ONEOK Partners (OKS) 10-Q 2010 Q0 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, 2009

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 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 30, 2009
Common units	54,426,087 units
Class B units	36,494,126 units

ONEOK PARTNERS, L.P.

QUARTERLY REPORT ON FORM 10-Q

Part I.	Financial Information	Page No.
Item 1.	Financial Statements (Unaudited)
	Consolidated Statements of Income - Three Months Ended March 31, 2009 and 2008	5
	Consolidated Balance Sheets - March 31, 2009 and December 31, 2008	6
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2009 and 2008	7
	Consolidated Statement of Changes in Partners’ Equity -  Three Months Ended March 31, 2009	8-9
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2009 and 2008	10
	Notes to Consolidated Financial Statements	11-21
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22-39
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39
Item 4.	Controls and Procedures	40
Part II.	Other Information
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 3.	Defaults Upon Senior Securities	40
Item 4.	Submission of Matters to a Vote of Security Holders	40
Item 5.	Other Information	40
Item 6.	Exhibits	41
Signature		42

As used in this Quarterly Report on Form 10-Q, 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 on Form 10-Q 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,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” and other words and terms of similar meaning.  Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that such expectations and assumptions will be achieved.  Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Forward-Looking Statements” in this Quarterly Report on Form 10-Q and under Part 1, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2008.

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GLOSSARY

The abbreviations, acronyms and industry terminology used in this Quarterly Report on Form 10-Q are defined as follows:

AFUDC Allowance for funds used during construction

ARB Accounting Research Bulletin

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

Bbl/d Barrels per day

BBtu/d Billion British thermal units per day

Bcf Billion cubic feet

Btu British thermal units, a measure of the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit

Bushton Plant Bushton Gas Processing Plant

EBITDA Earnings before interest, taxes, depreciation and amortization

EITF Emerging Issues Task Force

Exchange Act Securities Exchange Act of 1934, as amended

FASB Financial Accounting Standards Board

FERC Federal Energy Regulatory Commission

FIN FASB Interpretation

Fort Union Gas Gathering Fort Union Gas Gathering, L.L.C.

FSP FASB Staff Position

GAAP Accounting principles generally accepted in the United States of America

Guardian Pipeline Guardian Pipeline, L.L.C.

KCC Kansas Corporation Commission

KDHE Kansas Department of Health and Environment

LIBOR London Interbank Offered Rate

MBbl Thousand barrels

MBbl/d Thousand barrels per day

Midwestern Gas Transmission Midwestern Gas Transmission Company

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

OkTex Pipeline OkTex Pipeline Company, L.L.C.

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
POP	Percent of Proceeds

S&P Standard & Poor’s Rating Group

SEC Securities and Exchange Commission

Statement Statement of Financial Accounting Standards

AVAILABLE INFORMATION

We make available on our Web site copies of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC.  Our Web site and any contents thereof are not incorporated by reference into this report.

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PART I - FINANCIAL INFORMATION
ITEM 1.  FINANCIAL INFORMATION
ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
	Three Months Ended
	March 31,
(Unaudited)	2009			2008
	(Thousands of dollars, except per unit amounts)
Revenues	$	1,250,865		$	2,059,035
Cost of sales and fuel		997,324			1,790,510
Net Margin		253,541			268,525
Operating Expenses
Operations and maintenance		77,679			76,941
Depreciation and amortization		39,940			29,942
General taxes		11,767			11,141
Total Operating Expenses		129,386			118,024
Gain (Loss) on Sale of Assets		664			31
Operating Income		124,819			150,532
Equity earnings from investments (Note J)		21,222			27,783
Allowance for equity funds used during construction		9,003			8,496
Other income		391			2,058
Other expense		(2,046	)		(2,131	)
Interest expense		(50,908	)		(38,529	)
Income before Income Taxes		102,481			148,209
Income taxes		(2,871	)		(3,068	)
Net Income		99,610			145,141
Net income attributable to noncontrolling interests		(19	)		(123	)
Net Income Attributable to ONEOK Partners, L.P.	$	99,591		$	145,018
Limited partners’ interest in net income:
Net income attributable to ONEOK Partners, L.P.	$	99,591		$	145,018
General partner’s interest in net income		(22,312	)		(19,705	)
Limited Partners’ Interest in Net Income	$	77,279		$	125,313
Limited partners’ net income per unit (Note K)	$	0.85		$	1.48
Number of Units Used in Computation (Thousands)		90,920			84,454
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)	2009		2008
Assets	(Thousands of dollars)
Current Assets
Cash and cash equivalents	$	1,129	$	177,635
Accounts receivable, net		305,958		317,182
Affiliate receivables		20,896		25,776
Gas and natural gas liquids in storage		145,975		190,616
Commodity exchanges and imbalances		51,604		55,086
Derivative financial instruments (Notes B and C)		45,619		63,780
Materials and supplies		31,221		22,956
Other current assets		3,470		5,220
Total Current Assets		605,872		858,251
Property, Plant and Equipment
Property, plant and equipment		5,981,885		5,808,679
Accumulated depreciation and amortization		903,282		875,279
Net Property, Plant and Equipment (Note H)		5,078,603		4,933,400
Investments and Other Assets
Investments in unconsolidated affiliates		747,990		755,492
Goodwill and intangible assets		674,620		676,536
Other assets		37,819		30,593
Total Investments and Other Assets		1,460,429		1,462,621
Total Assets	$	7,144,904	$	7,254,272
Liabilities and Partners’ Equity
Current Liabilities
Current maturities of long-term debt	$	11,931	$	11,931
Notes payable (Note E)		436,700		870,000
Accounts payable		418,814		496,763
Affiliate payables		18,372		23,333
Commodity exchanges and imbalances		128,605		191,165
Accrued interest		77,659		44,104
Other current liabilities		36,249		56,728
Total Current Liabilities		1,128,330		1,694,024
Long-term Debt, excluding current maturities (Note F)		3,083,876		2,589,509
Deferred Credits and Other Liabilities		57,596		54,773
Commitments and Contingencies (Note G)
Partners’ Equity
General partner		77,119		77,546
Common units: 54,426,087 units issued and   outstanding at March 31, 2009 and December 31, 2008		1,348,538		1,361,058
Class B units: 36,494,126 units issued and outstanding at   March 31, 2009 and December 31, 2008		1,398,622		1,407,016
Accumulated other comprehensive income (Note D)		45,206		64,405
Total ONEOK Partners, L.P. Partners’ Equity		2,869,485		2,910,025
Noncontrolling Interests in Consolidated Subsidiaries		5,617		5,941
Total Partners’ Equity		2,875,102		2,915,966
Total Liabilities and Partners’ Equity	$	7,144,904	$	7,254,272
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)	2009			2008
	(Thousands of dollars)
Operating Activities
Net income	$	99,610		$	145,141
Depreciation and amortization		39,940			29,942
Allowance for equity funds used during construction		(9,003	)		(8,496	)
Gain on sale of assets		(664	)		(31	)
Equity earnings from investments		(21,222	)		(27,783	)
Distributions received from unconsolidated affiliates		25,187			24,040
Changes in assets and liabilities (net of acquisition and disposition effects):
Accounts receivable		11,224			81,852
Affiliate receivables		4,880			(11,277	)
Gas and natural gas liquids in storage		44,641			43,696
Derivative financial instruments		(1,038	)		(5,709	)
Materials and supplies		(8,265	)		(458	)
Accounts payable		(65,065	)		(34,232	)
Affiliate payables		(4,961	)		11,855
Commodity exchanges and imbalances, net		(59,078	)		(27,038	)
Accrued interest		33,555			34,317
Other assets and liabilities		(14,965	)		(13,746	)
Cash Provided by Operating Activities		74,776			242,073
Investing Activities
Changes in investments in unconsolidated affiliates		3,362			3,311
Acquisitions		-			2,450
Capital expenditures (less allowance for equity funds used during construction)		(192,494	)		(267,058	)
Proceeds from sale of assets		1,083			72
Cash Used in Investing Activities		(188,049	)		(261,225	)
Financing Activities
Cash distributions:
General and limited partners		(120,932	)		(101,135	)
Noncontrolling interests		(343	)		(74	)
Borrowing (repayment) of notes payable, net		36,700			(100,000	)
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	)		-
Issuance of common units, net of discounts		-			443,579
Contributions from general partner		-			9,355
Payment of long-term debt		(2,983	)		(2,981	)
Cash Provided by (Used in) Financing Activities		(63,233	)		248,744
Change in Cash and Cash Equivalents		(176,506	)		229,592
Cash and Cash Equivalents at Beginning of Period		177,635			3,213
Cash and Cash Equivalents at End of Period	$	1,129		$	232,805
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 Units		Class B Units		General Partner			Common Units
(Unaudited)
	(Units)				(Thousands of dollars)
December 31, 2008		54,426,087		36,494,126	$	77,546		$	1,361,058
Net income		-		-		22,312			46,260
Other comprehensive income (loss) (Note D)		-		-		-			-
Distributions paid (Note K)		-		-		(22,739	)		(58,780	)
March 31, 2009		54,426,087		36,494,126	$	77,119		$	1,348,538
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
							Noncontrolling Interests in Consolidated Subsidiaries
				Accumulated Other Comprehensive Income (Loss)
										Total Partners’ Equity
	Class B Units
	(Thousands of dollars)
December 31, 2008	$	1,407,016		$	64,405		$	5,941		$	2,915,966
Net income		31,019			-			19			99,610
Other comprehensive income (loss) (Note D)		-			(19,199	)		-			(19,199	)
Distributions paid (Note K)		(39,413	)		-			(343	)		(121,275	)
March 31, 2009	$	1,398,622		$	45,206		$	5,617		$	2,875,102

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	Three Months Ended
	March 31,
(Unaudited)	2009			2008
	(Thousands of dollars)
Net income	$	99,610		$	145,141
Other comprehensive income (loss) (Note D)		(19,199	)		1,749
Comprehensive Income		80,411			146,890
Comprehensive income attributable to noncontrolling interests		19			123
Comprehensive Income Attributable to ONEOK Partners, L.P.	$	80,392		$	146,767
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 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 2008 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 on Form 10-K for the year ended December 31, 2008.

