ONEOK Partners (OKS) 10-Q 2010 Q1 Quarterly report

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, 2010

OR

___ 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 __ 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 22, 2010
Common units	65,413,677 units
Class B 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, 2010 and 2009	5
	Consolidated Balance Sheets - March 31, 2010 and December 31, 2009	6
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2010 and 2009	7
	Consolidated Statement of Changes in Partners’ Equity - Three Months Ended March 31, 2010	8-9
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2010 and 2009	10
	Notes to Consolidated Financial Statements	11-21
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22-38
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38
Item 4.	Controls and Procedures	39
Part II.	Other Information
Item 1.	Legal Proceedings	39
Item 1A.	Risk Factors	39-40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 3.	Defaults Upon Senior Securities	40
Item 4.	(Removed and Reserved)	40
Item 5.	Other Information	40
Item 6.	Exhibits	40-41
Signature		42

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 re asonable 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 1, Item 1A, “Risk Factors,” in our Annual Report.

INFORMATION AVAILABLE ON OUR WEB SITE

We make available on our Web site 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 Web site and any contents thereof are not incorporated by reference into this report.

We also make available on our Web site the Interactive Data Files voluntarily submitted as Exhibit 101 to this Quarterly Report.  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, 2009

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

Clean Air Act Federal Clean Air Act, as amended

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

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

Intermediate Partnership ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary      of ONEOK Partners, L.P.

KCC LIBOR Kansas Corporation Commission London Interbank Offered Rate

MBbl Thousand barrels

MBbl/d Thousand barrels per day

MMBbl Million barrels

MMBtu Million British thermal units

MMBtu/d Million British thermal units per day

MMcf/d Million cubic feet per day

Moody’s Moody’s Investors Service, Inc.

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 Rating Group

SEC Securities and Exchange Commission

Securities Act Securities Act of 1933, as amended

XBRL eXtensible Business Reporting Language

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PART I - FINANCIAL INFORMATION
ITEM 1.  FINANCIAL STATEMENTS
ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
	Three Months Ended
	March 31,
(Unaudited)	2010			2009
	(Thousands of dollars, except per unit amounts)
Revenues	$	2,204,006		$	1,250,865
Cost of sales and fuel		1,942,881			997,324
Net margin		261,125			253,541
Operating expenses
Operations and maintenance		87,205			77,679
Depreciation and amortization		43,871			39,940
General taxes		9,101			11,767
Total operating expenses		140,177			129,386
Gain (loss) on sale of assets		(786	)		664
Operating income		120,162			124,819
Equity earnings from investments (Note I)		21,116			21,222
Allowance for equity funds used during construction		247			9,003
Other income		1,850			391
Other expense		(342	)		(2,046	)
Interest expense		(54,153	)		(50,908	)
Income before income taxes		88,880			102,481
Income taxes		(4,860	)		(2,871	)
Net income		84,020			99,610
Less: Net income attributable to noncontrolling interests		152			19
Net income attributable to ONEOK Partners, L.P.	$	83,868		$	99,591
Limited partners' interest in net income:
Net income attributable to ONEOK Partners, L.P.	$	83,868		$	99,591
General partner's interest in net income		(27,387	)		(22,312	)
Limited partners' interest in net income	$	56,481		$	77,279
Limited partners' net income per unit, basic and diluted (Note J)	$	0.57		$	0.85
Number of units used in computation (thousands)		99,721			90,920
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)	2010		2009
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	5,379	$	3,151
Accounts receivable, net		451,811		624,635
Affiliate receivables		33,935		32,397
Gas and natural gas liquids in storage		219,349		217,585
Commodity imbalances		98,011		188,177
Other current assets		44,802		36,148
Total current assets		853,287		1,102,093
Property, plant and equipment
Property, plant and equipment		6,385,176		6,353,909
Accumulated depreciation and amortization		1,011,304		972,497
Net property, plant and equipment		5,373,872		5,381,412
Investments and other assets
Investments in unconsolidated affiliates		762,435		765,163
Goodwill and intangible assets		666,953		668,870
Other assets		40,822		35,721
Total investments and other assets		1,470,210		1,469,754
Total assets	$	7,697,369	$	7,953,259
Liabilities and partners' equity
Current liabilities
Current maturities of long-term debt	$	486,931	$	261,931
Notes payable (Note E)		310,000		523,000
Accounts payable		519,675		694,290
Affiliate payables		16,983		21,866
Commodity imbalances		245,964		392,688
Other current liabilities		124,732		153,539
Total current liabilities		1,704,285		2,047,314
Long-term debt, excluding current maturities		2,593,157		2,822,086
Deferred credits and other liabilities		79,404		73,798
Commitments and contingencies (Note G)
Partners' equity
ONEOK Partners, L.P. partners’ equity:
General partner		92,602		84,434
Common units: 65,413,677 and 59,912,777 units issued and outstanding at    March 31, 2010 and December 31, 2009, respectively		1,854,011		1,561,762
Class B units: 36,494,126 units issued and outstanding at    March 31, 2010 and December 31, 2009		1,361,205		1,380,299
Accumulated other comprehensive income (loss) (Note D)		7,318		(22,037	)
Total ONEOK Partners, L.P. partners' equity		3,315,136		3,004,458
Noncontrolling interests in consolidated subsidiaries		5,387		5,603
Total partners' equity		3,320,523		3,010,061
Total liabilities and partners' equity	$	7,697,369	$	7,953,259
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)		2010			2009
	(Thousands of dollars)
Operating activities
Net income		$	84,020		$	99,610
Depreciation and amortization			43,871			39,940
Allowance for equity funds used during construction			(247	)		(9,003	)
Loss (gain) on sale of assets			786			(664	)
Deferred income taxes			1,239			1,706
Equity earnings from investments			(21,116	)		(21,222	)
Distributions received from unconsolidated affiliates			21,998			25,187
Changes in assets and liabilities:
Accounts receivable			172,824			11,224
Affiliate receivables			(1,538	)		4,880
Gas and natural gas liquids in storage			(1,764	)		44,641
Accounts payable			(168,406	)		(65,065	)
Affiliate payables			(4,883	)		(4,961	)
Commodity imbalances, net			(56,558	)		(59,078	)
Accrued interest			23,045			33,555
Other assets and liabilities			(37,792	)		(25,974	)
Cash provided by operating activities			55,479			74,776
Investing activities
Changes in investments in unconsolidated affiliates			1,334			3,362
Capital expenditures (less allowance for equity funds used during construction)			(35,827	)		(192,494	)
Proceeds from sale of assets			138			1,083
Cash used in investing activities			(34,355	)		(188,049	)
Financing activities
Cash distributions:
General and limited partners			(132,086	)		(120,932	)
Noncontrolling interests			(368	)		(343	)
Borrowing (repayment) of notes payable, net			(213,000	)		36,700
Repayment of notes payable with maturities over 90 days			-			(470,000	)
Issuance of long-term debt, net of discounts			-			498,325
Long-term debt financing costs			-			(4,000	)
Repayment of long-term debt			(2,983	)		(2,983	)
Issuance of common units, net of discounts			322,721			-
Contribution from general partner			6,820			-
Cash used in financing activities			(18,896	)		(63,233	)
Change in cash and cash equivalents			2,228			(176,506	)
Cash and cash equivalents at beginning of period			3,151			177,635
Cash and cash equivalents at end of period		$	5,379		$	1,129
See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY
	ONEOK Partners, L.P. Partners' Equity
	Common		Class B		General			Common
(Unaudited)	Units		Units		Partner			Units
	(Units)				(Thousands of dollars)
December 31, 2009		59,912,777		36,494,126	$	84,434		$	1,561,762
Net income		-		-		27,387			35,432
Other comprehensive income (Note D)		-		-		-			-
Issuance of common units (Note F)		5,500,900		-		-			322,721
Contribution from general partner (Note F)		-		-		6,820			-
Distributions paid (Note F)		-		-		(26,039	)		(65,904	)
March 31, 2010		65,413,677		36,494,126	$	92,602		$	1,854,011
See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY
(Continued)
	ONEOK Partners, L.P. Partners' Equity
				Accumulated			Noncontrolling
				Other			Interests in
	Class B			Comprehensive			Consolidated			Total Partners'
(Unaudited)	Units			Income (Loss)			Subsidiaries			Equity
	(Thousands of dollars)
December 31, 2009	$	1,380,299		$	(22,037	)	$	5,603		$	3,010,061
Net income		21,049			-			152			84,020
Other comprehensive income (Note D)		-			29,355			-			29,355
Issuance of common units (Note F)		-			-			-			322,721
Contribution from general partner (Note F)		-			-			-			6,820
Distributions paid (Note F)		(40,143	)		-			(368	)		(132,454	)
March 31, 2010	$	1,361,205		$	7,318		$	5,387		$	3,320,523

