10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2012

OR

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

For the transition period from __________ to __________.

Commission file number   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 website, if any, every

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

Indicate by 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 April 27, 2012, the Company had 103,926,470 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 Months Ended March 31, 2012 and 2011	6
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2012 and 2011	7
	Consolidated Balance Sheets - March 31, 2012 and December 31, 2011	8-9
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2012 and 2011	11
	Consolidated Statement of Changes in Equity - Three Months Ended March 31, 2012	12-13
	Notes to Consolidated Financial Statements	14-34
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35-57
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	57-58
Item 4.	Controls and Procedures	58
Part II.	Other Information
Item 1.	Legal Proceedings	58
Item 1A.	Risk Factors	58
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	59
Item 3.	Defaults Upon Senior Securities	59
Item 4.	Mine Safety Disclosures	59
Item 5.	Other Information	59
Item 6.	Exhibits	59-60
Signature		61

As used in this Quarterly Report, references to “we,” “our” or “us” refer to ONEOK, Inc., an Oklahoma corporation, and its predecessors, divisions 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 under Part I, Item IA, “Risk Factors,” in our Annual Report.

INFORMATION AVAILABLE ON OUR WEBSITE

We make available, free of charge, on our website (www.oneok.com) copies of our Annual Reports, 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.  Copies of our Code of Business Conduct, Corporate Governance Guidelines and Director Independence Guidelines are also available on our website, and we will provide copies of these documents upon request.  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.

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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, 2011
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
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
DOT	United States Department of Transportation
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
Intermediate Partnership	ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary           of ONEOK Partners, L.P.
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)
NYMEX	New York Mercantile Exchange
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 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 GP	ONEOK Partners GP, L.L.C., a wholly owned subsidiary of ONEOK and the sole           general partner of ONEOK Partners

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Quarterly Report(s)	Quarterly Report(s) on Form 10-Q
POP	Percent of Proceeds
S&P	Standard & Poor’s Rating Services
SEC	Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
XBRL	eXtensible Business Reporting Language

5

PART I - FINANCIAL INFORMATION
ITEM 1.  FINANCIAL STATEMENTS
ONEOK, Inc. and Subsidiaries
CONSOLIDATED  STATEMENTS OF INCOME
	Three Months Ended
	March 31,
(Unaudited)	2012	2011

(Thousands of dollars, except per share amounts)

Revenues	$	3,414,600		$	3,760,600
Cost of sales and fuel		2,771,013			3,130,723
Net margin		643,587			629,877
Operating expenses
Operations and maintenance		192,881			192,759
Depreciation and amortization		83,409			79,357
Goodwill impairment		10,255			-
General taxes		31,177			28,922
Total operating expenses		317,722			301,038
Gain (loss) on sale of assets		57			(510	)
Operating income		325,922			328,329
Equity earnings from investments (Note K)		34,620			32,092
Allowance for equity funds used during construction		975			466
Other income		9,861			3,352
Other expense		(2,274	)		(2,285	)
Interest expense		(75,815	)		(79,349	)
Income before income taxes		293,289			282,605
Income taxes		(73,839	)		(84,320	)
Income from continuing operations		219,450			198,285
Income from discontinued operations, net of tax (Note B)		762			1,061
Gain on sale of discontinued operations, net of tax (Note B)		13,250			-
Net income		233,462			199,346
Less: Net income attributable to noncontrolling interests		110,597			69,216
Net income attributable to ONEOK	$	122,865		$	130,130
Amounts attributable to ONEOK:
Income from continuing operations	$	108,853		$	129,069
Income from discontinued operations		14,012			1,061
Net Income	$	122,865		$	130,130
Basic earnings per share:
Income from continuing operations (Note I)	$	1.05		$	1.21
Income from discontinued operations		0.13			0.01
Net Income	$	1.18		$	1.22
Diluted earnings per share:
Income from continuing operations (Note I)	$	1.03		$	1.18
Income from discontinued operations		0.13			0.01
Net Income	$	1.16		$	1.19
Average shares (thousands)
Basic		103,809			107,020
Diluted		105,926			109,179
Dividends declared per share of common stock	$	0.61		$	0.52
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	Three Months Ended
	March 31,
(Unaudited)	2012			2011
	(Thousands of dollars)
Net income	$	233,462		$	199,346
Other comprehensive income (loss), net of tax
Unrealized gains (losses) on energy marketing and risk-management
assets/liabilities, net of tax of ($19,094) and $1,415, respectively		47,573			(16,888	)
Realized losses (gains) in net income, net of tax of ($1,615) and
$12,235, respectively		(1,180	)		(20,116	)
Unrealized holding gains (losses) on available-for-sale securities,
net of tax of ($141) and $63, respectively		224			(99	)
Change in pension and postretirement benefit plan liability, net of tax
of $3,644 and $2,947, respectively		(5,777	)		(4,673	)
Other, net of tax of $0 and $11, respectively		-			(18	)
Total other comprehensive income (loss), net of tax		40,840			(41,794	)
Comprehensive income		274,302			157,552
Less: Comprehensive income attributable to noncontrolling interests		124,161			53,757
Comprehensive income attributable to ONEOK	$	150,141		$	103,795
See accompanying Notes to Consolidated Financial Statements.

7

ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	March 31,		December 31,
(Unaudited)	2012		2011
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	781,192	$	65,953
Accounts receivable, net		1,154,951		1,339,933
Gas and natural gas liquids in storage		299,130		549,915
Commodity imbalances		163,939		63,452
Energy marketing and risk management assets (Notes C and D)		54,368		40,280
Other current assets		155,695		185,143
Assets of discontinued operations (Note B)		-		74,136
Total current assets		2,609,275		2,318,812
Property, plant and equipment
Property, plant and equipment		11,495,219		11,177,934
Accumulated depreciation and amortization		2,794,183		2,733,601
Net property, plant and equipment		8,701,036		8,444,333
Investments and other assets
Goodwill and intangible assets		1,001,956		1,014,127
Investments in unconsolidated affiliates (Note K)		1,219,635		1,223,398
Other assets		720,174		695,965
Total investments and other assets		2,941,765		2,933,490
Total assets	$	14,252,076	$	13,696,635
See accompanying Notes to Consolidated Financial Statements.

8

ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	March 31,			December 31,
(Unaudited)	2012			2011
Liabilities and equity	(Thousands of dollars)
Current liabilities
Current maturities of long-term debt	$	364,397		$	364,391
Notes payable (Note E)		419,757			841,982
Accounts payable		1,110,108			1,341,718
Commodity imbalances		201,089			202,206
Energy marketing and risk management liabilities (Notes C and D)		94,573			137,680
Other current liabilities		410,399			345,383
Liabilities of discontinued operations (Note B)		-			12,815
Total current liabilities		2,600,323			3,246,175
Long-term debt, excluding current maturities (Note F)		5,225,849			4,529,551
Deferred credits and other liabilities
Deferred income taxes		1,408,420			1,446,591
Other deferred credits		638,029			674,586
Total deferred credits and other liabilities		2,046,449			2,121,177
Commitments and contingencies (Note M)
Equity (Note G)
ONEOK shareholders' equity:
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 122,905,591 shares and outstanding
103,922,403 shares at March 31, 2012; issued 122,904,924 shares and
outstanding 103,254,980 shares at December 31, 2011		1,229			1,229
Paid-in capital		1,317,489			1,418,414
Accumulated other comprehensive loss (Note H)		(178,845	)		(206,121	)
Retained earnings		2,019,864			1,960,374
Treasury stock, at cost: 18,983,188 shares at March 31, 2012, and
19,649,944 shares at December 31, 2011		(903,585	)		(935,323	)
Total ONEOK shareholders' equity		2,256,152			2,238,573
Noncontrolling interests in consolidated subsidiaries		2,123,303			1,561,159
Total equity		4,379,455			3,799,732
Total liabilities and equity	$	14,252,076		$	13,696,635
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Three Months Ended
	March 31,
(Unaudited)	2012			2011
	(Thousands of dollars)
Operating Activities
Net income	$	233,462		$	199,346
Depreciation and amortization		83,417			79,391
Impairment of goodwill		10,255			-
Gain on sale of discontinued operations		(13,250	)		-
Reclassified loss on energy price risk management assets and liabilities		29,861			-
Equity earnings from investments		(34,620	)		(32,092	)
Distributions received from unconsolidated affiliates		36,879			27,607
Deferred income taxes		51,411			52,044
Share-based compensation expense		5,008			7,902
Allowance for equity funds used during construction		(975	)		(466	)
Loss (gain) on sale of assets		(57	)		510
Other		(1,360	)		(333	)
Changes in assets and liabilities:
Accounts receivable		180,413			53,410
Gas and natural gas liquids in storage		251,227			301,262
Accounts payable		(176,674	)		(77,843	)
Commodity imbalances, net		(101,604	)		(18,092	)
Energy marketing and risk management assets and liabilities		(122,900	)		(12,683	)
Other assets and liabilities		(4,408	)		67,818
Cash provided by operating activities		426,085			647,781
Investing Activities
Capital expenditures (less allowance for equity funds used during construction)		(348,437	)		(194,679	)
Proceeds from sale of discontinued operations, net of cash sold		32,008			-
Contributions to unconsolidated affiliates		(2,577	)		(250	)
Distributions received from unconsolidated affiliates		4,062			4,904
Proceeds from sale of assets		521			540
Other		24			-
Cash used in investing activities		(314,399	)		(189,485	)
Financing Activities
Borrowing (repayment) of notes payable, net		(422,225	)		(556,855	)
Issuance of debt, net of discounts		699,657			1,295,450
Long-term debt financing costs		(5,392	)		(10,986	)
Repayment of debt		(3,082	)		(228,137	)
Issuance of common stock		2,228			5,024
Issuance of common units		459,735			-
Dividends paid		(63,375	)		(55,651	)
Distributions to noncontrolling interests		(72,852	)		(68,041	)
Other		-			(48	)
Cash provided by financing activities		594,694			380,756
Change in cash and cash equivalents		706,380			839,052
Change in cash and cash equivalents included in discontinued operations		8,859			7,179
Change in cash and cash equivalents from continuing operations		715,239			846,231
Cash and cash equivalents at beginning of period		65,953			30,341
Cash and cash equivalents at end of period	$	781,192		$	876,572
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			Income (Loss)
	(Shares)		(Thousands of dollars)
December 31, 2011		122,904,924		$	1,229	$	1,418,414		$	(206,121	)
Net income		-			-		-			-
Other comprehensive income		-			-		-			27,276
Common stock issued		667			-		(29,177	)		-
Common stock dividends -
$0.61 per share		-			-		-			-
Issuance of common units of ONEOK Partners		-			-		(51,100	)		-
Distributions to noncontrolling interests		-			-		-			-
Other		-			-		(20,648	)		-
March 31, 2012		122,905,591		$	1,229	$	1,317,489		$	(178,845	)
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, 2011	$	1,960,374		$	(935,323	)	$	1,561,159		$	3,799,732
Net income		122,865			-			110,597			233,462
Other comprehensive income		-			-			13,564			40,840
Common stock issued		-			31,738			-			2,561
Common stock dividends -
$0.61 per share		(63,375	)		-			-			(63,375	)
Issuance of common units of ONEOK Partners		-			-			510,835			459,735
Distributions to noncontrolling interests		-			-			(72,852	)		(72,852	)
Other		-			-			-			(20,648	)
March 31, 2012	$	2,019,864		$	(903,585	)	$	2,123,303		$	4,379,455

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ONEOK, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 2011 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 months ended March 31, 2012, 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.

Recently Issued Accounting Standards Update -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 adopted this guidance with this Quarterly Report and the impact was not material.  See Note C for information on our fair value measurements.

In June 2011, the FASB issued ASU 2011-05, “Presentation of Comprehensive Income,” which provides two options for presenting items of net income, other comprehensive income and total comprehensive income by creating either one continuous statement of comprehensive income or two separate consecutive statements, and requires certain other disclosures.  In December 2011, the FASB issued ASU 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05,” which deferred certain presentation requirements in ASU 2011-05 for items reclassified out of accumulated other comprehensive income.  We adopted this guidance, except for the portions deferred by ASU 2011-12, with this Quarterly Report, and the impact was not material.

B.           DISCONTINUED OPERATIONS

On February 1, 2012, we sold ONEOK Energy Marketing Company, our retail natural gas marketing business, to Constellation Energy Group, Inc. for $22.5 million plus working capital.  We received net proceeds of approximately $32.0 million, and recognized an after-tax gain on the sale of approximately $13.3 million.  The proceeds from the sale were used to reduce short-term borrowings.  The financial information of ONEOK Energy Marketing Company is reflected as discontinued operations in this Quarterly Report.  All prior periods presented have been recast to reflect the discontinued operations.

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The amounts of revenue, costs and income taxes reported in discontinued operations are set forth in the table below for the periods indicated:

	One Month Ended			Three Months Ended
	January 31,			March 31,
	2012			2011
	(Thousands of dollars)
Operating revenues	$	27,607			$	106,289
Cost of sales and fuel		25,961				102,617
Net margin		1,646				3,672
Operating costs		408				1,933
Depreciation, depletion and amortization		8				32
Operating income		1,230				1,707
Other income (expense), net		-				16
Income taxes		(468	)			(662	)
Income from discontinued operations, net	$	762			$	1,061
Gain on sale of discontinued operation, net of tax of $8,119	$	13,250			$	-

The following table discloses the major classes of discontinued assets and liabilities included on our Consolidated Balance Sheets for the period indicated:

		December 31,
		2011
Assets	(Thousands of dollars)
Cash and cash equivalents		$	8,859
Accounts receivable, net			47,967
Gas in storage			2,101
Energy marketing and risk management assets			15,016
Other assets			193
Assets of discontinued operations		$	74,136
Liabilities
Accounts payable		$	11,435
Energy marketing and risk management liabilities			629
Other liabilities			751
Liabilities of discontinued operations		$	12,815

At December 31, 2011, the liabilities of our discontinued operations exclude $45.7 million of intercompany payables due to its parent or other affiliates.

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C.           FAIR VALUE MEASUREMENTS

Fair Value Measurements -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 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 monitor 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 our continuing and discontinued operations for the periods indicated:

	March 31, 2012
	Level 1			Level 2			Level 3			Netting			Total
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	601,625		$	20,271		$	27,480		$	-		$	649,376
Physical contracts		-			23,678			3,464			-			27,142
Netting		-			-			-			(603,984	)		(603,984	)
Total derivatives		601,625			43,949			30,944			(603,984	)		72,534
Trading securities (b)		6,826			-			-			-			6,826
Available-for-sale investment securities (c)		2,315			-			-			-			2,315
Total assets	$	610,766		$	43,949		$	30,944		$	(603,984	)	$	81,675
Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(595,397	)	$	(11,766	)	$	(12,859	)	$	-		$	(620,022	)
Physical contracts		-			(83	)		(137	)		-			(220	)
Netting		-			-			-			589,142			589,142
Interest-rate contracts		-			(63,473	)		-			-			(63,473	)
Total derivatives		(595,397	)		(75,322	)		(12,996	)		589,142			(94,573	)
Fair value of firm commitments (d)		-			-			(3,770	)		-			(3,770	)
Total liabilities	$	(595,397	)	$	(75,322	)	$	(16,766	)	$	589,142		$	(98,343	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk-management assets and liabilities and other assets 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 March 31, 2012, we held $15.1 million of cash collateral and had posted $0.3 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.

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	December 31, 2011
	Level 1			Level 2			Level 3			Netting			Total
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	545,247		$	13,874		$	32,931		$	-		$	592,052
Physical contracts		-			23,879			14,916			-			38,795
Netting		-			-			-			(569,243	)		(569,243	)
Total derivatives		545,247			37,753			47,847			(569,243	)		61,604
Trading securities (b)		5,749			-			-			-			5,749
Available-for-sale investment securities (c)		1,949			-			-			-			1,949
Total assets	$	552,945		$	37,753		$	47,847		$	(569,243	)	$	69,302
Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(479,073	)	$	(6,498	)	$	(20,995	)	$	-		$	(506,566	)
Physical contracts		-			(261	)		(1,748	)		-			(2,009	)
Netting		-			-			-			497,608			497,608
Interest-rate contracts		-			(128,666	)		-			-			(128,666	)
Total derivatives		(479,073	)		(135,425	)		(22,743	)		497,608			(139,633	)
Fair value of firm commitments (d)		-			-			(7,283	)		-			(7,283	)
Total liabilities	$	(479,073	)	$	(135,425	)	$	(30,026	)	$	497,608		$	(146,916	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk-management assets and liabilities, other assets and other deferred credits 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, 2011, we held $73.3 million of cash collateral and had posted $1.7 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.

The tables above include balances for ONEOK Energy Marketing Company that have been reflected as discontinued operations in our Consolidated Balance Sheets.  At December 31, 2011, we had $15.0 million in derivative assets and $0.6 million in derivative liabilities related to this discontinued operation.

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 nonexchange-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 broker quotes, 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.  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.  The significant unobservable inputs used in the fair value measurement of our swaps, forwards and firm commitments are the unpublished forward basis and

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index curves.  Significant increases or decreases in either of those inputs in isolation would not have a material impact on our fair value measurements.

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)
January 1, 2012	$	25,104		$	(7,283	)	$	17,821
Total realized/unrealized gains (losses):
Included in earnings (a)		(4,801	)		3,513			(1,288	)
Included in other comprehensive income (loss)		5,785			-			5,785
Sale of discontinued operations		(3,636	)		-			(3,636	)
Transfers into Level 3		-			-			-
Transfers out of Level 3		(4,504	)		-			(4,504	)
March 31, 2012	$	17,948		$	(3,770	)	$	14,178
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 March 31, 2012 (a)	$	(4,687	)	$	1,498		$	(3,189	)
(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, 2011	$	49,266		$	(29,536	)	$	19,730
Total realized/unrealized gains (losses):
Included in earnings (a)		(7,696	)		545			(7,151	)
Included in other comprehensive income (loss)		(9,855	)		-			(9,855	)
Transfers into Level 3		6			-			6
Transfers out of Level 3		(1,106	)		-			(1,106	)
March 31, 2011	$	30,615		$	(28,991	)	$	1,624
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 March 31, 2011 (a)	$	2,878		$	(4,191	)	$	(1,313	)
(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 the levels in the fair value hierarchy as of the end of each reporting period.  We had no transfers into or out of Level 1 during the periods presented.  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.

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The following table provides quantitative information about our Level 3 unobservable inputs, excluding the portion of our fair value measurements based on third-party pricing information without adjustment for the period indicated:

March 31, 2012
	Derivative Assets (Liabilities)		Fair Value of Firm Commitments			Unobservable Inputs	Valuation Process
(Thousands of dollars)
Commodity contracts (a)
Financial	$	126	$	-		Basis and Index Curves	Notional volume x Price Curve
Physical		1,355		(424	)	Basis and Index Curves	Notional volume x Price Curve
Unobservable inputs	$	1,481	$	(424	)
(a) - Unpublished basis and index curves on commodity contracts developed using broker quotes and management estimates.

Goodwill Impairment - As a result of the continued decline in natural gas prices and its effect on location and seasonal price differentials, we performed an interim impairment assessment of our Energy Services segment’s goodwill balance as of March 31, 2012. As a result of this assessment, goodwill with a carrying amount of $10.3 million was written down to its implied fair value of zero, with a resulting impairment charge of $10.3 million recorded in earnings for the period.  The fair value of our Energy Services reporting unit and the implied fair value of its goodwill were calculated using Level 3, significant unobservable inputs.

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.

Our cash and cash equivalents are comprised of bank and money market accounts and would be classified as Level 1.  Our notes payable would be classified as Level 2 since the estimated fair value of the notes payable can be determined using information available in the commercial paper market.  The estimated fair value of our consolidated long-term debt, including current maturities, was $6.3 billion at March 31, 2012, and $5.6 billion at December 31, 2011.  The book value of long-term debt, including current maturities, was $5.6 billion and $4.9 billion at March 31, 2012, and December 31, 2011, 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.  Our consolidated long-term debt would be classified as Level 2.

D.           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.

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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.

Our Natural Gas Distribution segment also uses derivative instruments to hedge the cost of a portion 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 Texas jurisdictions.

ONEOK and ONEOK Partners have each entered into forward-starting interest-rate swaps 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.  ONEOK had interest-rate swaps with a notional value of $500 million at December 31, 2011.  In January 2012, ONEOK entered into additional interest-rate swaps with a notional amount of $200 million.  Upon issuance in January 2012 of our $700 million, 4.25-percent senior notes due 2022, ONEOK settled all $700 million of its interest-rate swaps and realized a loss of $44.1 million in accumulated other comprehensive income that will be amortized to interest expense over the term of the hedged debt.  At March 31, 2012, and December 31, 2011, ONEOK Partners had forward-starting interest-rate swaps with notional amounts of $750 million.  In April 2012, ONEOK Partners entered into additional forward-starting interest-rate swaps with a notional amount of $250 million.

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.

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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 Natural Gas 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.

