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, 2011

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

For the transition period from __________ to __________.

Commission file number 1-12202

ONEOK PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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 27, 2011
Common units		130,827,354 units
Class B units		72,988,252 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, 2011 and 2010	5

	Consolidated Balance Sheets - September 30, 2011, and December 31, 2010	6

	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2011 and 2010	7

	Consolidated Statement of Changes in Equity - Nine Months Ended September 30, 2011	8-9

	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2011 and 2010	10

	Notes to Consolidated Financial Statements	11-28

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29-48

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48-49

Item 4.	Controls and Procedures	49

Part II.	Other Information

Item 1.	Legal Proceedings	49

Item 1A.	Risk Factors	49

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49

Item 3.	Defaults Upon Senior Securities	49

Item 4.	(Removed and Reserved)	49

Item 5.	Other Information	49

Item 6.	Exhibits	49-50

Signature		51

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

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

INFORMATION AVAILABLE ON OUR WEBSITE

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

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

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GLOSSARY

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

AFUDC

Allowance for funds used during construction

Annual Report

Annual Report on Form 10-K for the year ended December 31, 2010

ASU

Accounting Standards Update

Bbl

Barrels, one barrel is equivalent to 42 United States gallons

Bbl/d

Barrels per day

BBtu/d

Billion British thermal units per day

Bcf

Billion cubic feet

Btu(s)

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

temperature of one pound of water one degree Fahrenheit

Bushton Plant

Bushton Gas Processing Plant

CFTC

Commodities Futures Trading Commission

Clean Air Act

Federal Clean Air Act, as amended

Clean Water Act

Federal Water Pollution Control Act Amendments of 1972, as amended

Dodd-Frank Act

Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010

EBITDA

Earnings before interest, taxes, depreciation and amortization

EPA

United States Environmental Protection Agency

Exchange Act

Securities Exchange Act of 1934, as amended

FASB

Financial Accounting Standards Board

FERC

Federal Energy Regulatory Commission

GAAP

Accounting principles generally accepted in the United States of America

Guardian Pipeline

Guardian Pipeline, L.L.C.

Intermediate Partnership

ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary

of ONEOK Partners, L.P.

LIBOR

London Interbank Offered Rate

MBbl

Thousand barrels

MBbl/d

Thousand barrels per day

MDth/d

Thousand dekatherms per day

Midwestern Gas Transmission

Midwestern Gas Transmission Company

MMBbl

Million barrels

MMBtu

Million British thermal units

MMBtu/d

Million British thermal units per day

MMcf/d

Million cubic feet per day

Moody’s

Moody’s Investors Service, Inc.

NBP Services

NBP Services, LLC, a wholly owned subsidiary of ONEOK

NGL products

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

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

NGL(s)

Natural gas liquid(s)

Northern Border Pipeline

Northern Border Pipeline Company

NYMEX

New York Mercantile Exchange

OBPI

ONEOK Bushton Processing, L.L.C., formerly 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

Partnership 2011 Credit Agreement

The Partnership’s five-year, $1.2 billion Revolving Credit Agreement dated

August 1, 2011

POP

Percent of proceeds

Quarterly Report(s)

Quarterly Report(s) on Form 10-Q

S&P

Standard & Poor’s Financial Services LLC

SEC

Securities and Exchange Commission

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)		2011			2010			2011			2010
	(Thousands of dollars, except per unit amounts)

Revenues		$	2,903,576		$	2,070,144		$	8,187,405		$	6,329,271
Cost of sales and fuel			2,509,570			1,784,139			7,104,305			5,493,979
Net margin			394,006			286,005			1,083,100			835,292
Operating expenses
Operations and maintenance			96,211			90,670			291,346			263,212
Depreciation and amortization			45,221			43,823			131,665			131,680
General taxes			10,095			7,127			37,284			28,851
Total operating expenses			151,527			141,620			460,295			423,743
Gain (loss) on sale of assets			(69	)		16,126			(791	)		15,081
Operating income			242,410			160,511			622,014			426,630
Equity earnings from investments (Note H)			32,029			29,390			93,665			71,182
Allowance for equity funds used during construction			759			266			1,625			748
Other income			82			3,623			960			2,282
Other expense			(7,167	)		(600	)		(6,249	)		(1,341	)
Interest expense			(55,735	)		(49,131	)		(170,626	)		(156,613	)
Income before income taxes			212,378			144,059			541,389			342,888
Income taxes			(2,554	)		(2,362	)		(9,253	)		(12,022	)
Net income			209,824			141,697			532,136			330,866
Less: Net income attributable to noncontrolling interests			138			161			416			446
Net income attributable to ONEOK Partners, L.P.		$	209,686		$	141,536		$	531,720		$	330,420

Limited partners' interest in net income:
Net income attributable to ONEOK Partners, L.P.		$	209,686		$	141,536		$	531,720		$	330,420
General partner's interest in net income			(37,731	)		(30,498	)		(105,376	)		(86,674	)
Limited partners' interest in net income		$	171,955		$	111,038		$	426,344		$	243,746

Limited partners' net income per unit, basic and diluted (Note G)		$	0.84		$	0.54		$	2.09		$	1.20

Number of units used in computation (thousands)			203,816			203,816			203,816			202,374
See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
		September 30,			December 31,
(Unaudited)		2011			2010
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents		$	127,882		$	898
Accounts receivable, net			897,736			815,141
Affiliate receivables			5,760			5,161
Gas and natural gas liquids in storage			243,189			317,159
Commodity imbalances			105,387			92,353
Other current assets			104,123			48,060
Total current assets			1,484,077			1,278,772

Property, plant and equipment
Property, plant and equipment			6,554,177			5,857,000
Accumulated depreciation and amortization			1,220,134			1,099,548
Net property, plant and equipment			5,334,043			4,757,452

Investments and other assets
Investments in unconsolidated affiliates (Note H)			1,224,397			1,188,124
Goodwill and intangible assets			655,454			661,204
Other assets			77,582			34,548
Total investments and other assets			1,957,433			1,883,876
Total assets		$	8,775,553		$	7,920,100

Liabilities and partners' equity
Current liabilities
Current maturities of long-term debt		$	361,931		$	236,931
Notes payable (Note D)			-			429,855
Accounts payable			971,437			852,330
Affiliate payables			36,478			29,765
Commodity imbalances			237,080			291,110
Other current liabilities			225,987			134,151
Total current liabilities			1,832,913			1,974,142

Long-term debt, excluding current maturities (Note E)			3,517,543			2,581,572

Deferred credits and other liabilities			95,358			87,393

Commitments and contingencies (Note J)

Equity (Note F)
ONEOK Partners, L.P. partners’ equity:
General partner			101,188			94,691
Common units: 130,827,354 units issued and outstanding at
September 30, 2011, and December 31, 2010			1,872,856			1,825,521
Class B units: 72,988,252 units issued and outstanding at
September 30, 2011, and December 31, 2010			1,377,811			1,345,322
Accumulated other comprehensive income (loss)			(27,365	)		6,283
Total ONEOK Partners, L.P. partners' equity			3,324,490			3,271,817

Noncontrolling interests in consolidated subsidiaries			5,249			5,176

Total equity			3,329,739			3,276,993
Total liabilities and equity		$	8,775,553		$	7,920,100
See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS	Nine Months Ended
	September 30,
(Unaudited)	2011			2010
	(Thousands of dollars)
Operating activities
Net income	$	532,136		$	330,866
Depreciation and amortization		131,665			131,680
Allowance for equity funds used during construction		(1,625	)		(748	)
Loss (gain) on sale of assets		791			(15,081	)
Deferred income taxes		4,999			5,969
Equity earnings from investments		(93,665	)		(71,182	)
Distributions received from unconsolidated affiliates		87,151			69,889
Changes in assets and liabilities:
Accounts receivable		(82,595	)		48,067
Affiliate receivables		(599	)		4,287
Gas and natural gas liquids in storage		73,970			(46,393	)
Accounts payable		91,974			(78,921	)
Affiliate payables		6,713			(731	)
Commodity imbalances, net		(67,064	)		(66,921	)
Other assets and liabilities		(28,549	)		6,075
Cash provided by operating activities		655,302			316,856

Investing activities
Capital expenditures (less allowance for equity funds used during construction)		(662,386	)		(202,773	)
Contributions to unconsolidated affiliates		(51,686	)		(1,313	)
Distributions received from unconsolidated affiliates		16,158			9,342
Proceeds from sale of assets		758			423,975
Cash provided by (used in) investing activities		(697,156	)		229,231

Financing activities
Cash distributions:
General and limited partners		(451,480	)		(417,446	)
Noncontrolling interests		(343	)		(760	)
Borrowing (repayment) of notes payable, net		(429,855	)		(196,615	)
Issuance of long-term debt, net of discounts		1,295,450			-
Long-term debt financing costs		(10,986	)		-
Repayment of long-term debt		(233,948	)		(258,947	)
Issuance of common units, net of discounts		-			322,701
Contribution from general partner		-			6,820
Cash provided by (used in) financing activities		168,838			(544,247	)
Change in cash and cash equivalents		126,984			1,840
Cash and cash equivalents at beginning of period		898			3,151
Cash and cash equivalents at end of period	$	127,882		$	4,991
See accompanying Notes to Consolidated Financial Statements.

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


	ONEOK Partners, L.P. Partners' Equity


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

December 31, 2010		130,827,354		72,988,252	$	94,691		$	1,825,521
Net income		-		-		105,376			273,666
Other comprehensive loss		-		-		-			-
Distributions paid (Note F)		-		-		(98,879	)		(226,331	)
Other		-		-		-			-
September 30, 2011		130,827,354		72,988,252	$	101,188		$	1,872,856
See accompanying Notes to Consolidated Financial Statements.

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

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

December 31, 2010	$	1,345,322		$	6,283		$	5,176			$	3,276,993
Net income		152,678			-			416				532,136
Other comprehensive loss		-			(33,648	)		-				(33,648	)
Distributions paid (Note F)		(126,270	)		-			(343	)			(451,823	)
Other		6,081			-			-				6,081
September 30, 2011	$	1,377,811		$	(27,365	)	$	5,249			$	3,329,739

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Unaudited)	2011			2010			2011			2010
	(Thousands of dollars)

Net income	$	209,824		$	141,697		$	532,136		$	330,866
Other comprehensive income (loss)
Unrealized gains (losses) on derivatives		(27,460	)		2,955			(38,118	)		39,204
Less: Realized gains (losses) on derivatives
recognized in net income		(604	)		4,007			(4,470	)		289
Total other comprehensive income (loss)		(26,856	)		(1,052	)		(33,648	)		38,915
Comprehensive income		182,968			140,645			498,488			369,781
Less: Comprehensive income attributable to noncontrolling interests		138			161			416			446
Comprehensive income attributable to ONEOK Partners, L.P.	$	182,830		$	140,484		$	498,072		$	369,335
See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

A. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our accompanying unaudited consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. These statements have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair presentation of the results for the interim periods presented. All such adjustments are of a normal recurring nature. The 2010 year-end consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements in our Annual Report. Our significant 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, 2011, 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 - In January 2010, the FASB issued ASU 2010-06, “Improving Disclosures about Fair Value Measurements,” which requires separate disclosure of purchases, sales, issuances and settlements in the reconciliation of our Level 3 fair value measurements. We adopted this guidance with our March 31, 2011, Quarterly Report, and the impact was not material. Other provisions of ASU 2010-06 were adopted in 2010.

In May 2011, the FASB issued ASU 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRS),” which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and IFRS. This new guidance changes some fair value measurement principles and disclosure requirements. We are evaluating the impact of this guidance, which will be adopted beginning with our March 31, 2012, Quarterly Report.

In June 2011, the FASB issued ASU 2011-05, “Comprehensive Income,” which provides two options for presenting items of net income, comprehensive income and total comprehensive income, by either creating one continuous statement of comprehensive income or two separate consecutive statements and requires certain other disclosures. We are evaluating the impact of this guidance, which will be adopted beginning with our March 31, 2012, Quarterly Report.