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	Three Months Ended
	March 31,
(Unaudited)	2010		2009
	(Thousands of dollars)
Net income	$	84,020	$	99,610
Other comprehensive income (loss) (Note D)		29,355		(19,199	)
Comprehensive income		113,375		80,411
Less: Comprehensive income attributable to noncontrolling interests		152		19
Comprehensive income attributable to ONEOK Partners, L.P.	$	113,223	$	80,392
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 2009 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.

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

Recently Issued Accounting Updates

The following recently issued accounting standards updates affect our consolidated financial statements and related disclosures:

Fair Value Measurements and Disclosures - In January 2010, the FASB issued ASU 2010-06, “Improving Disclosures about Fair Value Measurements,” which established new disclosure requirements and clarified existing requirements for disclosures of fair value measurements.  ASU 2010-06 required us to add two new disclosures, when applicable: (i) transfers in and out of Level 1 and 2 fair value measurements including the reasons for the transfers, and (ii) a gross presentation of activity within the reconciliation of Level 3 fair value measurements.  Except for separate disclosure of purchases, sales, issuances and settlements in the reconciliation of our Level 3 fair value measurements, we applied this guidance to our disclosures beginning with this Quarter ly Report.  The separate disclosure of purchases, sales, issuances and settlements will be required beginning with our March 31, 2011, Quarterly Report, and we do not expect the impact to be material.  ASU 2010-06 requires prospective application in the period of adoption, and we have not recast our prior-year disclosures.  See Note B for more discussion of our fair value measurements.

Embedded Credit Derivatives - In March 2010, the FASB issued ASU 2010-11, “Scope Exception Related to Embedded Credit Derivatives,” which clarified that disclosures required for credit derivatives do not apply to an embedded derivative’s feature related to the transfer of credit risk that is only in the form of subordination of one financial instrument to another.  This guidance will be effective for our September 30, 2010, Quarterly Report and will be applied prospectively.  We are currently reviewing the applicability of ASU 2010-11 to our consolidated financial statements and related disclosures.

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 u tilize 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 U.S. Treasury 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, 2010
	Level 1		Level 2			Level 3			Total - Gross			Netting (a)			Total - Net
	(Thousands of dollars)
Derivatives - Commodity
Assets - Over-the-counter    Financial Contracts  (b)	$	-	$	18,895		$	2,588		$	21,483		$	(10,197	)	$	11,286
Liabilities  - Over-the-counter    Financial Contracts	$	-	$	(5,277	)	$	(4,920	)	$	(10,197	)	$	10,197		$	-
	December 31, 2009
	Level 1		Level 2			Level 3			Total - Gross			Netting (a)			Total - Net
	(Thousands of dollars)
Derivatives - Commodity
Assets	$	-	$	459		$	-		$	459		$	(459	)	$	-
Liabilities (c)	$	-	$	(5,720	)	$	(13,052	)	$	(18,772	)	$	459		$	(18,313	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheet 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 in our Consolidated Balance Sheet.
(c) - Included in other current liabilities in our Consolidated Balance Sheet.

At March 31, 2010, and December 31, 2009, we had no cash collateral held or posted under our master-netting arrangements.

We categorize derivatives for which fair value is determined using multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety.

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 purity NGL products and natural gas basis swaps.  These swaps 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 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.  We do not believe that our derivative instruments categorized as Level 3 have a material impact on our results of operations, as the majority of our derivatives are accounted for as cash flow hedges for which ineffectiveness is not material.

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)	2010			2009
	(Thousands of dollars)
Net assets (liabilities) at beginning of period	$	(13,052	)	$	37,649
Total realized/unrealized gains (losses):
Included in earnings (a)		-			1,104
Included in other comprehensive income (loss)		10,720			(12,758	)
Net assets (liabilities) at end of period	$	(2,332	)	$	25,995
(a) - Included in revenues in our Consolidated Statements of Income.

The change in our Level 3 fair value measurements is due to the execution of new hedge transactions during the period, as well as changes in commodity prices.  Realized/unrealized gains (losses) include the realization of our fair value derivative contracts through maturity.

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Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable and accounts payable is equal to book value, due to the short-term nature of these items.  The fair value of borrowings under our Partnership Credit Agreement approximates the carrying value since the interest rates are periodically adjusted to reflect current market conditions.

The estimated fair value of the aggregate of our senior notes outstanding, including current maturities, was $3.3 billion at March 31, 2010, and at December 31, 2009.  The book value of the aggregate of our senior notes outstanding, including current maturities, was $3.1 billion at March 31, 2010, and at December 31, 2009.  The estimated fair value of the aggregate of our senior notes outstanding has been determined using quoted market prices for 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 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 processing 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 uti lize a portion of our POP equity natural gas 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 collect 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, 2010, and December 31, 2009, we were not using any 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 fixed-price physical forward contracts to reduce the impact of price fluctuations related to NGLs.  At March 31, 2010, and December 31, 2009, we were not using any financial derivative instruments with respect to our NGL activities.

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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, 2010, and December 31, 2009, 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

We formally document all relationships between hedging instruments and hedged items, as well as risk management objectives, strategies for undertaking various hedge transactions and methods for assessing and testing correlation and hedge ineffectiveness.  We specifically identify the forecasted transaction that has been designated as the hedged item with a cash flow hedge.  We assess the effectiveness of hedging relationships quarterly by performing a regression 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.

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.

Fair Values of Derivative Instruments -See Note B for the fair values of our derivative instruments and a discussion of the inputs associated with our fair value measurements.

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

					March 31,		December 31,
				Contract	2010		2009
				Type	Receiver		Receiver
Derivatives designated as hedging instruments:
	Cash flow hedges
		Fixed price
			- Natural gas (Bcf)	Swaps		13.4	9.2
			- Crude oil and NGLs (MMBbl)	Swaps		2.4	2.4
		Basis
			- Natural gas (Bcf)	Swaps		13.4	9.2

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Cash Flow Hedges - At March 31, 2010, our Consolidated Balance Sheet reflected a net unrealized gain of $11.4 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 current levels, we will recognize $5.0 million in gains over the next 12 months, and we will recognize $6.4 million in gains thereafter.

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

	Three Months Ended
Derivatives in Cash Flow Hedging Relationships	March 31,
	2010		2009
	(Thousands of dollars)
Commodity contracts	$	24,707	$	(331	)
Interest rate contracts		-		121
Total gain (loss) recognized in other comprehensive    income (loss) (effective portion)	$	24,707	$	(210	)

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)	2010			2009
		(Thousands of dollars)
Commodity contracts	Revenues	$	(4,869	)	$	18,765
Interest rate contracts	Interest expense		221			436
Total gain (loss) reclassified from accumulated other comprehensive    income (loss) into net income (effective portion)		$	(4,648	)	$	19,201

Ineffectiveness related to our cash flow hedges was not material for the three months ended March 31, 2010 and 2009.  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, 2010 and 2009.