Our accounting policies are consistent with those disclosed in Note A of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008.  The following recently issued accounting pronouncements will affect our consolidated financial statements during 2009.

Fair Value Measurements - As of January 1, 2009, we have applied the provisions of Statement 157, “Fair Value Measurements,” to assets and liabilities that are measured at fair value on a nonrecurring basis subsequent to initial recognition, and the impact was not material.  See Note B for disclosures of our fair value measurements.

Noncontrolling Interests - In December 2007, the FASB issued Statement 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51,” which requires noncontrolling interests (previously referred to as minority interests) to be reported as a component of equity.  Statement 160 was effective for our year beginning January 1, 2009, and required retroactive adoption of the presentation and disclosure requirements for existing minority interests.

Derivative Instruments and Hedging Activities - In March 2008, the FASB issued Statement 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment to FASB Statement No. 133,” which required enhanced disclosures about how derivative and hedging activities affect our financial position, financial performance and cash flows.  Statement 161 was effective for our year beginning January 1, 2009, and has been applied prospectively.  See Note C for disclosures of our derivative instruments and hedging activities.

Limited Partners’ Net Income Per Unit - EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships,” was effective for our year beginning January 1, 2009, and required retrospective application.  Application of EITF 07-4 had no impact on our limited partners’ net income per unit for the three months ended March 31, 2009 and 2008.  See Note K for a discussion of our calculation of limited partners’ net income per unit.

Interim Disclosures about Fair Value - In April 2009, the FASB issued FSP 107-1 and Accounting Principles Board (APB) Opinion No. 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” which amends Statement 107, “Disclosures about Fair Value of Financial Instruments,” and also amends APB Opinion No. 28, “Interim Financial Reporting.”  FSP 107-1 and APB 28-1 require disclosures of fair value of financial instruments for interim reporting periods and will be effective for our June 30, 2009, Quarterly Report on Form 10-Q.

Reclassifications

Certain amounts in our consolidated financial statements have been reclassified to conform to the 2009 presentation.  These reclassifications did not impact previously reported net income.

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B.           FAIR VALUE MEASUREMENTS

Refer to Notes A and C of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008, for a discussion of our fair value measurements and the fair value hierarchy.

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

	March 31, 2009
	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Derivatives
Assets (a)	$	-	$	19,793	$	25,995	$	45,788
(a) - Included in derivative financial instruments and other assets on our Consolidated Balance Sheet.
	December 31, 2008
	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Derivatives
Assets (a)	$	-	$	26,131	$	37,649	$	63,780
(a) - Included in derivative financial instruments on our Consolidated Balance Sheet.

At March 31, 2009, and December 31, 2008, we had no cash collateral held or posted under our master netting arrangements.

In accordance with Statement 157, we categorize derivatives for which fair value is determined based on multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety.

When our fair value measurements that are based on NYMEX-settled prices are associated with exchange-traded instruments, we classify those derivatives as Level 1.  These measurements may include futures for natural gas and crude oil that are valued based on unadjusted quoted prices in active markets.  Our Level 2 fair value measurements are based on NYMEX-settled prices that are utilized to determine the fair value of certain non-exchange traded financial instruments, including natural gas and crude oil swaps.  For our Level 3 inputs, we utilize modeling techniques using NYMEX-settled pricing data and historical correlations of NGL product prices to crude oil.

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

	Three Months Ended
	March 31,
Derivatives	2009			2008
	(Thousands of dollars)
Net assets (liabilities) at beginning of period	$	37,649		$	(16,400	)
Total realized/unrealized gains (losses):
Included in earnings (a)		1,104			980
Included in other comprehensive income (loss)		(12,758	)		5,034
Net assets (liabilities) at end of period	$	25,995		$	(10,386	)
(a) - Included in revenues in our Consolidated Statements of Income.

There were no material gains (losses) for the three months ended March 31, 2009 and 2008, included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities classified as Level 3 fair value measurements still held as of the end of the period.

C.           RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

Risk Management Activities - We are sensitive to changes in natural gas, condensate and NGL prices, principally as a result of contractual terms under which these commodities are processed, purchased and sold.  We use physical forward sales and financial derivatives to secure a certain price for a portion of our natural gas, condensate and NGL products.  We follow established policies and procedures to assess risk and approve, monitor and report our risk management activities.  We have not used these instruments for trading purposes.  We are also subject to the risk of interest rate fluctuation in the normal course of business.

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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 and 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.

·   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. 

·   Options - Contractual agreements that give the holder the right, but not the obligation, to buy or sell a fixed quantity of a commodity, at a fixed price, within a specified period of time.  Options may either be standardized, exchange-traded or customized and non-exchange traded.

In our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk, primarily in regard to NGLs, as a result of receiving commodities in exchange for our services.  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 aforementioned commodity derivative instruments to minimize earnings volatility related to natural gas, NGL and condensate price fluctuations.  We reduce our gross processing spread exposure through a combination of physical and financial hedges.  We utilize a portion of our POP equity natural gas 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 Liquids Gathering and Fractionation 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 earnings volatility related to NGL price fluctuations.  At March 31, 2009, we were not using any financial derivative instruments with respect to our NGL gathering and fractionation activities.

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 to reduce earnings volatility related to natural gas price fluctuations.  At March 31, 2009, we were not using any financial derivative instruments with respect to our intrastate and interstate pipeline operations.

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.  Fixed-rate swaps are designed to reduce the risk of increased interest costs during periods of rising interest rates.  Floating-rate swaps may be used to convert the fixed rates of long-term borrowings into short-term variable rates.

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Accounting Treatment - We account for derivative instruments and hedging activities in accordance with Statement 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended.  Under Statement 133, entities are required to 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 exceptions	- 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 its book value	- Change in fair value of the hedged item is    recognized in earnings

As required by Statement 133, 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.  We assess the effectiveness of hedging relationships quarterly by performing a regression analysis on our 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, options and swaps that are accounted for as hedges are included in the same cash flow statement category as the cash flows from the related hedged items.

Fair Values of Derivative Instruments -Statement 157 defines fair value as the price that would be received to sell an asset or transfer a liability in an orderly transaction between market participants at the measurement date.  See Note B for a discussion of the inputs associated with our fair value measurements and our fair value hierarchy disclosures.

As of March 31, 2009, we had $45.8 million of derivative assets, all of which related to commodity contracts.

As of March 31, 2009, we had fixed-price natural gas swaps with a notional quantity of 5.1 Bcf and natural gas basis swaps with a notional quantity of 5.1 Bcf.  Additionally, we had fixed-price crude oil and NGL swaps with a notional quantity of 1.8 MMBbl.

Cash Flow Hedges - At March 31, 2009, our Consolidated Balance Sheet reflected an unrealized gain of $49.8 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 $49.6 million in gains over the next 12 months, and we will recognize gains of $0.2 million thereafter.

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

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

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

	Location of Gain (Loss) Reclassified from
Derivatives in Cash Flow	Accumulated Other Comprehensive Income	Three Months Ended
Hedging Relationships	(Loss) into Net Income (Effective Portion)	March 31, 2009
		(Thousands of dollars)
Commodity contracts	Revenues	$	18,765
Interest rate contracts	Interest expense		436
Total gain (loss) reclassified from accumulated other comprehensive    income (loss) into net income (effective portion)		$	19,201

Ineffectiveness related to our cash flow hedges was not material for the three months ended March 31, 2009 and 2008.  In the event that it becomes probable that a forecasted transaction will not occur, we would discontinue cash flow hedge treatment, which will affect earnings.  There were no gains or losses due to the discontinuance of cash flow hedge treatment during the three months ended March 31, 2009 and 2008, respectively.

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 for the three months ended March 31, 2009, from amortization of terminated swaps was $0.9 million, and the remaining amortization of terminated swaps will be recognized over the following periods.

