gathering lines (MBbl/d) (a) (b)		397		441
NGLs transported-distribution lines (MBbl/d) (a)		461		467
Conway-to-Mont Belvieu OPIS average price differential
Ethane ($/gallon)	$	0.15	$	0.08
(a) Includes volumes for consolidated entities only.
(b) 2010 volume information includes 96 MBbl/d related to Overland Pass Pipeline Company which is accounted for under the equity method in 2011.

Net margin increased for the three months ended March 31, 2011, compared with the same period last year, primarily as a result of the following:

·	an increase of $56.4 million related to higher optimization margins due to more favorable NGL price differentials and additional fractionation and transportation capacity available for optimization activities between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers;

·	an increase of $8.9 million related to higher gathered volumes, excluding the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company, and contract renegotiations associated with our exchange services; and

·	an increase of $2.9 million due to higher storage margins as a result of contract renegotiations; offset partially by

·	a decrease of $11.9 million due to the deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method.

Operating costs increased for the three months ended March 31, 2011, compared with the same period last year, due primarily to the following:

·	an increase of $2.9 million from higher employee-related costs associated with incentive and benefit plans administered by ONEOK; and

·	an increase of $1.9 million from higher ad valorem taxes; offset partially by

·	a decrease of $2.0 million due to the deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method.

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Depreciation and amortization expense decreased, and equity earnings increased for the three months ended March 31, 2011, compared with the same period last year, due primarily to the deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method.

Capital expenditures increased for the three months ended March 31, 2011, compared with the same period last year, due primarily to our growth projects discussed above.

CONTINGENCIES

Legal Proceedings - We are a party to various litigation matters and claims that are in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or liquidity. Additional information about legal proceedings is included under Part II, Item 1, Legal Proceedings, of this Quarterly Report and under Part I, Item 3, Legal Proceedings, in our Annual Report.

LIQUIDITY AND CAPITAL RESOURCES

General - Part of our strategy is to grow through internally generated growth projects and acquisitions that strengthen and complement our existing assets. We have relied primarily on operating cash flow, commercial paper, bank credit facilities, debt issuances and the sale of common units for our liquidity and capital resources requirements. We fund our operating expenses, debt service and cash distributions to our limited partners and general partner primarily with operating cash flow. Capital expenditures are funded by operating cash flow, short- and long-term debt and issuances of equity. We expect to continue to use these sources for liquidity and capital resource needs on both a short- and long-term basis. We have no guarantees of debt or other similar commitments to unaffiliated parties.

In the first three months of 2011, we utilized our commercial paper program, cash from operations and cash available from the January 2011 debt issuance to fund our short-term liquidity needs. We also used proceeds from our January 2011 debt issuance to fund our capital projects as part of our long-term financing plan. See discussion below under “Debt Issuance and Maturity” 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 anticipate that our cash flow generated from operations, existing capital resources and ability to obtain financing will enable us to maintain our current level of operations and our planned operations, as well as fund our capital expenditures.

Capitalization Structure - The following table sets forth our capital structure for the periods indicated:

	March 31,	December 31,
	2011	2010
Long-term debt	54%	46%
Equity	46%	54%
Debt (including notes payable)	54%	50%
Equity	46%	50%

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

The total amount of short-term borrowings authorized by our general partner’s Board of Directors is $2.5 billion. At March 31, 2011, we had no commercial paper outstanding and no borrowings outstanding under our Partnership Credit Agreement. As a result of our January 2011 debt issuance, available borrowings are limited by the ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in our Partnership Credit Agreement, adjusted for all non-cash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) covenant under our Partnership Credit Agreement; however, we had approximately $617.4 million of cash at March 31, 2011, and $772.0 million of available borrowings to meet our liquidity needs. At March 31, 2011, we had no letters of credit issued outside of our Partnership Credit Agreement.

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Our Partnership Credit Agreement is available to repay the commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowings available under our Partnership Credit Agreement.

Our Partnership Credit Agreement, which expires in March 2012, contains certain financial, operational and legal covenants as discussed in Note F of the Notes to Consolidated Financial Statements in our Annual Report. Among other things, these covenants include maintaining a ratio of indebtedness to adjusted EBITDA of no more than 5 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 three calendar quarters following the acquisitions. Upon breach of certain covenants by us in our Partnership Credit Agreement, amounts outstanding under our Partners Credit Agreement may become due and payable immediately. At March 31, 2011, our ratio of indebtedness to adjusted EBITDA was 4.17 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.

Long-term Financing - In addition to our principal sources of short-term liquidity discussed above, options available to us to meet our longer-term cash requirements include the issuance of 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.

