Edgar Filing: ONEOK INC /NEW/

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 001-13643

ONEOK, Inc.

(Exact name of registrant as specified in its charter)

Oklahoma	73-1520922
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

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

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

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

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

Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes X No __

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

Yes __ No X

On October 27, 2011, the Company had 102,989,141 shares of common stock outstanding.

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ONEOK, Inc.

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	6-7

	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2011 and 2010	9

	Consolidated Statement of Changes in Equity - Nine Months Ended September 30, 2011	10-11

	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2011 and 2010	12

	Notes to Consolidated Financial Statements	13-33

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34-55

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	56

Item 4.	Controls and Procedures	57

Part II.	Other Information

Item 1.	Legal Proceedings	57

Item 1A.	Risk Factors	57

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	58

Item 3.	Defaults Upon Senior Securities	58

Item 4.	(Removed and Reserved)	58

Item 5.	Other Information	58

Item 6.	Exhibits	58-59

Signature		60

As used in this Quarterly Report, references to “we,” “our” or “us” refer to ONEOK, Inc., an Oklahoma corporation, and its predecessors and 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, 1 barrel is equivalent to 42 United States gallons

Bbl/d

Barrels per day

BBtu/d

Billion British thermal units per day

Bcf

Billion cubic feet

Bcf/d

Billion cubic feet per day

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 expense, income 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

KCC

Kansas Corporation Commission

KDHE

Kansas Department of Health and Environment

LDCs

Local distribution companies

LIBOR

London Interbank Offered Rate

MBbl

Thousand barrels

MBbl/d

Thousand barrels per day

Mcf

Thousand cubic feet

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

Million cubic feet

MMcf/d

Million cubic feet per day

Moody’s

Moody’s Investors Service, Inc.

Natural Gas Policy Act

Natural Gas Policy Act of 1978, as amended

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 2011 Credit Agreement

ONEOK’s five-year, $1.2 billion revolving credit agreement dated April 5, 2011

ONEOK Credit Agreement

ONEOK’s amended and restated $1.2 billion revolving credit agreement dated

July 14, 2006

ONEOK Partners

ONEOK Partners, L.P.

ONEOK Partners 2011 Credit Agreement

ONEOK Partners’ five-year, $1.2 billion revolving credit agreement dated

August 1, 2011

ONEOK Partners Credit Agreement

ONEOK Partners' $1.0 billion amended and restated revolving credit agreement

dated March 30, 2007

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ONEOK Partners GP

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

sole general partner of ONEOK Partners

OPIS

Oil Price Information Service

Overland Pass Pipeline Company

Overland Pass Pipeline Company LLC

Quarterly Report(s)

Quarterly Report(s) on Form 10-Q

RRC

Railroad Commission of Texas

S&P

Standard & Poor’s Financial Services LLC

SEC

Securities and Exchange Commission

Securities Act

Securities Act of 1933, as amended

XBRL

eXtensible Business Reporting Language

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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ONEOK, Inc. 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 share amounts)

Revenues	$	3,595,191		$	2,942,703		$	10,976,555		$	9,673,802
Cost of sales and fuel		3,061,198			2,491,333			9,287,365			8,145,035
Net margin		533,993			451,370			1,689,190			1,528,767
Operating expenses
Operations and maintenance		186,935			183,893			581,338			542,643
Depreciation and amortization		75,986			77,234			234,201			230,600
General taxes		22,122			19,465			77,026			67,643
Total operating expenses		285,043			280,592			892,565			840,886
Gain (loss) on sale of assets		(69	)		16,126			(791	)		15,068
Operating income		248,881			186,904			795,834			702,949
Equity earnings from investments (Note J)		32,029			29,390			93,665			71,182
Allowance for equity funds used during construction		759			266			1,625			748
Other income		124			6,710			1,027			4,966
Other expense		(13,318	)		(2,097	)		(13,571	)		(5,338	)
Interest expense		(73,841	)		(70,907	)		(228,688	)		(222,788	)
Income before income taxes		194,634			150,266			649,892			551,719
Income taxes		(33,754	)		(29,965	)		(154,900	)		(158,324	)
Net income		160,880			120,301			494,992			393,395
Less: Net income attributable to noncontrolling interests		100,559			65,006			249,399			141,837
Net income attributable to ONEOK	$	60,321		$	55,295		$	245,593		$	251,558

Earnings per share of common stock (Note H)
Net earnings per share, basic	$	0.58		$	0.52		$	2.33		$	2.37
Net earnings per share, diluted	$	0.57		$	0.51		$	2.28		$	2.34

Average shares of common stock (thousands)
Basic		103,303			106,443			105,220			106,310
Diluted		105,970			107,651			107,727			107,415

Dividends declared per share of common stock	$	0.56		$	0.46		$	1.60		$	1.34
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	September 30,		December 31,
(Unaudited)	2011		2010
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	148,407	$	31,034
Accounts receivable, net		1,141,132		1,332,726
Gas and natural gas liquids in storage		658,059		708,933
Commodity imbalances		105,884		94,854
Energy marketing and risk management assets (Notes B and C)		56,301		61,940
Other current assets		202,260		149,558
Total current assets		2,312,043		2,379,045

Property, plant and equipment
Property, plant and equipment		10,709,417		9,854,485
Accumulated depreciation and amortization		2,690,104		2,541,302
Net property, plant and equipment		8,019,313		7,313,183

Investments and other assets
Goodwill and intangible assets		1,016,044		1,022,894
Energy marketing and risk management assets (Notes B and C)		24,232		1,921
Investments in unconsolidated affiliates (Note J)		1,224,397		1,188,124
Other assets		575,095		594,008
Total investments and other assets		2,839,768		2,806,947
Total assets	$	13,171,124	$	12,499,175
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	September 30,			December 31,
(Unaudited)	2011			2010
Liabilities and equity	(Thousands of dollars)
Current liabilities
Current maturities of long-term debt	$	365,253		$	643,236
Notes payable (Note D)		650,000			556,855
Accounts payable		1,241,633			1,215,468
Commodity imbalances		236,365			288,494
Energy marketing and risk management liabilities (Notes B and C)		130,993			22,800
Other current liabilities		352,520			424,259
Total current liabilities		2,976,764			3,151,112

Long-term debt, excluding current maturities (Note E)		4,532,053			3,686,542

Deferred credits and other liabilities
Deferred income taxes		1,386,959			1,171,997
Energy marketing and risk management liabilities (Notes B and C)		1,135			2,221
Other deferred credits		592,153			566,462
Total deferred credits and other liabilities		1,980,247			1,740,680

Commitments and contingencies (Note L)

Equity (Note F)
ONEOK shareholders' equity:
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 122,895,643 shares and outstanding
102,982,759 shares at September 30, 2011; issued 122,815,636 shares and
outstanding 106,815,582 shares at December 31, 2010		1,229			1,228
Paid-in capital		1,404,087			1,392,671
Accumulated other comprehensive loss (Note G)		(174,573	)		(108,802	)
Retained earnings		1,903,056			1,826,800
Treasury stock, at cost: 19,912,884 shares at September 30, 2011 and
16,000,054 shares at December 31, 2010		(947,839	)		(663,274	)
Total ONEOK shareholders' equity		2,185,960			2,448,623

Noncontrolling interests in consolidated subsidiaries		1,496,100			1,472,218

Total equity		3,682,060			3,920,841
Total liabilities and equity	$	13,171,124		$	12,499,175
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS	Nine Months Ended
	September 30,
(Unaudited)	2011			2010
	(Thousands of dollars)
Operating Activities
Net income	$	494,992		$	393,395
Depreciation and amortization		234,201			230,600
Allowance for equity funds used during construction		(1,625	)		(748	)
Loss (gain) on sale of assets		791			(15,068	)
Equity earnings from investments		(93,665	)		(71,182	)
Distributions received from unconsolidated affiliates		87,151			69,889
Deferred income taxes		200,961			94,997
Share-based compensation expense		39,297			15,949
Other		(1,260	)		3,853
Changes in assets and liabilities:
Accounts receivable		194,631			567,141
Gas and natural gas liquids in storage		26,975			(158,873	)
Accounts payable		(401	)		(363,285	)
Commodity imbalances, net		(63,159	)		(71,840	)
Unrecovered purchased gas costs		(28,676	)		72,431
Energy marketing and risk management assets and liabilities		(12,705	)		118,319
Fair value of firm commitments		(18,204	)		(91,575	)
Other assets and liabilities		(29,685	)		(33,972	)
Cash provided by operating activities		1,029,619			760,031
Investing Activities
Capital expenditures (less allowance for equity funds used during construction)		(862,310	)		(356,289	)
Distributions received from unconsolidated affiliates		16,158			9,342
Contributions to unconsolidated affiliates		(51,686	)		(1,313	)
Proceeds from sale of assets		951			424,740
Other		-			2,968
Cash provided by (used in) investing activities		(896,887	)		79,448
Financing Activities
Borrowing (repayment) of notes payable, net		93,145			(555,485	)
Issuance of debt, net of discounts		1,295,450			-
Long-term debt financing costs		(10,986	)		-
Payment of debt		(724,405	)		(259,648	)
Repurchase of common stock		(300,108	)		(5	)
Issuance of common stock		7,142			9,357
Issuance of common units, net of discounts		-			322,701
Dividends paid		(169,337	)		(142,426	)
Distributions to noncontrolling interests		(206,260	)		(192,889	)
Cash used in financing activities		(15,359	)		(818,395	)
Change in cash and cash equivalents		117,373			21,084
Cash and cash equivalents at beginning of period		31,034			29,399
Cash and cash equivalents at end of period	$	148,407		$	50,483
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY


	ONEOK Shareholders' Equity
								Accumulated
	Common							Other
	Stock			Common		Paid-in		Comprehensive
(Unaudited)	Issued			Stock		Capital		Loss
	(Shares)		(Thousands of dollars)

December 31, 2010		122,815,636		$	1,228	$	1,392,671	$	(108,802	)
Net income		-			-		-		-
Other comprehensive loss		-			-		-		(65,771	)
Repurchase of common stock		-			-		-		-
Common stock issued		80,007			1		11,416		-
Common stock dividends -
$1.60 per share		-			-		-		-
Distributions to noncontrolling interests		-			-		-		-
September 30, 2011		122,895,643		$	1,229	$	1,404,087	$	(174,573	)
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Continued)

	ONEOK Shareholders' Equity
							Noncontrolling
							Interests in
	Retained			Treasury			Consolidated			Total
(Unaudited)	Earnings			Stock			Subsidiaries			Equity
	(Thousands of dollars)

December 31, 2010	$	1,826,800		$	(663,274	)	$	1,472,218		$	3,920,841
Net income		245,593			-			249,399			494,992
Other comprehensive loss		-			-			(19,257	)		(85,028	)
Repurchase of common stock		-			(300,108	)		-			(300,108	)
Common stock issued		-			15,543			-			26,960
Common stock dividends -
$1.60 per share		(169,337	)		-			-			(169,337	)
Distributions to noncontrolling interests		-			-			(206,260	)		(206,260	)
September 30, 2011	$	1,903,056		$	(947,839	)	$	1,496,100		$	3,682,060

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ONEOK, Inc. 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	$	160,880		$	120,301		$	494,992		$	393,395
Other comprehensive income (loss), net of tax
Unrealized gains (losses) on energy marketing and risk management
assets/liabilities, net of tax of $14,194, $(24,044), $10,487 and
$(47,571), respectively		(37,842	)		39,808			(38,004	)		97,334
Realized gains in net income, net of tax of $10,193, $13,119,
$22,127 and $21,889, respectively		(15,814	)		(23,091	)		(32,522	)		(34,866	)
Unrealized holding losses on available-for-sale securities,
net of tax of $31, $65, $234 and $234, respectively		(331	)		(104	)		(370	)		(370	)
Change in pension and postretirement benefit plan liability, net of tax
of $2,947, $2,533, $8,842 and $7,599, respectively		(4,672	)		(4,016	)		(14,017	)		(12,048	)
Other, net of tax of $11, $(11), $73 and $(34), respectively		(18	)		18			(115	)		53
Total other comprehensive income (loss), net of tax		(58,677	)		12,615			(85,028	)		50,103
Comprehensive income		102,203			132,916			409,964			443,498
Less: Comprehensive income attributable to noncontrolling interests		85,189			64,403			230,142			163,595
Comprehensive income attributable to ONEOK	$	17,014		$	68,513		$	179,822		$	279,903
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, INC. 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. Due to the seasonal nature of our business, the results of operations for the three and nine months ended September 30, 2011, are not necessarily indicative of the results that may be expected for a 12-month period.

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

Goodwill and Indefinite-lived Intangible Assets Impairment Tests - We assess our goodwill and indefinite-lived intangible assets for impairment at least annually on July 1. Our July 1, 2011, estimates of the fair value of each of our reporting units and indefinite-lived assets significantly exceeded their carrying values. Accordingly, no impairment charges were necessary.

Recently Issued Accounting Standards Updates - 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 market and income approaches to determine the fair value of our 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. Inputs into our fair value estimates include commodity exchange prices, over-the-counter quotes, volatility, historical correlations of pricing data and LIBOR, and other liquid money market instrument rates. We also utilize internally developed basis curves that incorporate observable and unobservable market data. We validate our valuation inputs with third-party information and

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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 interest-rate yields to calculate present-value discount factors derived from LIBOR, Eurodollar futures and interest-rate swaps. We also take into consideration the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions. We consider current market data in evaluating counterparties’, as well as our own, nonperformance risk, net of collateral, by using specific and sector bond yields and also monitoring the credit default swap markets. 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 material.