In September 2011, the FASB issued ASU 2011-08, “Testing Goodwill for Impairment,” which permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Under the amendments in this update, an entity is not required to calculate the fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. An entity has the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. An entity may also resume performing the qualitative assessment in any subsequent period. We are evaluating the impact of this guidance, which will be adopted beginning with our July 1, 2012, goodwill impairment test.

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, historical correlations of NGL product prices to crude oil prices and implied forward LIBOR curves. We validate our valuation inputs with third-party information and settlement prices from other sources, where available. In addition, as prescribed by the income approach, we compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets and liabilities to present value using the interest-rate yields to calculate present-value discount factors derived from LIBOR, Eurodollar futures and interest-rate swaps. Finally, we consider the credit risk of our counterparties with whom our derivative assets and liabilities are executed. Although we use our best estimates to determine the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ from our estimates, and the differences could be significant.

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

	September 30, 2011

	Level 1		Level 2			Level 3			Total - Gross			Netting (a)			Total - Net (b)
	(Thousands of dollars)
Derivatives - commodity
Assets	$	-	$	45,000		$	6,097		$	51,097		$	(6,740	)	$	44,357
Liabilities	$	-	$	(1,092	)	$	(5,648	)	$	(6,740	)	$	6,740		$	-
Derivatives - interest rate
Liabilities	$	-	$	(67,048	)	$	-		$	(67,048	)	$	-		$	(67,048	)

	December 31, 2010

	Level 1		Level 2			Level 3			Total - Gross			Netting (a)			Total - Net (b)
	(Thousands of dollars)
Derivatives - commodity
Assets	$	-	$	15,305		$	2,311		$	17,616		$	(6,516	)	$	11,100
Liabilities	$	-	$	(5,361	)	$	(1,155	)	$	(6,516	)	$	6,516		$	-

(a) -	Our derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis. We net derivative assets and
	liabilities when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us.
(b) -	Included in other current assets, other assets or other current liabilities in our Consolidated Balance Sheets.

At September 30, 2011, and December 31, 2010, we had no cash collateral held or posted under our master-netting arrangements.

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

Our derivative instruments categorized as Level 2 include non-exchange-traded fixed-price swaps for natural gas and condensate that are valued based on NYMEX-settled prices for natural gas and crude oil, respectively. Also, included in Level 2 are our interest-rate swaps that are valued using financial models that incorporate the implied forward LIBOR yield curve for the same period as the future interest-rate swap settlements.

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

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Derivative Assets (Liabilities)	2011			2010			2011			2010
	(Thousands of dollars)
Net assets (liabilities) at beginning of period	$	(9,091	)	$	6,244		$	1,156		$	(13,052	)
Total realized/unrealized gains (losses):
Included in earnings (a)		1,246			(1,621	)		133			(2,680	)
Included in other comprehensive income (loss)		8,294			(5,830	)		(840	)		14,525
Net assets (liabilities) at end of period	$	449		$	(1,207	)	$	449		$	(1,207	)

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)	$	1,230		$	(1,446	)	$	1,230		$	(2,680	)
(a) - Included in revenues in our Consolidated Statements of Income.

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

The estimated fair value of the aggregate of our senior notes outstanding, including current maturities, was $4.4 billion and $3.1 billion at September 30, 2011, and December 31, 2010, respectively. The book value of the aggregate of our senior notes outstanding, including current maturities, was $3.9 billion and $2.8 billion at September 30, 2011, and December 31, 2010, respectively. The estimated fair value of the aggregate of our senior notes outstanding was determined using quoted market prices for our senior notes or similar issues with similar terms and maturities.

C. RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

Risk Management Activities - We are sensitive to changes in natural gas, crude oil and NGL prices, principally as a result of contractual terms under which these commodities are processed, purchased and sold. We use physical forward sales and financial derivatives to secure a certain price for a portion of our 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 fluctuations in the normal course of business.

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

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

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

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

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

In our Natural Gas Pipelines segment, we are exposed to commodity price risk because our intrastate and interstate natural gas pipelines retain natural gas from our customers for operations or as part of our fee for services provided. When the amount of natural gas consumed in operations by these pipelines differs from the amount provided by our customers, our pipelines must buy or sell natural gas, or store or use natural gas from inventory, which can expose us to commodity price risk depending on the regulatory treatment for this activity. We use physical forward sales or purchases to reduce the impact of price fluctuations related to natural gas. At September 30, 2011, and December 31, 2010, there were no financial derivative instruments with respect to our natural gas pipeline operations.

In our Natural Gas Liquids segment, we are exposed to basis risk primarily as a result of the relative value of NGL purchases at one location and sales at another location. To a lesser extent, we are exposed to commodity price risk resulting from the relative values of the various NGL products to each other, NGLs in storage and the relative value of NGLs to natural gas. We utilize physical forward contracts to reduce the impact of price fluctuations related to NGLs. At September 30, 2011, and December 31, 2010, 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 interest payments at some future point based on specified notional amounts.

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At September 30, 2011, we had forward-starting interest-rate swaps that have been designated as cash flow hedges of the variability of interest payments on a portion of a forecasted debt issuance that may result from changes in the benchmark interest rate before the debt is issued. At December 30, 2010, we did not have any interest-rate swap agreements.

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

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

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

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

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

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

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, 2011					December 31, 2010
	Assets (a)		(Liabilities) (a)			Assets (b)		(Liabilities) (b)
	(Thousands of dollars)
Derivatives designated as hedging instruments
Commodity contracts - financial	$	48,352	$	(5,024	)	$	13,782	$	(3,556	)
Interest-rate contracts		-		(67,048	)		-		-
Total derivatives designated as hedging instruments		48,352		(72,072	)		13,782		(3,556	)

Commodity derivatives not designated as hedging instruments
Financial		1,515		(1,716	)		2,218		(2,960	)
Physical		1,230		-			1,616		-
Total derivatives not designated as hedging instruments		2,745		(1,716	)		3,834		(2,960	)
Total derivatives	$	51,097	$	(73,788	)	$	17,616	$	(6,516	)
(a) - Included on a net basis in other current assets, other assets and other current liabilities on our Consolidated Balance Sheets.
(b) - Included on a net basis in other current assets on our Consolidated Balance Sheets.

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

				September 30, 2011			December 31, 2010

			Contract Type		Purchased/ Payor	Sold/ Receiver	Purchased/ Payor	Sold/ Receiver

Derivatives designated as hedging instruments:
	Cash flow hedges
	Fixed price
		- Natural gas (Bcf)	Swaps		-	(11.5)	-	(8.2)
		- Crude oil and NGLs (MMBbl)	Swaps		-	(3.6)	-	(1.5)
	Basis
		- Natural gas (Bcf)	Swaps		-	(11.5)	-	(8.2)
	Interest-rate contracts (Millions of dollars)		Forward-starting swaps	$	750.0	-	-	-

Derivatives not designated as hedging instruments:
	Fixed price
		- Natural gas (Bcf)	Swaps		0.7	(0.7)	2.6	(2.6)
		- Crude oil and NGLs (MMBbl)	Forwards and swaps		0.1	(0.1)	0.6	(0.6)
	Basis
		- Natural gas (Bcf)	Swaps		0.7	(0.7)	2.6	(2.6)

Cash Flow Hedges - At September 30, 2011, our Consolidated Balance Sheet reflected a net unrealized loss of $23.8 million in accumulated other comprehensive income (loss), with a corresponding offset in derivative financial instrument assets and liabilities. The portion of accumulated other comprehensive income (loss) attributable to our commodity derivative financial instruments is a gain of $43.2 million, which will be realized within the next 27 months as the forecasted transactions affect earnings. If commodity prices remain at the current levels, we will recognize $26.6 million in gains over the next 12 months, and we will recognize $16.6 million in gains thereafter. The amounts deferred in accumulated other comprehensive income (loss) attributable to our interest-rate swaps will be amortized to interest expense over the life of long-term, fixed-rate debt upon issuance of the debt.

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	September 30,					September 30,
Hedging Relationships	2011			2010		2011			2010
	(Thousands of dollars)
Commodity contracts	$	39,588		$	2,955	$	28,930		$	39,204
Interest-rate contracts		(67,048	)		-		(67,048	)		-
Total gain recognized in other comprehensive income (loss) (effective portion)	$	(27,460	)	$	2,955	$	(38,118	)	$	39,204

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)	2011			2010			2011			2010
		(Thousands of dollars)
Commodity contracts	Revenues	$	(514	)	$	4,214		$	(4,082	)	$	54
Interest-rate contracts	Interest expense		(90	)		(207	)		(388	)		235
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income (effective portion)		$	(604	)	$	4,007		$	(4,470	)	$	289

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Ineffectiveness related to our cash flow hedges was not material for the three and nine months ended September 30, 2011 and 2010. In the event that it becomes probable that a forecasted transaction will not occur, we would discontinue cash flow hedge treatment, which would affect earnings. There were no gains or losses due to the discontinuance of cash flow hedge treatment during the three and nine months ended September 30, 2011 and 2010.

Credit Risk - All of our commodity derivative financial contracts are with our affiliate, ONEOK Energy Services Company, L.P. (OES), a subsidiary of ONEOK, and our interest-rate derivatives are with investment-grade financial institutions. OES has entered into similar commodity derivative financial contracts with third parties at our direction and on our behalf. We have an indemnification agreement with OES that indemnifies and holds OES harmless from any liability it may incur solely as a result of its entering into commodity derivative financial contracts on our behalf. Derivative assets for which we would indemnify OES in the event of a default by the counterparty totaled $43.1 million and $9.5 million at September 30, 2011, and December 31, 2010, respectively, and were with investment-grade counterparties that are primarily in the oil and gas and financial services sectors.

D. CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

Partnership 2011 Credit Agreement - On August 1, 2011, we entered into the five-year, $1.2 billion Partnership 2011 Credit Agreement, which replaced the $1.0 billion Partnership Credit Agreement that was due to expire March 2012. Our Partnership 2011 Credit Agreement, which is scheduled to expire in August 2016, contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in our Partnership 2011 Credit Agreement, adjusted for all noncash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5.0 to 1. If we consummate one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will increase to 5.5 to 1 for the three calendar quarters following the acquisitions. Upon breach of certain covenants by us in our Partnership 2011 Credit Agreement, amounts outstanding under our Partnership 2011 Credit Agreement, if any, may become due and payable immediately.

Our Partnership 2011 Credit Agreement includes a $100-million sublimit for the issuance of standby letters of credit and also features an option to request an increase in the size of the facility to an aggregate of $1.7 billion by either commitments from new lenders or increased commitments from existing lenders.

Our Partnership 2011 Credit Agreement is available to repay our commercial paper notes, if necessary. Amounts outstanding under our commercial paper program reduce the borrowing capacity under our Partnership 2011 Credit Agreement. The Partnership 2011 Credit Agreement contains provisions for an applicable margin rate and an annual facility fee, both of which adjust with changes in our credit rating. Borrowings, if any, will accrue at LIBOR plus 130 basis points, and the annual facility fee is 20 basis points based on our current credit rating. Our Partnership 2011 Credit Agreement is guaranteed fully and unconditionally by the Intermediate Partnership. Borrowings under our Partnership 2011 Credit Agreement are nonrecourse to our general partner.

At September 30, 2011, our ratio of indebtedness to adjusted EBITDA was 3.4 to 1, and we were in compliance with all covenants under our Partnership 2011 Credit Agreement.

A portion of the proceeds from our January 2011 debt issuance, discussed in Note E, was used to repay the outstanding balance of our commercial paper. At September 30, 2011, we had no commercial paper outstanding, no letters of credit issued and no borrowings under our Partnership 2011 Credit Agreement. In October 2011, we increased the size of our commercial paper program to $1.2 billion.

E. LONG-TERM DEBT

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

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

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

We intend to repay our $350 million of 5.9-percent senior notes that mature in April 2012 with a combination of cash on hand and short-term borrowings.