	(Millions of dollars)
Remainder of 2009	$	2.8
2010	$	3.7
2011	$	0.9

At March 31, 2009, none of the interest on our fixed-rate debt was swapped to floating using interest-rate swaps.

Risk Policy and Oversight - Commodity Price Risk-We control the scope of risk management and marketing operations through a comprehensive set of policies and procedures involving senior levels of management.  The Audit Committee of our general partner’s Board of Directors has oversight responsibilities for our risk management policies.  Our Risk Oversight and Strategy Committee (ROSC), comprised of executive and business segment senior officers, is responsible for ensuring commodity price risk is monitored within the comprehensive risk management framework and that marketing and hedging strategies are developed and implemented to mitigate and manage this exposure.

We have a risk control organization that is assigned responsibility for establishing and enforcing the policies and procedures and monitoring certain risk metrics.  Key risk control activities include validation of transactions, portfolio valuation, collateral and liquidity stress testing, and monitoring of various risk metrics.  Certain thresholds related to these activities have been established by the ROSC that reflect our risk tolerance.  These thresholds are reviewed periodically and are set based on a number of factors, including market environment, price volatility and liquidity, and our business strategy.  Our risk control organization monitors and reports on our positions and risk metrics, including timely notification to the ROSC of any thresholds that have been exceeded.

Derivative Contracts - 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 entering into commodity derivative contracts on our behalf.

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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,
		2009		2008
		(Thousands of dollars)
Unrealized gains (losses) on derivatives	$	(210)	$	(5,543)
Less:  Realized gains (losses) recognized in net income		19,201		(7,292)
Other		212		-
Other comprehensive income (loss)	$	(19,199)	$	1,749

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

	Unrealized Gains (Losses) on Derivatives
	(Thousands of dollars)
December 31, 2008		$	64,405
Other comprehensive income (loss)		(19,199)
March 31, 2009		$	45,206

E.           CREDIT FACILITIES

Our $1.0 billion amended and restated revolving credit agreement dated March 30, 2007, (Partnership Credit Agreement), which expires in March 2012, contains certain financial and other typical covenants as discussed in Note H of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008.  At March 31, 2009, our ratio of indebtedness to adjusted EBITDA (EBITDA, as adjusted for all non-cash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) was 4.2 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.

At March 31, 2009, we had $436.7 million of borrowings outstanding and $563.3 million of credit available under our Partnership Credit Agreement.  We have a total of $49.2 million issued in letters of credit outside of the Partnership Credit Agreement.

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

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F.           LONG-TERM DEBT

Debt Issuance - In March 2009, we completed an underwritten public offering of $500 million aggregate principal amount of 8.625 percent Senior Notes due 2019 (2019 Notes).  The 2019 Notes were issued under our existing shelf registration statement filed with the SEC.

We may redeem the 2019 Notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium.  The redemption price will never be less than 100 percent of the principal amount of the 2019 Notes plus accrued and unpaid interest to the redemption date.  The 2019 Notes 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 our non-guarantor subsidiaries.  The 2019 Notes are nonrecourse to our general partner.

The net proceeds from the 2019 Notes, after deducting underwriting discounts and commissions and expenses, of approximately $494.3 million were used to repay indebtedness outstanding under our Partnership Credit Agreement.

The 2019 Notes are fully and unconditionally guaranteed on a senior unsecured basis by ONEOK Partners Intermediate Limited Partnership (Intermediate Partnership).  The guarantee ranks equally in right of payment to all of the Intermediate Partnership’s existing and future unsecured senior indebtedness.

The terms of the 2019 Notes are governed by an indenture, dated as of September 25, 2006, between us and Wells Fargo Bank, N.A., as trustee, as supplemented by the Fifth Supplemental Indenture, dated March 3, 2009 (Indenture).  The Indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series.  The Indenture contains covenants including, among other provisions, limitations on our ability to place liens on our property or assets and to sell and lease back our property.

The 2019 Notes will mature on March 1, 2019.  We will pay interest on the 2019 Notes on March 1 and September 1 of each year.  The first payment of interest on the 2019 Notes will be made on September 1, 2009.  Interest on the 2019 Notes accrues from March 3, 2009, which was the issuance date.

G.           COMMITMENTS AND CONTINGENCIES

Investment in Northern Border Pipeline - In March 2009, we made an equity contribution of $4.3 million to Northern Border Pipeline.  Northern Border Pipeline anticipates requiring an additional equity contribution of approximately $76 million from its partners in the third quarter of 2009, of which our share will be approximately $38 million based on our 50 percent equity interest.

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 interruptions in our operations that could be material to our results of operations.  If a leak or spill of hazardous substances or petroleum products occurs from lines 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 federal 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 and remediation to date have not been significant in relation to our results of operations, and there were no material effects upon earnings during the three months ended March 31, 2009 or 2008 related to compliance with environmental regulations.

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H.           PROPERTY, PLANT AND EQUIPMENT

The following table sets forth our property, plant and equipment, by segment, for the periods indicated.

		March 31,		December31,
		2009		2008
		(Thousands of dollars)
Non-Regulated
Natural Gas Gathering and Processing	$		1,391,526	$	1,368,223
Natural Gas Pipelines			168,016		167,625
Natural Gas Liquids Gathering and Fractionation			889,130		879,047
Other			45,939		50,474
Regulated
Natural Gas Pipelines			1,473,506		1,460,764
Natural Gas Liquids Pipelines			2,013,768		1,882,546
Property, plant and equipment			5,981,885		5,808,679
Accumulated depreciation and amortization			903,282		875,279
Net property, plant and equipment	$		5,078,603	$	4,933,400

Property, plant and equipment on our Consolidated Balance Sheets includes construction work in process for capital projects that have not yet been put in service and therefore are not being depreciated.  The following table sets forth our construction work in process, by segment, for the periods indicated.

	March 31,		December 31,
	2009		2008
	(Millions of dollars)
Natural Gas Gathering and Processing	$	85.4	$	135.3
Natural Gas Pipelines	30.8		107.7
Natural Gas Liquids Gathering and Fractionation	114.8		121.0
Natural Gas Liquids Pipelines	496.2		445.8
Other	0.1		0.2
Total construction work in process	$	727.3	$	810.0

I.           SEGMENTS

Segment Descriptions - Our operations are divided into four 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 unprocessed natural gas;

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

·   our Natural Gas Liquids Gathering and Fractionation segment primarily gathers, treats and fractionates NGLs and stores and markets NGL products; and

·   our Natural Gas Liquids Pipelines segment primarily operates regulated interstate natural gas liquids gathering and distribution pipelines.

Accounting Policies - The accounting policies of the segments are the same as those described in Note A and Note L of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008.  Intersegment and affiliate sales are recorded on the same basis as sales to unaffiliated customers.

Customers - For the three months ended March 31, 2009 and 2008, we had no single unaffiliated customer from which we received 10 percent or more of our consolidated revenues.  Sales to affiliated customers represent revenues from subsidiaries of ONEOK and represented approximately 12 percent of our consolidated revenues for the three months ended March 31, 2009.  For the three months ended March 31, 2008, sales to affiliated customers were less than 10 percent of our consolidated revenues.  See Note L 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, 2009	Natural Gas Gathering and Processing			Natural Gas Pipelines (a)		Natural Gas Liquids Gathering and Fractionation		Natural Gas Liquids Pipelines (b)		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	62,146		$	48,717	$	971,899	$	23,967	$	1		$	1,106,730
Sales to affiliated customers		118,207			25,928		-		-		-			144,135
Intersegment sales		69,890			147		7,706		33,680		(111,423	)		-
Total revenues	$	250,243		$	74,792	$	979,605	$	57,647	$	(111,422	)	$	1,250,865
Net margin	$	86,052		$	65,568	$	59,222	$	44,144	$	(1,445	)	$	253,541
Operating costs		31,828			20,180		22,837		15,565		(964	)		89,446
Depreciation and amortization		14,448			12,793		6,413		6,284		2			39,940
Gain (loss) on sale of assets		(19	)		27		3		-		653			664
Operating income	$	39,757		$	32,622	$	29,975	$	22,295	$	170		$	124,819
Equity earnings from investments	$	4,466		$	16,208	$	-	$	548	$	-		$	21,222
Investments in unconsolidated   affiliates	$	321,111		$	396,972	$	-	$	29,907	$	-		$	747,990
Total assets	$	1,597,894		$	1,477,567	$	1,680,098	$	2,036,428	$	352,917		$	7,144,904
Noncontrolling interests in   consolidated subsidiaries	$	-		$	5,413	$	-	$	189	$	15		$	5,617
Capital expenditures	$	28,818		$	17,428	$	13,005	$	133,243	$	-		$	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 Pipelines segment’s operations are primarily regulated. Our Natural Gas Liquids Pipelines segment’s non-regulated operations were not material.

