form_10-q.htm

10-Q 1 form_10-q.htm FORM 10-Q form_10-q.htm

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 September 30, 2009

___ 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					(I.R.S. Employer Identification No.)
incorporation or organization)

100 West Fifth Street, Tulsa, OK					74103
(Address of principal executive offices)					(Zip Code)

Registrant’s telephone number, including area code (918) 588-7000

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No __

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every

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

Yes __ No __

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

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

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

Yes __ No X

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

Class			Outstanding at October 30, 2009
Common units			59,912,777 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 and Nine Months Ended September 30, 2009 and 2008	5
	Consolidated Balance Sheets - September 30, 2009, and December 31, 2008	6
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2009 and 2008	7
	Consolidated Statement of Changes in Partners’ Equity - Nine Months Ended September 30, 2009	8-9
	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2009 and 2008	10
	Notes to Consolidated Financial Statements	11-23
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24-42
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42
Item 4.	Controls and Procedures	43
Part II.	Other Information
Item 1.	Legal Proceedings	43-44
Item 1A.	Risk Factors	44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 3.	Defaults Upon Senior Securities	44
Item 4.	Submission of Matters to a Vote of Security Holders	44
Item 5.	Other Information	44
Item 6.	Exhibits	44-45
Signature		46

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

The statements in this Quarterly Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “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” and Part II, Item 1A, “Risk Factors” in this Quarterly Report and under Part 1, Item 1A, "Risk Factors,” in our Annual Report.

INFORMATION AVAILABLE ON OUR WEB SITE

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

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

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GLOSSARY

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

AFUDC

Allowance for funds used during construction

Annual Report

Annual Report on Form 10-K for the year ended December 31, 2008

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(s)

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

temperature of one pound of water one degree Fahrenheit

Bushton Plant

Bushton Gas Processing Plant

EBITDA

Earnings before interest, taxes, depreciation and amortization

Exchange Act

Securities Exchange Act of 1934, as amended

FASB

Financial Accounting Standards Board

FERC

Federal Energy Regulatory Commission

GAAP

Accounting principles generally accepted in the United States of America

Guardian Pipeline

Guardian Pipeline, L.L.C.

Intermediate Partnership

ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary

of ONEOK Partners, L.P.

KCC

Kansas Corporation Commission

MBbl

Thousand barrels

MBbl/d

Thousand barrels per day

Midwestern Gas Transmission

Midwestern Gas Transmission Company

MMBbl

Million barrels

MMBtu

Million British thermal units

MMBtu/d

Million British thermal units per day

MMcf/d

Million cubic feet per day

Moody’s

Moody’s Investors Service, Inc.

NBP Services

NBP Services, LLC, a wholly owned subsidiary of ONEOK

NGL products

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

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

NGL(s)

Natural gas liquid(s)

Northern Border Pipeline

Northern Border Pipeline Company

NYMEX

New York Mercantile Exchange

OBPI

ONEOK Bushton Processing Inc.

OCC

Oklahoma Corporation Commission

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

Quarterly Report(s)

Quarterly Report(s) on Form 10-Q

S&P

Standard & Poor’s Rating Group

SEC

Securities and Exchange Commission

Securities Act

Securities Act of 1933, as amended

XBRL

eXtensible Business Reporting Language

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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Unaudited)	2009			2008			2009			2008
	(Thousands of dollars, except per unit amounts)

Revenues	$	1,560,003		$	2,241,107		$	4,207,925		$	6,444,034
Cost of sales and fuel		1,267,124			1,915,707			3,399,523			5,569,176
Net margin		292,879			325,400			808,402			874,858
Operating expenses
Operations and maintenance		92,855			86,456			258,246			243,929
Depreciation and amortization		41,857			30,408			121,750			90,383
General taxes		12,253			11,032			36,815			28,799
Total operating expenses		146,965			127,896			416,811			363,111
Gain (loss) on sale of assets		(1,180	)		22			2,760			50
Operating income		144,734			197,526			394,351			511,797
Equity earnings from investments (Note K)		20,054			29,412			55,464			74,805
Allowance for equity funds used during construction		7,290			15,616			25,761			35,788
Other income		5,026			990			8,841			3,724
Other expense		(299	)		(5,784	)		(2,728	)		(7,951	)
Interest expense		(50,371	)		(34,447	)		(152,167	)		(107,681	)
Income before income taxes		126,434			203,313			329,522			510,482
Income taxes		(4,729	)		670			(10,668	)		(6,703	)
Net income		121,705			203,983			318,854			503,779
Less: Net income attributable to noncontrolling interests		212			111			232			368
Net income attributable to ONEOK Partners, L.P.	$	121,493		$	203,872		$	318,622		$	503,411

Limited partners’ interest in net income:
Net income attributable to ONEOK Partners, L.P.	$	121,493		$	203,872		$	318,622		$	503,411
General partner’s interest in net income		(25,010	)		(24,397	)		(70,710	)		(65,790	)
Limited partners’ interest in net income	$	96,483		$	179,475		$	247,912		$	437,621

Limited partners’ net income per unit, basic and diluted (Note L)	$	1.00		$	1.97		$	2.67		$	4.93

Number of units used in computation (thousands)		96,402			90,920			92,932			88,768
See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	September 30,		December 31,
(Unaudited)	2009		2008
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	30,535	$	177,635
Accounts receivable, net		445,185		317,182
Affiliate receivables		21,532		25,776
Gas and natural gas liquids in storage		187,773		190,616
Commodity exchanges and imbalances		85,073		55,086
Derivative financial instruments (Notes B and C)		5,983		63,780
Other current assets		41,713		28,176
Total current assets		817,794		858,251

Property, plant and equipment
Property, plant and equipment		6,250,762		5,808,679
Accumulated depreciation and amortization		933,264		875,279
Net property, plant and equipment (Note I)		5,317,498		4,933,400

Investments and other assets
Investments in unconsolidated affiliates		774,347		755,492
Goodwill and intangible assets		670,786		676,536
Other assets		36,619		30,593
Total investments and other assets		1,481,752		1,462,621
Total assets	$	7,617,044	$	7,254,272

Liabilities and partners’ equity
Current liabilities
Current maturities of long-term debt	$	261,931	$	11,931
Notes payable (Note F)		515,000		870,000
Accounts payable		508,331		496,763
Affiliate payables		32,489		23,333
Commodity exchanges and imbalances		204,401		191,165
Other current liabilities		159,154		100,832
Total current liabilities		1,681,306		1,694,024

Long-term debt, excluding current maturities (Note G)		2,826,016		2,589,509

Deferred credits and other liabilities		60,717		54,773

Commitments and contingencies (Note H)

Partners’ equity
ONEOK Partners, L.P. partners’ equity:
General partner		83,798		77,546
Common units: 59,912,777 and 54,426,087 units issued and outstanding at September 30, 2009 and December 31, 2008, respectively		1,571,123		1,361,058
Class B units: 36,494,126 units issued and outstanding at September 30, 2009 and December 31, 2008		1,386,000		1,407,016
Accumulated other comprehensive income (Note D)		2,499		64,405
Total ONEOK Partners, L.P. partners’ equity		3,043,420		2,910,025

Noncontrolling interests in consolidated subsidiaries		5,585		5,941

Total partners’ equity		3,049,005		2,915,966
Total liabilities and partners’ equity	$	7,617,044	$	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	Nine Months Ended
	September 30,
(Unaudited)	2009			2008
	(Thousands of dollars)
Operating activities
Net income	$	318,854		$	503,779
Depreciation and amortization		121,750			90,383
Allowance for equity funds used during construction		(25,761	)		(35,788	)
Gain on sale of assets		(2,760	)		(50	)
Equity earnings from investments		(55,464	)		(74,805	)
Distributions received from unconsolidated affiliates		56,896			67,812
Changes in assets and liabilities:
Accounts receivable		(128,003	)		98,214
Affiliate receivables		4,244			9,245
Gas and natural gas liquids in storage		2,843			(59,690	)
Derivative financial instruments		(3,035	)		(47,017	)
Accounts payable		20,375			(52,516	)
Affiliate payables		9,156			11,401
Commodity exchanges and imbalances, net		(16,751	)		(3,521	)
Accrued interest		29,695			32,117
Other assets and liabilities		16,999			29,101
Cash provided by operating activities		349,038			568,665

Investing activities
Changes in investments in unconsolidated affiliates		(19,878	)		3,063
Acquisitions		-			2,450
Capital expenditures (less allowance for equity funds used during construction)		(491,256	)		(860,167	)
Proceeds from sale of assets		8,528			133
Cash used in investing activities		(502,606	)		(854,521	)

Financing activities
Cash distributions:
General and limited partners		(370,094	)		(332,090	)
Noncontrolling interests		(588	)		(223	)
Borrowing of notes payable, net		515,000			180,000
Repayment of notes payable with maturities over 90 days		(870,000	)		-
Issuance of long-term debt, net of discounts		498,325			-
Long-term debt financing costs		(4,000	)		-
Repayment of long-term debt		(8,948	)		(8,947	)
Issuance of common units, net of discounts		241,643			450,198
Contribution from general partner		5,130			9,508
Cash provided by financing activities		6,468			298,446
Change in cash and cash equivalents		(147,100	)		12,590
Cash and cash equivalents at beginning of period		177,635			3,213
Cash and cash equivalents at end of period	$	30,535		$	15,803
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)	Common Units		Class B Units		General Partner			Common Units
	(Units)				(Thousands of dollars)

December 31, 2008		54,426,087		36,494,126	$	77,546		$	1,361,058
Net income		-		-		70,710			150,688
Other comprehensive loss (Note D)		-		-		-			-
Issuance of common units (Note E)		5,486,690		-		-			241,643
Contribution from general partner (Note E)		-		-		5,130			-
Distributions paid (Note E)		-		-		(69,588	)		(182,266	)
September 30, 2009		59,912,777		36,494,126	$	83,798		$	1,571,123
See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY
(Continued)

	ONEOK Partners, L.P. Partners’ Equity
				Accumulated Other Comprehensive Income			Noncontrolling Interests in Consolidated Subsidiaries
										Total Partners’ Equity
	Class B Units
(Unaudited)	Class B Units
	(Thousands of dollars)

December 31, 2008	$	1,407,016		$	64,405		$	5,941		$	2,915,966
Net income		97,224			-			232			318,854
Other comprehensive loss (Note D)		-			(61,906	)		-			(61,906	)
Issuance of common units (Note E)		-			-			-			241,643
Contribution from general partner (Note E)		-			-			-			5,130
Distributions paid (Note E)		(118,240	)		-			(588	)		(370,682	)
September 30, 2009	$	1,386,000		$	2,499		$	5,585		$	3,049,005

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

		Three Months Ended					Nine Months Ended
		September 30,					September 30,
(Unaudited)		2009			2008		2009			2008
	(Thousands of dollars)

Net income		$	121,705		$	203,983	$	318,854		$	503,779
Other comprehensive income (loss) (Note D)			(13,418	)		80,863		(61,906	)		44,563
Comprehensive income			108,287			284,846		256,948			548,342
Less: Comprehensive income attributable to noncontrolling interests			212			111		232			368
Comprehensive income attributable to ONEOK Partners, L.P.		$	108,075		$	284,735	$	256,716		$	547,974
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.