F. EQUITY

Partnership Agreement - Under our Partnership Agreement, available cash generally will be distributed to our general partner and limited partners according to their partnership percentages of 2 percent and 98 percent, respectively. Our general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met during the quarter. On July 12, 2011, the Partnership Agreement was amended to adjust the formula for distributing available cash among our general partner and limited partners to reflect the two-for-one unit split described below. Under the incentive distribution provisions, as set forth in our Partnership Agreement, our general partner receives:

·	15 percent of amounts distributed in excess of $0.3025 per unit;

·	25 percent of amounts distributed in excess of $0.3575 per unit; and

·	50 percent of amounts distributed in excess of $0.4675 per unit.

ONEOK - ONEOK and its subsidiaries owned all of the Class B units, 11.8 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, 2011.

Cash Distributions - Cash distributions paid to our general partner of $98.9 million and $84.1 million in the nine months ended September 30, 2011 and 2010, respectively, included incentive distributions of $89.8 million and $75.8 million, respectively.

In October 2011, our general partner declared a cash distribution of $0.595 per unit ($2.38 per unit on an annualized basis) for the third quarter of 2011, an increase of 1 cent from the previous quarter, which will be paid on November 14, 2011, to unitholders of record at the close of business on November 7, 2011.

G. LIMITED PARTNERS’ NET INCOME PER UNIT

Limited partners’ net income per unit is computed by dividing net income attributable to ONEOK Partners, L.P., after deducting the general partner’s allocation as discussed below, by the weighted-average number of outstanding limited partner units, which includes our common and Class B limited partner units. Because ONEOK has conditionally waived its right to increased quarterly distributions, until it gives 90 days notice of the withdrawal of the waiver, currently each Class B unit and common unit share equally in the earnings of the partnership, and neither has any liquidation or other preferences. As a result of our two-for-one unit split, we have adjusted the computation of limited partners’ net income per unit in our Consolidated Statements of Income to present the amounts on a post-split basis for all periods presented.

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 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 $33.5 million and $27.7 million for the three months ended September 30, 2011 and 2010, respectively, and $94.7 million and $80.1 million for the nine months ended September 30, 2011 and 2010, respectively.

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The terms of our Partnership Agreement limit the general partner’s incentive distribution to the amount of available cash calculated for the period. As such, incentive distribution rights are not allocated on undistributed earnings or distributions in excess of earnings. For additional information regarding our general partner’s incentive distribution rights, see “Partnership Agreement” in Note H of the Notes to Consolidated Financial Statements in our Annual Report.

H. UNCONSOLIDATED AFFILIATES

Northern Border Pipeline - In July 2011, the partners of Northern Border Pipeline made equity contributions of approximately $99.6 million, with our share totaling approximately $49.8 million. We do not anticipate additional significant equity contributions in 2011.

Overland Pass Pipeline Company - The members of Overland Pass Pipeline Company expect to make contributions primarily in 2012 totaling approximately $70 million to $80 million, with our share expected to be approximately $35 million to $40 million, to install additional pump stations and to expand existing pump stations.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
	(Thousands of dollars)
Northern Border Pipeline	$	19,723	$	21,183	$	56,970	$	48,401
Overland Pass Pipeline Company (a)		4,338		1,011		14,074		1,011
Fort Union Gas Gathering, L.L.C.		3,444		3,633		10,120		10,772
Bighorn Gas Gathering, L.L.C.		1,389		1,664		4,727		3,712
Other		3,135		1,899		7,774		7,286
Equity earnings from investments	$	32,029	$	29,390	$	93,665	$	71,182
(a) - Beginning in September 2010, following the sale of a 49-percent interest, Overland Pass Pipeline Company was deconsolidated and prospectively accounted for under the equity method.

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,
	2011		2010		2011		2010
	(Thousands of dollars)
Income Statement (a)
Operating revenues	$	124,955	$	119,205	$	369,258	$	316,513
Operating expenses	$	55,899	$	48,566	$	162,123	$	138,177
Net income	$	65,368	$	63,588	$	187,777	$	156,454

Distributions paid to us (a)	$	32,257	$	29,587	$	103,309	$	79,231
(a) - Financial information for 2011 is not directly comparable with 2010 due to the deconsolidation of Overland Pass Pipeline Company in September 2010.

I. RELATED-PARTY TRANSACTIONS

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

Previously, we had a Processing and Services Agreement with ONEOK and OBPI, under which we contracted for all of OBPI’s rights, including all of the capacity of the Bushton Plant, reimbursing OBPI for all costs associated with the operation and maintenance of the Bushton Plant and its obligations under equipment leases covering portions of the Bushton Plant. In April 2011, pursuant to our rights under the Processing and Services Agreement, we directed OBPI to give notice of intent to exercise the purchase option for the leased equipment pursuant to the terms of the equipment leases. On June 30, 2011, we

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acquired OBPI and OBPI closed the purchase option and terminated the equipment lease agreements. The total amount paid by us to complete the transactions was approximately $94.2 million, which included the reimbursement to ONEOK of obligations related to the Processing and Services Agreement.

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

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

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

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
		2011		2010		2011		2010
	(Thousands of dollars)
Revenues		$	111,177	$	117,985	$	306,669	$	363,004

Expenses
Cost of sales and fuel		$	13,942	$	12,402	$	37,113	$	41,377
Administrative and general expenses			62,306		47,703		175,815		150,702
Total expenses		$	76,248	$	60,105	$	212,928	$	192,079

Cash Distributions to ONEOK - We paid cash distributions to ONEOK and its subsidiaries related to its general and limited partner interests of $84.3 million and $77.0 million during the three months ended September 30, 2011 and 2010, respectively, and $245.6 million and $225.3 million during the nine months ended September 30, 2011 and 2010, respectively.

J. COMMITMENTS AND CONTINGENCIES

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

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Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, 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, 2011 and 2010.

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

In addition, the EPA has issued a rule on air-quality standards, “National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines,” also known as RICE NESHAP, scheduled to be adopted in 2013. The rule will require capital expenditures over the next two 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.

On July 28, 2011, the EPA issued a proposed rule package that would change the air emission New Source Performance Standards and Maximum Achievable Control Technology requirements applicable to natural gas production, processing, transmission and underground storage. The proposed rules would impact emission limits for specific equipment through the use of controls; however, potential costs associated with the proposed rules are currently unknown.

Pipeline Safety - We are subject to Pipeline and Hazardous Materials Safety Administration regulations, including integrity- management regulations. The Pipeline Safety Improvement Act of 2002 requires pipeline companies operating high-pressure pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. In January 2011, the Pipeline and Hazardous Materials Safety Administration issued an “Advisory Bulletin” regarding maximum allowable operating pressures for natural gas and hazardous liquids pipelines. This bulletin requests that all operators review pipeline records and data to validate existing maximum pressure determinations. Currently, the United States Congress (Congress) is considering reauthorization of existing pipeline safety legislation. The Pipeline Transportation Safety Improvement Act of 2011 was passed by the United States Senate (Senate) in late October. The United States House of Representatives’ (House) Energy and Commerce Committee and the House Transportation and Infrastructure Committee have passed similar bills that will be combined to form the House’s version to present at conference with the Senate.

We are monitoring activity concerning reauthorization, proposed new legislation and potential changes in the Pipeline and Hazardous Materials Safety Administration’s regulations to assess the potential impact on our operations. At this time, our review of records relating to maximum pressure determinations is ongoing, and no revised or new legislation has been enacted resulting in any potential cost, fees or expenses associated with these issues. We cannot provide assurance that existing pipeline safety regulations will not be revised or interpreted in a different manner or that new regulations will not be adopted that could result in increased compliance costs or additional operating restrictions.

If a release of natural gas or natural gas liquids occurs as a result of failure or abnormal operating conditions from pipelines or facilities that we own, operate or otherwise use, we could be held liable for all resulting liabilities, including personal injury and property damage, as well as response, investigation and cleanup costs, which could affect materially our results of operations and cash flows.

Financial Markets Legislation - The Dodd-Frank Act represents a far-reaching overhaul of the framework for regulation of United States financial markets. Various regulatory agencies, including the SEC and the CFTC, have proposed regulations for implementation of many of the provisions of the Dodd-Frank Act. Although the CFTC has issued final regulations for certain provisions of the Dodd-Frank Act, the majority remain outstanding. Because the CFTC did not complete its rulemaking process by the Act’s deadline of July 16, 2011, it has deferred the effective date of the provisions of the Dodd-Frank Act that require a rulemaking and is proposing a further extension. Until certain final regulations are established, we are unable to ascertain how we may be affected. Based on our assessment of the proposed regulations issued to date, we expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest-rate risks; however, the costs of doing so may increase as a result of the new legislation. We also may incur additional costs associated with our compliance with the new regulations and anticipated additional recordkeeping, reporting and disclosure obligations.

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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 reasonably possible losses of such matters, individually and in the aggregate, are not material. Additionally, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or liquidity.

K. SEGMENTS

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

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

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

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

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

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

For the three months ended September 30, 2011 and 2010, and the nine months ended September 30, 2010, we had no customers from which we received 10 percent or more of our consolidated revenues. For the nine months ended September 30, 2011, our Natural Gas Liquids segment had one customer from which we received 11 percent of our consolidated revenues.

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

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

Three Months Ended September 30, 2011	Natural Gas Gathering and Processing			Natural Gas Pipelines (a)			Natural Gas Liquids (b)		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	102,828		$	60,835		$	2,628,736	$	-		$	2,792,399
Sales to affiliated customers		83,151			28,026			-		-			111,177
Intersegment revenues		229,234			651			10,027		(239,912	)		-
Total revenues	$	415,213		$	89,512		$	2,638,763	$	(239,912	)	$	2,903,576

Net margin	$	104,127		$	69,821		$	221,342	$	(1,284	)	$	394,006
Operating costs		35,018			24,385			47,618		(715	)		106,306
Depreciation and amortization		17,259			11,356			16,606		-			45,221
Gain (loss) on sale of assets		(2	)		(77	)		10		-			(69	)
Operating income	$	51,848		$	34,003		$	157,128	$	(569	)	$	242,410

Equity earnings from investments	$	7,991		$	19,776		$	4,262	$	-		$	32,029
Capital expenditures	$	164,954		$	10,629		$	76,477	$	167		$	252,227
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $70.8 million, net margin of $53.5 million and operating income of $23.5 million.
(b) - Our Natural Gas Liquids segment has regulated and non-regulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $95.5 million, of which $66.2 million related to sales within the segment, net margin of $59.0 million and operating income of $32.4 million.

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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.

Nine Months Ended September 30, 2011	Natural Gas Gathering and Processing			Natural Gas Pipelines (a)			Natural Gas Liquids (b)			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	260,144		$	171,694		$	7,448,898		$	-		$	7,880,736
Sales to affiliated customers		228,780			77,889			-			-			306,669
Intersegment revenues		653,587			1,117			27,278			(681,982	)		-
Total revenues	$	1,142,511		$	250,700		$	7,476,176		$	(681,982	)	$	8,187,405

Net margin	$	298,184		$	213,929		$	572,541		$	(1,554	)	$	1,083,100
Operating costs		109,558			79,133			141,086			(1,147	)		328,630
Depreciation and amortization		50,120			33,902			47,643			-			131,665
Gain (loss) on sale of assets		(208	)		(286	)		(297	)		-			(791	)
Operating income	$	138,298		$	100,608		$	383,515		$	(407	)	$	622,014

Equity earnings from investments	$	21,931		$	57,426		$	14,308		$	-		$	93,665
Investments in unconsolidated affiliates	$	324,018		$	425,570		$	474,809		$	-		$	1,224,397
Total assets	$	2,283,628		$	1,896,337		$	4,474,868		$	120,720		$	8,775,553
Noncontrolling interests in consolidated subsidiaries	$	-		$	5,308		$	-		$	(59	)	$	5,249
Capital expenditures	$	404,112		$	25,178		$	232,698		$	398		$	662,386
(a) - Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $196.7 million, net margin of $164.3 million and operating income of $69.0 million.
(b) - Our Natural Gas Liquids segment has regulated and non-regulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $278.1 million, of which $189.9 million related to sales within the segment, net margin of $177.3 million and operating income of $100.0 million.

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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.

L. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

We have no significant assets or operations other than our investment in our wholly owned subsidiary, the Intermediate Partnership. The Intermediate Partnership holds all our partnership interests and equity in our subsidiaries, as well as a 50-percent interest in Northern Border Pipeline. Our Intermediate Partnership guarantees our senior notes. The Intermediate Partnership’s guarantee is full and unconditional, subject to certain customary automatic release provisions.

For purposes of the following footnote:

·	we are referred to as “Parent”;

·	the Intermediate Partnership is referred to as “Guarantor Subsidiary”; and

·	the “Non-Guarantor Subsidiaries” are all subsidiaries other than the Guarantor Subsidiary.

The following unaudited supplemental condensed consolidating financial information is presented on an equity method basis reflecting the Parent’s separate accounts, the Guarantor Subsidiary’s separate accounts, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations and the Parent’s consolidated amounts for the periods indicated.

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Condensed Consolidating Statements of Income

	Three Months Ended September 30, 2011

(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)

Revenues	$	-		$	-		$	2,903.6		$	-		$	2,903.6
Cost of sales and fuel		-			-			2,509.6			-			2,509.6
Net margin		-			-			394.0			-			394.0
Operating expenses
Operations and maintenance		-			-			96.2			-			96.2
Depreciation and amortization		-			-			45.2			-			45.2
General taxes		-			-			10.1			-			10.1
Total operating expenses		-			-			151.5			-			151.5
Loss on sale of assets		-			-			(0.1	)		-			(0.1	)
Operating income		-			-			242.4			-			242.4
Equity earnings from investments		209.7			209.7			12.3			(399.7	)		32.0
Allowance for equity funds used during
construction		-			-			0.8			-			0.8
Other income (expense), net		53.9			53.9			(7.1	)		(107.8	)		(7.1	)
Interest expense		(53.9	)		(53.9	)		(55.7	)		107.8			(55.7	)
Income before income taxes		209.7			209.7			192.7			(399.7	)		212.4
Income taxes		-			-			(2.6	)		-			(2.6	)
Net income		209.7			209.7			190.1			(399.7	)		209.8
Less: Net income attributable to
noncontrolling interests		-			-			0.1			-			0.1
Net income attributable to ONEOK
Partners, L.P.	$	209.7		$	209.7		$	190.0		$	(399.7	)	$	209.7

	Three Months Ended September 30, 2010

(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)

Revenues	$	-		$	-		$	2,070.1		$	-		$	2,070.1
Cost of sales and fuel		-			-			1,784.1			-			1,784.1
Net margin		-			-			286.0			-			286.0
Operating expenses
Operations and maintenance		-			-			90.7			-			90.7
Depreciation and amortization		-			-			43.8			-			43.8
General taxes		-			-			7.1			-			7.1
Total operating expenses		-			-			141.6			-			141.6
Gain on sale of assets		-			-			16.1			-			16.1
Operating income		-			-			160.5			-			160.5
Equity earnings from investments		141.5			141.5			8.2			(261.8	)		29.4
Allowance for equity funds used during
construction		-			-			0.3			-			0.3
Other income (expense), net		47.1			47.1			3.0			(94.2	)		3.0
Interest expense		(47.1	)		(47.1	)		(49.1	)		94.2			(49.1	)
Income before income taxes		141.5			141.5			122.9			(261.8	)		144.1
Income taxes		-			-			(2.4	)		-			(2.4	)
Net income		141.5			141.5			120.5			(261.8	)		141.7
Less: Net income attributable to
noncontrolling interests		-			-			0.2			-			0.2
Net income attributable to ONEOK
Partners, L.P.	$	141.5		$	141.5		$	120.3		$	(261.8	)	$	141.5

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	Nine Months Ended September 30, 2011

(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)

Revenues	$	-		$	-		$	8,187.4		$	-		$	8,187.4
Cost of sales and fuel		-			-			7,104.3			-			7,104.3
Net margin		-			-			1,083.1			-			1,083.1
Operating expenses
Operations and maintenance		-			-			291.3			-			291.3
Depreciation and amortization		-			-			131.7			-			131.7
General taxes		-			-			37.3			-			37.3
Total operating expenses		-			-			460.3			-			460.3
Loss on sale of assets		-			-			(0.8	)		-			(0.8	)
Operating income		-			-			622.0			-			622.0
Equity earnings from investments		531.7			531.7			36.7			(1,006.4	)		93.7
Allowance for equity funds used during
construction		-			-			1.6			-			1.6
Other income (expense), net		165.0			165.0			(5.3	)		(330.0	)		(5.3	)
Interest expense		(165.0	)		(165.0	)		(170.6	)		330.0			(170.6	)
Income before income taxes		531.7			531.7			484.4			(1,006.4	)		541.4
Income taxes		-			-			(9.3	)		-			(9.3	)
Net income		531.7			531.7			475.1			(1,006.4	)		532.1
Less: Net income attributable to
noncontrolling interests		-			-			0.4			-			0.4
Net income attributable to ONEOK
Partners, L.P.	$	531.7		$	531.7		$	474.7		$	(1,006.4	)	$	531.7

	Nine Months Ended September 30, 2010

(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)

Revenues	$	-		$	-		$	6,329.3		$	-		$	6,329.3
Cost of sales and fuel		-			-			5,494.0			-			5,494.0
Net margin		-			-			835.3			-			835.3
Operating expenses
Operations and maintenance		-			-			263.2			-			263.2
Depreciation and amortization		-			-			131.7			-			131.7
General taxes		-			-			28.9			-			28.9
Total operating expenses		-			-			423.8			-			423.8
Gain on sale of assets		-			-			15.1			-			15.1
Operating income		-			-			426.6			-			426.6
Equity earnings from investments		330.4			330.4			22.8			(612.4	)		71.2
Allowance for equity funds used during
construction		-			-			0.7			-			0.7
Other income (expense), net		150.3			150.3			0.9			(300.6	)		0.9
Interest expense		(150.3	)		(150.3	)		(156.6	)		300.6			(156.6	)
Income before income taxes		330.4			330.4			294.4			(612.4	)		342.8
Income taxes		-			-			(12.0	)		-			(12.0	)
Net income		330.4			330.4			282.4			(612.4	)		330.8
Less: Net income attributable to
noncontrolling interests		-			-			0.4			-			0.4
Net income attributable to ONEOK
Partners, L.P.	$	330.4		$	330.4		$	282.0		$	(612.4	)	$	330.4

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Condensed Consolidating Balance Sheets

	September 30, 2011

(Unaudited)	Parent		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidating Entries			Total
Assets	(Millions of dollars)
Current assets
Cash and cash equivalents	$	-	$	127.9	$	-	$	-		$	127.9
Accounts receivable, net		-		-		897.7		-			897.7
Affiliate receivables		-		-		5.8		-			5.8
Gas and natural gas liquids in storage		-		-		243.2		-			243.2
Commodity imbalances		-		-		105.4		-			105.4
Other current assets		-		-		104.1		-			104.1
Total current assets		-		127.9		1,356.2		-			1,484.1

Property, plant and equipment
Property, plant and equipment		-		-		6,554.1		-			6,554.1
Accumulated depreciation and amortization		-		-		1,220.1		-			1,220.1
Net property, plant and equipment		-		-		5,334.0		-			5,334.0

Investments and other assets
Investments in unconsolidated affiliates		3,324.5		3,613.4		806.9		(6,520.4	)		1,224.4
Intercompany notes receivable		3,908.9		3,492.1		-		(7,401.0	)		-
Goodwill and intangible assets		-		-		655.5		-			655.5
Other assets		25.4		-		52.2		-			77.6
Total investments and other assets		7,258.8		7,105.5		1,514.6		(13,921.4	)		1,957.5
Total assets	$	7,258.8	$	7,233.4	$	8,204.8	$	(13,921.4	)	$	8,775.6

Liabilities and partners' equity
Current liabilities
Current maturities of long-term debt	$	350.0	$	-	$	11.9	$	-		$	361.9
Accounts payable		-		-		971.4		-			971.4
Affiliate payables		-		-		36.5		-			36.5
Commodity imbalances		-		-		237.1		-			237.1
Other current liabilities		143.7		-		82.3		-			226.0
Total current liabilities		493.7		-		1,339.2		-			1,832.9

Intercompany debt		-		3,908.9		3,492.1		(7,401.0	)		-

Long-term debt, excluding current maturities		3,440.6		-		77.0		-			3,517.6

Deferred credits and other liabilities		-		-		95.4		-			95.4

Commitments and contingencies

Equity
Equity excluding noncontrolling interests in
consolidated subsidiaries		3,324.5		3,324.5		3,195.9		(6,520.4	)		3,324.5
Noncontrolling interests in consolidated
subsidiaries		-		-		5.2		-			5.2
Total equity		3,324.5		3,324.5		3,201.1		(6,520.4	)		3,329.7
Total liabilities and equity	$	7,258.8	$	7,233.4	$	8,204.8	$	(13,921.4	)	$	8,775.6

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	December 31, 2010

(Unaudited)	Parent		Guarantor Subsidiary		Combined Non-Guarantor Subsidiaries		Consolidating Entries			Total
Assets	(Millions of dollars)
Current assets
Cash and cash equivalents	$	-	$	0.9	$	-	$	-		$	0.9
Accounts receivable, net		-		-		815.1		-			815.1
Affiliate receivables		-		-		5.2		-			5.2
Gas and natural gas liquids in storage		-		-		317.2		-			317.2
Commodity imbalances		-		-		92.4		-			92.4
Other current assets		-		-		48.0		-			48.0
Total current assets		-		0.09		1,277.9		-			1,278.8

Property, plant and equipment
Property, plant and equipment		-		-		5,857.0		-			5,857.0
Accumulated depreciation and amortization		-		-		1,099.5		-			1,099.5
Net property, plant and equipment		-		-		4,757.5		-			4,757.5

Investments and other assets
Investments in unconsolidated affiliates		3,271.8		3,491.1		804.4		(6,379.2	)		1,188.1
Intercompany notes receivable		3,183.6		2,963.4		-		(6,147.0	)		-
Goodwill and intangible assets		-		-		661.2		-			661.2
Other assets		16.6		-		17.9		-			34.5
Total investments and other assets		6,472.0		6,454.5		1,483.5		(12,526.2	)		1,883.8
Total assets	$	6,472.0	$	6,455.4	$	7,518.9	$	(12,526.2	)	$	7,920.1

Liabilities and partners' equity
Current liabilities
Current maturities of long-term debt	$	225.0	$	-	$	11.9	$	-		$	236.9
Notes payable		429.9		-		-		-			429.9
Accounts payable		-		-		852.3		-			852.3
Affiliate payables		-		-		29.8		-			29.8
Commodity imbalances		-		-		291.1		-			291.1
Other current liabilities		49.6		-		84.5		-			134.1
Total current liabilities		704.5		-		1,269.6		-			1,974.1

Intercompany debt		-		3,183.6		2,963.4		(6,147.0	)		-

Long-term debt, excluding current maturities		2,495.7		-		85.9		-			2,581.6

Deferred credits and other liabilities		-		-		87.4		-			87.4

Commitments and contingencies

Equity
Equity excluding noncontrolling interests in
consolidated subsidiaries		3,271.8		3,271.8		3,107.4		(6,379.2	)		3,271.8
Noncontrolling interests in consolidated
subsidiaries		-		-		5.2		-			5.2
Total equity		3,271.8		3,271.8		3,112.6		(6,379.2	)		3,277.0
Total liabilities and equity	$	6,472.0	$	6,455.4	$	7,518.9	$	(12,526.2	)	$	7,920.1

Condensed Consolidating Statements of Cash Flows

	Nine Months Ended September 30, 2011

(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Operating Activities
Cash provided by operating activities	$	-		$	57.0		$	598.3		$	-		$	655.3

Investing Activities
Capital expenditures (less allowance for equity funds
used during construction)		-			-			(662.4	)		-			(662.4	)
Contributions to unconsolidated affiliates		-			(49.8	)		(1.9	)		-			(51.7	)
Distributions received from unconsolidated affiliates		-			16.1			0.1			-			16.2
Proceeds from sale of assets		-			-			0.7			-			0.7
Cash used in investing activities		-			(33.7	)		(663.5	)		-			(697.2	)