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

	September 30, 2011
	Level 1			Level 2			Level 3			Netting			Total
Assets	(Thousands of dollars)
Derivatives (a)
Commodity contracts
Financial contracts	$	217,739		$	32,689		$	56,505		$	-		$	306,933
Physical contracts		-			10,225			16,220			-			26,445
Netting		-			-			-			(252,845	)		(252,845	)
Total derivatives		217,739			42,914			72,725			(252,845	)		80,533
Trading securities (b)		5,814			-			-			-			5,814
Available-for-sale investment securities (c)		1,971			-			-			-			1,971
Total assets	$	225,524		$	42,914		$	72,725		$	(252,845	)	$	88,318

Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(192,313	)	$	(1,985	)	$	(44,058	)	$	-		$	(238,356	)
Physical contracts		-			(1,001	)		(2,934	)		-			(3,935	)
Netting		-			-			-			222,416			222,416
Interest-rate contracts		-			(112,253	)		-			-			(112,253	)
Total derivatives		(192,313	)		(115,239	)		(46,992	)		222,416			(132,128	)
Fair value of firm commitments (d)		-			-			(11,331	)		-			(11,331	)
Total liabilities	$	(192,313	)	$	(115,239	)	$	(58,323	)	$	222,416		$	(143,459	)
(a) - Included in our Consolidated Balance Sheets as energy marketing and risk management assets and liabilities on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At September 30, 2011, we held $30.4 million of cash collateral from various counterparties.
(b) - Included in our Consolidated Balance Sheets as other current assets.
(c) - Included in our Consolidated Balance Sheets as other assets.
(d) - Included in our Consolidated Balance Sheets as other current liabilities and other deferred credits.

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	December 31, 2010
	Level 1			Level 2			Level 3			Netting			Total
Assets	(Thousands of dollars)
Derivatives (a)
Commodity contracts
Financial contracts	$	127,789		$	1,755		$	152,639		$	-		$	282,183
Physical contracts		-			13,185			20,391			-			33,576
Netting		-			-			-			(251,898	)		(251,898	)
Total derivatives		127,789			14,940			173,030			(251,898	)		63,861
Trading securities (b)		7,591			-			-			-			7,591
Available-for-sale investment securities (c)		2,574			-			-			-			2,574
Total assets	$	137,954		$	14,940		$	173,030		$	(251,898	)	$	74,026

Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(64,768	)	$	(3,241	)	$	(119,430	)	$	-		$	(187,439	)
Physical contracts		-			(3,763	)		(4,334	)		-			(8,097	)
Netting		-			-			-			170,515			170,515
Total derivatives		(64,768	)		(7,004	)		(123,764	)		170,515			(25,021	)
Fair value of firm commitments (d)		-			-			(29,536	)		-			(29,536	)
Total liabilities	$	(64,768	)	$	(7,004	)	$	(153,300	)	$	170,515		$	(54,557	)
(a) - Included in our Consolidated Balance Sheets as energy marketing and risk management assets and liabilities on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2010, we held $82.5 million of cash collateral and posted $1.1 million of cash collateral with various counterparties.
(b) - Included in our Consolidated Balance Sheets as other current assets.
(c) - Included in our Consolidated Balance Sheets as other assets.
(d) - Included in our Consolidated Balance Sheets as other current liabilities and other deferred credits.

Our Level 1 fair value measurements are based on NYMEX-settled prices and actively quoted prices for equity securities. These balances are comprised predominantly of exchange-traded derivative contracts, including futures and certain options for natural gas and crude oil, which are valued based on unadjusted quoted prices in active markets. Also included in Level 1 are equity securities.

Our Level 2 fair value inputs are based on NYMEX-settled prices for natural gas and crude oil that are utilized to determine the fair value of certain non-exchange-traded financial instruments, including natural gas and crude oil swaps, as well as physical forwards. Also, included in Level 2 are 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 swap settlements.

Our Level 3 inputs include internally developed basis curves incorporating observable and unobservable market data, NGL price curves from a pricing service, historical correlations of NGL product prices to published NYMEX crude oil prices, market volatilities derived from the most recent NYMEX close spot prices and forward LIBOR curves, and adjustments for the credit risk of our counterparties. We corroborate the data on which our fair value estimates are based using our market knowledge of recent transactions, analysis of historical correlations and validation with independent broker quotes or a pricing service. The derivatives categorized as Level 3 include natural gas basis swaps, swing swaps, options, other commodity swaps and physical forward contracts. Also included in Level 3 are the fair values of firm commitments. We do not believe that our Level 3 fair value estimates have a material impact on our results of operations, as the majority of our derivatives are accounted for as hedges for which ineffectiveness is not material.

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The following tables set forth the reconciliation of our Level 3 fair value measurements for the periods indicated:

	Derivative Assets (Liabilities)			Fair Value of Firm Commitments			Total
	(Thousands of dollars)
July 1, 2011	$	23,858		$	(21,212	)	$	2,646
Total realized/unrealized gains (losses):
Included in earnings (a)		(5,444	)		9,881			4,437
Included in other comprehensive income (loss)		9,717			-			9,717
Transfers into Level 3		1,284			-			1,284
Transfers out of Level 3		(3,682	)		-			(3,682	)
September 30, 2011	$	25,733		$	(11,331	)	$	14,402

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 September 30, 2011 (a)	$	14,115		$	(3,229	)	$	10,886
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.

	Derivative Assets (Liabilities)			Fair Value of Firm Commitments			Total
	(Thousands of dollars)
July 1, 2010	$	89,112		$	(65,653	)	$	23,459
Total realized/unrealized gains (losses):
Included in earnings (a)		(12,885	)		22,608			9,723
Included in other comprehensive income (loss)		(8,161	)		-			(8,161	)
Transfers into Level 3		-			-			-
Transfers out of Level 3		(3,483	)		-			(3,483	)
September 30, 2010	$	64,583		$	(43,045	)	$	21,538

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 September 30, 2010 (a)	$	15,542		$	(8,655	)	$	6,887
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.

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	Derivative Assets (Liabilities)			Fair Value of Firm Commitments			Total
	(Thousands of dollars)
January 1, 2011	$	49,266		$	(29,536	)	$	19,730
Total realized/unrealized gains (losses):
Included in earnings (a)		(28,352	)		18,205			(10,147	)
Included in other comprehensive income (loss)		1,160			-			1,160
Transfers into Level 3		4,739			-			4,739
Transfers out of Level 3		(1,080	)		-			(1,080	)
September 30, 2011	$	25,733		$	(11,331	)	$	14,402

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 September 30, 2011 (a)	$	20,620		$	(6,978	)	$	13,642
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.

	Derivative Assets (Liabilities)			Fair Value of Firm Commitments			Total
	(Thousands of dollars)
January 1, 2010	$	136,694		$	(134,620	)	$	2,074
Total realized/unrealized gains (losses):
Included in earnings (a)		(69,241	)		91,575			22,334
Included in other comprehensive income (loss)		13,544			-			13,544
Transfers into Level 3		1,342			-			1,342
Transfers out of Level 3		(17,756	)		-			(17,756	)
September 30, 2010	$	64,583		$	(43,045	)	$	21,538

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 September 30, 2010 (a)	$	15,513		$	208		$	15,721
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.

Realized/unrealized gains (losses) include the realization of our derivative contracts through maturity and changes in fair value of our hedged firm commitments. We recognize transfers into and out of Level 3 as of the end of each reporting period. Transfers into Level 3 represent existing assets or liabilities that were previously categorized at a higher level for which the unobservable inputs became a more significant portion of the fair value estimates. Transfers out of Level 3 represent existing assets and liabilities that were classified previously as Level 3 for which the observable inputs became a more significant portion of the fair value estimates.

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 our consolidated long-term debt, including current maturities, was $5.4 billion at September 30, 2011, and $4.7 billion at December 31, 2010. The book value of long-term debt, including current maturities, was $4.9 billion and $4.3 billion at September 30, 2011, and December 31, 2010, respectively. The estimated fair value of long-term debt has been determined using quoted market prices of ONEOK’s and ONEOK Partners’ senior notes or similar issues with similar terms and maturities.

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C. RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

Our Energy Services and ONEOK Partners segments are exposed to various risks that we manage by periodically entering into derivative instruments. These risks include the following:

Commodity price risk - We are exposed to the risk of loss in cash flows and future earnings arising from adverse changes in the price of natural gas, NGLs and crude oil. We use commodity derivative instruments such as futures, physical forward contracts, swaps and options to reduce the commodity price risk associated with a portion of the forecasted purchases and sales of commodities and natural gas and natural gas liquids in storage. Commodity price volatility may have a significant impact on the fair value of our derivative instruments as of a given date;

Basis risk - We are exposed to the risk of loss in cash flows and future earnings arising from adverse changes in the price differentials between pipeline receipt and delivery locations. Our firm transportation capacity allows us to purchase natural gas at a pipeline receipt point and sell natural gas at a pipeline delivery point. As market conditions permit, our Energy Services segment periodically enters into basis swaps between the transportation receipt and delivery points in order to protect the fair value of these location price differentials related to our firm commitments;

Currency exchange rate risk - As a result of our Energy Services segment’s activities in Canada, we are exposed to the risk of loss in cash flows and future earnings from adverse changes in currency exchange rates on our commodity purchases and sales, primarily related to our firm transportation and storage contracts that are transacted in a currency other than our functional currency, the United States dollar. To reduce our exposure to exchange-rate fluctuations, we use physical forward transactions, which result in an actual two-way flow of currency on the settlement date in which we exchange United States dollars for Canadian dollars with another party; and

·	Interest-rate risk - We are also subject to fluctuations in interest rates. We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps.

The following derivative instruments are used to manage our exposure to these risks:

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

Forward contracts - Commitments to purchase or sell natural gas, crude oil or NGLs for physical delivery at some specified time in the future. We also use currency forward contracts to manage our currency exchange rate risk. Forward contracts are different from futures in that forwards are customized and nonexchange traded;

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 movements in market prices, while the other party assumes the risks and benefits of a fixed price for the commodity. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts; and

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

Our objectives for entering into such contracts include but are not limited to:

·	reducing the variability of cash flows by locking in the price for all or a portion of anticipated index-based physical purchases and sales, transportation fuel requirements, asset management transactions and customer-related business activities;

·	locking in a price differential to protect the fair value between transportation receipt and delivery points and to protect the fair value of natural gas or NGLs that are purchased in one month and sold in a later month;

·	reducing our exposure to fluctuations in interest and foreign currency exchange rates; and

·	reducing variability in cash flows from changes in interest rates associated with forecasted debt issuances.

Our Energy Services segment also enters into derivative contracts for financial trading purposes primarily to capitalize on opportunities created by market volatility, weather-related events, supply-demand imbalances and market liquidity inefficiencies, which allow us to capture additional margin. Financial trading activities are executed generally using financially settled derivatives and are normally short term in nature.

With respect to the net open positions that exist within our marketing and financial trading operations, fluctuating commodity prices can impact our financial position and results of operations. The net open positions are actively managed, and the impact of the changing prices on our financial condition at a point in time is not necessarily indicative of the impact of price movements throughout the year.

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Our Distribution segment also uses derivative instruments to hedge the cost of anticipated natural gas purchases during the winter heating months to protect our customers from upward volatility in the market price of natural gas. The use of these derivative instruments and the associated recovery of these costs have been approved by the OCC, KCC and regulatory authorities in certain of our Texas jurisdictions.

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

Accounting Treatment

We record all 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 hedging relationship and, if so, the reason for holding it.

If certain conditions are met, we may elect to designate a derivative instrument as a hedge of exposure to changes in fair values, cash flows or foreign currency. Certain nontrading derivative transactions, which are economic hedges of our accrual transactions such as our storage and transportation contracts, do not qualify for hedge accounting treatment.

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

Gains or losses associated with the fair value of derivative instruments entered into by our Distribution segment are included in, and recoverable through, the monthly purchased-gas cost mechanism.

We formally document all relationships between hedging instruments and hedged items, as well as risk-management objectives, strategies for undertaking various hedge transactions and methods for assessing and testing correlation and hedge ineffectiveness. We specifically identify the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item. We assess the effectiveness of hedging relationships quarterly by performing an effectiveness analysis on our cash flow and fair value 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 presentation of settled derivative instruments on either a gross or net basis in our Consolidated Statements of Income is dependent on the relevant facts and circumstances of our different types of activities rather than based solely on the terms of the individual contracts. All financially settled derivative instruments, as well as derivative instruments considered held for trading purposes that result in physical delivery, are reported on a net basis in revenues in our Consolidated Statements of Income. The realized revenues and purchase costs of derivative instruments that are not considered held for trading purposes and nonderivative contracts are reported on a gross basis. Derivatives that qualify as normal purchases or normal sales that are expected to result in physical delivery are also reported on a gross basis.

Revenues in our Consolidated Statements of Income include financial trading margins, as well as certain physical natural gas transactions with our trading counterparties. Revenues and cost of sales and fuel from such physical transactions are reported on a net basis.

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Cash flows from futures, forwards, options 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 Statements of Cash Flows.

Fair Values of Derivative Instruments - The following table sets forth the fair values of our derivative instruments for the periods indicated:

	September 30, 2011						December 31, 2010
	Fair Values of Derivatives (a)						Fair Values of Derivatives (a)
	Assets			(Liabilities)			Assets			(Liabilities)
Derivatives designated as hedging instruments	(Thousands of dollars)
Commodity contracts
Financial contracts	$	117,892	(b)	$	(37,965	)	$	136,040	(c)	$	(23,843	)
Physical contracts		68			(370	)		-			(883	)
Interest-rate contracts		-			(112,253	)		-			-
Total derivatives designated as hedging instruments		117,960			(150,588	)		136,040			(24,726	)
Derivatives not designated as hedging instruments
Commodity contracts
Nontrading instruments
Financial contracts		150,068			(163,150	)		125,503			(144,940	)
Physical contracts		26,377			(3,565	)		33,576			(7,214	)
Trading instruments
Financial contracts		38,973			(37,241	)		20,640			(18,656	)
Total derivatives not designated as hedging instruments		215,418			(203,956	)		179,719			(170,810	)
Total derivatives	$	333,378		$	(354,544	)	$	315,759		$	(195,536	)
(a) - Included on a net basis in energy marketing and risk management assets and liabilities on our Consolidated Balance Sheets.
(b) - Includes $23.9 million of derivative assets associated with cash flow hedges of inventory that were adjusted to reflect the lower of cost or market. The deferred gains associated with these assets have been reclassified from accumulated other comprehensive loss.
(c) - Includes $44.9 million of derivative assets associated with cash flow hedges of inventory that were adjusted to reflect the lower of cost or market value. The deferred gains associated with these assets have been reclassified from accumulated other comprehensive loss.