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.

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

	March 31, 2012							December 31, 2011
	Fair Values of Derivatives (a)							Fair Values of Derivatives (a)
	Assets			(Liabilities)				Assets			(Liabilities)
	(Thousands of dollars)
Derivatives designated as hedging instruments
Commodity contracts
Financial contracts	$	146,928	(b)	$	(102,526	)	(b)	$	184,184	(c)	$	(73,346	)
Physical contracts		375			(43	)			62			(344	)
Interest-rate contracts		-			(63,473	)			-			(128,666	)
Total derivatives designated as hedging instruments		147,303			(166,042	)			184,246			(202,356	)
Derivatives not designated as hedging instruments
Commodity contracts
Nontrading instruments
Financial contracts		345,662			(362,653	)			295,948			(323,170	)
Physical contracts		26,767			(177	)			38,733			(1,665	)
Trading instruments
Financial contracts		156,786			(154,843	)			111,920			(110,050	)
Total derivatives not designated as hedging instruments		529,215			(517,673	)			446,601			(434,885	)
Total derivatives	$	676,518		$	(683,715	)		$	630,847		$	(637,241	)
(a) - Included on a net basis in energy marketing and risk-management assets and liabilities, other assets and other deferred credits on our Consolidated Balance Sheets.
(b) - Includes $11.1 million of derivative assets associated with cash flow hedges of inventory that were adjusted to reflect the lower of cost or market value in a prior period. Also, includes $31.6 million of net derivative liabilities and ineffectiveness associated with cash flow hedges of inventory related to certain financial contracts that were used to hedge forecasted purchases of natural gas. The deferred gains and losses associated with these assets and net liabilities have been reclassified from accumulated other comprehensive loss.
(c) - Includes $88.9 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.

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

		March 31, 2012				December 31, 2011
	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		21.0	(20.9	)		21.2	(23.4	)
	Swaps		18.4	(95.2	)		19.5	(111.9	)
- Crude oil and NGLs (MMBbl)	Swaps		-	(3.6	)		-	(2.9	)
Basis
- Natural gas (Bcf)	Forwards and swaps		4.1	(49.6	)		3.2	(82.8	)
Interest-rate contracts (Millions of dollars)	Forward-starting swaps	$	750.0	-		$	1,250.0	-
Fair value hedges
Basis
- Natural gas (Bcf)	Forwards and swaps		109.1	(109.1	)		76.5	(77.0	)
Derivatives not designated as hedging instruments:
Fixed price
- Natural gas (Bcf)	Exchange futures		56.7	(53.4	)		76.9	(59.6	)
	Forwards and swaps		197.3	(200.6	)		235.8	(253.4	)
	Options		146.1	(141.1	)		33.6	(14.3	)
Basis
- Natural gas (Bcf)	Forwards and swaps		184.0	(186.1	)		216.9	(219.3	)
Index
- Natural gas (Bcf)	Forwards and swaps		51.8	(22.7	)		29.3	(22.1	)

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 March 31, 2012, includes net gains of approximately $22.8 million, net of tax, related to these hedges that will be recognized within the next 21 months as the forecasted transactions affect earnings.  If prices remain at current levels, we will recognize $13.1 million in net gains over the next 12 months, and we will recognize net gains of $9.7 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 months ended March 31, 2012, net margin in Consolidated Statements of Income includes losses of $29.9 million related to certain financial contracts that were used to hedge forecasted purchases of natural gas.  As a result of the continued decline in natural gas prices, the combination of the cost basis of the forecasted purchases of inventory and the financial contracts exceed the amount expected to be recovered through sales of that inventory after considering related sales hedges, which requires reclassification of the loss from accumulated other comprehensive loss to current period earnings.

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

	Three Months Ended
Derivatives in Cash Flow Hedging Relationships	March 31,
	2012		2011
	(Thousands of dollars)
Commodity contracts	$	45,565	$	(18,303	)
Interest rate contracts		21,102		-
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	$	66,667	$	(18,303	)

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

	Location of Gain (Loss) Reclassified from	Three Months Ended
Derivatives in Cash Flow	Accumulated Other Comprehensive Income	March 31,
Hedging Relationship	(Loss) into Net Income (Effective Portion)	2012			2011
		(Thousands of dollars)
Commodity contracts	Revenues	$	62,369		$	33,387
Commodity contracts	Cost of sales and fuel		(61,977	)		(828	)
Interest-rate contracts	Interest expense		(827	)		(208	)
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)		$	(435	)	$	32,351

Ineffectiveness related to our cash flow hedges was not material for the three months ended March 31, 2012 and 2011.  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 months ended March 31, 2012 and 2011, there were no gains or losses due to the discontinuance of cash flow hedge treatment as a result of the underlying transactions being 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 our continuing and discontinued operations for the periods indicated:

		Three Months Ended
Derivatives Not Designated as		March 31,
Hedging Instruments	Location of Gain (Loss)	2012		2011
		(Thousands of dollars)
Commodity contracts - trading	Revenues	$	315	$	406
Commodity contracts - nontrading (a)	Cost of sales and fuel		2,963		2,548
Total gain recognized in income on derivatives		$	3,278	$	2,954
(a) - Amounts are presented net of deferred losses associated with derivatives entered into by our Natural Gas Distribution segment.

Our Natural Gas Distribution segment did not hold any derivative financial instruments at March 31, 2012, and held call options with premiums totaling $10 million at December 31, 2011.  The premiums are recorded in other current assets as these contracts are included in, and recoverable through, the monthly purchased-gas cost mechanism.  We recorded immaterial losses associated with the decline in the value and expiration of option contracts for the three months ended March 31, 2012 and 2011.  The gains and losses associated with these derivative instruments are deferred as part of our unrecovered purchase-gas costs.

Fair Value Hedges - 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 $0.5 million and $5.4 million for the three months ended March 31, 2012 and 2011, respectively, related to the change in fair value of derivatives designated as fair value hedges.  Revenues include losses of $1.8 million and $5.0 million for the three months ended March 31, 2012 and 2011, respectively, to recognize the change in fair value of the related hedged firm commitments.  Ineffectiveness included in cost of sales and fuel related to these hedges was immaterial for the three months ended March 31, 2012 and 2011.

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

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contingent features related to credit risk that were in a net liability position as of March 31, 2012, was $6.8 million.  If the contingent features underlying these agreements were triggered on March 31, 2012, we would have been required to post an additional $6.8 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 affected similarly 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 period indicated:

	March 31, 2012
	Investment		Noninvestment		Not
	Grade		Grade		Rated		Total
Counterparty sector	(Thousands of dollars)
Gas and electric utilities	$	34,644	$	-	$	374	$	35,018
Oil and gas		11,791		3		75		11,869
Financial		24,798		-		-		24,798
Other		124		11		714		849
Total	$	71,357	$	14	$	1,163	$	72,534

	December 31, 2011
	Investment		Noninvestment		Not
	Grade		Grade		Rated		Total
Counterparty sector	(Thousands of dollars)
Gas and electric utilities	$	22,335	$	-	$	564	$	22,899
Oil and gas		9,986		5		80		10,071
Industrial		7		-		14,955		14,962
Financial		13,566		-		-		13,566
Other		100		6		-		106
Total	$	45,994	$	11	$	15,599	$	61,604

E.           CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

ONEOK 2011 Credit Agreement -The ONEOK 2011 Credit Agreement, which is scheduled to expire in April 2016, contains certain financial, operational and legal covenants.  Among other things, these covenants include maintaining ONEOK’s stand-alone debt-to-capital ratio of no more than 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 from $1.2 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 March 31, 2012, ONEOK’s stand-alone debt-to-capital ratio, as defined by the ONEOK 2011 Credit Agreement, was 47.1 percent, and ONEOK was in compliance with all covenants under the ONEOK 2011 Credit

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Agreement.  At March 31, 2012, ONEOK had $419.8 million of commercial paper outstanding and $2.0 million in letters of credit issued, leaving approximately $778.2 million of credit available under the ONEOK 2011 Credit Agreement.

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.

ONEOK Partners 2011 Credit Agreement - 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 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 increase to 5.5 to 1 for the quarter of the acquisition and the two following quarters.  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 from $1.2 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.

At March 31, 2012, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 2.6 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners 2011 Credit Agreement.  At March 31, 2012, ONEOK Partners had no commercial paper outstanding, no letters of credit issued and no borrowings under the ONEOK Partners 2011 Credit Agreement.

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.

F.           LONG-TERM DEBT

In January 2012, we completed an underwritten public offering of $700 million, 4.25-percent senior notes due 2022.  The net proceeds from the offering, after deducting underwriting discounts and offering expenses, of approximately $694.3 million were used to repay amounts outstanding under our $1.2 billion commercial paper program and for general corporate purposes.

The indenture governing ONEOK’s senior notes due 2022 includes 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 2022 to declare those senior notes immediately due and payable in full.

ONEOK may redeem its senior notes due 2022 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting three months before the maturity date.  Prior to this date, ONEOK may redeem the senior notes due 2022, in whole or in part, at any time for 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’s senior notes due 2022 are senior unsecured obligations, ranking equally in right of payment with all of ONEOK’s existing and future unsecured senior indebtedness.

ONEOK Partners repaid its $350 million, 5.9-percent senior notes at maturity in April 2012 with a portion of the proceeds from its March 2012 equity issuance.

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G.           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
	March 31, 2012									March 31, 2011
	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	$	2,238,573		$	1,561,159		$	3,799,732		$	2,448,623		$	1,472,218		$	3,920,841
Net income		122,865			110,597			233,462			130,130			69,216			199,346
Other comprehensive income (loss)		27,276			13,564			40,840			(26,335	)		(15,459	)		(41,794	)
Repurchase of common stock		-			-			-			(48	)		-			(48	)
Common stock issued		2,561			-			2,561			2,365			-			2,365
Common stock dividends		(63,375	)		-			(63,375	)		(55,651	)		-			(55,651	)
Issuance of common units of ONEOK Partners		(51,100	)		510,835			459,735			-			-			-
Distributions to noncontrolling interests		-			(72,852	)		(72,852	)		-			(68,041	)		(68,041	)
Other		(20,648	)		-			(20,648	)		-			-			-
Ending balance	$	2,256,152		$	2,123,303		$	4,379,455		$	2,499,084		$	1,457,934		$	3,957,018

Stock Split - On February 15, 2012, our Board of Directors authorized a two-for-one split of our common stock, subject to shareholder approval of a proposal to increase the number of authorized shares of our common stock to 600 million from 300 million.  The proposal will be voted on at our 2012 annual meeting of shareholders on May 23, 2012.

Dividends - Fourth-quarter 2011 and first-quarter 2012 dividends paid on our common stock to shareholders of record at the close of business on January 31, 2012, and April 30, 2012, respectively, were $0.61 per share for each period.

See Note L for a discussion of the issuance of common units and distributions to noncontrolling interests.

H.           ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following table sets forth the balance in accumulated other comprehensive income (loss) for the period 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, 2011	$	(55,367)	$	987	$	(151,741)	$	(206,121)
Other comprehensive income (loss)    attributable to ONEOK		32,829		224		(5,777)		27,276
March 31, 2012	$	(22,538)	$	1,211	$	(157,518)	$	(178,845)

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I.           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 March 31, 2012
	Income		Shares		Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK
available for common stock	$	108,853		103,809	$	1.05
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-		2,117
Income from continuing operations attributable to ONEOK
available for common stock and common stock equivalents	$	108,853		105,926	$	1.03

	Three Months Ended March 31, 2011
	Income		Shares		Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK
available for common stock	$	129,069		107,020	$	1.21
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-		2,159
Income from continuing operations attributable to ONEOK
available for common stock and common stock equivalents	$	129,069		109,179	$	1.18

There were no option shares excluded from the calculation of diluted EPS for the three months ended March 31, 2012 and 2011.

J.           EMPLOYEE BENEFIT PLANS

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

	Pension Benefits						Postretirement Benefits
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2012			2011			2012			2011
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	5,325		$	5,003		$	1,240		$	1,260
Interest cost		14,809			14,689			3,473			3,958
Expected return on assets		(20,689	)		(18,875	)		(2,671	)		(2,568	)
Amortization of unrecognized net asset at adoption		-			-			718			797
Amortization of unrecognized prior service cost		242			254			(2,063	)		(501	)
Amortization of net loss		12,111			8,928			3,296			2,031
Net periodic benefit cost	$	11,798		$	9,999		$	3,993		$	4,977

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K.           UNCONSOLIDATED AFFILIATES

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
	March 31,
	2012		2011
	(Thousands of dollars)
Northern Border Pipeline Company	$	20,231	$	20,852
Overland Pass Pipeline		5,317		4,376
Fort Union Gas Gathering		4,208		2,965
Bighorn Gas Gathering		1,165		1,493
Other		3,699		2,406
Equity earnings from investments	$	34,620	$	32,092

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

	Three Months Ended
	March 31,
	2012		2011
	(Thousands of dollars)
Income Statement
Operating revenues	$	127,924	$	123,301
Operating expenses	$	54,568	$	54,236
Net income	$	65,254	$	63,165
Distributions paid to us	$	40,941	$	32,511

L.           ONEOK PARTNERS

Unit Split - In July 2011, ONEOK Partners completed a two-for-one split of its common and Class B units, and its Partnership Agreement was amended to adjust the formula for distributing available cash among its general partner and limited partners to reflect the unit split.  As a result, all unit and per-unit amounts contained herein have been adjusted to be presented on a post-split basis.

Equity Issuance -In March 2012, ONEOK Partners completed an underwritten public offering of 8,000,000 common units at a public offering price of $59.27 per common unit, generating net proceeds of approximately $460 million.  ONEOK Partners also sold 8,000,000 common units to us in a private placement, generating net proceeds of approximately $460 million.  In conjunction with the issuances, we contributed $19.1 million in order to maintain our 2-percent general partner interest in ONEOK Partners.  ONEOK Partners used the net proceeds from the offering to repay approximately $295 million under its $1.2 billion commercial paper program, to repay amounts on the maturity of its $350 million, 5.9-percent senior notes due April 2012 and for other general partnership purposes, including capital expenditures.  As a result of these transactions, our aggregate ownership interest in ONEOK Partners increased to 43.4 percent from 42.8 percent.

We account for the difference between the carrying amount of our investment in ONEOK Partners and the underlying book value arising from issuance of common units by ONEOK Partners as an equity transaction.  As a result of ONEOK Partners’ issuance of common units, we recognized a decrease in paid-in capital of approximately $51.1 million during the three months ended March 31, 2012.

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Ownership Interest in ONEOK Partners - Our ownership interest in ONEOK Partners is shown in the table below as of March 31, 2012:

General partner interest	2.0%
Limited partner interest (a)	41.4%
Total ownership interest	43.4%
(a) - Represents 19.8 million common units and approximately 73.0 million Class B units, which are convertible, at our option, into common units.

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.  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
	March 31,
	2012		2011
	(Thousands, except per unit amounts)
Distribution per unit	$	0.61	$	0.57
General partner distributions	$	3,281	$	2,956
Incentive distributions		36,472		28,645
Distributions to general partner		39,753		31,601
Limited partner distributions to ONEOK		51,721		48,329
Limited partner distributions to noncontrolling interest		72,609		67,846
Total distributions paid	$	164,083	$	147,776

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
	March 31,
	2012		2011
	(Thousands, except per unit amounts)
Distribution per unit	$	0.635	$	0.575
General partner distributions	$	3,759	$	2,996
Incentive distributions		44,610		29,624
Distributions to general partner		48,369		32,620
Limited partner distributions to ONEOK		58,921		48,753
Limited partner distributions to noncontrolling interest		80,662		68,441
Total distributions declared	$	187,952	$	149,814

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 the distributions we receive.  Distributions are declared quarterly by ONEOK Partners’ general partner based on the terms of the ONEOK Partners partnership agreement.  See Note N for more information on ONEOK Partners’ results.

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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 Natural Gas 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.

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
	March 31,
	2012		2011
	(Thousands of dollars)
Revenues	$	75,705	$	96,793
Expenses
Cost of sales and fuel	$	9,275	$	10,731
Administrative and general expenses		56,361		56,295
Total expenses	$	65,636	$	67,026

M.           COMMITMENTS AND CONTINGENCIES

Environmental Liabilities - 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, storm water 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.

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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 material 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 months ended March 31, 2012 or 2011.

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, with a compliance date 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 2012, The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law.  The new law increased the maximum penalties for violating federal pipeline safety regulations and directs the DOT and Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us.  These issues include but are not limited to:

·   an evaluation of whether hazardous natural gas liquid and natural gas pipeline integrity-management requirements should be expanded beyond current high-consequence areas;

·   a review of all natural gas and hazardous natural gas liquid gathering pipeline exemptions;

·   a verification of records for pipelines in class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and

·   a requirement to test pipelines previously untested in high-consequence areas operating above 30 percent yield strength.

The potential capital and operating expenditures related to this legislation, the associated regulations or other new pipeline safety regulations are unknown.

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, many remain outstanding, including critical definitions.  In December 2011, the CFTC issued an order that further defers the effective date of the provisions of the Dodd-Frank Act that require a rulemaking, such as definitions of certain terms, until the earlier of the effective date of the final rule defining the reference terms or July 16, 2012.  Until the remaining final regulations are established, we are unable to ascertain how we may be affected by them.  Based on our assessment of the regulations issued to date and those proposed, 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 capital requirements and costs of hedging may increase as a result of the legislation.  We also may incur additional costs associated with our compliance with the new regulations and anticipated additional record keeping, reporting and disclosure obligations; however, we do not believe the costs will be material.  These requirements could affect adversely market liquidity and pricing of derivative contracts making it more difficult to execute our risk-management strategies in the future.  Also, the anticipated increased costs of compliance by dealers and counterparties likely will be passed on to customers, which could decrease the benefits of hedging to us and could reduce our profitability and liquidity.

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

N.           SEGMENTS

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

·   our ONEOK Partners segment reflects the consolidated operations of ONEOK Partners.  We own a 43.4-percent ownership interest and control ONEOK Partners through our ownership of its general partner interest.  ONEOK Partners gathers, processes, treats, transports, stores and sells natural gas and gathers, treats, fractionates, stores, distributes and markets NGLs.  We and ONEOK Partners maintain significant financial and corporate governance separations.  We seek to receive increasing cash distributions as a result of our investment in ONEOK Partners, and our investment decisions are made based on the anticipated returns from ONEOK Partners in total, not specific to any of its businesses individually;

·   our Natural Gas Distribution segment is comprised of our regulated public utilities that deliver natural gas to residential, commercial and industrial customers, and transport natural gas; and

·   our Energy Services segment markets natural gas to wholesale customers. 

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 L.  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 months ended March 31, 2012 and 2011, we had no single external customer from which we received 10 percent or more 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 March 31, 2012	ONEOK Partners (a)		Natural Gas Distribution		Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	2,518,383	$	516,923	$	378,698		$	596		$	3,414,600
Intersegment revenues		75,705		841		82,110			(158,656	)		-
Total revenues	$	2,594,088	$	517,764	$	460,808		$	(158,060	)	$	3,414,600
Net margin	$	421,090	$	237,348	$	(15,446	)	$	595		$	643,587
Operating costs		115,870		104,986		4,839			(1,637	)		224,058
Depreciation and amortization		49,256		33,520		129			504			83,409
Goodwill impairment		-		-		10,255			-			10,255
Gain on sale of assets		57		-		-			-			57
Operating income	$	256,021	$	98,842	$	(30,669	)	$	1,728		$	325,922
Equity earnings from investments	$	34,620	$	-	$	-		$	-		$	34,620
Investments in unconsolidated    affiliates	$	1,219,635	$	-	$	-		$	-		$	1,219,635
Total assets	$	9,807,189	$	3,175,009	$	401,218		$	868,660		$	14,252,076
Noncontrolling interests in    consolidated subsidiaries	$	4,988	$	-	$	-		$	2,118,315		$	2,123,303
Capital expenditures	$	280,793	$	58,448	$	-		$	9,196		$	348,437
(a) - Our ONEOK Partners segment has regulated and nonregulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $171.2 million, net margin of $122.9 million and operating income of $64.6 million.

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Three Months Ended March 31, 2011	ONEOK Partners (a)			Natural Gas Distribution		Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	2,402,817		$	679,407	$	677,800	$	576		$	3,760,600
Intersegment revenues		96,793			4,775		213,939		(315,507	)		-
Total revenues	$	2,499,610		$	684,182	$	891,739	$	(314,931	)	$	3,760,600
Net margin	$	329,554		$	243,734	$	55,949	$	640		$	629,877
Operating costs		108,743			104,697		8,004		237			221,681
Depreciation and amortization		42,730			35,947		149		531			79,357
Loss on sale of assets		(510	)		-		-		-			(510	)
Operating income	$	177,571		$	103,090	$	47,796	$	(128	)	$	328,329
Equity earnings from investments	$	32,092		$	-	$	-	$	-		$	32,092
Investments in unconsolidated   affiliates	$	1,186,588		$	-	$	-	$	-		$	1,186,588
Total assets	$	8,482,304		$	3,171,977	$	498,450	$	886,865		$	13,039,596
Noncontrolling interests in   consolidated subsidiaries	$	5,128		$	-	$	-	$	1,452,805		$	1,457,933
Capital expenditures	$	144,826		$	47,150	$	-	$	2,703		$	194,679
(a) - Our ONEOK Partners segment has regulated and nonregulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $155.5 million, net margin of $115.9 million and operating income of $59.6 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 months ended March 31, 2012, are not necessarily indicative of the results that may be expected for a 12-month period.