Financing Activities
Cash distributions:
General and limited partners		(451.5	)		(451.5	)		(451.5	)		903.0			(451.5	)
Noncontrolling interests		-			-			(0.3	)		-			(0.3	)
Intercompany distributions received		451.5			451.5			-			(903.0	)		-
Borrowing (repayment) of notes payable, net		(429.9	)		-			-			-			(429.9	)
Intercompany borrowings (advances), net		(629.6	)		103.7			525.9			-			-
Issuance of long-term debt		1,295.5			-			-			-			1,295.5
Long-term debt financing costs		(11.0	)		-			-			-			(11.0	)
Repayment of long-term debt		(225.0	)		-			(8.9	)		-			(233.9	)
Cash provided by financing activities		-			103.7			65.2			-			168.9
Change in cash and cash equivalents		-			127.0			-			-			127.0
Cash and cash equivalents at beginning of period		-			0.9			-			-			0.9
Cash and cash equivalents at end of period	$	-		$	127.9		$	-		$	-		$	127.9

	Nine Months Ended September 30, 2010

(Unaudited)	Parent			Guarantor Subsidiary			Combined Non-Guarantor Subsidiaries			Consolidating Entries			Total
	(Millions of dollars)
Operating Activities
Cash provided by operating activities	$	-		$	48.4		$	268.5		$	-		$	316.9

Investing Activities
Capital expenditures (less allowance for equity funds
used during construction)		-			-			(202.8	)		-			(202.8	)
Contributions to unconsolidated affiliates		-			-			(1.3	)		-			(1.3	)
Distributions received from unconsolidated affiliates		-			9.3			-			-			9.3
Proceeds from sale of assets		-			-			424.0			-			424.0
Cash provided by investing activities		-			9.3			219.9			-			229.2

Financing Activities
Cash distributions:
General and limited partners		(417.4	)		(417.4	)		(417.4	)		834.8			(417.4	)
Noncontrolling interests		-			-			(0.8	)		-			(0.8	)
Intercompany distributions received		417.4			417.4			-			(834.8	)		-
Borrowing (repayment) of notes payable, net		(196.6	)		-			-			-			(196.6	)
Intercompany borrowings (advances), net		117.1			(55.8	)		(61.3	)		-			-
Repayment of long-term debt		(250.0	)		-			(8.9	)		-			(258.9	)
Issuance of common units, net of discounts		322.7			-			-			-			322.7
Contribution from general partner		6.8			-			-			-			6.8
Cash used in financing activities		-			(55.8	)		(488.4	)		-			(544.2	)
Change in cash and cash equivalents		-			1.9			-			-			1.9
Cash and cash equivalents at beginning of period		-			3.1			-			-			3.1
Cash and cash equivalents at end of period	$	-		$	5.0		$	-		$	-		$	5.0

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ITEM 2.

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

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

RECENT DEVELOPMENTS

Unit Split - In June 2011, the board of directors of our general partner approved a two-for-one split of our common and Class B units. The two-for-one unit split was completed on July 12, 2011, by a distribution of one unit for each unit outstanding and held by unitholders of record on June 30, 2011. In July 2011, the Partnership Agreement was amended to adjust the formula for distributing available cash among our general partner and limited partners to reflect the unit split. As a result of this unit split, we have adjusted all unit and per-unit amounts contained herein to be presented on a post-split basis.

Growth Projects - Drilling rig counts are higher and related development activities continue to progress in many areas of our operations compared with 2010. Increasing natural gas and NGL production resulting from these activities and higher petrochemical industry demand for NGL products have required additional capital investments to increase the capacity of our infrastructure to bring these commodities from supply basins to market. In response to this increased production and demand for NGL products, we have announced $2.7 billion to $3.3 billion in new capital projects to meet the needs of oil and natural gas producers in the Bakken Shale, the Cana-Woodford Shale and the Granite Wash areas, and for additional NGL infrastructure in the Mid-Continent and Gulf Coast areas that will enhance the distribution of NGL products to meet the increasing petrochemical industry and NGL export demand, which, when completed, are anticipated to provide additional earnings and cash flows.

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

Cash Distributions - In October 2011, our general partner declared a cash distribution of $0.595 per unit ($2.38 per unit on an annualized basis) for the third quarter of 2011, an increase of 1 cent from the previous quarter, which will be paid November 14, 2011, to unitholders of record at the close of business on November 7, 2011.

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

Partnership 2011 Credit Agreement - On August 1, 2011, we entered into the Partnership 2011 Credit Agreement, which replaced the Partnership Credit Agreement.

FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

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,						2011 vs. 2010					2011 vs. 2010
Financial Results	2011			2010			2011			2010			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Revenues	$	2,903.6		$	2,070.1		$	8,187.4		$	6,329.3		$	833.5		40	%	$	1,858.1		29	%
Cost of sales and fuel		2,509.6			1,784.1			7,104.3			5,494.0			725.5		41	%		1,610.3		29	%
Net margin		394.0			286.0			1,083.1			835.3			108.0		38	%		247.8		30	%
Operating costs		106.3			97.8			328.6			292.1			8.5		9	%		36.5		12	%
Depreciation and amortization		45.2			43.8			131.7			131.7			1.4		3	%		-		0	%
Gain (loss) on sale of assets		(0.1	)		16.1			(0.8	)		15.1			(16.2	)	*			(15.9	)	*
Operating income	$	242.4		$	160.5		$	622.0		$	426.6		$	81.9		51	%	$	195.4		46	%

Equity earnings from investments	$	32.0		$	29.4		$	93.7		$	71.2		$	2.6		9	%	$	22.5		32	%
Interest expense	$	(55.7	)	$	(49.1	)	$	(170.6	)	$	(156.6	)	$	6.6		13	%	$	14.0		9	%
Capital expenditures	$	252.2		$	104.1		$	662.4		$	202.8		$	148.1		*		$	459.6		*
* Percentage change is greater than 100 percent.

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NGL prices were higher during the three and nine months ended September 30, 2011, compared with the same periods last year. The increase in NGL prices had a direct impact on our revenues and cost of sales and fuel.

Operating income increased approximately 51 percent and 46 percent for the three and nine months ended September 30, 2011, respectively, compared with the same periods last year. The increase in operating income reflects higher net margin in our Natural Gas Liquids and Natural Gas Gathering and Processing segments.

Our Natural Gas Liquids segment benefited from more favorable NGL price differentials, as well as additional NGL fractionation and transportation capacity available for optimization activities between the Mid-Continent and Gulf-Coast markets. Our Natural Gas Liquids segment also realized higher exchange service margins due primarily to higher NGL gathering and fractionation volumes and contract renegotiations at higher fees with our customers. In addition, our Natural Gas Liquids segment realized higher isomerization margins resulting from wider price differentials between normal butane and iso-butane, and higher isomerization volumes.

Our Natural Gas Gathering and Processing segment benefited from higher realized commodity prices, higher natural gas volumes processed and favorable changes in contract terms, offset partially by lower natural gas volumes gathered primarily in the Powder River Basin.

These increases were offset partially by the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method in our Natural Gas Liquids segment following the sale of a 49-percent ownership interest in Overland Pass Pipeline Company. Additionally, our Natural Gas Pipelines segment realized lower transportation margins due to narrower natural gas price location differentials that caused a reduction in contracted capacity primarily on Midwestern Gas Transmission.

Gain (loss) on sale of assets decreased from the sale of a 49-percent interest of Overland Pass Pipeline Company in September 2010.

Operating costs increased for the three and nine months ended September 30, 2011, compared with the same periods last year, due primarily to higher labor and employee-related costs associated with incentive and benefit plans, and higher ad valorem taxes, as well as higher materials and outside services expenses associated primarily with scheduled maintenance at our natural gas liquids fractionation and storage facilities.

Equity earnings from investments increased for the three months ended September 30, 2011, compared with the same period last year, due to the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company in our Natural Gas Liquids segment. Equity earnings from investments increased for the nine months ended September 30, 2011, compared with the same period last year, due to the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company in our Natural Gas Liquids segment and increased contracted capacity on Northern Border Pipeline in our Natural Gas Pipeline segment.

Capital expenditures increased for the three and nine months ended September 30, 2011, compared with the same periods last year, due primarily to growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments.

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

Natural Gas Gathering and Processing

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

In the Mid-Continent region and the Williston Basin, unprocessed natural gas is compressed and transported through pipelines to processing facilities where volumes are aggregated, treated and processed to remove water vapor, solids and other contaminants, and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas.

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

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

Williston Basin Processing Plants and related projects - We are constructing three new 100 MMcf/d natural gas processing facilities: the Garden Creek plant in eastern McKenzie County, North Dakota, and the Stateline I and II plants in western Williams County, North Dakota. We have multi-year supply commitments and acreage dedications for all the capacity of the Garden Creek and Stateline I plants and for approximately 75 percent of the Stateline II plant’s capacity. In addition, we will expand and upgrade our existing gathering and compression infrastructure and add new well connections associated with these plants. The Garden Creek plant, which is expected to be in service by the end of 2011, and related infrastructure projects are expected to cost approximately $350 million to $415 million, excluding AFUDC. The Stateline I plant, which is expected to be in service by the third quarter of 2012, and related infrastructure projects are expected to cost approximately $300 million to $355 million, excluding AFUDC. The Stateline II plant, which is expected to be in service during the first half of 2013, and related infrastructure projects are expected to cost approximately $260 million to $305 million, excluding AFUDC.

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

For a discussion of our capital expenditure financing, see “Capital Expenditures” in “Liquidity and Capital Resources” on page 42.

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,				2011 vs. 2010					2011 vs. 2010
Financial Results	2011		2010		2011		2010		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	243.5	$	163.8	$	682.7	$	524.1	$	79.7		49	%	$	158.6		30	%
Residue gas sales		132.5		110.5		348.2		347.8		22.0		20	%		0.4		0	%
Gathering, compression, dehydration and processing fees and other revenue		39.2		38.1		111.6		110.8		1.1		3	%		0.8		0	%
Cost of sales and fuel		311.1		224.6		844.3		724.8		86.5		39	%		119.5		16	%
Net margin		104.1		87.8		298.2		257.9		16.3		19	%		40.3		16	%
Operating costs		35.0		34.1		109.6		98.5		0.9		3	%		11.1		11	%
Depreciation and amortization		17.3		15.3		50.1		44.9		2.0		13	%		5.2		12	%
Loss on sale of assets		-		0.2		0.2		0.4		(0.2	)	*			(0.2	)	(50	%)
Operating income	$	51.8	$	38.2	$	138.3	$	114.1	$	13.6		36	%	$	24.2		21	%

Equity earnings from investments	$	8.0	$	7.4	$	21.9	$	20.7	$	0.6		8	%	$	1.2		6	%
Capital expenditures	$	165.0	$	69.3	$	404.1	$	118.3	$	95.7		*		$	285.8		*
* Percentage change is greater than 100 percent.

Net margin increased for the three months ended September 30, 2011, compared with the same period last year, primarily as result of the following:

·	an increase of $11.6 million due to higher net realized NGL and condensate prices;

·	an increase of $6.2 million due to higher volumes processed in the Williston Basin, offset partially by lower volumes in Kansas due to natural production declines; and

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·	an increase of $3.0 million due to favorable changes in contract terms; offset partially by

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

·	a decrease of $2.0 million due to lower natural gas volumes gathered as a result of continued production declines and reduced drilling activity by producers in the Powder River Basin.

Net margin increased for the nine months ended September 30, 2011, compared with the same period last year, primarily as a result of the following:

·	an increase of $26.7 million due to higher net realized commodity prices;

·	an increase of $11.8 million due to favorable changes in contract terms; and

·	an increase of $9.3 million due to higher natural gas volumes processed in the Williston Basin resulting from increased drilling activity, offsetting reduced drilling activity in certain parts of western Oklahoma and Kansas and weather-related outages in the first quarter; offset partially by

·	a decrease of $6.1 million due to lower natural gas volumes gathered as a result of continued production declines and reduced drilling activity by producers in the Powder River Basin.