Fair Value Hedges - In prior years, we terminated various interest-rate swap agreements.  The net savings from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged.  Interest expense savings from the amortization of terminated swaps for the three months ended March 31, 2010 and 2009, were not material, and the remaining amortization of terminated swaps will be recognized over the following periods.

	(Millions of dollars)
Remainder of 2010		$	2.8
2011		$	0.9

Credit Risk - All the commodity derivative contracts we enter into are withONEOK Energy Services Company, L.P. (OES), a subsidiary of ONEOK.  OES enters into similar commodity derivative 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 they may incur solely as a result of its entering into commodity derivative contracts on our behalf.  Derivative assets for which we would indemnify OES in the event of a default by the counterparty totaled $11.3 million at March 31, 2010, and were with investment-grade counterparties that are primarily in the oil and gas and financial servic es sectors.  At December 31, 2009, there were no derivative assets for which we would indemnify OES in the event of a default by the counterparty.

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D.           OTHER COMPREHENSIVE INCOME (LOSS)

The following table sets forth other comprehensive income (loss) for the periods indicated:

		Three Months Ended
		March 31,
		2010		2009
		(Thousands of dollars)
Unrealized gains (losses) on derivatives	$	24,707	$	(210)
Less:  Realized gains (losses) on derivatives recognized in net income		(4,648)		19,201
Other		-		212
Other comprehensive income (loss)	$	29,355	$	(19,199)

The balance in accumulated other comprehensive income in our Consolidated Balance Sheets as of March 31, 2010, and December 31, 2009, was attributable to unrealized gains and losses on derivatives.

E.           CREDIT FACILITIES

Our Partnership Credit Agreement, which expires in March 2012, contains certain financial, operational and legal covenants.  Among other things, these requirements 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 be increased to 5.5 to 1 for the three calendar quarters following the acquisitions.  At March 31, 2010, our ratio of indebtedness to adjusted EBITDA was 4.3 to 1, and we were in compliance with all covenants under our Pa rtnership Credit Agreement.

At March 31, 2010, and December 31, 2009, we had $310 million and $523 million, respectively, of borrowings outstanding under our Partnership Credit Agreement, and under the most restrictive provisions of our Partnership Credit Agreement had $558 million and $367 million of credit available, respectively.  At March 31, 2010, and December 31, 2009, we had a total of $24.2 million issued in letters of credit outside of the Partnership Credit Agreement.  Borrowings under our Partnership Credit Agreement are nonrecourse to our general partner.

Borrowings under our Partnership Credit Agreement are typically short term in nature, ranging from one day to six months.  Accordingly, these borrowings are classified as short-term notes payable.

F.           PARTNERS’ EQUITY

ONEOK -ONEOK and its affiliates 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, 2010.

Equity Issuance - In February 2010, we completed an underwritten public offering of 5,500,900 common units, including the partial exercise by the underwriters of their over-allotment option, at a public offering price of $60.75 per common unit, generating net proceeds of approximately $322.7 million.  In conjunction with the offering, ONEOK Partners GP contributed $6.8 million in order to maintain its 2 percent general partner interest in us.  We used the proceeds from the sale of common units and the general partner contribution to repay borrowings under our Partnership Credit Agreement and for general partnership purposes.

Cash Distributions - Cash distributions paid to our general partner of $26.0 million and $22.7 million in the three months ended March 31, 2010 and 2009, respectively, included incentive distributions of $23.4 million and $20.3 million, respectively.

In April 2010, our general partner declared a cash distribution of $1.11 per unit ($4.44 per unit on an annualized basis) for the first quarter of 2010, an increase of $0.01 from the previous quarter, which will be paid on May 14, 2010, to unitholders of record at the close of business on April 30, 2010.

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G.           COMMITMENTS AND CONTINGENCIES

Environmental Liabilities -We are subject to multiple environmental, historical and wildlife preservation laws and 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 interruption s 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 materially affect 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.

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, 2010 or 2009.

The EPA is proposing to finalize the “Tailoring Rule” that will regulate greenhouse gas emissions at certain facilities that emit more than 25,000 tons of greenhouse gas emissions per year.  Under the Prevention of Significant Deterioration requirement for existing facilities, upon making a major modification to a facility, the facility would be required to obtain permits that demonstrate it has installed the best available technology to control greenhouse gas emissions.  The rule is expected to be phased in beginning January 2011 and could impact some of our facilities.  At this time, potential costs, fees or expenses associated with the proposed “Tailoring Rule” are unknown.

In addition, the EPA has issued a proposed 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 early 2013.  The proposed 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.

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.

Overland Pass Pipeline Company - Overland Pass Pipeline Company is a joint venture between us and a subsidiary of The Williams Companies, Inc. (Williams).  We own 99 percent of the joint venture and operate the pipeline.  On or before November 17, 2010, Williams has the option to increase its ownership in Overland Pass Pipeline Company up to a total of 50 percent, with the purchase price being determined in accordance with the joint venture’s operating agreement.  If Williams exercises its option to increase its ownership to 50 percent, Williams would have the option to become operator.  Should Williams exercise its option to obtain a 50 percent ownership interest, we may be required to deconsolidate Overland Pass Pipeline Company and acc ount for it under the equity method of accounting.

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H.           SEGMENTS

Segment Descriptions - We implemented changes to the structure of our previous reportable business segments during the third quarter of 2009 to better align them with how we manage our businesses.  Our financial results are now reported in these three segments: (i) Natural Gas Gathering and Processing; (ii) Natural Gas Pipelines, both of which remain unchanged; and (iii) Natural Gas Liquids, which consolidates our former natural gas liquids gathering and fractionation segment with our former natural gas liquids pipelines segment, due to the integrated manner in which they are managed.  Prior-period amounts have been recast to reflect these segment changes.

Our operations are divided into three reportable business segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment, 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 M 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.

Customers - For the three months ended March 31, 2010 and 2009, we had no single unaffiliated customer from which we received 10 percent or more of our consolidated revenues.

For the three months ended March 31, 2010, sales to affiliated customers were less than 10 percent.  For the three months ended March 31, 2009, sales to affiliated customers were 12 percent of our consolidated revenues.  See Note K for additional information about our sales to affiliated customers.

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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, 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.

Three Months Ended March 31, 2009	Natural Gas Gathering and Processing			Natural Gas Pipelines (a)		Natural Gas Liquids (b)			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	62,146		$	48,717	$	995,866		$	1		$	1,106,730
Sales to affiliated customers		118,207			25,928		-			-			144,135
Intersegment revenues		69,890			147		5,095	��		(75,132	)		-
Total revenues	$	250,243		$	74,792	$	1,000,961		$	(75,131	)	$	1,250,865
Net margin	$	86,052		$	65,568	$	102,591		$	(670	)	$	253,541
Operating costs		31,828			20,180		37,627			(189	)		89,446
Depreciation and amortization		14,448			12,793		12,697			2			39,940
Gain (loss) on sale of assets		(19	)		27		3			653			664
Operating income	$	39,757		$	32,622	$	52,270		$	170		$	124,819
Equity earnings from investments	$	4,466		$	16,208	$	548		$	-		$	21,222
Capital expenditures	$	28,818		$	17,428	$	146,248		$	-		$	192,494
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $61.6 million, net margin of $51.7 million and operating income of $23.3 million.
(b) - Our Natural Gas Liquids segment has regulated and non-regulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $57.9 million, of which $33.7 million related to sales within the segment, net margin of $43.8 million and operating income of $22.0 million.