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)	Exchange futures		21.2	(28.2)	0.4	(7.6)
				Swaps		16.5	(66.4)	3.0	(69.9)
			- Crude oil and NGLs (MMBbl)	Swaps		-	(3.6)	-	(1.5)
		Basis
			- Natural gas (Bcf)	Forwards and swaps		2.3	(55.1)	2.8	(64.9)
		Interest-rate contracts (Millions of dollars)		Forward-starting swaps	$	1,250.0	-	-	-

	Fair value hedges
		Basis
			- Natural gas (Bcf)	Forwards and swaps		79.3	(79.3)	141.1	(141.1)

Derivatives not designated as hedging instruments:
		Fixed price
			- Natural gas (Bcf)	Exchange futures		77.3	(57.6)	34.6	(20.6)
				Forwards and swaps		235.7	(255.7)	73.6	(100.3)
				Options		86.5	(77.3)	81.0	(74.3)
			- Crude and NGLs (MMBbl)	Forwards and swaps		0.1	(0.1)	0.6	(0.6)
		Basis
			- Natural gas (Bcf)	Forwards and swaps		268.6	(273.6)	411.5	(419.7)
		Index
			- Natural gas (Bcf)	Forwards and swaps		33.5	(23.2)	33.6	(6.1)

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These notional amounts are used to summarize the volume of financial instruments; however, they do not reflect the extent to which the positions offset one another and consequently do not reflect our actual exposure to market or credit risk.

Cash Flow Hedges - Our Energy Services and ONEOK Partners segments use derivative instruments to hedge the cash flows associated with anticipated purchases and sales of natural gas, NGLs and condensate and cost of fuel used in the transportation of natural gas. Accumulated other comprehensive income (loss) at September 30, 2011, includes gains of approximately $11.6 million, net of tax, related to these hedges that will be recognized within the next 27 months as the forecasted transactions affect earnings. If prices remain at current levels, we will recognize $6.3 million in net gains over the next 12 months, and we will recognize net gains of $5.3 million thereafter. The amounts deferred in accumulated 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.

For the three and nine months ended September 30, 2011, cost of sales and fuel in our Consolidated Statements of Income includes $23.9 million, reflecting an adjustment to natural gas inventory at the lower of cost or market value. We reclassified this amount of deferred gains, before income taxes, on associated cash flow hedges from accumulated other comprehensive income (loss) into earnings in 2011.

For the three and nine months ended September 30, 2010, cost of sales and fuel in our Consolidated Statements of Income includes $47.4 million and $58.7 million, respectively, reflecting adjustments to natural gas inventory at the lower of cost or market value. We reclassified these amounts of deferred gains, before income taxes, on associated cash flow hedges from accumulated other comprehensive income (loss) into earnings in 2010.

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

	Three Months Ended					Nine Months Ended
Derivatives in Cash Flow Hedging Relationships	September 30,					September 30,
Derivatives in Cash Flow Hedging Relationships	2011			2010		2011			2010
	(Thousands of dollars)
Commodity contracts	$	60,217		$	63,852	$	63,762		$	144,905
Interest-rate contracts		(112,253	)		-		(112,253	)		-
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	$	(52,036	)	$	63,852	$	(48,491	)	$	144,905

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

	Location of Gain (Loss) Reclassified from Accumulated	Three Months Ended
Derivatives in Cash Flow	Other Comprehensive Income (Loss) into Net Income	September 30,
Hedging Relationships	(Effective Portion)	2011				2010
		(Thousands of dollars)
Commodity contracts	Revenues	$	2,416		$	9,830
Commodity contracts	Cost of sales and fuel		23,681			26,587
Interest-rate contracts	Interest expense		(90	)		(207	)
Total gain (loss) reclassified from accumulated other comprehensive income (loss)
into net income on derivatives (effective portion)		$	26,007		$	36,210

	Location of Gain (Loss) Reclassified from Accumulated		Nine Months Ended
Derivatives in Cash Flow	Other Comprehensive Income (Loss) into Net Income		September 30,
Hedging Relationships	(Effective Portion)		2011			2010
			(Thousands of dollars)
Commodity contracts	Revenues	$	32,292		$	11,243
Commodity contracts	Cost of sales and fuel		22,745			45,276
Interest-rate contracts	Interest expense		(388	)		236
Total gain (loss) reclassified from accumulated other comprehensive income (loss)
into net income on derivatives (effective portion)		$	54,649		$	56,755

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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 will discontinue cash flow hedge treatment, which will affect earnings. For the three and nine months ended September 30, 2011 and 2010, there were no gains or losses due to the discontinuance of cash flow hedge treatment because the underlying transactions were no longer probable.

Other Derivative Instruments - The following table sets forth the effect of our derivative instruments that are not part of a hedging relationship on our Consolidated Statements of Income for the periods indicated:

		Three Months Ended				Nine Months Ended
Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss)	September 30,				September 30,
Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss)	2011		2010		2011		2010
		(Thousands of dollars)
Commodity contracts - trading	Revenues	$	1,357	$	2,053	$	1,474	$	5,438
Commodity contracts - nontrading (a)	Cost of sales and fuel		4,991		2,559		15,498		4,931
Foreign exchange contracts	Revenues		-		27		-		17
Total gain recognized in income on derivatives		$	6,348	$	4,639	$	16,972	$	10,386
(a) - Amounts are presented net of deferred losses associated with derivatives entered into by our Distribution segment.

Our Distribution segment held natural gas call options with premiums totaling $12.8 million and $16.7 million at September 30, 2011, and December 31, 2010, respectively. The premiums are recorded in other current assets as these contracts are included in, and recoverable through, the monthly purchased-gas cost mechanism. For the three and nine months ended September 30, 2011, we recognized losses of $8.4 million and $11.5 million, respectively, associated with the decline in value and expiration of option contracts, which were deferred as part of the unrecognized purchased gas costs. For the three and nine months ended September 30, 2010, we recognized losses of $16.6 million and $22.0 million, respectively, associated with the decline in value and expiration of option contracts, which were deferred as part of our unrecognized purchased gas costs.

Fair Value Hedges - In prior years, we terminated various interest-rate swap agreements. The net savings from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged. Interest expense savings from the amortization of terminated swaps for the three months ended September 30, 2011 and 2010, were $0.6 million and $2.5 million, respectively, and for the nine months ended September 30, 2011 and 2010, were $3.9 million and $7.6 million, respectively.

Our Energy Services segment uses basis swaps to hedge the fair value of price location differentials related to certain firm transportation commitments. Cost of sales and fuel in our Consolidated Statements of Income includes gains of $3.3 million and $12.9 million for the three and nine months ended September 30, 2011, respectively, related to the change in fair value of derivatives designated as fair value hedges. The ineffectiveness related to these hedges was not material for the three and nine months ended September 30, 2011. Revenues include losses of $3.1 million and $12.5 million for the three and nine months ended September 30, 2011, respectively, to recognize the change in fair value of the related hedged firm commitments.

Cost of sales and fuel in our Consolidated Statements of Income includes gains of $4.6 million and $0.7 million for the three and nine months ended September 30, 2010, respectively, related to the change in fair value of derivatives designated as fair value hedges. The ineffectiveness related to these hedges was not material for the three and nine months ended September 30, 2010. Revenues include losses of $5.3 million and $1.2 million for the three and nine months ended September 30, 2010, respectively, to recognize the change in fair value of the related hedged firm commitments.

Credit Risk - We monitor the creditworthiness of our counterparties and compliance with policies and limits established by our Risk Oversight and Strategy Committee. We maintain credit policies with regard to our counterparties that we believe minimize overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings, bond yields and credit default swap rates), collateral requirements under certain circumstances and the use of standardized master-netting agreements that allow us to net the positive and negative exposures associated with a single counterparty. We have counterparties whose credit is not rated, and for those customers we use internally developed credit ratings.

Some of our derivative instruments contain provisions that require us to maintain an investment-grade credit rating from S&P and/or Moody’s. If our credit ratings on senior unsecured long-term debt were to decline below investment grade, we would be in violation of these provisions, and the counterparties to the derivative instruments could request collateralization on derivative instruments in net liability positions. The aggregate fair value of all financial derivative instruments with contingent features related to credit risk that were in a net liability position as of September 30, 2011, was $3.1 million. If

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the contingent features underlying these agreements were triggered on September 30, 2011, we would have been required to post the entire $3.1 million of collateral to our counterparties.

The counterparties to our derivative contracts consist primarily of major energy companies, LDCs, electric utilities, financial institutions and commercial and industrial end-users. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and other reserves, we do not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance.

The following tables set forth the net credit exposure from our derivative assets for the periods indicated:

	September 30, 2011
	Investment		Non-investment			Not
	Grade			Grade		Rated		Total
Counterparty sector	(Thousands of dollars)
Gas and electric utilities	$	15,735		$	266	$	274	$	16,275
Oil and gas		11,815			-		1,235		13,050
Industrial		-			-		7,770		7,770
Financial		43,436			-		-		43,436
Other		-			-		2		2
Total	$	70,986		$	266	$	9,281	$	80,533

	December 31, 2010
	Investment		Non-investment		Not
	Grade		Grade		Rated		Total
Counterparty sector	(Thousands of dollars)
Gas and electric utilities	$	33,847	$	1,240	$	678	$	35,765
Oil and gas		8,995		35		2,091		11,121
Industrial		18		-		7,682		7,700
Financial		9,254		-		-		9,254
Other		-		-		21		21
Total	$	52,114	$	1,275	$	10,472	$	63,861

D. CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

ONEOK 2011 Credit Agreement - In April 2011, ONEOK entered into the ONEOK 2011 Credit Agreement, which replaced the ONEOK Credit Agreement. Under the ONEOK 2011 Credit Agreement, which is scheduled to expire in April 2016, ONEOK is required to comply with certain financial, operational and legal covenants. Among other things, these requirements include:

·	a limitation on ONEOK’s stand-alone debt-to-capital ratio, which may not exceed 67.5 percent at the end of any calendar quarter;

·	limitations on the ratio of indebtedness secured by liens and indebtedness of subsidiaries to consolidated net tangible assets;

·	a requirement that ONEOK maintains the power to control the management and policies of ONEOK Partners; and

·	a limit on new investments in master limited partnerships.

The ONEOK 2011 Credit Agreement also contains customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in the nature of ONEOK’s businesses, transactions with affiliates, the use of proceeds and a covenant that limits ONEOK’s ability to restrict its subsidiaries’ ability to pay dividends. Under the terms of the ONEOK 2011 Credit Agreement, ONEOK may 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.

The debt covenant calculations in the ONEOK 2011 Credit Agreement exclude the debt of ONEOK Partners. Upon breach of certain covenants by ONEOK, amounts outstanding under the ONEOK 2011 Credit Agreement may become due and payable immediately. At September 30, 2011, ONEOK’s stand-alone debt-to-capital ratio, as defined by the ONEOK 2011 Credit Agreement, was 42.4 percent, and ONEOK was in compliance with all covenants under the ONEOK 2011 Credit Agreement. At September 30, 2011, ONEOK had $650.0 million of commercial paper outstanding and $2.0 million in letters of credit issued, leaving approximately $548.0 million of credit available under the ONEOK 2011 Credit Agreement.

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The ONEOK 2011 Credit Agreement is available to repay our commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowing capacity under the ONEOK 2011 Credit Agreement. The ONEOK 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 150 basis points, and the annual facility fee is 25 basis points based on our current credit rating.

ONEOK Partners 2011 Credit Agreement - On August 1, 2011, ONEOK Partners entered into the five-year, $1.2 billion ONEOK Partners 2011 Credit Agreement, which replaced the $1.0 billion ONEOK Partners Credit Agreement, that was due to expire March 2012. The ONEOK Partners 2011 Credit Agreement, which is scheduled to expire in August 2016, contains certain financial, operational and legal covenants. Among other things, these requirements include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in the ONEOK Partners 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 ONEOK Partners consummates 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 ONEOK Partners in the ONEOK Partners 2011 Credit Agreement, amounts outstanding under the ONEOK Partners 2011 Credit Agreement, if any, may become due and payable immediately.

The ONEOK Partners 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.

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

At September 30, 2011, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 3.4 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement.

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

Neither ONEOK nor ONEOK Partners guarantees the debt or other similar commitments to unaffiliated parties, and ONEOK does not guarantee the debt or other similar commitments of ONEOK Partners.

E. LONG-TERM DEBT

In January 2011, ONEOK Partners 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 ONEOK Partners’ commercial paper program, to repay the $225 million of ONEOK Partners’ senior notes that matured in March 2011 and for general partnership purposes, including capital expenditures.

These notes are governed by an indenture, dated as of September 25, 2006, between ONEOK Partners 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 ONEOK Partners’ ability to place liens on its property or assets and to sell and lease back its 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 ONEOK Partners’ outstanding senior notes to declare those notes immediately due and payable in full.

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ONEOK Partners may redeem its 3.25-percent senior notes due 2016 and its 6.125-percent senior notes due 2041 at par starting one month and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners 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. The senior notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and structurally subordinate to any of the existing and future debt and other liabilities of any nonguarantor subsidiaries.

In 2011, ONEOK repaid $400 million of maturing senior notes and redeemed $90.5 million of 6.4-percent senior notes with available cash and short-term borrowings.

