form_10-q.htm

10-Q 1 form_10-q.htm 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, 2010

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

For the transition period from __________ to __________.

Commission file number 1-12202

ONEOK PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware		93-1120873
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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

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

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

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

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

Yes X No __

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

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

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

Yes __ No X

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

Class		Outstanding at October 29, 2010
Common units Class B units		65,413,677 units 36,494,126 units

ONEOK PARTNERS, L.P.

TABLE OF CONTENTS

Part I.	Financial Information	Page No.
Item 1.	Financial Statements (Unaudited)
	Consolidated Statements of Income - Three and Nine Months Ended September 30, 2010 and 2009	5
	Consolidated Balance Sheets - September 30, 2010, and December 31, 2009	6
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2010 and 2009	7
	Consolidated Statement of Changes in Equity - Nine Months Ended September 30, 2010	8-9
	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2010 and 2009	10
	Notes to Consolidated Financial Statements	11-22
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23-42
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	43
Part II.	Other Information
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 3.	Defaults Upon Senior Securities	43
Item 4.	(Removed and Reserved)	43
Item 5.	Other Information	43
Item 6.	Exhibits	44
Signature		45

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

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

INFORMATION AVAILABLE ON OUR 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 required to be submitted and posted pursuant to Rule 405 of Regulation S-T. In accordance with Rule 402 of Regulation S-T, the Interactive Data Files shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

GLOSSARY

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

AFUDC

Allowance for funds used during construction

Annual Report

Annual Report on Form 10-K for the year ended December 31, 2009

ASU

Accounting Standards Update

Bbl

Barrels, one barrel is equivalent to 42 United States gallons

Bbl/d

Barrels per day

BBtu/d

Billion British thermal units per day

Bcf

Billion cubic feet

Btu(s)

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

temperature of one pound of water one degree Fahrenheit

Bushton Plant

Bushton Gas Processing Plant

Clean Air Act

Federal Clean Air Act, as amended

Clean Water Act

Federal Water Pollution Control Act Amendments of 1972, as amended

EBITDA

Earnings before interest, taxes, depreciation and amortization

EPA

United States Environmental Protection Agency

Exchange Act

Securities Exchange Act of 1934, as amended

FASB

Financial Accounting Standards Board

FERC

Federal Energy Regulatory Commission

GAAP

Accounting principles generally accepted in the United States of America

Intermediate Partnership

ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary

of ONEOK Partners, L.P.

KCC

LIBOR

Kansas Corporation Commission

London Interbank Offered Rate

MBbl

Thousand barrels

MBbl/d

Thousand barrels per day

MDth/d

Thousand dekatherms per day

MMBbl

Million barrels

MMBtu

Million British thermal units

MMBtu/d

Million British thermal units per day

MMcf/d

Million cubic feet per day

Moody’s

Moody’s Investors Service, Inc.

NBP Services

NBP Services, LLC, a wholly owned subsidiary of ONEOK

NGL products

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

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

NGL(s)

Natural gas liquid(s)

Northern Border Pipeline

Northern Border Pipeline Company

NYMEX

New York Mercantile Exchange

OBPI

ONEOK Bushton Processing Inc.

OCC

Oklahoma Corporation Commission

ONEOK

ONEOK, Inc.

ONEOK Partners GP

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

sole general partner

OPIS

Oil Price Information Service

Overland Pass Pipeline Company

Overland Pass Pipeline Company LLC

Partnership Agreement

Third Amended and Restated Agreement of Limited Partnership of ONEOK

Partners, L.P., as amended

Partnership Credit Agreement

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

Agreement dated March 30, 2007

POP

Percent of proceeds

Quarterly Report(s)

Quarterly Report(s) on Form 10-Q

S&P

Standard & Poor’s Rating Group

SEC

Securities and Exchange Commission

Securities Act

Securities Act of 1933, as amended

Viking Gas Transmission

Viking Gas Transmission Company

XBRL

eXtensible Business Reporting Language

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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Unaudited)	2010			2009			2010			2009
	(Thousands of dollars, except per unit amounts)

Revenues	$	2,070,144		$	1,560,003		$	6,329,271		$	4,207,925
Cost of sales and fuel		1,784,139			1,267,124			5,493,979			3,399,523
Net margin		286,005			292,879			835,292			808,402
Operating expenses
Operations and maintenance		90,670			92,855			263,212			258,246
Depreciation and amortization		43,823			41,857			131,680			121,750
General taxes		7,127			12,253			28,851			36,815
Total operating expenses		141,620			146,965			423,743			416,811
Gain (loss) on sale of assets		16,126			(1,180	)		15,081			2,760
Operating income		160,511			144,734			426,630			394,351
Equity earnings from investments (Note H)		29,390			20,054			71,182			55,464
Allowance for equity funds used during construction		266			7,290			748			25,761
Other income		3,623			5,026			2,282			8,841
Other expense		(600	)		(299	)		(1,341	)		(2,728	)
Interest expense		(49,131	)		(50,371	)		(156,613	)		(152,167	)
Income before income taxes		144,059			126,434			342,888			329,522
Income taxes		(2,362	)		(4,729	)		(12,022	)		(10,668	)
Net income		141,697			121,705			330,866			318,854
Less: Net income attributable to noncontrolling interests		161			212			446			232
Net income attributable to ONEOK Partners, L.P.	$	141,536		$	121,493		$	330,420		$	318,622

Limited partners' interest in net income:
Net income attributable to ONEOK Partners, L.P.	$	141,536		$	121,493		$	330,420		$	318,622
General partner's interest in net income		(30,498	)		(25,010	)		(86,674	)		(70,710	)
Limited partners' interest in net income	$	111,038		$	96,483		$	243,746		$	247,912

Limited partners' net income per unit, basic and diluted (Note I)	$	1.09		$	1.00		$	2.41		$	2.67

Number of units used in computation (thousands)		101,908			96,402			101,187			92,932
See accompanying Notes to Consolidated Financial Statements.

ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	September 30,		December 31,
(Unaudited)	2010		2009
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	4,991	$	3,151
Accounts receivable, net		570,781		624,635
Affiliate receivables		28,110		32,397
Gas and natural gas liquids in storage		263,385		217,585
Commodity imbalances		98,264		188,177
Other current assets		54,318		36,148
Total current assets		1,019,849		1,102,093

Property, plant and equipment
Property, plant and equipment		5,701,670		6,353,909
Accumulated depreciation and amortization		1,065,891		972,497
Net property, plant and equipment		4,635,779		5,381,412

Investments and other assets
Investments in unconsolidated affiliates		1,194,087		765,163
Goodwill and intangible assets		663,120		668,870
Other assets		36,965		35,721
Total investments and other assets		1,894,172		1,469,754
Total assets	$	7,549,800	$	7,953,259

Liabilities and equity
Current liabilities
Current maturities of long-term debt	$	236,931	$	261,931
Notes payable (Note D)		326,385		523,000
Accounts payable		623,461		694,290
Affiliate payables		21,135		21,866
Commodity imbalances		235,854		392,688
Other current liabilities		144,858		153,539
Total current liabilities		1,588,624		2,047,314

Long-term debt, excluding current maturities		2,585,399		2,822,086

Deferred credits and other liabilities		84,648		73,798

Commitments and contingencies (Note F)

Equity
ONEOK Partners, L.P. partners’ equity:
General partner		93,782		84,434
Common units: 65,413,677 and 59,912,777 units issued and outstanding at September 30, 2010 and December 31, 2009, respectively		1,828,323		1,561,762
Class B units: 36,494,126 units issued and outstanding at September 30, 2010 and December 31, 2009		1,346,885		1,380,299
Accumulated other comprehensive income (loss)		16,878		(22,037	)
Total ONEOK Partners, L.P. partners' equity		3,285,868		3,004,458

Noncontrolling interests in consolidated subsidiaries		5,261		5,603

Total equity		3,291,129		3,010,061
Total liabilities and equity	$	7,549,800	$	7,953,259
See accompanying Notes to Consolidated Financial Statements.

ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS	Nine Months Ended
	September 30,
(Unaudited)	2010			2009
	(Thousands of dollars)
Operating Activities
Net income	$	330,866		$	318,854
Depreciation and amortization		131,680			121,750
Allowance for equity funds used during construction		(748	)		(25,761	)
Gain on sale of assets		(15,081	)		(2,760	)
Deferred income taxes		5,969			6,900
Equity earnings from investments		(71,182	)		(55,464	)
Distributions received from unconsolidated affiliates		69,889			56,896
Changes in assets and liabilities:
Accounts receivable		48,067			(128,003	)
Affiliate receivables		4,287			4,244
Gas and natural gas liquids in storage		(46,393	)		2,843
Accounts payable		(78,921	)		20,375
Affiliate payables		(731	)		9,156
Commodity imbalances, net		(66,921	)		(16,751	)
Other assets and liabilities		6,075			36,759
Cash provided by operating activities		316,856			349,038

Investing Activities
Contributions to unconsolidated affiliates		(1,313	)		(46,070	)
Distributions received from unconsolidated affiliates		9,342			26,192
Capital expenditures (less allowance for equity funds used during construction)		(202,773	)		(491,256	)
Proceeds from sale of assets		423,975			8,528
Cash provided by (used in) investing activities		229,231			(502,606	)

Financing Activities
Cash distributions:
General and limited partners		(417,446	)		(370,094	)
Noncontrolling interests		(760	)		(588	)
Borrowing (repayment) of notes payable, net		(196,615	)		515,000
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		(258,947	)		(8,948	)
Issuance of common units, net of discounts		322,701			241,643
Contribution from general partner		6,820			5,130
Cash provided by (used in) financing activities		(544,247	)		6,468
Change in cash and cash equivalents		1,840			(147,100	)
Cash and cash equivalents at beginning of period		3,151			177,635
Cash and cash equivalents at end of period	$	4,991		$	30,535
See accompanying Notes to Consolidated Financial Statements.

ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY


	ONEOK Partners, L.P. Partners' Equity


(Unaudited)	Common Units		Class B Units		General Partner			Common Units
	(Units)				(Thousands of dollars)

December 31, 2009		59,912,777		36,494,126	$	84,434		$	1,561,762
Net income		-		-		86,674			155,636
Other comprehensive income		-		-		-			-
Issuance of common units (Note E)		5,500,900		-		-			322,701
Contribution from general partner (Note E)		-		-		6,820			-
Distributions paid (Note E)		-		-		(84,146	)		(211,776	)
Other		-		-		-			-
September 30, 2010		65,413,677		36,494,126	$	93,782		$	1,828,323
See accompanying Notes to Consolidated Financial Statements.