As a result of increased integration within our natural gas liquids business, we implemented changes to the structure of our previous reportable business segments during the third quarter of 2009 to better align them with how we manage our businesses. Our financial results are now reported in three segments: (i) Natural Gas Gathering and Processing; (ii) Natural Gas Pipelines, both of which remain unchanged; and (iii) Natural Gas Liquids, which is comprised of our former natural gas liquids gathering and fractionation segment and our former natural gas liquids pipelines segment. Prior period amounts have been recast to reflect these segment changes.

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

Goodwill Impairment Test - We assess our goodwill for impairment at least annually. There were no impairment charges resulting from our July 1, 2009, impairment test.

Recently Issued Accounting Updates

The following recently issued accounting updates affect our consolidated financial statements during 2009:

FASB Accounting Standards Codification - In June 2009, the FASB established the FASB Accounting Standards Codification (Codification) as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP. While the Codification does not change GAAP, it does change the manner in which we reference authoritative accounting principles in our consolidated financial statements. The Codification is effective for and has been implemented in this Quarterly Report.

Noncontrolling Interests - Effective for our year beginning January 1, 2009, we retroactively adopted new presentation and disclosure requirements for existing noncontrolling interests (previously referred to as minority interests). We report noncontrolling interests as a component of equity in our Consolidated Balance Sheets and the amounts of consolidated net income attributable to noncontrolling interests and to us in our Consolidated Statements of Income.

Derivative Instruments and Hedging Activities - Effective for our year beginning January 1, 2009, we provide enhanced disclosures about how derivative and hedging activities affect our financial position, financial performance and cash flows. These additional disclosures have been applied prospectively. See Note C for applicable disclosures.

Fair Value Measurements - As of January 1, 2009, we began measuring our assets and liabilities that are measured at fair value on a nonrecurring basis subsequent to initial recognition based upon a revised definition of fair value. The impact of these measurement changes was not material. See Note B for disclosures of our fair value measurements.

Measuring Liabilities at Fair Value - In August 2009, the FASB provided clarification for measuring liabilities at fair value. When a quoted price in an active market for an identical liability is not available, we will be required to measure fair value using a valuation technique that uses quoted prices of similar liabilities, quoted prices of identical or similar liabilities when traded as assets, or another valuation technique that is consistent with GAAP, such as the income or market approach. Additionally, when estimating the fair value of a liability, we will not be required to include a separate input or adjustment to other inputs relating to the existence of a restriction that prevents the transfer of the liability. We will consider liabilities measured using an unadjusted quoted price in an active market for either an identical liability or an identical liability when traded as an asset as a Level 1 fair value measurement. We will apply this guidance when measuring liabilities at fair value beginning in the fourth quarter of 2009 and do not expect the impact on those measurements to be material.

Limited Partners’ Net Income Per Unit - Effective for our year beginning January 1, 2009, the Emerging Issues Task Force issued guidance aimed to improve the comparability of net income per unit calculations for master limited partnerships

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with incentive distributions rights. We retroactively applied this guidance, and there was no impact on our limited partners’ net income per unit for the three and nine months ended September 30, 2009 and 2008. See Note L for a discussion of our calculation of basic and diluted limited partners’ net income per unit.

Interim Disclosures about Fair Value - Effective for our quarter ended June 30, 2009, we provide disclosures of fair value of financial instruments for interim reporting periods. These disclosures are included in Note B.

Subsequent Events - Effective for our quarter ended June 30, 2009, the FASB established standards related to the accounting for and disclosure of events that occur after the balance sheet date but before consolidated financial statements are issued. We have evaluated subsequent events through November 5, 2009, the date our consolidated financial statements were issued, and all required disclosures have been made.

B. FAIR VALUE MEASUREMENTS

Refer to Notes A and C of the Notes to Consolidated Financial Statements in our Annual Report 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:

	September 30, 2009
	Level 1		Level 2			Level 3			Netting (a)			Total
	(Thousands of dollars)
Derivatives
Assets (b)	$	-	$	6,143		$	7,316		$	(7,476	)	$	5,983
Liabilities (c)	$	-	$	(4,444	)	$	(4,106	)	$	7,476		$	(1,074	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheet on a net basis. We net derivative assets and liabilities when a legally enforceable master netting arrangement exists between us and the counterparty to a derivative contract.
(b) - Included in derivative financial instruments in our Consolidated Balance Sheet.
(c) - Included in deferred credits and other liabilities in our Consolidated Balance Sheet.

	December 31, 2008
	Level 1		Level 2		Level 3		Netting (a)		Total
	(Thousands of dollars)
Derivatives
Assets (b)	$	-	$	26,131	$	37,649	$	-	$	63,780
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheet on a net basis. We net derivative assets and liabilities when a legally enforceable master netting arrangement exists between us and the counterparty to a derivative contract.
(b) - Included in derivative financial instruments in our Consolidated Balance Sheet.

At September 30, 2009, and December 31, 2008, we had no cash collateral held or posted under our master netting arrangements.

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.

Our derivative instruments categorized as Level 2 include non-exchange traded fixed-price swaps for natural gas and condensate that are valued based on NYMEX-settled prices for natural gas and crude oil, respectively. Our derivative instruments categorized as Level 3 include over-the-counter fixed-price swaps for purity NGL products and natural gas basis swaps. These swaps are valued based on information from a pricing service, the forward NYMEX curve for crude oil, correlations of specific NGL purity products to crude oil and internally developed basis curves incorporating observable and unobservable market data. We corroborate the data on which our fair value estimates are based using our market knowledge of recent transactions and day-to-day pricing fluctuations and analysis of historical relationships of data from the pricing service compared with actual settlements and correlations. We do not believe that our Level 3 fair value estimates have a material impact on our results of operations, as the majority of our derivatives are accounted for as cash flow hedges for which ineffectiveness is not material.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Derivative Assets (Liabilities)	2009			2008			2009			2008
	(Thousands of dollars)
Net assets (liabilities) at beginning of period	$	11,597		$	(37,704	)	$	37,649		$	(16,400	)
Total realized/unrealized gains (losses):
Included in earnings (a)		1,652			(3,407	)		3,738			(2,434	)
Included in other comprehensive income (loss)		(10,039	)		56,176			(38,177	)		33,899
Net assets (liabilities) at end of period	$	3,210		$	15,065		$	3,210		$	15,065

Total gains (losses) for the period included in earnings
attributable to the change in unrealized gains (losses)
relating to assets and liabilities still held as of the end
of the period (a)	$	51		$	(3,422	)	$	51		$	(3,422	)
(a) - Included in revenues in our Consolidated Statements of Income.

Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable and accounts payable is equal to book value, due to its short-term nature. The fair value of borrowings under our $1.0 billion amended and restated revolving credit agreement dated March 30, 2007 (Partnership Credit Agreement), approximates the carrying value since the interest rates are periodically adjusted to reflect current market conditions.

The estimated fair value of the aggregate of our senior notes outstanding, including current maturities, was $3.3 billion at September 30, 2009. The book value of the aggregate of our senior notes outstanding, including current maturities, was $3.1 billion at September 30, 2009. The estimated fair value of the aggregate of our senior notes outstanding has been determined using quoted market prices for similar issues with similar terms and maturities.

C. RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

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

Commodity price risk - Commodity price risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in the price of natural gas, NGLs and crude oil. 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.

In our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk, primarily NGLs and natural gas, as a result of receiving commodities in exchange for services associated with our POP contracts. To a lesser extent, exposures arise from the relative price differential between NGLs and natural gas, or the gross processing spread, with respect to our keep-whole processing contracts. We are also exposed to basis risk between the various production and market locations where we buy and sell commodities. As part of our hedging strategy, we use the previously described commodity derivative instruments to minimize the impact of price fluctuations related to natural gas, NGLs and condensate. We reduce our gross processing spread exposure through a combination of physical and financial hedges. We utilize a portion of our

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POP equity natural gas as an offset, or natural hedge, to an equivalent portion of our keep-whole shrink requirements. This has the effect of converting our gross processing spread risk to NGL commodity price risk. We hedge a portion of the forecasted sales of the commodities we retain, including NGLs, natural gas and condensate.

In our Natural Gas Pipelines segment, we are exposed to commodity price risk because our intrastate and interstate natural gas pipelines collect natural gas from our customers for operations or as part of our fee for services provided. When the amount of natural gas consumed in operations by these pipelines differs from the amount provided by our customers, our pipelines must buy or sell natural gas, or store or use natural gas from inventory, which can expose us to commodity price risk depending on the regulatory treatment for this activity. We use physical forward sales to reduce the impact of price fluctuations related to natural gas. At September 30, 2009, we were not using any financial derivative instruments with respect to our natural gas pipeline operations.