Operating costs increased for the three months ended September 30, 2011, compared with the same period last year, due primarily to $1.5 million of higher labor costs and employee-related costs associated with incentive plans.

Operating costs increased for the nine months ended September 30, 2011, compared with the same period last year, primarily as a result of:

·	an increase of $7.1 million due to higher labor costs and employee-related costs associated with incentive and benefit plans, which includes higher equity-based compensation costs; and

·	an increase of $3.0 million due to higher ad valorem taxes due to our completed growth projects.

Depreciation and amortization increased for the three and nine months ended September 30, 2011, compared with the same periods last year, due primarily to the completion of the connection of our western Oklahoma natural gas gathering system to our Maysville natural gas processing facility in central Oklahoma and the completion of well connections and infrastructure projects supporting our volume growth in the Williston Basin.

Capital expenditures increased for the three and nine months ended September 30, 2011, compared with the same periods last year, due primarily to our growth projects discussed above.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Operating Information (a)	2011		2010		2011		2010
Natural gas gathered (BBtu/d)		1,044		1,046		1,021		1,075
Natural gas processed (BBtu/d)		723		669		682		674
NGL sales (MBbl/d)		50		44		47		44
Residue gas sales (BBtu/d)		348		292		308		286
Realized composite NGL net sales price ($/gallon) (b)	$	1.09	$	0.87	$	1.09	$	0.92
Realized condensate net sales price ($/Bbl) (b)	$	87.89	$	65.14	$	81.63	$	63.61
Realized residue gas net sales price ($/MMBtu) (b)	$	5.25	$	5.60	$	5.63	$	5.43
Realized gross processing spread ($/MMBtu) (b)	$	8.17	$	5.67	$	8.30	$	5.97
(a) - Includes volumes for consolidated entities only.
(b) - Presented net of the impact of hedging activities and includes equity volumes only.

Natural gas gathered decreased for the three months ended September 30, 2011, compared with the same period last year, due to continued production declines and reduced drilling activity, primarily in the Powder River Basin in Wyoming and certain parts of Kansas, offset partially by increased drilling activity in the Williston Basin.

Natural gas gathered decreased for the nine months ended September 30, 2011, compared with the same period last year, due to continued production declines and reduced drilling activity, primarily in the Powder River Basin in Wyoming and certain parts of western Oklahoma and Kansas, and weather-related outages in the first quarter of 2011, offset partially by increased drilling activity in the Williston Basin.

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Natural gas processed increased for the three and nine months ended September 30, 2011, compared with the same periods last year, due to an increase in drilling activity in the Williston Basin, offsetting reduced drilling activity and natural production declines in Kansas for the three and nine-month periods, and reduced drilling activity in certain parts of western Oklahoma and weather-related outages in the first quarter of 2011 for the nine-month period.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Operating Information (a)	2011			2010			2011			2010
Percent of proceeds
NGL sales (Bbl/d)		6,963			6,966			6,433			5,933
Residue gas sales (MMBtu/d)		52,038			40,603			46,702			40,852
Condensate sales (Bbl/d)		1,401			1,482			1,754			1,761
Percentage of total net margin		63	%		56	%		61	%		55	%
Fee-based
Wellhead volumes (MMBtu/d)		1,044,385			1,046,475			1,020,871			1,075,491
Average rate ($/MMBtu)	$	0.35		$	0.31		$	0.34		$	0.31
Percentage of total net margin		31	%		35	%		32	%		35	%
Keep-whole
NGL shrink (MMBtu/d) (b)		9,145			13,443			10,753			13,800
Plant fuel (MMBtu/d) (b)		973			1,667			1,193			1,639
Condensate shrink (MMBtu/d) (b)		801			1,222			1,204			1,531
Condensate sales (Bbl/d)		162			247			244			310
Percentage of total net margin		6	%		9	%		7	%		10	%
(a) - Includes volumes for consolidated entities only.
(b) - Refers to the Btus that are removed from natural gas through processing.

Commodity Price Risk - The following tables set forth our Natural Gas Gathering and Processing segment’s hedging information for the periods indicated as of September 30, 2011:

	Three Months Ending
	December 31, 2011
	Volumes Hedged	Average Price		Percentage Hedged
NGLs (Bbl/d) (a)	5,075	$1.19	/ gallon	56%
Condensate (Bbl/d) (a)	1,838	$2.15	/ gallon	77%
Total (Bbl/d)	6,913	$1.45	/ gallon	60%
Natural gas (MMBtu/d)	24,457	$5.78	/ MMBtu	63%
(a) - Hedged with fixed-price swaps.

	Year Ending
	December 31, 2012
	Volumes Hedged	Average Price		Percentage Hedged
NGLs (Bbl/d) (a)	5,169	$1.61	/ gallon	43%
Condensate (Bbl/d) (a)	1,819	$2.43	/ gallon	73%
Total (Bbl/d)	6,988	$1.82	/ gallon	48%
Natural gas (MMBtu/d)	25,301	$5.09	/ MMBtu	42%
(a) - Hedged with fixed-price swaps.

	Year Ending
	December 31, 2013
	Volumes Hedged	Average Price		Percentage Hedged
NGLs (Bbl/d) (a)	367	$2.55	/ gallon	2%
Condensate (Bbl/d) (a)	649	$2.55	/ gallon	23%
Total (Bbl/d)	1,016	$2.55	/ gallon	4%
(a) - Hedged with fixed-price swaps.

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Our Natural Gas Gathering and Processing segment’s commodity price risk is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at September 30, 2011, excluding the effects of hedging and assuming normal operating conditions. Our condensate sales are based on the price of crude oil. We estimate the following:

·	a $0.01 per gallon change in the composite price of NGLs would change annual net margin by approximately $1.5 million;

·	a $1.00 per barrel change in the price of crude oil would change annual net margin by approximately $1.3 million; and

·	a $0.10 per MMBtu change in the price of natural gas would change annual net margin by approximately $2.0 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 nonprocessed gas. We also provide interstate natural gas transportation and storage services in accordance with Section 311(a) of the Natural Gas Policy Act of 1978, as amended.

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

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

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

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

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

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

We own underground natural gas storage facilities in Oklahoma, Kansas and Texas, which are connected to our intrastate natural gas pipeline assets.

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

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

	Three Months Ended				Nine Months Ended					Three Months					Nine Months
	September 30,				September 30,					2011 vs. 2010					2011 vs. 2010
Financial Results	2011		2010		2011			2010		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Transportation revenues	$	57.7	$	60.7	$	176.1		$	184.6	$	(3.0	)	(5	%)	$	(8.5	)	(5	%)
Storage revenues		17.3		16.9		51.9			51.1		0.4		2	%		0.8		2	%
Gas sales and other revenues		14.5		15.5		22.7			24.9		(1.0	)	(6	%)		(2.2	)	(9	%)
Cost of sales		19.7		18.1		36.8			34.2		1.6		9	%		2.6		8	%
Net margin		69.8		75.0		213.9			226.4		(5.2	)	(7	%)		(12.5	)	(6	%)
Operating costs		24.4		24.8		79.1			71.3		(0.4	)	(2	%)		7.8		11	%
Depreciation and amortization		11.4		11.2		33.9			33.1		0.2		2	%		0.8		2	%
Gain (loss) on sale of assets		-		-		(0.3	)		0.1		-		*			(0.4	)	*
Operating income	$	34.0	$	39.0	$	100.6		$	122.1	$	(5.0	)	(13	%)	$	(21.5	)	(18	%)

Equity earnings from investments	$	19.8	$	21.3	$	57.4		$	48.9	$	(1.5	)	(7	%)	$	8.5		17	%
Capital expenditures	$	10.6	$	6.8	$	25.2		$	18.4	$	3.8		56	%	$	6.8		37	%

* Percentage change is greater than 100 percent.

Net margin decreased for the three months ended September 30, 2011, compared with the same period last year, primarily as a result of:

·	a decrease of $3.7 million due to lower natural gas transportation margins as a result of narrower natural gas price location differentials that decreased contracted transportation capacity on Midwestern Gas Transmission and reduced interruptible transportation volumes across our pipelines; and

·	a decrease of $1.2 million due to lower realized prices on our retained fuel positions.

Net margin decreased for the nine months ended September 30, 2011, compared with the same period last year, primarily as a result of the following:

·	a decrease of $9.6 million from lower natural gas transportation margins due to narrower natural gas price location differentials that decreased contracted transportation capacity on Midwestern Gas Transmission and interruptible transportation volumes across our pipelines; and

·	a decrease of $4.5 million due primarily to lower realized prices on our retained fuel positions; offset partially by

·	an increase of $2.3 million due to higher natural gas storage margins, primarily as a result of higher park-and-loan activity due to periods of higher heating and electric demand.

Operating costs increased for the nine months ended September 30, 2011, compared with the same period last year, primarily as a result of:

·	an increase of $4.4 million due to higher labor costs and employee-related costs associated with incentive and benefit plans, which include higher equity-based compensation costs;

·	an increase of $1.8 million due to higher outside services costs atributable to pipeline integrity and maintenance projects; and

·	an increase of $1.5 million due to higher ad valorem taxes associated with our completed capital projects.

Equity earnings from investments decreased for the three months ended September 30, 2011, compared with the same period last year, due primarily to a greater portion of Northern Border Pipeline’s capacity being contracted on an annual basis at lower rates in 2011 compared with higher premium seasonal rates in 2010. Equity earnings from investments increased for the nine months ended September 30, 2011, compared with the same period last year, due to increased contracted capacity on Northern Border Pipeline resulting from wider natural gas price location differentials between the markets it serves. Substantially all of Northern Border Pipeline’s capacity has been contracted through October 2012.

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	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Operating Information (a)	2011			2010			2011			2010
Natural gas transportation capacity contracted (MDth/d)		5,132			5,460			5,353			5,627
Transportation capacity subscribed		79	%		84	%		83	%		87	%
Average natural gas price
Mid-Continent region ($/MMBtu)	$	4.02		$	3.94		$	4.10		$	4.35
(a) - Includes volumes for consolidated entities only.

Natural gas transportation capacity contracted for the three and nine months ended September 30, 2011, decreased compared with the same periods last year due primarily to lower subscribed capacity on Midwestern Gas Transmission due to narrower natural gas price location differentials between the markets we serve. Our other natural gas pipelines primarily serve end-users, such as natural gas distribution companies and electric-generation companies, that require natural gas to operate their business regardless of natural gas price location differentials.

Natural Gas Liquids

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

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

Revenues for our Natural Gas Liquids segment are derived primarily from fee-based services provided to our customers and from the physical optimization of our assets. Our sources of revenue are categorized as exchange services, optimization and marketing, pipeline transportation, isomerization and storage, which are defined as follows:

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

Our optimization and marketing business utilizes our assets, contract portfolio and market knowledge to capture location, product, and seasonal price differentials. We transport NGL products between the Mid-Continent and Gulf Coast in order to capture the price differentials between the two market centers. Our natural gas liquids storage facilities are also utilized to capture seasonal price variances;

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

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

Growth Projects - Our growth strategy in the Natural Gas Liquids segment is focused around the oil and natural gas drilling activity in shale plays from the Rockies through the Mid-Continent region down to the Texas Gulf Coast region. Increasing natural gas and NGL production resulting from this activity and higher petrochemical industry demand for NGL products have required additional capital investments to increase the capacity of our infrastructure to bring these commodities from supply basins to market. Our Natural Gas Liquids segment has announced plans to invest approximately $1.7 billion to $2.2 billion. This investment will accommodate the gathering and fractionation of growing NGL supplies from the shale plays

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across our asset base and alleviate infrastructure constraints between the Mid-Continent and Texas Gulf Coast regions to meet the increasing petrochemical industry and NGL export demand in the Gulf Coast.