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

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

December 31, 2009	$	1,380,299		$	(22,037	)	$	5,603		$	3,010,061
Net income		88,110			-			446			330,866
Other comprehensive income		-			38,915			-			38,915
Issuance of common units (Note E)		-			-			-			322,701
Contribution from general partner (Note E)		-			-			-			6,820
Distributions paid (Note E)		(121,524	)		-			(760	)		(418,206	)
Other		-			-			(28	)		(28	)
September 30, 2010	$	1,346,885		$	16,878		$	5,261		$	3,291,129

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Unaudited)	2010			2009			2010		2009
	(Thousands of dollars)

Net income	$	141,697		$	121,705		$	330,866	$	318,854
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives		2,955			(553	)		39,204		(13,633	)
Less: Realized gains (losses) on derivatives recognized in net income		4,007			12,865			289		48,485
Other		-			-			-		212
Total other comprehensive income (loss)		(1,052	)		(13,418	)		38,915		(61,906	)
Comprehensive income		140,645			108,287			369,781		256,948
Less: Comprehensive income attributable to noncontrolling interests		161			212			446		232
Comprehensive income attributable to ONEOK Partners, L.P.	$	140,484		$	108,075		$	369,335	$	256,716
See accompanying Notes to Consolidated Financial Statements.

ONEOK Partners, L.P. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

A. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our accompanying unaudited consolidated financial statements have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair presentation of the results for the interim periods presented. All such adjustments are of a normal recurring nature. The 2009 year-end consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements in our Annual Report.

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

Goodwill Impairment Test - We assess our goodwill for impairment at least annually on July 1. Our July 1, 2010, estimates of the fair value of each of our reporting units significantly exceeded their carrying values. Accordingly, no impairment charges were necessary.

Recently Issued Accounting Standards Update

The following recently issued accounting standards update affects our consolidated financial statements and related disclosures:

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

B. FAIR VALUE MEASUREMENTS

Determining Fair Value - We define fair value as the price that would be received from the sale of an asset or the transfer of a liability in an orderly transaction between market participants at the measurement date. We use the income approach to determine the fair value of our derivative assets and liabilities and consider the markets in which the transactions are executed. While many of the contracts in our portfolio are executed in liquid markets where price transparency exists, some contracts are executed in markets for which market prices may exist, but the market may be relatively inactive. This results in limited price transparency that requires management’s judgment and assumptions to estimate fair values. For certain transactions, we utilize modeling techniques using NYMEX-settled pricing data and historical correlations of NGL product prices to crude oil prices. We validate our valuation inputs with third-party information and settlement prices from other sources, where available. In addition, as prescribed by the income approach, we compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets and liabilities to present value using the interest rate-yields to calculate present-value discount factors derived from LIBOR, Eurodollar futures and U.S. Treasury swaps. Finally, we consider the credit risk of our counterparties with whom our derivative assets and liabilities are executed. Although we use our best estimates to determine the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ from our estimates, and the differences could be significant.

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


	September 30, 2010
	Level 1		Level 2			Level 3			Total - Gross			Netting (a)			Total - Net
	(Thousands of dollars)
Derivatives - commodity
Assets (b)	$	-	$	23,257		$	3,592		$	26,849		$	(6,305	)	$	20,544
Liabilities (c)	$	-	$	(3,769	)	$	(4,799	)	$	(8,568	)	$	6,305		$	(2,263	)

	December 31, 2009
	Level 1		Level 2			Level 3			Total - Gross			Netting (a)			Total - Net
	(Thousands of dollars)
Derivatives - commodity
Assets (b)	$	-	$	459		$	-		$	459		$	(459	)	$	-
Liabilities (c)	$	-	$	(5,720	)	$	(13,052	)	$	(18,772	)	$	459		$	(18,313	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us.
(b) - Included in other current assets and other assets in our Consolidated Balance Sheets.
(c) - Included in other current liabilities in our Consolidated Balance Sheets.

At September 30, 2010, and December 31, 2009, we had no cash collateral held or posted under our master-netting arrangements.

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

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

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

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Derivative Assets (Liabilities)	2010			2009			2010			2009
	(Thousands of dollars)
Net assets (liabilities) at beginning of period	$	6,244		$	11,597		$	(13,052	)	$	37,649
Total realized/unrealized gains (losses):
Included in earnings (a)		(1,621	)		1,652			(2,680	)		3,738
Included in other comprehensive income (loss)		(5,830	)		(10,039	)		14,525			(38,177	)
Net assets (liabilities) at end of period	$	(1,207	)	$	3,210		$	(1,207	)	$	3,210

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)	$	(1,446	)	$	51		$	(2,680	)	$	51
(a) - Included in revenues in our Consolidated Statements of Income.

Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable, accounts payable and notes payable is equal to book value, due to the short-term nature of these items.

The estimated fair value of the aggregate of our senior notes outstanding, including current maturities, was $3.2 billion and $3.3 billion at September 30, 2010, and December 31, 2009, respectively. The book value of the aggregate of our senior notes outstanding, including current maturities, was $2.8 billion and $3.1 billion at September 30, 2010, and December 31, 2009, respectively. The estimated fair value of the aggregate of our senior notes outstanding has been determined using quoted market prices for similar issues with similar terms and maturities.

C. RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

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

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

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

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

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

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

minimize the impact of price fluctuations related to natural gas, NGLs and condensate. We reduce our gross processing spread exposure through a combination of physical and financial hedges. We utilize a portion of our POP equity natural gas production as an offset, or natural hedge, to an equivalent portion of our keep-whole shrink requirements. This has the effect of converting our gross processing spread risk to NGL commodity price risk. We hedge a portion of the forecasted sales of the commodities we retain, including NGLs, natural gas and condensate.

In our Natural Gas Pipelines segment, we are exposed to commodity price risk because our intrastate and interstate natural gas pipelines collect natural gas from our customers for operations or as part of our fee for services provided. When the amount of natural gas consumed in operations by these pipelines differs from the amount provided by our customers, our pipelines must buy or sell natural gas, or store or use natural gas from inventory, which can expose us to commodity price risk depending on the regulatory treatment for this activity. We use physical forward sales or purchases to reduce the impact of price fluctuations related to natural gas. At September 30, 2010, and December 31, 2009, there were no financial derivative instruments with respect to our natural gas pipeline operations.

In our Natural Gas Liquids segment, we are exposed to basis risk primarily as a result of the relative value of NGL purchases at one location and sales at another location. To a lesser extent, we are exposed to commodity price risk resulting from the relative values of the various NGL products to each other, NGLs in storage and the relative value of NGLs to natural gas. We utilize physical forward contracts to reduce the impact of price fluctuations related to NGLs. At September 30, 2010, and December 31, 2009, there were no financial derivative instruments with respect to our NGL operations.

Interest-rate risk - We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps. Interest-rate swaps are agreements to exchange an interest payment at some future point based on the differential between two interest rates. At September 30, 2010, and December 31, 2009, we did not have any interest-rate swap agreements.

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

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

	Recognition and Measurement
Accounting Treatment	Balance Sheet	Income Statement
Normal purchases and normal sales	- Fair value not recorded	- Change in fair value not recognized in earnings
Mark-to-market	- Recorded at fair value	- Change in fair value recognized in earnings
Cash flow hedge	- Recorded at fair value	- Ineffective portion of the gain or loss on the derivative instrument is recognized in earnings

	- Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated other comprehensive income (loss)	- Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated other comprehensive income (loss) into earnings when the forecasted transaction affects earnings
Fair value hedge	- Recorded at fair value	- The gain or loss on the derivative instrument is recognized in earnings

	- Change in fair value of the hedged item is recorded as an adjustment to book value	- Change in fair value of the hedged item is recognized in earnings

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

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

Fair Values of Derivative Instruments - See Note B for a discussion of the inputs associated with our fair value measurements. The following table sets forth the fair values of our derivative instruments for the periods indicated:

	September 30, 2010					December 31, 2009
	Assets (a)		(Liabilities) (b)			Assets (a)		(Liabilities) (b)
	(Thousands of dollars)

Commodity derivatives designated as hedging instruments - financial	$	24,061	$	(3,223	)	$	459	$	(18,772	)

Commodity derivatives not designated as hedging instruments
Financial		2,381		(3,082	)		-		-
Physical		407		(2,263	)		-		-
Total derivatives not designated as hedging instruments		2,788		(5,345	)		-		-
Total derivatives	$	26,849	$	(8,568	)	$	459	$	(18,772	)
(a) - Included on a net basis in other current assets and other assets on our Consolidated Balance Sheets.
(b) - Included on a net basis in other current liabilities on our Consolidated Balance Sheets.

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

					September 30, 2010		December 31, 2009
				Contract Type	Purchased/ Payor	Sold/ Receiver	Purchased/ Payor	Sold/ Receiver
Derivatives designated as hedging instruments:
	Cash flow hedges
		Fixed price
			- Natural gas (Bcf)	Swaps	-	(10.4)	-	(9.2)
			- Crude oil and NGLs (MMBbl)	Swaps	-	(1.2)	-	(2.4)
		Basis
			- Natural gas (Bcf)	Swaps	-	(10.4)	-	(9.2)

Derivatives not designated as hedging instruments
	Cash flow hedges
		Fixed price
			- Natural gas (Bcf)	Swaps	2.9	(2.9)	-	-
			- Crude oil and NGLs (MMBbl)	Forwards and Swaps	1.0	(1.4)	-	-
		Basis
			- Natural gas (Bcf)	Swaps	3.6	(3.6)	-	-

Cash Flow Hedges - At September 30, 2010, our Consolidated Balance Sheet reflected a net unrealized gain of $21.0 million in accumulated other comprehensive income (loss), with a corresponding offset in derivative financial instrument assets and liabilities that will be realized within the next 15 months as the forecasted transactions affect earnings. If prices remain at current levels, we will recognize $17.1 million in gains over the next 12 months, and we will recognize $3.9 million in gains thereafter.

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

	Three Months Ended					Nine Months Ended
Derivatives in Cash Flow Hedging Relationships	September 30,					September 30,
Derivatives in Cash Flow Hedging Relationships	2010		2009			2010		2009
	(Thousands of dollars)
Commodity contracts	$	2,955	$	(1,588	)	$	39,204	$	(15,232	)
Interest-rate contracts		-		1,035			-		1,599
Total gain (loss) recognized in other comprehensive income (loss) (effective portion)	$	2,955	$	(553	)	$	39,204	$	(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	Three Months Ended					Nine Months Ended
Derivatives in Cash Flow	Accumulated Other Comprehensive Income	September 30,					September 30,
Hedging Relationships	(Loss) into Net Income (Effective Portion)	2010			2009		2010		2009
		(Thousands of dollars)
Commodity contracts	Revenues	$	4,214		$	12,500	$	54	$	47,248
Interest-rate contracts	Interest expense		(207	)		365		235		1,237
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income (effective portion)		$	4,007		$	12,865	$	289	$	48,485

Ineffectiveness related to our cash flow hedges was not material for the three and nine months ended September 30, 2010 and 2009. In the event that it becomes probable that a forecasted transaction will not occur, we would discontinue cash flow hedge treatment, which would affect earnings. There were no gains or losses due to the discontinuance of cash flow hedge treatment during the three and nine months ended September 30, 2010 and 2009.