RECENT DEVELOPMENTS

Growth Projects - Oil and gas producers continue to drill aggressively in crude oil and NGL-rich areas, and related development activities continue to progress in many regions of ONEOK Partners’ operations.  Increasing crude oil, 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, ONEOK Partners is investing approximately $4.7 billion to $5.6 billion in capital projects to meet the needs of oil and natural gas producers in the Bakken Shale, the Cana-Woodford Shale, the Granite Wash and Mississippian Lime areas, and to provide additional NGL infrastructure in the Rocky Mountain, Mid-Continent and Gulf Coast regions that will enhance its ability to distribute NGL products to meet the increasing petrochemical industry and NGL export demand.  The execution of these capital investments aligns with ONEOK Partners’ focus to grow fee-based earnings.  ONEOK Partners expects supply commitments from producers and natural gas processors associated with its growth projects will provide incremental and long-term fee-based 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 $0.61 per share ($2.44 per share on an annualized basis) in April 2012 for the first quarter of 2012.  A cash distribution from ONEOK Partners of $0.635 per unit ($2.54 per unit on an annualized basis) was declared in April 2012 for the first quarter of 2012, an increase of approximately 2.5 cents from the previous quarter.  The quarterly dividend and distribution payments will be made May 15, 2012, to shareholders and unitholders of record at the close of business on April 30, 2012.

Debt Issuance and Maturities - In January 2012, we completed an underwritten public offering of $700 million, 4.25-percent senior notes due 2022.  The net proceeds from the offering of approximately $694.3 million, after deducting underwriting discounts and offering expenses, were used to repay amounts outstanding under our $1.2 billion commercial paper program and for general corporate purposes.

ONEOK Partners Equity Issuance - In March 2012, ONEOK Partners completed an underwritten public offering of 8,000,000 common units at a public offering price of $59.27 per common unit, generating net proceeds of approximately $460 million.  ONEOK Partners also sold 8,000,000 common units to us in a private placement, generating net proceeds of approximately $460 million.  In conjunction with the issuances, we contributed $19.1 million in order to maintain our 2-percent general partner interest in ONEOK Partners.  ONEOK Partners used the net proceeds from the offering to repay approximately $295 million under its $1.2 billion commercial paper program, to repay at maturity its $350 million, 5.9-percent senior notes in April 2012 and for other general partnership purposes, including capital expenditures.  As a result of these transactions, our aggregate ownership interest in ONEOK Partners increased to 43.4 percent from 42.8 percent.

Stock Split - On February 15, 2012, our Board of Directors authorized a two-for-one split of our common stock, subject to shareholder approval of a proposal to increase the number of authorized shares of our common stock to 600 million from 300 million.  The proposal will be voted on at our 2012 annual meeting of shareholders on May 23, 2012.

Retail Marketing Sale - On February 1, 2012, we sold ONEOK Energy Marketing Company, our retail natural gas marketing business, to Constellation Energy Group, Inc for $22.5 million plus working capital.  We received net proceeds of approximately $32.0 million and recognized an after-tax gain on the sale of approximately $13.3 million.  The proceeds from the sale were used to reduce short-term borrowings.  The financial information of ONEOK Energy Marketing Company is reflected as discontinued operations in this Quarterly Report.  All prior periods presented have been recast to reflect the discontinued operations.

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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					Variances
	March 31,					2012 vs. 2011
Financial Results	2012		2011			Increase (Decrease)
	(Millions of dollars)
Revenues	$	3,414.6	$	3,760.6		$	(346.0	)	(9	%)
Cost of sales and fuel		2,771.0		3,130.7			(359.7	)	(11	%)
Net margin		643.6		629.9			13.7		2	%
Operating costs		224.1		221.7			2.4		1	%
Depreciation and amortization		83.4		79.4			4.0		5	%
Goodwill impairment		10.3		-			10.3		100	%
Gain (loss) on sale of assets		0.1		(0.5	)		0.6			*
Operating income	$	325.9	$	328.3		$	(2.4	)	(1	%)
Net income	$	233.5	$	199.3		$	34.2		17	%
Net income attributable to    noncontrolling interests	$	110.6	$	69.2		$	41.4		60	%
Net income attributable to ONEOK	$	122.9	$	130.1		$	(7.2	)	(6	%)
Capital expenditures	$	348.4	$	194.7		$	153.7		79	%
* Percentage change is greater than 100 percent.

Operating income decreased 1 percent for the three months ended March 31, 2012, compared with the same period last year, reflecting higher results from our ONEOK Partners segment, offset by significantly lower results from our Energy Services segment and slightly lower results from our Natural Gas Distribution segment.  Our ONEOK Partners segment’s operating income increased due primarily to higher NGL sales volumes from our completed capital projects and more favorable NGL price differentials, offset partially by lower natural gas and NGL product prices in its natural gas gathering and processing and natural gas liquids businesses and lower realized prices on retained fuel positions in its natural gas pipelines business.

Our Natural Gas Distribution segment’s operating income decreased 4 percent for the three months ended March 31, 2012, compared with the same period last year, due primarily to higher depreciation costs from new capital investments, which include its investment in automated meter reading, and reduced transportation margins due to warmer weather, offset partially by new rates in Texas.

Our Energy Services segment’s operating income decreased significantly for the three months ended March 31, 2012, compared with the same period last year, due primarily to lower storage and marketing margins, net of hedging activities, and goodwill impairment.

Net income attributable to noncontrolling interests for the three months ended March 31, 2012 and 2011, reflects primarily the portion of ONEOK Partners that we do not own and the increase reflects higher earnings in our ONEOK Partners segment during 2012.

Capital expenditures increased for the three months ended March 31, 2012, 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.

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

ONEOK Partners

Overview - ONEOK Partners is a diversified master limited partnership involved in the gathering, processing, storage and transportation of natural gas in the United States.  In addition, ONEOK Partners owns one of the nation’s premier natural gas liquids systems, connecting NGL supply in the Mid-Continent and Rocky Mountain regions with key market centers.

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We own approximately 92.8 million common and Class B limited partner units, and the entire 2-percent general partner interest, which, together, represent a 43.4-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 L of the Notes to Consolidated Financial Statements in this Quarterly Report for discussion of our incentive distribution rights.

We and ONEOK Partners maintain significant financial and corporate governance separations.  We seek to receive increasing cash distributions as a result of our investment in ONEOK Partners, and our investment decisions are made based on the anticipated returns from ONEOK Partners in total, not specific to any of ONEOK Partners’ businesses individually.  To aid in understanding the important business and financial characteristics of our ONEOK Partners segment, the following describes its business with reference to its underlying activities.

Natural gas gathering and processing business - ONEOK Partners’ natural gas gathering and processing business provides nondiscretionary services to producers that include gathering and processing of natural gas produced from crude oil and natural gas wells.  ONEOK Partners gathers and processes natural gas in the Mid-Continent region, which includes the NGL-rich Cana-Woodford Shale and Granite Wash formations; the Mississippian Lime formation of Oklahoma and Kansas; and the Hugoton and Central Kansas Uplift Basins of Kansas.  It also gathers and/or processes natural gas in two producing basins in the Rocky Mountain region:  the Williston Basin, which spans portions of Montana and North Dakota and includes the oil-producing, NGL-rich Bakken Shale and Three Forks formations; and the Powder River Basin of Wyoming.  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 pipeline business owns and operates regulated natural gas transmission pipelines, natural gas storage facilities and natural gas gathering systems for unprocessed natural gas.  ONEOK Partners also provides interstate 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 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 - Bakken Crude Express Pipeline - In April 2012, ONEOK Partners announced plans to invest $1.5 billion to $1.8 billion to build a 1,300-mile crude-oil pipeline, the Bakken Crude Express Pipeline, with the capacity to transport 200 MBbl/d.  The Bakken Crude Express Pipeline will transport light-sweet crude oil primarily from the Bakken Shale and Three Forks in the Williston Basin in North Dakota to the Cushing, Oklahoma, market hub.

ONEOK Partners is the largest independent gatherer and processor of natural gas in the Williston Basin and currently is constructing a natural gas liquids pipeline to provide needed transportation capacity for the growing NGL production in the area.  The development of the Bakken Crude Express Pipeline is a natural extension to the suite of midstream services we currently provide to producers in the Williston Basin and is expected to generate additional fee-based earnings.  Additional crude-oil infrastructure is needed due to the continued crude-oil production growth that is expected to saturate the area’s current truck and railcar transportation capacity.  ONEOK Partners’ proposed pipeline will provide producers with efficient and reliable transportation capacity directly to one of the largest market-hubs in the U.S. and will enable them to maintain the quality of the light-sweet crude oil during transportation.

Based on supply commitments received prior to construction, the capacity of this pipeline can be increased.  The proposed pipeline route is expected to parallel more than 80 percent of the partnership’s existing and planned natural gas liquids pipelines.  Supply commitments for the proposed pipeline are in various stages of negotiation with many of the same producers and natural gas processors that ONEOK Partners serves currently.  Following receipt of all necessary permits and

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compliance with customary regulatory requirements, construction is expected to begin in late 2013 or early 2014 and be completed by early 2015.

Natural gas gathering and processing projects - ONEOK Partners’ natural gas gathering and processing business is investing approximately $1.4 billion to $1.6 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 projects in this basin include three 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, Stateline I and Stateline II plants.  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 was placed in service in December 2011, and related infrastructure projects are expected to cost approximately $360 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.

ONEOK Partners also announced in April 2012 plans to invest $140 million to $160 million to construct a 270-mile natural gas gathering system and related infrastructure in Divide County, North Dakota.  The new system will gather and deliver natural gas from producers in the Bakken Shale in the Williston Basin to ONEOK Partners’ Stateline II natural gas processing facility in western Williams County, North Dakota.  ONEOK Partners has secured long-term supply commitments from producers structured with percent-of-proceeds and fee-based components.  This infrastructure is expected to be completed in the second half of 2013.

Horizontal wells drilled in the Williston Basin are justified primarily by crude-oil economics.  In addition, ONEOK Partners expects its commodity price exposure to increase particularly to NGLs and natural gas, as equity volumes increase under its POP contracts with its customers in the Williston Basin.

Canadian Valley Plant and related projects - In April 2012, ONEOK Partners announced plans to invest approximately $340 million to $360 million to construct a new 200 MMcf/d natural gas processing facility and related infrastructure in the Cana-Woodford Shale in Canadian County, Oklahoma, and in close proximity to its existing natural gas and natural gas liquids pipelines.  The additional natural gas processing infrastructure is necessary to accommodate increased production of NGL-rich natural gas in the Cana-Woodford Shale where ONEOK Partners has substantial acreage dedications from active producers.  The new Canadian Valley plant will cost approximately $190 million, excluding AFUDC, and is expected to be in service in the first quarter 2014.  The related additional infrastructure will cost approximately $160 million, excluding AFUDC, and is expected to increase ONEOK Partners’ capacity to gather and process natural gas to approximately 390 MMcf/d in the Cana-Woodford Shale.

In both the Williston Basin and Cana-Woodford Shale project areas, nearly all of the new gas production is from horizontally drilled and completed wells.  These wells tend to produce at higher initial volumes; however, they generally have higher initial decline rates than conventional vertical wells, but the declines flatten out. These wells are expected to have long-lasting reserves.  ONEOK Partners expects the routine growth capital needed to connect to new wells and expand its infrastructure to be higher compared with its previous experience.

Natural gas liquids projects - The growth strategy in ONEOK Partners’ natural gas liquids business is focused around the oil and NGL-rich natural gas drilling activity in shale and other resource plays from the Rocky Mountain region through the Mid-Continent region down into Texas.  Increasing crude oil, 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.  Expansion of the petrochemical industry in the United States is expected to increases ethane demand significantly over the next five years, and international demand for propane is expected to impact the NGL market in the future.  ONEOK Partners’ natural gas liquids business is investing approximately $1.8 billion to $2.2 billion on NGL-related projects through 2014.  This investment will accommodate the transportation and fractionation of growing NGL supplies from the shale and other resource plays across ONEOK Partners’ asset base and alleviate infrastructure constraints between the Mid-Continent and Texas Gulf Coast regions that will enhance ONEOK Partners’ ability to distribute NGL products to meet the increasing petrochemical industry and NGL export demand in the Gulf Coast.  Over time, these growing fee-based volumes will fill a portion of the capacity to capture the price differentials between the two market centers.  In addition, we believe the price differentials between the Mid-Continent and Gulf Coast market centers will narrow over the long-term as new fractionators and pipelines, including ONEOK Partners’ MB-2 fractionator and Sterling III pipeline, begin to alleviate constraints affecting NGL prices and the location price differential between the two market centers.

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Sterling III Pipeline - 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 75 percent 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 in 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 is constructing a 75-MBbl/d fractionator, MB-2, near its storage facility in Mont Belvieu, Texas.  The Texas Commission on Environmental Quality (TCEQ) approved the permit application to build this fractionator.  Construction began in June 2011 and is expected to be completed in mid-2013.  The cost of the new 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 all 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 NGL Pipeline and related projects - ONEOK Partners plans to build a 525- to 615-mile natural gas liquids pipeline, the Bakken NGL Pipeline, to transport unfractionated NGLs from the Williston Basin to the Overland Pass Pipeline.  The Bakken NGL Pipeline initially will 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 NGL 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 NGL Pipeline and other supply sources under development in the Rocky Mountain region 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’ 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 NGL Pipeline, ONEOK Partners is investing $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 fourth quarter of 2012.

Cana-Woodford Shale and Granite Wash projects - ONEOK Partners has constructed approximately 230 miles of natural gas liquids pipelines that have expanded its existing Mid-Continent natural gas liquids gathering system in the Cana-Woodford Shale and Granite Wash areas.  These pipelines have expanded ONEOK Partners’ capacity 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.  The pipelines are connected to three new third-party natural gas processing facilities and to three existing third-party natural gas processing facilities that have been expanded.  Additionally, ONEOK Partners has installed additional pump stations on the Arbuckle Pipeline to increase its capacity to 240 MBbl/d.  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 were placed in service in April 2012 and cost approximately $210 million to $230 million, excluding AFUDC.

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Sterling I Pipeline Expansion - In 2011, ONEOK Partners installed seven additional pump stations at a cost of approximately $30 million, excluding AFUDC, along its existing Sterling I natural gas liquids distribution pipeline, increasing its capacity by 15 MBbl/d, which is 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.

For a discussion of ONEOK Partners’ capital expenditure financing, see “Capital Expenditures” in “Liquidity and Capital Resources” on page 50.

Selected Financial Results and Operating Information - The following table sets forth certain selected financial results for our ONEOK Partners segment for the periods indicated:

	Three Months Ended					Variances
	March 31,					2012 vs. 2011
Financial Results	2012		2011			Increase (Decrease)
	(Millions of dollars)
Revenues	$	2,594.1	$	2,499.6		$	94.5	4	%
Cost of sales and fuel		2,173.0		2,170.1			2.9	0	%
Net margin		421.1		329.5			91.6	28	%
Operating costs		115.9		108.7			7.2	7	%
Depreciation and amortization		49.3		42.7			6.6	15	%
Gain (loss) on sale of assets		0.1		(0.5	)		0.6		*
Operating income	$	256.0	$	177.6		$	78.4	44	%
Capital expenditures	$	280.8	$	144.8		$	136.0	94	%
* Percentage change is greater than 100 percent.

Revenues increased for the three months ended March 31, 2012, compared with the same period last year, due to higher natural gas and NGL sales volumes from our completed capital projects and more favorable NGL price differentials, offset partially by lower natural gas and NGL prices.

Net margin increased for the three months ended March 31, 2012, compared with the same period last year, due primarily to the following:

·   an increase of $60.1 million in optimization margins in ONEOK Partners’ natural gas liquids business due primarily to favorable NGL price differentials and additional fractionation and transportation capacity available for optimization activities made available by our 60 MBbl/d fractionation-services agreement with Targa Resources Partners that began in the second quarter 2011 and completed expansions of the Arbuckle and Sterling I pipelines that enable the transportation of NGLs between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers;

·   an increase of $26.5 million due to higher natural gas volumes gathered, processed and commodities sold from our new Garden Creek plant and increased drilling activity in the Williston Basin and western Oklahoma in ONEOK Partners’ natural gas gathering and processing business;

·   an increase of $18.0 million from higher NGL volumes gathered and fractionated in Texas and the Mid-Continent and Rocky Mountain regions, 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; and

·   an increase of $6.3 million due to the impact of operational measurement gains of approximately $0.7 million in the first quarter of 2012 compared with a loss of approximately $5.6 million in the same period last year in ONEOK Partners’ natural gas liquids business; offset partially by

·   a decrease of $5.3 million due to increased third-party processing costs in the Williston Basin in ONEOK Partners’ natural gas gathering and processing business;

·   a decrease of $5.2 million due to lower natural gas and NGL product prices, particularly ethane and propane, offset partially by higher condensate prices in ONEOK Partners’ natural gas gathering and processing business;

·   a decrease of $3.5 million related to lower isomerization margins resulting from lower price differentials between normal butane and iso-butane, and lower isomerization volumes in ONEOK Partners’ natural gas liquids business; and

·   a decrease of $3.0 million due to lower realized natural gas prices on our retained fuel position.

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Beginning on February 28, 2012, ONEOK Partners experienced an unexpected release of brine and propane from a storage well at its fractionation facility in Medford, Oklahoma, which caused a 10-day disruption in its operations.  Without this disruption, ONEOK Partners estimates net margin would have been approximately $10 million higher.  The well was capped successfully and will be taken out of service permanently.  The costs associated with this incident are not expected to be material.

Operating costs increased for the months ended March 31, 2012, compared with the same period last year, due primarily to the following:

·   an increase of $4.9 million from higher materials, utilities and outside services expenses associated primarily with scheduled maintenance and completed capital projects in ONEOK Partners’ natural gas liquids business; and

·   an increase of $3.2 million in higher employee-related costs associated with growth of ONEOK Partners’ operations and completed capital projects.

Depreciation and amortization expense increased for the three months ended March 31, 2012, compared with the same period last year, due primarily to the depreciation associated with ONEOK Partners’ completed capital projects, which includes the completion of its Garden Creek plant, well connections and infrastructure projects supporting the volume growth in the Williston Basin.

Capital expenditures increased for the three months ended March 31, 2012, 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.

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

	Three Months Ended
	March 31,
Operating Information	2012			2011
Natural gas gathering and processing business (a)
Natural gas gathered (BBtu/d)		1,045			992
Natural gas processed (BBtu/d) (b)		769			641
NGL sales (MBbl/d)		53			44
Residue gas sales (BBtu/d)		357			274
Realized composite NGL net sales price ($/gallon) (c)	$	1.09		$	1.09
Realized condensate net sales price ($/Bbl) (c)	$	89.89		$	76.25
Realized residue gas net sales price ($/MMBtu) (c)	$	3.71		$	6.06
Realized gross processing spread ($/MMBtu) (c)	$	8.59		$	8.33
Natural gas pipelines business (a)
Natural gas transportation capacity contracted (MDth/d)		5,552			5,608
Transportation capacity subscribed		86	%		87	%
Average natural gas price
Mid-Continent region ($/MMBtu)	$	2.37		$	4.10
Natural gas liquids business
NGL sales (MBbl/d)		511			478
NGLs fractionated (MBbl/d) (d)		585			495
NGLs transported-gathering lines (MBbl/d) (a)		498			397
NGLs transported-distribution lines (MBbl/d) (a)		485			461
Conway-to-Mont Belvieu OPIS average price differential
Ethane ($/gallon)	$	0.24		$	0.15
(a) - For consolidated entities only.
(b) - Includes volumes processed at company-owned and third-party facilities.
(c) - Presented net of the impact of hedging activities and includes equity volumes only.
(d) - Includes volumes fractionated from company-owned and third-party facilities.

Natural gas gathered increased for the three months ended March 31, 2012, compared with the same period last year, due to increased drilling activity in the Williston Basin and western Oklahoma, completion of additional gathering lines and compression to support ONEOK Partners’ new Garden Creek plant that was placed in service in December 2011 and the impact of weather-related outages in the first quarter 2011, offset partially by declining production and reduced drilling activity in the Powder River Basin in Wyoming.

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Natural gas processed, NGL sales and residue gas sales increased for the three months ended March 31, 2012, compared with the same period last year, due to an increase in drilling activity in the Williston Basin and western Oklahoma, placing the new Garden Creek plant into service in December 2011 and the impact of weather-related outages in the first quarter of 2011.