In our Natural Gas Liquids segment, we are exposed to basis risk primarily as a result of the relative value of NGL purchases at one location and sales at another location. To a lesser extent, we are exposed to commodity price risk resulting from the relative values of the various NGL products to each other, NGLs in storage and the relative value of NGLs to natural gas. We utilize fixed-price physical forward contracts to reduce the impact of price fluctuations related to NGLs. At September 30, 2009, we were not using any financial derivative instruments with respect to our NGL activities.

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.

Accounting Treatment - We record derivative instruments at fair value, with the exception of normal purchases and normal sales that are expected to result in physical delivery. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a cash flow hedging relationship and, if so, the reason for holding it.

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

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

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

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

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Fair Values of Derivative Instruments - Fair value is defined 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 September 30, 2009, we had $13.5 million of derivative assets and $8.6 million of derivative liabilities, excluding the impact of netting, all of which related to commodity contracts.

As of September 30, 2009, we had fixed-price natural gas swaps with a notional quantity of 4.4 Bcf and natural gas basis swaps with a notional quantity of 4.4 Bcf. Additionally, we had fixed-price crude oil and NGL swaps with a notional quantity of 1.5 MMBbl.

Cash Flow Hedges - At September 30, 2009, our Consolidated Balance Sheet reflected a net unrealized gain of $6.4 million in accumulated other comprehensive income (loss), with a corresponding offset in derivative financial instrument assets and liabilities that will be realized within the next 15 months as the forecasted transactions affect earnings. If prices remain at current levels, we will recognize $7.4 million in gains over the next 12 months, and we will recognize losses of $1.0 million thereafter.

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

Derivatives in Cash Flow Hedging Relationships	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
	(Thousands of dollars)
Commodity contracts	$	(1,588	)	$	(15,232	)
Interest rate contracts		1,035			1,599
Total gain (loss) recognized in other comprehensive income (loss) (effective portion)	$	(553	)	$	(13,633	)

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

	Location of Gain (Loss) Reclassified from
Derivatives in Cash Flow	Accumulated Other Comprehensive Income	Three Months Ended		Nine Months Ended
Hedging Relationships	(Loss) into Net Income (Effective Portion)	September 30, 2009		September 30, 2009
		(Thousands of dollars)
Commodity contracts	Revenues	$	12,500	$	47,248
Interest rate contracts	Interest expense		365		1,237
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income (effective portion)		$	12,865	$	48,485

Ineffectiveness related to our cash flow hedges was not material for the three and nine months ended September 30, 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 would affect earnings. There were no gains or losses due to the discontinuance of cash flow hedge treatment during the three and nine months ended September 30, 2009 and 2008.

Fair Value Hedges - In prior years, we terminated various interest-rate swap agreements. The net savings from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged. Interest expense savings from the amortization of terminated swaps for the three months ended September 30, 2009 and 2008, were not material. Interest expense savings from the amortization of terminated swaps for the nine months ended September 30, 2009 and 2008, were $2.8 million, and the remaining amortization of terminated swaps will be recognized over the following periods.


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

At September 30, 2009, none of the interest on our fixed-rate debt was swapped to floating using interest-rate swaps.

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Credit Risk - All the commodity derivative contracts we enter into are with ONEOK 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. Derivative assets for which we would indemnify OES in the event of a default by the counterparty totaled $6.0 million at September 30, 2009, and were with investment-grade counterparties that are primarily in the oil and gas sector.

D. OTHER COMPREHENSIVE INCOME (LOSS)

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
	(Thousands of dollars)
Unrealized gains (losses) on derivatives	$	(553	)	$	66,661		$	(13,633	)	$	13,496
Less: Realized gains (losses) on derivatives recognized in net income		12,865			(14,202	)		48,485			(31,067	)
Other		-			-			212			-
Other comprehensive income (loss)	$	(13,418	)	$	80,863		$	(61,906	)	$	44,563

The balance in accumulated other comprehensive income in our Consolidated Balance Sheets as of September 30, 2009, and December 31, 2008 was attributable to unrealized gains and losses on derivatives.

E. PARTNERS’ EQUITY

Equity Issuance - In June 2009, we completed an underwritten public offering of 5,000,000 common units at $45.81 per common unit, generating net proceeds of approximately $219.9 million after deducting underwriting discounts but before offering expenses.

In July 2009, we sold an additional 486,690 common units at $45.81 per common unit to the underwriters of the public offering upon the partial exercise of their option to purchase additional common units to cover over-allotments. We received net proceeds of approximately $21.4 million from the sale of the common units after deducting underwriting discounts but before offering expenses.

In conjunction with the public offering and partial exercise by the underwriters of their overallotment option, ONEOK Partners GP contributed an aggregate of $5.1 million in order to maintain its 2 percent general partner interest in us. As a result of these transactions, ONEOK and its subsidiaries now hold an aggregate 45.1 percent interest in us.

We used the proceeds from the sale of common units and the general partner contributions to repay borrowings under our Partnership Credit Agreement and for general partnership purposes.

Cash Distributions Paid - For the nine months ended September 30, 2009, cash distributions included $69.6 million paid to our general partner, of which $62.2 million was related to incentive distributions. The quarterly distributions paid to our limited partners in each of the first, second and third quarters of 2009 were $1.08 per unit. These distributions pertained to the fourth quarter of 2008, first quarter of 2009 and second quarter of 2009.

Cash Distributions Declared - In October 2009, we declared a cash distribution of $1.09 per unit ($4.36 per unit on an annualized basis) for the third quarter of 2009, an increase of $0.01 from the previous quarter. The distribution will be paid on November 13, 2009, to unitholders of record at the close of business on October 30, 2009.

F. CREDIT FACILITIES

Our 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. Among other things, these covenants include maintaining a 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) of no more than 5 to 1. At

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September 30, 2009, our ratio of indebtedness to adjusted EBITDA was 4.7 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.

At September 30, 2009, we had $515 million of borrowings outstanding under our Partnership Credit Agreement, and under the most restrictive provisions of our Partnership Credit Agreement had $219.7 million of credit available. At September 30, 2009, we had 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.

G. 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).

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 any 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 the Intermediate Partnership. The guarantee ranks equally in right of payment to all of the Intermediate Partnership’s existing and future unsecured senior indebtedness. We have no significant assets or operations other than our investment in our wholly owned subsidiary, the Intermediate Partnership, which is also consolidated. At September 30, 2009, the Intermediate Partnership held partnership interests and the equity in our subsidiaries, as well as a 50 percent interest in Northern Border Pipeline.

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 leaseback 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 was made on September 1, 2009. Interest on the 2019 Notes accrues from March 3, 2009, which was the issuance date.

H. COMMITMENTS AND CONTINGENCIES

Investment in Northern Border Pipeline - During the nine months ended September 30, 2009, we made equity contributions of $42.3 million to Northern Border Pipeline. We do not anticipate any additional equity contributions in 2009 or material equity contributions in 2010.

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

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in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations.

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position or results of operations, and our expenditures related to environmental matters had no material effect on earnings or cash flows during the three and nine months ended September 30, 2009 and 2008.

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

I. PROPERTY, PLANT AND EQUIPMENT

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

	September 30,		December 31,
	2009		2008
	(Thousands of dollars)
Non-Regulated
Natural Gas Gathering and Processing	$	1,432,781	$	1,368,223
Natural Gas Pipelines		168,316		167,625
Natural Gas Liquids		916,495		879,047
Other		5,432		50,474
Regulated
Natural Gas Pipelines		1,506,122		1,460,764
Natural Gas Liquids		2,221,616		1,882,546
Property, plant and equipment		6,250,762		5,808,679
Accumulated depreciation and amortization		933,264		875,279
Net property, plant and equipment	$	5,317,498	$	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 placed in service and therefore are not being depreciated. The following table sets forth our construction work in process, by segment, for the periods indicated:

		September 30,		December 31,
		2009		2008
	(Thousands of dollars)
Natural Gas Gathering and Processing		$	59,573	$	135,252
Natural Gas Pipelines			35,544		107,686
Natural Gas Liquids			239,938		566,843
Other			817		197
Total construction work in process		$	335,872	$	809,978

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J. SEGMENTS

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

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

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

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

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

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

Customers - For the three and nine months ended September 30, 2009, and three months ended September 30, 2008, we had no single unaffiliated customer from which we received 10 percent or more of our consolidated revenues. We had one unaffiliated customer from which we received $686.3 million, or approximately 11 percent, of our consolidated revenues, for the nine months ended September 30, 2008. All of these revenues pertained to our Natural Gas Liquids segment.

For the three and nine months ended September 30, 2009 and 2008, sales to affiliated customers were less than 10 percent of our consolidated revenues. See Note M for additional information about our sales to affiliated customers.

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

Three Months Ended September 30, 2009	Natural Gas Gathering and Processing			Natural Gas Pipelines (a)			Natural Gas Liquids (b)			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	91,349		$	68,523		$	1,283,549		$	-		$	1,443,421
Sales to affiliated customers		86,676			29,906			-			-			116,582
Intersegment revenues		84,751			213			5,640			(90,604	)		-
Total revenues	$	262,776		$	98,642		$	1,289,189		$	(90,604	)	$	1,560,003

Net margin	$	89,342		$	75,938		$	128,917		$	(1,318	)	$	292,879
Operating costs		33,559			22,869			49,557			(877	)		105,108
Depreciation and amortization		15,312			10,607			15,944			(6	)		41,857
Gain (loss) on sale of assets		(253	)		(730	)		(144	)		(53	)		(1,180	)
Operating income (loss)	$	40,218		$	41,732		$	63,272		$	(488	)	$	144,734

Equity earnings from investments	$	8,396		$	11,039		$	619		$	-		$	20,054
Capital expenditures	$	23,230		$	14,000		$	131,820		$	346		$	169,396
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $81.3 million, net margin of $59.9 million and operating income of $31.7 million.
(b) - Our Natural Gas Liquids segment has regulated and non-regulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $66.8 million, of which $42.4 million related to sales within the segment, net margin of $50.5 million and operating income of $22.4 million.