The balance in accumulated other comprehensive income in our Consolidated Balance Sheets at September 30, 2010, and December 31, 2009, was attributable to unrealized gains and losses on derivatives.

Credit Risk - All of our commodity derivative financial contracts are with ONEOK Energy Services Company, L.P. (OES), a subsidiary of ONEOK. OES has entered similar commodity derivative financial contracts with third parties at our direction and on our behalf. We have an indemnification agreement with OES that indemnifies and holds OES harmless from any liability it may incur solely as a result of its entering into commodity derivative financial contracts on our behalf. Derivative assets for which we would indemnify OES in the event of a default by the counterparty totaled $20.1 million at September 30, 2010, and were with investment-grade counterparties that are primarily in the oil and gas and financial services sectors. At December 31, 2009, there were no derivative assets for which we would indemnify OES in the event of a default by the counterparty.

D. CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

Our Partnership Credit Agreement, which expires in March 2012, contains certain financial, operational and legal covenants. Among other things, these requirements include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in our Partnership Credit Agreement, adjusted for all non-cash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5 to 1. If we consummate one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will increase to 5.5 to 1 for the three calendar quarters following the acquisitions. At September 30, 2010, our ratio of indebtedness to adjusted EBITDA was 3.8 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.

In June 2010, we initiated a new commercial paper program under which we may issue unsecured commercial paper notes up to a maximum amount outstanding of $1.0 billion to fund our short-term borrowing needs. The maturities of the commercial paper notes vary but may not exceed 270 days from the date of issue. The commercial paper notes are sold at a negotiated discount from par or will bear interest at a negotiated rate.

Our Partnership Credit Agreement is available to repay the commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowings available under our Partnership Credit Agreement. In July 2010, we repaid all borrowings outstanding under our Partnership Credit Agreement with the issuance of commercial paper.

At September 30, 2010, we had $326.4 million in commercial paper outstanding and no borrowings under our Partnership Credit Agreement, leaving approximately $673.6 million of credit available under the Partnership Credit Agreement. At December 31, 2009, we had $523.0 million in borrowings outstanding under our Partnership Credit Agreement. At September 30, 2010, and December 31, 2009, we had $24.2 million issued in letters of credit outside of the Partnership Credit Agreement. Borrowings under our Partnership Credit Agreement are nonrecourse to our general partner.

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

E. EQUITY

ONEOK - ONEOK and its affiliates owned all of the Class B units, 5.9 million common units and the entire 2 percent general partner interest in us, which together constituted a 42.8 percent ownership interest in us at September 30, 2010.

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

Cash Distributions - Cash distributions paid to our general partner of $84.1 million and $69.6 million in the nine months ended September 30, 2010 and 2009, respectively, included incentive distributions of $75.8 million and $62.2 million, respectively.

In October 2010, our general partner declared a cash distribution of $1.13 per unit ($4.52 per unit on an annualized basis) for the third quarter of 2010, an increase of $.01 from the previous quarter, which will be paid on November 12, 2010, to unitholders of record at the close of business on October 29, 2010.

F. COMMITMENTS AND CONTINGENCIES

Environmental Liabilities - We are subject to multiple environmental, historical and wildlife preservation laws and regulations affecting many aspects of our present and future operations. Regulated activities include those involving air emissions, stormwater and wastewater discharges, handling and disposal of solid and hazardous wastes, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. If a leak or spill of hazardous substances or petroleum products occurs from pipelines or facilities that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including response, investigation and clean-up costs, which could materially affect our results of operations and cash flows. In addition, emission controls required under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations.

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position or results of operations, and our expenditures related to environmental matters had no material effect upon earnings or cash flows during the three and nine months ended September 30, 2010 and 2009.

will consider lowering the threshold levels over the next five years, which could increase the impact on our existing facilities; however, potential costs, fees or expenses associated with the potential adjustments are unknown.

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

G. SEGMENTS

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

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

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

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

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

Customers - For the three and nine months ended September 30, 2010 and 2009, we had no single customer from which we received 10 percent or more of our consolidated revenues.

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

Three Months Ended September 30, 2010	Natural Gas Gathering and Processing			Natural Gas Pipelines (a)		Natural Gas Liquids (b)		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	119,002		$	61,215	$	1,771,942	$	-		$	1,952,159
Sales to affiliated customers		86,496			31,489		-		-			117,985
Intersegment revenues		106,891			346		7,421		(114,658	)		-
Total revenues	$	312,389		$	93,050	$	1,779,363	$	(114,658	)	$	2,070,144

Net margin	$	87,797		$	75,027	$	123,766	$	(585	)	$	286,005
Operating costs		34,142			24,868		39,420		(633	)		97,797
Depreciation and amortization		15,266			11,157		17,400		-			43,823
Gain (loss) on sale of assets		(158	)		-		16,284		-			16,126
Operating income	$	38,231		$	39,002	$	83,230	$	48		$	160,511

Equity earnings from investments	$	7,424		$	21,289	$	677	$	-		$	29,390
Capital expenditures	$	69,344		$	6,757	$	27,701	$	277		$	104,079
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $74.0 million, net margin of $58.4 million and operating income of $28.1 million.
(b) - Our Natural Gas Liquids segment has regulated and non-regulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $76.6 million, of which $50.5 million related to sales within the segment, net margin of $52.7 million and operating income of $28.9 million.

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	$	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.

Nine Months Ended September 30, 2010	Natural Gas Gathering and Processing			Natural Gas Pipelines (a)		Natural Gas Liquids (b)		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	342,849		$	175,227	$	5,448,191	$	-		$	5,966,267
Sales to affiliated customers		278,887			84,117		-		-			363,004
Intersegment revenues		360,971			1,283		20,718		(382,972	)		-
Total revenues	$	982,707		$	260,627	$	5,468,909	$	(382,972	)	$	6,329,271

Net margin	$	257,857		$	226,414	$	356,287	$	(5,266	)	$	835,292
Operating costs		98,438			71,252		126,188		(3,815	)		292,063
Depreciation and amortization		44,924			33,100		53,656		-			131,680
Gain (loss) on sale of assets		(433	)		64		15,450		-			15,081
Operating income	$	114,062		$	122,126	$	191,893	$	(1,451	)	$	426,630

Equity earnings from investments	$	20,663		$	48,864	$	1,655	$	-		$	71,182
Investments in unconsolidated affiliates	$	326,245		$	400,577	$	467,265	$	-		$	1,194,087
Total assets	$	1,714,194		$	1,888,386	$	4,406,422	$	(459,202	)	$	7,549,800
Noncontrolling interests in consolidated subsidiaries	$	-		$	5,246	$	-	$	15		$	5,261
Capital expenditures	$	118,284		$	18,426	$	65,256	$	807		$	202,773
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $206.5 million, net margin of $177.6 million and operating income of $90.3 million.
(b) - Our Natural Gas Liquids segment has regulated and non-regulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $248.2 million, of which $158.1 million related to sales within the segment, net margin of $185.7 million and operating income of $102.9 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	$	120,864	$	106,078		$	167,895		$	(486	)	$	394,351

Equity earnings from investments	$	20,583	$	32,802		$	2,079		$	-		$	55,464
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.

H. UNCONSOLIDATED AFFILIATES

Overland Pass Pipeline Company - In September 2010, we completed a transaction to sell a 49 percent ownership interest in Overland Pass Pipeline Company to a subsidiary of Williams Partners L. P. (Williams) resulting in each joint-venture member now owning 50 percent of Overland Pass Pipeline Company. In accordance with the joint-venture agreement, we received approximately $423.7 million in cash at closing. As a result of the transaction, we no longer control Overland Pass Pipeline Company and began accounting for our investment under the equity method of accounting in September 2010. In connection with the deconsolidation of Overland Pass Pipeline Company, we recognized approximately $16.3 million in gain on sale of assets, primarily attributable to the remeasurement of our retained investment in Overland Pass Pipeline Company to its fair value, and have recorded our retained investment of approximately $438.0 million in investments in unconsolidated affiliates. Our estimate of the fair value of our retained interest in Overland Pass Pipeline Company was based upon the income and market valuation approaches.

Northern Border Pipeline - Northern Border Pipeline anticipates requiring an additional equity contribution of approximately $102 million from its partners in 2011, of which our share will be approximately $51 million based on our 50 percent equity interest.

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,
		2010	2009		2010		2009
	(Thousands of dollars)
Northern Border Pipeline	$	21,183	$	10,882	$	48,401	$	32,374
Fort Union Gas Gathering, L.L.C.		3,633		4,397		10,772		10,412
Bighorn Gas Gathering, L.L.C.		1,664		1,935		3,712		5,845
Lost Creek Gathering Company, L.L.C.		1,156		1,445		4,012		3,647
Overland Pass Pipeline Company		1,011		-		1,011		-
Other		743		1,395		3,274		3,186
Equity earnings from investments	$	29,390	$	20,054	$	71,182	$	55,464

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,
	2010		2009		2010		2009
	(Thousands of dollars)
Income Statement
Operating revenues	$	119,205	$	101,987	$	316,513	$	296,004
Operating expenses	$	48,566	$	49,312	$	138,177	$	138,544
Net income	$	63,588	$	42,929	$	156,454	$	125,574

Distributions paid to us	$	29,587	$	19,615	$	79,231	$	83,088

Distributions paid to us are classified as operating activities on our Consolidated Statements of Cash Flows until the cumulative distributions exceed our proportionate share of income from the unconsolidated affiliate since the date of our initial investment. The amount of cumulative distributions paid to us that exceeds our cumulative proportionate share of income in each period represents a return of investment and is classified as an investing activity on our Consolidated Statement of Cash Flows.

I. LIMITED PARTNERS’ NET INCOME PER UNIT

Limited partners’ net income per unit is computed by dividing net income attributable to ONEOK Partners, L.P., after deducting the general partner’s allocation as discussed below, by the weighted-average number of outstanding limited partner units, which includes our common and Class B limited partner units. ONEOK, as sole holder of our Class B units, has waived its right to receive increased quarterly distributions on the Class B units. Because ONEOK has waived its right to increased quarterly distributions, currently each Class B unit and common unit share equally in the earnings of the partnership, and neither has any liquidation or other preferences. ONEOK retains the option to withdraw its waiver of increased distributions on Class B units 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 $27.7 million and $22.5 million for the three months ended September 30, 2010 and 2009, respectively, and $80.1 million and $64.3 million for the nine months ended September 30, 2010 and 2009, respectively.