NGLs gathered and fractionated increased for the three months ended March 31, 2012, compared with the same period last year, due primarily to increased throughput 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.  In second quarter 2011, additional Gulf Coast fractionation capacity became available through a 60 MBbl/d fractionation-services agreement with Targa Resources Partners.

NGLs transported on distribution lines increased for the three months ended March 31, 2012, compared with the same period last year, due primarily to the completion of our Sterling I pipeline expansion.

Commodity Price Risk - The following tables set forth ONEOK Partners’ natural gas gathering processing business’ hedging information for the periods indicated, as of March 31, 2012.

	Nine Months Ending
	December 31, 2012
	Volumes Hedged		(a)	Average Price			Percentage Hedged
NGLs (Bbl/d)		9,094		$	1.24	/ gallon	71%
Condensate (Bbl/d)		1,753		$	2.43	/ gallon	73%
Total (Bbl/d)		10,847		$	1.43	/ gallon	72%
Natural gas (MMBtu/d)		48,145		$	4.12	/ MMBtu	78%
(a) - Hedged with fixed-price swaps.

	Year Ending
	December 31, 2013
	Volumes Hedged		(a)	Average Price			Percentage Hedged
NGLs (Bbl/d)		367		$	2.55	/ gallon	2%
Condensate (Bbl/d)		1,275		$	2.53	/ gallon	47%
Total (Bbl/d)		1,642		$	2.54	/ gallon	7%
Natural gas (MMBtu/d)		50,137		$	3.85	/ MMBtu	80%
(a) - Hedged with fixed-price swaps.

ONEOK Partners expects its commodity price sensitivity in its gathering and processing business to increase in the future as volumes increase under POP contracts with our customers.  ONEOK Partners’ commodity price sensitivity is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas, excluding the effects of hedging, and assuming normal operating conditions.  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 $2.1 million;

·   a $1.00 per barrel change in the price of crude oil would change annual net margin by approximately $1.2 million; and

·   a $0.10 per MMBtu change in the price of natural gas would change annual net margin by approximately $2.2 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 D of the Notes to Consolidated Financial Statements in this Quarterly Report for more information on ONEOK Partners’ hedging activities.

Natural Gas Distribution

Overview - Our Natural Gas Distribution segment provides natural gas distribution services to more than 2 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 LDCs serve wholesale and

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public authority customers.  We operate subject to regulations and oversight of the state regulatory agencies.  Our regulatory strategy incorporates features that are designed to reduce earnings lag, protect margin and mitigate risks.

Retail Marketing Sale - On February 1, 2012, we sold ONEOK Energy Marketing Company, our retail natural gas marketing business, to Constellation Energy Group, Inc. for $22.5 million plus working capital.  We received net proceeds of approximately $32.0 million and recognized an after-tax gain on the sale of approximately $13.3 million.  The proceeds from the sale were used to reduce short-term borrowings.  The financial information of ONEOK Energy Marketing Company is reflected as discontinued operations in this Quarterly Report.  All prior periods presented have been recast to reflect the discontinued operations.

Selected Financial Results - The following table sets forth certain selected financial results for the continuing operations of our Distribution segment for the periods indicated:

	Three Months Ended				Variances
	March 31,				2012 vs. 2011
Financial Results	2012		2011		Increase (Decrease)
	(Millions of dollars)
Gas sales	$	481.5	$	644.6	$	(163.1	)	(25	%)
Transportation revenues		27.0		29.0		(2.0	)	(7	%)
Cost of gas		280.5		440.5		(160.0	)	(36	%)
Net margin, excluding other revenues		228.0		233.1		(5.1	)	(2	%)
Other revenues		9.3		10.6		(1.3	)	(12	%)
Net margin		237.3		243.7		(6.4	)	(3	%)
Operating costs		105.0		104.7		0.3		0	%
Depreciation and amortization		33.5		35.9		(2.4	)	(7	%)
Operating income	$	98.8	$	103.1	$	(4.3	)	(4	%)
Capital expenditures	$	58.4	$	47.2	$	11.2		24	%

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

	Three Months Ended				Variances
	March 31,				2012 vs. 2011
Net Margin, Excluding Other Revenues	2012		2011		Increase (Decrease)
Gas sales	(Millions of dollars)
Regulated
Residential	$	165.1	$	165.2	$	(0.1	)	(0	%)
Commercial		33.6		36.6		(3.0	)	(8	%)
Industrial		0.6		0.8		(0.2	)	(25	%)
Wholesale/public authority		1.7		1.5		0.2		13	%
Net margin on gas sales		201.0		204.1		(3.1	)	(2	%)
Transportation margin		27.0		29.0		(2.0	)	(7	%)
Net margin, excluding other revenues	$	228.0	$	233.1	$	(5.1	)	(2	%)

Natural gas prices decreased during the three months ended March 31, 2012, compared with the same period last year.  The decrease in natural gas prices had a direct impact on our revenues and cost of sales.

Net margin decreased for the three months ended March 31, 2012, compared with the same period last year, due primarily to the following:

·   a decrease of $4.3 million due to expiration of the Integrity Management Program (IMP) rider, which allowed us to recover certain deferred pipeline-integrity costs in Oklahoma.  This decrease is offset by lower regulatory amortization in depreciation and amortization expense; and

·   a decrease of $1.7 million from lower transportation volumes due to weather-sensitive customers in Kansas and Oklahoma; offset partially by

·   an increase of $1.8 million from new rates and rider recoveries in Texas.

Operating costs remained relatively unchanged for the three months ended March 31, 2012, compared with the same period last year, due primarily to the following:

·   a decrease of $7.0 million in share-based compensation costs from common stock awarded in the prior year to employees as part of ONEOK’s stock award program and the appreciation in ONEOK’s share price; offset partially by

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·   an increase of $2.4 million from higher outside service costs due primarily to expenses associated with IMP activities in Oklahoma; and

·   an increase of $1.5 million from legal costs in Texas.

Depreciation and amortization expense decreased for the three months ended March 31, 2012, due primarily to a decrease of $4.3 million in regulatory amortization associated with the expiration of the IMP rider, which allowed us to defer recognition of certain pipeline-integrity costs in Oklahoma; offset partially by an increase of $1.8 million associated with additional capital expenditures, primarily investments in Oklahoma, including automated meter reading devices.

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, relocating facilities to accommodate government construction and replacements.  It is our practice to maintain and upgrade facilities to ensure safe, reliable and efficient operations.

Capital expenditures increased for the three months ended March 31, 2012, compared with the same period last year, primarily as a result of increased spending on pipeline replacements in Kansas and Texas.

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

	Three Months Ended
	March 31,
Number of Customers	2012	2011
Residential	1,944,754	1,938,529
Commercial	155,894	156,440
Industrial	1,250	1,247
Wholesale/Public Authority	2,703	2,784
Transportation	11,878	11,607
Total customers	2,116,479	2,110,607

	Three Months Ended
	March 31,
Volumes (MMcf)	2012	2011
Gas sales
Residential	49,697	58,465
Commercial	13,097	15,555
Industrial	342	423
Wholesale/Public Authority	2,508	1,169
Total volumes sold	65,644	75,612
Transportation	57,532	62,449
Total volumes delivered	123,176	138,061

Residential and commercial volumes decreased for the three months ended March 31, 2012, compared with the same period last year, due primarily to warmer temperatures in the first quarter of 2012; however, the impact on margins was mitigated largely by weather normalization mechanisms.  Wholesale sales represent contracted gas volumes that exceed the needs of our residential, commercial and industrial customer base and are available for sale to other parties.

Regulatory Initiatives - Oklahoma - In March 2012, Oklahoma Natural Gas filed aPerformance Based Rate Change (PBRC) filing seeking to increase base rates by $16.2 million.  The proposed increase to rates reflects the guidelines set forth in the PBRC Tariff to restore the Oklahoma Natural Gas regulated return on equity (ROE) to 10.25 percent, which is 25 basis points below the current Commission-approved ROE of 10.5 percent.  The hearing on this matter is set for June 28, 2012.

In May 2011, the OCC approved a portfolio of conservation and energy-efficiency programs and authorized recovery of costs and performance incentives.  The agreement allows Oklahoma Natural Gas to pursue key energy-efficiency programs and allows the company to earn up to $1.5 million annually beginning mid-2012, if program objectives are achieved.

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Kansas - The KCC approved the application from Kansas Gas Service to increase the Gas System Reliability Surcharge by an additional $2.9 million effective January 2012.  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.  We also expect to file a general rate proceeding with the KCC in mid-2012.

In March 2012, Kansas Gas Service submitted an application with the KCC to approve the implementation of a cast-iron pipeline-replacement program that would accelerate the rate at which we are replacing cast-iron pipe.  Pursuant to the request, Kansas Gas Service would replace all of the cast-iron pipeline mains on its system over an eight-year period.  Kansas Gas Service also requested approval of a surcharge that would recover the carrying charges and depreciation expense associated with the investment as the costs were incurred.  The total cost estimate of the replacement program is $8.75 million annually over the eight-year period.

Texas - Texas Gas Service has 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 2012 and El Paso, Texas, in April 2012 for approximately $3.8 million and $2.1 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 January 2012, the Texas Railroad Commission approved the settlement between Texas Gas Service and the City of El Paso that allows for recovery of 2010-2013 pipeline-integrity expenditures and partial recovery of rate-case expenses.  The settlement did not have a material impact on our results of operations.

In the normal course of business, we have filed rate cases and 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 is a provider of natural gas supply and risk-management services for natural gas and electric utilities and commercial and industrial customers.  We use a network of leased storage and transportation capacity to supply natural gas to our customers.  This network connects the major supply and demand centers throughout the United States and into Canada and, coupled with our industry knowledge and market intelligence, allows us to provide our customers with customized services in a more efficient and reliable manner than they can achieve independently.

We follow a strategy of optimizing our storage and cross-regional transportation capacity through the application of market knowledge and effective risk management.  We seek to maximize value by actively hedging the risks associated with seasonal and location price differentials that are inherent to storage and transportation contracts.  At the same time, we attempt to capitalize on opportunities created by market volatility, weather-related events, supply-demand imbalances and market inefficiencies, which allow us to capture additional margin.  Using market information, we manage these asset-based positions and seek to provide incremental margin in our trading portfolio.

To ensure natural gas is available when our customers need it, we offer premium services and products that satisfy our customers’ nonuniform supply needs such as swing and peaking natural gas load requirements on a year-round basis.  Types of premium services include next-day and no-notice services.  Next-day services allow our customers to call on additional gas supply, up to an amount agreed upon in a service contract, and expect delivery the following day.  No-notice services allow customers to call on additional natural gas supply and expect immediate delivery.  We also provide 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 capture daily, monthly and seasonal value due to market inefficiencies.

As a result of significant increases in the supply of natural gas, primarily from shale production across North America, location and seasonal price differentials have narrowed significantly, resulting in reduced opportunities to capture margins with our firm transportation and storage capacity.  Additionally, price volatility in the natural gas markets remains relatively low as compared with volatility in the past, which, coupled with a fairly flat forward price curve, reduces the value of the demand fee we receive for premium services and further limits opportunities to optimize our assets.  We have undertaken several steps to better align fixed costs with the current business environment, including attempts to renegotiate various natural gas storage and transportation contracts.  Contract renegotiation activities that we have taken or expect to take include renewing contracts at current market prices at contract expiration, extending contracts in order to negotiate a more favorable rate or paying to terminate contracts in areas that are no longer strategic to our business.  For the three months ended March 31, 2012, we recognized charges to our earnings as a result of certain of these actions.  As we continue our contract renegotiation activities, it is possible we may recognize additional charges to our earnings in the future.  We expect these contractual changes to result in less storage and transportation capacity under lease and a better alignment of our contracted natural gas transportation and storage capacity with the needs of our premium-services customers.  We also expect the reduction in our contracted natural gas transportation and storage capacity would reduce our operating costs and working-capital requirements.

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Selected Financial Results - The following table sets forth certain selected financial results for our Energy Services segment for the periods indicated:

	Three Months Ended					Variances
	March 31,					2012 vs. 2011
Financial Results	2012			2011		Increase (Decrease)
	(Millions of dollars)
Revenues	$	460.8		$	891.7	$	(430.9	)	(48	%)
Cost of sales and fuel		476.2			835.8		(359.6	)	(43	%)
Net margin		(15.4	)		55.9		(71.3	)		*
Operating costs		4.8			8.0		(3.2	)	(40	%)
Depreciation and amortization		0.2			0.1		0.1		100	%
Goodwill impairment		10.3			-		10.3			*
Operating income (loss)	$	(30.7	)	$	47.8	$	(78.5	)		*
* Percentage change is greater than 100 percent.

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

	Three Months Ended					Variances
	March 31,					2012 vs. 2011
	2012			2011		Increase (Decrease)
	(Millions of dollars)
Marketing, storage and transportation revenues, gross	$	28.8		$	97.3	$	(68.5	)	(70	%)
Storage and transportation costs		44.5			41.9		2.6		6	%
Marketing, storage and transportation, net		(15.7	)		55.4		(71.1	)		*
Financial trading, net		0.3			0.5		(0.2	)	(40	%)
Net margin	$	(15.4	)	$	55.9	$	(71.3	)		*
* Percentage change is greater than 100 percent.

Our storage and transportation costs increased 6 percent for the three months ended March 31, 2012, compared with the same period last year, due primarily to an increase in storage demand fees and a loss resulting from the release to a third party of contracted transportation capacity that expires in December 2012, offset partially by reduced transportation capacity.  For additional information on transportation and storage capacity refer to “Selected Operating Information” below.

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.

Revenues and cost of sales and fuel decreased for the three months ended March 31, 2012, compared with the same period last year, due primarily to lower natural gas prices and, to a lesser extent, reduced volumes associated with our premium-services business as a result of warmer weather.  Net margin decreased for the three months ended March 31, 2012, compared with the same period last year, due primarily to the following:

·   a decrease of $65.3 million in storage and marketing margins, net of hedging activities, due primarily to the following:

-   a decrease of $29.9 million related to the reclassification of losses on certain financial contracts that were used to hedge forecasted purchases of natural gas, as a result of the continued decline in natural gas prices.  The combination of the cost basis of the forecasted inventory and the financial contracts exceed the amount expected to be recovered through sales of that inventory after considering related sales hedges, which requires reclassification of the loss from accumulated other comprehensive income (loss) to current period earnings;

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-   a decrease of $27.8 million due to lower realized seasonal storage price differentials; and

-   a decrease of $7.0 million due to unfavorable market conditions, higher demand fees on storage contracts and unrealized fair value changes on nonqualifying economic storage hedges; and

·   a decrease of $4.9 million in transportation margins, net of hedging, due primarily to the following:

-   lower hedge settlements in 2012; and

-   release of contracted transportation capacity to a third party resulting in the recognition of a loss in the first quarter of 2012, which will reduce our overall loss on the transportation contract expiring in December 2012.

Operating costs decreased due primarily to lower employee-related expenses.

We also recognized an expense of $10.3 million related to the impairment of our goodwill.  Given the continued significant decline in natural gas prices and its effect on location and seasonal price differentials, we performed an interim impairment assessment that reduced our goodwill balance to zero.

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

	Three Months Ended
	March 31,
Operating Information	2012			2011
Natural gas marketed (Bcf)		218			259
Natural gas gross margin ($/Mcf)	$	(0.07	)	$	0.22
Physically settled volumes (Bcf)		417			494

Natural gas volumes marketed and physically settled volumes decreased for the three months ended March 31, 2012, compared with the same period 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 as a result of increased supply of natural gas, primarily from shale production, and increased pipeline capacity as a result of pipeline construction.

At March 31, 2012, our natural gas transportation capacity was 1.1 Bcf/d, all of which was contracted under long-term natural gas transportation contracts, compared with 1.3 Bcf/d of total capacity and 1.1 Bcf/d of long-term capacity at March 31, 2011.  Approximately 10 percent of our transportation capacity expires by the end of 2012, and approximately an additional 66 percent expires by the end of 2015.  Approximately 35.0 MMcf/d of transportation capacity expired in the first quarter of 2012, an additional 46.2 MMcf/d expired on April 1, 2012, and 59.8 MMcf/d is expiring in the fourth quarter of 2012.  We do not expect to renew any of this transportation capacity.

Our natural gas in storage at March 31, 2012, was 41.5 Bcf, compared with 28.3 Bcf at March 31, 2011.  At March 31, 2012, our total natural gas storage capacity under lease was 75.6 Bcf, compared with 73.6 Bcf at March 31, 2011.  The increase in the capacity under lease was the result of new capacity that was contracted in prior years.  At March 31, 2012, our natural gas storage capacity under lease had a maximum withdrawal capability of 2.4 Bcf/d and maximum injection capability of 1.3 Bcf/d.  Approximately 20 percent of our storage capacity expires by the end of 2012, and approximately 68 percent expires by the end of 2015.  Approximately 15.2 Bcf of storage capacity expired on April 1, 2012, with 12.7 Bcf renewed at market rates.

Reducing storage and transportation capacity continues to be a focus as we reduce fixed costs and align our capacity with the needs of our premium-services customers.  It is possible that we may recognize charges to our earnings in the future as a result of these actions.

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 probable 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 I, Item 3, Legal Proceedings, in our Annual Report.

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LIQUIDITY AND CAPITAL RESOURCES

General - ONEOK and ONEOK Partners have relied primarily on operating cash flow, commercial paper, bank credit facilities, debt issuances and/or the issuance of equity for their liquidity and capital resource requirements.  ONEOK and ONEOK Partners fund operating expenses, debt service, dividends to shareholders and distributions to unitholders primarily with operating cash flow.  Capital expenditures are funded by short- and long-term debt, issuances of equity and operating cash flow.  We expect to continue to use these sources for our liquidity and capital resource needs.  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.  We anticipate that our cash flow generated from operations, existing capital resources, including proceeds from the issuance of our $700 million, 4.25-percent senior notes issued in January 2012 and distributions from ONEOK Partners will enable us to maintain our current and planned level of operations and fund the remainder of our three-year, $750-million stock repurchase program.  ONEOK Partners anticipates that its cash flow generated from operations, proceeds from its March 2012 equity offering, existing capital resources and ability to obtain financing will enable it to maintain its current and planned level of operations.  Additionally, ONEOK Partners expects to fund its future capital expenditures with short- and long-term debt, the issuance of equity and operating cash flows.

Capitalization Structure - The following table sets forth our consolidated capitalization structure as of the dates indicated:

	March 31,	December 31,
	2012	2011
Long-term debt	56%	56%
Total equity	44%	44%
Debt (including notes payable)	58%	60%
Total equity	42%	40%

For purposes 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:

	March 31,	December 31,
	2012	2011
Long-term debt	43%	31%
ONEOK shareholders' equity	57%	69%
Debt (including notes payable)	49%	45%
ONEOK shareholders' equity	51%	55%

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.  ONEOK Partners’ principal sources of short-term liquidity consist of cash generated from operating activities, the issuance of commercial paper and distributions received from unconsolidated affiliates.  To the extent commercial paper is unavailable, ONEOK’s and ONEOK Partners’ respective revolving credit agreements may be utilized.

ONEOK 2011 Credit Agreement -The ONEOK 2011 Credit Agreement, which is scheduled to expire in April 2016, contains certain financial, operational and legal covenants.  Among other things, these covenants include maintaining ONEOK’s stand-alone debt-to-capital ratio of no more than 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

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of the ONEOK 2011 Credit Agreement, ONEOK may request an increase in the size of the facility to an aggregate of $1.7 billion from $1.2 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.  In the event of a breach of certain covenants by ONEOK, amounts outstanding under the ONEOK 2011 Credit Agreement may become due and payable immediately.

The total amount of short-term borrowings authorized by ONEOK’s Board of Directors is $2.8 billion.  At March 31, 2012, ONEOK had $419.8 million of commercial paper outstanding, $2.0 million in letters of credit issued under the ONEOK 2011 Credit Agreement and approximately $34.5 million of cash and cash equivalents.  ONEOK had approximately $778.2 million of credit available at March 31, 2012, under the ONEOK 2011 Credit Agreement.  As of March 31, 2012, ONEOK could have issued $2.9 billion of additional short- and long-term debt under the most restrictive provisions contained in its various borrowing agreements.

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.

ONEOK Partners 2011 Credit Agreement - 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 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 quarter of the acquisition and the two following quarters.  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 from $1.2 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 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 March 31, 2012, ONEOK Partners had no commercial paper outstanding, no letters of credit issued, no borrowings outstanding under the ONEOK Partners 2011 Credit Agreement, approximately $746.7 million of cash and $1.2 billion of credit available under the ONEOK Partners 2011 Credit Agreement.  As of March 31, 2012, ONEOK Partners could have issued $4.2 billion of short- and long-term debt to meet its liquidity needs under the most restrictive provisions contained in its various borrowing agreements.

At March 31, 2012, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 2.6 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners 2011 Credit Agreement.