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I.           UNCONSOLIDATED AFFILIATES

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

	Three Months Ended
	March 31,
	2010		2009
	(Thousands of dollars)
Northern Border Pipeline	$	14,846	$	16,038
Bighorn Gas Gathering, L.L.C.		237		2,086
Fort Union Gas Gathering, L.L.C.		3,558		2,210
Lost Creek Gathering Company, L.L.C.		1,402		890
Other		1,073		(2	)
Equity earnings from investments	$	21,116	$	21,222

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,
		2010		2009
	(Thousands of dollars)
Income Statement
Operating revenues		$	99,231	$	106,066
Operating expenses		$	44,715	$	44,803
Net income		$	46,911	$	50,516
Distributions paid to us		$	23,529	$	33,331

Distributions paid to us are classified as operating activities on our Consolidated Statements of Cash Flows until the cumulative distributions exceed our proportionate share of income from the unconsolidated affiliate since the date of our initial investment.  The amount of cumulative distributions paid to us that exceeds our cumulative proportionate share of income in each period represents a return of investment and is classified as an investing activity on our Consolidated Statement of Cash Flows.  Distributions paid to us include a $1.5 million and $8.1 million return of investment for the three months ended March 31, 2010 and 2009, respectively. 

J.           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.  ONEOK, as sole holder of our Class B units, has waived its right to receive increased quarterly distributions on the Class B 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 retains the option to withdraw its waiver at any time by giving us no less than 90 days advance notice.  ONEOK Partners GP own s 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 $25.7 million and $20.3 million for the three months ended March 31, 2010 and 2009, 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.  Gains resulting from interim capital transactions, as defined in our Partnership Agreement, are generally not subject to distribution; however, our Partnership Agreement provides that if such distributions were made, the incentive

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distribution rights would not apply.  For additional information regarding our general partner’s incentive distribution rights, see Note J of the Notes to Consolidated Financial Statements in our Annual Report.

K.           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 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 the operation and maintenance of the Bushton Plant, and we reimburse ONEOK for a portion of OBPI’s obligations under equipment leases covering the Bushton Plant.

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 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, administrative services, insurance and office space leased in ONEOK’s headquarters building and other field locations.  Where costs are specifically incurred 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 allo cated by the modified Distrigas method, a method using a combination of ratios that include gross plant and investment, earnings before interest and taxes 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 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,
		2010		2009
	(Thousands of dollars)
Revenues		$	136,931	$	144,135
Expenses
Cost of sales and fuel		$	17,759	$	16,638
Administrative and general expenses			51,025		48,623
Total expenses		$	68,784	$	65,261

Cash Distributions to ONEOK - We paid cash distributions to ONEOK and its subsidiaries related to its general and limited partner interests of $72.7 million and $68.5 million in the three months ended March 31, 2010 and 2009, respectively.

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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.

EXECUTIVE SUMMARY

Outlook - We expect a moderate economic recovery in 2010, with inflationary pressures beginning in 2011.  Although recent volatility in the financial markets could limit our access to financial markets on a timely basis or increase our cost of capital in the future, we anticipate improved credit markets during 2010, compared with 2009; however, inflation risks may increase the cost of capital.  We anticipate the consolidation of underperforming assets in the industry, particularly those with high commodity price exposure and/or high levels of debt.  Additionally, we anticipate an improving commodity price environment during 2010, compared with 2009. 

Recent Developments - In April 2010, we announced that we will invest approximately $405 million to $470 million for projects in the Bakken Shale in the Williston Basin in North Dakota and in the Woodford Shale in Oklahoma, which will enable us to meet the rapidly growing needs of producers in these areas.  These investments include construction of a new 100 MMcf/d natural gas processing facility, the Garden Creek plant, in eastern McKenzie County, North Dakota.  The plant and related expansions are estimated to cost between $150 million and $210 million and will double our natural gas processing capacity in the Williston Basin.  These projects are expected to be completed in the fourth quarter of 2011.  In addition, we will invest an additiona l $200 million to $205 million during 2010 and 2011 for new well connections, expansions and upgrades to our existing natural gas gathering infrastructure in the Bakken Shale.

We will invest an additional $55 million in the Woodford Shale in Oklahoma for new well connections in 2010 and 2011 and to connect our existing gathering system to our existing Maysville, Oklahoma, natural gas processing facility as well as the connection of a new plant to our NGL gathering system.

Equity Issuance - In February 2010, we completed an underwritten public offering of 5,500,900 common units, including the partial exercise by the underwriters of their over-allotment option, at a public offering price of $60.75 per common unit, generating net proceeds of approximately $322.7 million.  In conjunction with the offering, ONEOK Partners GP contributed $6.8 million in order to maintain its 2 percent general partner interest in us.  We used the proceeds from the sale of common units and the general partner contribution to repay borrowings under our Partnership Credit Agreement and for general partnership purposes.  As a result of these transactions, ONEOK and its subsidiaries own a 42.8 percent aggregate equity interest in us.

Cash Distributions - In April 2010, our general partner declared a cash distribution of $1.11 per unit ($4.44 per unit on an annualized basis) for the first quarter of 2010, an increase of $0.01 from the previous quarter, which will be paid May 14, 2010, to unitholders of record at the close of business on April 30, 2010.

Segment Realignment - We implemented changes to the structure of our previous reportable business segments during the third quarter of 2009 to better align them with how we manage our businesses.  Our financial results are now reported in these three segments: (i) Natural Gas Gathering and Processing; (ii) Natural Gas Pipelines, both of which remain unchanged; and (iii) Natural Gas Liquids, which consolidates our former natural gas liquids gathering and fractionation segment with our former natural gas liquids pipelines segment, due to the integrated manner in which they are managed.  Prior-period amounts have been recast to reflect these segment changes.

Operating Results - Limited partners’ net income per unit decreased to $0.57 for the three months ended March 31, 2010, compared with $0.85 for the same period in 2009.  The decrease in limited partners’ net income per unit for the three-month period ending March 31, 2010, is due primarily to the following:

·   an increase in operating costs resulting from the operation of our recently completed capital projects and higher employee-related costs;

·   a decrease in allowance for equity funds used during construction due to the completion of the Arbuckle Pipeline, Piceance lateral and D-J Basin lateral in our Natural Gas Liquids segment; and

·   an increase in the number of common units outstanding; offset partially by

·   an increase in net margin due primarily to:

-   higher NGL volumes gathered, fractionated and transported, associated with the completion of the Arbuckle Pipeline, Piceance lateral and D-J Basin lateral, as well as new NGL supply connections in our Natural Gas Liquids segment;

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-   higher natural gas transportation margins from the Guardian Pipeline expansion and extension that was completed in February 2009 and an increase in volumes contracted on Midwestern Gas Transmission in our Natural Gas Pipelines segment; offset partially by

-   lower optimization margins due to less NGL fractionation and transportation capacity available for optimization in our Natural Gas Liquids segment;

-   the impact of operational measurement gains and losses as compared with the same period last year; and

-   lower gathered volumes, primarily in the Powder River Basin of Wyoming, and a favorable contract settlement recognized in the first quarter of 2009 in our Natural Gas Gathering and Processing segment.

IMPACT OF NEW ACCOUNTING STANDARDS

Information about the impact of new accounting standards is included in Note Aof the Notes to Consolidated Financial Statements in this Quarterly Report:

·   ASU 2010-06, “Improving Disclosures about Fair Value Measurements,” which did not have a material impact on our consolidated financial statements and related disclosures.  See Note B of the Notes to Consolidated Financial Statements for discussion of our fair value measurements; and

·   ASU 2010-11, “Scope Exception Related to Embedded Credit Derivatives,” which will be effective for our September 30, 2010, Quarterly Report and will be applied prospectively.  We are currently reviewing the applicability of ASU 2010-11 to our consolidated financial statements and related disclosures.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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, “Critical Accounting Estimates,” in our Annual Report.