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Three Months Ended September 30, 2008	Natural Gas Gathering and Processing		Natural Gas Pipelines (a)		Natural Gas Liquids (b)		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	129,305	$	55,528	$	1,847,464	$	48		$	2,032,345
Sales to affiliated customers		178,167		30,595		-		-			208,762
Intersegment revenues		190,403		567		6,194		(197,164	)		-
Total revenues	$	497,875	$	86,690	$	1,853,658	$	(197,116	)	$	2,241,107

Net margin	$	111,720	$	65,762	$	148,384	$	(466	)	$	325,400
Operating costs		35,651		23,852		37,940		45			97,488
Depreciation and amortization		12,533		8,607		9,262		6			30,408
Gain (loss) on sale of assets		2		-		20		-			22
Operating income (loss)	$	63,538	$	33,303	$	101,202	$	(517	)	$	197,526

Equity earnings from investments	$	8,819	$	20,207	$	386	$	-		$	29,412
Capital expenditures	$	35,769	$	107,822	$	191,989	$	-		$	335,580
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $71.2 million, net margin of $52.8 million and operating income of $25.9 million.
(b) - Our Natural Gas Liquids segment has regulated and non-regulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $33.6 million, of which $23.7 million related to sales within the segment, net margin of $29.3 million and operating income of $11.0 million.

Nine Months Ended September 30, 2009	Natural Gas Gathering and Processing		Natural Gas Pipelines (a)			Natural Gas Liquids (b)			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	227,162	$	168,733		$	3,443,743		$	-		$	3,839,638
Sales to affiliated customers		289,596		78,691			-			-			368,287
Intersegment revenues		236,362		536			15,950			(252,848	)		-
Total revenues	$	753,120	$	247,960		$	3,459,693		$	(252,848	)	$	4,207,925

Net margin	$	261,686	$	208,367		$	341,361		$	(3,012	)	$	808,402
Operating costs		99,418		67,533			129,833			(1,723	)		295,061
Depreciation and amortization		44,225		34,029			43,488			8			121,750
Gain (loss) on sale of assets		2,821		(727	)		(145	)		811			2,760
Operating income (loss)	$	120,864	$	106,078		$	167,895		$	(486	)	$	394,351

Equity earnings from investments	$	20,583	$	32,802		$	2,079		$	-		$	55,464
Investments in unconsolidated affiliates	$	326,722	$	418,137		$	29,488		$	-		$	774,347
Total assets	$	1,587,760	$	1,488,645		$	4,133,618		$	407,021		$	7,617,044
Noncontrolling interests in consolidated subsidiaries	$	-	$	5,451		$	119		$	15		$	5,585
Capital expenditures	$	75,557	$	48,268		$	366,614		$	817		$	491,256
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $200.7 million, net margin of $164.3 million and operating income of $77.6 million.
(b) - Our Natural Gas Liquids segment has regulated and non-regulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $181.6 million, of which $112.5 million related to sales within the segment, net margin of $139.3 million and operating income of $63.2 million.

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Nine Months Ended September 30, 2008	Natural Gas Gathering and Processing			Natural Gas Pipelines (a)			Natural Gas Liquids (b)		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	366,095		$	173,442		$	5,308,029	$	49		$	5,847,615
Sales to affiliated customers		504,541			91,878			-		-			596,419
Intersegment revenues		602,542			1,338			19,573		(623,453	)		-
Total revenues	$	1,473,178		$	266,658		$	5,327,602	$	(623,404	)	$	6,444,034

Net margin	$	336,746		$	196,173		$	343,974	$	(2,035	)	$	874,858
Operating costs		101,538			67,900			103,746		(456	)		272,728
Depreciation and amortization		36,431			25,547			28,388		17			90,383
Gain (loss) on sale of assets		(3	)		(18	)		39		32			50
Operating income (loss)	$	198,774		$	102,708		$	211,879	$	(1,564	)	$	511,797

Equity earnings from investments	$	23,989		$	49,421		$	1,395	$	-		$	74,805
Investments in unconsolidated affiliates	$	323,537		$	403,373		$	29,539	$	-		$	756,449
Total assets	$	1,593,872		$	1,371,178		$	3,669,801	$	357,444		$	6,992,295
Noncontrolling interests in consolidated subsidiaries	$	-		$	5,800		$	132	$	15		$	5,947
Capital expenditures	$	98,604		$	159,810		$	601,688	$	65		$	860,167
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $221.7 million, net margin of $155.0 million and operating income of $76.9 million.
(b) - Our Natural Gas Liquids segment has regulated and non-regulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $104.1 million, of which $67.2 million related to sales within the segment, net margin of $86.8 million and operating income of $33.6 million.

K. UNCONSOLIDATED AFFILIATES

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008
	(Thousands of dollars)
Northern Border Pipeline	$	10,882	$	20,090	$	32,374	$	48,752
Fort Union Gas Gathering, L.L.C.		4,397		4,033		10,412		9,792
Bighorn Gas Gathering, L.L.C.		1,935		2,044		5,845		6,367
Lost Creek Gathering Company, L.L.C.		1,445		1,345		3,647		4,427
Other		1,395		1,900		3,186		5,467
Equity earnings from investments	$	20,054	$	29,412	$	55,464	$	74,805

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008
	(Thousands of dollars)
Income Statement
Operating revenues	$	101,987	$	98,298	$	296,004	$	304,733
Operating expenses	$	49,312	$	44,382	$	138,544	$	132,927
Net income	$	42,929	$	64,217	$	125,574	$	153,965

Distributions paid to us	$	19,615	$	30,466	$	83,088	$	91,093

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L. LIMITED PARTNERS’ NET INCOME PER UNIT

Limited partners’ net income per unit is computed by dividing net income attributable to ONEOK Partners, L.P., after deducting the general partner’s allocation as discussed below, by the weighted-average number of outstanding limited partner units, which includes our common and Class B limited partner units. As discussed in Note B of the Notes to Consolidated Financial Statements in our Annual Report, ONEOK, as sole holder of our Class B units, has waived its right to receive increased quarterly distributions on the Class B units. Because ONEOK has waived its right to increased quarterly distributions, currently each Class B unit and common unit share equally in the earnings of the partnership, and neither has any liquidation or other preferences. ONEOK retains the option to withdraw its waiver at any time by giving us no less than 90 days advance notice. ONEOK Partners GP 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 $22.5 million and $64.3 million for the three and nine months ended September 30, 2009, respectively. The amount of incentive distribution allocated to our general partner totaled $20.3 million and $55.7 million for the three and nine months ended September 30, 2008, respectively.

The terms of our Partnership Agreement limit the general partner’s incentive distribution to the amount of available cash calculated for the period. As such, incentive distribution rights are not allocated on undistributed earnings or distributions in excess of earnings. Gains resulting from interim capital transactions, as defined in our Partnership Agreement, are generally not subject to distribution; however, our Partnership Agreement provides that if such distributions were made, the incentive 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.

M. RELATED-PARTY TRANSACTIONS

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

We have certain contractual rights to the Bushton Plant. Our Processing and Services Agreement with ONEOK and OBPI sets out the terms by which OBPI provides services to us at the Bushton Plant through 2012. We have contracted for all of the capacity of the Bushton Plant from OBPI. In exchange, we pay OBPI for all costs and expenses 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 operating obligations.

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

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

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008
	(Thousands of dollars)
Revenues	$	116,582	$	208,762	$	368,287	$	596,419

Expenses
Cost of sales and fuel	$	10,267	$	34,338	$	36,321	$	94,398
Administrative and general expenses		43,800		53,154		142,278		143,387
Total expenses	$	54,067	$	87,492	$	178,599	$	237,785

Cash Distributions to ONEOK - We paid cash distributions to ONEOK and its subsidiaries related to its general and limited partner interests of $69.9 million and $65.9 million for the three months ended September 30, 2009 and 2008, respectively, and $206.9 million and $183.1 million for the nine months ended September 30, 2009 and 2008, respectively.

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ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

EXECUTIVE SUMMARY

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:

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

Outlook - We expect improving economic conditions for the remainder of 2009 and into 2010, compared with the fourth quarter of 2008 and the first two quarters of 2009, when we began to experience reduced drilling activity, less supply growth and lower commodity prices for natural gas, NGLs and crude oil. Although we have been able to access the capital markets for our debt and equity needs in 2009, we expect continued volatility in the financial markets, which could limit our access to these markets or increase the cost of issuing new debt or equity securities in the future.

Operating Results - Limited partners’ net income per unit decreased to $1.00 for the three months ended September 30, 2009, compared with $1.97 for the same period in 2008. For the nine-month period, limited partners’ net income per unit decreased to $2.67 from $4.93 for the same period last year. The decrease in limited partners’ net income per unit for the three- and nine-month periods is due primarily to the following:

·	a decrease in net margin due primarily to:

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

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

-	a decrease related to prior-year operational measurement gains, primarily at NGL storage caverns; partially offset by

-	higher NGL volumes gathered, fractionated and transported, primarily associated with the completion of the Overland Pass Pipeline and related expansion projects, and the Arbuckle Pipeline, as well as new NGL supply connections in our Natural Gas Liquids segment;

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

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

·	an increase in operating costs resulting from the operation of the Overland Pass Pipeline and the Arbuckle Pipeline and increased costs at our fractionation facilities, which includes the expanded Bushton Plant fractionator;

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

·	an increase in interest expense due primarily to our March 2009 debt issuance and a decrease in capitalized interest due to the completion of our capital projects; and

·	an increase in the number of common units outstanding.

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We used the proceeds from the sale of common units and the general partner contributions to repay borrowings under our Partnership Credit Agreement and for general partnership purposes.

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

Cash Distributions - In October 2009, we declared a cash distribution of $1.09 per unit ($4.36 per unit on an annualized basis), an increase of approximately 1 percent over the $1.08 per unit declared in October 2008.