Long-term Financing - In addition to the principal sources of short-term liquidity discussed above, ONEOK expects to fund its longer-term cash requirements by issuing equity or long-term notes.  ONEOK Partners expects to fund its longer-term cash requirements by issuing common units or long-term notes.  Other options to obtain financing include, but are not limited to, issuance of convertible debt securities, asset securitization and the sale and leaseback of facilities.

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.

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ONEOK Debt Issuance - In January 2012, we completed an underwritten public offering of $700 million, 4.25-percent senior notes due 2022.  The net proceeds from the offering, after deducting underwriting discounts and offering expenses, of approximately $693.9 million were used to repay amounts outstanding under our commercial paper program.  We will pay interest on the senior notes due 2022 on February 1 and August 1 of each year, beginning August 1, 2012.

ONEOK Debt Covenants - The indenture governing ONEOK’s senior notes due 2022 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 the outstanding senior notes due 2022 to declare those senior notes immediately due and payable in full.

ONEOK may redeem its senior notes due 2022 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting three months before the maturity date.  Prior to this date, ONEOK may redeem the senior notes due 2022, in whole or in part, at any time for 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’s senior notes due 2022 are senior unsecured obligations, ranking equally in right of payment with all of ONEOK’s existing and future unsecured senior indebtedness.

ONEOK Partners’ Debt Maturities- ONEOK Partners repaid its $350 million, 5.9-percent senior notes upon maturity in April 2012 with a portion of the proceeds from its March 2012 equity issuance.

ONEOK Partners’ Equity Issuance - In March 2012, ONEOK Partners completed an underwritten public offering of 8,000,000 common units at a public offering price of $59.27 per common unit, generating net proceeds of approximately $460 million.  ONEOK Partners also sold 8,000,000 common units to us in a private placement, generating net proceeds of approximately $460 million.  In conjunction with the issuances, we contributed $19.1 million in order to maintain our 2-percent general partner interest in ONEOK Partners.  ONEOK Partners used the proceeds from the offerings to repay approximately $295.0 million of borrowing under its $1.2 billion commercial paper program, to repay amounts on the maturity of their $350 million, 5.9-percent senior notes due April 2012 and for other general partnership purposes, including capital expenditures.  As a result of these transactions, our aggregate ownership interest in ONEOK Partners increased to 43.4 percent from 42.8 percent.

Interest-rate Swaps - ONEOK and ONEOK Partners have each entered into forward-starting interest-rate swaps 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.  ONEOK had interest-rate swaps with a notional value of $500 million at December 31, 2011.  In January 2012, ONEOK entered into additional interest-rate swaps with a notional amount of $200 million.  Upon issuance in January 2012 of our $700 million, 4.25-percent senior notes due 2022, ONEOK settled all $700 million of its interest-rate swaps and realized a loss of $44.1 million in accumulated other comprehensive income that will be amortized to interest expense over the term of the hedged debt.  At March 31, 2012, and December 31, 2011, ONEOK Partners had forward-starting interest-rate swaps with notional amounts of $750 million.  In April 2012, ONEOK Partners entered into additional forward-starting interest-rate swaps with a notional amount of $250 million.

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 $348.4 million and $194.7 million for the three months ending March 31, 2012 and 2011, respectively, exclusive of acquisitions.  Of these amounts, ONEOK Partners’ capital expenditures were $280.8 million and $144.8 million for the three months ended March 31, 2012 and 2011, respectively, exclusive of acquisitions.  Capital expenditures for 2012 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 2012 projected capital expenditures, excluding AFUDC:

2012 Projected Capital Expenditures
	(Millions of dollars)
ONEOK Partners		$	1,969
Natural Gas Distribution			270
Other			32
Total projected capital expenditures		$	2,271

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Credit Ratings - Our credit ratings as of March 31, 2012, 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 the debt-to-capital ratio, business risk profile, pre-tax 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, which expires in August 2016.  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 March 31, 2012, ONEOK could have been required to fund approximately $6.8 million in margin requirements related to financial contracts upon such a downgrade.  A decline in ONEOK’s credit rating below investment grade also may impact significantly 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 will 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 Note D of the Notes to Consolidated Financial Statements; the discussion under ONEOK Partners’ “Commodity Price Risk” in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations; and Energy Services’ discussion 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 M of the Notes to Consolidated Financial Statements in our Annual Report.  See Note J 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, other amounts and changes in our assets and liabilities not classified as investing or financing activities.

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

	Three Months Ended							Variances
	March 31,							2012 vs. 2011
	2012			2011			Increase (Decrease)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	426.1		$	647.8			$	(221.7	)
Investing activities		(314.4	)		(189.5	)			(124.9	)
Financing activities		594.7			380.8				213.9
Change in cash and cash equivalents		706.4			839.1				(132.7	)
Change in cash and cash equivalents included in discontinued operations		8.8			7.2				1.6
Change in cash and cash equivalents from continuing operations		715.2			846.3				(131.1	)
Cash and cash equivalents at beginning of period		66.0			30.3				35.7
Cash and cash equivalents at end of period	$	781.2		$	876.6			$	(95.4	)

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 supply, 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 $400.0 million for the three months ended March 31, 2012, compared with $333.9 million for the same period in 2011.  The increase was due primarily to changes in net margin and operating expenses discussed in Financial Results and Operating Information on page 36.

The changes in operating assets and liabilities decreased operating cash flows $26.1 million for the three months ended March 31, 2012, compared with an increase of $313.9 million for the same period last year.  The change 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.

Investing Cash Flows - Cash used in investing activities increased for the three months ended March 31, 2012, compared with cash used in investing activities for the same period in 2011, due primarily to ONEOK Partners’ growth projects in its natural gas gathering and processing and natural gas liquids businesses and proceeds from the sale of ONEOK Energy Marketing Company.

Financing Cash Flows - Cash provided by financing activities increased for the three months ended March 31, 2012, compared with the same period in 2011.  The change is a result of our January 2012 debt issuance and the ONEOK Partners equity issuances in March 2012, offset partially by increased distributions to noncontrolling interests and increased dividends.

REGULATORY

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, many remain outstanding, including critical definitions.  In December 2011, the CFTC issued an order that further defers the effective date of the provisions of the Dodd-Frank Act that require a rulemaking, such as definitions of certain terms, until the earlier of the effective date of the final rule defining the reference terms or July 16, 2012.  Until the remaining final regulations are established, we are unable to ascertain how we may be affected by them.  Based on our assessment of the regulations issued to date and those proposed, 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 capital requirements and costs of hedging may increase as a result of the legislation.  We also may incur additional costs associated with our compliance with the new regulations and anticipated additional record keeping, reporting and disclosure obligations; however, we do not believe the costs will be material.  These requirements could affect adversely market liquidity and pricing of derivative contracts making it more difficult to execute our risk-management strategies in the future.  Also, the anticipated increased costs of compliance by dealers and counterparties likely will be passed on to customers, which could decrease the benefits of hedging to us and could reduce our profitability and liquidity.

Other - Several regulatory initiatives impacted the earnings and future earnings potential for our Natural Gas Distribution segment.  See discussion of our Natural Gas Distribution segment’s regulatory initiatives beginning on page 44.

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ENVIRONMENTAL MATTERS

Environmental Liabilities -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; storm water 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.

Additional information about our environmental matters is included in Note M 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 2012, The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law.  The new law increased maximum penalties for violating federal pipeline safety regulations and directs the DOT and Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us.  These issues include but are not limited to:

·   an evaluation on whether hazardous natural gas liquid and natural gas pipeline integrity-management requirements should be expanded beyond current high-consequence areas;

·   a review of all natural gas and hazardous natural gas liquid gathering pipeline exemptions;

·   a verification of records for pipelines in class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and

·   a requirement to test pipelines previously untested in high-consequence areas operating above 30-percent yield strength.

The potential capital and operating expenditures related to this legislation, the associated regulations or other new pipeline safety regulations are unknown.

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 were 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, as well as carbon dioxide equivalents from natural gas and NGL products delivered to customers, as if all such fuel and NGL products were combusted with the resulting carbon dioxide injected directly into disposal wells.  We reported 2011 greenhouse gas emissions for a portion of our facilities by March 31, 2012, as required by the EPA, and will report for the remainder of our facilities by September 30, 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,

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legislation to reduce greenhouse gas emissions, including carbon dioxide and methane.  At this time, no rule or legislation has been enacted that assesses 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.

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, with a compliance date 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 currently are unknown.

Superfund - The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or Superfund, imposes liability, without regard to fault or the legality of the original act, on certain classes of persons that 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.  In 2011, 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.  Neither we nor ONEOK Partners expect our respective current responsibilities under CERCLA, for this facility and any other, to have a material impact on our respective 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 and the DOT 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 have reviewed our pipeline facilities according to the new guideline requirements, and there have been no material changes required to date.

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 reduce voluntarily methane emissions.  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.

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IMPACT OF NEW ACCOUNTING STANDARDS

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

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 amounts 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 and crude oil because of market conditions caused by concerns about global warming;

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·   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;

·   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.

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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.

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 D 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 $5.6 million and $80.7 million of net assets at March 31, 2012, and December 31, 2011, 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, 2011	$	12,609
Derivatives reclassified or otherwise settled during the period		(1,575	)
Fair value of new derivatives entered into during the period		2,760
Other changes in fair value		(2,250	)
Net fair value of derivatives outstanding at March 31, 2012 (a)	$	11,544
(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: $10.2 million matures through March 2013 and $1.3 million matures through March 2016.

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 fair value measurements and derivative instruments, 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 C and D 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 $1.9 million and $4.6 million at March 31, 2012 and 2011, respectively.  The following table sets forth the average, high and low VAR calculations for the periods indicated:

	Three Months Ended
	March 31,
Value-at-Risk	2012		2011
	(Millions of dollars)
Average	$	2.4	$	3.2
High	$	3.0	$	4.9
Low	$	1.9	$	2.0

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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 our portfolio during the year.  The decrease in average VAR for March 31, 2012, compared with March 31, 2011, was due primarily to a decrease in total transportation capacity over the five-year period that VAR is calculated.

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.

INTEREST-RATE RISK

We are subject to the risk of interest-rate fluctuation in the normal course of business.  We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps.  At March 31, 2012, the interest rate on all of ONEOK’s and ONEOK Partners’ long-term debt was fixed.

ONEOK and ONEOK Partners have each entered into forward-starting interest-rate swaps 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.  ONEOK had interest-rate swaps with a notional value of $500 million at December 31, 2011.  In January 2012, ONEOK entered into additional interest-rate swaps with a notional amount of $200 million.  Upon issuance in January 2012 of our $700 million, 4.25-percent senior notes due 2022, ONEOK settled all $700 million of its interest-rate swaps and realized a loss of $44.1 million in accumulated other comprehensive income that will be amortized to interest expense over the term of the hedged debt.  At March 31, 2012, and December 31, 2011, ONEOK Partners had forward-starting interest-rate swaps with notional amounts of $750 million.  In April 2012, ONEOK Partners entered into additional forward-starting interest-rate swaps with a notional amount of $250 million.

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 first quarter ended March 31, 2012, 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.

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.

58

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 (a)	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 (or Units) that May Be Purchased Under the Plans or Programs
January 1-31, 2012	3,750	$	16.99		-
February 1-29, 2012	2,000	$	16.88		-
March 1-31, 2012	-		-		-
Total	5,750	$	16.95		-	$	450,000,000	(b)
(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.
(b) - 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.                      MINE SAFETY DISCLOSURES

Not Applicable.

ITEM 5.                      OTHER INFORMATION

Not Applicable.

ITEM 6.                      EXHIBITS

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

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

Exhibit No.             Exhibit Description

4.1 Indenture, dated as of January 26, 2012, among ONEOK, Inc. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed January 26, 2010.)

4.2 First Supplemental Indenture, dated January 26, 2012, among ONEOK, Inc. and U.S. Bank National Association, as trustee, with respect to the 4.25 percent Senior Notes due 2022 (incorporated by reference to Exhibit 4.2 to Form 8-K filed January 26, 2012).

59

10.1 Underwriting Agreement dated January 23, 2012, among ONEOK, Inc. and J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein (incorporated by reference to Exhibit 4.1 to Form 8-K filed January 26, 2012).

10.2 Underwriting Agreement dated February 28, 2012, among ONEOK Partners, L.P. and the underwriters therein (incorporated by reference to Exhibit 1.1 to ONEOK Partners, L.P.’s report on Form 8-K filed on March 2, 2012).

10.3 Common Unit Purchase Agreement dated February 28, 2012, between ONEOK Partners, L.P. and ONEOK, Inc. (incorporated by reference to Exhibit 1.2 to ONEOK Partners, L.P.’s report on Form 8-K filed on March 2, 2012).

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 XBRL-related documents:  (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three months ended March 31, 2012 and 2011; (iii) Consolidated Statements of Comprehensive Income for the three months ended March 31, 2012 and 2011; (iv) Consolidated Balance Sheets at March 31, 2012, and December 31, 2011; (v) Consolidated Statements of Cash Flows for the three months ended March 31, 2012 and 2011; (vi) Consolidated Statement of Changes in Equity for the three months ended March 31, 2012; and (vii) Notes to Consolidated Financial Statements.

We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report.

60

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:  May 2, 2012                                                                By:         /s/ Robert F. Martinovich

Robert F. Martinovich

Executive Vice President,

Chief Financial Officer and Treasurer

(Principal Financial Officer)

61

EX-31.1

Exhibit 31.1

Certification

I, John W. Gibson, certify that:

I have reviewed this quarterly report on Form 10-Q of ONEOK, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors:

a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 2, 2012

/s/ John W. Gibson

John W. Gibson

Chief Executive Officer

EX-31.2

Exhibit 31.2

Certification

I, Robert F. Martinovich, certify that:

I have reviewed this quarterly report on Form 10-Q of ONEOK, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors:

a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 2, 2012

/s/ Robert F. Martinovich

Robert F. Martinovich

Chief Financial Officer

EX-32.1

 Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of ONEOK, Inc. (the “Registrant”) for the period ending March 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John W. Gibson, Chief Executive Officer of the Registrant, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)       the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)       the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

/s/ John W. Gibson

John W. Gibson

Chief Executive Officer

May 2, 2012

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to ONEOK, Inc. and will be retained by ONEOK, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

 Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of ONEOK, Inc. (the “Registrant”) for the period ending March 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert F. Martinovich, Chief Financial Officer of the Registrant, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)       the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)       the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

/s/ Robert F. Martinovich

Robert F. Martinovich

Chief Financial Officer

May 2, 2012

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to ONEOK, Inc. and will be retained by ONEOK, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

XML

FAIR VALUE MEASUREMENTS, Fair Value Measurements - Part 2 (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation Calculation [Roll Forward]
Balance, beginning	$ 17,821	$ 19,730
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 March 31	(3,189)	(1,313)
Total realized/unrealized gains (losses):
Included in earnings	(1,288)	(7,151)
Included in other comprehensive income (loss)	5,785	(9,855)
Sale of discontinued operations	(3,636)
Transfers into Level 3	0	6
Transfers out of Level 3	(4,504)	(1,106)
Balance, ending	14,178	1,624
Derivative Financial Instruments, Assets Liabilities [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation Calculation [Roll Forward]
Balance, beginning	25,104	49,266
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 March 31	(4,687)	2,878
Total realized/unrealized gains (losses):
Included in earnings	(4,801)	(7,696)
Included in other comprehensive income (loss)	5,785	(9,855)
Sale of discontinued operations	(3,636)
Transfers into Level 3	0	6
Transfers out of Level 3	(4,504)	(1,106)
Balance, ending	17,948	30,615
Fair Value Measurement With Unobservable Inputs Recurring Basis Assets And Liabilities Value	1,481
Derivative Financial Instruments, Assets Liabilities [Member] | Commodity Contract [Member] | Financial Derivative Instrument [Member]
Total realized/unrealized gains (losses):
Fair Value Measurement With Unobservable Inputs Recurring Basis Assets And Liabilities Value	126
Derivative Financial Instruments, Assets Liabilities [Member] | Commodity Contract [Member] | Physical Derivative Instrument [Member]
Total realized/unrealized gains (losses):
Fair Value Measurement With Unobservable Inputs Recurring Basis Assets And Liabilities Value	1,355
Firm Commitments [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation Calculation [Roll Forward]
Balance, beginning	(7,283)	(29,536)
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 March 31	1,498	(4,191)
Total realized/unrealized gains (losses):
Included in earnings	3,513	545
Included in other comprehensive income (loss)	0	0
Sale of discontinued operations	0
Transfers into Level 3	0	0
Transfers out of Level 3	0	0
Balance, ending	(3,770)	(28,991)
Fair Value Measurement With Unobservable Inputs Recurring Basis Assets And Liabilities Value	(424)
Firm Commitments [Member] | Commodity Contract [Member] | Financial Derivative Instrument [Member]
Total realized/unrealized gains (losses):
Fair Value Measurement With Unobservable Inputs Recurring Basis Assets And Liabilities Value	0
Firm Commitments [Member] | Commodity Contract [Member] | Physical Derivative Instrument [Member]
Total realized/unrealized gains (losses):
Fair Value Measurement With Unobservable Inputs Recurring Basis Assets And Liabilities Value	$ (424)

XML

EMPLOYEE BENEFIT PLANS (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Pension Benefits [Member]
Components of net periodic benefit cost
Service cost	$ 5,325	$ 5,003
Interest cost	14,809	14,689
Expected return on assets	(20,689)	(18,875)
Amortization of unrecognized net asset at adoption	0	0
Amortization of unrecognized prior service cost	242	254
Amortization of net loss	12,111	8,928
Net periodic benefit cost	11,798	9,999
Postretirement Benefits [Member]
Components of net periodic benefit cost
Service cost	1,240	1,260
Interest cost	3,473	3,958
Expected return on assets	(2,671)	(2,568)
Amortization of unrecognized net asset at adoption	718	797
Amortization of unrecognized prior service cost	(2,063)	(501)
Amortization of net loss	3,296	2,031
Net periodic benefit cost	$ 3,993	$ 4,977

XML

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Balance of accumulated other comprehensive income (loss) [Abstract]
Unrealized Gains (Losses) on Energy Marketing and Risk Management Assets/Liabilities	$ (22,538)		$ (55,367)
Unrealized Holding Gains (Losses) on Investment Securities	1,211		987
Pension and Postretirement Benefit Plan Obligations	(157,518)		(151,741)
Accumulated Other Comprehensive Income (Loss)	(178,845)		(206,121)
Other comprehensive income (loss) attributable to ONEOK [Abstract]
Unrealized Gains (Losses) on Energy Marketing and Risk Management Assets/Liabilities	32,829
Unrealized Holding Gains (Losses) on Investment Securities	224	(99)
Pension and Postretirement Benefit Plan Obligations	(5,777)	(4,673)
Accumulated Other Comprehensive Income (Loss)	$ 27,276

XML

UNCONSOLIDATED AFFILIATES (Tables)

3 Months Ended

Mar. 31, 2012

UNCONSOLIDATED AFFILIATES [Abstract]

Equity Earnings from Investments

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
	March 31,
	2012		2011
	(Thousands of dollars)
Northern Border Pipeline Company	$	20,231	$	20,852
Overland Pass Pipeline		5,317		4,376
Fort Union Gas Gathering		4,208		2,965
Bighorn Gas Gathering		1,165		1,493
Other		3,699		2,406
Equity earnings from investments	$	34,620	$	32,092

Unconsolidated Affiliates Financial Information

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

	Three Months Ended
	March 31,
	2012		2011
	(Thousands of dollars)
Income Statement
Operating revenues	$	127,924	$	123,301
Operating expenses	$	54,568	$	54,236
Net income	$	65,254	$	63,165
Distributions paid to us	$	40,941	$	32,511

XML

ONEOK PARTNERS (Policies)

3 Months Ended

Mar. 31, 2012

ONEOK PARTNERS [Abstract]

Cash Distributions

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.  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.

XML

ONEOK PARTNERS (Details) (USD $)

3 Months Ended

12 Months Ended

Mar. 31, 2012

Mar. 31, 2011

Dec. 31, 2011

Related Party Transaction [Line Items]

Issuance of common units (in units)

8,000,000

Issuance of common units, in value

$ 459,735,000

$ 0

Issuance of Common Units Sold in Private Placement (in units)

8,000,000

Issuance of Common Units Sold in Private Placement (in value)

460,000,000

Face Value

350,000,000

Interest rate (in hundredths)

5.90%

Repayment on line of credit facility

295,000,000

Maturity date

Apr. 01, 2012

Ownership interest (in hundredths)

43.40%

42.80%

Total distributions paid

164,083,000

147,776,000

Total distributions declared

187,952,000

149,814,000

Revenues

75,705,000

96,793,000

Expenses

Cost of sales and fuel

9,275,000

10,731,000

Administrative and general expenses

56,361,000

56,295,000

Total expenses

65,636,000

67,026,000

Partnership agreement

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.  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.