J. RELATED-PARTY TRANSACTIONS

Our Natural Gas Gathering and Processing segment sells natural gas to ONEOK and its subsidiaries. A portion of our Natural Gas Pipelines segment’s revenues are from ONEOK and its subsidiaries. Additionally, our Natural Gas Gathering and Processing segment and Natural Gas Liquids segment purchase a portion of the natural gas used in their operations from ONEOK and its subsidiaries.

We have certain contractual rights to the Bushton Plant. Our Processing and Services Agreement with ONEOK and OBPI sets out the terms by which OBPI provides services to us at the Bushton Plant through 2012. We have contracted for all of the capacity of the Bushton Plant from OBPI. In exchange, we pay OBPI for all costs and expenses necessary for the operation and maintenance of the Bushton Plant, and we reimburse ONEOK for OBPI’s obligations under equipment leases covering the Bushton Plant.

Under the Services Agreement with ONEOK, ONEOK Partners GP and NBP Services (Services Agreement), our operations and the operations of ONEOK and its affiliates can combine or share certain common services in order to operate more efficiently and cost effectively. Under the Services Agreement, ONEOK provides to us similar services that it provides to its affiliates, including those services required to be provided pursuant to our Partnership Agreement. ONEOK Partners GP may purchase services from ONEOK and its affiliates pursuant to the terms of the Services Agreement. ONEOK Partners GP has no employees and utilizes the services of ONEOK and ONEOK Services Company to fulfill its operating obligations.

ONEOK and its affiliates provide a variety of services to us under the Services Agreement, including cash management and financial services, employee benefits provided through ONEOK’s benefit plans, legal and 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.

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

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
		2010		2009		2010		2009
	(Thousands of dollars)
Revenues		$	117,985	$	116,582	$	363,004	$	368,287

Expenses
Cost of sales and fuel		$	12,402	$	10,267	$	41,377	$	36,321
Administrative and general expenses			47,703		43,800		150,702		142,278
Total expenses		$	60,105	$	54,067	$	192,079	$	178,599

Cash Distributions to ONEOK - We paid cash distributions to ONEOK and its subsidiaries related to its general and limited partner interests of $77.0 million and $69.9 million for the three months ended September 30, 2010 and 2009, respectively, and $225.3 million and $206.9 million for the nine months ended September 30, 2010 and 2009, respectively.

ITEM 2.

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

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

RECENT DEVELOPMENTS

Growth Projects - In 2010, we announced approximately $1.3 billion to $1.6 billion in growth projects primarily in the Williston Basin in North Dakota that will enable us to meet the rapidly growing needs of crude oil and natural gas producers as they increase their drilling activities. Drilling rig counts in Dunn, McKenzie and Williams counties in North Dakota have increased dramatically since the beginning of the year. The development of the reserves in the Bakken Shale and Three Forks formations in the Williston Basin are being driven primarily by crude oil economics with the associated natural gas production having a high NGL content. Current natural gas processing and NGL infrastructure in the Williston Basin is being expanded to accommodate the additional production from the increased development activities.

We are the largest independent gatherer and processor of natural gas in the Williston Basin. With our Natural Gas Gathering and Processing segment’s existing infrastructure and acreage dedications, we are well positioned to provide midstream services to crude oil and natural gas producers as they develop Bakken Shale and Three Forks reserves. Additional NGL infrastructure is also needed due to the continued NGL production growth that has saturated the area’s current truck and railcar transportation capacity and market. The following provides additional details about the individual projects:

Williston Basin Processing Plants and related projects - We announced plans to construct two new 100 MMcf/d natural gas processing facilities, the Garden Creek plant in eastern McKenzie County, North Dakota, and the Stateline I plant in western Williams County, North Dakota. In addition, we plan to make investments in related NGL infrastructure, expansions and upgrades to our existing gathering and compression infrastructure and new well connections associated with these plants. The Garden Creek plant and related projects are expected to be in service by the end of 2011 and cost approximately $350 million to $415 million, excluding AFUDC. The Stateline I plant and related projects are expected to be completed during the third quarter of 2012 and cost approximately $300 million to $355 million, excluding AFUDC. These projects are in our Natural Gas Gathering and Processing segment.

Bakken Pipeline and related projects - We announced plans to build a 525- to 615-mile natural gas liquids pipeline that will transport unfractionated NGLs from the Williston Basin in North Dakota to the Overland Pass Pipeline. The Bakken Pipeline will initially transport up to 60 MBbl/d of unfractionated NGL production from our natural gas gathering and processing assets in the Williston Basin and from third-party natural gas processing plants south through western North Dakota and eastern Montana to Wyoming, where it will connect to the Overland Pass Pipeline near Cheyenne, Wyoming. The unfractionated NGLs will then be delivered to our existing NGL fractionation and distribution infrastructure in the Mid-Continent. Additional pump facilities could increase the new pipeline’s capacity to 110 MBbl/d. Supply commitments for the Bakken Pipeline will be anchored by NGL production from our natural gas processing plants. We are also discussing NGL supply commitments with third-party processors. Following receipt of all necessary permits, construction of the 12-inch diameter pipeline is expected to begin in the second quarter of 2012 and be completed during the first half of 2013. Project costs for the new pipeline are estimated to be $450 million to $550 million, excluding AFUDC.

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

We also announced plans to invest $110 million to $140 million, excluding AFUDC, to expand and upgrade our existing fractionation capacity at Bushton, Kansas, increasing our capacity to 210 MBbl/d from 150 MBbl/d. The Bakken Pipeline and related projects are in our Natural Gas Liquids segment.

Sterling I Pipeline Expansion - We will install seven additional pump stations for approximately $36 million along our existing Sterling I natural gas liquids distribution pipeline, increasing its capacity by 15 MBbl/d, which will be supplied by our Mid-Continent NGL infrastructure. The Sterling I pipeline transports purity NGL products from our fractionator in Medford, Oklahoma, to the Mont Belvieu, Texas, market center and is currently operating at capacity. The pump stations are expected to be completed in the second half of 2011. This project is in our Natural Gas Liquids segment.

Woodford Shale projects - We will invest $55 million in the Woodford Shale development in Oklahoma for new well connections in 2010 and 2011, which includes connecting our natural gas gathering system to our Maysville, Oklahoma, natural gas processing facility and connecting a new third-party processing plant to our NGL gathering system in Oklahoma. These projects are in our Natural Gas Gathering and Processing and Natural Gas Liquids segments, respectively.

For a discussion of our capital expenditure financing, see “Capital Expenditures” in “Liquidity and Capital Resources” on page 36.

Cash Distributions - In October 2010, our general partner declared a cash distribution of $1.13 per unit ($4.52 per unit on an annualized basis) for the third quarter of 2010, an increase of $0.01 from the previous quarter, which will be paid November 12, 2010, to unitholders of record at the close of business on October 29, 2010.

Commercial Paper Program - In June 2010, we established a commercial paper program providing for the issuance of up to $1.0 billion of unsecured commercial paper notes. Amounts outstanding under the commercial paper program reduce the borrowings available under our Partnership Credit Agreement. In July 2010, we repaid all borrowings outstanding under our Partnership Credit Agreement with the issuance of commercial paper.

Long-Term Debt - In June 2010, we repaid $250 million of maturing senior notes with available cash and short-term borrowings. With the repayment of these notes, we no longer have any obligation to offer to repurchase the $225 million senior notes due 2011 in the event that our long-term debt credit ratings fall below investment grade.

Overland Pass Pipeline Company - In September 2010, we completed a transaction to sell a 49 percent ownership interest in Overland Pass Pipeline Company to a subsidiary of Williams resulting in each joint-venture member now owning 50 percent of Overland Pass Pipeline Company. In accordance with the joint-venture agreement, we received approximately $423.7 million in cash at closing. We used the proceeds from the transaction to repay short-term debt and to fund a portion of our recently announced capital projects. Williams has elected to become the operator of Overland Pass Pipeline Company. Williams is expected to fully assume the role of operator by the end of the first quarter of 2011. As a result of the transaction, we no longer control Overland Pass Pipeline Company and began accounting for our investment under the equity method of accounting in September 2010. In connection with the deconsolidation of Overland Pass Pipeline Company, we recognized a gain of approximately $16.3 million.

REGULATORY

Environmental Matters - 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 pipelines or facilities that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including response, investigation and clean-up costs, which could materially affect our results of operations and cash flows. In addition, emission controls required under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations.

2011 and, at current emission threshold levels, will have a minimal impact on our existing facilities. The EPA has stated it will consider lowering the threshold levels over the next five years, which could increase the impact on our existing facilities; however, potential costs, fees or expenses associated with the potential adjustments are unknown.

Financial Markets Legislation - In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted, representing a far-reaching overhaul of the framework for regulation of U.S. financial markets. We are currently evaluating the provisions of the Dodd-Frank Act. The Dodd-Frank Act calls for various regulatory agencies, including the SEC and the Commodities Futures Trading Commission, to establish regulations for implementation of many of the provisions of the Dodd-Frank Act, which we expect will provide additional clarity regarding the extent of the impact of this legislation on us. We expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest-rate risks; however, the costs of doing so may be increased as a result of the new legislation. We may also incur additional costs associated with our compliance with the new regulations and anticipated additional reporting and disclosure obligations.

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Information about our critical accounting policies and estimates is included under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Critical Accounting Policies and 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, 2010, 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, and assumptions consistent with a market participant’s perspective. 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 discount rates. Under the market approach, we apply multiples to forecasted cash flows. The multiples used are consistent with historical asset transactions. The forecasted cash flows are based on average forecasted cash flows 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, 2010, impairment test. Even if the estimated fair values used in our July 1, 2010, impairment test were reduced by 10 percent, no impairment charges would have resulted. At both September 30, 2010, and December 31, 2009, we had $396.7 million of goodwill recorded on our Consolidated Balance Sheets.

FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

Selected Financial Results - We placed the following projects in service during 2009:

·	February - Guardian Pipeline’s expansion and extension project in our Natural Gas Pipelines segment;

·	March - Williston Basin natural gas processing plant expansion in our Natural Gas Gathering and Processing segment;

·	March - D-J Basin lateral pipeline in our Natural Gas Liquids segment;

·	July - Arbuckle Pipeline in our Natural Gas Liquids segment; and

·	October - Piceance lateral pipeline in our Natural Gas Liquids segment.