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

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

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

MB-2 fractionator - We plan to construct a new 75-MBbl/d fractionator, MB-2, near our storage facility in Mont Belvieu, Texas. The Texas Commission on Environmental Quality (TCEQ) has approved our permit application to build this fractionator. Construction of the MB-2 fractionator began in June 2011 and is expected to be completed in mid-2013. The cost of the MB-2 fractionator is estimated to be $300 million to $390 million, excluding AFUDC. We have multi-year supply commitments from producers and natural gas processors for approximately two-thirds of the fractionator’s capacity. The fractionator can be expanded to 125 MBbl/d to accommodate additional NGL volumes from the Arbuckle Pipeline and the Sterling I, II and III pipelines.

Bakken Pipeline and related projects - We plan to build a 525- to 615-mile natural gas liquids pipeline, the Bakken Pipeline, to transport unfractionated NGLs from the Williston Basin to the Overland Pass Pipeline. The Bakken Pipeline will initially have the capacity to transport up to 60 MBbl/d of unfractionated NGL production and can be expanded to 110 MBbl/d with additional pump stations. The unfractionated NGLs will then be delivered to our existing natural gas liquids fractionation and distribution infrastructure in the Mid-Continent. Project costs for the new pipeline are estimated to be $450 million to $550 million, excluding AFUDC.

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

The unfractionated NGLs from the Bakken Pipeline and other supply sources under development in the Rockies will require installing additional pump stations and expanding existing pump stations on the Overland Pass Pipeline, in which we own a 50-percent equity interest. These additions and expansions will increase the capacity of Overland Pass Pipeline to 255 MBbl/d. Our anticipated share of the costs for this project is estimated to be $35 million to $40 million, excluding AFUDC.

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

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

These investments include constructing more than 230 miles of natural gas liquids pipelines that will expand our existing Mid-Continent natural gas liquids gathering system in the Cana-Woodford Shale and Granite Wash areas. The pipelines will connect to three new third-party natural gas processing facilities that are under construction and to three existing third-party natural gas processing facilities that are being expanded. Additionally, we will install additional pump stations on our Arbuckle Pipeline to increase its capacity to 240 MBbl/d. When completed, these projects are expected to add, through multi-year supply contracts, approximately 75 to 80 MBbl/d of unfractionated NGLs to our existing natural gas liquids

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gathering systems. These projects are expected to be in service during the first half of 2012 and cost approximately $180 million to $240 million, excluding AFUDC.

In 2010, we invested approximately $17 million to increase the accessibility of new NGL supply to our Arbuckle Pipeline and Mont Belvieu fractionation facilities.

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

For a discussion of our capital expenditure financing, see “Capital Expenditures” in “Liquidity and Capital Resources” on page 42.

Selected Financial Results and Operating Information - Beginning in September 2010, following the sale of a 49-percent interest, Overland Pass Pipeline Company was deconsolidated and prospectively accounted for under the equity method. 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,					2011 vs. 2010					2011 vs. 2010
Financial Results	2011		2010		2011			2010		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
NGL and condensate sales	$	2,488.6	$	1,647.0	$	7,047.3		$	5,067.4	$	841.6		51	%	$	1,979.9		39	%
Exchange service and storage revenues		137.2		115.6		384.6			332.7		21.6		19	%		51.9		16	%
Transportation revenues		13.0		16.7		44.3			68.8		(3.7	)	(22	%)		(24.5	)	(36	%)
Cost of sales and fuel		2,417.5		1,655.5		6,903.7			5,112.6		762.0		46	%		1,791.1		35	%
Net margin		221.3		123.8		572.5			356.3		97.5		79	%		216.2		61	%
Operating costs		47.6		39.5		141.1			126.2		8.1		21	%		14.9		12	%
Depreciation and amortization		16.6		17.4		47.6			53.7		(0.8	)	(5	%)		(6.1	)	(11	%)
Gain (loss) on sale of assets		-		16.3		(0.3	)		15.5		(16.3	)	*			(15.8	)	*
Operating income	$	157.1	$	83.2	$	383.5		$	191.9	$	73.9		89	%	$	191.6		100	%

Equity earnings from investments	$	4.3	$	0.7	$	14.3		$	1.7	$	3.6		*		$	12.6		*
Capital expenditures	$	76.5	$	27.7	$	232.7		$	65.3	$	48.8		*		$	167.4		*
* Percentage change is greater than 100 percent.

Net margin increased for the three months ended September 30, 2011, compared with the same period last year, primarily as a result of the following:

·	an increase of $89.4 million related to more favorable NGL price differentials and additional fractionation and transportation capacity available for optimization activities between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers;

an increase of $7.9 million related to higher NGL volumes gathered and fractionated in Texas and the Mid-Continent and Rocky Mountain regions, excluding the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company, and contract renegotiations for higher fees associated with our NGL exchange services activities, offset partially by higher costs associated with NGL volumes fractionated by third parties;

·	an increase of $7.3 million related to higher isomerization margins resulting from wider price differentials between normal butane and iso-butane and higher isomerization volumes; and

·	an increase of $3.1 million due to higher storage margins as a result of contract renegotiations; offset partially by

·	a decrease of $10.2 million due to the deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method.

Net margin increased for the nine months ended September 30, 2011, compared with the same period last year, primarily as a result of the following:

·	an increase of $207.4 million related to more favorable NGL price differentials and additional fractionation and transportation capacity available for optimization activities between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers;

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an increase of $29.6 million related to higher NGL volumes gathered and fractionated in Texas and the Mid-Continent and Rocky Mountain regions, excluding the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company, and contract renegotiations for higher fees associated with our NGL exchange services activities, offset partially by higher costs associated with NGL volumes fractionated by third parties;

·	an increase of $12.8 million related to higher isomerization margins resulting from wider price differentials between normal butane and iso-butane and higher isomerization volumes; and

·	an increase of $9.2 million due to higher storage margins as a result of contract renegotiations at higher fees; offset partially by

·	a decrease of $42.8 million due to the deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method.

Operating costs increased for the three months ended September 30, 2011, compared with the same period last year, primarily as a result of the following:

·	an increase of $3.2 million due to higher materials and outside services expenses associated primarily with scheduled maintenance at our fractionation and storage facilities;

·	an increase of $2.6 million due to higher ad valorem taxes as a result of our completed capital projects; and

·	an increase of $2.2 million due to higher labor costs and employee-related costs associated with incentive plans.

Operating costs increased for the nine months ended September 30, 2011, compared with the same period last year, primarily as a result of the following:

·	an increase of $8.8 million due to higher labor costs and employee-related costs associated with incentive and benefit plans, which includes higher equity-based compensation costs;

·	an increase of $6.3 million from higher materials and outside services expenses associated primarily with scheduled maintenance at our fractionation and storage facilities; and

·	an increase of $4.8 million from higher ad valorem taxes as a result of our completed capital projects; partially offset by

·	a decrease of $5.4 million due to the deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method.

Depreciation and amortization expense decreased, and equity earnings increased for the nine months ended September 30, 2011, compared with the same periods last year, due primarily to the deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method.

Gain (loss) on sale of assets decreased for the three and nine months ended September 30, 2011, compared with the same periods last year, due primarily to the prior year gain on sale of a 49-percent ownership interest in Overland Pass Pipeline Company.

Capital expenditures increased for the three months ended September 30, 2011, compared with the same period last year, due primarily to our growth projects discussed above.

Capital expenditures increased for the nine months ended September 30, 2011, compared with the same period last year, due primarily to the purchase of leased equipment at our Bushton Plant and expenditures related to our growth projects discussed above.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Operating Information	2011		2010		2011		2010
NGL sales (MBbl/d)		485		449		481		443
NGLs fractionated (MBbl/d) (a)		529		500		522		505
NGLs transported-gathering lines (MBbl/d) (b) (c)		443		436		424		452
NGLs transported-distribution lines (MBbl/d) (b)		457		455		460		468
Conway-to-Mont Belvieu OPIS average price differential
Ethane ($/gallon)	$	0.27	$	0.10	$	0.21	$	0.11
(a) - Includes volumes fractionated at company-owned and third-party facilities.
(b) - Includes volumes for consolidated entities only.
(c) - 2010 volume information includes 52 MBbl/d and 84 MBbl/d for the three and nine months ended September 30, 2010, respectively, related to Overland Pass Pipeline Company which is accounted for under the equity method in 2011.

NGLs gathered and fractionated, excluding the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company, increased for the three and nine months ended September 30, 2011, compared with the same periods last year, due primarily to increased production through existing connections in Texas and the Mid-Continent and Rocky Mountain regions, and new supply connections in the Mid-Continent and Rocky Mountain regions.

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NGLs transported on distribution lines increased for the three months ended September 30, 2011, compared with the same period last year, due primarily to increased volumes transported from the Mid-Continent to Midwest markets. NGLs transported on distribution lines decreased for nine months ended September 30, 2011, compared with the same period last year, due primarily to managing the transportation of unfractionated NGL volumes across the system by placing additional NGL volumes on the Arbuckle natural gas liquids gathering pipeline to Mont Belvieu to capture additional margins from favorable NGL price location differentials.

CONTINGENCIES

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

LIQUIDITY AND CAPITAL RESOURCES

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

In the first nine months of 2011, we utilized cash from operations, proceeds from the January 2011 debt issuance and our commercial paper program to fund our short-term liquidity needs. We also used proceeds from our January 2011 debt issuance to fund our capital projects as part of our long-term financing plan. See discussion below under “Debt Issuance and Maturity” for more information.

Our ability to continue to access capital markets for debt and equity financing under reasonable terms depends on our financial condition, credit ratings and market conditions. We anticipate that our cash flow generated from operations, existing capital resources and ability to obtain financing will enable us to maintain our current level of operations and our planned operations, as well as fund our capital expenditures.

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

	September 30,			December 31,
	2011			2010
Long-term debt		54	%		46	%
Equity		46	%		54	%

Debt (including notes payable)		54	%		50	%
Equity		46	%		50	%

Short-term Liquidity - Our principal sources of short-term liquidity consist of cash generated from operating activities, our commercial paper program and our Partnership 2011 Credit Agreement.

The total amount of short-term borrowings authorized by our general partner’s Board of Directors is $2.5 billion. At September 30, 2011, we had no commercial paper outstanding, no letters of credit issued and no borrowings outstanding under our Partnership Credit Agreement. At September 30, 2011, we had approximately $127.9 million of cash and $1.2 billion of credit available under the Partnership Credit Agreement. As of September 30, 2011, we could have issued $2.3 billion of short- and long-term debt to meet our liquidity needs under the most restrictive provisions contained in our various borrowing agreements.

On August 1, 2011, we entered into the five-year, $1.2 billion Partnership 2011 Credit Agreement, which replaced the $1.0 billion Partnership Credit Agreement that was due to expire in March 2012. Our Partnership 2011 Credit Agreement, which is scheduled to expire in August 2016, contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in our Partnership 2011

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Credit Agreement, adjusted for all noncash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5.0 to 1. If we consummate one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will increase to 5.5 to 1 for the three calendar quarters following the acquisitions. Upon breach of certain covenants by us in our Partnership 2011 Credit Agreement, amounts outstanding under our Partnership 2011 Credit Agreement, if any, may become due and payable immediately.

Our Partnership 2011 Credit Agreement includes a $100-million sublimit for the issuance of standby letters of credit and also features an option permitting us to increase the size of the facility to an aggregate of $1.7 billion by either commitments from new lenders or increased commitments from existing lenders.

Our Partnership 2011 Credit Agreement is available to repay commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowings available under our Partnership 2011 Credit Agreement. The Partnership 2011 Credit Agreement contains provisions for an applicable margin rate and an annual facility fee, both of which adjust with changes in our credit rating. Borrowings, if any, will accrue at LIBOR plus 130 basis points, and the annual facility fee is 20 basis points based on our current credit rating. Our Partnership 2011 Credit Agreement is guaranteed fully and unconditionally by the Intermediate Partnership. Borrowings under our Partnership 2011 Credit Agreement are nonrecourse to our general partner.

In October 2011, we increased the size of our commercial paper program to $1.2 billion.

At September 30, 2011, our ratio of indebtedness to adjusted EBITDA was 3.4 to 1, and we were in compliance with all covenants under our Partnership Credit Agreement.