General Partner [Member]

Related Party Transaction [Line Items]

Ownership interest (in hundredths)

2.00%

Limited Partner [Member]

Related Party Transaction [Line Items]

Ownership interest (in hundredths)

41.40%

Common units

19,800,000

Class B units

73,000,000

Dividend Paid [Member]

Related Party Transaction [Line Items]

Distribution per unit

$ 0.61

$ 0.57

Dividend Paid [Member] | General Partner [Member]

Related Party Transaction [Line Items]

General partner distributions

3,281,000

2,956,000

Incentive distributions

36,472,000

28,645,000

Distributions to general partner

39,753,000

31,601,000

Dividend Paid [Member] | Limited Partner [Member]

Related Party Transaction [Line Items]

Limited partner distributions to ONEOK

51,721,000

48,329,000

Limited partner distributions to noncontrolling interest

72,609,000

67,846,000

Dividend Declared [Member]

Related Party Transaction [Line Items]

Distribution per unit

$ 0.635

$ 0.575

Dividend Declared [Member] | General Partner [Member]

Related Party Transaction [Line Items]

General partner distributions

3,759,000

2,996,000

Incentive distributions

44,610,000

29,624,000

Distributions to general partner

48,369,000

32,620,000

Dividend Declared [Member] | Limited Partner [Member]

Related Party Transaction [Line Items]

Limited partner distributions to ONEOK

58,921,000

48,753,000

Limited partner distributions to noncontrolling interest

$ 80,662,000

$ 68,441,000

XML

RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES, Part 2 (Details) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Premiums recorded in other current assets on natural gas contracts held			$ 10,000,000
Entity Information [Line Items]
Gains related to the change in fair value of derivatives	500,000	5,400,000
Change in fair value of the related hedged firm commitments for transportation contracts	1,800,000	5,000,000
Fair value of collateral	6,800,000
Aggregate fair value of additional collateral	6,800,000
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	72,534,000		61,604,000
Financial [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	24,798,000		13,566,000
Gas and Electric Utilities [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	35,018,000		22,899,000
Industrial [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure			14,962,000
Oil and Gas [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	11,869,000		10,071,000
Other companies [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	849,000		106,000
Investment Grade [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	71,357,000		45,994,000
Investment Grade [Member] | Financial [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	24,798,000		13,566,000
Investment Grade [Member] | Gas and Electric Utilities [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	34,644,000		22,335,000
Investment Grade [Member] | Industrial [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure			7,000
Investment Grade [Member] | Oil and Gas [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	11,791,000		9,986,000
Investment Grade [Member] | Other companies [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	124,000		100,000
Non-Investment Grade [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	14,000		11,000
Non-Investment Grade [Member] | Financial [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	0		0
Non-Investment Grade [Member] | Gas and Electric Utilities [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	0		0
Non-Investment Grade [Member] | Industrial [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure			0
Non-Investment Grade [Member] | Oil and Gas [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	3,000		5,000
Non-Investment Grade [Member] | Other companies [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	11,000		6,000
Not Rated [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	1,163,000		15,599,000
Not Rated [Member] | Financial [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	0		0
Not Rated [Member] | Gas and Electric Utilities [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	374,000		564,000
Not Rated [Member] | Industrial [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure			14,955,000
Not Rated [Member] | Oil and Gas [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	75,000		80,000
Not Rated [Member] | Other companies [Member]
Derivative Credit Exposure [Line Items]
Derivative Credit Exposure	714,000		0
Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	66,667,000	(18,303,000)
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)	(435,000)	32,351,000
Cash Flow Hedging [Member] | Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	45,565,000	(18,303,000)
Cash Flow Hedging [Member] | Interest Rate Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	21,102,000	0
Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gain recognized in income on derivatives	3,278,000	2,954,000
Cost of Sales and Fuel [Member] | Cash Flow Hedging [Member] | Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)	(61,977,000)	(828,000)
Cost of Sales and Fuel [Member] | Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Non-trading [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gain recognized in income on derivatives	2,963,000	2,548,000
Interest Expense [Member] | Cash Flow Hedging [Member] | Interest Rate Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)	(827,000)	(208,000)
Revenues [Member] | Cash Flow Hedging [Member] | Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)	62,369,000	33,387,000
Revenues [Member] | Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Trading [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gain recognized in income on derivatives	$ 315,000	$ 406,000

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DISCONTINUED OPERATIONS (Details) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
DISCONTINUED OPERATIONS [Abstract]
Description and timing of discontinued operations	On February 1, 2012, we sold ONEOK Energy Marketing Company, our retail natural gas marketing business, to Constellation Energy Group, Inc. for $22.5 million plus working capital.
Proceeds from sale of business	$ 32,000,000
Operating Revenues	27,607,000	106,289,000
Cost of sales and fuel	25,961,000	102,617,000
Net Margin	1,646,000	3,672,000
Operating costs	408,000	1,933,000
Depreciation, depletion and amortization	8,000	32,000
Operating income	1,230,000	1,707,000
Other income (expense), net	0	16,000
Income taxes	(468,000)	(662,000)
Income from discontinued operations, net	762,000	1,061,000
Gain on sale of discontinued operations	13,250,000	0
Gain on sale of business, tax impact	8,119,000
Assets
Cash and cash equivalents			8,859,000
Accounts recievable, net			47,967,000
Gas in storage			2,101,000
Energy marketing and risk management assets			15,016,000
Other assets			193,000
Assets of discontinued operations			74,136,000
Liabilities
Accounts payable			11,435,000
Energy marketing and risk management liabilities			629,000
Other liabilities			751,000
Liabilities of discontinued operations			12,815,000
Intercompany payables			$ 45,700,000

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SEGMENTS (Details) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Segment Reporting Information [Line Items]
Ownership interest (in hundredths)	43.40%		42.80%
Sales to unaffiliated customers	$ 3,414,600,000	$ 3,760,600,000
Intersegment revenues	0	0
Total revenues	3,414,600,000	3,760,600,000
Net margin	643,587,000	629,877,000
Operating costs	224,058,000	221,681,000
Depreciation and amortization	83,409,000	79,357,000
Goodwill impairment	10,255,000	0
Gain (loss) on sale of assets	57,000	(510,000)
Operating income	325,922,000	328,329,000
Equity earnings from investments	34,620,000	32,092,000
Investments in unconsolidated affiliates	1,219,635,000	1,186,588,000	1,223,398,000
Total assets	14,252,076,000	13,039,596,000	13,696,635,000
Noncontrolling interests in consolidated subsidiaries	2,123,303,000	1,457,933,000	1,561,159,000
Capital expenditures	348,437,000	194,679,000
Description of benchmark criteria	10 percent or more of our consolidated gross revenues	10 percent or more of our consolidated gross revenues
ONEOK Partners Regulated Segment [Member]
Segment Reporting Information [Line Items]
Sales to unaffiliated customers	2,518,383,000	2,402,817,000
Intersegment revenues	75,705,000	96,793,000
Total revenues	2,594,088,000	2,499,610,000
Net margin	421,090,000	329,554,000
Operating costs	115,870,000	108,743,000
Depreciation and amortization	49,256,000	42,730,000
Goodwill impairment	0
Gain (loss) on sale of assets	57,000	(510,000)
Operating income	256,021,000	177,571,000
Equity earnings from investments	34,620,000	32,092,000
Investments in unconsolidated affiliates	1,219,635,000	1,186,588,000
Total assets	9,807,189,000	8,482,304,000
Noncontrolling interests in consolidated subsidiaries	4,988,000	5,128,000
Capital expenditures	280,793,000	144,826,000
ONEOK Partners Regulated Segment [Member] | Regulated Segment [Member]
Segment Reporting Information [Line Items]
Total revenues	171,200,000	155,500,000
Net margin	122,900,000	115,900,000
Operating income	64,600,000	59,600,000
Natural Gas Distribution Regulated Segment [Member]
Segment Reporting Information [Line Items]
Sales to unaffiliated customers	516,923,000	679,407,000
Intersegment revenues	841,000	4,775,000
Total revenues	517,764,000	684,182,000
Net margin	237,348,000	243,734,000
Operating costs	104,986,000	104,697,000
Depreciation and amortization	33,520,000	35,947,000
Goodwill impairment	0
Gain (loss) on sale of assets	0	0
Operating income	98,842,000	103,090,000
Equity earnings from investments	0	0
Investments in unconsolidated affiliates	0	0
Total assets	3,175,009,000	3,171,977,000
Noncontrolling interests in consolidated subsidiaries	0	0
Capital expenditures	58,448,000	47,150,000
Energy Services [Member]
Segment Reporting Information [Line Items]
Sales to unaffiliated customers	378,698,000	677,800,000
Intersegment revenues	82,110,000	213,939,000
Total revenues	460,808,000	891,739,000
Net margin	(15,446,000)	55,949,000
Operating costs	4,839,000	8,004,000
Depreciation and amortization	129,000	149,000
Goodwill impairment	10,255,000
Gain (loss) on sale of assets	0	0
Operating income	(30,669,000)	47,796,000
Equity earnings from investments	0	0
Investments in unconsolidated affiliates	0	0
Total assets	401,218,000	498,450,000
Noncontrolling interests in consolidated subsidiaries	0	0
Capital expenditures	0	0
Corporate Elimination [Member]
Segment Reporting Information [Line Items]
Sales to unaffiliated customers	596,000	576,000
Intersegment revenues	(158,656,000)	(315,507,000)
Total revenues	(158,060,000)	(314,931,000)
Net margin	595,000	640,000
Operating costs	(1,637,000)	237,000
Depreciation and amortization	504,000	531,000
Goodwill impairment	0
Gain (loss) on sale of assets	0	0
Operating income	1,728,000	(128,000)
Equity earnings from investments	0	0
Investments in unconsolidated affiliates	0	0
Total assets	868,660,000	886,865,000
Noncontrolling interests in consolidated subsidiaries	2,118,315,000	1,452,805,000
Capital expenditures	$ 9,196,000	$ 2,703,000

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EARNINGS PER SHARE (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Basic EPS from continuing operations [Abstract]
Net income attributable to ONEOK available for common stock	$ 108,853	$ 129,069
Weighted Average number of share, basic (in shares)	103,809	107,020
Per share amount, basic (in dollars per shares)	$ 1.05	$ 1.21
Diluted EPS from continuing operations [Abstract]
Effect of options and other dilutive securities	0	0
Effect of options and other dilutive securities, number of shares (in shares)	2,117	2,159
Net income attributable to ONEOK available for common stock and common stock equivalents, diluted	$ 108,853	$ 129,069
Weighted Average number of share, diluted (in shares)	105,926	109,179
Per Share amount, diluted (in dollars per share)	$ 1.03	$ 1.18

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CONSOLIDATED STATEMENT OF CHANGES IN EQUITY Parenthetical (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY [Abstract]
Dividends declared per share of common stock	$ 0.61	$ 0.52

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CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE (Details) (USD $)	3 Months Ended
	Mar. 31, 2012
ONEOK 2011 Credit Agreement [Member]
Line of Credit Facility [Line Items]
Expiration date	April 2016
Maximum debt-to-capital ratio (in hundredths)	67.50%
Current debt-to-capital ratio (in hundredths)	47.10%
Commercial paper	$ 419,800,000
Letters of credit issued	2,000,000
Remaining available borrowing capacity to meet liquidity needs	778,200,000
Maximum borrowing capacity	1,200,000,000
Option to increase borrowing capacity	1,700,000,000
ONEOK Partners 2011 Credit Agreement [Member]
Line of Credit Facility [Line Items]
Expiration date	August 2016
Partnership 2011 Credit Agreement sublimit for issuance of standby letters of credit	100,000,000
Debt to EBITDA covenant ratio, before amendment	5.0 to 1
Acquisition price threshold for increase in permitted debt to EBITDA covenant ratio	25,000,000
Debt to EBITDA covenant ratio, amendment	5.5 to 1
Debt to EBITDA covenant, period end	2.6 to 1
Maximum borrowing capacity	1,200,000,000
Option to increase borrowing capacity	$ 1,700,000,000

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EQUITY (Tables)

3 Months Ended

Mar. 31, 2012

EQUITY [Abstract]

Changes in equity, including other comprehensive income, net of tax

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
	March 31, 2012									March 31, 2011
	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	$	2,238,573		$	1,561,159		$	3,799,732		$	2,448,623		$	1,472,218		$	3,920,841
Net income		122,865			110,597			233,462			130,130			69,216			199,346
Other comprehensive income (loss)		27,276			13,564			40,840			(26,335	)		(15,459	)		(41,794	)
Repurchase of common stock		-			-			-			(48	)		-			(48	)
Common stock issued		2,561			-			2,561			2,365			-			2,365
Common stock dividends		(63,375	)		-			(63,375	)		(55,651	)		-			(55,651	)
Issuance of common units of ONEOK Partners		(51,100	)		510,835			459,735			-			-			-
Distributions to noncontrolling interests		-			(72,852	)		(72,852	)		-			(68,041	)		(68,041	)
Other		(20,648	)		-			(20,648	)		-			-			-
Ending balance	$	2,256,152		$	2,123,303		$	4,379,455		$	2,499,084		$	1,457,934		$	3,957,018

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RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES (Tables)

3 Months Ended

Mar. 31, 2012

RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES [Abstract]

Fair value of derivatives

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

	March 31, 2012							December 31, 2011
	Fair Values of Derivatives (a)							Fair Values of Derivatives (a)
	Assets			(Liabilities)				Assets			(Liabilities)
	(Thousands of dollars)
Derivatives designated as hedging instruments
Commodity contracts
Financial contracts	$	146,928	(b)	$	(102,526	)	(b)	$	184,184	(c)	$	(73,346	)
Physical contracts		375			(43	)			62			(344	)
Interest-rate contracts		-			(63,473	)			-			(128,666	)
Total derivatives designated as hedging instruments		147,303			(166,042	)			184,246			(202,356	)
Derivatives not designated as hedging instruments
Commodity contracts
Nontrading instruments
Financial contracts		345,662			(362,653	)			295,948			(323,170	)
Physical contracts		26,767			(177	)			38,733			(1,665	)
Trading instruments
Financial contracts		156,786			(154,843	)			111,920			(110,050	)
Total derivatives not designated as hedging instruments		529,215			(517,673	)			446,601			(434,885	)
Total derivatives	$	676,518		$	(683,715	)		$	630,847		$	(637,241	)
(a) - Included on a net basis in energy marketing and risk-management assets and liabilities, other assets and other deferred credits on our Consolidated Balance Sheets.
(b) - Includes $11.1 million of derivative assets associated with cash flow hedges of inventory that were adjusted to reflect the lower of cost or market value in a prior period. Also, includes $31.6 million of net derivative liabilities and ineffectiveness associated with cash flow hedges of inventory related to certain financial contracts that were used to hedge forecasted purchases of natural gas. The deferred gains and losses associated with these assets and net liabilities have been reclassified from accumulated other comprehensive loss.
(c) - Includes $88.9 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 amounts of derivative instruments

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

		March 31, 2012				December 31, 2011
	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		21.0	(20.9	)		21.2	(23.4	)
	Swaps		18.4	(95.2	)		19.5	(111.9	)
- Crude oil and NGLs (MMBbl)	Swaps		-	(3.6	)		-	(2.9	)
Basis
- Natural gas (Bcf)	Forwards and swaps		4.1	(49.6	)		3.2	(82.8	)
Interest-rate contracts (Millions of dollars)	Forward-starting swaps	$	750.0	-		$	1,250.0	-
Fair value hedges
Basis
- Natural gas (Bcf)	Forwards and swaps		109.1	(109.1	)		76.5	(77.0	)
Derivatives not designated as hedging instruments:
Fixed price
- Natural gas (Bcf)	Exchange futures		56.7	(53.4	)		76.9	(59.6	)
	Forwards and swaps		197.3	(200.6	)		235.8	(253.4	)
	Options		146.1	(141.1	)		33.6	(14.3	)
Basis
- Natural gas (Bcf)	Forwards and swaps		184.0	(186.1	)		216.9	(219.3	)
Index
- Natural gas (Bcf)	Forwards and swaps		51.8	(22.7	)		29.3	(22.1	)

Schedule of cash flow hedging instruments effect on comprehensive income (loss)

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

	Three Months Ended
Derivatives in Cash Flow Hedging Relationships	March 31,
	2012		2011
	(Thousands of dollars)
Commodity contracts	$	45,565	$	(18,303	)
Interest rate contracts		21,102		-
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	$	66,667	$	(18,303	)

Schedule of cash flow hedging instruments effect on income

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

	Location of Gain (Loss) Reclassified from	Three Months Ended
Derivatives in Cash Flow	Accumulated Other Comprehensive Income	March 31,
Hedging Relationship	(Loss) into Net Income (Effective Portion)	2012			2011
		(Thousands of dollars)
Commodity contracts	Revenues	$	62,369		$	33,387
Commodity contracts	Cost of sales and fuel		(61,977	)		(828	)
Interest-rate contracts	Interest expense		(827	)		(208	)
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)		$	(435	)	$	32,351

Schedule of derivatives not designated as hedging effect on income

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 our continuing and discontinued operations for the periods indicated:

		Three Months Ended
Derivatives Not Designated as		March 31,
Hedging Instruments	Location of Gain (Loss)	2012		2011
		(Thousands of dollars)
Commodity contracts - trading	Revenues	$	315	$	406
Commodity contracts - nontrading (a)	Cost of sales and fuel		2,963		2,548
Total gain recognized in income on derivatives		$	3,278	$	2,954
(a) - Amounts are presented net of deferred losses associated with derivatives entered into by our Natural Gas Distribution segment.

Schedule of net credit exposure from derivative assets

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

	March 31, 2012
	Investment		Noninvestment		Not
	Grade		Grade		Rated		Total
Counterparty sector	(Thousands of dollars)
Gas and electric utilities	$	34,644	$	-	$	374	$	35,018
Oil and gas		11,791		3		75		11,869
Financial		24,798		-		-		24,798
Other		124		11		714		849
Total	$	71,357	$	14	$	1,163	$	72,534

	December 31, 2011
	Investment		Noninvestment		Not
	Grade		Grade		Rated		Total
Counterparty sector	(Thousands of dollars)
Gas and electric utilities	$	22,335	$	-	$	564	$	22,899
Oil and gas		9,986		5		80		10,071
Industrial		7		-		14,955		14,962
Financial		13,566		-		-		13,566
Other		100		6		-		106
Total	$	45,994	$	11	$	15,599	$	61,604

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LONG-TERM DEBT (Details) (USD $)	3 Months Ended
	Mar. 31, 2012
Debt Instrument [Line Items]
Face Amount	$ 350,000,000
Interest rate (in hundredths)	5.90%
Maturity date	Apr. 01, 2012
Oneok [Member] | Notes Payables due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument call feature	ONEOK may redeem its senior notes due 2022 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting three month before the maturity date. Prior to this date, ONEOK may redeem the senior notes due 2022 in whole or in part, at any time 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's senior notes due 2022 are senior unsecured obligations, ranking equally in right of payment with all of ONEOK's existing and future unsecured senior indebtedness.
Debt instrument covenant description	The indenture governing ONEOK's senior notes due 2022 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 2022 to declare those senior notes immediately due and payable in full.
Maximum borrowing capacity	1,200,000,000
Underwritten public offering	700,000,000
Net proceeds from public offering	$ 694,300,000
Interest rates (in hundredths)	4.25%

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)

3 Months Ended

Mar. 31, 2012

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) [Abstract]

Accumulated other comprehensive income (loss)

The following table sets forth the balance in accumulated other comprehensive income (loss) for the period 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, 2011	$	(55,367)	$	987	$	(151,741)	$	(206,121)
Other comprehensive income (loss)    attributable to ONEOK		32,829		224		(5,777)		27,276
March 31, 2012	$	(22,538)	$	1,211	$	(157,518)	$	(178,845)

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EARNINGS PER SHARE (Tables)

3 Months Ended

Mar. 31, 2012

EARNINGS PER SHARE [Abstract]

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 March 31, 2012
	Income		Shares		Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK
available for common stock	$	108,853		103,809	$	1.05
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-		2,117
Income from continuing operations attributable to ONEOK
available for common stock and common stock equivalents	$	108,853		105,926	$	1.03

	Three Months Ended March 31, 2011
	Income		Shares		Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK
available for common stock	$	129,069		107,020	$	1.21
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-		2,159
Income from continuing operations attributable to ONEOK
available for common stock and common stock equivalents	$	129,069		109,179	$	1.18