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FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

Selected Financial Results - The following table sets forth certain selected consolidated financial results for the periods indicated:

	Three Months Ended						Variances
	March 31,						2010 vs. 2009
Financial Results	2010			2009			Increase (Decrease)
	(Millions of dollars)
Revenues	$	2,204.0		$	1,250.9		$	953.1		76	%
Cost of sales and fuel		1,942.9			997.4			945.5		95	%
Net margin		261.1			253.5			7.6		3	%
Operating costs		96.2			89.5			6.7		7	%
Depreciation and amortization		43.9			39.9			4.0		10	%
Gain (loss) on sale of assets		(0.8	)		0.7			(1.5	)		*
Operating income	$	120.2		$	124.8		$	(4.6	)	(4	%)
Equity earnings from investments	$	21.1		$	21.2		$	(0.1	)	(0	%)
Allowance for equity funds used      during construction	$	0.2		$	9.0		$	(8.8	)	(98	%)
Interest expense	$	(54.2	)	$	(50.9	)	$	3.3		6	%
Capital expenditures	$	35.8		$	192.5		$	(156.7	)	(81	%)
* Percentage change is greater than 100 percent.

Energy markets were affected by increased commodity prices during the three months ended March 31, 2010, compared with the same period last year.  The increase in commodity prices had a direct impact on our revenues and cost of sales and fuel.  Net margin increased for the three months ended March 31, 2010, compared with the same period last year, due to the following:

·   higher NGL volumes gathered, fractionated and transported, associated with the completion of the Arbuckle Pipeline, Piceance lateral and D-J Basin lateral, as well as new NGL supply connections in our Natural Gas Liquids segment;

·   higher natural gas transportation margins from the Guardian Pipeline expansion and extension that was completed in February 2009 and an increase in volumes contracted on Midwestern Gas Transmission in our Natural Gas Pipelines segment; offset partially by

·   lower optimization margins due to less NGL fractionation and transportation capacity available for optimization in our Natural Gas Liquids segment;

·   the impact of operational measurement gains and losses as compared with the same period last year; and

·   lower gathered volumes, primarily in the Powder River Basin of Wyoming, and a favorable contract settlement recognized in the first quarter of 2009 in our Natural Gas Gathering and Processing segment.

Operating costs increased for the three months ended March 31, 2010, compared with the same period last year, due primarily to the operation of our recently completed capital projects and higher employee-related costs.

Depreciation and amortization increased for the three months ended March 31, 2010, compared with the same period last year, due primarily to higher depreciation expense associated with our completed capital projects.

Allowance for equity funds used during construction decreased for the three months ended March 31, 2010, compared with the same period last year, due to the completion of the Arbuckle Pipeline, Piceance lateral and D-J Basin lateral.

Capital expenditures decreased for the three months ended March 31, 2010, compared with the same period last year, due primarily to the completion of our capital projects discussed in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, of our Annual Report.

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 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 the Powder River Basin of Wyoming.  The natural gas we gather in the Powder River Basin of Wyoming is coal-bed methane, or dry gas, that does not require processing or NGL extraction, in order to be marketable; dry gas is gathered, compressed and d elivered 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 fractionated, through the application of heat and pressure, and separated into NGL products.  Our natural gas and N GL products are sold to affiliates and a diverse customer base.  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 the 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.

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,				2010 vs. 2009
Financial Results		2010		2009		Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales		$	187.1	$	117.8	$	69.3		59	%
Residue gas sales			131.9		92.0		39.9		43	%
Gathering, compression, dehydration   and processing fees and other revenue			36.2		40.5		(4.3	)	(11	%)
Cost of sales and fuel			273.9		164.2		109.7		67	%
Net margin			81.3		86.1		(4.8	)	(6	%)
Operating costs			34.4		31.8		2.6		8	%
Depreciation and amortization			14.7		14.5		0.2		1	%
Operating income		$	32.2	$	39.8	$	(7.6	)	(19	%)
Equity earnings from investments		$	5.7	$	4.5	$	1.2		27	%
Capital expenditures		$	19.1	$	28.8	$	(9.7	)	(34	%)

Net margin decreased for the three months ended March 31, 2010, compared with the same period last year, primarily as result of lower gathered volumes, primarily in the Powder River Basin of Wyoming, and a favorable contract settlement recognized in the first quarter of 2009.

Operating costs increased for the three months ended March 31, 2010, compared with the same period last year, primarily as a result of higher employee-related costs.

Capital expenditures decreased for the three months ended March 31, 2010, compared with the same period last year, due to the completion of our capital projects.

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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	2010		2009
Natural gas gathered (BBtu/d) (a)		1,092		1,163
Natural gas processed (BBtu/d) (a)		664		653
NGL sales (MBbl/d) (a)		43		41
Residue gas sales (BBtu/d) (a)		275		285
Realized composite NGL net sales price ($/gallon) (b)	$	0.99	$	0.88
Realized condensate net sales price ($/Bbl) (b)	$	62.39	$	68.45
Realized residue gas net sales price ($/MMBtu) (b)	$	5.20	$	3.58
Realized gross processing spread ($/MMBtu) (a)	$	6.37	$	7.43
(a) - Includes volumes for consolidated entities only.
(b) - Includes equity volumes only.

	Three Months Ended
	March 31,
Operating Information (a)	2010		2009
Percent of proceeds
Wellhead purchases (MMBtu/d)		44,586		60,496
NGL sales (Bbl/d)		5,014		5,040
Residue gas sales (MMBtu/d)		38,395		34,819
Condensate sales (Bbl/d)		1,918		2,095
Percentage of total net margin		53%		50%
Fee-based
Wellhead volumes (MMBtu/d)		1,092,061		1,163,376
Average rate ($/MMBtu)	$	0.30	$	0.28
Percentage of total net margin		36%		35%
Keep-whole
NGL shrink (MMBtu/d)		13,819		16,960
Plant fuel (MMBtu/d)		1,714		2,182
Condensate shrink (MMBtu/d)		1,579		1,755
Condensate sales (Bbl/d)		320		355
Percentage of total net margin		11%		15%
(a) - Includes volumes for consolidated entities only.

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Commodity Price Risk - The following tables set forth our Natural Gas Gathering and Processing segment’s hedging information for the remainder of 2010 and for the year ending December 31, 2011, as of April 28, 2010.

	Nine Months Ending
	December 31, 2010
	Volumes Hedged		Average Price				Percentage Hedged
NGLs (Bbl/d) (a)		5,261		$	1.04	/ gallon		68%
Condensate (Bbl/d) (a)		1,648		$	1.81	/ gallon		76%
Total (Bbl/d)		6,909		$	1.22	/ gallon		70%
Natural gas (MMBtu/d)		26,504		$	5.60	/ MMBtu		81%
(a) - Hedged with fixed-price swaps.

	Year Ending
	December 31, 2011
	Volumes Hedged		Average Price				Percentage Hedged
NGLs (Bbl/d) (a)		902		$	1.34	/ gallon		13%
Condensate (Bbl/d) (a)		596		$	2.12	/ gallon		26%
Total (Bbl/d)		1,498		$	1.65	/ gallon		16%
Natural gas (MMBtu/d)		16,616		$	6.29	/ MMBtu		43%
(a) - Hedged with fixed-price swaps.

Our Natural Gas Gathering and Processing segment’s commodity price risk related to physical sales of commodities is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at March 31, 2010, 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 decrease in the composite price of NGLs would decrease annual net margin by approximately $1.1 million;

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

·   a $0.10 per MMBtu decrease in the price of natural gas would decrease annual net margin by approximately $1.2 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.