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

·	Guardian Pipeline’s natural gas pipeline expansion and extension project;

·	D-J Basin lateral natural gas liquids pipeline;

·	Williston Basin natural gas processing plant expansion;

·	Arbuckle natural gas liquids pipeline; and

·	Piceance lateral natural gas liquids pipeline.

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 $583 million on capital expenditures in 2009, of which approximately $523 million is for growth projects.

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. At the end of the third quarter 2009, average flow rates on the Overland Pass Pipeline were approximately 99 MBbl/d. 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 in Overland Pass Pipeline Company, which includes the Piceance Lateral and D-J Basin Lateral pipeline projects, 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 project costs for the Overland Pass Pipeline, the Piceance Lateral Pipeline and the DJ Basin Lateral Pipeline in total are expected to be approximately $780 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 70 MBbl/d to 80 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. During the fourth quarter of 2009 and following the completion of the Piceance Lateral, throughput on the Overland Pass Pipeline is expected to reach 130 MBbl/d to 140 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, Kansas, 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 were 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 and the associated expansions are included in our Natural Gas Liquids segment.

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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, from the Piceance Basin in Colorado to the Overland Pass Pipeline. Williams has dedicated its NGL production from its new Willow Creek natural gas processing plant, and will dedicate NGL production from an additional existing natural gas processing plant. Another plant owned by a third party has also been dedicated. We expect the total throughput on the lateral pipeline to reach approximately 30 MBbl/d during the fourth quarter of 2009. We continue to negotiate with other producers for supply commitments. Construction was completed and the lateral pipeline was placed in service in October 2009. The project is currently estimated to cost in the range of $135 million to $140 million, excluding AFUDC. This project is in our Natural Gas Liquids 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 cost was approximately $70 million, excluding AFUDC. Daily volumes reached approximately 30 MBbl/d during the third quarter of 2009, with the potential for an additional 10 MBbl/d from new drilling and plant upgrades in the next two years. This project is in our Natural Gas Liquids segment.

Arbuckle Natural Gas Liquids Pipeline - In July 2009, we completed construction of the 440-mile Arbuckle pipeline project, a natural gas liquids pipeline system that delivers unfractionated NGLs from points in southern Oklahoma and Texas to the Texas Gulf Coast. The Arbuckle pipeline system has the capacity to transport 160 MBbl/d of unfractionated NGLs, expandable to 240 MBbl/d with additional pump facilities, and connects our existing Mid-Continent infrastructure with our fractionation facility in Mont Belvieu, Texas, and other Gulf Coast region fractionators. We have NGL production dedicated from existing and new natural gas processing plants that we expect to provide throughput of approximately 210 MBbl/d over the next three to five years.

The demand for surface easements increased dramatically in Texas and Oklahoma over the last two years because of increased oil and natural gas exploration and production activities, as well as pipeline construction. As previously reported, project costs have been more expensive than originally estimated due to delays associated with right-of-way acquisition, increased materials costs and difficult construction conditions associated with several weeks of heavy spring rains, resulting in greatly reduced construction productivity. We also experienced increased costs due to a number of scope changes, arising primarily from additional supply development opportunities. As previously discussed, we currently estimate project costs will be approximately $490 million, excluding AFUDC, for the current capacity. We began filling the pipeline with product in July 2009 and placed the project in service in August 2009. Volumes reached 80 MBbl/d during the month of October 2009. This project is in our Natural Gas Liquids segment.

Williston Basin Gas Processing Plant Expansion - The expansion of our Grasslands natural gas processing facility in North Dakota was placed in service in March 2009. The expansion increased processing capacity to approximately 100 MMcf/d from its previous capacity of 63 MMcf/d and increased fractionation capacity to approximately 12 MBbl/d from 8 MBbl/d. The cost of the project was 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 completed the 119-mile extension of our Guardian Pipeline. 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. This project is in our Natural Gas Pipelines segment.

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IMPACT OF NEW ACCOUNTING STANDARDS

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

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.

Goodwill Impairment Test - We assess our goodwill for impairment at least annually. There were no impairment charges resulting from our July 1, 2009, impairment test.

As part of our impairment test, an initial assessment is made by comparing the fair value of a reporting unit with its book value, including goodwill. To estimate the fair value of our reporting units, we use two generally accepted valuation approaches, an income approach and a market approach. Under the income approach, we use anticipated cash flows over a period of years plus a terminal value and discount these amounts to their present value using appropriate rates of return. Under the market approach, we apply multiples to forecasted EBITDA amounts. The multiples used are consistent with historical asset transactions, and the EBITDA amounts are based on average forecasted EBITDA for a reporting unit over a period of years.

Our estimates of fair value significantly exceeded the book value of our reporting units in our July 1, 2009, impairment test. Even if the estimated fair values used in our July 1, 2009, impairment test were reduced by 10 percent, no impairment charges would have resulted. At September 30, 2009, and December 31, 2008, we had $396.7 million of goodwill recorded on our Consolidated Balance Sheets.

Derivatives and Risk Management - We utilize financial instruments to reduce our market risk exposure to commodity price and interest rate fluctuations and to achieve more predictable cash flows. We do not believe that changes in our fair value estimates of our derivative instruments have a material impact on our results of operations, as the majority of our derivatives are accounted for as cash flow hedges for which ineffectiveness is not material. See Notes B and C of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion of our fair value measurements and derivatives and risk management activities.

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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						Nine Months Ended						Increase (Decrease)					Increase (Decrease)
	September 30,						September 30,						Three Months					Nine Months
Financial Results	2009			2008			2009			2008			2009 vs. 2008					2009 vs. 2008
	(Millions of dollars)
Revenues	$	1,560.0		$	2,241.1		$	4,207.9		$	6,444.0		$	(681.1	)	(30	%)	$	(2,236.1	)	(35	%)
Cost of sales and fuel		1,267.1			1,915.7			3,399.5			5,569.1			(648.6	)	(34	%)		(2,169.6	)	(39	%)
Net margin		292.9			325.4			808.4			874.9			(32.5	)	(10	%)		(66.5	)	(8	%)
Operating costs		105.1			97.5			295.0			272.7			7.6		8	%		22.3		8	%
Depreciation and amortization		41.9			30.4			121.8			90.4			11.5		38	%		31.4		35	%
Gain (loss) on sale of assets		(1.2	)		-			2.8			-			(1.2	)	100	%		2.8		100	%
Operating income	$	144.7		$	197.5		$	394.4		$	511.8		$	(52.8	)	(27	%)	$	(117.4	)	(23	%)

Equity earnings from investments	$	20.1		$	29.4		$	55.5		$	74.8		$	(9.3	)	(32	%)	$	(19.3	)	(26	%)
Allowance for equity funds used during construction	$	7.3		$	15.6		$	25.8		$	35.8		$	(8.3	)	(53	%)	$	(10.0	)	(28	%)
Other income (expense)	$	4.7		$	(4.8	)	$	6.1		$	(4.2	)	$	9.5		*		$	10.3		*
Interest expense	$	(50.4	)	$	(34.4	)	$	(152.2	)	$	(107.7	)	$	16.0		47	%	$	44.5		41	%
Capital expenditures	$	169.4		$	335.6		$	491.3		$	860.2		$	(166.2	)	(50	%)	$	(368.9	)	(43	%)
* Percentage change is greater than 100 percent.

Net margin decreased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily 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 segment; and

·	a decrease related to prior-year operational measurement gains, primarily at NGL storage caverns; partially offset by

·	higher NGL volumes gathered, fractionated and transported, primarily associated with the completion of the Overland Pass Pipeline and related expansion projects, and the Arbuckle Pipeline, as well as new NGL supply connections in our Natural Gas Liquids segment;

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

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

Operating costs increased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to higher operating costs resulting from the operation of the Overland Pass Pipeline and the Arbuckle Pipeline and increased costs at our fractionation facilities, which includes the expanded Bushton Plant fractionator.

Equity earnings from investments decreased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to a gain on the sale of Bison Pipeline LLC by Northern Border Pipeline in the third quarter of 2008 and lower subscription volumes and rates on Northern Border Pipeline. Equity earnings from investments also decreased due to lower volumes gathered in our Natural Gas Gathering and Processing segment’s equity investments, whose assets are primarily located in the Powder River Basin of Wyoming.

Allowance for equity funds used during construction decreased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to the completion of the Arbuckle Pipeline, the Overland Pass Pipeline and related expansion projects, and the Guardian Pipeline expansion and extension.

Interest expense increased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to our March 2009 debt issuance and a decrease in capitalized interest due to the completion of our capital projects.

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Capital expenditures decreased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to the completion of the Arbuckle Pipeline, the Overland Pass Pipeline and related expansion projects, a pipeline expansion project into the Woodford Shale in Oklahoma, the Williston Basin gas processing plant expansion 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.

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. The natural gas we gather in the Powder River Basin of Wyoming is coal bed methane, or dry gas, that does not require processing in order to be marketable; dry gas is gathered, compressed and delivered into a pipeline for a fee.

In the Mid-Continent region and the Williston Basin, unprocessed natural gas is compressed and transported through pipelines to processing facilities where volumes are aggregated, treated and processed to remove water vapor, solids and other contaminants, and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. The residue gas, which consists primarily of methane, is compressed and delivered to natural gas pipelines for transportation to end users. When the NGLs are separated from the unprocessed natural gas at the processing plants, the NGLs are generally in the form of a mixed, unfractionated NGL stream. This unfractionated NGL stream is 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 derived primarily from POP, fee and keep-whole contracts. Under a POP contract, we retain a portion of sales proceeds from the commodity sales for our services. With a fee-based contract, we charge a fee for our services, and with the keep-whole contract, we retain the NGLs as our fee for service and return to the producer an equivalent quantity of or payment for residue gas containing the same amount of Btus as the unprocessed natural gas that was delivered to us. Our natural gas and NGL products are sold to affiliates and a diverse customer base.