ONEOK Partners intends to repay $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

The following tables set forth the changes in equity attributable to us and our noncontrolling interests, including other comprehensive income, net of tax, for the periods indicated:

	Three Months Ended									Three Months Ended
	September 30, 2011									September 30, 2010
	ONEOK Shareholders' Equity			Noncontrolling Interests in Consolidated Subsidiaries			Total Equity			ONEOK Shareholders' Equity			Noncontrolling Interests in Consolidated Subsidiaries			Total Equity
	(Thousands of dollars)
Beginning balance	$	2,217,089		$	1,480,615		$	3,697,704		$	2,387,229		$	1,483,345		$	3,870,574
Net income		60,321			100,559			160,880			55,295			65,006			120,301
Other comprehensive income (loss)		(43,307	)		(15,370	)		(58,677	)		13,218			(603	)		12,615
Repurchase of common stock		(3	)		-			(3	)		-			-			-
Common stock issued		9,841			-			9,841			7,691			-			7,691
Common stock dividends		(57,981	)		-			(57,981	)		(48,954	)		-			(48,954	)
Issuance of common units of ONEOK Partners		-			-			-			-			(3	)		(3	)
Distributions to noncontrolling interests		-			(69,704	)		(69,704	)		-			(66,801	)		(66,801	)
Other		-			-			-			-			(28	)		(28	)
Ending balance	$	2,185,960		$	1,496,100		$	3,682,060		$	2,414,479		$	1,480,916		$	3,895,395

	Nine Months Ended									Nine Months Ended
	September 30, 2011									September 30, 2010
	ONEOK Shareholders' Equity			Noncontrolling Interests in Consolidated Subsidiaries			Total Equity			ONEOK Shareholders' Equity			Noncontrolling Interests in Consolidated Subsidiaries			Total Equity
	(Thousands of dollars)
Beginning balance	$	2,448,623		$	1,472,218		$	3,920,841		$	2,207,194		$	1,238,268		$	3,445,462
Net income		245,593			249,399			494,992			251,558			141,837			393,395
Other comprehensive income (loss)		(65,771	)		(19,257	)		(85,028	)		28,345			21,758			50,103
Repurchase of common stock		(300,108	)		-			(300,108	)		(5	)		-			(5	)
Common stock issued		26,960			-			26,960			19,082			-			19,082
Common stock dividends		(169,337	)		-			(169,337	)		(142,426	)		-			(142,426	)
Issuance of common units of ONEOK Partners		-			-			-			50,731			271,970			322,701
Distributions to noncontrolling interests		-			(206,260	)		(206,260	)		-			(192,889	)		(192,889	)
Other		-			-			-			-			(28	)		(28	)
Ending balance	$	2,185,960		$	1,496,100		$	3,682,060		$	2,414,479		$	1,480,916		$	3,895,395

Dividends - Fourth-quarter 2010 and first-quarter 2011 dividends paid on our common stock to shareholders of record at the close of business on January 31, 2011, and April 29, 2011, respectively, were $0.52 per share for each period. A second-quarter 2011 dividend of $0.56 per share was declared for shareholders of record on August 1, 2011, and paid on August 12, 2011. Additionally, a third-quarter 2011 dividend of $0.56 per share was declared for shareholders of record at the close of business on November 7, 2011, payable on November 14, 2011.

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See Note K for a discussion of ONEOK Partners’ distributions to noncontrolling interests.

Stock Repurchase Plan - In May 2011, we entered into an accelerated share repurchase agreement (the ASR Agreement) with Barclays Capital (Barclays), pursuant to which we paid $300 million to Barclays and received from Barclays approximately 3.7 million shares of our common stock, representing approximately 85 percent of the estimated total number of shares to be repurchased. In August 2011, Barclays delivered to us an additional 0.6 million shares based on the volume-weighted-average price per share of our common stock during the repurchase period and other adjustments pursuant to the terms and conditions of the ASR Agreement. The delivery of additional shares completed the ASR Agreement. We accounted for the repurchase as two separate transactions: (i) as shares of common stock acquired in a treasury stock transaction recorded on the acquisition date; and (ii) as a forward contract indexed to ONEOK common stock that is classified as equity.

The ASR Agreement was part of our three-year stock repurchase program to buy up to $750 million of our common stock that was authorized by our Board of Directors in October 2010.

G. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

	Unrealized Gains (Losses) on Energy Marketing and Risk Management Assets/Liabilities		Unrealized Holding Gains (Losses) on Investment Securities		Pension and Postretirement Benefit Plan Obligations		Accumulated Other Comprehensive Income (Loss)
		(Thousands of dollars)
December 31, 2010	$	15,731	$	1,371	$	(125,904)	$	(108,802)
Other comprehensive income (loss)
attributable to ONEOK		(51,384)		(370)		(14,017)		(65,771)
September 30, 2011	$	(35,653)	$	1,001	$	(139,921)	$	(174,573)

H. EARNINGS PER SHARE

The following tables set forth the computation of basic and diluted EPS from continuing operations for the periods indicated:

	Three Months Ended September 30, 2011
					Per Share
	Income		Shares		Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Net income attributable to ONEOK available for common stock	$	60,321		103,303	$	0.58
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-		2,667
Net income attributable to ONEOK available for common stock
and common stock equivalents	$	60,321		105,970	$	0.57

	Three Months Ended September 30, 2010
					Per Share
	Income		Shares		Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Net income attributable to ONEOK available for common stock	$	55,295		106,443	$	0.52
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-		1,208
Net income attributable to ONEOK available for common stock
and common stock equivalents	$	55,295		107,651	$	0.51

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	Nine Months Ended September 30, 2011
					Per Share
	Income		Shares		Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Net income attributable to ONEOK available for common stock	$	245,593		105,220	$	2.33
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-		2,507
Net income attributable to ONEOK available for common stock
and common stock equivalents	$	245,593		107,727	$	2.28

	Nine Months Ended September 30, 2010
					Per Share
	Income		Shares		Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Net income attributable to ONEOK available for common stock	$	251,558		106,310	$	2.37
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-		1,105
Net income attributable to ONEOK available for common stock
and common stock equivalents	$	251,558		107,415	$	2.34

There were no option shares excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2011 and 2010.

I. EMPLOYEE BENEFIT PLANS

The following tables set forth the components of net periodic benefit cost for our pension and postretirement benefit plans for the periods indicated:

	Pension Benefits						Pension Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Components of net periodic benefit cost		(Thousands of dollars)
Service cost	$	5,003		$	4,819		$	15,009		$	14,457
Interest cost		14,689			14,536			44,067			43,608
Expected return on assets		(18,875	)		(18,413	)		(56,625	)		(55,239	)
Amortization of unrecognized prior service cost		255			319			764			959
Amortization of net loss		8,927			6,889			26,782			20,666
Net periodic benefit cost	$	9,999		$	8,150		$	29,997		$	24,451

	Postretirement Benefits						Postretirement Benefits
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Components of net periodic benefit cost		(Thousands of dollars)
Service cost	$	1,257		$	1,231		$	3,772		$	3,694
Interest cost		3,958			3,911			11,874			11,733
Expected return on assets		(2,568	)		(1,974	)		(7,704	)		(5,922	)
Amortization of unrecognized net asset at adoption		797			797			2,391			2,392
Amortization of unrecognized prior service cost		(501	)		(500	)		(1,503	)		(1,502	)
Amortization of net loss		2,031			1,752			6,093			5,256
Net periodic benefit cost	$	4,974		$	5,217		$	14,923		$	15,651

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J. UNCONSOLIDATED AFFILIATES

Northern Border Pipeline - In July 2011, the partners of Northern Border Pipeline made equity contributions of approximately $99.6 million, with ONEOK Partners’ share totaling approximately $49.8 million. ONEOK Partners does 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 ONEOK Partners’ 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. All amounts in the table below are equity earnings from investments in our ONEOK Partners segment:

	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.

K. ONEOK PARTNERS

Unit Split - In June 2011, ONEOK Partners announced that the board of directors of its general partner approved a two-for-one split of its 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. 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.

Ownership Interest in ONEOK Partners - Our ownership interest in ONEOK Partners is shown in the table below as of September 30, 2011, and December 31, 2010:


General partner interest	2.0	%
Limited partner interest (a)	40.8	%
Total ownership interest	42.8	%
(a) - Represents 11.8 million common units and approximately 73.0 million Class B units, which are convertible, at our option, into common units.

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Cash Distributions - We receive distributions from ONEOK Partners on our common and Class B units and our 2-percent general partner interest, which includes our incentive distribution rights. Under ONEOK Partners’ partnership agreement, as amended, distributions are made to the partners with respect to each calendar quarter in an amount equal to 100 percent of available cash as defined in ONEOK Partners’ partnership agreement, as amended. Available cash generally will be distributed 98 percent to limited partners and 2 percent to the general partner. The general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met during the quarter. In July 2011, the partnership agreement was amended to adjust the formula for distributing available cash among the general partner and limited partners to reflect the two-for-one unit split. Under the incentive distribution provisions, as set forth in ONEOK Partners’ partnership agreement, as amended, the 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.

The following table shows ONEOK Partners’ distributions paid in the periods indicated:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
	(Thousands, except per unit amounts)
Distribution per unit	$	0.585	$	0.560	$	1.730	$	1.665

General partner distributions	$	3,078	$	2,874	$	9,030	$	8,349
Incentive distributions		31,580		26,689		89,849		75,796
Distributions to general partner		34,658		29,563		98,879		84,145
Limited partner distributions to ONEOK		49,601		47,481		146,684		141,172
Limited partner distributions to noncontrolling interest		69,631		66,655		205,917		192,130
Total distributions paid	$	153,890	$	143,699	$	451,480	$	417,447

The following table shows ONEOK Partners’ distributions declared for the periods indicated and paid within 45 days of the end of the period:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
	(Thousands, except per unit amounts)
Distribution per unit	$	0.595	$	0.565	$	1.755	$	1.680

General partner distributions	$	3,159	$	2,915	$	9,233	$	8,622
Incentive distributions		33,537		27,667		94,741		80,066
Distributions to general partner		36,696		30,582		103,974		88,688
Limited partner distributions to ONEOK		50,450		47,905		148,803		142,444
Limited partner distributions to noncontrolling interest		70,821		67,250		208,893		199,966
Total distributions declared	$	157,967	$	145,737	$	461,670	$	431,098

Relationship - We consolidate ONEOK Partners in our consolidated financial statements; however, we are restricted from the assets and cash flows of ONEOK Partners except for our distributions. Distributions are declared quarterly by ONEOK Partners’ general partner based on the terms of the ONEOK Partners partnership agreement, as amended. See Note M for more information on ONEOK Partners’ results.

Affiliate Transactions - We have certain transactions with ONEOK Partners and its subsidiaries, which comprise our ONEOK Partners segment.

ONEOK Partners sells natural gas from its natural gas gathering and processing operations to our Energy Services segment. In addition, a portion of ONEOK Partners’ revenues from its natural gas pipelines business is from our Energy Services and Distribution segments, which contract with ONEOK Partners for natural gas transportation and storage services. ONEOK Partners also purchases natural gas from our Energy Services segment for its natural gas liquids and its natural gas gathering and processing operations.

Previously, ONEOK Partners had a Processing and Services Agreement with us and OBPI, under which it 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 its rights under the Processing and Services Agreement, ONEOK Partners directed OBPI to

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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, through a series of transactions, we sold OBPI to ONEOK Partners and OBPI closed the purchase option and terminated the equipment leases. The total amount paid by ONEOK Partners to complete the transactions was approximately $94.2 million, which included the reimbursement to us of obligations related to the Processing and Services Agreement.

We provide a variety of services to our affiliates, including cash management and financial services, legal and administrative services by our employees and management, insurance and office space leased in our headquarters building and other field locations. Where costs are incurred specifically on behalf of an affiliate, the costs are billed directly to the affiliate by us. In other situations, the costs may be allocated to the affiliates through a variety of methods, depending upon the nature of the expenses and the activities of the affiliates. For example, a service that applies equally to all employees is allocated based upon the number of employees in each affiliate. 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 include 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.

The following table shows ONEOK Partners’ transactions with us 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

L. 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.

We own or retain legal responsibility for the environmental conditions at 12 former manufactured natural gas sites in Kansas. These sites contain potentially harmful materials that are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE presently governs all work at these sites. The terms of the consent agreement allow us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater.

Of the 12 sites, we have begun soil remediation on 11 sites. Regulatory closure has been achieved at three locations, and we have completed or are near completion of soil remediation at eight sites. We have begun site assessment at the remaining site where no active remediation has occurred.

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 effects on earnings or cash flows during the three and nine months ended September 30, 2011 or 2010.

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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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M. SEGMENTS

Segment Descriptions - Our operations are divided into three reportable business segments as follows: (i) our ONEOK Partners segment gathers, processes, treats, transports, stores and sells natural gas and gathers, treats, fractionates, stores, distributes and markets NGLs; (ii) our Distribution segment, which includes our retail marketing operations, delivers natural gas to residential, commercial and industrial customers, and transports natural gas; and (iii) our Energy Services segment markets natural gas to wholesale customers. Our Distribution segment is comprised primarily of regulated public utilities, and portions of our ONEOK Partners segment are also regulated. Other and eliminations consist of the operating and leasing operations of our headquarters building and related parking facility and other amounts needed to reconcile our reportable segments to our consolidated financial statements.

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

Customers - For the three and nine months ended September 30, 2011 and 2010, we had no single external customer from which we received 10 percent of our consolidated gross revenues.

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

Three Months Ended September 30, 2011	ONEOK Partners (a)			Distribution (b)		Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	2,792,399		$	277,539	$	524,667		$	586		$	3,595,191
Intersegment revenues		111,177			2,176		83,522			(196,875	)		-
Total revenues	$	2,903,576		$	279,715	$	608,189		$	(196,289	)	$	3,595,191

Net margin	$	394,006		$	146,777	$	(7,373	)	$	583		$	533,993
Operating costs		106,306			97,137		5,252			362			209,057
Depreciation and amortization		45,221			30,287		100			378			75,986
Loss on sale of assets		(69	)		-		-			-			(69	)
Operating income	$	242,410		$	19,353	$	(12,725	)	$	(157	)	$	248,881

Equity earnings from investments	$	32,029		$	-	$	-		$	-		$	32,029
Capital expenditures	$	252,227		$	67,459	$	21		$	18,831		$	338,538
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment's regulated operations had revenues of $166.3 million, net margin of $112.5 million and operating income of $55.9 million.
(b) - Our Distribution segment has regulated and non-regulated operations. Our Distribution segment's regulated operations had revenues of $213.8 million, net margin of $145.4 million and operating income of $19.8 million.