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 interstate natural gas pipeline assets transport natural gas through FERC-regulated interstate natural gas 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 a TransCanada Corporation pipeline near Emerson, Manitoba, to an interconnection with ANR Pipeline Company near Marshfield, Wisconsin;

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

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·   OkTex Pipeline, which has interconnections 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.

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 ser vices.

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,				2010 vs. 2009
Financial Results		2010		2009		Increase (Decrease)
	(Millions of dollars)
Transportation revenues		$	65.9	$	56.6	$	9.3		16	%
Storage revenues			16.7		14.3		2.4		17	%
Gas sales and other revenues			5.0		3.9		1.1		28	%
Cost of sales			9.0		9.2		(0.2	)	(2	%)
Net margin			78.6		65.6		13.0		20	%
Operating costs			22.8		20.2		2.6		13	%
Depreciation and amortization			10.9		12.8		(1.9	)	(15	%)
Operating income		$	44.9	$	32.6	$	12.3		38	%
Equity earnings from investments		$	15.1	$	16.2	$	(1.1	)	(7	%)
Allowance for equity funds used      during construction		$	-	$	1.2	$	(1.2	)	(100	%)
Capital expenditures		$	3.2	$	17.4	$	(14.2	)	(82	%)

	Three Months Ended
	March 31,
Operating Information (a)	2010		2009
Natural gas transportation capacity contracted (MMcf/d)		5,860		5,247
Transportation capacity subscribed		91%		79%
Average natural gas price
Mid-Continent region  ($/MMBtu)	$	5.03	$	3.19
(a) - Includes volumes for consolidated entities only.

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Net margin increased for the three months ended March 31, 2010, compared with the same period last year, primarily as a result of the following:

·   an increase of $9.2 million from higher natural gas transportation margins, excluding retained fuel, primarily as a result of incremental margin from the Guardian Pipeline expansion and extension that was completed in February 2009 and an increase in volumes contracted on Midwestern Gas Transmission as a result of a new interconnection with the Rockies Express Pipeline that was placed in service beginning in June 2009; and

·   an increase of $2.5 million from higher natural gas storage margins, excluding retained fuel, primarily as a result of contract renegotiations.

Operating costs increased for the three months ended March 31, 2010, compared with the same period last year, due primarily to higher employee-related costs.

Equity earnings from investments decreased for the three months ended March 31, 2010, compared with the same period last year, due to lower subscription volumes and rates on Northern Border Pipeline.   

Allowance for equity funds used during construction and capital expenditures decreased for the three months ended March 31, 2010, compared with the same period last year, due primarily to the Guardian Pipeline expansion and extension that was completed in February 2009. 

Natural Gas Liquids

Overview - Our natural gas liquids assets consist of facilities that gather, fractionate and treat NGLs and store NGL products primarily in Oklahoma, Kansas and Texas.  We own 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 unpro cessed 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, refineries and propane dis tributors.  We also purchase NGLs 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 exchange services, optimization and marketing, pipeline transportation, isomerization and storage, 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 locational and seasonal price differentials.  We move NGL products between Conway, Kansas, and Mont Belvieu, Texas, in order to capture the locational price differentials between the two market centers.  Our NGL storage facilities are also utilized to capture seasonal price variances.

·   Our pipeline transportation business transports NGLs, 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.

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

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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,					2010 vs. 2009
Financial Results		2010			2009		Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales		$	1,770.2		$	893.8	$	876.4		98	%
Exchange service and storage revenues			105.1			84.9		20.2		24	%
Transportation revenues			27.2			22.3		4.9		22	%
Cost of sales and fuel			1,798.5			898.4		900.1			*
Net margin			104.0			102.6		1.4		1	%
Operating costs			41.0			37.6		3.4		9	%
Depreciation and amortization			18.3			12.7		5.6		44	%
Loss on sale of assets			(0.8	)		-		(0.8	)	(100	%)
Operating income		$	43.9		$	52.3	$	(8.4	)	(16	%)
Equity earnings from investments		$	0.4		$	0.5	$	(0.1	)	(20	%)
Allowance for equity funds used
during construction		$	0.2		$	7.8	$	(7.6	)	(97	%)
Capital expenditures		$	15.8		$	146.2	$	(130.4	)	(89	%)
* Percentage change is greater than 100 percent.

	Three Months Ended
	March 31,
Operating Information		2010		2009
NGL sales (MBbl/d)			427		380
NGLs fractionated (MBbl/d)			492		465
NGLs transported-gathering lines (MBbl/d)			441		324
NGLs transported-distribution lines (MBbl/d)			467		445
Conway-to-Mont Belvieu OPIS average price differential
Ethane ($/gallon)		$	0.08	$	0.08

Net margin increased for the three months ended March 31, 2010, compared with the same period last year, primarily as a result of the following:

·   an increase of $20.0 million due to increased volumes gathered, fractionated and transported, primarily associated with the completion of the Arbuckle Pipeline, Piceance lateral and D-J Basin lateral, as well as new supply connections; and

·   an increase of $3.0 million due to higher storage margins as a result of contract renegotiations; offset partially by,

·   a decrease of $14.8 million related to lower optimization margins due to less NGL fractionation and transportation capacity available for optimization, offset partially by increased volumes marketed; and

·   a decrease of $6.8 million due to the impact of operational measurement gains and losses as compared with the same period last year.

Operating costs increased for the three months ended March 31, 2010, compared with the same period last year, due primarily to the operation of the Arbuckle Pipeline, increased materials and supplies expense and higher employee-related costs.

Depreciation and amortization increased for the three months ended March 31, 2010, compared with the same period last year, due primarily to higher depreciation expense associated with the Arbuckle Pipeline placed in service in August 2009, the Piceance lateral placed in service in October 2009 and the D-J Basin lateral placed in service in March 2009.

Allowance for equity funds used during construction and capital expenditures decreased for the three months ended March 31, 2010, compared with the same period last year, due primarily to the completion of the Arbuckle Pipeline, Piceance lateral and D-J Basin lateral.

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Contingencies

Legal Proceedings -We are a party to various litigation matters and claims that have arisen in the normal course of our operations.  While the results of litigation and claims cannot be predicted with certainty, we believe the 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 our 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, 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.  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 quarter of 2010, we utilized our Partnership Credit Agreement to fund our short-term liquidity needs, and we have been able to access the public debt and equity markets for our long-term financing needs.  In February 2010, we issued common units.  See discussion below under “Equity Issuance” for more information.

We expect a moderate economic recovery in 2010, with inflationary pressures beginning in 2011.  Although recent volatility in the financial markets could limit our access to financial markets on a timely basis or increase our cost of capital in the future, we anticipate improved credit markets during 2010, compared with 2009.  Our ability to continue to access capital markets for debt and equity financing under reasonable terms depends on our financial condition and 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 capital expenditures.

Capital Structure - The following table sets forth our capitalization structure for the periods indicated:

	March 31,	December 31,
	2010	2009
Long-term debt	48%	51%
Equity	52%	49%
Debt (including notes payable)	51%	55%
Equity	49%	45%

Cash Management - We use a centralized cash management program that concentrates the cash assets of our operating subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing, transaction costs and bank fees.  Our centralized cash management program provides that funds in excess of the daily needs of our operating subsidiaries are concentrated, consolidated or made available for use by other entities within our consolidated group.  Our operating subsidiaries participate in this program to the extent they are permitted pursuant to FERC regulations or our operating agreements.  Under the cash management program, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, the Intermediate Partnership provides cash to the subsidiary or the subsidiary provides cash to the Intermediate Partnership.