We are 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 negatively affect 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.

Capital Expenditures - Our capital expenditures are financed typically through operating cash flows, short- and long-term debt and the issuance of equity. Capital expenditures were $144.8 million and $35.8 million for the three months ended March 31, 2011 and 2010, respectively. We classify expenditures that are expected to generate additional revenue or significant operating efficiencies as growth capital expenditures. Maintenance capital expenditures are those required to maintain existing operations and do not generate additional revenues.

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The following table summarizes our 2011 projected growth and maintenance capital expenditures, excluding AFUDC:

2011 Projected Capital Expenditures	Growth		Maintenance		Total
	(Millions of dollars)
Natural Gas Gathering and Processing	$	514	$	30	$	544
Natural Gas Pipelines		9		31		40
Natural Gas Liquids		488		43		531
Other		-		1		1
Total projected capital expenditures	$	1,011	$	105	$	1,116

Unconsolidated Affiliates - Northern Border Pipeline anticipates requiring additional equity contributions of approximately $100 million to $120 million from its partners in 2011, of which our share will be approximately $50 million to $60 million based on our 50-percent equity interest.

We expect to make contributions in 2011 and 2012 totaling approximately $35 million to $40 million to Overland Pass Pipeline Company to install additional pump stations and to expand existing pump stations to increase the capacity of the pipeline to accommodate increased volumes of unfractionated NGLs from the Bakken Pipeline and other supply sources under development in the Rockies.

Other - We have certain contractual rights to the Bushton Plant. Our Processing and Services Agreement with ONEOK and OBPI sets out the terms by which OBPI provides services to us at the Bushton Plant through May 2012. We have contracted for all of the capacity of the Bushton Plant from OBPI. In exchange, we pay OBPI for all costs and expenses necessary for operation and maintenance of the Bushton Plant, and we reimburse ONEOK for OBPI’s obligations under equipment leases covering portions of the Bushton Plant. Pursuant to our rights under the Processing and Services Agreement, on April 22, 2011, we directed OBPI to exercise its purchase option for the original leased equipment (or any replacement parts) pursuant to the terms of the equipment leases. Our Processing and Services Agreement provides that we will reimburse OBPI for amounts incurred in connection with the exercised option, and upon reimbursement, we will become the owner of the purchased equipment.

Credit Ratings - Our long-term debt credit ratings as of March 31, 2011, 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 A2 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. We do not anticipate a downgrade in our credit ratings; however, 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. 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.

Cash Distributions - We distribute 100 percent of our available cash, which 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 for 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 interests, during the periods indicated:

	Three Months Ended
	March 31,
	2011		2010
	(Millions of dollars)
Common unitholders	$	74.6	$	65.9
Class B unitholders		41.6		40.1
General partner		31.6		26.0
Total cash distributions paid	$	147.8	$	132.0

In the three months ended March 31, 2011 and 2010, cash distributions paid to our general partner included incentive distributions of $28.6 million and $23.4 million, respectively.

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 may impact 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 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 may not result in actual cash receipts or payments during the period. 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:

	Three Months Ended						Variance
	March 31,						2011 vs. 2010
	2011			2010			Increase (Decrease)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	277.5		$	55.5		$	222.0
Investing activities		(139.7	)		(34.4	)		(105.3	)
Financing activities		478.7			(18.9	)		497.6
Change in cash and cash equivalents		616.5			2.2			614.3
Cash and cash equivalents at beginning of period		0.9			3.2			(2.3	)
Cash and cash equivalents at end of period	$	617.4		$	5.4		$	612.0

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 demand for the end products that are made with our products or increased competition from other service providers, could affect our earnings and operating cash flows.

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Cash flows from operating activities, before changes in operating assets and liabilities, were $191.3 million for the three months ended March 31, 2011, compared with $130.6 million for the same period in 2010. The increase was due primarily to changes in net margin and operating expenses discussed in Financial Results and Operating Information in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Quarterly Report, offset partially by an increase in undistributed earnings from our unconsolidated affiliates.

The changes in operating assets and liabilities increased operating cash flows $86.2 million for the three months ended March 31, 2011, compared with a decrease of $75.1 million for the same period in 2010, due primarily to a decrease in volumes of commodities in storage in the current period compared with an increase in volumes in storage during the same period last year in our Natural Gas Liquids segment.

Investing Cash Flows - Cash used in investing activities increased for the three months ended March 31, 2011, compared with the same period in 2010, due primarily to increased capital expenditures on our growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments.