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

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

We intend to repay our $350 million of 5.9-percent senior notes that mature in April 2012 with a combination of cash on hand and short-term borrowings.

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Interest-rate swaps - At September 30, 2011, we had forward-starting interest-rate swaps with a total notional amount of $750 million. The purpose of these swaps is to hedge the variability of interest payments on a portion of a forecasted debt issuance that may result from changes in the benchmark interest rate before the debt is issued.

Capital Expenditures - Our capital expenditures are financed typically through operating cash flows, short- and long-term debt and the issuance of equity. Capital expenditures were $662.4 million and $202.8 million for the nine months ended September 30, 2011 and 2010, respectively. We classify expenditures that are expected to generate additional revenue or significant operating efficiencies as growth capital expenditures. Maintenance capital expenditures are those required to maintain existing operations and do not generate additional revenues.

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

2011 Projected Capital Expenditures	Growth		Maintenance		Total
	(Millions of dollars)
Natural Gas Gathering and Processing	$	598	$	23	$	621
Natural Gas Pipelines		6		30		36
Natural Gas Liquids		485		43		528
Other		-		1		1
Total projected capital expenditures	$	1,089	$	97	$	1,186

Unconsolidated Affiliates - In July 2011, the partners of Northern Border Pipeline made equity contributions of approximately $99.6 million, with our share totaling approximately $49.8 million. We do not anticipate additional significant equity contributions in 2011.

The members of Overland Pass Pipeline Company expect to make contributions primarily in 2012 totaling approximately $70 million to $80 million, with our share expected to be approximately $35 million to $40 million, to install additional pump stations and to expand existing pump stations to increase the capacity of the pipeline to accommodate increased volumes of unfractionated NGLs from the Bakken Pipeline and other supply sources under development in the Rockies.

Other - Previously, we had a Processing and Services Agreement with ONEOK and OBPI, under which we contracted for all of OBPI’s rights, including all of the capacity of the Bushton Plant, reimbursing OBPI for all costs associated with the operation and maintenance of the Bushton Plant and its obligations under equipment leases covering portions of the Bushton Plant. In April 2011, pursuant to our rights under the Processing and Services Agreement, we directed OBPI to give notice of intent to exercise the purchase option for the leased equipment pursuant to the terms of the equipment leases. On June 30, 2011, we acquired OBPI and OBPI closed the purchase option and terminated the equipment lease agreements. The total amount paid by us to complete the transactions was approximately $94.2 million, which included the reimbursement to ONEOK of obligations related to the Processing and Services Agreement.

Credit Ratings - Our long-term debt credit ratings as of September 30, 2011, are shown in the table below:

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

Our commercial paper program is rated Prime-2 by Moody’s and A2 by Standard & Poor’s Financial Services LLC. Our credit ratings, which are currently investment grade, may be affected by a material change in our financial ratios or a material event affecting our business. The most common criteria for assessment of our credit ratings are the debt-to-EBITDA ratio, interest coverage, business risk profile and liquidity. We do not anticipate a downgrade in our credit ratings; however, if our credit ratings were downgraded, our cost to borrow funds under our commercial paper program or Partnership Credit Agreement would increase, and a potential loss of access to the commercial paper market could occur. In the event that we are unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we would continue to have access to our Partnership 2011 Credit Agreement. An adverse rating change alone is not a default under our Partnership 2011 Credit Agreement.

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

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

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,
	2011		2010
	(Millions of dollars)
Common unitholders	$	226.3	$	211.8
Class B unitholders		126.3		121.5
General partner		98.9		84.1
Noncontrolling interests		0.3		-
Total cash distributions paid	$	451.8	$	417.4

In the nine months ended September 30, 2011 and 2010, cash distributions paid to our general partner included incentive distributions of $89.8 million and $75.8 million, respectively.

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

Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity prices may impact our overall liquidity due to the impact commodity price changes have on our cash flows from operating activities, including the impact on working capital for NGLs and natural gas held in storage, margin requirements and certain energy-related receivables. We believe that our available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity price volatility. See Note C of the Notes to Consolidated Financial Statements and the discussion under Natural Gas Gathering and Processing’s “Commodity Price Risk” in Part I, 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						Variance
	September 30,						2011 vs. 2010
	2011			2010			Increase (Decrease)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	655.3		$	316.8		$	338.5
Investing activities		(697.1	)		229.2			(926.3	)
Financing activities		168.8			(544.2	)		713.0
Change in cash and cash equivalents		127.0			1.8			125.2
Cash and cash equivalents at beginning of period		0.9			3.2			(2.3	)
Cash and cash equivalents at end of period	$	127.9		$	5.0		$	122.9

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Operating Cash Flows - Operating cash flows are affected by earnings from our business activities. Changes in commodity prices and demand for our services or products, whether because of general economic conditions, changes in demand for the end products that are made with our products or 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 $661.5 million for the nine months ended September 30, 2011, compared with $451.4 million for the same period in 2010. The increase was due primarily to changes in net margin and operating expenses discussed in Financial Results and Operating Information in Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Quarterly Report, offset partially by an increase in undistributed earnings from our unconsolidated affiliates.

The changes in operating assets and liabilities decreased operating cash flows $6.2 million for the nine months ended September 30, 2011, compared with a decrease of $134.5 million for the same period in 2010. The change is due largely to the change in accounts receivable resulting from higher revenues and the timing of invoicing customers and receipt of cash, as well as accounts payable and the timing of the receipt of invoices from and payments to vendors and suppliers, which vary from period to period. Additionally we had a decrease in volumes of NGLs in storage in the current period compared with an increase in volumes in storage during the same period last year in our Natural Gas Liquids segment.

Investing Cash Flows - Cash used in investing activities increased for the nine months ended September 30, 2011, compared with the same period in 2010, due primarily to increased capital expenditures on our growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments and the purchase of leased equipment at our Bushton Plant.

Financing Cash Flows - Cash provided by financing activities increased during the nine months ended September 30, 2011, compared with the same period in 2010. The change is a result of our January 2011 debt issuance, a portion of the proceeds from which were used to repay short-term borrowings and the scheduled maturity of long-term debt. The remainder of the proceeds are used to fund our capital projects and for general partnership purposes. Additionally, we paid increased distributions to our general and limited partners as a result of increased available cash.

REGULATORY

ENVIRONMENTAL AND SAFETY MATTERS

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

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Pipeline Safety - We are subject to Pipeline and Hazardous Materials Safety Administration regulations, including integrity- management regulations. The Pipeline Safety Improvement Act of 2002 requires pipeline companies operating high-pressure pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. In January 2011, the Pipeline and Hazardous Materials Safety Administration issued an “Advisory Bulletin” regarding maximum allowable operating pressure for natural gas and hazardous liquids pipelines. This bulletin requests that all operators review pipeline records and data to validate existing maximum pressure determinations. Currently, Congress is considering reauthorization of existing pipeline safety legislation. The Pipeline Transportation Safety Improvement Act of 2011 was passed by the Senate in late October. The House Energy and Commerce Committee and the House Transportation and Infrastructure Committee have passed similar bills that will be combined to form the House’s version to present at conference with the Senate.

We are monitoring activity concerning reauthorization, proposed new legislation and potential changes in the Pipeline and Hazardous Materials Safety Administration’s regulations, to assess the potential impact on our operations. At this time, our review of records relating to maximum pressure determinations is on-going and no revised or new legislation has been enacted resulting in any potential cost, fees or expenses associated with these issues. We cannot provide assurance that existing pipeline safety regulations will not be revised or interpreted in a different manner or that new regulations will not be adopted that could result in increased compliance costs or additional operating restrictions.

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

Federal, state and regional initiatives to measure and regulate greenhouse gas emissions are under way. We are monitoring federal and state legislation to assess the potential impact on our operations. The EPA’s Mandatory Greenhouse Gas Reporting Rule released in September 2009 requires greenhouse gas emissions reporting for affected facilities on an annual basis and requires us to track the emission equivalents for all NGLs delivered to our customers. Our 2010 total reported emissions was less than 53.2 million metric tons of carbon dioxide equivalents. This total includes direct emissions from the combustion of fuel in our equipment such as compressor engines and heaters and carbon dioxide equivalents from NGL products delivered to customers, as if all such fuel and NGL products were combusted and the resulting carbon dioxide was injected directly into disposal wells. The next required reporting period for 2011 greenhouse gas emissions will be due March 31, 2012. Also, the EPA released a subpart to the Mandatory Greenhouse Gas Reporting Rule that will require the reporting of vented and fugitive emissions of methane from our facilities. The new requirements began in January 2011, with the first reporting of fugitive emissions due September 30, 2012. We do not expect the cost to gather this emission data to have a material impact on our results of operations, financial position or cash flows. In addition, Congress has considered and may consider in the future legislation to reduce greenhouse gas emissions, including carbon dioxide and methane. At this time, no rule or legislation has been enacted that assess any costs, fees or expense on any of these emissions.

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

In addition, the EPA 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 two 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.

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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. Recently, we received notice from the EPA of potential liability at the U.S. Oil Recovery Superfund Site location in Harris County, Texas. We are named a potentially responsible party as a result of waste disposal at the now-abandoned site. We do not expect our current responsibilities under CERCLA, for this facility or any other, to have a material impact on our results of operations, financial position or cash flows.

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

Pipeline Security - Homeland Security’s Transportation Security Administration, along with the United States Department of Transportation, has completed a review and inspection of our “critical facilities” and identified no material security issues. Also, the Transportation Security Administration has released new pipeline security guidelines that include broader definitions for the determination of pipeline “critical facilities.” We are currently reviewing our pipeline facilities according to the new guideline requirements and do not expect significant or material changes to result.

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

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

IMPACT OF NEW ACCOUNTING STANDARDS

See Note A of the Notes to Consolidated Financial Statements for discussion of new accounting standards.

ESTIMATES AND CRITICAL ACCOUNTING POLICIES

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

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Information about our critical accounting policies and estimates is included under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Estimates and Critical Accounting Policies,” in our Annual Report.

FORWARD-LOOKING STATEMENTS

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

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

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

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

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

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

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

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

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

·	the results of administrative proceedings and litigation, regulatory actions, rule changes and receipt of expected clearances involving the OCC, Kansas Corporation Commission, Texas regulatory authorities or any other local,

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state or federal regulatory body, including the FERC, the National Transportation Safety Board, the Pipeline and Hazardous Materials Safety Administration, the EPA and CFTC;

·	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 United States or international economies, including liquidity risks in United States or foreign 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 uncontracted capacity in our assets 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.

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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 Part I, 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, 2011, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

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

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Not Applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not Applicable.

ITEM 4. (REMOVED AND RESERVED)

Not Applicable.

ITEM 5. OTHER INFORMATION

Not Applicable.

ITEM 6. EXHIBITS

Readers of this report should not rely on or assume the accuracy of any representation or warranty or the validity of any opinion conotained 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.

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

Exhibit No.

Exhibit Description

31.1

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

31.2

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

32.1

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

32.2

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

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema Document.

101.CAL

XBRL Taxonomy Calculation Linkbase Document.

101.DEF

XBRL Taxonomy Extension Definitions Document.

101.LAB

XBRL Taxonomy Label Linkbase Document.

101.PRE

XBRL Taxonomy Presentation Linkbase Document.

Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in XBRL: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three and nine months ended September 30, 2011 and 2010; (iii) Consolidated Balance Sheets at September 30, 2011, and December 31, 2010; (iv) Consolidated Statements of Cash Flows for the nine months ended September 30, 2011 and 2010; (v) Consolidated Statement of Changes in Equity for the nine months ended September 30, 2011; (vi) Consolidated Statements of Comprehensive Income for the nine months ended September 30, 2011 and 2010; and (vii) Notes to Consolidated Financial Statements.

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

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

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SIGNATURE

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

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

Date: November 2, 2011		By: /s/ Robert F. Martinovich
		Robert F. Martinovich
		Senior Vice President,
		Chief Financial Officer and Treasurer
		(Signing on behalf of the Registrant
		and as Principal Financial Officer)