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CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (USD $) In Thousands, except Share data	Total	Common Stock [Member]	Paid-in Capital [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Retained Earnings [Member]	Treasury Stock [Member]	Noncontrolling Interests in Consolidated Subsidiaries [Member]
Stockholders' equity, beginning balance at Dec. 31, 2010	$ 3,920,841						$ 1,472,218
Net income	199,346						69,216
Other comprehensive income (loss)	(41,794)						(15,459)
Repurchase of common stock	(48)						0
Common stock dividends - $0.61 per share	(55,651)						0
Distributions to noncontrolling interests	(68,041)						(68,041)
Other	0						0
Stockholders' equity, ending balance at Mar. 31, 2011	3,957,018						1,457,934
Stockholders' equity, beginning balance at Dec. 31, 2011	3,799,732	1,229	1,418,414	(206,121)	1,960,374	(935,323)	1,561,159
Common stock issued, beginning balance (in shares) at Dec. 31, 2011		122,904,924
Net income	233,462	0	0	0	122,865	0	110,597
Other comprehensive income (loss)	40,840	0	0	27,276	0	0	13,564
Repurchase of common stock	0						0
Common stock issued	2,561	0	(29,177)	0	0	31,738	0
Common stock issued (in shares)		667
Common stock dividends - $0.61 per share	(63,375)	0	0	0	(63,375)	0	0
Issuance of common units of ONEOK Partners	459,735	0	(51,100)	0	0	0	510,835
Distributions to noncontrolling interests	(72,852)	0	0	0	0	0	(72,852)
Other	(20,648)	0	(20,648)	0	0	0	0
Stockholders' equity, ending balance at Mar. 31, 2012	$ 4,379,455	$ 1,229	$ 1,317,489	$ (178,845)	$ 2,019,864	$ (903,585)	$ 2,123,303
Common stock issued, ending balance (in shares) at Mar. 31, 2012		122,905,591

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EMPLOYEE BENEFIT PLANS (Tables)

3 Months Ended

Mar. 31, 2012

EMPLOYEE BENEFIT PLANS [Abstract]

The components of net periodic benefit cost

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

	Pension Benefits						Postretirement Benefits
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2012			2011			2012			2011
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	5,325		$	5,003		$	1,240		$	1,260
Interest cost		14,809			14,689			3,473			3,958
Expected return on assets		(20,689	)		(18,875	)		(2,671	)		(2,568	)
Amortization of unrecognized net asset at adoption		-			-			718			797
Amortization of unrecognized prior service cost		242			254			(2,063	)		(501	)
Amortization of net loss		12,111			8,928			3,296			2,031
Net periodic benefit cost	$	11,798		$	9,999		$	3,993		$	4,977

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FAIR VALUE MEASUREMENTS, Fair Value - Part 3 (Details) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012 Energy Services [Member]	Mar. 31, 2012 Carrying (Reported) Amount, Fair Value Disclosure [Member]	Dec. 31, 2011 Carrying (Reported) Amount, Fair Value Disclosure [Member]	Mar. 31, 2012 Estimate of Fair Value, Fair Value Disclosure [Member]	Dec. 31, 2011 Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, including current maturities				$ 5,600,000,000	$ 4,900,000,000	$ 6,300,000,000	$ 5,600,000,000
Goodwill impairment	10,255,000	0
Goodwill, Impairment Loss	$ 10,255,000	$ 0	$ 10,255,000

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
CONSOLIDATED STATEMENTS OF INCOME [Abstract]
Revenues	$ 3,414,600	$ 3,760,600
Cost of sales and fuel	2,771,013	3,130,723
Net margin	643,587	629,877
Operating expenses
Operations and maintenance	192,881	192,759
Depreciation and amortization	83,409	79,357
Goodwill impairment	10,255	0
General taxes	31,177	28,922
Total operating expenses	317,722	301,038
Gain (loss) on sale of assets	57	(510)
Operating income	325,922	328,329
Equity earnings from investments (Note K)	34,620	32,092
Allowance for equity funds used during construction	975	466
Other income	9,861	3,352
Other expense	(2,274)	(2,285)
Interest expense	(75,815)	(79,349)
Income before income taxes	293,289	282,605
Income taxes	(73,839)	(84,320)
Income from continuing operations	219,450	198,285
Income from discontinued operations, net of tax (Note B)	762	1,061
Gain on sale of discontinued operations, net of tax (Note B)	13,250	0
Net income	233,462	199,346
Less: Net income attributable to noncontrolling interests	110,597	69,216
Net income attributable to ONEOK	122,865	130,130
Amounts attributable to ONEOK:
Income from continuing operations	108,853	129,069
Income from discontinued operations	14,012	1,061
Net Income	$ 122,865	$ 130,130
Basic earnings per share:
Income from continuing operations (Note I)	$ 1.05	$ 1.21
Income from discontinued operations	$ 0.13	$ 0.01
Net Income	$ 1.18	$ 1.22
Diluted earnings per share:
Income from continuing operations (Note I)	$ 1.03	$ 1.18
Income from discontinued operations	$ 0.13	$ 0.01
Net Income	$ 1.16	$ 1.19
Average shares (thousands)
Basic	103,809	107,020
Diluted	105,926	109,179
Dividends declared per share of common stock	$ 0.61	$ 0.52

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EQUITY (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Stockholders' equity, beginning balance	$ 3,799,732	$ 3,920,841
Net income	233,462	199,346
Other comprehensive income (loss)	40,840	(41,794)
Repurchase of common stock	0	(48)
Common stock issued	2,561	2,365
Common stock dividends	(63,375)	(55,651)
Issuance of common units of ONEOK Partners	459,735	0
Distributions to noncontrolling interests	(72,852)	(68,041)
Other	(20,648)	0
Stockholders' equity, ending balance	4,379,455	3,957,018
Stock Split	Stock Split - On February 15, 2012, our Board of Directors authorized a two-for-one split of our common stock, subject to shareholder approval of a proposal to increase the number of authorized shares of our common stock to 600 million from 300 million. The proposal will be voted on at our 2012 annual meeting of shareholders on May 23, 2012.
Dividend paid (in dollars per share)	$ 0.61
ONEOK Shareholders' Equity [Member]
Stockholders' equity, beginning balance	2,238,573	2,448,623
Net income	122,865	130,130
Other comprehensive income (loss)	27,276	(26,335)
Repurchase of common stock	0	(48)
Common stock issued	2,561	2,365
Common stock dividends	(63,375)	(55,651)
Issuance of common units of ONEOK Partners	(51,100)	0
Distributions to noncontrolling interests	0	0
Other	(20,648)	0
Stockholders' equity, ending balance	2,256,152	2,499,084
Noncontrolling Interests in Consolidated Subsidiaries [Member]
Stockholders' equity, beginning balance	1,561,159	1,472,218
Net income	110,597	69,216
Other comprehensive income (loss)	13,564	(15,459)
Repurchase of common stock	0	0
Common stock issued	0	0
Common stock dividends	0	0
Issuance of common units of ONEOK Partners	510,835	0
Distributions to noncontrolling interests	(72,852)	(68,041)
Other	0	0
Stockholders' equity, ending balance	$ 2,123,303	$ 1,457,934

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CONSOLIDATED BALANCE SHEETS Parenthetical (USD $)	Mar. 31, 2012	Dec. 31, 2011
CONSOLIDATED BALANCE SHEETS Parenthetical [Abstract]
Common stock, shares, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares, authorized (in shares)	300,000,000	300,000,000
Common stock, shares, outstanding (in shares)	103,922,403	103,254,980
Treasury stock, shares (in shares)	18,983,188	19,649,944

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SEGMENTS (Tables)

3 Months Ended

Mar. 31, 2012

SEGMENTS [Abstract]

Segments

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

Three Months Ended March 31, 2012	ONEOK Partners (a)		Natural Gas Distribution		Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	2,518,383	$	516,923	$	378,698		$	596		$	3,414,600
Intersegment revenues		75,705		841		82,110			(158,656	)		-
Total revenues	$	2,594,088	$	517,764	$	460,808		$	(158,060	)	$	3,414,600
Net margin	$	421,090	$	237,348	$	(15,446	)	$	595		$	643,587
Operating costs		115,870		104,986		4,839			(1,637	)		224,058
Depreciation and amortization		49,256		33,520		129			504			83,409
Goodwill impairment		-		-		10,255			-			10,255
Gain on sale of assets		57		-		-			-			57
Operating income	$	256,021	$	98,842	$	(30,669	)	$	1,728		$	325,922
Equity earnings from investments	$	34,620	$	-	$	-		$	-		$	34,620
Investments in unconsolidated    affiliates	$	1,219,635	$	-	$	-		$	-		$	1,219,635
Total assets	$	9,807,189	$	3,175,009	$	401,218		$	868,660		$	14,252,076
Noncontrolling interests in    consolidated subsidiaries	$	4,988	$	-	$	-		$	2,118,315		$	2,123,303
Capital expenditures	$	280,793	$	58,448	$	-		$	9,196		$	348,437
(a) - Our ONEOK Partners segment has regulated and nonregulated operations. Our ONEOK Partners segment's regulated operations had revenues of $171.2 million, net margin of $122.9 million and operating income of $64.6 million.

Three Months Ended March 31, 2011	ONEOK Partners (a)			Natural Gas Distribution		Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	2,402,817		$	679,407	$	677,800	$	576		$	3,760,600
Intersegment revenues		96,793			4,775		213,939		(315,507	)		-
Total revenues	$	2,499,610		$	684,182	$	891,739	$	(314,931	)	$	3,760,600
Net margin	$	329,554		$	243,734	$	55,949	$	640		$	629,877
Operating costs		108,743			104,697		8,004		237			221,681
Depreciation and amortization		42,730			35,947		149		531			79,357
Loss on sale of assets		(510	)		-		-		-			(510	)
Operating income	$	177,571		$	103,090	$	47,796	$	(128	)	$	328,329
Equity earnings from investments	$	32,092		$	-	$	-	$	-		$	32,092
Investments in unconsolidated   affiliates	$	1,186,588		$	-	$	-	$	-		$	1,186,588
Total assets	$	8,482,304		$	3,171,977	$	498,450	$	886,865		$	13,039,596
Noncontrolling interests in   consolidated subsidiaries	$	5,128		$	-	$	-	$	1,452,805		$	1,457,933
Capital expenditures	$	144,826		$	47,150	$	-	$	2,703		$	194,679
(a) - Our ONEOK Partners segment has regulated and nonregulated operations. Our ONEOK Partners segment's regulated operations had revenues of $155.5 million, net margin of $115.9 million and operating income of $59.6 million.

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COMMITMENTS AND CONTINGENCIES

3 Months Ended

Mar. 31, 2012

COMMITMENTS AND CONTINGENCIES [Abstract]

COMMITMENTS AND CONTINGENCIES

M.           COMMITMENTS AND CONTINGENCIES

Environmental Liabilities - 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, storm water 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 material 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 months ended March 31, 2012 or 2011.

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, with a compliance date 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 2012, The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law.  The new law increased the maximum penalties for violating federal pipeline safety regulations and directs the DOT and Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us.  These issues include but are not limited to:

·   an evaluation of whether hazardous natural gas liquid and natural gas pipeline integrity-management requirements should be expanded beyond current high-consequence areas;

·   a review of all natural gas and hazardous natural gas liquid gathering pipeline exemptions;

·   a verification of records for pipelines in class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and

·   a requirement to test pipelines previously untested in high-consequence areas operating above 30 percent yield strength.

The potential capital and operating expenditures related to this legislation, the associated regulations or other new pipeline safety regulations are unknown.

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, many remain outstanding, including critical definitions.  In December 2011, the CFTC issued an order that further defers the effective date of the provisions of the Dodd-Frank Act that require a rulemaking, such as definitions of certain terms, until the earlier of the effective date of the final rule defining the reference terms or July 16, 2012.  Until the remaining final regulations are established, we are unable to ascertain how we may be affected by them.  Based on our assessment of the regulations issued to date and those proposed, 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 capital requirements and costs of hedging may increase as a result of the legislation.  We also may incur additional costs associated with our compliance with the new regulations and anticipated additional record keeping, reporting and disclosure obligations; however, we do not believe the costs will be material.  These requirements could affect adversely market liquidity and pricing of derivative contracts making it more difficult to execute our risk-management strategies in the future.  Also, the anticipated increased costs of compliance by dealers and counterparties likely will be passed on to customers, which could decrease the benefits of hedging to us and could reduce our profitability and liquidity.

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 probable final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details)

3 Months Ended

Mar. 31, 2012

Summary of Significant Accounting Policies [Abstract]

Recently Issued Accounting Standards Update

Recently Issued Accounting Standards Update -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 adopted this guidance with this Quarterly Report and the impact was not material.  See Note C for information on our fair value measurements.

In June 2011, the FASB issued ASU 2011-05, 'Presentation of Comprehensive Income,' which provides two options for presenting items of net income, other comprehensive income and total comprehensive income by creating either one continuous statement of comprehensive income or two separate consecutive statements, and requires certain other disclosures.  In December 2011, the FASB issued ASU 2011-12, 'Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05,' which deferred certain presentation requirements in ASU 2011-05 for items reclassified out of accumulated other comprehensive income.  We adopted this guidance, except for the portions deferred by ASU 2011-12, with this Quarterly Report, and the impact was not material.

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RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES (Policies)

3 Months Ended

Mar. 31, 2012

RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES [Abstract]

Accounting treatment for derivative instruments

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 Natural Gas 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.

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.

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Operating Activities
Net income	$ 233,462	$ 199,346
Depreciation and amortization	83,417	79,391
Impairment of goodwill	10,255	0
Gain on sale of discontinued operations	(13,250)	0
Reclassified loss on energy price risk management assets and liabilities	29,861	0
Equity earnings from investments	(34,620)	(32,092)
Distributions received from unconsolidated affiliates	36,879	27,607
Deferred income taxes	51,411	52,044
Share-based compensation expense	5,008	7,902
Allowance for equity funds used during construction	(975)	(466)
Loss (gain) on sale of assets	(57)	510
Other	(1,360)	(333)
Changes in assets and liabilities:
Accounts receivable	180,413	53,410
Gas and natural gas liquids in storage	251,227	301,262
Accounts payable	(176,674)	(77,843)
Commodity imbalances, net	(101,604)	(18,092)
Energy marketing and risk management assets and liabilities	(122,900)	(12,683)
Other assets and liabilities	(4,408)	67,818
Cash provided by operating activities	426,085	647,781
Investing Activities
Capital expenditures (less allowance for equity funds used during construction)	(348,437)	(194,679)
Proceeds from sale of discontinued operations, net of cash sold	32,008	0
Contributions to unconsolidated affiliates	(2,577)	(250)
Distributions received from unconsolidated affiliates	4,062	4,904
Proceeds from sale of assets	521	540
Other	24	0
Cash used in investing activities	(314,399)	(189,485)
Financing Activities
Borrowing (repayment) of notes payable, net	(422,225)	(556,855)
Issuance of debt, net of discounts	699,657	1,295,450
Long-term debt financing costs	(5,392)	(10,986)
Repayment of debt	(3,082)	(228,137)
Issuance of common stock	2,228	5,024
Issuance of common units	459,735	0
Dividends paid	(63,375)	(55,651)
Distributions to noncontrolling interests	(72,852)	(68,041)
Other	0	(48)
Cash provided by financing activities	594,694	380,756
Change in cash and cash equivalents	706,380	839,052
Change in cash and cash equivalents included in discontinued operations	8,859	7,179
Change in cash and cash equivalents from continuing operations	715,239	846,231
Cash and cash equivalents at beginning of period	65,953	30,341
Cash and cash equivalents at end of period	$ 781,192	$ 876,572

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME [Abstract]
Net income	$ 233,462	$ 199,346
Other comprehensive income (loss), net of tax
Unrealized gains (losses) on energy marketing and risk-management assets/liabilities, net of tax of ($19,094) and $1,415, respectively	47,573	(16,888)
Realized losses (gains) in net income, net of tax of ($1,615) and $12,235, respectively	(1,180)	(20,116)
Unrealized holding gains (losses) on available-for-sale securities, net of tax of ($141) and $63, respectively	224	(99)
Change in pension and postretirement benefit plan liability, net of tax of $3,644 and $2,947, respectively	(5,777)	(4,673)
Other, net of tax of $0 and $11, respectively	0	(18)
Total other comprehensive income (loss), net of tax	40,840	(41,794)
Comprehensive income	274,302	157,552
Less: Comprehensive income attributable to noncontrolling interests	124,161	53,757
Comprehensive income attributable to ONEOK	$ 150,141	$ 103,795

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

3 Months Ended

Mar. 31, 2012

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) [Abstract]

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

H.           ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following table sets forth the balance in accumulated other comprehensive income (loss) for the period 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, 2011	$	(55,367)	$	987	$	(151,741)	$	(206,121)
Other comprehensive income (loss)    attributable to ONEOK		32,829		224		(5,777)		27,276
March 31, 2012	$	(22,538)	$	1,211	$	(157,518)	$	(178,845)

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Document And Entity Information (USD $) In Billions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Apr. 27, 2012	Jun. 30, 2011
Entity Registrant Name	ONEOK INC /NEW/
Entity Central Index Key	0001039684
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 7.3
Entity Common Stock, Shares Outstanding		103,926,470
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2012

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EARNINGS PER SHARE

3 Months Ended

Mar. 31, 2012

EARNINGS PER SHARE [Abstract]

EARNINGS PER SHARE

I.           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 March 31, 2012
	Income		Shares		Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK
available for common stock	$	108,853		103,809	$	1.05
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-		2,117
Income from continuing operations attributable to ONEOK
available for common stock and common stock equivalents	$	108,853		105,926	$	1.03

	Three Months Ended March 31, 2011
	Income		Shares		Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK
available for common stock	$	129,069		107,020	$	1.21
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-		2,159
Income from continuing operations attributable to ONEOK
available for common stock and common stock equivalents	$	129,069		109,179	$	1.18

There were no option shares excluded from the calculation of diluted EPS for the three months ended March 31, 2012 and 2011.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Parenthetical (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Other comprehensive income (loss), net of tax
Unrealized gains (losses) on energy marketing and risk-management assets/liabilities, tax	$ (19,094)	$ 1,415
Realized losses (gains) in net income, tax	(1,615)	12,235
Unrealized holding gains (losses) on available-for-sale securities, tax	(141)	63
Change in pension and postretirement benefit plan liability, tax	3,644	2,947
Other, tax	$ 0	$ 11

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FAIR VALUE MEASUREMENTS

3 Months Ended

Mar. 31, 2012

FAIR VALUE MEASUREMENTS [Abstract]

FAIR VALUE MEASUREMENTS

C.           FAIR VALUE MEASUREMENTS

Fair Value Measurements -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 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 monitor 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 our continuing and discontinued operations for the periods indicated:

	March 31, 2012
	Level 1			Level 2			Level 3			Netting			Total
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	601,625		$	20,271		$	27,480		$	-		$	649,376
Physical contracts		-			23,678			3,464			-			27,142
Netting		-			-			-			(603,984	)		(603,984	)
Total derivatives		601,625			43,949			30,944			(603,984	)		72,534
Trading securities (b)		6,826			-			-			-			6,826
Available-for-sale investment securities (c)		2,315			-			-			-			2,315
Total assets	$	610,766		$	43,949		$	30,944		$	(603,984	)	$	81,675
Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(595,397	)	$	(11,766	)	$	(12,859	)	$	-		$	(620,022	)
Physical contracts		-			(83	)		(137	)		-			(220	)
Netting		-			-			-			589,142			589,142
Interest-rate contracts		-			(63,473	)		-			-			(63,473	)
Total derivatives		(595,397	)		(75,322	)		(12,996	)		589,142			(94,573	)
Fair value of firm commitments (d)		-			-			(3,770	)		-			(3,770	)
Total liabilities	$	(595,397	)	$	(75,322	)	$	(16,766	)	$	589,142		$	(98,343	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk-management assets and liabilities and other assets 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 March 31, 2012, we held $15.1 million of cash collateral and had posted $0.3 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.

	December 31, 2011
	Level 1			Level 2			Level 3			Netting			Total
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	545,247		$	13,874		$	32,931		$	-		$	592,052
Physical contracts		-			23,879			14,916			-			38,795
Netting		-			-			-			(569,243	)		(569,243	)
Total derivatives		545,247			37,753			47,847			(569,243	)		61,604
Trading securities (b)		5,749			-			-			-			5,749
Available-for-sale investment securities (c)		1,949			-			-			-			1,949
Total assets	$	552,945		$	37,753		$	47,847		$	(569,243	)	$	69,302
Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(479,073	)	$	(6,498	)	$	(20,995	)	$	-		$	(506,566	)
Physical contracts		-			(261	)		(1,748	)		-			(2,009	)
Netting		-			-			-			497,608			497,608
Interest-rate contracts		-			(128,666	)		-			-			(128,666	)
Total derivatives		(479,073	)		(135,425	)		(22,743	)		497,608			(139,633	)
Fair value of firm commitments (d)		-			-			(7,283	)		-			(7,283	)
Total liabilities	$	(479,073	)	$	(135,425	)	$	(30,026	)	$	497,608		$	(146,916	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk-management assets and liabilities, other assets and other deferred credits 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, 2011, we held $73.3 million of cash collateral and had posted $1.7 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.

The tables above include balances for ONEOK Energy Marketing Company that have been reflected as discontinued operations in our Consolidated Balance Sheets.  At December 31, 2011, we had $15.0 million in derivative assets and $0.6 million in derivative liabilities related to this discontinued operation.