Additional discussion of our completed capital projects is included under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report. The in-service dates of these completed capital projects have impacted the period-to-period comparisons of net margin and operating expenses primarily in our Natural Gas Liquids and Natural Gas Pipelines segments, as operations associated with these projects have been increasing since being placed in service. The following table sets forth certain selected consolidated financial results for the periods indicated:

	Three Months Ended						Nine Months Ended						Three Months					Nine Months
	September 30,						September 30,						2010 vs. 2009					2010 vs. 2009
Financial Results	2010			2009			2010			2009			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Revenues	$	2,070.1		$	1,560.0		$	6,329.3		$	4,207.9		$	510.1		33	%	$	2,121.4		50	%
Cost of sales and fuel		1,784.1			1,267.1			5,494.0			3,399.5			517.0		41	%		2,094.5		62	%
Net margin		286.0			292.9			835.3			808.4			(6.9	)	(2	%)		26.9		3	%
Operating costs		97.8			105.1			292.1			295.0			(7.3	)	(7	%)		(2.9	)	(1	%)
Depreciation and amortization		43.8			41.9			131.7			121.8			1.9		5	%		9.9		8	%
Gain (loss) on sale of assets		16.1			(1.2	)		15.1			2.8			17.3		*			12.3		*
Operating income	$	160.5		$	144.7		$	426.6		$	394.4		$	15.8		11	%	$	32.2		8	%

Equity earnings from investments	$	29.4		$	20.1		$	71.2		$	55.5		$	9.3		46	%	$	15.7		28	%
Allowance for equity funds used during construction	$	0.3		$	7.3		$	0.7		$	25.8		$	(7.0	)	(96	%)	$	(25.1	)	(97	%)
Interest expense	$	(49.1	)	$	(50.4	)	$	(156.6	)	$	(152.2	)	$	(1.3	)	(3	%)	$	4.4		3	%
Capital expenditures	$	104.1		$	169.4		$	202.8		$	491.3		$	(65.3	)	(39	%)	$	(288.5	)	(59	%)
* Percentage change is greater than 100 percent.

Energy markets were affected by increased commodity prices during the three and nine months ended September 30, 2010, compared with the same periods last year. The increase in commodity prices had a direct impact on our revenues and cost of sales and fuel.

Net margin decreased for the three months ended September 30, 2010, compared with the same period last year, due primarily to the following:

·	lower optimization margins due to narrower NGL product price differentials between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers and limited NGL fractionation and transportation capacity available for optimization activities; offset partially by

·	an increase in volumes gathered, fractionated and transported, primarily associated with the completion of the Arbuckle Pipeline and Piceance lateral pipeline, as well as new supply connections in our Natural Gas Liquids segment.

Net margin increased for the nine months ended September 30, 2010, compared with the same period last year, due primarily to the following:

·	increased NGL volumes gathered, fractionated and transported, primarily associated with the completion of the Arbuckle Pipeline, Piceance lateral pipeline and D-J Basin lateral pipeline, as well as new supply connections;

·	higher natural gas transportation margins from increased capacity contracted on Midwestern Gas Transmission and Viking Gas Transmission’s Fargo lateral and the incremental margin from the Guardian Pipeline expansion and extension project;

·	an increase from the impact of higher natural gas prices on retained fuel;

·	higher storage margins primarily due to contract renegotiations in our Natural Gas Pipelines and Natural Gas Liquids segments; offset partially by

·	a decrease in optimization margins due to limited fractionation and transportation capacity available for optimization activities and narrower NGL product price differentials between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers; and

·	a decrease in natural gas volumes gathered as a result of natural production declines and reduced drilling activity by our customers in the Powder River Basin in our Natural Gas Gathering and Processing segment.

Operating costs decreased for the three and nine months ended September 30, 2010, compared with the same period last year, due primarily to lower than estimated ad valorem taxes associated with our capital projects completed in 2009 and lower costs for outside services attributable to maintenance projects at our NGL fractionators in 2009. For the nine month period, these decreases were offset by higher property insurance costs related to increased coverage for our assets and higher employee labor costs resulting from the operation of our completed capital projects in 2009.

Depreciation and amortization increased for the three and nine months ended September 30, 2010, compared with the same periods last year, due primarily to higher depreciation expense associated with our completed capital projects.

Gain (loss) on sale of assets increased for the three and nine months ended September 30, 2010, compared with the same periods last year, due to the gain on sale of a 49 percent ownership interest in Overland Pass Pipeline Company in our Natural Gas Liquids segment.

Equity earnings from investments increased for the three and nine months ended September 30, 2010, compared with the same periods last year, due to increased contracted capacity on Northern Border Pipeline due to wider natural gas price differentials between the markets it serves.

Allowance for equity funds used during construction decreased for the three and nine months ended September 30, 2010, compared with the same periods last year, due primarily to our completed capital projects.

Capital expenditures decreased for the three and nine months ended September 30, 2010, compared with the same periods last year, due primarily to our completed capital projects, offset partially by initial expenditures on our recently announced capital projects, primarily in our Natural Gas Gathering and Processing and Natural Gas Liquids segments.

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

Natural Gas Gathering and Processing

Overview - Our Natural Gas Gathering and Processing segment’s operations include gathering and processing of natural gas produced from crude oil and natural gas wells. We gather and process natural gas in the Mid-Continent region, which includes the Anadarko Basin of Oklahoma that contains the NGL-rich Woodford shale formation and the Hugoton and Central Kansas Uplift Basins of Kansas. We also gather and/or process natural gas in two producing basins in the Rocky Mountain region: the Williston Basin, which spans portions of Montana and North Dakota that includes the oil-producing Bakken and Three Forks shale formations, and the Powder River Basin of Wyoming. The natural gas we gather in the Powder River Basin of Wyoming is coal-bed methane, or dry gas, that does not require processing or NGL extraction, in order to be marketable; dry gas is gathered, compressed and delivered into a downstream pipeline or marketed for a fee.

In the Mid-Continent region and the Williston Basin, unprocessed natural gas is compressed and transported through pipelines to processing facilities where volumes are aggregated, treated and processed to remove water vapor, solids and other contaminants, and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. The residue gas, which consists primarily of methane, is compressed and delivered to natural gas pipelines for transportation to end users. When the NGLs are separated from the unprocessed natural gas at the processing plants, the NGLs are generally in the form of a mixed, unfractionated NGL stream. This unfractionated NGL stream is fractionated, through the application of heat and pressure, and separated into NGL products. Our natural gas and NGL products are sold to affiliates and a diverse customer base. Revenues for this segment are derived primarily from POP, fee and keep-whole contracts.

Under a POP contract, we retain a portion of sales proceeds from the commodity sales for our services. With a fee-based contract, we charge a fee for our services, and with the keep-whole contract, we retain the NGLs as our fee for service and return to the producer an equivalent quantity of or payment for residue gas containing the same amount of Btus as the unprocessed natural gas that was delivered to us.

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

	Three Months Ended						Nine Months Ended					Three Months					Nine Months
	September 30,						September 30,					2010 vs. 2009					2010 vs. 2009
Financial Results	2010			2009			2010			2009		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	163.8		$	143.8		$	524.1		$	390.8	$	20.0		14	%	$	133.3		34	%
Residue gas sales		110.5			81.8			347.8			247.8		28.7		35	%		100.0		40	%
Gathering, compression, dehydration and processing fees and other revenue		38.1			37.2			110.8			114.5		0.9		2	%		(3.7	)	(3	%)
Cost of sales and fuel		224.6			173.5			724.8			491.4		51.1		29	%		233.4		47	%
Net margin		87.8			89.3			257.9			261.7		(1.5	)	(2	%)		(3.8	)	(1	%)
Operating costs		34.1			33.6			98.5			99.4		0.5		1	%		(0.9	)	(1	%)
Depreciation and amortization		15.3			15.3			44.9			44.2		-		0	%		0.7		2	%
Gain (loss) on sale of assets		(0.2	)		(0.2	)		(0.4	)		2.8		-		0	%		(3.2	)	*
Operating income	$	38.2		$	40.2		$	114.1		$	120.9	$	(2.0	)	(5	%)	$	(6.8	)	(6	%)

Equity earnings from investments	$	7.4		$	8.4		$	20.7		$	20.6	$	(1.0	)	(12	%)	$	0.1		0	%
Capital expenditures	$	69.3		$	23.2		$	118.3		$	75.6	$	46.1		*		$	42.7		56	%
* Percentage change is greater than 100 percent.

Net margin decreased for the three months ended September 30, 2010, compared with the same period last year, primarily as result of the following:

·	a decrease of $2.4 million due to lower net realized commodity prices;

·	a decrease of $1.5 million due to lower volumes gathered as a result of natural production declines and reduced drilling activity by our customers in the Powder River Basin; and

·	a decrease of $1.2 million due to lower volumes processed and sold in western Oklahoma and Kansas as a result of an operational outage, a period of ethane rejection and natural production declines; offset partially by

·	an increase of $2.2 million due to a favorable contract settlement in the third quarter 2010; and

·	an increase of $1.3 million due to changes in contract terms.

Net margin decreased for the nine months ended September 30, 2010, compared with the same period last year, primarily as result of the following:

·	a decrease of $5.3 million due to lower volumes gathered as a result of natural production declines and reduced drilling activity by our customers in the Powder River Basin; and

·	a decrease of $1.2 million due to changes in contract terms; offset partially by

·	an increase of $3.1 million due to higher net realized commodity prices.

Operating costs increased for the three months ended September 30, 2010, compared with the same period last year, due primarily to higher outside services costs associated with increased operating activities in the Williston Basin as a result of increased drilling activity by our customers.

Operating costs decreased for the nine months ended September 30, 2010, compared with the same period last year, due primarily to a $1.4 million decrease in costs for outside services and maintenance primarily as a result of reduced drilling activity by our customers in the Powder River Basin.

Gain (loss) on sale of assets decreased for the nine months ended September 30, 2010, compared with the same period last year, due to the sale of excess compression equipment in 2009.

Capital expenditures increased for the three and nine months ended September 30, 2010, compared with the same periods last year, due to our recently announced capital projects.