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

		Three Months Ended					Nine Months Ended				Increase (Decrease)					Increase (Decrease)
		September 30,					September 30,				Three Months					Nine Months
Financial Results		2009			2008		2009		2008		2009 vs. 2008					2009 vs. 2008
	(Millions of dollars)
NGL and condensate sales		$	143.8		$	249.2	$	390.8	$	720.2	$	(105.4	)	(42	%)	$	(329.4	)	(46	%)
Residue gas sales			81.8			209.7		247.8		637.0		(127.9	)	(61	%)		(389.2	)	(61	%)
Gathering, compression, dehydration and processing fees and other revenue			37.2			38.9		114.5		116.0		(1.7	)	(4	%)		(1.5	)	(1	%)
Cost of sales and fuel			173.5			386.1		491.4		1,136.5		(212.6	)	(55	%)		(645.1	)	(57	%)
Net margin			89.3			111.7		261.7		336.7		(22.4	)	(20	%)		(75.0	)	(22	%)
Operating costs			33.6			35.7		99.4		101.5		(2.1	)	(6	%)		(2.1	)	(2	%)
Depreciation and amortization			15.3			12.5		44.2		36.4		2.8		22	%		7.8		21	%
Gain (loss) on sale of assets			(0.2	)		-		2.8		-		(0.2	)	(100	%)		2.8		100	%
Operating income		$	40.2		$	63.5	$	120.9	$	198.8	$	(23.3	)	(37	%)	$	(77.9	)	(39	%)

Equity earnings from investments		$	8.4		$	8.8	$	20.6	$	24.0	$	(0.4	)	(5	%)	$	(3.4	)	(14	%)
Capital expenditures		$	23.2		$	35.8	$	75.6	$	98.6	$	(12.6	)	(35	%)	$	(23.0	)	(23	%)

Net margin decreased for the three and nine months ended September 30, 2009, compared with the same periods last year, primarily as a result of the following:

·	a decrease of $33.7 million and $95.1 million, respectively, due to lower realized commodity prices; partially offset by

·	an increase of $11.4 million and $20.1 million, respectively, due to higher volumes processed and sold.

Operating costs decreased for the three and nine months ended September 30, 2009, compared with the same periods last year, primarily as a result of lower chemical and employee-related costs.

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Depreciation and amortization increased for the three and nine months ended September 30, 2009, compared with the same periods last year, primarily as a result of higher depreciation expense associated with our completed capital projects.

Gain on sale of assets increased for the nine months ended September 30, 2009, compared with the same period last year, due to the sale of excess compression equipment.

Equity earnings from investments decreased for the nine months ended September 30, 2009, compared with the same period last year, primarily as a result of decreased earnings from lower volumes gathered in our equity investments.

Capital expenditures decreased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to the completion of a pipeline expansion project into the Woodford Shale in Oklahoma and the Williston Basin gas processing plant expansion.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Operating Information (a)	2009		2008		2009		2008
Natural gas gathered (BBtu/d)		1,100		1,146		1,131		1,174
Natural gas processed (BBtu/d)		664		649		658		641
NGL sales (MBbl/d)		43		39		42		39
Residue gas sales (BBtu/d)		297		281		291		280
Realized composite NGL sales price ($/gallon)	$	0.76	$	1.51	$	0.70	$	1.44
Realized condensate sales price ($/Bbl)	$	79.46	$	99.61	$	70.66	$	96.91
Realized residue gas sales price ($/MMBtu)	$	2.99	$	8.33	$	3.11	$	8.39
Realized gross processing spread ($/MMBtu)	$	6.54	$	6.69	$	6.41	$	6.94
(a) - Includes volumes for consolidated entities only.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Operating Information (a)	2009		2008		2009		2008
Percent of proceeds
Wellhead purchases (MMBtu/d)		49,472		65,804		55,545		68,564
NGL sales (Bbl/d)		5,408		3,998		5,215		4,637
Residue gas sales (MMBtu/d)		46,406		42,119		41,698		38,570
Condensate sales (Bbl/d)		1,488		1,469		1,786		1,711
Percentage of total net margin		50%		64%		49%		62%
Fee-based
Wellhead volumes (MMBtu/d)		1,100,202		1,145,656		1,131,018		1,173,894
Average rate ($/MMBtu)	$	0.31	$	0.27	$	0.30	$	0.26
Percentage of total net margin		35%		22%		36%		23%
Keep-whole
NGL shrink (MMBtu/d)		16,843		20,016		17,875		21,978
Plant fuel (MMBtu/d)		1,954		2,106		2,100		2,301
Condensate shrink (MMBtu/d)		1,407		1,574		1,893		1,941
Condensate sales (Bbl/d)		285		318		383		393
Percentage of total net margin		15%		14%		15%		15%
(a) - Includes volumes for consolidated entities only.

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Commodity Price Risk - The following tables set forth our Natural Gas Gathering and Processing segment’s hedging information for the remainder of 2009 and for the year ending December 31, 2010, as of November 3, 2009.

	Three Months Ending
	December 31, 2009
	Volumes Hedged		Average Price			Percentage Hedged
NGLs (Bbl/d) (a)		7,857		$1.04	/ gallon		87%
Condensate (Bbl/d) (a)		2,064		$2.08	/ gallon		91%
Total (Bbl/d)		9,921		$1.26	/ gallon		88%
Natural gas (MMBtu/d)		17,009		$4.25	/ MMBtu		88%
(a) - Hedged with fixed-price swaps.

	Year Ending
	December 31, 2010
	Volumes Hedged		Average Price			Percentage Hedged
NGLs (Bbl/d) (a)		3,881		$1.19	/ gallon		55%
Condensate (Bbl/d) (a)		1,696		$1.79	/ gallon		75%
Total (Bbl/d)		5,577		$1.38	/ gallon		60%
Natural gas (MMBtu/d)		25,225		$5.55	/ MMBtu		75%
(a) - Hedged with fixed-price swaps.

See Note C of the Notes to Consolidated Financial Statements in this Quarterly Report for more information on our hedging activities.

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 September 30, 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 $1.1 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 $1.1 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 or changes in operations that we may undertake to compensate for or improve our ability to realize market advantages from periodic price changes. For example, a change in the gross processing spread may cause us to change the amount of ethane we extract from the natural gas stream, impacting gathering and processing margins for certain contracts.

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Natural Gas Pipelines

Overview - Our Natural Gas Pipelines segment primarily owns and operates regulated natural gas transmission pipelines, natural gas storage facilities and 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 North Dakota, Minnesota, Wisconsin, 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 Company, 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 to the Mid-Continent market and west to the California market.

We own underground natural gas storage facilities in Oklahoma, Kansas and Texas.

Our transportation contracts for our regulated natural gas activities are based upon rates stated in our tariffs. Tariffs specify the maximum rates 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.

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					Nine Months Ended					Increase (Decrease)					Increase (Decrease)
		September 30,					September 30,					Three Months					Nine Months
Financial Results		2009			2008		2009			2008		2009 vs. 2008					2009 vs. 2008
	(Millions of dollars)
Transportation revenues		$	58.0		$	59.2	$	168.4		$	184.5	$	(1.2	)	(2	%)	$	(16.1	)	(9	%)
Storage revenues			16.0			17.1		45.3			49.3		(1.1	)	(6	%)		(4.0	)	(8	%)
Gas sales and other revenues			24.6			10.4		34.3			32.9		14.2		*			1.4		4	%
Cost of sales			22.7			20.9		39.7			70.6		1.8		9	%		(30.9	)	(44	%)
Net margin			75.9			65.8		208.3			196.1		10.1		15	%		12.2		6	%
Operating costs			22.9			23.9		67.5			67.9		(1.0	)	(4	%)		(0.4	)	(1	%)
Depreciation and amortization			10.6			8.6		34.0			25.5		2.0		23	%		8.5		33	%
Loss on sale of assets			(0.7	)		-		(0.7	)		-		(0.7	)	(100	%)		(0.7	)	(100	%)
Operating income		$	41.7		$	33.3	$	106.1		$	102.7	$	8.4		25	%	$	3.4		3	%

Equity earnings from investments		$	11.0		$	20.2	$	32.8		$	49.4	$	(9.2	)	(46	%)	$	(16.6	)	(34	%)
Allowance for equity funds used during construction		$	0.1		$	3.8	$	1.5		$	8.3	$	(3.7	)	(97	%)	$	(6.8	)	(82	%)
Capital expenditures		$	14.0		$	107.8	$	48.3		$	159.8	$	(93.8	)	(87	%)	$	(111.5	)	(70	%)
* Percentage change is greater than 100 percent.

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	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Operating Information (a)	2009		2008		2009		2008
Natural gas transportation capacity contracted (MMcf/d)		5,764		4,765		5,461		4,877
Transportation capacity subscribed		87%		81%		83%		83%
Average natural gas price
Mid-Continent region ($/MMBtu)	$	2.94	$	8.44	$	3.01	$	8.27
(a) - Includes volumes for consolidated entities only.

Net margin increased for the three and nine months ended September 30, 2009, compared with the same periods last year, primarily as a result of the following:

an increase of $10.1 million and $23.3 million, respectively, from higher natural gas transportation margins, excluding retained fuel, primarily as a result of incremental margin from the Guardian Pipeline expansion and extension that was completed in February 2009 and an increase in volumes contracted on Midwestern Gas Transmission as a result of a new interconnect with the Rockies Express Pipeline that was placed in service beginning in June 2009;

·	an increase of $2.5 million and $4.3 million, respectively, from higher natural gas storage margins, excluding retained fuel, primarily as a result of contract renegotiations; and

·	an increase of $3.1 million and $1.5 million, respectively, from increased operational natural gas inventory sales; partially offset by

·	a decrease of $4.8 million and $18.3 million, respectively, from the impact of lower natural gas prices on retained fuel.

Equity earnings from investments decreased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to an $8.3 million gain on the sale of Bison Pipeline LLC by Northern Border Pipeline in the third quarter of 2008 and due to lower subscription volumes and rates on Northern Border Pipeline.

Allowance for equity funds used during construction and capital expenditures decreased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to the Guardian Pipeline expansion and extension that was constructed during 2008 and has since been completed. See discussion of the Guardian Pipeline expansion and extension beginning on page 26.