Financing Cash Flows - Cash provided by financing activities increased during the three months ended March 31, 2011, compared with the same period in 2010. The change is a result of our January 2011 debt issuance, a portion of the proceeds from which were used to repay short-term borrowings and the scheduled maturity of long-term debt. The remainder of the proceeds are used to fund our capital projects and for general partnership purposes. Additionally, we paid increased distributions to our general and limited partners as a result of increased available cash.

REGULATORY

IMPACT OF NEW ACCOUNTING STANDARDS

Information about the impact of new accounting standards is included in Note A of the Notes to Consolidated Financial Statements in this Quarterly Report. ASU 2010-06, “Improving Disclosures about Fair Value Measurements,” is a disclosure only standard, which did not have a material impact. See Note B of the Notes to Consolidated Financial Statements for discussion of our fair value measurements.

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 amount 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 revenues 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 CriticalAccounting Policies,” in our Annual Report.

ENVIRONMENTAL AND SAFETY MATTERS

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

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Pipeline Safety - We are subject to Pipeline and Hazardous Materials Safety Administration regulations, including 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. Currently, Congress is reauthorizing existing pipeline safety legislation, and there are also a number of new bills addressing pipeline safety being considered. Recently, the Pipeline and Hazardous Materials Safety Administration issued an “Advisory Bulletin” regarding maximum allowable operating pressure for gas and hazardous liquids pipelines. This bulletin requests all operators review pipeline records and data to validate existing maximum pressure determinations. We are monitoring activity concerning reauthorization, proposed new legislation and potential changes in the Pipeline and Hazardous Materials Safety Administration’s regulations, to assess the potential impact on our operations. At this time, our review of records relating to maximum pressure determinations is on-going and no revised or new legislation has been enacted resulting in any potential cost, fees or expenses associated with these issues. We cannot provide assurance that existing pipeline safety regulations will not be revised or interpreted in a different manner or that new regulations will not be adopted that could result in increased compliance costs or additional operating restrictions.

Air and Water Emissions - The Clean Air Act, the Clean Water Act and analogous state laws 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 regulate greenhouse gas emissions are under way. We are monitoring federal and state legislation to assess the potential impact on our operations. We estimate our direct greenhouse gas emissions annually as we collect certain greenhouse gas emission data for the previous year. Our most recent estimate indicates that our direct emissions were less than 3.5 million metric tons of carbon dioxide equivalents during 2009. This does not include the carbon dioxide-equivalents of NGLs delivered to certain customers as required by the EPA’s Mandatory Greenhouse Gas Reporting Rule. The EPA’s Mandatory Greenhouse Gas Reporting rule released in September 2009, requires greenhouse gas emissions reporting for affected facilities on an annual basis and requires us to track the emission equivalents for all NGLs delivered to our customers. Our 2010 emissions report is due in September 2011 as a result of the EPA extending the original March 31, 2011 deadline. Also, the EPA has recently released a subpart to the Mandatory Greenhouse Gas Reporting Rule that will require the reporting of vented and fugitive emissions of methane from our facilities. The new requirements began in January 2011, with the first reporting of fugitive emissions due March 31, 2012. We do not expect the cost to gather this emission data to have a material impact on our results of operations, financial position or cash flows. In addition, the United States Congress has considered and may consider in the future legislation to reduce greenhouse gas emissions, including carbon dioxide and methane. At this time, no rule or legislation has been enacted that assess any costs, fees or expense on any of these emissions.

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In addition, the EPA issued a rule on air-quality standards, “National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines,” also known as RICE NESHAP, scheduled to be adopted in 2013. The rule will require capital expenditures over the next three years for the purchase and installation of new emissions-control equipment. We do not expect these expenditures to have a material impact on our results of operations, financial position or cash flows.

Finally, while the TCEQ has been delegated primary responsibility for implementing federal environmental programs under the Clean Air Act and Clean Water Act in Texas, the EPA retains program oversight. Recently, an apparent disagreement has arisen between TCEQ and EPA over key aspects of these Texas regulatory programs (including among others, air and new source review permitting). This disagreement led to increased EPA scrutiny of TCEQ’s environmental permitting decisions and uncertainty about how these programs will be administered in the future.

Superfund - The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or Superfund, imposes liability, without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of a facility where the release occurred and 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 current responsibilities under CERCLA, if any, to 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 were subsequently 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 - Homeland Security’s Transportation Security Administration, along with the United States Department of Transportation, has completed a review and inspection of our “critical facilities” and identified no material security issues.