Three Months Ended March 31, 2008	Natural Gas Gathering and Processing		Natural Gas Pipelines (a)		Natural Gas Liquids Gathering and Fractionation		Natural Gas Liquids Pipelines (b)		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	96,581	$	61,864	$	1,700,070	$	17,183	$	2		$	1,875,700
Sales to affiliated customers		155,294		28,041		-		-		-			183,335
Intersegment revenues		184,695		267		6,450		21,500		(212,912	)		-
Total revenues	$	436,570	$	90,172	$	1,706,520	$	38,683	$	(212,910	)	$	2,059,035
Net margin	$	103,906	$	63,695	$	69,525	$	31,357	$	42		$	268,525
Operating costs		33,097		23,580		18,631		13,403		(629	)		88,082
Depreciation and amortization		11,757		8,418		5,619		4,142		6			29,942
Gain (loss) on sale of assets		1		17		12		1		-			31
Operating income	$	59,053	$	31,714	$	45,287	$	13,813	$	665		$	150,532
Equity earnings from investments	$	7,044	$	20,061	$	-	$	678	$	-		$	27,783
Investments in unconsolidated   affiliates	$	300,788	$	422,169	$	-	$	31,347	$	-		$	754,304
Total assets	$	1,504,864	$	1,263,696	$	1,807,466	$	1,396,940	$	522,989		$	6,495,955
Noncontrolling interests in   consolidated subsidiaries	$	-	$	5,781	$	-	$	55	$	15		$	5,851
Capital expenditures	$	26,487	$	22,222	$	29,571	$	188,726	$	52		$	267,058
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $77.1 million, net margin of $50.5 million and operating income of $23.8 million.
(b) - Our Natural Gas Liquids Pipelines segment’s operations are primarily regulated. Our Natural Gas Liquids Pipelines segment’s non-regulated operations were not material.

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J.           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,
	2009			2008
	(Thousands of dollars)
Northern Border Pipeline	$	16,038		$	19,782
Fort Union Gas Gathering		2,210			2,295
Bighorn Gas Gathering, L.L.C.		2,086			2,318
Lost Creek Gathering Company, L.L.C.		890			1,285
Other		(2	)		2,103
Equity earnings from investments	$	21,222		$	27,783

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,
	2009		2008
	(Thousands of dollars)
Income Statement
Operating revenue	$	106,066	$	111,395
Operating expenses	$	44,803	$	43,344
Net income	$	50,516	$	55,821
Distributions paid to us	$	33,331	$	27,413

K.           LIMITED PARTNERS’ NET INCOME PER UNIT AND DISTRIBUTIONS TO PARTNERS

As discussed in Note A, we adopted EITF 07-4 on January 1, 2009, which requires us to utilize the two-class method of calculating 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, by the weighted-average number of outstanding common units.  ONEOK Partners GP owns the entire 2 percent general partnership interest in us, which entitles it to incentive distribution rights that provide for an increasing proportion of cash distributions from the partnership as the distributions made to limited partners increase above specified levels.

For purposes of our calculation of limited partners’ net income per unit, net income attributable to ONEOK Partners, L.P. is generally allocated to the general partner as follows: (i) an amount based upon the 2 percent general partner interest in net income attributable to ONEOK Partners, L.P. and (ii) the amount of the general partner’s incentive distribution rights based on the total cash distributions declared for the period.  The amount of incentive distribution allocated to our general partner totaled $20.3 million for the three months ended March 31, 2009.

Distributions are limited to available cash.  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 distribution rights would not apply.  For additional information regarding our general partner’s incentive distribution rights, see “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 on Form 10-K for the year ended December 31, 2008.

In January 2009, we declared a cash distribution of $1.08 per unit ($4.32 on an annualized basis) for the fourth quarter of 2008.  The distribution was paid in February 2009, and included a distribution to our general partner of $22.7 million, of which $20.3 million related to incentive distributions.

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In April 2009, we declared a cash distribution of $1.08 per unit ($4.32 per unit on an annualized basis) for the first quarter of 2009.  The distribution will be paid on May 15, 2009, to unitholders of record as of April 30, 2009.

L.           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 Gathering and Fractionation 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 that is leased by OBPI.  Our Processing and Services Agreement with ONEOK and OBPI sets out the terms by which OBPI provides services 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 direct costs and expenses of the Bushton Plant, including reimbursement of 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 operates our interstate natural gas pipeline assets according to each pipeline’s operating agreement.  ONEOK Partners GP may purchase services from ONEOK and its affiliates pursuant to the terms of the Services Agreement.  ONEOK Partners GP has no employees and utilizes the services of ONEOK and ONEOK Services Company to fulfill its responsibilities.

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 allocated by the modified Distrigas method, a method using a combination of ratios that includes gross plant and investment, earnings before interest and taxes and payroll expense.  All costs directly charged or allocated to us are included in our Consolidated Statements of Income.

See Note C for a discussion of our derivative contracts with OES.

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

	Three Months Ended
	March 31,
	2009		2008
	(Thousands of dollars)
Revenues	$	144,135	$	183,335
Expenses
Cost of sales and fuel	$	16,638	$	35,329
Administrative and general expenses		48,623		46,901
Total expenses	$	65,261	$	82,230

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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 on Form 10-Q, as well as our Annual Report on Form 10-K for the year ended December 31, 2008.

EXECUTIVE SUMMARY

The following discussion highlights some of our achievements and significant issues affecting us for the periods presented.  Please refer to the “Capital Projects,” “Financial Results and Operating Information,” and “Liquidity and Capital Resources” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements for additional information.

Outlook - We expect challenging economic conditions for the remainder of 2009, relative to 2008, when we experienced unprecedented drilling activity, supply growth and commodity price levels for natural gas, NGLs and crude oil.  We anticipate that lower commodity prices will result in reduced drilling activity, and current economic conditions will result in reduced demand for NGL products from the petrochemical industry.  We also expect continued volatility and disruption in the financial markets that could result in an increased cost of capital.  We expect depressed commodity prices and tighter capital markets to also result in the sale or consolidation of underperforming assets in the industry, which may present opportunities for us.

Operating Results - Limited partners’ net income per unit decreased to $0.85 for the three months ended March 31, 2009, compared with $1.48 for the same period in 2008.  The decrease in limited partners’ net income per unit for the three-month period is primarily due to the following:

·   a decrease in net margin primarily due to:

-   lower realized commodity prices in our Natural Gas Gathering and Processing segment;

-   narrower NGL product price differentials in our Natural Gas Liquids Gathering and Fractionation segment;

partially offset by

-   increased throughput primarily associated with the completion of the Overland Pass Pipeline and related expansion projects, as well as new supply connections in our natural gas liquids businesses;

-   higher volumes processed and sold in our Natural Gas Gathering and Processing segment; and

-   higher natural gas transportation net margin primarily as a result of the Guardian Pipeline expansion and extension being placed into service in February 2009 in our Natural Gas Pipelines segment;

·   an increase in depreciation expense associated with our completed capital projects; and

·   an increase in interest expense primarily due to increased borrowings to fund our capital projects.

Debt Issuance - In March 2009, we completed an underwritten public offering of $500 million aggregate principal amount of 8.625 percent Senior Notes due 2019.

Cash Distributions - In April 2009, we declared a cash distribution of $1.08 per unit ($4.32 per unit on an annualized basis), an increase of approximately 4 percent over the $1.04 per unit declared in April 2008.

Capital Projects - The following projects were placed in service during the first quarter of 2009:

·   Guardian Pipeline’s expansion and extension project;

·   D-J Basin lateral pipeline; and

·   Williston Basin gas processing plant expansion.

Capital expenditures in 2009 are expected to be significantly lower than in 2008, when we spent approximately $1.3 billion.  We plan to spend approximately $439 million on capital expenditures in 2009, of which approximately $378 million is for growth projects.

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CAPITAL PROJECTS

Overland Pass Pipeline -In November 2008, Overland Pass Pipeline Company completed construction of a 760-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas.  The Overland Pass Pipeline is designed to transport approximately 110 MBbl/d of unfractionated NGLs and can be increased to approximately 255 MBbl/d with additional pump facilities.  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 are currently operating the pipeline.  On or before November 17, 2010, Williams has the option to increase its ownership up to 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 the full 50 percent, Williams would have the option to become operator.  If Williams does not elect to increase its ownership to at least 10 percent, we will have the right, but not the obligation, to purchase Williams’ entire ownership interest, with the purchase price being determined in accordance with the joint venture’s operating agreement.  The pipeline project cost approximately $575 million, excluding AFUDC.

As part of a long-term agreement, Williams dedicated its NGL production from two of its natural gas processing plants in Wyoming, estimated to be approximately 60 MBbl/d, to the Overland Pass Pipeline.  We provide downstream fractionation, storage and transportation services to Williams.  We have also reached agreements with certain producers for supply commitments from the D-J Basin and Piceance lateral pipelines for up to an additional 80 MBbl/d, and we are negotiating agreements with other producers for supply commitments that could add an additional 60 MBbl/d of supply to this pipeline within the next three to five years.