Natural Gas Liquids

Overview - Our Natural Gas Liquids segment’s assets consist of facilities that gather, fractionate and treat NGLs and store NGL products primarily in Oklahoma, Kansas and Texas. We also 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. We also own natural gas liquids distribution and refined petroleum products pipelines that connect our Mid-Continent assets with Midwest markets, including Chicago, Illinois. The majority of the pipeline-connected natural gas processing plants in Oklahoma, Kansas and the Texas panhandle, which extract NGLs from unprocessed natural gas, are connected to our 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 and marketing, pipeline transportation, isomerization and storage, defined as follows:

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

Our optimization and marketing business utilizes our assets, contract portfolio and market knowledge to capture locational and seasonal price differentials. We move NGL products between Conway, Kansas, and Mont Belvieu, Texas, in order to capture the locational price differentials between the two market centers. Our NGL storage facilities are also utilized to capture seasonal price variances.

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

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

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

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

		Three Months Ended					Nine Months Ended					Increase (Decrease)					Increase (Decrease)
		September 30,					September 30,					Three Months					Nine Months
Financial Results		2009			2008		2009			2008		2009 vs. 2008					2009 vs. 2008
	(Millions of dollars)
NGL and condensate sales		$	1,176.7		$	1,759.1	$	3,135.5		$	5,038.9	$	(582.4	)	(33	%)	$	(1,903.4	)	(38	%)
Exchange service and storage revenues			92.3			85.0		262.7			254.6		7.3		9	%		8.1		3	%
Transportation revenues			20.2			9.6		61.5			34.1		10.6		*			27.4		80	%
Cost of sales and fuel			1,160.3			1,705.3		3,118.3			4,983.6		(545.0	)	(32	%)		(1,865.3	)	(37	%)
Net margin			128.9			148.4		341.4			344.0		(19.5	)	(13	%)		(2.6	)	(1	%)
Operating costs			49.6			37.9		129.8			103.7		11.7		31	%		26.1		25	%
Depreciation and amortization			15.9			9.3		43.5			28.4		6.6		71	%		15.1		53	%
Loss on sale of assets			(0.1	)		-		(0.1	)		-		(0.1	)	(100	%)		(0.1	)	(100	%)
Operating income		$	63.3		$	101.2	$	168.0		$	211.9	$	(37.9	)	(37	%)	$	(43.9	)	(21	%)

Equity earnings from investments		$	0.6		$	0.4	$	2.1		$	1.4	$	0.2		50	%	$	0.7		50	%
Allowance for equity funds used
during construction		$	7.1		$	11.8	$	24.3		$	27.5	$	(4.7	)	(40	%)	$	(3.2	)	(12	%)
Capital expenditures		$	131.8		$	192.0	$	366.6		$	601.7	$	(60.2	)	(31	%)	$	(235.1	)	(39	%)
* Percentage change is greater than 100 percent.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Operating Information	2009		2008		2009		2008
NGL sales (MBbl/d)		382		273		388		275
NGLs fractionated (MBbl/d)		496		375		458		379
NGLs transported-gathering lines (MBbl/d)		385		253		358		255
NGLs transported-distribution lines (MBbl/d)		446		430		451		347
Conway-to-Mont Belvieu OPIS average price differential
Ethane ($/gallon)	$	0.15	$	0.24	$	0.12	$	0.15

Net margin decreased for the three and nine months ended September 30, 2009, compared with the same period last year, primarily as a result of the following:

·	a decrease of $28.0 million and $38.4 million, respectively, related to narrower NGL product price differentials, partially offset by increased volumes marketed; and

·	a decrease of $11.6 million and $12.5 million, respectively, related to prior-year operational measurement gains, primarily at NGL storage caverns; partially offset by

·	an increase of $18.2 million and $46.2 million, respectively, due to increased volumes gathered, fractionated and transported, primarily associated with the completion of the Overland Pass Pipeline and related expansion projects, and the Arbuckle Pipeline, as well as new supply connections; and

·	an increase of $2.2 million and $2.1 million, respectively, due to higher storage margins as a result of contract renegotiations.

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Operating costs increased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to the operation of the Overland Pass Pipeline, the Arbuckle Pipeline and the expanded Bushton Plant fractionator, increased outside services expenses at our other fractionators, incremental ad valorem taxes and higher employee-related costs.

Depreciation and amortization increased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to higher depreciation expense associated with the Arbuckle Pipeline and the Overland Pass Pipeline and related projects, including the new and modified fractionation facilities at the Bushton Plant.

Allowance for equity funds used during construction and capital expenditures decreased for the three and nine months ended September 30, 2009, compared with the same periods last year, due primarily to the completion of the Arbuckle Pipeline and the Overland Pass Pipeline and associated fractionation and storage expansions, which are discussed beginning on page 25.

Contingencies

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

LIQUIDITY AND CAPITAL RESOURCES

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

During 2009, the capital markets have improved significantly from year-end 2008. Throughout 2009, we have continued to have access to our Partnership Credit Agreement to fund our short-term liquidity needs, and we have been able to access the debt and equity markets for our long-term financing needs.

We expect improving economic conditions for the remainder of 2009 and into 2010, compared with the fourth quarter of 2008 and the first two quarters of 2009, when we began to experience reduced drilling activity, less supply growth and lower commodity prices for natural gas, NGLs and crude oil. We also expect continued volatility in the financial markets, which could limit our access to these markets or increase the cost of issuing new debt or equity securities in the future. Our ability to continue to access capital markets for debt and equity financing under reasonable terms depends on our financial condition and credit ratings, and market conditions. We anticipate that our cash flow generated from operations, existing capital resources and ability to obtain financing will enable us to maintain our current level of operations and our planned operations, as well as capital expenditures.

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

	September 30, 2009	December 31, 2008
Long-term debt	50%	47%
Equity	50%	53%

Debt (including notes payable)	54%	54%
Equity	46%	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 pursuant to FERC regulations or our operating agreements. Under the cash management program, depending on whether a participating subsidiary has

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short-term cash surpluses or cash requirements, the Intermediate Partnership provides cash to the subsidiary or the subsidiary provides cash to the Intermediate Partnership.

Short-term Liquidity - Our principal sources of short-term liquidity consist of cash generated from operating activities and 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 September 30, 2009, we had $515 million of borrowings outstanding under our Partnership Credit Agreement, which expires in March 2012, and available cash and cash equivalents of approximately $30.5 million. As of September 30, 2009, our borrowing capacity was limited to $219.7 million of additional short- and long-term debt under the most restrictive provisions contained in our Partnership Credit Agreement. At September 30, 2009, we had a total of $49.2 million in letters of credit issued 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. Among other things, these covenants include maintaining a 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) of no more than 5 to 1. At September 30, 2009, our ratio of indebtedness to adjusted EBITDA was 4.7 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.

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

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

We used the proceeds from the sale of common units and the general partner contributions to repay borrowings under our Partnership Credit Agreement and for general partnership purposes.

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 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 G of the Notes to Consolidated Financial Statements in this Quarterly Report.

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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.

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 $491.3 million and $860.2 million for the nine months ended September 30, 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 typically generate additional revenues. Projected 2009 capital expenditures are significantly lower than 2008 capital expenditures due to the completion of the Arbuckle Pipeline, the Overland Pass Pipeline and related expansion projects, the Williston Basin gas processing plant expansion and the Guardian Pipeline expansion and extension. Additional information about our growth capital expenditures is included under “Capital Projects” on page 25.

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	$	92	$	21	$	113
Natural Gas Pipelines		57		16		73
Natural Gas Liquids		374		23		397
Total projected capital expenditures	$	523	$	60	$	583

Credit Ratings - Our credit ratings as of September 30, 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 but could trigger repurchase obligations with respect to certain of our long-term debt. See additional discussion about our credit ratings under “Debt Covenants.”

If our repurchase obligations are triggered, we may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause us to borrow money under our credit facilities 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.

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

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

Cash Distributions - We distribute 100 percent of our available cash, which generally consists of all cash receipts less adjustments for cash disbursements and net change to reserves, to our general and limited partners. Our income is allocated to our general partner and limited partners according to their partnership percentages of 2 percent and 98 percent, respectively. The effect of any incremental income allocations for incentive distributions to our general partner is calculated after the income allocation for the general partner’s partnership interest and before the income allocation to the limited partners.

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

	Nine Months Ended
	September 30,
	2009		2008
	(Millions of dollars)
Common unitholders	$	182.3	$	161.9
Class B unitholders		118.2		114.0
General partner		69.6		56.2
Total cash distributions paid before noncontrolling interests	$	370.1	$	332.1

For the nine months ended September 30, 2009, cash distributions paid to our general partner included $62.2 million related to incentive distributions. These distributions pertained to the fourth quarter of 2008, first quarter of 2009 and second quarter of 2009. In October 2009, we declared a cash distribution to $1.09 per unit ($4.36 per unit on an annualized basis) for the third quarter of 2009, an increase of $0.01 from the previous quarter. The distribution will be paid on November 13, 2009, to unitholders of record at the close of business on October 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.

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

CASH FLOW ANALYSIS

We use the indirect method to prepare our Consolidated Statements of Cash Flows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payments during the period. These reconciling items include depreciation and amortization, allowance for equity funds used during construction, gain on sale of assets, equity earnings from investments, distributions received from unconsolidated affiliates, and changes in our assets and liabilities not classified as investing or financing activities.

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

	Nine Months Ended						Increase (Decrease)
	September 30,						Nine Months
	2009			2008			2009 vs. 2008
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	349.0		$	568.7		$	(219.7	)	(39%)
Investing activities		(502.6	)		(854.5	)		351.9		41%
Financing activities		6.5			298.4			(291.9	)	(98%)
Change in cash and cash equivalents		(147.1	)		12.6			(159.7	)	*
Cash and cash equivalents at beginning of period		177.6			3.2			174.4		*
Cash and cash equivalents at end of period	$	30.5		$	15.8		$	14.7		93%
* Percentage change is greater than 100 percent.