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	2010		2009		2010		2009
Natural gas gathered (BBtu/d) (a)		1,046		1,100		1,075		1,131
Natural gas processed (BBtu/d) (a)		669		664		674		658
NGL sales (MBbl/d) (a)		44		43		44		42
Residue gas sales (BBtu/d) (a)		292		297		286		291
Realized composite NGL net sales price ($/gallon) (b)	$	0.87	$	0.89	$	0.92	$	0.87
Realized condensate net sales price ($/Bbl) (b)	$	65.14	$	86.90	$	63.61	$	76.75
Realized residue gas net sales price ($/MMBtu) (b)	$	5.60	$	3.34	$	5.43	$	3.37
Realized gross processing spread ($/MMBtu) (a)	$	5.67	$	6.54	$	5.97	$	6.41
(a) - Includes volumes for consolidated entities only.
(b) - Presented net of the impact of hedging activities and includes equity volumes only.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Operating Information (a)	2010			2009			2010			2009
Percent of proceeds
NGL sales (Bbl/d)		6,966			5,408			5,933			5,215
Residue gas sales (MMBtu/d)		40,603			46,406			40,852			41,698
Condensate sales (Bbl/d)		1,482			1,488			1,761			1,786
Percentage of total net margin		56	%		50	%		55	%		49	%
Fee-based
Wellhead volumes (MMBtu/d)		1,046,475			1,100,202			1,075,491			1,131,018
Average rate ($/MMBtu)	$	0.31		$	0.31		$	0.31		$	0.30
Percentage of total net margin		35	%		35	%		35	%		36	%
Keep-whole
NGL shrink (MMBtu/d) (b)		13,443			16,843			13,800			17,875
Plant fuel (MMBtu/d) (b)		1,667			1,954			1,639			2,100
Condensate shrink (MMBtu/d) (b)		1,222			1,407			1,531			1,893
Condensate sales (Bbl/d)		247			285			310			383
Percentage of total net margin		9	%		15	%		10	%		15	%
(a) - Includes volumes for consolidated entities only.
(b) - Refers to the Btus that are removed from natural gas through processing operation.

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

	Three Months Ending
	December 31, 2010
	Volumes Hedged	Average Price			Percentage Hedged
NGLs (Bbl/d) (a)	5,267	$	1.05	/ gallon	61%
Condensate (Bbl/d) (a)	1,820	$	1.84	/ gallon	79%
Total (Bbl/d)	7,087	$	1.25	/ gallon	65%
Natural gas (MMBtu/d)	24,020	$	5.55	/ MMBtu	99%
(a) - Hedged with fixed-price swaps.
	Year Ending
	December 31, 2011
	Volumes Hedged	Average Price			Percentage Hedged
NGLs (Bbl/d) (a)	1,316	$	1.04	/ gallon	15%
Condensate (Bbl/d) (a)	596	$	2.12	/ gallon	26%
Total (Bbl/d)	1,912	$	1.37	/ gallon	18%
Natural gas (MMBtu/d)	22,541	$	5.72	/ MMBtu	74%
(a) - Hedged with fixed-price swaps.

Our Natural Gas Gathering and Processing segment’s commodity price risk related to physical sales of commodities is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas, excluding the effects of hedging and assuming normal operating conditions. Our condensate sales are based on the price of crude oil. We estimate the following:

·	a $0.01 per gallon change in the composite price of NGLs would change annual net margin by approximately $1.2 million;

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

·	a $0.10 per MMBtu change in the price of natural gas would change annual net margin by approximately $1.0 million.

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

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

Natural Gas Pipelines

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

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

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

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

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

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

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

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

Our transportation contracts for our regulated natural gas activities are based upon rates stated in our tariffs. Tariffs specify the maximum rates that customers can be charged, which can be discounted to meet competition if necessary, and the general terms and conditions for pipeline transportation service, which are established at FERC or appropriate state jurisdictional agency proceedings, known as rate cases. In Texas and Kansas, natural gas storage service is a fee business that may be regulated by the state in which the facility operates and by the FERC for certain types of services. In Oklahoma, natural gas gathering and natural gas storage operations are also a fee business but are not subject to rate regulation by the OCC and have market-based rate authority from the FERC for certain types of 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					Three Months					Nine Months
	September 30,					September 30,					2010 vs. 2009					2010 vs. 2009
Financial Results	2010		2009			2010		2009			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Transportation revenues	$	60.7	$	58.0		$	184.6	$	168.4		$	2.7		5	%	$	16.2		10	%
Storage revenues		16.9		16.0			51.1		45.3			0.9		6	%		5.8		13	%
Gas sales and other revenues		15.5		24.6			24.9		34.3			(9.1	)	(37	%)		(9.4	)	(27	%)
Cost of sales		18.1		22.7			34.2		39.6			(4.6	)	(20	%)		(5.4	)	(14	%)
Net margin		75.0		75.9			226.4		208.4			(0.9	)	(1	%)		18.0		9	%
Operating costs		24.8		22.9			71.3		67.6			1.9		8	%		3.7		5	%
Depreciation and amortization		11.2		10.6			33.1		34.0			0.6		6	%		(0.9	)	(3	%)
Gain (loss) on sale of assets		-		(0.7	)		0.1		(0.7	)		0.7		100	%		0.8		*
Operating income	$	39.0	$	41.7		$	122.1	$	106.1		$	(2.7	)	(6	%)	$	16.0		15	%

Equity earnings from investments	$	21.3	$	11.0		$	48.9	$	32.8		$	10.3		94	%	$	16.1		49	%
Capital expenditures	$	6.8	$	14.0		$	18.4	$	48.3		$	(7.2	)	(51	%)	$	(29.9	)	(62	%)
* Percentage change is greater than 100 percent.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Operating Information (a)	2010		2009		2010		2009
Natural gas transportation capacity contracted (MDth/d) (b)		5,460		5,712		5,627		5,412
Transportation capacity subscribed		84%		86%		87%		82%
Average natural gas price
Mid-Continent region ($/MMBtu)	$	3.94	$	2.94	$	4.35	$	3.01
(a) - Includes volumes for consolidated entities only.
(b) - Unit of measure converted from MMcf/d in the third quarter 2010. Prior periods have been recast to reflect this change.

Net margin decreased for the three months ended September 30, 2010, compared with the same period last year, primarily as a result of the following:

·	a decrease of $3.2 million from lower operational natural gas inventory sales volumes and margins; offset partially by

·	an increase of $2.3 million from the impact of higher natural gas prices on retained fuel and higher natural gas volumes retained.

Net margin increased for the nine months ended September 30, 2010, compared with the same period last year, primarily as a result of the following:

an increase of $11.3 million from higher natural gas transportation margins, excluding retained fuel, primarily as a result of increased capacity contracted on Midwestern Gas Transmission as a result of a new interconnection with the Rockies Express Pipeline that was placed in service beginning in June 2009; Viking Gas Transmission’s Fargo lateral that was completed in October 2009; and incremental margin from the Guardian Pipeline expansion and extension project that was completed in February 2009;

·	an increase of $5.6 million from the impact of higher natural gas prices on retained fuel, offset partially by lower natural gas volumes retained; and

·	an increase of $3.4 million from higher natural gas storage margins, excluding retained fuel, primarily as a result of contract renegotiations; offset partially by

·	a decrease of $3.3 million from lower operational natural gas inventory sales volumes and margins.

Operating costs increased for the three and nine months ended September 30, 2010, compared with the same period last year, due primarily to increased employee labor costs resulting from the operation of our completed capital projects in 2009 and the timing of various maintenance activities.

Capital expenditures decreased for the three months ended September 30, 2010, compared with the same period last year, due primarily to the new Midwestern Gas Transmission interconnection with the Rockies Express Pipeline that was placed in service beginning in June 2009 and Viking Gas Transmission’s Fargo lateral that was completed in October 2009.

Capital expenditures decreased for the nine months ended September 30, 2010, compared with the same period last year due primarily to the new Midwestern Gas Transmission interconnection with the Rockies Express Pipeline, Viking Gas Transmission’s Fargo lateral and the Guardian Pipeline expansion and extension project.

Natural Gas Liquids

Overview - Our natural gas liquids assets consist of facilities that gather, fractionate and treat NGLs and store NGL products primarily in Oklahoma, Kansas and Texas. We own FERC-regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas, Texas, Wyoming and Colorado, and terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois. We also own FERC-regulated natural gas liquids distribution and refined petroleum products pipelines in Kansas, Missouri, Nebraska, Iowa, Illinois and Indiana that connect our Mid-Continent assets with Midwest markets, including Chicago, Illinois. The majority of the pipeline-connected natural gas processing plants in Oklahoma, Kansas and the Texas panhandle, which extract NGLs from unprocessed natural gas, are connected to our gathering systems.

Most natural gas produced at the wellhead contains a mixture of NGL components, such as ethane, propane, iso-butane, normal butane and natural gasoline. Natural gas processing plants remove the NGLs from the natural gas stream to realize the higher economic value of the NGLs and to meet natural gas pipeline-quality specifications, which limit NGLs in the natural gas stream due to liquid and Btu content. The NGLs that are separated from the natural gas stream at the natural gas processing plants remain in a mixed, unfractionated form until they are gathered, primarily by pipeline, and delivered to fractionators where the NGLs are separated into NGL products. These NGL products are then stored or distributed to our customers, such as petrochemical manufacturers, heating fuel users, refineries and propane distributors. We also purchase NGLs from third parties, as well as from our Natural Gas Gathering and Processing segment.

Net margin for our Natural Gas Liquids segment is derived primarily from exchange services, optimization and marketing, pipeline transportation, isomerization and storage, defined as follows:

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

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

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

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

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

Selected Financial Results and Operating Information - In September 2010, we completed a transaction to sell a 49 percent ownership interest in Overland Pass Pipeline Company to a subsidiary of Williams resulting in each joint-venture member now owning 50 percent of Overland Pass Pipeline Company. Following the transaction in September 2010, we account for our investment under the equity method of accounting.

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					Three Months					Nine Months
	September 30,					September 30,					2010 vs. 2009					2010 vs. 2009
Financial Results	2010		2009			2010		2009			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	1,647.0	$	1,176.7		$	5,067.4	$	3,135.5		$	470.3		40	%	$	1,931.9		62	%
Exchange service and storage revenues		115.6		92.3			332.7		262.7			23.3		25	%		70.0		27	%
Transportation revenues		16.7		20.2			68.8		61.5			(3.5	)	(17	%)		7.3		12	%
Cost of sales and fuel		1,655.5		1,160.3			5,112.6		3,118.3			495.2		43	%		1,994.3		64	%
Net margin		123.8		128.9			356.3		341.4			(5.1	)	(4	%)		14.9		4	%
Operating costs		39.5		49.6			126.2		129.8			(10.1	)	(20	%)		(3.6	)	(3	%)
Depreciation and amortization		17.4		15.9			53.7		43.5			1.5		9	%		10.2		23	%
Gain (loss) on sale of assets		16.3		(0.1	)		15.5		(0.1	)		16.4		*			15.6		*
Operating income	$	83.2	$	63.3		$	191.9	$	168.0		$	19.9		31	%	$	23.9		14	%

Equity earnings from investments	$	0.7	$	0.6		$	1.7	$	2.1		$	0.1		17	%	$	(0.4	)	(19	%)
Allowance for equity funds used
during construction	$	0.2	$	7.1		$	0.7	$	24.3		$	(6.9	)	(97	%)	$	(23.6	)	(97	%)
Capital expenditures	$	27.7	$	131.8		$	65.3	$	366.6		$	(104.1	)	(79	%)	$	(301.3	)	(82	%)
* Percentage change is greater than 100 percent.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Operating Information	2010		2009		2010		2009
NGL sales (MBbl/d) (a)		449		382		443		388
NGLs fractionated (MBbl/d) (a)		500		496		505		458
NGLs transported-gathering lines (MBbl/d) (a)		436		385		452		358
NGLs transported-distribution lines (MBbl/d) (a)		455		446		468		451
Conway-to-Mont Belvieu OPIS average price differential
Ethane ($/gallon)	$	0.10	$	0.15	$	0.11	$	0.12
(a) Includes volumes for consolidated entities only.