We also invested approximately $239 million, excluding AFUDC, to expand our existing fractionation and storage capabilities and to increase the capacity of our natural gas liquids distribution pipelines.  Part of this expansion included adding new fractionation facilities at our Bushton location, which increased the total fractionation capacity at the Bushton facility to 150 MBbl/d from 80 MBbl/d.  The addition of the new facilities and the upgrade to the existing fractionator was completed in October 2008.  Additionally, portions of our natural gas liquids distribution pipeline upgrades were completed in the second and third quarters of 2008.  Overland Pass Pipeline Company is included in our Natural Gas Liquids Pipelines segment, while the associated expansions are included in our Natural Gas Liquids Gathering and Fractionation segment and Natural Gas Liquids Pipelines segment.

Piceance Lateral Pipeline - In October 2008, Overland Pass Pipeline Company began construction of a 150-mile lateral pipeline with capacity to transport as much as 100 MBbl/d of unfractionated NGLs from the Piceance Basin in Colorado to the Overland Pass Pipeline.  Williams will dedicate its NGL production from an existing natural gas processing plant and a new natural gas processing plant, with estimated volumes totaling approximately 30 MBbl/d, to be transported by the lateral pipeline.  We continue to negotiate with other producers for supply commitments.  Construction is expected to be completed during the third quarter of 2009, assuming we have the necessary regulatory approvals to access the right-of-way during critical construction times.  The project is currently estimated to cost in the range of $110 million to $140 million, excluding AFUDC.  This project is in our Natural Gas Liquids Pipelines segment.

D-J Basin Lateral Pipeline - In March 2009, Overland Pass Pipeline Company placed in service the 125-mile natural gas liquids lateral pipeline from the Denver-Julesburg Basin in northeastern Colorado to the Overland Pass Pipeline.  The pipeline has capacity to transport as much as 55 MBbl/d of unfractionated NGLs.  The project is currently estimated to cost approximately $70 million, excluding AFUDC.  We have supply commitments for up to 33 MBbl/d of unfractionated NGLs with potential for an additional 10 MBbl/d of supply from new drilling and plant upgrades in the next two years.  This project is in our Natural Gas Liquids Pipelines segment.

Arbuckle Natural Gas Liquids Pipeline - Construction continues on the 440-mile Arbuckle Pipeline, a natural gas liquids pipeline from southern Oklahoma through northern Texas and continuing on to the Texas Gulf Coast.  The Arbuckle Pipeline will have the capacity to transport 160 MBbl/d of unfractionated NGLs, expandable to 210 MBbl/d with additional pump facilities, and will connect our existing Mid-Continent infrastructure with our fractionation facility in Mont Belvieu, Texas, and other Gulf Coast region fractionators.  We have supply commitments from producers that we expect will be sufficient to fill the 210 MBbl/d capacity level over the next three to five years.  Much of the Oklahoma and north Texas portions of the pipeline are either complete or nearing completion.  However, right-of-way acquisition has been challenging, time consuming and expensive, which could affect the completion schedule and final cost of the project.  Many of Arbuckle Pipeline’s remaining right-of-way tracts are being acquired through a condemnation process, which adds to the cost and time to construct the pipeline.

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The demand for surface easements has increased dramatically in Texas and Oklahoma in the last two years because of increased oil and natural gas exploration and production activities, as well as pipeline construction.  As previously reported, we anticipate project costs will be more expensive than originally estimated due to delays associated with right-of-way acquisition and weather impacts from anticipated spring rains in wet low-lying areas.  We currently estimate project costs will be in the range of $395 million to $415 million, excluding AFUDC.We expect the project to be operational in the second quarter of 2009.  This project is in our Natural Gas Liquids Pipelines segment.

Williston Basin Gas Processing Plant Expansion - The expansion of our Grasslands natural gas processing facility in North Dakota has been placed in service.  The expansion increases processing capacity to approximately 100 MMcf/d from its current capacity of 63 MMcf/d and increases fractionation capacity to approximately 12 MBbl/d from 8 MBbl/d.  The estimated cost of the project is approximately $46 million, excluding AFUDC.  This project is in our Natural Gas Gathering and Processing segment.

Guardian Pipeline Expansion and Extension - In February 2009, we placed the 119-mile extension of our Guardian Pipeline in full service.  The pipeline has capacity to transport 537 MMcf/d of natural gas north from Ixonia, Wisconsin, to the Green Bay, Wisconsin area.  The project is supported by 15-year shipper commitments with We Energies and Wisconsin Public Service Corporation, and the capacity is close to fully subscribed.  The project cost approximately $325 million, excluding AFUDC, increasing from our previous estimate due to higher costs associated with delays related to weather and equipment delivery.  This project is in our Natural Gas Pipelines segment.

IMPACT OF NEW ACCOUNTING STANDARDS

Information about the impact of the following new accounting standards is included in Note A of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q:

·   Statement 157, “Fair Value Measurements;”

·   Statement 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51;”

·   Statement 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment to FASB Statement No. 133;”

·   EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships;” and

·   FSP 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.”

CRITICAL ACCOUNTING 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 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 on Form 10-K for the year ended December 31, 2008.

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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,						2009 vs. 2008
Financial Results	2009			2008			Increase (Decrease)
	(Millions of dollars)
Revenues	$	1,250.9		$	2,059.0		$	(808.1	)	(39	%)
Cost of sales and fuel		997.4			1,790.5			(793.1	)	(44	%)
Net margin		253.5			268.5			(15.0	)	(6	%)
Operating costs		89.5			88.1			1.4		2	%
Depreciation and amortization		39.9			29.9			10.0		33	%
Gain (loss) on sale of assets		0.7			-			0.7		100	%
Operating income	$	124.8		$	150.5		$	(25.7	)	(17	%)
Equity earnings from investments	$	21.2		$	27.8		$	(6.6	)	(24	%)
Allowance for equity funds used during construction	$	9.0		$	8.5		$	0.5		6	%
Other income (expense)	$	(1.7	)	$	(0.1	)	$	(1.6	)		*
Interest expense	$	(50.9	)	$	(38.5	)	$	12.4		32	%
Net income attributable to noncontrolling interests	$	-		$	(0.1	)	$	(0.1	)	100	%
Capital expenditures	$	192.5		$	267.1		$	(74.6	)	(28	%)
* Percentage change is greater than 100 percent.

2009 vs. 2008 - Net margin decreased primarily due to the following:

·   lower realized commodity prices in our Natural Gas Gathering and Processing segment;

·   narrower NGL product price differentials in our Natural Gas Liquids Gathering and Fractionation segment;

partially offset by

·   increased throughput primarily associated with the completion of the Overland Pass Pipeline and related expansion projects, as well as new supply connections in our natural gas liquids businesses;

·   higher volumes processed and sold in our Natural Gas Gathering and Processing segment; and

·   higher natural gas transportation net margin primarily as a result of the Guardian Pipeline expansion and extension being placed into service in February 2009 in our Natural Gas Pipelines segment.

Operating costs increased primarily due to higher operating costs at our fractionation facilities, which included incremental operating expenses associated with the recently expanded Bushton fractionator that began operations in the third quarter of 2008.  These increases were partially offset by lower general operating costs.

Depreciation and amortization increased primarily due to higher depreciation expense associated with our completed capital projects.

Equity earnings from investments decreased primarily due to lower subscription rates on Northern Border Pipeline and decreased earnings from investments in our Natural Gas Gathering and Processing segment.

Other income (expense) decreased primarily due to lower interest income.

Interest expense increased primarily due to increased borrowings to fund our capital projects.

Capital expenditures decreased primarily due to the completion of the Overland Pass Pipeline and related projects, the Woodford Shale extension and the Guardian Pipeline expansion and extension.

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 of unprocessed natural gas produced from crude oil and natural gas wells.  We gather unprocessed 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 unprocessed natural gas in two producing basins in the Rocky Mountain region: the Williston Basin, which spans portions of Montana, North Dakota and the Canadian province of Saskatchewan, and the Powder River Basin of Wyoming.

In the Mid-Continent and Rocky Mountain regions, 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 generally shipped to fractionators where, through the application of heat and pressure, the unfractionated NGL stream is separated into NGL products.  Revenues for this segment are primarily derived 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.  Our natural gas and NGL products are sold to affiliates and a diverse customer base.