Operating Cash Flows - Operating cash flows are affected by earnings from our business activities. We provide services for producers and consumers of natural gas and NGLs. Changes in commodity prices and demand for our services or products, whether because of general economic conditions, changes in demand for the end products that are made with our products or increased competition from other service providers, could affect our earnings and operating cash flows.

Operating cash flows, before changes in operating assets and liabilities, were $413.5 million for the nine months ended September 30, 2009, compared with $551.3 million for the same period last year. The decrease was due primarily to lower commodity prices, increased operating costs at our fractionation facilities, Overland Pass Pipeline and Arbuckle Pipeline, and increased interest cost as a result of borrowings to fund our capital projects.

The changes in operating assets and liabilities decreased operating cash flows $64.5 million for the nine months ended September 30, 2009, compared with an increase of $17.4 million for the same period last year, primarily as a result of the following:

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

·	the timing of cash receipts from our revenues resulting in increased accounts receivable;

·	the timing of payments for purchases of commodities and other expenses resulting in increased accounts payable; and

·	the changes in volumes of commodities in storage.

Investing Cash Flows - Cash used in investing activities decreased for the nine months ended September 30, 2009, compared with the same period last year, due primarily to reduced capital expenditures as a result of the completion of the Arbuckle Pipeline and Overland Pass Pipeline and related expansion projects, the Williston Basin gas processing plant expansion and the Guardian Pipeline expansion and extension.

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.

During 2009, our common unit offering generated net proceeds of approximately $241.6 million. In addition, ONEOK Partners GP contributed $5.1 million in order to maintain its 2 percent general partner interest in us. We used the proceeds and general partner contributions to repay borrowings under our Partnership Credit Agreement and for general partnership purposes. During 2008, our common unit offering and private placement of common units generated proceeds of approximately $450.2 million. In addition, ONEOK Partners GP contributed $9.5 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.

Cash distributions to our general and limited partners for the nine months ended September 30, 2009, were $370.1 million, compared with $332.1 million in the same period last year, an increase of $38 million. This increase was due primarily to additional units outstanding during 2009, as well as cash distributions of $3.24 per unit during the nine months ended September 30, 2009, compared with cash distributions of $3.125 per unit for the same period last year.

Net repayments of notes payable were $355 million during the nine months ended September 2009, compared with net borrowings of $180 million for the same period last year.

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ENVIRONMENTAL AND SAFETY MATTERS

Information about our environmental matters is included in Note H of the Notes to Consolidated Financial Statements in this Quarterly Report.

Pipeline Safety - We are subject to United States Department of Transportation regulations, including integrity management regulations. The Pipeline Safety Improvement Act 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. We cannot be assured 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.

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 air and water quality regulations.

The United States Congress is actively considering legislation to reduce greenhouse gas emissions, 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 2008 data, indicates that our emissions are less than 4 million metric tons of carbon dioxide equivalents on an annual basis. We will continue efforts to improve our ability to quantify our direct greenhouse gas emissions and will report such emissions as required by the United States Environmental Protection Agency’s (EPA) Mandatory Greenhouse Gas Reporting rule released in September 2009. The rule requires greenhouse gas emissions reporting for affected facilities on an annual basis, beginning with our 2010 emissions report that will be due in March 2011.

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 risk-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.

Environmental Footprint - Our environmental and climate change strategy focuses on taking steps to minimize the impact of our operations on the environment. These strategies include: (i) developing and maintaining an accurate greenhouse gas emissions inventory, according to new rules issued by the EPA, (ii) improving the efficiency of our various pipelines, natural gas processing facilities and natural gas liquids fractionation facilities, (iii) following developing technologies for emissions control, (iv) following developing technologies to capture carbon dioxide to keep it from reaching the atmosphere, and (v) analyzing options for future energy investment.

We 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 2008 calculation of our annual lost-and-unaccounted-for natural gas, for all of our business operations, is less than 1 percent of total throughput.

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FORWARD-LOOKING STATEMENTS

Some of the statements contained and incorporated in this Quarterly Report are forward-looking statements within the meaning of Section 27A of the Securities Act, and Section 21E of the Exchange Act, 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 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, which are applicable only as of the date of this Quarterly Report. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:

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

·	competition from other United States and foreign energy suppliers and transporters, as well as alternative forms of energy, including, but not limited to, solar power, wind power, geothermal energy and biofuels such as ethanol and biodiesel;

·	the capital intensive nature of our businesses;

·	the profitability of assets or businesses acquired or constructed by us;

·	our ability to make cost-saving changes in operations;

·	risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties;

·	the uncertainty of estimates, including accruals and costs of environmental remediation;

·	the timing and extent of changes in energy commodity prices;

·	the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, environmental compliance, climate change initiatives, authorized rates of recovery of gas and gas transportation costs;

the impact on drilling and production by factors beyond our control, including the demand for natural gas and 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 with our competitors that have less debt or have other adverse consequences;

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

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

·	our ability to access capital at competitive rates or on terms acceptable to us;

·	risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines that outpace new drilling;

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·	the risk that material weaknesses or significant deficiencies in our internal control over financial reporting could emerge or that minor problems could become significant;

·	the impact and outcome of pending and future litigation;

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

-	future demand for and prices of natural gas and NGLs;

-	competitive conditions in the overall energy market;

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

-	availability of additional storage capacity;

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

·	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 updates and other changes in accounting policies;

·	the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions in the Middle East and elsewhere;

·	the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;

·	risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions;

·	the impact of unsold pipeline capacity being greater or less than expected;

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

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

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

·	the impact of potential impairment charges;

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

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

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

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our quantitative and qualitative disclosures about market risk are consistent with those discussed in Part II, Item 7A, Quantitative and Qualitative Disclosures About Market Risk in our Annual Report.

COMMODITY PRICE RISK

See Note C of the Notes to Consolidated Financial Statements and the discussion under Natural Gas Gathering and Processing’s “Commodity Price Risk” in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Quarterly Report for information on our hedging activities.

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ITEM 4.

CONTROLS AND PROCEDURES

Quarterly Evaluation of Disclosure Controls and Procedures - As of the end of the period covered by this report, the Chief Executive Officer (Principal Executive Officer) and the Chief Financial Officer (Principal Financial Officer) of ONEOK Partners GP, our general partner, evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to management of ONEOK Partners GP, including the officers of 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 September 30, 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 third quarter ended September 30, 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.

Will Price, et al. v. Gas Pipelines, et al. (f/k/a Quinque Operating Company, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 99C30 (“Price I”) - As previously reported, ONEOK and its division, Oklahoma Natural Gas, our subsidiaries Mid-Continent Market Center, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK WesTex Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP, successor to Koch Hydrocarbon Company), as well as approximately 225 other defendants, are defending against a lawsuit claiming underpayment of gas purchase proceeds. The plaintiffs initially asserted that the defendants understated both the volume and the heating content of the purchased gas, and sought class certification for gas producers and royalty owners throughout the United States. The Court refused to certify the class that resulted in the plaintiffs amending their petition to limit the purported class to gas producers and royalty owners in Kansas, Colorado and Wyoming, and limiting the claim to undermeasurement of volume. Oral arguments on the plaintiffs’ motion to certify this suit as a class action were conducted on April 1, 2005. On September 18, 2009, the Court denied the plaintiffs’ motions for class certification, which, in effect, limited the named plaintiffs to pursuing individual claims against only those defendants who purchased or measured their gas. On October 2, 2009, the plaintiffs filed a motion for reconsideration of the Court’s denial of class certification. Briefing, oral arguments and a ruling by the Court on this motion are pending.

Will Price and Stixon Petroleum, et al. v. Gas Pipelines, et al., 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 03C232 (“Price II”) - As previously reported, 21 groups of defendants, including ONEOK and its division, Oklahoma Natural Gas, our subsidiaries Mid-Continent Market Center, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK WesTex Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP, successor to Koch Hydrocarbon Company), are defending against a lawsuit claiming underpayment of gas producers and royalty owners by allegedly understating the heating content of purchased gas in Kansas, Colorado and Wyoming. This action was filed by the plaintiffs after the Court denied the initial motion for class status in Price I, and Price II was consolidated with Price I to determine whether either or both cases may properly be certified. Oral argument on the plaintiffs’ motion to certify this suit as a class action were conducted on April 1, 2005. On September 18, 2009, the Court denied the plaintiffs’ motions for class certification, which, in effect, limited the named plaintiffs to pursuing individual claims against only those defendants who purchased or measured their gas. On October 2, 2009, the plaintiffs filed a motion for reconsideration of the Court’s denial of class certification. Briefing, oral arguments and a ruling by the Court on this motion are pending.

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. We have tentatively reached agreement with the TCEQ staff on the terms of a settlement under which we would pay $160,000. Half of our

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payment obligation would be satisfied by contributions to two local environmental projects in Texas. We expect to enter into an Agreed Order memorializing the settlement, which will be subject to approval by the TCEQ, in early November 2009.

ITEM 1A.

RISK FACTORS

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

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Not Applicable.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

Not Applicable.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not Applicable.

ITEM 5.

OTHER INFORMATION

Not Applicable.

ITEM 6.

EXHIBITS

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

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

Exhibit No. Exhibit Description

31.1

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

31.2

Certification of Curtis L. Dinan pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

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

32.2

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

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema Document.

101.CAL

XBRL Taxonomy Calculation Linkbase Document.

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101.DEF

XBRL Taxonomy Extension Definitions Document.

101.LAB

XBRL Taxonomy Label Linkbase Document.

101.PRE

XBRL Taxonomy Presentation Linkbase Document.

Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in XBRL: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three and nine months ended September 30, 2009 and 2008; (iii) Consolidated Balance Sheets at September 30, 2009, and December 31, 2008; (iv) Consolidated Statements of Cash Flows for the nine months ended September 30, 2009 and 2008; (v) Consolidated Statement of Changes in Partners’ Equity for the nine months ended September 30, 2009; (vi) Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2009 and 2008; and (vii) Notes to Consolidated Financial Statements.

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

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

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

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

Date: November 5, 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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