Three Months Ended September 30, 2010	ONEOK Partners (a)		Distribution (b)		Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	1,952,159	$	301,730	$	688,293	$	521		$	2,942,703
Intersegment revenues		117,985		951		85,485		(204,421	)		-
Total revenues	$	2,070,144	$	302,681	$	773,778	$	(203,900	)	$	2,942,703

Net margin	$	286,005	$	150,763	$	14,083	$	519		$	451,370
Operating costs		97,797		98,353		7,011		197			203,358
Depreciation and amortization		43,823		32,778		179		454			77,234
Gain (loss) on sale of assets		16,126		-		-		-			16,126
Operating income	$	160,511	$	19,632	$	6,893	$	(132	)	$	186,904

Equity earnings from investments	$	29,390	$	-	$	-	$	-		$	29,390
Capital expenditures	$	104,079	$	67,353	$	-	$	5,153		$	176,585
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment's regulated operations had revenues of $150.6 million, net margin of $111.1 million and operating income of $57.0 million.
(b) - Our Distribution segment has regulated and non-regulated operations. Our Distribution segment's regulated operations had revenues of $237.8 million, net margin of $148.9 million and operating income of $19.9 million.

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Nine Months Ended September 30, 2011	ONEOK Partners (a)			Distribution (b)		Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	7,880,736		$	1,386,830	$	1,707,223	$	1,766		$	10,976,555
Intersegment revenues		306,669			10,016		408,734		(725,419	)		-
Total revenues	$	8,187,405		$	1,396,846	$	2,115,957	$	(723,653	)	$	10,976,555

Net margin	$	1,083,100		$	556,139	$	48,143	$	1,808		$	1,689,190
Operating costs		328,630			310,368		18,554		812			658,364
Depreciation and amortization		131,665			100,736		359		1,441			234,201
Loss on sale of assets		(791	)		-		-		-			(791	)
Operating income	$	622,014		$	145,035	$	29,230	$	(445	)	$	795,834

Equity earnings from investments	$	93,665		$	-	$	-	$	-		$	93,665
Investments in unconsolidated affiliates	$	1,224,397		$	-	$	-	$	-		$	1,224,397
Total assets	$	8,775,553		$	3,095,688	$	562,724	$	737,159		$	13,171,124
Noncontrolling interests in consolidated subsidiaries	$	5,249		$	-	$	-	$	1,490,851		$	1,496,100
Capital expenditures	$	662,386		$	176,508	$	24	$	23,392		$	862,310
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment's regulated operations had revenues of $474.8 million, net margin of $341.6 million and operating income of $169.0 million.
(b) - Our Distribution segment has regulated and non-regulated operations. Our Distribution segment's regulated operations had revenues of $1,155.0 million, net margin of $548.3 million and operating income of $143.1 million.

Nine Months Ended September 30, 2010	ONEOK Partners (a)		Distribution (b)			Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	5,966,267	$	1,638,114		$	2,067,382	$	2,039		$	9,673,802
Intersegment revenues		363,004		8,199			555,972		(927,175	)		-
Total revenues	$	6,329,271	$	1,646,313		$	2,623,354	$	(925,136	)	$	9,673,802

Net margin	$	835,292	$	559,070		$	132,371	$	2,034		$	1,528,767
Operating costs		292,063		296,374			20,981		868			610,286
Depreciation and amortization		131,680		97,000			525		1,395			230,600
Gain (loss) on sale of assets		15,081		(13	)		-		-			15,068
Operating income	$	426,630	$	165,683		$	110,865	$	(229	)	$	702,949

Equity earnings from investments	$	71,182	$	-		$	-	$	-		$	71,182
Investments in unconsolidated affiliates	$	1,194,087	$	-		$	-	$	-		$	1,194,087
Total assets	$	7,549,800	$	3,052,964		$	607,145	$	719,844		$	11,929,753
Noncontrolling interests in consolidated subsidiaries	$	5,261	$	-		$	-	$	1,475,655		$	1,480,916
Capital expenditures	$	202,773	$	145,678		$	52	$	7,786		$	356,289
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment's regulated operations had revenues of $454.7 million, net margin of $363.3 million and operating income of $193.2 million.
(b) - Our Distribution segment has regulated and non-regulated operations. Our Distribution segment's regulated operations had revenues of $1,371.3 million, net margin of $550.5 million and operating income of $163.1 million.

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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. Due to the seasonal nature of our business, the results of operations for the three and nine months ended September 30, 2011, are not necessarily indicative of the results that may be expected for a 12-month period.

Growth Projects - Drilling rig counts are higher and related development activities continue to progress in many areas of ONEOK Partners’ 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 the infrastructure to bring these commodities from supply basins to market. In response to this increased production and demand for NGL products, ONEOK Partners has 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 ONEOK Partners’ growth projects in the “Financial Results and Operating Information” section for our ONEOK Partners segment.

Dividends/Distributions - We declared a quarterly dividend of $0.56 per share ($2.24 per share on an annualized basis) in October 2011, an increase of approximately 17 percent over the $0.48 declared in October 2010. A cash distribution from ONEOK Partners of $0.595 per unit ($2.38 per unit on an annualized basis) was declared in October 2011, an increase of approximately 5 percent over the $0.565 per unit declared, on a split-adjusted basis, in October 2010.

ONEOK 2011 Credit Agreement - On April 5, 2011, ONEOK entered into the ONEOK 2011 Credit Agreement, which replaced the ONEOK Credit Agreement.

ONEOK Partners 2011 Credit Agreement - On August 1, 2011, ONEOK Partners entered into the ONEOK Partners 2011 Credit Agreement, which replaced the ONEOK Partners Credit Agreement.

Debt Issuance and Maturities - In January 2011, ONEOK Partners 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 ONEOK Partners’ commercial paper program, to repay $225 million of ONEOK Partners’ senior notes that matured in March 2011 and for general partnership purposes, including capital expenditures.

In 2011, ONEOK repaid $400 million of maturing senior notes and redeemed $90.5 million of 6.4-percent senior notes with available cash and short-term borrowings.

Unit Split - In June 2011, ONEOK Partners announced that the board of directors of its general partner approved a two-for-one split of its 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, ONEOK Partners’ partnership agreement was amended to adjust the formula for distributing available cash among the 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.

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FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

Selected Financial Results - The following table sets forth certain selected 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	$	3,595.2		$	2,942.7		$	10,976.6		$	9,673.8		$	652.5		22	%		$	1,302.8		13	%
Cost of sales and fuel		3,061.2			2,491.3			9,287.4			8,145.0			569.9		23	%			1,142.4		14	%
Net margin		534.0			451.4			1,689.2			1,528.8			82.6		18	%			160.4		10	%
Operating costs		209.0			203.4			658.4			610.3			5.6		3	%			48.1		8	%
Depreciation and amortization		76.0			77.2			234.2			230.6			(1.2	)	(2	%)			3.6		2	%
Gain (loss) on sale of assets		(0.1	)		16.1			(0.8	)		15.0			(16.2	)	*				(15.8	)	*
Operating income	$	248.9		$	186.9		$	795.8		$	702.9		$	62.0		33	%		$	92.9		13	%

Equity earnings from investments	$	32.0		$	29.4		$	93.7		$	71.2		$	2.6		9	%		$	22.5		32	%
Interest expense	$	(73.8	)	$	(70.9	)	$	(228.7	)	$	(222.8	)	$	2.9		4	%		$	5.9		3	%
Net income	$	160.9		$	120.3		$	495.0		$	393.4		$	40.6		34	%		$	101.6		26	%
Net income attributable to noncontrolling interests	$	100.6		$	65.0		$	249.4		$	141.8		$	35.6		55	%		$	107.6		76	%
Net income attributable to ONEOK	$	60.3		$	55.3		$	245.6		$	251.6		$	5.0		9	%		$	(6.0	)	(2	%)
Capital expenditures	$	338.5		$	176.6		$	862.3		$	356.3		$	161.9		92	%		$	506.0		*
* Percentage change is greater than 100 percent.

Operating income increased 33 percent and 13 percent for the three and nine months ended September 30, 2011, respectively, compared with the same periods last year, reflecting higher results at our ONEOK Partners segment, offset partially by lower operating income at our Distribution and Energy Services segments. Our ONEOK Partners segment’s operating income increased due primarily to more favorable NGL price differentials and higher NGL volumes gathered and fractionated, offset partially by the deconsolidation of Overland Pass Pipeline in September 2010 in its natural gas liquids business and lower natural gas transportation margins due to narrower natural gas price location differentials in its natural gas pipelines business.

Our Distribution segment’s operating income decreased for the nine months ended September 30, 2011, compared with the same period last year, due to increased operating costs and higher depreciation and amortization expense. Operating income for the three months ended September 30, 2011, was relatively unchanged from the same period last year.

Our Energy Services segment’s operating income for the three-month period decreased due to lower transportation margins, net of hedging activities, due primarily to narrower price location differentials and lower hedge settlements in 2011. For the nine-month period, our Energy Services segment’s operating income decreased due primarily to lower transportation margins, net of hedging activities, and lower storage and marketing margins, net of hedging activities.

Operating costs increased for the nine months ended September 30, 2011, compared with the same period last year, due primarily to increased share-based compensation and other labor and benefit costs, and increased ad valorem taxes, materials and outside services expenses in our ONEOK Partners segment.

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 to the sale of a 49-percent interest of Overland Pass Pipeline Company in September 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 and the impact of accounting for Overland Pass Pipeline Company as an equity method investment beginning in September 2010.

Net income attributable to noncontrolling interests for the three and nine months ended September 30, 2011 and 2010, primarily reflects the portion of ONEOK Partners that we do not own and reflects higher earnings in our ONEOK Partners segment.

Capital expenditures increased for the three and nine months ended September 30, 2011, compared with the same periods last year, due primarily to the new growth projects in ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses.

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

ONEOK Partners

Overview - We own approximately 84.8 million common and Class B limited partner units, and the entire 2-percent general partner interest, which, together, represents a 42.8-percent ownership interest in ONEOK Partners. We receive distributions from ONEOK Partners on our common and Class B units and our 2-percent general partner interest, which includes our incentive distribution rights. See Note O of the Notes to Consolidated Financial Statements in our Annual Report for discussion of our incentive distribution rights.

Natural gas gathering and processing business - ONEOK Partners’ natural gas gathering and processing business is engaged in the gathering and processing of natural gas produced from crude oil and natural gas wells, primarily in the Mid-Continent and Rocky Mountain regions. These regions include the Anadarko Basin of Oklahoma that contains the NGL-rich Cana-Woodford Shale formation; Hugoton and Central Kansas Uplift Basins of Kansas; the Williston Basin of Montana and North Dakota that includes the oil-producing, NGL-rich Bakken Shale and Three Forks formations; and the Powder River Basin of Wyoming. Through gathering systems, natural gas is aggregated and treated or processed for removal of water vapor, solids and other contaminants, and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. 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. In the Powder River Basin, the natural gas that ONEOK Partners gathers 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.

Natural gas pipelines business - ONEOK Partners’ natural gas pipelines business operates interstate and intrastate natural gas transmission pipelines, natural gas storage facilities and nonprocessable natural gas gathering facilities. ONEOK Partners also provides natural gas transportation and storage services in accordance with Section 311(a) of the Natural Gas Policy Act. ONEOK Partners’ FERC-regulated interstate assets transport natural gas through pipelines that access supply from Canada and from the Mid-Continent, Rocky Mountain and Gulf Coast regions. ONEOK Partners’ intrastate natural gas pipeline assets are located in Oklahoma, Texas and Kansas, and have access to major natural gas producing areas in those states. ONEOK Partners owns underground natural gas storage facilities in Oklahoma, Kansas and Texas.

Natural gas liquids business - ONEOK Partners’ natural gas liquids business gathers, treats, fractionates, stores and transports NGLs and distributes and stores NGL products. ONEOK Partners’ natural gas liquids gathering pipelines deliver unfractionated NGLs gathered from natural gas processing plants located in Oklahoma, Kansas, Texas and the Rocky Mountain region to fractionators it owns in Oklahoma, Kansas and Texas, as well as to third-party fractionators and third-party pipelines. The NGLs are then separated through the fractionation process into the individual NGL products that realize the greater economic value of the NGL components. The individual NGL products are then stored or distributed to petrochemical manufacturers, heating-fuel users, refineries and propane distributors through ONEOK Partners’ FERC-regulated distribution pipelines that move NGL products from Oklahoma and Kansas to the Mid-Continent and Gulf Coast NGL market centers, as well as the Midwest markets near Chicago, Illinois.

Growth Projects - Natural gas gathering and processing business - ONEOK Partners’ natural gas gathering and processing business 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 ONEOK Partners to meet the rapidly growing needs of crude oil and natural gas producers in those areas.

Williston Basin Processing Plants and related projects - ONEOK Partners is 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. ONEOK Partners has 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, ONEOK Partners will expand and upgrade its 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, ONEOK Partners completed projects totaling approximately $38 million in the Cana-Woodford Shale development in Oklahoma, which included the connection of its western Oklahoma natural gas gathering system to its 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.

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Natural gas liquids business - The growth strategy in the natural gas liquids business 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 ONEOK Partners to make additional capital investments to increase the capacity of its infrastructure to bring these commodities from supply basins to market. ONEOK Partners’ natural gas liquids business 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 across ONEOK Partners’ asset base and alleviate infrastructure constraints between the Mid-Continent and Texas Gulf Coast regions that will enhance the distribution of NGL products to meet the increasing petrochemical industry and NGL export demand in the Gulf Coast.

Sterling III Pipeline and reconfiguring Sterling I and II Pipelines - ONEOK Partners plans 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 ONEOK Partners’ natural gas liquids infrastructure at Medford, Oklahoma, to its storage and fractionation facilities in Mont Belvieu, Texas. ONEOK Partners has 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 its 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 - ONEOK Partners plans to construct a 75-MBbl/d fractionator, MB-2, near ONEOK Partners’ storage facility in Mont Belvieu, Texas. The Texas Commission on Environmental Quality (TCEQ) has approved the 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. ONEOK Partners has 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 - ONEOK Partners plans 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 ONEOK Partners’ 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 ONEOK Partners’ 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 ONEOK Partners owns a 50-percent equity interest. These additions and expansions will increase the capacity of Overland Pass Pipeline to 255 MBbl/d. ONEOK Partners’ 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, ONEOK Partners will invest $110 million to $140 million, excluding AFUDC, to expand and upgrade its existing fractionation capacity at Bushton, Kansas, increasing its 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 - ONEOK Partners plans to invest approximately $197 million to $257 million, excluding AFUDC, in its existing Mid-Continent infrastructure, primarily in the Cana-Woodford Shale and Granite Wash areas. These investments will expand ONEOK Partners’ 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.