Net margin decreased for the three months ended September 30, 2010, compared with the same period last year, primarily as a result of the following:

·	a decrease of $9.9 million related to lower optimization margins due to narrower NGL product price differentials between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers and limited NGL fractionation and transportation capacity available for optimization activities; and

·	a decrease of $1.6 million due to the impact of operational measurement gains and losses, compared with the same period last year; offset partially by

·	an increase of $3.8 million due to increased volumes gathered, fractionated and transported, primarily associated with the completion of the Arbuckle Pipeline and Piceance lateral pipeline, as well as new supply connections; and

·	an increase of $2.5 million due to higher storage margins as a result of contract renegotiations.

Net margin increased for the nine months ended September 30, 2010, compared with the same period last year, primarily as a result of the following:

·	an increase of $49.2 million due to increased volumes gathered, fractionated and transported, primarily associated with the completion of the Arbuckle Pipeline, Piceance lateral pipeline and D-J Basin lateral pipeline, as well as new supply connections; and

·	an increase of $7.4 million due to higher storage margins as a result of contract renegotiations; offset partially by

·	a decrease of $39.5 million related to lower optimization margins due to limited fractionation and transportation capacity available for optimization activities and narrower NGL product price differentials between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers; and

·	a decrease of $2.1 million due to the impact of operational measurement gains and losses, compared with the same period last year.

Additional NGL fractionation capacity, which benefits optimization activities, became available on September 1, 2010, when a contract at our Mont Belvieu, Texas, fractionator expired. Additional capacity also will become available when a 60,000 barrel-per-day fractionation services agreement with Targa Resources Partners begins in the second quarter 2011. The expansion of the Sterling I NGL distribution pipeline, expected to be completed in the second half of 2011, will enable the transportation of additional NGL purity products to the Gulf Coast market.

Operating costs decreased for the three months ended September 30, 2010, compared with the same period last year, due primarily to the following:

·	a decrease of $5.4 million resulting from lower than estimated ad valorem taxes associated with our capital projects completed in 2009; and

·	a decrease of $3.1 million in outside services costs attributable primarily to maintenance projects at our fractionators in 2009.

Operating costs decreased for the nine months ended September 30, 2010, compared with the same period last year, due primarily to the following:

·	a decrease of $6.0 million resulting from lower than estimated ad valorem taxes associated with our capital projects completed in 2009; and

·	a decrease of $2.9 million in outside services costs attributable primarily to maintenance projects at our fractionators in 2009; offset partially by

·	an increase of $2.5 million in property insurance costs related to increased coverage for our assets; and

·	an increase of $1.6 million due primarily to increased employee labor costs resulting from the operation of our completed capital projects in 2009.

Depreciation and amortization increased for the nine months ended September 30, 2010, compared with the same periods last year, due primarily to higher depreciation expense associated with our capital projects completed in 2009.

Gain on sale of assets increased for the three and nine months ended September 30, 2010, compared with the same periods last year, due primarily to the sale of a 49 percent ownership interest in Overland Pass Pipeline Company discussed on page 24.

Allowance for equity funds used during construction and capital expenditures decreased for the three and nine months ended September 30, 2010, compared with the same periods last year, due primarily to the completion of our capital projects in 2009.

Contingencies

Legal Proceedings - We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows. 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 and our newly established commercial paper program, discussed below, for liquidity and capital resource needs on both a short- and long-term basis. We have no guarantees of debt or other similar commitments to unaffiliated parties.

In June 2010, we established a commercial paper program providing for the issuance of up to $1.0 billion of unsecured commercial paper notes to fund our short-term borrowing needs. The maturities of our commercial paper notes vary but may not exceed 270 days from the date of issue. Our commercial paper notes are sold at a negotiated discount from par or bear interest at a negotiated rate. Our Partnership Credit Agreement, which expires in March 2012, is available to repay our commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowings available under our Partnership Credit Agreement.

In the first nine months of 2010, we utilized our Partnership Credit Agreement and our newly established commercial paper program to fund our short-term liquidity needs, and we accessed the public equity markets for our long-term financing needs. See discussion below under “Equity Issuance” for more information.

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 fund our capital expenditures.

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

	September 30,		December 31,
	2010		2009
Long-term debt		46%		51%
Equity		54%		49%

Debt (including notes payable)		49%		55%
Equity		51%		45%

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

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

The total amount of short-term borrowings authorized by our general partner’s Board of Directors is $1.5 billion. At September 30, 2010, we had $326.4 million of commercial paper outstanding and no borrowings outstanding under our Partnership Credit Agreement, leaving approximately $673.6 million of credit available under the Partnership Credit Agreement and approximately $5.0 million of available cash and cash equivalents. As of September 30, 2010, we could have issued $1.0 billion of additional short- and long-term debt under the most restrictive provisions contained in our various borrowing agreements. At September 30, 2010, we had $24.2 million in letters of credit issued outside of our Partnership Credit Agreement.

we repaid all borrowings outstanding under our Partnership Credit Agreement with proceeds from the issuance of commercial paper.

Our Partnership Credit Agreement contains certain financial, operational and legal covenants as discussed in Note H of the Notes to Consolidated Financial Statements in our Annual Report. Among other things, these covenants include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in our Partnership Credit Agreement, adjusted for all non cash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5 to 1. If we consummate one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will increase to 5.5 to 1 for the three calendar quarters following the acquisitions. At September 30, 2010, our ratio of indebtedness to adjusted EBITDA was 3.8 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, asset securitization, and the sale and leaseback of facilities.

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

In June 2010, we repaid $250 million of maturing senior notes with available cash and short-term borrowings. With the repayment of these notes, we no longer have any obligation to offer to repurchase the $225 million senior notes due 2011 in the event that our long-term debt credit ratings fall below investment grade.

The indentures governing our senior notes due 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. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2011, 2012, 2016, 2019, 2036 and 2037 to declare those notes immediately due and payable in full.

We may redeem the notes due 2011, 2012, 2016, 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. The notes due 2011, 2012, 2016, 2019, 2036 and 2037 are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness, and effectively junior to all of the existing and future debt and other liabilities of any non-guarantor subsidiaries. Our long-term debt is nonrecourse to our general partner.

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 $202.8 million and $491.3 million for the nine months ended September 30, 2010 and 2009, respectively. We classify expenditures that are expected to generate additional revenue or significant operating efficiencies as growth capital expenditures. Maintenance capital expenditures are those required to maintain existing operations and do not generate additional revenues.

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

2010 Projected Capital Expenditures	Growth		Maintenance		Total
	(Millions of dollars)
Natural Gas Gathering and Processing	$	240	$	19	$	259
Natural Gas Pipelines		5		22		27
Natural Gas Liquids		149		28		177
Other		-		1		1
Total projected capital expenditures	$	394	$	70	$	464

Credit Ratings - Our long-term debt credit ratings as of September 30, 2010, are shown in the table below:

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

Our recently established commercial paper program is rated Prime-2 by Moody’s and A2 by S&P. Our credit ratings, which are currently investment grade, may be affected by a material change in our financial ratios or a material event affecting our business. The most common criteria for assessment of our credit ratings are the debt-to-EBITDA ratio, interest coverage, business risk profile and liquidity. We do not currently anticipate a downgrade in our credit ratings. However, if our credit ratings were downgraded, the interest rates on our commercial paper borrowings and borrowings under our Partnership Credit Agreement would increase, resulting in an increase in our cost to borrow funds and potentially a loss of access to the commercial paper market. In the event that we are unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we would continue to have access to our Partnership Credit Agreement. An adverse rating change alone is not a default under our Partnership Credit Agreement. See additional discussion about our credit ratings under “Long-term Financing.”

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 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 long-term debt credit ratings.

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,
	2010		2009
	(Millions of dollars)
Common unitholders	$	211.8	$	182.3
Class B unitholders		121.5		118.2
General partner		84.1		69.6
Total cash distributions paid	$	417.4	$	370.1

In the nine months ended September 30, 2010 and 2009, cash distributions paid to our general partner included incentive distributions of $75.8 million and $62.2 million, respectively.

In October 2010, our general partner declared a cash distribution of $1.13 per unit ($4.52 per unit on an annualized basis) for the third quarter of 2010, an increase of $0.01 from the previous quarter, which will be paid on November 12, 2010, to unitholders of record at the close of business on October 29, 2010.

Additional information about our cash distributions is included in “Cash Distribution Policy” under Part II, Item 5, Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities, in our Annual Report.

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

CASH FLOW ANALYSIS

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

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

		Nine Months Ended						Variances
		September 30,						2010 vs. 2009
		2010			2009			Increase (Decrease)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities		$	316.8		$	349.0		$	(32.2	)	(9	%)
Investing activities			229.2			(502.6	)		731.8			*
Financing activities			(544.2	)		6.5			(550.7	)		*
Change in cash and cash equivalents			1.8			(147.1	)		148.9			*
Cash and cash equivalents at beginning of period			3.2			177.6			(174.4	)	(98	%)
Cash and cash equivalents at end of period		$	5.0		$	30.5		$	(25.5	)	(84	%)
* Percentage change is greater than 100 percent.

Operating Cash Flows - Operating cash flows are affected by earnings from our business activities. We provide services to producers and consumers of natural gas, condensate and NGLs. Changes in commodity prices and demand for our services

or products, whether because of general economic conditions, changes in demand for the end products that are made with our products or increased competition from other service providers, could affect our earnings and operating cash flows.

Cash flows from operating activities, before changes in operating assets and liabilities, were $451.4 million for the nine months ended September 30, 2010, compared with $420.4 million for the same period in 2009. The increase was due primarily to changes in net margin and operating expenses discussed in “Consolidated Operations” under Financial Results and Operating Information in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Quarterly Report.