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

The total amount of short-term borrowings authorized by our general partner’s Board of Directors is $1.5 billion.  At March 31, 2010, we had $310 million of borrowings outstanding under our Partnership Credit Agreement, which expires in March 2012, and approximately $5.4 million of available cash and cash equivalents.  As of March 31, 2010, our borrowing capacity was limited to $558 million of additional short- and long-term debt under the most restrictive provisions contained in our Partnership Credit Agreement.  At March 31, 2010, we had a total of $24.2 million in letters of credit issued outside of our Partnership Credit Agreement.

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Our Partnership Credit Agreement contains certain financial, operational and legal covenants as discussed in Note H 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 (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.  At March 31, 2010, our ratio of indebtedness to adjusted EBITDA was 4.3 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.

We expect to refinance our $250 million senior notes due June 15, 2010, with 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 existing credit facilities, 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 maint ain our investment-grade credit ratings.

Our $250 million and $225 million senior notes, due June 15, 2010, and March 15, 2011, respectively, contain provisions that require us to offer to repurchase the senior notes at par value if our Moody’s or S&P credit rating falls below investment grade (Baa3 for Moody’s or BBB- for S&P) and the investment-grade rating is not reinstated within a period of 40 days; however, once the $250 million 2010 senior notes have been retired, whether by maturity, redemption or otherwise, we will no longer have any obligation to offer to repurchase the $225 million 2011 senior notes in the event our credit rating falls below investment grade.  Further, the indentures governing our senior notes due 2010 and 2011 include an event of default upon acceleration of other indebtedness of $25 million or more and the indentures governi ng our senior notes due 2012, 2016, 2019, 2036 and 2037 include an event of default upon the acceleration of other indebtedness of $100 million or more that would be triggered by such an offer to repurchase.  Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2010, 2011, 2012, 2016, 2019, 2036 and 2037 to declare those notes immediately due and payable in full.

We may redeem the notes due 2012, 2016, 2019, 2036 and 2037, 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.  The notes due 2012, 2016, 2019, 2036 and 2037 are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness, and effectively junior to all of the existing and future debt and other liabilities of any non-guarantor subsidiaries.  Our long-term debt is nonrecourse to our general partner.

Equity Issuance - In February 2010, we completed an underwritten public offering of 5,500,900 common units, including the partial exercise by the underwriters of their over-allotment option, at a public offering price of $60.75 per common unit, generating net proceeds of approximately $322.7 million.  In conjunction with the offering, ONEOK partners GP contributed $6.8 million in order to maintain its 2 percent general partner interest in us.  We used the proceeds from the sale of common units and the general partner contribution to repay borrowings under our Partnership Credit Agreement and for general partnership purposes.  As a result of these transactions, ONEOK and its subsidiaries own a 42.8 percent aggregate equity interest in us.

Capital Expenditures- Our capital expenditures are typically financed through operating cash flows, short- and long-term debt and the issuance of equity.  Capital expenditures were $35.8 million and $192.5 million for the three months ended March 31, 2010 and 2009, 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.  Projected 2010 capital expenditures are significantly lower than 2009 capital expenditures due to various projects being completed or placed in service during 2009.

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The following table summarizes our 2010 projected growth and maintenance capital expenditures, excluding AFUDC:

2010 Projected Capital Expenditures	Growth		Maintenance		Total
	(Millions of dollars)
Natural Gas Gathering and Processing	$	240	$	22	$	262
Natural Gas Pipelines		3		22		25
Natural Gas Liquids		35		38		73
Other		-		2		2
Total projected capital expenditures	$	278	$	84	$	362

Overland Pass Pipeline Company - Overland Pass Pipeline Company is a joint venture between us and a subsidiary of The Williams Companies, Inc. (Williams).  We own 99 percent of the joint venture and operate the pipeline.  On or before November 17, 2010, Williams has the option to increase its ownership in Overland Pass Pipeline Company up to a total of 50 percent, with the purchase price being determined in accordance with the joint venture’s operating agreement.

Credit Ratings - Our credit ratings as of March 31, 2010, are shown in the table below:

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

Our credit ratings, which are currently investment grade, may be affected by a material change in our financial ratios or a material event affecting our business.  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 currently anticipate a downgrade in our credit ratings.  However, if our credit ratings were downgraded, the interest rates on borrowings under our Partnership Credit Agreement would increase, resulting in an increase in our cost to borrow funds.  An adverse rating change alone is not a default under our Partnership Credit Agreement but could trigger repurchase obligations with respect to certain of our long-term debt.  See additional discussion about our credit ratings un der “Long-term Financing.”

If our repurchase obligations are triggered, we may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause us to borrow money under our credit facilities, seek alternative financing sources or sell assets to finance the repurchases and repayment.  We could also face difficulties accessing capital or our borrowing costs could increase, impacting our ability to obtain financing for acquisitions or capital expenditures, to refinance indebtedness and to fulfill our debt obligations.

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.

Other than the note repurchase obligations described under “Long-term Financing” or the provisions discussed in the previous paragraph, we have determined that we do not have significant exposure to rating triggers in various other contracts and equipment leases.  Rating triggers are defined as provisions that would create an automatic default or acceleration of indebtedness based on a change in our credit rating.

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.  Our income is 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 income allocations for incentive distributions to our general partner is calculated after the income allocation for the general partner’s partnership interest and before the income 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,
	2010		2009
	(Millions of dollars)
Common unitholders	$	65.9	$	58.8
Class B unitholders		40.1		39.4
General partner		26.0		22.7
Total cash distributions paid before noncontrolling interests	$	132.0	$	120.9

In the three months ended March 31, 2010 and 2009, cash distributions paid to our general partner included incentive distributions of $23.4 million and $20.3 million, respectively.

In April 2010, our general partner declared a cash distribution of $1.11 per unit ($4.44 per unit on an annualized basis) for the first quarter of 2010, an increase of $0.01 from the previous quarter, which will be paid on May 14, 2010, to unitholders of record at the close of business on April 30, 2010.

Additional information, about our cash distribution 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 Financ ial 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						Variances
		March 31,						2010 vs. 2009
		2010			2009			Increase (Decrease)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities		$	55.5		$	74.7		$	(19.2	)	(26	%)
Investing activities			(34.4	)		(188.0	)		153.6		82	%
Financing activities			(18.9	)		(63.2	)		44.3		(70	%)
Change in cash and cash equivalents			2.2			(176.5	)		178.7			*
Cash and cash equivalents at beginning of period			3.2			177.6			(174.4	)	(98	%)
Cash and cash equivalents at end of period		$	5.4		$	1.1		$	4.3			*
* Percentage change is greater than 100 percent.

Operating Cash Flows - Operating cash flows are affected by earnings from our business activities.  We provide services for producers and consumers of natural gas, condensate and NGLs.  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 $130.6 million for the three months ended March 31, 2010, compared with $135.5 million for the same period in 2009.  The decrease was due primarily to lower optimization margins in our Natural Gas Liquids segment, increased operating costs due to the operation of our recently completed capital projects and higher employee-related costs.

The changes in operating assets and liabilities decreased operating cash flows $75.1 million for the three months ended March 31, 2010, compared with a decrease of $60.8 million for the same period in 2009, primarily as a result of the following:

·   the impact of commodity prices on our operating assets and liabilities;

·   the changes in volumes of commodities in storage; and

·   the timing of cash receipts from our revenues resulting in decreased accounts receivable; offset partially by

·   the timing of payments for purchases of commodities and other expenses resulting in decreased accounts payable.

Investing Cash Flows - Cash used in investing activities decreased for the three months ended March 31, 2010, compared with the same period in 2009, due primarily to reduced capital expenditures as a result of the completion of our capital projects included under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Capital Projects,” in our Annual Report.