Environmental Footprint - Our environmental and climate change strategy focuses on taking steps to minimize 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 (iv) following developing technologies to capture carbon dioxide to keep it from reaching the atmosphere.

We participate in the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions. In 2010, we were recognized as the EPA’s “Natural Gas STAR Gathering and Processing Partner of Year” for our efforts to positively address environmental issues through voluntary implementation of emission-reduction opportunities in our Gathering and Processing segment. In addition, we received a Continuing Excellence Award for five years of active participation in the program including consistent reporting of emission-reduction activities by our Natural Gas Pipelines segment. 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 methane gas during pipeline and facility maintenance and operations. Our most recent calculation of our annual lost-and-unaccounted-for natural gas, for all of our business operations, is less than 1 percent of total throughput. We expect to complete our annual estimate for 2010 during the second quarter of 2011 and will post the information on our website when available.

FORWARD-LOOKING STATEMENTS

Some of the statements contained and incorporated in this Quarterly Report are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. The forward-looking statements relate to our anticipated financial performance, liquidity, management’s plans and objectives for our future operations, 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.

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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, environmental compliance, climate change initiatives and authorized rates of recovery of natural gas and natural gas transportation costs;

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

·	difficulties or delays experienced by trucks or pipelines in delivering products to or from our terminals or pipelines;

·	changes in demand for the use of natural gas 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 the OCC, KCC, Texas regulatory authorities or any other local, state or federal regulatory body, including the FERC, the Pipeline and Hazardous Materials Safety Administration and EPA;

·	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;

·	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 and NGLs;

-	competitive conditions in the overall energy market;

-	availability of supplies of Canadian and United States natural gas; and

-	availability of additional storage capacity;

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

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·	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 economy or the risk of delay in growth recovery in the United States economy, including liquidity risks in United States 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 unsold pipeline capacity being greater or less than expected;

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

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

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

·	the impact of potential impairment charges;

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

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

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

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future results. These and other risks are described in greater detail in Part I, Item 1A, Risk Factors, in our Annual Report. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.

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 Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Quarterly Report for information on our hedging activities.

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.

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Changes in Internal Control Over Financial Reporting - There have been no changes in our internal control over financial reporting during the first quarter ended March 31, 2011, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

Information about our legal proceedings is included under Part I, Item 3, Legal Proceedings, in our Annual Report.

ITEM 1A. RISK FACTORS

Our investors should consider the risks set forth in Part I, Item 1A, Risk Factors of our Annual Report that could affect us and our business. Although we have tried to discuss key factors, our investors need to be aware that other risks may prove to be important in the future. New risks may emerge at any time, and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors should carefully consider the discussion of risks and the other information included or incorporated by reference in this Quarterly Report, including “Forward-Looking Statements,” which are included in Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Not Applicable.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

Not Applicable.

ITEM 4.

(REMOVED AND RESERVED)

Not Applicable.

ITEM 5.

OTHER INFORMATION

Not Applicable.

ITEM 6.

EXHIBITS

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

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

Exhibit No. Exhibit Description

31.1

Certification of John W. Gibson pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification of Robert F. Martinovich pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Certification of John W. Gibson 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)).

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32.2

Certification of Robert F. Martinovich 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 documents formatted in XBRL: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three months ended March 31, 2011 and 2010; (iii) Consolidated Balance Sheets at March 31, 2011, and December 31, 2010; (iv) Consolidated Statements of Cash Flows for the three months ended March 31, 2011 and 2010; (v) Consolidated Statement of Changes in Equity for the three months ended March 31, 2011; (vi) Consolidated Statements of Comprehensive Income for the three months ended March 31, 2011 and 2010; and (vii) Notes to Consolidated Financial Statements.

Users of this data are advised pursuant to Rule 401 of Regulation S-T that the information contained in the XBRL documents is unaudited, and these XBRL documents are not the official publicly filed consolidated financial statements of ONEOK Partners, L.P. The purpose of submitting these XBRL formatted documents is to test the related format and technology, and as a result, investors should continue to rely on the official filed version of the furnished documents and not rely on this information in making investment decisions.

In accordance with Rule 402 of Regulation S-T, the XBRL related information in Exhibit 101 to this Quarterly Report shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act or the Exchange Act, except as shall be expressly set forth by specific reference in such filing. We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report.

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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: May 4, 2011
		By: /s/ Robert F. Martinovich Robert F. Martinovich Senior Vice President, Chief Financial Officer and Treasurer (Signing on behalf of the Registrant and as Principal Financial Officer)

ONEOK Partners LP - FORM 10-Q - May 4, 2011

Attached files

ONEOK Partners LP Reports