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

	Three Months Ended				Variances
	March 31,				2009 vs. 2008
Financial Results	2009		2008		Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	117.8	$	211.6	$	(93.8	)	(44	%)
Residue gas sales		92.0		186.7		(94.7	)	(51	%)
Gathering, compression, dehydration   and processing fees and other revenue		40.5		38.2		2.3		6	%
Cost of sales and fuel		164.2		332.6		(168.4	)	(51	%)
Net margin		86.1		103.9		(17.8	)	(17	%)
Operating costs		31.8		33.1		(1.3	)	(4	%)
Depreciation and amortization		14.5		11.7		2.8		24	%
Operating income	$	39.8	$	59.1	$	(19.3	)	(33	%)
Equity earnings from investments	$	4.5	$	7.0	$	(2.5	)	(36	%)
Capital expenditures	$	28.8	$	26.5	$	2.3		9	%

	Three Months Ended
	March 31,
Operating Information (a)	2009		2008
Natural gas gathered (BBtu/d)		1,163		1,192
Natural gas processed (BBtu/d)		653		624
NGL sales (MBbl/d)		41		38
Residue gas sales (BBtu/d)		285		277
Realized composite NGL sales price ($/gallon)	$	0.66	$	1.33
Realized condensate sales price ($/Bbl)	$	62.24	$	87.51
Realized residue gas sales price ($/MMBtu)	$	3.59	$	7.40
Realized gross processing spread ($/MMBtu)	$	6.59	$	7.43
(a) - Includes volumes for consolidated entities only.

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	Three Months Ended
	March 31,
Operating Information (a)	2009		2008
Percent of proceeds
Wellhead purchases (MMBtu/d)		60,496		70,594
NGL sales (Bbl/d)		5,040		4,809
Residue gas sales (MMBtu/d)		34,819		36,607
Condensate sales (Bbl/d)		2,095		1,823
Percentage of total net margin		50%		58%
Fee-based
Wellhead volumes (MMBtu/d)		1,163,376		1,191,801
Average rate ($/MMBtu)	$	0.28	$	0.26
Percentage of total net margin		35%		24%
Keep-whole
NGL shrink (MMBtu/d)		16,960		23,515
Plant fuel (MMBtu/d)		2,182		2,488
Condensate shrink (MMBtu/d)		1,755		2,011
Condensate sales (Bbl/d)		355		407
Percentage of total net margin		15%		18%
(a) - Includes volumes for consolidated entities only.

2009 vs. 2008 - Net margin decreased primarily as a result of the following: 

·   a decrease of $27.5 million due to lower realized commodity prices, partially offset by

·   an increase of $8.3 million due to higher volumes processed and sold.

Operating costs decreased primarily due to lower employee-related costs and decreased costs for chemicals.

Depreciation and amortization increased primarily as a result of higher depreciation expense associated with our completed capital projects.

Equity earnings from investments decreased primarily as a result of decreased earnings from our investments.

Capital expenditures increased due to our increased growth activities, primarily in the Rocky Mountain region.

Commodity Price Risk - The following tables set forth our Natural Gas Gathering and Processing segment’s hedging information for the nine months ending December 31, 2009, and for the year ending December 31, 2010, as of April 29, 2009.

	Nine Months Ending
	December 31, 2009
	Volumes Hedged	Average Price		Percentage Hedged
NGLs (Bbl/d) (a)	5,981	$1.07	/ gallon	69%
Condensate (Bbl/d) (a)	1,410	$2.23	/ gallon	68%
Total (Bbl/d)	7,391	$1.29	/ gallon	69%
Natural gas (MMBtu/d)	8,159	$4.20	/ MMBtu	45%
(a) - Hedged with fixed-price swaps.

	Year Ending
	December 31, 2010
	Volumes Hedged	Average Price		Percentage Hedged
NGLs (Bbl/d) (a)	150	$1.54	/ gallon	2%
Condensate (Bbl/d) (a)	520	$1.54	/ gallon	24%
Total (Bbl/d)	670	$1.54	/ gallon	6%
Natural gas (MMBtu/d)	7,828	$5.71	/ MMBtu	39%
(a) - Hedged with fixed-price swaps.

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Commodity price risk related to estimated physical sales of commodities in our Natural Gas Gathering and Processing segment is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at March 31, 2009.  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 $1.2 million;

·   a $1.00 per barrel decrease in the price of crude oil would decrease annual net margin by approximately $1.0 million; and

·   a $0.10 per MMBtu decrease in the price of natural gas would decrease annual net margin by approximately $0.7 million.

The above estimates of commodity price risk exclude the effects of hedging and assume normal operating conditions.  Further, these estimates do not include any effects on demand for our services that might be caused by, or arise in conjunction with, price changes.  For example, a change in the gross processing spread may cause a change in the amount of ethane extracted from the natural gas stream, impacting gathering and processing margins.

Natural Gas Pipelines

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

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

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

·   Viking Gas Transmission, which transports natural gas from an interconnection with TransCanada 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

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

Our intrastate natural gas pipeline assets in Oklahoma have access to the major natural gas producing areas and transport natural gas throughout the state.  We also have access to the major natural gas producing area in south central Kansas.  In Texas, our intrastate natural gas pipelines are connected to the major natural gas producing areas in the Texas panhandle and the Permian Basin and transport natural gas to the Waha Hub, where other pipelines may be accessed for transportation east to the Houston Ship Channel market, north into the Mid-Continent market and west to the California market.

We own storage capacity in 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 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 not subject to rate regulation and have market-based rate authority from the FERC for certain types of services.

- 28 - -

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,				2009 vs. 2008
Financial Results	2009		2008		Increase (Decrease)
	(Millions of dollars)
Transportation revenues	$	56.6	$	62.6	$	(6.0	)	(10	%)
Storage revenues		14.3		14.4		(0.1	)	(1	%)
Gas sales and other revenues		3.9		13.2		(9.3	)	(70	%)
Cost of sales		9.2		26.5		(17.3	)	(65	%)
Net margin		65.6		63.7		1.9		3	%
Operating costs		20.2		23.6		(3.4	)	(14	%)
Depreciation and amortization		12.8		8.4		4.4		52	%
Operating income	$	32.6	$	31.7	$	0.9		3	%
Equity earnings from investments	$	16.2	$	20.1	$	(3.9	)	(19	%)
Allowance for equity funds used during construction	$	1.2	$	2.1	$	(0.9	)	(43	%)
Capital expenditures	$	17.4	$	22.2	$	(4.8	)	(22	%)

	Three Months Ended
	March 31,
Operating Information (a)	2009		2008
Natural gas transported (MMcf/d)		4,200		4,075
Average natural gas price
Mid-Continent region  ($/MMBtu)	$	3.44	$	7.18
(a) - Includes volumes for consolidated entities only.

2009 vs. 2008 -Net margin increased primarily due to an increase of $1.8 million from higher natural gas transportation margins, primarily as a result of the Guardian Pipeline expansion and extension being placed into service in February 2009, and increased retained fuel volumes, partially offset by the impact of lower natural gas prices on retained fuel.

Operating costs decreased primarily due to decreased employee-related costs and lower general operating costs.

Depreciation and amortization increased primarily as a result of higher depreciation expense due to our completed capital projects.

Equity earnings from investments decreased primarily due to lower subscription rates on Northern Border Pipeline.

Allowance for equity funds used during construction and capital expenditures decreased, primarily due to the Guardian Pipeline expansion and extension that was constructed during 2008 and has since been completed.  See discussion of Guardian Pipeline beginning on page 24.

Natural Gas Liquids Gathering and Fractionation

Overview - Our Natural Gas Liquids Gathering and Fractionation assets consist of facilities that gather, fractionate and treat NGLs and store NGL products primarily in Oklahoma, Kansas and Texas, as well as store and fractionate NGLs and NGL products in Mont Belvieu, Texas.  The majority of the pipeline-connected natural gas processing plants in Oklahoma, Kansas and the Texas panhandle, which extract NGLs from unprocessed natural gas, are connected to our NGL 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 distributors.

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Revenues for this segment are primarily derived from exchange services, optimization, isomerization and storage.

·   Our exchange services business collects fees to gather, fractionate and treat unfractionated NGLs, thereby converting them into NGL products that are stored and shipped to a market center or customer-designated location.

·   Our optimization 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 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.

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

	Three Months Ended				Variances
	March 31,				2009 vs. 2008
Financial Results	2009		2008		Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	895.2	$	1,626.1	$	(730.9	)	(45	%)
Storage and fractionation revenues		84.4		80.4		4.0		5	%
Cost of sales and fuel		920.4		1,637.0		(716.6	)	(44	%)
Net margin		59.2		69.5		(10.3	)	(15	%)
Operating costs		22.8		18.6		4.2		23	%
Depreciation and amortization		6.4		5.6		0.8		14	%
Operating income	$	30.0	$	45.3	$	(15.3	)	(34	%)
Capital expenditures	$	13.0	$	29.6	$	(16.6	)	(56	%)

	Three Months Ended
	March 31,
Operating Information	2009		2008
NGLs gathered (MBbl/d)		264		250
NGL sales (MBbl/d)		380		286
NGLs fractionated (MBbl/d)		465		391
Conway-to-Mont Belvieu OPIS average price differential
Ethane ($/gallon)	$	0.08	$	0.09

2009 vs. 2008 - Net margin decreased primarily as a result of the following:

·   a decrease of $16.5 million due to narrower product price differentials between Conway, Kansas, and Mont Belvieu, Texas, and lower marketing margins due to lower prices, partially offset by

·   an increase of $6.4 million due to higher exchange margins primarily related to increased gathering and fractionation volumes associated with new supply connections and Overland Pass Pipeline volumes, as well as increased rates.