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These investments include constructing more than 230 miles of natural gas liquids pipelines that will expand its 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, ONEOK Partners will install additional pump stations on the 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 ONEOK Partners’ existing natural gas liquids 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, ONEOK Partners invested approximately $17 million to increase the accessibility of new NGL supply to the Arbuckle Pipeline and Mont Belvieu fractionation facilities.

Sterling I Pipeline Expansion - ONEOK Partners is installing seven additional pump stations for approximately $36 million, excluding AFUDC, along its existing Sterling I natural gas liquids distribution pipeline, increasing its capacity by 15 MBbl/d, which will be supplied by ONEOK Partners’ Mid-Continent natural gas liquids infrastructure. The Sterling I pipeline transports NGL products from ONEOK Partners’ 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 ONEOK Partners’ capital expenditure financing, see “Capital Expenditures” in “Liquidity and Capital Resources” on page 49.

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 in ONEOK Partners’ natural gas liquids business. The following table sets forth certain selected financial results for our ONEOK Partners 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)
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.

Net margin increased for the three months ended September 30, 2011, compared with the same period last year, due primarily to 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 in ONEOK Partners’ natural gas liquids business;

·	an increase of $11.6 million due to higher net realized NGL and condensate prices in ONEOK Partners’ natural gas gathering and processing business;

an increase of $7.9 million from 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 ONEOK Partners’ NGL exchange services activities, offset partially by higher costs associated with NGL volumes fractionated by third parties in its natural gas liquids business;

·	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 in ONEOK Partners’ natural gas liquids business; and

·	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 in ONEOK Partners’ natural gas gathering and processing business; offset partially by

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·	a decrease of $10.2 million due to the deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method in ONEOK Partners’ natural gas liquids business.

Net margin increased for the nine months ended September 30, 2011, compared with the same period last year, due primarily to 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 in ONEOK Partners’ natural gas liquids business;

an increase of $29.6 million from 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 ONEOK Partners’ NGL exchange services activities, offset partially by higher costs associated with NGL volumes fractionated by third parties in its natural gas liquids business;

·	an increase of $26.7 million due to higher net realized commodity prices in ONEOK Partners’ natural gas gathering and processing business;

·	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 in ONEOK Partners’ natural gas liquids business;

·	an increase of $11.8 million due to favorable changes in contract terms in ONEOK Partners’ natural gas gathering and processing business;

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 in ONEOK Partners’ natural gas gathering and processing business; and

·	an increase of $9.2 million due to higher storage margins as a result of contract renegotiations at higher fees in ONEOK Partners’ natural gas liquids business; 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 in ONEOK Partners’ natural gas liquids business;

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 ONEOK Partners’ pipelines in its natural gas pipelines business; and

·	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 in ONEOK Partners’ natural gas gathering and processing business.

Operating costs increased for the three months ended September 30, 2011, compared with the same period last year, due primarily to the following:

·	an increase of $3.7 million in higher labor and employee-related costs associated with incentive and benefit plans;

·	an increase of $3.2 million from higher materials and outside services expenses associated primarily with scheduled maintenance at fractionation and storage facilities in ONEOK Partners’ natural gas liquids business; and

·	an increase of $2.6 million due to higher ad valorem taxes associated with the completed capital projects in ONEOK Partners’ natural gas liquids business.

Operating costs increased for the nine months ended September 30, 2011, compared with the same period last year, due primarily to the following:

an increase of $20.3 million in higher labor and employee-related costs associated with incentive and benefit plans, which includes higher share-based compensation costs resulting from common stock awarded to employees as part of ONEOK’s stock award program and the appreciation in ONEOK’s share price, affecting all of ONEOK Partners’ businesses;

·	an increase of $9.3 million due to higher ad valorem taxes associated with the completed capital projects in all of ONEOK Partners’ businesses; and

·	an increase of $6.3 million from higher materials and outside services expenses associated primarily with scheduled maintenance at fractionation and storage facilities in ONEOK Partners’ natural gas liquids business; offset partially 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 of accounting in ONEOK Partners’ natural gas liquids business.

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Equity earnings from investments increased for the nine months ended September 30, 2011, compared with the same period last year, due primarily to increased contracted capacity on Northern Border Pipeline in ONEOK Partners’ natural gas pipelines business. Northern Border Pipeline benefited 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. Equity earnings also includes Overland Pass Pipeline Company in ONEOK Partners’ natural gas liquids business, which it began accounting for under the equity method of accounting in September 2010.

Capital expenditures increased for the three and nine months ended September 30, 2011, compared with the same periods last year, due primarily to the growth projects in ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses.

Selected Operating Information - The following table sets forth selected operating information for ONEOK Partners’ businesses for the periods indicated:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Operating Information (a)	2011			2010			2011			2010
Natural gas gathering and processing business
Natural gas gathered (BBtu/d)		1,044			1,046			1,021			1,075
Natural gas processed (BBtu/d)		723			669			682			674
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
Natural gas pipelines business
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
Natural gas liquids business
NGL sales (MBbl/d)		485			449			481			443
NGLs fractionated (MBbl/d) (c)		529			500			522			505
NGLs transported-gathering lines (MBbl/d) (d)		443			436			424			452
NGLs transported-distribution lines (MBbl/d)		457			455			460			468
Conway-to-Mont Belvieu OPIS average price differential
Ethane ($/gallon)	$	0.27		$	0.10		$	0.21		$	0.11
(a) - For consolidated entities only.
(b) - Presented net of the impact of hedging activities and includes equity volumes only.
(c) - Includes volumes fractionated from company-owned and third-party facilities.
(d) - 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.

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.

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.

Natural gas transportation capacity contracted decreased for the three and nine months ended September 30, 2011, compared with the same periods last year, due primarily to lower contracted capacity on Midwestern Gas Transmission due to narrower natural gas price location differentials between the markets it serves. ONEOK Partners’ 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.

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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.

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 the 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.

Commodity Price Risk - The following tables set forth ONEOK Partners’ natural gas gathering processing business’ 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.

ONEOK Partners’ natural gas gathering and processing business’ 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. ONEOK Partners’ condensate sales are based on the price of crude oil. ONEOK Partners estimates 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 ONEOK Partners’ services or processing plant operations that might be caused by, or arise in conjunction with, price changes. For example, a change in the gross processing spread may cause a change in the amount of ethane extracted from the natural gas stream, impacting gathering and processing margins for certain contracts.

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

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Distribution

Overview - Our Distribution segment provides natural gas distribution services to more than two million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service. We serve residential, commercial, industrial and transportation customers in all three states. In addition, our distribution companies serve wholesale and public authority customers. Our Distribution segment’s retail marketing business serves municipal, small commercial, industrial and agricultural customers in the Mid-Continent region, residential and agricultural customers in Nebraska and residential customers in Wyoming.

Selected Financial Results - The following table sets forth certain selected financial results for our Distribution 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)
Gas sales	$	252.3	$	273.6	$	1,301.2	$	1,549.4	$	(21.3	)	(8	%)	$	(248.2	)	(16	%)
Transportation revenues		19.3		19.0		67.3		67.1		0.3		2	%		0.2		0	%
Cost of gas		132.9		151.9		840.7		1,087.2		(19.0	)	(13	%)		(246.5	)	(23	%)
Net margin, excluding other revenues		138.7		140.7		527.8		529.3		(2.0	)	(1	%)		(1.5	)	(0	%)
Other revenues		8.1		10.1		28.3		29.8		(2.0	)	(20	%)		(1.5	)	(5	%)
Net margin		146.8		150.8		556.1		559.1		(4.0	)	(3	%)		(3.0	)	(1	%)
Operating costs		97.1		98.4		310.4		296.4		(1.3	)	(1	%)		14.0		5	%
Depreciation and amortization		30.3		32.8		100.7		97.0		(2.5	)	(8	%)		3.7		4	%
Operating income	$	19.4	$	19.6	$	145.0	$	165.7	$	(0.2	)	(1	%)	$	(20.7	)	(12	%)
Capital expenditures	$	67.5	$	67.4	$	176.5	$	145.7	$	0.1		0	%	$	30.8		21	%

The following table sets forth our net margin, excluding other revenues, by type of customer, for the periods indicated:

	Three Months Ended				Nine Months Ended				Three Months					Nine Months
	September 30,				September 30,				2011 vs. 2010					2011 vs. 2010
Net margin, excluding other revenues	2011		2010		2011		2010		Increase (Decrease)					Increase (Decrease)
Gas sales	(Millions of dollars)
Regulated
Residential	$	97.6	$	98.1	$	368.8	$	369.1	$	(0.5	)	(1	%)	$	(0.3	)	(0	%)
Commercial		19.0		20.6		78.8		79.5		(1.6	)	(8	%)		(0.7	)	(1	%)
Industrial		0.6		0.6		2.2		1.9		-		0	%		0.3		16	%
Wholesale/Public Authority		0.8		0.7		2.9		3.3		0.1		14	%		(0.4	)	(12	%)
Retail marketing		1.4		1.7		7.8		8.4		(0.3	)	(18	%)		(0.6	)	(7	%)
Net margin on gas sales		119.4		121.7		460.5		462.2		(2.3	)	(2	%)		(1.7	)	(0	%)
Transportation margin		19.3		19.0		67.3		67.1		0.3		2	%		0.2		0	%
Net margin, excluding other revenues	$	138.7	$	140.7	$	527.8	$	529.3	$	(2.0	)	(1	%)	$	(1.5	)	(0	%)

Net margin decreased for the three and nine months ended September 30, 2011, compared with the same periods last year, due primarily to a decrease of $3.8 million and $1.1 million, respectively, from the expiration of the Integrity Management Program (IMP) rider in Oklahoma. This decrease is offset by lower regulatory amortization in depreciation and amortization expense.

Operating costs increased for the nine months ended September 30, 2011, compared with the same period last year, due primarily to the following:

·	an increase of $9.5 million in share-based compensation costs from common stock awarded to employees as part of ONEOK’s stock award program and the appreciation in ONEOK’s share price; and

·	an increase of $2.4 million from increased pension costs as a result of the annual change in our estimated discount rate.

On October 29, 2011, the United Steelworkers, which represents approximately 400 Kansas Gas Service employees, ratified a new five-year contract.

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Depreciation and amortization expense decreased for the three months ended September 30, 2011, compared with the same period last year, due to a decrease of $4.1 million in regulatory amortization associated primarily with the expiration of the IMP Rider in Oklahoma, offset partially by higher depreciation expense of $1.6 million associated with the additional capital expenditures.

Depreciation and amortization expense increased for the nine months ended September 30, 2011, compared with the same period last year, due primarily to an increase of $4.8 million associated with the additional capital expenditures, specifically an additional investment in automated meter reading in Oklahoma, offset partially by a decrease of $1.1 million in regulatory amortization associated with the expiration of the IMP Rider in Oklahoma.

Capital Expenditures - Our capital expenditures program includes expenditures for pipeline integrity, automated meter reading, extending service to new areas, modifications to customer-service lines, increasing system capabilities, and replacements. It is our practice to maintain and upgrade facilities to ensure safe, reliable and efficient operations.

Capital expenditures increased for the nine months ended September 30, 2011, compared with the same period last year, due to increased spending on pipeline replacements.

Selected Operating Information - The following tables set forth certain selected information for the regulated operations of our Distribution segment for the periods indicated:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Number of Customers	2011		2010		2011		2010
Residential		1,902,709		1,893,290		1,921,949		1,913,622
Commercial		150,740		150,748		153,637		154,151
Industrial		1,244		1,258		1,243		1,279
Wholesale/Public Authority		2,713		2,713		2,744		2,695
Transportation		11,738		11,357		11,674		11,241
Total customers		2,069,144		2,059,366		2,091,247		2,082,988

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Volumes (MMcf)	2011		2010		2011		2010
Gas sales
Residential		7,253		7,384		78,054		82,086
Commercial		3,511		3,260		23,409		24,683
Industrial		374		315		1,084		940
Wholesale/Public Authority		289		3,436		1,851		8,540
Total volumes sold		11,427		14,395		104,398		116,249
Transportation		44,300		42,766		153,182		153,074
Total volumes delivered		55,727		57,161		257,580		269,323

Residential and commercial volumes decreased for the nine months ended September 30, 2011, compared with the same period last year, due to warmer temperatures across our entire service territory in the first quarter of 2011; however, the impact on margin was moderated by weather-normalization mechanisms.

Regulatory Initiatives - Oklahoma - In February 2011, Oklahoma Natural Gas filed its first application related to its performance-based rate change mechanism. The application did not seek a modification of customer rates because Oklahoma Natural Gas’ regulatory return on equity was within the range approved by the OCC. The OCC signed the final order on this filing on July 5, 2011, with no modification to customer rates.

In September 2010, Oklahoma Natural Gas filed an application and supporting testimony with the OCC seeking approval of a demand portfolio of conservation and energy-efficiency programs and authorizing recovery of costs and performance incentives. A settlement agreement was reached between all the parties and filed at the OCC on February 10, 2011. This agreement allows Oklahoma Natural Gas to pursue the key energy-efficiency programs requested in its filing and allows the company to earn up to $1.5 million annually beginning mid-2012 if program objectives are achieved. The filing and settlement agreement were approved by the OCC on May 12, 2011, and billings to customers began in June 2011.

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Kansas - In September 2011, Kansas Gas Service filed an application to increase the Gas System Reliability Surcharge by an additional $2.9 million. This surcharge is a capital-recovery mechanism that allows for rate adjustment providing recovery and a return on incremental safety-related and government-mandated capital investments made between rate cases.

Texas - Texas Gas Service made annual filings for interim rate relief under the Gas Reliability Infrastructure Program (GRIP) statute with the cities of Austin, Texas, and surrounding communities in February 2011 and El Paso, Texas, in May 2011 for approximately $1.6 million and $1.1 million, respectively. GRIP is a capital-recovery mechanism that allows for an interim rate adjustment providing recovery and a return on incremental capital investments made between rate cases. In May 2011, the city of Austin approved the filing in the amount of $1.5 million, effective in June 2011. In August 2011, the city of El Paso approved the filing in the amount of $1.0 million, effective in August 2011. In the normal course of business, we have filed for GRIP and cost-of-service adjustments in various other Texas jurisdictions to address investments in rate base and changes in expense.