The changes in operating assets and liabilities decreased operating cash flows $134.5 million for the nine months ended September 30, 2010, compared with a decrease of $71.4 million for the same period in 2009, primarily as a result of the following:

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

·	the increase in volumes of commodities in storage primarily in our Natural Gas Liquids segment.

Investing Cash Flows - Cash provided by investing activities increased for the nine months ended September 30, 2010, compared with cash used in investing activities for the same period in 2009, due primarily to the $423.7 million in proceeds received from the Overland Pass Pipeline Company transaction; reduced capital expenditures as a result of the completion of our capital projects in 2009; and reduced contributions to and distributions from unconsolidated affiliates.

Financing Cash Flows - Cash used in financing activities increased for the nine months ended September 30, 2010, compared with cash provided by financing activities for same period in 2009. The increase was due primarily to the following:

Increased cash distributions to our general and limited partners for the nine months ended September 30, 2010, due primarily to additional units outstanding during 2010, as well as cash distributions of $3.33 per unit paid during the first nine months of 2010, compared with cash distributions of $3.24 per unit for the same period last year;

·	Net repayments of notes payable were $196.6 million during the nine months ended September 30, 2010, compared with net repayments of $355.0 million for the same period last year;

·	In June 2010, we repaid $250.0 million of maturing long-term debt with available cash and short-term borrowings.

·	The change in net proceeds generated from common unit offerings for the nine months ended September 30, 2010, compared with the same period last year, due primarily to the following:

–

In February 2010, our common unit offering generated net proceeds of approximately $322.7 million. In addition, ONEOK Partners GP contributed $6.8 million in order to maintain its 2 percent general partner interest in us. We used the proceeds from the sale of common units and the general partner contribution to repay borrowings under our Partnership Credit Agreement and for general partnership purposes;

–

In July 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; and

·	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.

ENVIRONMENTAL AND SAFETY MATTERS

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

Pipeline Safety - We are subject to Pipeline and Hazardous Materials Safety Administration regulations, including integrity management regulations. The Pipeline Safety Improvement Act of 2002 requires pipeline companies to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. We are in compliance with all material requirements associated with the various pipeline safety regulations. Currently, Congress is reauthorizing existing Pipeline Safety legislation, and there are also a number of new bills addressing pipeline safety being considered. We are monitoring activity concerning the reauthorization and proposed new legislation, as well as potential changes in the Pipeline and Hazardous Materials Safety Administration’s regulations, to assess the potential impact on our operations. At this time, no revised or new legislation has been enacted, and potential cost, fees or expenses associated with changes or new legislation are unknown. We cannot provide assurance that existing pipeline safety

regulations will not be revised or interpreted in a different manner or that new regulations will not be adapted that could result in increased compliance costs or additional operating restrictions.

Air and Water Emissions - The Clean Air Act, the Clean Water Act and analogous state laws impose restrictions and controls regarding the discharge of pollutants into the air and water in the United States. Under the Clean Air Act, a federally enforceable operating permit is required for sources of significant air emissions. We may be required to incur certain capital expenditures for air pollution-control equipment in connection with obtaining or maintaining permits and approvals for sources of air emissions. The Clean Water Act imposes substantial potential liability for the removal of pollutants discharged to waters of the United States and remediation of waters affected by such discharge. We are in compliance with all material requirements associated with the various air and water regulations.

The United States Congress is actively considering legislation to reduce greenhouse gas emissions, including carbon dioxide and methane. In addition, other federal, state and regional initiatives to regulate greenhouse gas emissions are under way. We are monitoring federal and state legislation to assess the potential impact on our operations. We estimate our direct greenhouse gas emissions annually as we collect all applicable greenhouse gas emission data for the previous year. Our most recent estimate indicates that our 2009 emissions were less than 3.5 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 EPA’s Mandatory Greenhouse Gas Reporting rule adopted in September 2009. The rule requires greenhouse gas emissions reporting for affected facilities on an annual basis, beginning with our 2010 emissions report that will be due in March 2011, and will require us to track the emission equivalents for all NGLs delivered to our customers. Also, the EPA has recently released a proposed subpart to the Mandatory Greenhouse Gas Reporting Rule that will require the reporting of vented and fugitive emissions of methane from our facilities. The new requirements are proposed to begin in January 2011, with the first reporting of fugitive emissions due March 31, 2012. We do not expect the cost to gather this emission data to have a material impact on our results of operations, financial position or cash flows. At this time, no legislation has been enacted that assesses any costs, fees or expense on any of these emissions.

In May 2010, the EPA finalized the “Tailoring Rule” that will regulate greenhouse gas emissions at new or modified facilities that meet certain criteria. Affected facilities will be required to review best available control technology, conduct air-quality analysis, impact analysis and public reviews with respect to such emissions. The rule will be phased in beginning January 2011 and, at current emission threshold levels, will have a minimal impact on our existing facilities. The EPA has stated it will consider lowering the threshold levels over the next five years, which could increase the impact on our existing facilities. However, potential costs, fees or expenses associated with the potential adjustments are unknown.

Superfund - The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or Superfund, imposes liability, without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of a facility where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the facility. Under CERCLA, these persons may be liable for the costs of cleaning up the hazardous substances released into the environment, damages to natural resources and the costs of certain health studies.

Chemical Site Security - The United States Department of Homeland Security (Homeland Security) released an interim rule in April 2007 that requires companies to provide reports on sites where certain chemicals, including many hydrocarbon products, are stored. We completed the Homeland Security assessments, and our facilities were subsequently assigned, on a preliminary basis, one of four risk-based tiers ranging from high (Tier 1) to low (Tier 4) risk, or not tiered at all due to low risk. To date, four of our facilities have been given a Tier 4 rating. Facilities receiving a Tier 4 rating are required to complete Site Security Plans and possible physical security enhancements. We do not expect the Site Security Plans and possible security enhancement costs to have a material impact on our results of operations, financial position or cash flows.

Pipeline Security - Homeland Security’s Transportation Security Administration, along with the United States Department of Transportation, has completed a review and inspection of our “critical facilities” and identified no material security issues.

Environmental Footprint - Our environmental and climate change strategy focuses on taking steps to minimize the impact of our operations on the environment. These strategies include: (i) developing and maintaining an accurate greenhouse gas emissions inventory, according to new rules issued by the EPA; (ii) improving the efficiency of our various pipelines, natural

gas processing facilities and natural gas liquids fractionation facilities; (iii) following developing technologies for emissions control; (iv) following developing technologies to capture carbon dioxide to keep it from reaching the atmosphere; and (v) analyzing options for future energy investment.

We continue to focus on maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices to limit the release of natural gas during pipeline and facility maintenance and operations. Our most recent calculation of our annual lost-and-unaccounted-for natural gas, for all of our business operations, is less than 1 percent of total throughput.

FORWARD-LOOKING STATEMENTS

Some of the statements contained and incorporated in this Quarterly Report are forward-looking statements within the meaning of Section 27A of the Securities Act, and Section 21E of the Exchange Act. The forward-looking statements relate to our anticipated financial performance, management’s plans and objectives for our future operations, our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this Quarterly Report identified by words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” and other words and terms of similar meaning.

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

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

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

·	the capital intensive nature of our businesses;

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

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

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

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

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

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

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

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

·	changes in demand for the use of natural gas because of market conditions caused by concerns about global warming;

·	conflicts of interest between us, our general partner, ONEOK Partners GP, and related parties of ONEOK Partners GP;

·	the impact of unforeseen changes in interest rates, equity markets, inflation rates, economic recession and other external factors over which we have no control;

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

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

the results of administrative proceedings and litigation, regulatory actions, rule changes and receipt of expected clearances involving the OCC, KCC, Texas regulatory authorities or any other local, state or federal regulatory body, including the FERC and the Pipeline and Hazardous Materials Safety Administration;

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

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

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

·	the impact and outcome of pending and future litigation;

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

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

-	competitive conditions in the overall energy market;

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

-	availability of additional storage capacity;

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

·	the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances;

our ability to acquire all necessary permits, consents and other approvals in a timely manner, to promptly obtain all necessary materials and supplies required for construction, and to construct gathering, processing, storage, fractionation and transportation facilities without labor or contractor problems;

·	the mechanical integrity of facilities operated;

·	demand for our services in the proximity of our facilities;

·	our ability to control operating costs;

·	acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’ or shippers’ facilities;

·	economic climate and growth in the geographic areas in which we do business;

·	the risk of a prolonged slowdown in growth or decline in the U.S. economy or the risk of delay in growth recovery in the U.S. economy, including liquidity risks in U.S. credit markets;

·	the impact of recently issued and future accounting updates and other changes in accounting policies;

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

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

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

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

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

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

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

·	the impact of potential impairment charges;

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

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

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

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

COMMODITY PRICE RISK

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

ITEM 4.

CONTROLS AND PROCEDURES

Quarterly Evaluation of Disclosure Controls and Procedures - The Chief Executive Officer and the Chief Financial Officer of ONEOK Partners GP, our general partner, who are the equivalent of our principal executive and principal financial officers, have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report based on the evaluation of the controls and procedures required by Rule 13a-15(b) of the Exchange Act.

Changes in Internal Control Over Financial Reporting - There have been no changes in our internal control over financial reporting during the third quarter ended September 30, 2010, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

Additional information about our legal proceedings is included under Part I, Item 3, Legal Proceedings, in our Annual Report and our March 31, 2010 Quarterly Report.

ITEM 1A.

RISK FACTORS

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

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Not Applicable.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

Not Applicable.

ITEM 4.

(REMOVED AND RESERVED)

Not Applicable.

ITEM 5.

OTHER INFORMATION

Not Applicable.

ITEM 6.

EXHIBITS

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

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

Exhibit No. Exhibit Description

31.1

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

31.2

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

32.1

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

32.2

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

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema Document.

101.CAL

XBRL Taxonomy Calculation Linkbase Document.

101.DEF

XBRL Taxonomy Extension Definitions Document.

101.LAB

XBRL Taxonomy Label Linkbase Document.

101.PRE

XBRL Taxonomy Presentation Linkbase Document.

Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in XBRL: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three and nine months ended September 30, 2010 and 2009; (iii) Consolidated Balance Sheets at September 30, 2010, and December 31, 2009; (iv) Consolidated Statements of Cash Flows for the nine months ended September 30, 2010 and 2009; (v) Consolidated Statement of Changes in Equity for the nine months ended September 30, 2010; (vi) Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2010 and 2009; and (vii) Notes to Consolidated Financial Statements.

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

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

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 3, 2010 By: /s/ Curtis L. Dinan

Curtis L. Dinan

Senior Vice President,

Chief Financial Officer and Treasurer

(Signing on behalf of the Registrant

and as Principal Financial Officer)