Operating costs increased primarily due to incremental operating expenses associated with the recently expanded Bushton fractionator that began operations in the third quarter of 2008, increased outside services expenses at our other fractionators and higher employee-related costs.

Capital expenditures decreased primarily due to the completion of the fractionation and storage expansions related to the Overland Pass Pipeline, which are discussed beginning on page 23.

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Natural Gas Liquids Pipelines

Overview - Our Natural Gas Liquids Pipelines segment primarily owns and operates regulated natural gas liquids gathering and distribution pipelines and associated above- and below-ground NGL storage facilities.  Our natural gas liquids gathering pipelines deliver unfractionated NGLs gathered in Oklahoma, Kansas, the Texas panhandle and the Rocky Mountain region to our Natural Gas Liquids Gathering and Fractionation segment’s Mid-Continent fractionation facilities in Oklahoma and Kansas.  Our natural gas liquids distribution pipelines deliver unfractionated NGLs and NGL products to the natural gas liquids market hubs in Conway, Kansas, and Mont Belvieu, Texas.  Our natural gas liquids distribution and refined petroleum products pipelines connect our Mid-Continent assets with Midwest markets, including Chicago, Illinois.  We operate FERC-regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas, Nebraska, Missouri, Iowa, Illinois, Indiana, Texas, Wyoming and Colorado and terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois. 

Revenues for this segment are primarily derived from transporting product 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 tariffs include specifications regarding the receipt and delivery of NGLs at points along the pipeline systems.  We generally charge tariff rates under a FERC-approved indexing methodology, which allows charging rates up to a prescribed ceiling that changes annually based on the year-to-year change in the Producer Price Index for finished goods.  The FERC also permits interstate natural gas liquids pipelines to support rates by using a cost-of-service methodology, competitive market price or an agreement with a pipeline’s non-affiliated shipper.

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

	Three Months Ended				Variances
	March 31,				2009 vs. 2008
Financial Results	2009		2008		Increase (Decrease)
	(Millions of dollars)
Transportation and gathering revenues	$	53.8	$	34.1	$	19.7		58	%
Storage revenues		0.9		2.6		(1.7	)	(65	%)
NGL sales and other revenues		3.0		2.0		1.0		50	%
Cost of sales and fuel		13.5		7.4		6.1		82	%
Net margin		44.2		31.3		12.9		41	%
Operating costs		15.6		13.4		2.2		16	%
Depreciation and amortization		6.3		4.1		2.2		54	%
Operating income	$	22.3	$	13.8	$	8.5		62	%
Equity earnings from investments	$	0.5	$	0.7	$	(0.2	)	(29	%)
Allowance for equity funds used during construction	$	7.8	$	6.4	$	1.4		22	%
Capital expenditures	$	133.2	$	188.7	$	(55.5	)	(29	%)

	Three Months Ended
	March 31,
Operating Information	2009		2008
NGLs transported-gathering lines (MBbl/d)		163		92
NGLs transported-distribution lines (MBbl/d)		445		303

2009 vs. 2008 - Net margin increased primarily as a result of the following:

·   an increase of $8.9 million in incremental margin from gathering and distribution volumes associated with the startup of the Overland Pass Pipeline, which began operating during the fourth quarter of 2008; and

·   an increase of $5.1 million due to increased throughput on our natural gas liquids distribution pipelines, primarily due to favorable weather patterns increasing propane demand and increased shipments of natural gasoline to meet higher demand in the diluent market.

Operating costs and depreciation and amortization increased primarily due to the startup of the Overland Pass Pipeline.

Capital expenditures decreased primarily due to the completion of the Overland Pass Pipeline and related projects, which are discussed beginning on page 23.

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Contingencies

Legal Proceedings -We are a party to various litigation matters and claims that are in the normal course of our operations.  While the results of litigation and claims cannot be predicted with certainty, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or liquidity.

Mont Belvieu Emissions, Texas Commission on Environmental Quality - As previously reported, we are in discussions with the Texas Commission on Environmental Quality (TCEQ) staff regarding air emissions at our Mont Belvieu fractionator, which may have exceeded the emissions allowed under our air permit.  On March 13, 2009, the TCEQ issued a Notice of Enforcement, alleging that we failed to isolate the source of the emissions in a timely manner.  In a letter dated April 15, 2009, the TCEQ proposed settling the matter by entering into an Agreed Order with an administrative penalty of $160,000 and requiring us to perform certain preventative procedures.  We are evaluating this proposal and preparing a response.  

LIQUIDITY AND CAPITAL RESOURCES

General -Part of our strategy is to grow through acquisitions and internally-generated growth projects 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.

During 2008 and continuing into 2009, the capital markets experienced volatility and disruption, which could limit our access to those markets or increase the cost of issuing new securities in the future.  During this period, we have continued to have access to our $1.0 billion Partnership Credit Agreement to fund our short-term liquidity needs.

We expect challenging economic conditions in 2009, with downward pressures, relative to 2008, on commodity prices.  We also expect continued volatility and disruption in the financial markets.  Our ability to continue to access capital markets for debt and equity financing under reasonable terms depends on our financial condition, credit ratings and market conditions.  We anticipate that our cash flow generated from operations, existing capital resources and ability to obtain financing will enable us to maintain our current level of operations and our planned operations, collateral requirements and capital expenditures.

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

	March 31,			December 31,
	2009			2008
Long-term debt		52	%		47	%
Equity		48	%		53	%
Debt (including notes payable)		55	%		54	%
Equity		45	%		46	%

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 under FERC regulations.  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.

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Short-term Liquidity - Our principal sources of short-term liquidity consist of cash generated from operating activities and borrowings under 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, 2009, we had $436.7 million of borrowings outstanding and $563.3 million available under our Partnership Credit Agreement, which expires in March 2012, and available cash and cash equivalents of approximately $1.1 million.  As of March 31, 2009, we could have issued $706.4 million of additional short- and long-term debt under the most restrictive provisions contained in our Partnership Credit Agreement.  We have a total of $49.2 million issued in letters of credit outside of the Partnership Credit Agreement.

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 on Form 10-K for the year ended December 31, 2008.  At March 31, 2009, our ratio of indebtedness to adjusted EBITDA (EBITDA, as adjusted for all non-cash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) was 4.2 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.

Long-term Financing - In addition to our principal sources of short-term liquidity discussed above, options available to us to meet our longer-term cash requirements include the issuance of common units or long-term notes.  Other options to obtain financing include, but are not limited to, issuance of convertible debt securities and asset securitization, and the sale and leaseback of facilities.

We are subject, however, to changes in the equity and debt 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, which may include issuing common units to ONEOK in a private placement transaction.  Some of these alternatives could involve higher costs or negatively affect our credit ratings, among other factors.  Based on our investment-grade credit ratings, general financial condition and market expectations regarding our future earnings and projected cash flows, we believe that we will be able to meet our cash requirements and maintain our investment-grade credit ratings.

Debt Issuance - In March 2009, we completed an underwritten public offering of $500 million aggregate principal amount of 8.625 percent Senior Notes due 2019.  The 2019 Notes were issued under our existing shelf registration statement filed with the SEC.

We may redeem the 2019 Notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium.  The redemption price will never be less than 100 percent of the principal amount of the 2019 Notes plus accrued and unpaid interest to the redemption date.  The 2019 Notes 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 our non-guarantor subsidiaries.  The 2019 Notes are nonrecourse to our general partner.  For more information regarding the 2019 Notes, refer to discussion in Note F of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Debt Covenants - The terms of the 2019 Notes are governed by an indenture, dated as of September 25, 2006, between us and Wells Fargo Bank, N.A., as trustee, as supplemented by the Fifth Supplemental Indenture, dated March 3, 2009 (Indenture).  The Indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series.  The Indenture contains covenants including, among other provisions, limitations on our ability to place liens on our property or assets and to sell and lease back our property.

Our $250 million and $225 million senior notes, due 2010 and 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.  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 governing 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.

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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 $192.5 million and $267.1 million for three months ended March 31, 2009 and 2008, 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 2009 capital expenditures are significantly less than 2008 capital expenditures due to the completion of the Overland Pass Pipeline and related projects, the Woodford Shale extension and the Guardian Pipeline expansion and extension.  Additional information about our growth capital expenditures is included under “Capital Projects” on page 23.

The following table summarizes our 2009 projected growth and maintenance capital expenditures, excluding AFUDC.

2009 Projected Capital Expenditures	Growth		Maintenance		Total
	(Millions of dollars)
Natural Gas Gathering and Processing	$	74	$	19	$	93
Natural Gas Pipelines		63		19		82
Natural Gas Liquids Gathering and Fractionation		36		13		49
Natural Gas Liquids Pipelines		205		10		215
Total projected capital expenditures	$	378	$	61	$	439

Investment in Northern Border Pipeline - In March 2009, we made an equity contribution of $4.3 million to Northern Border Pipeline.  Northern Border Pipeline anticipates requiring an additional equity contribution of approximately $76 million from its partners in the third quarter of 2009, of which our share will be approximately $38 million based on our 50 percent equity interest.