Energy Services

Overview - Our Energy Services segment’s primary focus is to create value for our customers by delivering natural gas products and providing risk-management services through our network of contracted natural gas transportation and storage capacity and natural gas supply. This contracted storage and transportation capacity connects the major supply and demand centers throughout the United States and into Canada. Our customers are primarily LDCs, electric utilities and commercial and industrial end-users. Our customers’ natural gas needs vary with seasonal changes in weather and are therefore somewhat unpredictable.

To ensure natural gas is available when our customers need it, we offer premium services and products that satisfy our customers’ swing and peaking natural gas commodity requirements on a year-round basis. We also provide no-notice service, weather-related protection and other custom solutions based on our customers’ specific needs. Our storage and transportation assets enable us to provide these services and provide us with opportunities to optimize our contracted assets through our application of market knowledge and risk-management skills. Location and seasonal basis differentials have narrowed, resulting in reduced opportunities to optimize our firm transportation and storage capacity.

Our Energy Services segment has focused its efforts on aligning its contracted natural gas transportation and storage capacity with meeting the needs of its premium-services customers. The effect of this strategy has been a reduction in its contracted natural gas transportation and storage capacity, which also will reduce its working-capital requirements primarily through a reduction in natural gas inventory levels. Approximately 14 percent of our transportation capacity and approximately 20 percent of our storage capacity expires by the end of 2012, and approximately 75 percent of our transportation capacity and approximately 89 percent of our storage capacity expires by the end of 2015.

An increase in shale gas production and related pipeline construction has resulted in excess natural gas supply in certain areas of the United States and Canada, and lower volatility in natural gas prices. In prior years, we were able to hedge location differentials and seasonal storage spreads at more favorable rates compared with opportunities currently available to us. These factors have impacted negatively our Energy Services segment’s results of operations in 2011, and we anticipate these factors will persist throughout 2012. A significant amount of our storage and transportation hedges that were entered into at favorable rates have already been or will be realized by the end of 2011.

Selected Financial Results - The following table sets forth certain selected financial results for our Energy Services 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)
Revenues	$	608.2		$	773.8	$	2,116.0	$	2,623.4	$	(165.6	)	(21	%)	$	(507.4	)	(19	%)
Cost of sales and fuel		615.6			759.7		2,067.9		2,491.0		(144.1	)	(19	%)		(423.1	)	(17	%)
Net margin		(7.4	)		14.1		48.1		132.4		(21.5	)	*			(84.3	)	(64	%)
Operating costs		5.2			7.0		18.6		21.0		(1.8	)	(26	%)		(2.4	)	(12	%)
Depreciation and amortization		0.1			0.2		0.3		0.5		(0.1	)	(50	%)		(0.2	)	(40	%)
Operating income (loss)	$	(12.7	)	$	6.9	$	29.2	$	110.9	$	(19.6	)	*		$	(81.7	)	(74	%)
* Percentage change is greater than 100 percent.

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The following table sets forth our margins by activity for the periods indicated:

	Three Months Ended					Nine Months Ended				Three Months					Nine Months
	September 30,					September 30,				2011 vs. 2010					2011 vs. 2010
	2011			2010		2011		2010		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Marketing, storage and transportation revenues, gross	$	30.6		$	57.6	$	167.3	$	272.6	$	(27.0	)	(47	%)		$	(105.3	)	(39	%)
Storage and transportation costs		39.4			45.9		120.8		145.8		(6.5	)	(14	%)			(25.0	)	(17	%)
Marketing, storage and transportation, net		(8.8	)		11.7		46.5		126.8		(20.5	)	*				(80.3	)	(63	%)
Financial trading, net		1.4			2.4		1.6		5.6		(1.0	)	(42	%)			(4.0	)	(71	%)
Net margin	$	(7.4	)	$	14.1	$	48.1	$	132.4	$	(21.5	)	*			$	(84.3	)	(64	%)
* Percentage change is greater than 100 percent.

Marketing, storage and transportation revenues, gross, primarily includes marketing, purchases and sales, premium services and the impact of cash flow and fair value hedges and other derivative instruments used to manage our risk associated with these activities. Storage and transportation costs primarily include the cost of leasing capacity, storage injection and withdrawal fees, fuel charges and gathering fees. Risk management and operational decisions have an impact on the net result of our marketing, premium services and storage activities. We evaluate our strategies on an ongoing basis to optimize the value of our contracted assets and to minimize the financial impact of market conditions on the services we provide.

Financial trading, net, includes activities that are executed generally using financially settled derivatives. These activities are normally short term in nature, with a focus on capturing short-term price volatility. Revenues in our Consolidated Statements of Income include financial trading margins, as well as certain physical natural gas transactions with our trading counterparties. Revenues and cost of sales and fuel from such physical transactions are reported on a net basis.

Net margin decreased for the three months ended September 30, 2011, compared with the same period last year, due primarily to a decrease of $21.3 million in transportation margins, net of hedging, due primarily to narrower price location differentials and lower hedge settlements in 2011.

Net margin decreased for the nine months ended September 30, 2011, compared with the same period last year, due primarily to the following:

·	a decrease of $55.5 million in transportation margins, net of hedging, due primarily to narrower price location differentials and lower hedge settlements in 2011;

·	a decrease of $18.3 million in storage and marketing margins, net of hedging activities, due primarily to the following:

-	lower realized seasonal storage price differentials primarily in the first quarter 2011 compared with the first quarter 2010; offset partially by

-	favorable unrealized fair value changes on nonqualifying economic storage hedges and marketing activity;

·	a decrease of $6.5 million in premium-services margins, associated primarily with the reduction in the value of the fee collected for these services as a result of low commodity prices and reduced market volatility in the first quarter 2011 compared with the first quarter 2010; and

·	a decrease of $4.0 million in financial trading margins.

Selected Operating Information - The following table sets forth certain selected operating information for our Energy Services segment for the periods indicated:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Operating Information	2011			2010		2011		2010
Natural gas marketed (Bcf)		187			224		639		693
Natural gas gross margin ($/Mcf)	$	(0.03	)	$	0.07	$	0.08	$	0.20
Physically settled volumes (Bcf)		395			470		1,294		1,414

Natural gas volumes marketed and physically settled volumes decreased for the three and nine months ended September 30, 2011, compared with the same periods last year, due primarily to reduced transportation capacity and lower transported volumes. Transportation capacity in certain markets was not utilized due to the economics of the location differentials.

Our natural gas in storage at September 30, 2011, was 61.6 Bcf, compared with 65.4 Bcf at September 30, 2010. At September 30, 2011, our total natural gas storage capacity under lease was 75.6 Bcf, compared with 76.6 Bcf at September 30, 2010. At September 30, 2011, our natural gas storage capacity under lease had a maximum withdrawal capability of 2.1 Bcf/d and maximum injection capability of 1.2 Bcf/d. At September 30, 2011, our natural gas transportation capacity was 1.2 Bcf/d, of which 1.2 Bcf/d was contracted under long-term natural gas transportation contracts, compared with 1.4 Bcf/d of total capacity and 1.2 Bcf/d of long-term capacity at September 30, 2010.

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CONTINGENCIES

Legal Proceedings - We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, and we are unable to estimate reasonably possible losses, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows. Additional information about our legal proceedings is included under Part II, Item I, 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. ONEOK and ONEOK Partners have relied primarily on operating cash flow, commercial paper, bank credit facilities, debt issuances and/or the sale of equity for their liquidity and capital resource requirements. ONEOK and ONEOK Partners fund their operating expenses, debt service, dividends to shareholders and distributions to unitholders 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. Neither ONEOK nor ONEOK Partners guarantees the debt or other similar commitments to unaffiliated parties, and ONEOK does not guarantee the debt or other similar commitments of ONEOK Partners.

ONEOK’s and ONEOK Partners’ ability to continue to access capital markets for debt and equity financing under reasonable terms depends on market conditions and ONEOK’s and ONEOK Partners’ respective financial condition and credit ratings. ONEOK and ONEOK Partners anticipate that cash flow generated from operations, existing capital resources and ability to obtain financing will enable both entities to maintain current levels of operations and planned operations, collateral requirements and fund capital expenditures.

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

	September 30,		December 31,
	2011		2010
Long-term debt		57%		52%
Total equity		43%		48%

Debt (including notes payable)		60%		55%
Total equity		40%		45%

For the purpose of determining compliance with financial covenants in the ONEOK 2011 Credit Agreement, which are described below, the debt of ONEOK Partners is excluded. The following table sets forth ONEOK’s capital structure, excluding the debt of ONEOK Partners, for the periods indicated:

	September 30,		December 31,
	2011		2010
Long-term debt		32%		38%
ONEOK shareholders' equity		68%		62%

Debt (including notes payable)		43%		40%
ONEOK shareholders' equity		57%		60%

Stock Repurchase Program - In May 2011, we entered into an accelerated share repurchase agreement (the ASR Agreement) with Barclays Capital (Barclays), pursuant to which we paid $300 million to Barclays and received from Barclays approximately 3.7 million shares of our common stock, representing approximately 85 percent of the estimated total number of shares to be repurchased. In August 2011, Barclays delivered to us an additional 0.6 million shares based on the volume-weighted-average price per share of our common stock during the repurchase period and other adjustments pursuant to the terms and conditions of the ASR Agreement. The delivery of additional shares completed the ASR Agreement.

The ASR Agreement was part of our three-year stock repurchase program to buy up to $750 million of our common stock that was authorized by our Board of Directors in October 2010.

Short-term Liquidity - ONEOK’s principal sources of short-term liquidity consist of cash generated from operating activities, quarterly distributions from ONEOK Partners and the issuance of commercial paper. To the extent commercial paper is unavailable, the ONEOK 2011 Credit Agreement may be utilized. ONEOK Partners’ principal sources of short-term

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liquidity consist of cash generated from operating activities, ONEOK Partners’ commercial paper program and the ONEOK Partners 2011 Credit Agreement.

ONEOK 2011 Credit Agreement - On April 5, 2011, ONEOK entered into the ONEOK 2011 Credit Agreement, which replaced the ONEOK Credit Agreement. Under the ONEOK 2011 Credit Agreement, which is scheduled to expire in April 2016, ONEOK is required to comply with certain financial, operational and legal covenants. Among other things, these requirements include:

·	a limitation on ONEOK’s stand-alone debt-to-capital ratio, which may not exceed 67.5 percent at the end of any calendar quarter;

·	limitations on the ratio of indebtedness secured by liens and indebtedness of subsidiaries to consolidated net tangible assets;

·	a requirement that ONEOK maintains the power to control the management and policies of ONEOK Partners; and

·	a limit on new investments in master limited partnerships.

The total amount of short-term borrowings authorized by ONEOK’s Board of Directors is $2.8 billion. At September 30, 2011, ONEOK had $650.0 million of commercial paper outstanding, $2.0 million in letters of credit issued under the ONEOK 2011 Credit Agreement and approximately $20.5 million of available cash and cash equivalents. ONEOK had approximately $548.0 million of credit available at September 30, 2011, under the ONEOK 2011 Credit Agreement. As of September 30, 2011, ONEOK could have issued $3.1 billion of additional short- and long-term debt under the most restrictive provisions contained in its various borrowing agreements.

ONEOK Partners 2011 Credit Agreement - On August 1, 2011, ONEOK Partners entered into the five-year, $1.2 billion ONEOK Partners 2011 Credit Agreement, which replaced the $1.0 billion ONEOK Partners Credit Agreement that was due to expire in March 2012. The ONEOK Partners 2011 Credit Agreement, which is scheduled to expire in August 2016, contains certain financial, operational and legal covenants. Among other things, the ONEOK Partners 2011 Credit Agreement covenants include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in the ONEOK Partners 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 ONEOK Partners consummates one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will be increased to 5.5 to 1 for the three calendar quarters following the acquisition. Upon any breach of certain covenants by ONEOK Partners in the ONEOK Partners 2011 Credit Agreement, amounts outstanding under the ONEOK Partners 2011 Credit Agreement, if any, may become due and payable immediately.

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

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

In October 2011, ONEOK Partners increased the size of its commercial paper program to $1.2 billion.

At September 30, 2011, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 3.4 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement.

The ONEOK 2011 Credit Agreement and the ONEOK Partners 2011 Credit Agreement contain certain similar financial, operational and legal covenants as discussed in Note F of the Notes to Consolidated Financial Statements in our Annual Report.

Long-term Financing - In addition to the principal sources of short-term liquidity discussed above, options available to ONEOK to meet its longer-term cash requirements include the issuance of equity, long-term notes and convertible debt securities, asset securitization and the sale and leaseback of facilities. Options available to ONEOK Partners to meet its longer-term cash requirements include the issuance of common units, long-term notes and convertible debt securities, asset securitization and the sale and leaseback of facilities.

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

ONEOK Debt Maturity - In 2011, ONEOK repaid $400 million of maturing senior notes and redeemed $90.5 million of 6.4-percent senior notes with available cash and short-term borrowings.

ONEOK Debt Covenants - The indentures governing ONEOK’s senior notes due 2028 include an event of default upon acceleration of other indebtedness of $15 million or more, and the indentures governing the senior notes due 2015 and 2035 include an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2015, 2028 and 2035 to declare those notes immediately due and payable in full.

ONEOK may redeem the notes due 2015, 2028 (6.875 percent) and 2035, 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. ONEOK may redeem the notes due 2028 (6.5 percent), 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. 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. ONEOK’s senior notes due 2015, 2028 and 2035 are senior unsecured obligations, ranking equally in right of payment with all of ONEOK’s existing and future unsecured senior indebtedness.

ONEOK Partners’ Debt Issuance and Maturity - In January 2011, ONEOK Partners 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 ONEOK Partners’ commercial paper program, to repay $225 million of ONEOK Partners’ senior notes that matured in March 2011 and for general partnership purposes, including capital expenditures.

ONEOK Partners intends to repay its $350 million of 5.9-percent senior notes that mature in April 2012 with a combination of cash on hand and short-term borrowings.

ONEOK Partners’ Debt Covenants - The indentures governing ONEOK Partners’ senior notes include an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of ONEOK Partners’ outstanding senior notes to declare those notes immediately due and payable in full.