Financing Cash Flows -In February 2010, we completed an underwritten public offering of 5,500,900 common units, including the partial exercise by the underwriters of their over-allotment option, at a public offering price of $60.75 per common unit, generating net proceeds of approximately $322.7 million.  In conjunction with the offering, ONEOK Partners GP contributed $6.8 million in order to maintain its 2 percent general partner interest in us.  We used the proceeds from the sale of common units and the general partner contribution to repay borrowings under our Partnership Credit Agreement and for general partnership purposes. 

In March 2009, we completed an underwritten public offering of senior notes totaling approximately $498.3 million, net of discounts but before offering expenses.  The net proceeds from the notes were used to repay borrowings under our Partnership Credit Agreement.

Cash distributions to our general and limited partners for the first quarter of 2010 were $132.1 million, compared with $120.9 million for the same period in 2009, an increase of $11.2 million.  This increase was due primarily to additional units outstanding during the first quarter of 2010, as well as cash distributions of $1.10 per unit paid during the first quarter of 2010, compared with cash distributions of $1.08 per unit paid during the first quarter of 2009.

Net repayments of notes payable were $213.0 million during the first quarter of 2010, compared with net repayments of $433.3 million for the first quarter of 2009.

ENVIRONMENTAL AND SAFETY MATTERS

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

Pipeline Safety - We are subject to United States Department of Transportation regulations, including integrity management regulations.  The Pipeline Safety Improvement Act of 2002 requires pipeline companies to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high consequence areas.  We are in compliance with all material requirements associated with the various pipeline safety regulations.  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.  We are in compliance with all material requiremen ts associated with the various air and water regulations.

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The United States Congress is actively considering legislation to reduce greenhouse gas emissions, including carbon dioxide and methane.  In addition, other 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 all applicable greenhouse gas emission data for the previous year.Our most recent estimate indicates that our emissions are less than 4 million metric tons of carbon dioxide equivalents on an annual basis.  We expect to complete our annual estimate for 2009 during the second quarter of 2010 and will post the information on our W eb site when available.  We will continue efforts to improve our ability to quantify our direct greenhouse gas emissions and will report such emissions as required by the EPA’s Mandatory Greenhouse Gas Reporting rule released in September 2009.  The rule requires greenhouse gas emissions reporting for affected facilities on an annual basis, beginning with our 2010 emissions report that will be due in March 2011 and will require us to track the emission equivalents for all NGLs delivered to our customers.  Also, the EPA has recently released a proposed 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 are proposed to begin in January 2011, with the first reporting of fugitive emissions due March 31, 2012.  At this time, no legislation has been enacted as to what costs, fees or expense will be associated with any of these emissions.

The EPA is proposing to finalize the “Tailoring Rule” that will regulate greenhouse gas emissions at certain facilities that emit more than 25,000 tons of greenhouse gas emissions per year.  Under the Prevention of Significant Deterioration requirement for existing facilities, upon making a major modification to a facility, the facility would be required to obtain permits that demonstrate it has installed the best available technology to control greenhouse gas emissions.  The rule is expected to be phased in beginning January 2011 and could impact some of our facilities.  At this time, potential costs, fees or expenses associated with the proposed “Tailoring Rule” are unknown.

In addition, the EPA has issued a proposed 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 early 2013.  The proposed 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.

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.

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, on a preliminary basis, 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, and one other has been given a preliminary 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 new 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; (iv) following developing technologies to capture carbon dioxide to keep it from reaching the atmosphere, and (v) analyzing options for future energy investment.

We continue to focus on maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices to limit the release of natural 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 2009 during the second quarter of 2010 and will post the information on our Web site when available.

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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, 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.

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 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, authorized rates of recovery of gas and 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 our general partner;

·   the results of administrative proceedings and litigation, regulatory actions and receipt of expected clearances involving the OCC, KCC, Texas regulatory authorities or any other local, state or federal regulatory body, including the FERC;

·   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;

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·   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;

·   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 U.S. economy or the risk of delay in growth recovery in the U.S. economy, including liquidity risks in U.S. 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.

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ITEM 4. CONTROLS AND PROCEDURES

Quarterly Evaluation of Disclosure Controls and Procedures -As of the end of the period covered by this report, the Chief Executive Officer (Principal Executive Officer) and the Chief Financial Officer (Principal Financial Officer) of ONEOK Partners GP, our general partner, evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to management of ONEOK Partners GP, including the officers of O NEOK Partners GP who are the equivalent of our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.  Based on their evaluation, they concluded that as of March 31, 2010, our disclosure controls and procedures were effective in ensuring that the information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Changes in Internal Control Over Financial Reporting -We have made no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the first quarter ended March 31, 2010, 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

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

Thomas F. Boles, et al. v. El Paso Corporation, et al. (f/k/a Will Price, et al. v. Gas Pipelines, et al.,  f/k/a Quinque Operating Company, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 99C30 (“Boles I”) - As previously reported, ONEOK and its division, Oklahoma Natural Gas, our subsidiaries Mid-Continent Market Center, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK WesTex Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP, successor to Koch Hydrocarbon Company), as well as approximately 225 other defendants, are defendants in a lawsuit claiming underpayment of gas purchase proceeds.  The plaintiffs initially asserted that the defendants understated both the volume and the heating content of the purchased gas, and sought class certification for gas producers and royalty owners throughout the United States.  The Court refused to certify the class and the plaintiffs amended their petition to limit the purported class to gas producers and royalty owners in Kansas, Colorado and Wyoming, and limited the claim to undermeasurement of volume.  On September 18, 2009, the Court denied the plaintiffs’ motions for class certification, which, in effect, limited the named plaintiffs to pursuing individual claims against only those defendants who purchased or measured their gas.  On October 2, 2009, the plaintiffs filed a motion for reconsideration of the Court’s denial of class certification.  On March 31, 2010, the Court denied the plaintiffs motion for reconsideration.

Thomas F. Boles, et al. v. El Paso Corporation, et al. (f/k/a Will Price and Stixon Petroleum, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 03C232 (“Boles II”) - As previously reported, 21 groups of defendants, including ONEOK and its division, Oklahoma Natural Gas, our subsidiaries Mid-Continent Market Center, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK WesTex Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP, successor to Koch Hydrocarbon Company), are defendants in a lawsuit claiming underpayment of gas producers and royalty owners by allegedly understating the heating content of purchased gas in Kansas, Colorado and Wyoming.  This action was filed by the plaintiffs after the Court denied the initial motion for class status in Boles I, and Boles II was consolidated with Boles I to determine whether either or both cases may properly be certified.  On September 18, 2009, the Court denied the plaintiffs’ motions for class certification, which, in effect, limited the named plaintiffs to pursuing individual claims against only those defendants who purchased or measured their gas.  On October 2, 2009, the plaintiffs filed a motion for reconsideration of the Court’s denial of class certification.  On March 31, 2010, the Court denied the plaintiffs motion for reconsideration.

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

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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, and, 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 Curtis L. Dinan 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)).

32.2 Certification of Curtis L. Dinan 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, 2010 and 2009; (iii) Consolidated Balance Sheets at March 31, 2010 and December 31, 2009; (iv) Consolidated Statements of Cash Flows for the three months

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ended March 31, 2010 and 2009; (v) Consolidated Statement of Changes in Partners’ Equity for the three months ended March 31, 2010; (vi) Consolidated Statements of Comprehensive Income for the three months ended March 31, 2010 and 2009; 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 Web site the Interactive Data Files voluntarily submitted as Exhibit 101 to this Quarterly Report.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, 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:	April 29, 2010	By: /s/ Curtis L. Dinan
		Curtis L. Dinan Executive Vice President, Chief Financial Officer and Treasurer (Signing on behalf of the Registrant and as Principal Financial Officer)

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