Credit Ratings - Our credit ratings as of March 31, 2009, 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 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.  See additional discussion about our credit ratings under “Debt Covenants.”

In the event of a default under our senior notes, 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 or seek alternative financing sources 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.

Other than the note repurchase obligations described above under “Debt Covenants,” 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.

In the normal course of business, our counterparties provide us with secured and unsecured credit.  In the event of a downgrade in our credit rating or a significant change in our counterparties’ evaluation of our creditworthiness, we could be asked to provide additional collateral in the form of cash, letters of credit or other negotiable instruments.

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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.

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,
	2009		2008
	(Millions of dollars)
Common unitholders	$	58.8	$	47.6
Class B unitholders	39.4		37.4
General Partner	22.7		16.2
Total cash distributions paid before noncontrolling interests	$	120.9	$	101.2

The following summarizes our quarterly cash distribution activity for 2009.

·   In January 2009, we declared a cash distribution of $1.08 per unit for the fourth quarter of 2008.  The distribution was paid on February 13, 2009, to unitholders of record on January 30, 2009.

·   In April 2009, we declared a cash distribution of $1.08 per unit for the first quarter of 2009.  The distribution will be paid on May 15, 2009, to unitholders of record as of April 30, 2009.

Our general partner’s percentage interest in quarterly distributions increases after certain specified target levels are met.  For additional information, see “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 on Form 10-K for the year ended December 31, 2008.

Commodity Prices - We are subject to commodity price volatility.  Significant fluctuations in commodity prices may impact our overall liquidity due to the impact commodity price changes have on our cash flows from operating activities, including the impact on working capital for NGLs and natural gas held in storage, margin requirements and certain energy-related receivables.  We believe that our available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity price volatility.  See Note C of the Notes to Consolidated Financial Statements and the discussion under Natural Gas Gathering and Processing’s “Commodity Price Risk” in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Quarterly Report on Form 10-Q for information on our hedging activities.

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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 on sale of assets, noncontrolling interests in income of consolidated subsidiaries, and undistributed earnings from equity investments in excess of distributions received.

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,						2009 vs. 2008
	2009			2008			Increase (Decrease)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	74.7		$	242.1		$	(167.4	)	(69	%)
Investing activities		(188.0	)		(261.2	)		73.2		28	%
Financing activities		(63.2	)		248.7			(311.9	)		*
Change in cash and cash equivalents		(176.5	)		229.6			(406.1	)		*
Cash and cash equivalents at beginning of period		177.6			3.2			174.4			*
Cash and cash equivalents at end of period	$	1.1		$	232.8		$	(231.7	)	(100	%)
* Percentage change is greater than 100 percent.

Operating Cash Flows - Operating cash flows decreased, primarily due to changes in the components of working capital.  These changes decreased operating cash flows by $59.1 million for the three months ended March 31, 2009, compared with an increase of $79.3 million for the same period in 2008, primarily due to decreases in cash flows from accounts payable and accounts receivable in 2009 relative to 2008.  The decrease in operating cash flows was also impacted by decreased net income for the three months ended March 31, 2009, compared with the same period in 2008.

Investing Cash Flows - Investing cash flows for the three months ended March 31, 2009, include decreased capital expenditures of $74.6 million, compared with the same period in 2008, due to decreased spending for our capital projects.

Financing Cash Flows - 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.  Net repayments of notes payable were $433.3 million during the first quarter of 2009.

Cash distributions to our general and limited partners for the first quarter of 2009 were $120.9 million, compared with $101.1 million in the same period in 2008, an increase of $19.8 million.  This increase was due to additional units outstanding during 2009, as well as cash distributions of $1.08 per unit during the first quarter of 2009, compared with $1.025 per unit in the first quarter of 2008.

In the first quarter of 2008, our common unit offering and private placement of common units generated proceeds of approximately $443.6 million.  In addition, ONEOK Partners GP contributed $9.4 million in order to maintain its 2 percent general partner interest in us.  We used a portion of the proceeds and general partner contributions to repay borrowings under our Partnership Credit Agreement.  Net repayments of notes payable were $100 million during the first quarter of 2008.

ENVIRONMENTAL AND SAFETY MATTERS

Information about our environmental matters is included in Note G of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Pipeline Safety - We are subject to United States Department of Transportation regulations, including integrity management regulations.  The Pipeline Safety Improvement Act requires pipeline companies to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high consequence areas.  To our knowledge, we are in compliance with all material requirements associated with the various pipeline safety regulations.  Further, we cannot assure that existing pipeline safety regulations will not be revised or that new regulations will not be adopted that could result in increased compliance costs or additional operating restrictions.

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Air and Water Emissions - The federal Clean Air Act, the federal 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.  To our knowledge, we are in compliance with all material requirements associated with the various regulations.

The United States Congress is actively considering legislation to reduce emissions of greenhouse gases, including carbon dioxide and methane.  In addition, 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, based on 2007 data, is estimated to be less than 6 million metric tons of carbon dioxide equivalents on an annual basis.  We expect to complete our annual estimate for 2008 during the second quarter of 2009 and will post the information on our Web site when available.  We will continue efforts to quantify our direct greenhouse gas emissions and will report such emissions as required by any mandatory reporting rule, including the rules anticipated to be issued by the United States Environmental Protection Agency (EPA) in mid-2009.

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 one of four risked-based tiers ranging from high (Tier 1) to low (Tier 4) risk, or not tiered at all due to low risk.  A majority of our facilities were not tiered.  We are currently waiting for Homeland Security’s analysis to determine if any of the tiered facilities will require Site Security Plans and possible physical security enhancements.  In addition, the Transportation Security Administration, along with the Department of Transportation, has completed a review and inspection of our “critical facilities” with no material issues.

Climate Change - 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 rules anticipated to be issued by the EPA in mid-2009, (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 participate in the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions.  We were honored in 2008 as the “Natural Gas STAR Gathering and Processing Partner of the Year” for our efforts to positively address environmental issues through voluntary implementation of emission-reduction opportunities.  In addition, we continue to focus on maintaining low rates of lost-and-unaccounted-for methane gas through expanded implementation of best practices to limit the release of methane gas during pipeline and facility maintenance and operations.  Our most recent calculation of our annual lost-and-unaccounted-for natural gas, for all of our business operations, is less than 1 percent of total throughput.  We expect to complete our annual estimate for 2008 during the second quarter of 2009 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 on Form 10-Q are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act, as amended.  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 on Form 10-Q identified by words such as “anticipate,” “estimate,” “expect,” “project,”  “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” and other words and terms of similar meaning.

You should not place undue reliance on forward-looking statements.  Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements.  Those factors may affect our operations, markets, products, services and prices.  In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:

·   the effects of weather and other natural phenomena on our operations, demand for our services and energy prices;

·   competition from other United States and Canadian energy suppliers and transporters, as well as alternative forms of energy, including, but not limited to, 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 refinery-grade 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 to 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 increasing liquidity risks in U.S. credit markets;

·   the impact of recently issued and future accounting pronouncements 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 on Form 10-K for the year ended December 31, 2008.  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 on Form 10-K for the year ended December 31, 2008.

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 on Form 10-Q 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 ONEOK 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, 2009, 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, 2009, 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 on Form 10-K for the year ended December 31, 2008.

Mont Belvieu Emissions, Texas Commission on Environmental Quality - As previously reported, we are in discussions with the Texas Commission on Environmental Quality (TCEQ) staff regarding air emissions at our Mont Belvieu fractionator, which may have exceeded the emissions allowed under our air permit.  On March 13, 2009, the TCEQ issued a Notice of Enforcement, alleging that we failed to isolate the source of the emissions in a timely manner.  In a letter dated April 15, 2009, the TCEQ proposed settling the matter by entering into an Agreed Order with an administrative penalty of $160,000 and requiring us to perform certain preventative procedures.  We are evaluating this proposal and preparing a response.  

ITEM 1A. RISK FACTORS

Our investors should consider the risks set forth in Part I, Item 1A, Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2008, that could affect us and our business.  Although we have tried to discuss key factors, our investors need to be aware that other risks may prove to be important in the future.  New risks may emerge at any time and we cannot predict such risks or estimate the extent to which they may affect our financial performance.  Investors should carefully consider the discussion of risks and the other information included or incorporated by reference in this Quarterly Report on Form 10-Q, 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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not Applicable.

ITEM 5. OTHER INFORMATION

Not Applicable.

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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 on Form 10-Q (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 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 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 on Form 10-Q:

Exhibit No. Exhibit Description

4.1 Fifth Supplemental Indenture, dated as of March 3, 2009, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 8.625 percent Senior Notes due 2019 (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K, filed by ONEOK Partners, L.P. on March 3, 2009 (File No. 1-12202)).

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)).

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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 30, 2009		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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