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ONEOK Partners may redeem the notes due 2012, 2016 (6.15 percent), 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. ONEOK Partners may redeem its 3.25-percent notes due 2016 and 6.125-percent notes due 2041 at par starting one month and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners may redeem these notes on the same terms as its other senior notes. ONEOK Partners’ senior notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and structurally subordinate to all of the existing and future debt and other liabilities of any nonguarantor subsidiaries. ONEOK Partners’ senior notes are nonrecourse to ONEOK.

Interest-rate swaps - At September 30, 2011, we and ONEOK Partners had forward-starting interest-rate swaps with notional amounts of $500 million and $750 million, respectively. The purpose of the swaps is to hedge the variability of interest payments on a portion of forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued.

Capital Expenditures - ONEOK’s and ONEOK Partners’ capital expenditures are financed typically through operating cash flows, short- and long-term debt and the issuance of equity. Capital expenditures were $862.3 million and $356.3 million for the nine months ended September 30, 2011 and 2010, respectively. Of these amounts, ONEOK Partners’ capital expenditures were $662.4 million and $202.8 million for the nine months ended September 30, 2011 and 2010, respectively. Capital expenditures for 2011 increased, compared with the same period last year, due primarily to the growth projects in ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses.

The following table sets forth our 2011 projected capital expenditures, excluding AFUDC:

2011 Projected Capital Expenditures
	(Millions of dollars)
ONEOK Partners	$	1,186
Distribution		240
Other		31
Total projected capital expenditures	$	1,457

Unconsolidated Affiliates - In July 2011, the partners of Northern Border Pipeline made equity contributions of approximately $99.6 million, with ONEOK Partners’ share totaling approximately $49.8 million. ONEOK Partners does 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 ONEOK Partners’ 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, ONEOK Partners had a Processing and Services Agreement with us and OBPI, under which it 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 its rights under the Processing and Services Agreement, ONEOK Partners 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, through a series of transactions, we sold OBPI to ONEOK Partners and OBPI closed the purchase option and terminated the equipment leases. The total amount paid by ONEOK Partners to complete the transactions was approximately $94.2 million, which included the reimbursement to us of obligations related to the Processing and Services Agreement.

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

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

ONEOK’s and ONEOK Partners’ commercial paper programs are each rated Prime-2 by Moody’s and A2 by S&P. ONEOK’s and ONEOK Partners’ credit ratings, which currently are investment grade, may be affected by a material change in financial ratios or a material event affecting the business. The most common criteria for assessment of credit ratings are

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the debt-to-capital ratio, business risk profile, pretax and after-tax interest coverage, and liquidity. ONEOK and ONEOK Partners currently do not anticipate their respective credit ratings to be downgraded. However, if ONEOK’s or ONEOK Partners’ credit ratings were downgraded, the cost to borrow funds under their respective commercial paper programs and credit agreements would increase, and ONEOK or ONEOK Partners potentially could lose access to the commercial paper market. In the event that ONEOK is unable to borrow funds under its commercial paper program and there has not been a material adverse change in its business, ONEOK would continue to have access to the ONEOK 2011 Credit Agreement, which expires in April 2016. In the event that ONEOK Partners is unable to borrow funds under its commercial paper program and there has not been a material adverse change in its business, ONEOK Partners would continue to have access to the ONEOK Partners 2011 Credit Agreement. An adverse rating change alone is not a default under the ONEOK 2011 Credit Agreement or the ONEOK Partners 2011 Credit Agreement.

Our Energy Services segment relies upon the investment-grade rating of ONEOK’s senior unsecured long-term debt to reduce its collateral requirements. If ONEOK’s credit ratings were to decline below investment grade, our ability to participate in energy marketing and trading activities could be significantly limited. Without an investment-grade rating, we may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments. At September 30, 2011, ONEOK could have been required to fund approximately $3.1 million in margin requirements related to financial contracts upon such a downgrade. A decline in ONEOK’s credit rating below investment grade may also significantly impact other business segments.

In the normal course of business, ONEOK’s and ONEOK Partners’ counterparties provide secured and unsecured credit. In the event of a downgrade in ONEOK’s or ONEOK Partners’ credit ratings or a significant change in ONEOK’s or ONEOK Partners’ counterparties’ evaluation of our creditworthiness, ONEOK or ONEOK Partners 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.

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 ONEOK’s and ONEOK Partners’ available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity price volatility. See discussion beginning on page 56 under “Commodity Price Risk” in Item 3, Quantitative and Qualitative Disclosures about Market Risk, for information on our hedging activities.

Pension and Postretirement Benefit Plans - Information about our pension and postretirement benefits plans, including anticipated contributions, is included under Note L of the Notes to Consolidated Financial Statements in our Annual Report. See Note I of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.

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, equity earnings from investments, distributions received from unconsolidated affiliates, deferred income taxes, share-based compensation expense and other amounts and changes in our assets and liabilities not classified as investing or financing activities.

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

	Nine Months Ended						Variances
	September 30,						2011 vs. 2010
	2011			2010			Increase (Decrease)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	1,029.6		$	760.0		$	269.6
Investing activities		(896.9	)		79.5			(976.4	)
Financing activities		(15.4	)		(818.4	)		803.0
Change in cash and cash equivalents		117.3			21.1			96.2
Cash and cash equivalents at beginning of period		31.1			29.4			1.7
Cash and cash equivalents at end of period	$	148.4		$	50.5		$	97.9

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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 increased competition from other service providers, could affect our earnings and operating cash flows.

Cash flows from operating activities, before changes in operating assets and liabilities, were $960.8 million for the nine months ended September 30, 2011, compared with $721.7 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 on page 35.

The changes in operating assets and liabilities increased operating cash flows $68.8 million for the nine months ended September 30, 2011, compared with an increase of $38.3 million for the same period in 2010. The increase was due primarily to the collection and payment of trade receivables and payables, resulting from the timing of invoices collected from customers and paid to vendors and suppliers, which vary from period to period; and a decrease in volumes of NGLs in storage in ONEOK Partners’ natural gas liquids business in the current period, compared with an increase in volumes in storage in ONEOK Partners’ natural gas liquids business in the same period last year.

Investing Cash Flows - Cash used in investing activities increased for the nine months ended September 30, 2011, compared with cash provided by investing activities for the same period in 2010, due primarily to ONEOK Partners’ growth projects in its natural gas gathering and processing and natural gas liquids businesses and the $423.7 million in proceeds ONEOK Partners received from the Overland Pass Pipeline transaction in September 2010.

Financing Cash Flows - Cash provided by financing activities increased for the nine months ended September 30, 2011, compared with the same period in 2010. The change is a result of ONEOK Partners’ January 2011 debt issuance, a portion of the proceeds from which were used to repay ONEOK Partners’ short-term borrowings and the March 2011 maturity of a portion of ONEOK Partners’ long-term debt. The remainder of the funds are used to fund ONEOK Partners’ growth projects and for general partnership purposes. The net cash flows provided by these financing activities were offset partially by the repayment of a scheduled maturity of ONEOK’s long-term debt, ONEOK’s $300 million share repurchase in May 2011, increased distributions to noncontrolling interests and increased dividends.

REGULATORY

Other - Several regulatory initiatives impacted the earnings and future earnings potential for our Distribution segment. See discussion of our Distribution segment’s regulatory initiatives beginning on page 43.

ENVIRONMENTAL AND SAFETY MATTERS

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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.

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

Pipeline Safety - We are subject to Pipeline and Hazardous Materials Safety Administration regulations, including integrity-management regulations. The Pipeline Safety Improvement Act of 2002 requires pipeline companies 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, 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.

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 the natural gas delivered by us to our distribution customers and emission equivalents for all NGLs delivered to customers of ONEOK Partners. Our 2010 total reported emissions was less than 66.6 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, carbon dioxide equivalents from NGL products and natural gas 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 expenses 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.

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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.

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, ONEOK Partners received notice from the EPA of potential liability for the U.S. Oil Recovery Superfund Site location in Harris County, Texas. ONEOK Partners is named a potentially responsible party as a result of waste disposal at the now-abandoned site. ONEOK Partners does not expect its current responsibilities under CERCLA, for this facility and any other, to have a material impact on its 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 enhancements cost 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 have 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 emission control; and (iv) following developing technologies to capture carbon dioxide to keep it from reaching the atmosphere.

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

IMPACT OF NEW ACCOUNTING STANDARDS

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

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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 revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.

Information about our estimates and critical accounting policies 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, including energy sales and 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 status of deregulation of retail natural gas distribution;

·	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;

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

·	the impact of unforeseen changes in interest rates, equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension and postretirement expense and funding resulting from changes in stock and bond market returns;

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·	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 ONEOK and ONEOK Partners;

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

·	adverse labor relations;

·	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 possible loss of natural gas distribution franchises or other adverse effects caused by the actions of municipalities;

·	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 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.

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ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

COMMODITY PRICE RISK

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

Energy Services

Fair Value Component of the Energy Marketing and Risk Management Assets and Liabilities - The following table sets forth the fair value component of the energy marketing and risk management assets and liabilities, excluding $36.3 million and $101.1 million of net assets at September 30, 2011, and December 31, 2010, respectively, from derivative instruments declared as either fair value or cash flow hedges for the periods indicated:

Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities
	(Thousands of dollars)
Net fair value of derivatives outstanding at December 31, 2010	$	8,441
Derivatives reclassified or otherwise settled during the period		(9,230	)
Fair value of new derivatives entered into during the period		19,636
Other changes in fair value		(7,463	)
Net fair value of derivatives outstanding at September 30, 2011 (a)	$	11,384
(a) - The maturities of derivatives are based on injection and withdrawal periods from April through March, which is consistent with our business strategy. The maturities are as follows: $1.8 million matures through March 2012 and $9.6 million matures through March 2015.

The change in the net fair value of derivatives outstanding includes the effect of settled energy contracts and current period changes resulting primarily from newly originated transactions and the impact of market movements on the fair value of energy marketing and risk management assets and liabilities.

For further discussion of derivative instruments and fair value measurements, see the “Estimates and Critical Accounting Policies” section of Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in our Annual Report. Also, see Notes B and C of the Notes to Consolidated Financial Statements in this Quarterly Report.

Value-at-Risk (VAR) Disclosure of Commodity Price Risk - The potential impact on our future earnings, as measured by VAR, was $3.2 million and $4.1 million at September 30, 2011 and 2010, respectively. The following table sets forth the average, high and low VAR calculations for the periods indicated:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Value-at-Risk	2011		2010		2011		2010
	(Millions of dollars)
Average	$	2.5	$	4.9	$	3.1	$	6.3
High	$	4.5	$	7.5	$	6.6	$	9.6
Low	$	1.2	$	3.3	$	1.2	$	3.3

Our VAR calculation includes derivatives, executory storage and transportation agreements and their related hedges. The variations in the VAR data are reflective of market volatility and changes in the portfolios during the year. The decrease in VAR for September 30, 2011, compared with September 30, 2010, is due to lower average commodity prices and decreased price volatility in 2011.

To the extent open commodity positions exist, fluctuating commodity prices can impact our financial results and financial position either favorably or unfavorably. As a result, we cannot predict with precision the impact risk-management decisions may have on our business, operating results or financial position.

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ITEM 4.

CONTROLS AND PROCEDURES

Quarterly Evaluation of Disclosure Controls and Procedures - Our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer) 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 Rules 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

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

Gas Index Pricing Litigation - As previously reported, ONEOK, Inc., and its affiliates, ONEOK Energy Services Company, L.P. (“OESC”), and Kansas Gas Marketing Company (“KGMC”), are defending multiple lawsuits arising from alleged market manipulation or false reporting of natural gas prices to natural gas-index publications. On August 3, 2011, the trial court entered a stay of any further proceedings in the Sinclair case while the trial court’s judgment on Sinclair’s state law claims is on appeal. On August 18, 2011, the trial court entered an order approving a stipulation by the plaintiffs and KGMC for a dismissal without prejudice of the plaintiffs’ claims against KGMC in the Learjet and Heartland cases. The plaintiffs in the Sinclair, Reorganized FLI, Learjet, Breckenridge, Arandell, Heartland and NewPage cases have appealed the judgments entered by the trial court in favor of ONEOK, Inc., OESC and other unaffiliated entities on July 18, 2011, to the United States Court of Appeals for the Ninth Circuit. On August 24, 2011, all of the appeals were consolidated for briefing purposes by the Ninth Circuit. We continue to analyze all claims and are defending vigorously against them.

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.

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ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth information relating to our purchases of our common stock for the periods indicated:

Period	Total Number of Shares Purchased		Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs

July 1-31, 2011	1,648	(a)	$20.67		-		-
August 1-31, 2011	586,112	(a), (b)	$69.98		584,021	$	450,000,000	(c)
September 1-30, 2011	-		-		-		-
Total	587,760		$69.84		584,021	$	450,000,000

(a) - Includes shares withheld pursuant to attestation of ownership and deemed tendered to us in connection with the exercise
of stock options under the ONEOK, Inc. Long-Term Incentive Plan, as follows:
1,648 shares for the period of July 1-31, 2011
2,091 shares for the period of August 1-31, 2011
(b) - Includes 584,021 shares based on the volume-weighted-average price of $70.17, purchased pursuant to our $300 million accelerated
share repurchase agreement discussed under "Liquidity and Capital Resources" in Item 2, Management's Discussion and
Analysis of Financial Condition and Results of Operations, in this Quarterly Report.
(c) - The maximum approximate dollar value of shares that may yet be purchased pursuant to our approximately $750 million stock repurchase
program that was announced on October 21, 2010, subject to the limitation that purchases will not exceed $300 million in any one calendar
year. The program will terminate upon the completion of the repurchase of $750 million of common stock or on December 31, 2013,
whichever occurs first.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

Not Applicable.

ITEM 4.

(REMOVED AND RESERVED)

Not Applicable.

ITEM 5.

OTHER INFORMATION

Not Applicable.

ITEM 6.

EXHIBITS

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

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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 three and 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, Inc. 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 thereunto duly authorized.

ONEOK, Inc.

Registrant

Date: November 2, 2011 By: /s/ Robert F. Martinovich

Robert F. Martinovich

Senior Vice President,

Chief Financial Officer and Treasurer

(Principal Financial Officer)