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 nonexchange-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 broker quotes, 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.  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.  The significant unobservable inputs used in the fair value measurement of our swaps, forwards and firm commitments are the unpublished forward basis and index curves.  Significant increases or decreases in either of those inputs in isolation would not have a material impact on our fair value measurements.

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)
January 1, 2012	$	25,104		$	(7,283	)	$	17,821
Total realized/unrealized gains (losses):
Included in earnings (a)		(4,801	)		3,513			(1,288	)
Included in other comprehensive income (loss)		5,785			-			5,785
Sale of discontinued operations		(3,636	)		-			(3,636	)
Transfers into Level 3		-			-			-
Transfers out of Level 3		(4,504	)		-			(4,504	)
March 31, 2012	$	17,948		$	(3,770	)	$	14,178
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 March 31, 2012 (a)	$	(4,687	)	$	1,498		$	(3,189	)
(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, 2011	$	49,266		$	(29,536	)	$	19,730
Total realized/unrealized gains (losses):
Included in earnings (a)		(7,696	)		545			(7,151	)
Included in other comprehensive income (loss)		(9,855	)		-			(9,855	)
Transfers into Level 3		6			-			6
Transfers out of Level 3		(1,106	)		-			(1,106	)
March 31, 2011	$	30,615		$	(28,991	)	$	1,624
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 March 31, 2011 (a)	$	2,878		$	(4,191	)	$	(1,313	)
(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 the levels in the fair value hierarchy as of the end of each reporting period.  We had no transfers into or out of Level 1 during the periods presented.  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.

The following table provides quantitative information about our Level 3 unobservable inputs, excluding the portion of our fair value measurements based on third-party pricing information without adjustment for the period indicated:

March 31, 2012
	Derivative Assets (Liabilities)		Fair Value of Firm Commitments			Unobservable Inputs	Valuation Process
(Thousands of dollars)
Commodity contracts (a)
Financial	$	126	$	-		Basis and Index Curves	Notional volume x Price Curve
Physical		1,355		(424	)	Basis and Index Curves	Notional volume x Price Curve
Unobservable inputs	$	1,481	$	(424	)
(a) - Unpublished basis and index curves on commodity contracts developed using broker quotes and management estimates.

Goodwill Impairment - As a result of the continued decline in natural gas prices and its effect on location and seasonal price differentials, we performed an interim impairment assessment of our Energy Services segment’s goodwill balance as of March 31, 2012. As a result of this assessment, goodwill with a carrying amount of $10.3 million was written down to its implied fair value of zero, with a resulting impairment charge of $10.3 million recorded in earnings for the period.  The fair value of our Energy Services reporting unit and the implied fair value of its goodwill were calculated using Level 3, significant unobservable inputs.

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.

Our cash and cash equivalents are comprised of bank and money market accounts and would be classified as Level 1.  Our notes payable would be classified as Level 2 since the estimated fair value of the notes payable can be determined using information available in the commercial paper market.  The estimated fair value of our consolidated long-term debt, including current maturities, was $6.3 billion at March 31, 2012, and $5.6 billion at December 31, 2011.  The book value of long-term debt, including current maturities, was $5.6 billion and $4.9 billion at March 31, 2012, and December 31, 2011, 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.  Our consolidated long-term debt would be classified as Level 2.

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DISCONTINUED OPERATIONS

3 Months Ended

Mar. 31, 2012

DISCONTINUED OPERATIONS [Abstract]

DISCONTINUED OPERATIONS

B.           DISCONTINUED OPERATIONS

On February 1, 2012, we sold ONEOK Energy Marketing Company, our retail natural gas marketing business, to Constellation Energy Group, Inc. for $22.5 million plus working capital.  We received net proceeds of approximately $32.0 million, and recognized an after-tax gain on the sale of approximately $13.3 million.  The proceeds from the sale were used to reduce short-term borrowings.  The financial information of ONEOK Energy Marketing Company is reflected as discontinued operations in this Quarterly Report.  All prior periods presented have been recast to reflect the discontinued operations.

The amounts of revenue, costs and income taxes reported in discontinued operations are set forth in the table below for the periods indicated:

	One Month Ended			Three Months Ended
	January 31,			March 31,
	2012			2011
	(Thousands of dollars)
Operating revenues	$	27,607			$	106,289
Cost of sales and fuel		25,961				102,617
Net margin		1,646				3,672
Operating costs		408				1,933
Depreciation, depletion and amortization		8				32
Operating income		1,230				1,707
Other income (expense), net		-				16
Income taxes		(468	)			(662	)
Income from discontinued operations, net	$	762			$	1,061
Gain on sale of discontinued operation, net of tax of $8,119	$	13,250			$	-

The following table discloses the major classes of discontinued assets and liabilities included on our Consolidated Balance Sheets for the period indicated:

		December 31,
		2011
Assets	(Thousands of dollars)
Cash and cash equivalents		$	8,859
Accounts receivable, net			47,967
Gas in storage			2,101
Energy marketing and risk management assets			15,016
Other assets			193
Assets of discontinued operations		$	74,136
Liabilities
Accounts payable		$	11,435
Energy marketing and risk management liabilities			629
Other liabilities			751
Liabilities of discontinued operations		$	12,815

At December 31, 2011, the liabilities of our discontinued operations exclude $45.7 million of intercompany payables due to its parent or other affiliates.

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SEGMENTS

3 Months Ended

Mar. 31, 2012

SEGMENTS [Abstract]

SEGMENTS

N.           SEGMENTS

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

·   our ONEOK Partners segment reflects the consolidated operations of ONEOK Partners.  We own a 43.4-percent ownership interest and control ONEOK Partners through our ownership of its general partner interest.  ONEOK Partners gathers, processes, treats, transports, stores and sells natural gas and gathers, treats, fractionates, stores, distributes and markets NGLs.  We and ONEOK Partners maintain significant financial and corporate governance separations.  We seek to receive increasing cash distributions as a result of our investment in ONEOK Partners, and our investment decisions are made based on the anticipated returns from ONEOK Partners in total, not specific to any of its businesses individually;

·   our Natural Gas Distribution segment is comprised of our regulated public utilities that deliver natural gas to residential, commercial and industrial customers, and transport natural gas; and

·   our Energy Services segment markets natural gas to wholesale customers. 

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 L.  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 months ended March 31, 2012 and 2011, we had no single external customer from which we received 10 percent or more 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 March 31, 2012	ONEOK Partners (a)		Natural Gas Distribution		Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	2,518,383	$	516,923	$	378,698		$	596		$	3,414,600
Intersegment revenues		75,705		841		82,110			(158,656	)		-
Total revenues	$	2,594,088	$	517,764	$	460,808		$	(158,060	)	$	3,414,600
Net margin	$	421,090	$	237,348	$	(15,446	)	$	595		$	643,587
Operating costs		115,870		104,986		4,839			(1,637	)		224,058
Depreciation and amortization		49,256		33,520		129			504			83,409
Goodwill impairment		-		-		10,255			-			10,255
Gain on sale of assets		57		-		-			-			57
Operating income	$	256,021	$	98,842	$	(30,669	)	$	1,728		$	325,922
Equity earnings from investments	$	34,620	$	-	$	-		$	-		$	34,620
Investments in unconsolidated    affiliates	$	1,219,635	$	-	$	-		$	-		$	1,219,635
Total assets	$	9,807,189	$	3,175,009	$	401,218		$	868,660		$	14,252,076
Noncontrolling interests in    consolidated subsidiaries	$	4,988	$	-	$	-		$	2,118,315		$	2,123,303
Capital expenditures	$	280,793	$	58,448	$	-		$	9,196		$	348,437
(a) - Our ONEOK Partners segment has regulated and nonregulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $171.2 million, net margin of $122.9 million and operating income of $64.6 million.

Three Months Ended March 31, 2011	ONEOK Partners (a)			Natural Gas Distribution		Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	2,402,817		$	679,407	$	677,800	$	576		$	3,760,600
Intersegment revenues		96,793			4,775		213,939		(315,507	)		-
Total revenues	$	2,499,610		$	684,182	$	891,739	$	(314,931	)	$	3,760,600
Net margin	$	329,554		$	243,734	$	55,949	$	640		$	629,877
Operating costs		108,743			104,697		8,004		237			221,681
Depreciation and amortization		42,730			35,947		149		531			79,357
Loss on sale of assets		(510	)		-		-		-			(510	)
Operating income	$	177,571		$	103,090	$	47,796	$	(128	)	$	328,329
Equity earnings from investments	$	32,092		$	-	$	-	$	-		$	32,092
Investments in unconsolidated   affiliates	$	1,186,588		$	-	$	-	$	-		$	1,186,588
Total assets	$	8,482,304		$	3,171,977	$	498,450	$	886,865		$	13,039,596
Noncontrolling interests in   consolidated subsidiaries	$	5,128		$	-	$	-	$	1,452,805		$	1,457,933
Capital expenditures	$	144,826		$	47,150	$	-	$	2,703		$	194,679
(a) - Our ONEOK Partners segment has regulated and nonregulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $155.5 million, net margin of $115.9 million and operating income of $59.6 million.

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EMPLOYEE BENEFIT PLANS

3 Months Ended

Mar. 31, 2012

EMPLOYEE BENEFIT PLANS [Abstract]

EMPLOYEE BENEFIT PLANS

J.           EMPLOYEE BENEFIT PLANS

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

	Pension Benefits						Postretirement Benefits
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2012			2011			2012			2011
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	5,325		$	5,003		$	1,240		$	1,260
Interest cost		14,809			14,689			3,473			3,958
Expected return on assets		(20,689	)		(18,875	)		(2,671	)		(2,568	)
Amortization of unrecognized net asset at adoption		-			-			718			797
Amortization of unrecognized prior service cost		242			254			(2,063	)		(501	)
Amortization of net loss		12,111			8,928			3,296			2,031
Net periodic benefit cost	$	11,798		$	9,999		$	3,993		$	4,977

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LONG-TERM DEBT

3 Months Ended

Mar. 31, 2012

LONG-TERM DEBT [Abstract]

LONG-TERM DEBT

F.           LONG-TERM DEBT

In January 2012, we completed an underwritten public offering of $700 million, 4.25-percent senior notes due 2022.  The net proceeds from the offering, after deducting underwriting discounts and offering expenses, of approximately $694.3 million were used to repay amounts outstanding under our $1.2 billion commercial paper program and for general corporate purposes.

The indenture governing ONEOK's senior notes due 2022 includes 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 2022 to declare those senior notes immediately due and payable in full.

ONEOK may redeem its senior notes due 2022 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting three months before the maturity date.  Prior to this date, ONEOK may redeem the senior notes due 2022, in whole or in part, at any time for 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's senior notes due 2022 are senior unsecured obligations, ranking equally in right of payment with all of ONEOK's existing and future unsecured senior indebtedness.

ONEOK Partners repaid its $350 million, 5.9-percent senior notes at maturity in April 2012 with a portion of the proceeds from its March 2012 equity issuance.

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RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

3 Months Ended

Mar. 31, 2012

RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES [Abstract]

RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

D.           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.

Our Natural Gas Distribution segment also uses derivative instruments to hedge the cost of a portion 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 Texas jurisdictions.

ONEOK and ONEOK Partners have each entered into forward-starting interest-rate swaps 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.  ONEOK had interest-rate swaps with a notional value of $500 million at December 31, 2011.  In January 2012, ONEOK entered into additional interest-rate swaps with a notional amount of $200 million.  Upon issuance in January 2012 of our $700 million, 4.25-percent senior notes due 2022, ONEOK settled all $700 million of its interest-rate swaps and realized a loss of $44.1 million in accumulated other comprehensive income that will be amortized to interest expense over the term of the hedged debt.  At March 31, 2012, and December 31, 2011, ONEOK Partners had forward-starting interest-rate swaps with notional amounts of $750 million.  In April 2012, ONEOK Partners entered into additional forward-starting interest-rate swaps with a notional amount of $250 million.

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 Natural Gas 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.

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 our continuing and discontinued operations for the periods indicated:

	March 31, 2012							December 31, 2011
	Fair Values of Derivatives (a)							Fair Values of Derivatives (a)
	Assets			(Liabilities)				Assets			(Liabilities)
	(Thousands of dollars)
Derivatives designated as hedging instruments
Commodity contracts
Financial contracts	$	146,928	(b)	$	(102,526	)	(b)	$	184,184	(c)	$	(73,346	)
Physical contracts		375			(43	)			62			(344	)
Interest-rate contracts		-			(63,473	)			-			(128,666	)
Total derivatives designated as hedging instruments		147,303			(166,042	)			184,246			(202,356	)
Derivatives not designated as hedging instruments
Commodity contracts
Nontrading instruments
Financial contracts		345,662			(362,653	)			295,948			(323,170	)
Physical contracts		26,767			(177	)			38,733			(1,665	)
Trading instruments
Financial contracts		156,786			(154,843	)			111,920			(110,050	)
Total derivatives not designated as hedging instruments		529,215			(517,673	)			446,601			(434,885	)
Total derivatives	$	676,518		$	(683,715	)		$	630,847		$	(637,241	)
(a) - Included on a net basis in energy marketing and risk-management assets and liabilities, other assets and other deferred credits on our Consolidated Balance Sheets.
(b) - Includes $11.1 million of derivative assets associated with cash flow hedges of inventory that were adjusted to reflect the lower of cost or market value in a prior period. Also, includes $31.6 million of net derivative liabilities and ineffectiveness associated with cash flow hedges of inventory related to certain financial contracts that were used to hedge forecasted purchases of natural gas. The deferred gains and losses associated with these assets and net liabilities have been reclassified from accumulated other comprehensive loss.
(c) - Includes $88.9 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 our continuing and discontinued operations for the periods indicated:

		March 31, 2012				December 31, 2011
	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		21.0	(20.9	)		21.2	(23.4	)
	Swaps		18.4	(95.2	)		19.5	(111.9	)
- Crude oil and NGLs (MMBbl)	Swaps		-	(3.6	)		-	(2.9	)
Basis
- Natural gas (Bcf)	Forwards and swaps		4.1	(49.6	)		3.2	(82.8	)
Interest-rate contracts (Millions of dollars)	Forward-starting swaps	$	750.0	-		$	1,250.0	-
Fair value hedges
Basis
- Natural gas (Bcf)	Forwards and swaps		109.1	(109.1	)		76.5	(77.0	)
Derivatives not designated as hedging instruments:
Fixed price
- Natural gas (Bcf)	Exchange futures		56.7	(53.4	)		76.9	(59.6	)
	Forwards and swaps		197.3	(200.6	)		235.8	(253.4	)
	Options		146.1	(141.1	)		33.6	(14.3	)
Basis
- Natural gas (Bcf)	Forwards and swaps		184.0	(186.1	)		216.9	(219.3	)
Index
- Natural gas (Bcf)	Forwards and swaps		51.8	(22.7	)		29.3	(22.1	)

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 March 31, 2012, includes net gains of approximately $22.8 million, net of tax, related to these hedges that will be recognized within the next 21 months as the forecasted transactions affect earnings.  If prices remain at current levels, we will recognize $13.1 million in net gains over the next 12 months, and we will recognize net gains of $9.7 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 months ended March 31, 2012, net margin in Consolidated Statements of Income includes losses of $29.9 million related to certain financial contracts that were used to hedge forecasted purchases of natural gas.  As a result of the continued decline in natural gas prices, the combination of the cost basis of the forecasted purchases of inventory and the financial contracts exceed the amount expected to be recovered through sales of that inventory after considering related sales hedges, which requires reclassification of the loss from accumulated other comprehensive loss to current period earnings.

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

	Three Months Ended
Derivatives in Cash Flow Hedging Relationships	March 31,
	2012		2011
	(Thousands of dollars)
Commodity contracts	$	45,565	$	(18,303	)
Interest rate contracts		21,102		-
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	$	66,667	$	(18,303	)

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

	Location of Gain (Loss) Reclassified from	Three Months Ended
Derivatives in Cash Flow	Accumulated Other Comprehensive Income	March 31,
Hedging Relationship	(Loss) into Net Income (Effective Portion)	2012			2011
		(Thousands of dollars)
Commodity contracts	Revenues	$	62,369		$	33,387
Commodity contracts	Cost of sales and fuel		(61,977	)		(828	)
Interest-rate contracts	Interest expense		(827	)		(208	)
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)		$	(435	)	$	32,351

Ineffectiveness related to our cash flow hedges was not material for the three months ended March 31, 2012 and 2011.  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 months ended March 31, 2012 and 2011, there were no gains or losses due to the discontinuance of cash flow hedge treatment as a result of the underlying transactions being 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 our continuing and discontinued operations for the periods indicated:

		Three Months Ended
Derivatives Not Designated as		March 31,
Hedging Instruments	Location of Gain (Loss)	2012		2011
		(Thousands of dollars)
Commodity contracts - trading	Revenues	$	315	$	406
Commodity contracts - nontrading (a)	Cost of sales and fuel		2,963		2,548
Total gain recognized in income on derivatives		$	3,278	$	2,954
(a) - Amounts are presented net of deferred losses associated with derivatives entered into by our Natural Gas Distribution segment.

Our Natural Gas Distribution segment did not hold any derivative financial instruments at March 31, 2012, and held call options with premiums totaling $10 million at December 31, 2011.  The premiums are recorded in other current assets as these contracts are included in, and recoverable through, the monthly purchased-gas cost mechanism.  We recorded immaterial losses associated with the decline in the value and expiration of option contracts for the three months ended March 31, 2012 and 2011.  The gains and losses associated with these derivative instruments are deferred as part of our unrecovered purchase-gas costs.

Fair Value Hedges - 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 $0.5 million and $5.4 million for the three months ended March 31, 2012 and 2011, respectively, related to the change in fair value of derivatives designated as fair value hedges.  Revenues include losses of $1.8 million and $5.0 million for the three months ended March 31, 2012 and 2011, respectively, to recognize the change in fair value of the related hedged firm commitments.  Ineffectiveness included in cost of sales and fuel related to these hedges was immaterial for the three months ended March 31, 2012 and 2011.

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 March 31, 2012, was $6.8 million.  If the contingent features underlying these agreements were triggered on March 31, 2012, we would have been required to post an additional $6.8 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 affected similarly 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 period indicated:

	March 31, 2012
	Investment		Noninvestment		Not
	Grade		Grade		Rated		Total
Counterparty sector	(Thousands of dollars)
Gas and electric utilities	$	34,644	$	-	$	374	$	35,018
Oil and gas		11,791		3		75		11,869
Financial		24,798		-		-		24,798
Other		124		11		714		849
Total	$	71,357	$	14	$	1,163	$	72,534

	December 31, 2011
	Investment		Noninvestment		Not
	Grade		Grade		Rated		Total
Counterparty sector	(Thousands of dollars)
Gas and electric utilities	$	22,335	$	-	$	564	$	22,899
Oil and gas		9,986		5		80		10,071
Industrial		7		-		14,955		14,962
Financial		13,566		-		-		13,566
Other		100		6		-		106
Total	$	45,994	$	11	$	15,599	$	61,604

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CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

3 Months Ended

Mar. 31, 2012

CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE [Abstract]

CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

E.           CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

ONEOK 2011 Credit Agreement -The ONEOK 2011 Credit Agreement, which is scheduled to expire in April 2016, contains certain financial, operational and legal covenants.  Among other things, these covenants include maintaining ONEOK's stand-alone debt-to-capital ratio of no more than 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 from $1.2 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 March 31, 2012, ONEOK's stand-alone debt-to-capital ratio, as defined by the ONEOK 2011 Credit Agreement, was 47.1 percent, and ONEOK was in compliance with all covenants under the ONEOK 2011 Credit Agreement.  At March 31, 2012, ONEOK had $419.8 million of commercial paper outstanding and $2.0 million in letters of credit issued, leaving approximately $778.2 million of credit available under the ONEOK 2011 Credit Agreement.

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.

ONEOK Partners 2011 Credit Agreement - 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 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 increase to 5.5 to 1 for the quarter of the acquisition and the two following quarters.  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 from $1.2 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.

At March 31, 2012, ONEOK Partners' ratio of indebtedness to adjusted EBITDA was 2.6 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners 2011 Credit Agreement.  At March 31, 2012, ONEOK Partners had no commercial paper outstanding, no letters of credit issued and no borrowings under the ONEOK Partners 2011 Credit Agreement.

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.

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EQUITY

3 Months Ended

Mar. 31, 2012

EQUITY [Abstract]

EQUITY

G.           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
	March 31, 2012									March 31, 2011
	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	$	2,238,573		$	1,561,159		$	3,799,732		$	2,448,623		$	1,472,218		$	3,920,841
Net income		122,865			110,597			233,462			130,130			69,216			199,346
Other comprehensive income (loss)		27,276			13,564			40,840			(26,335	)		(15,459	)		(41,794	)
Repurchase of common stock		-			-			-			(48	)		-			(48	)
Common stock issued		2,561			-			2,561			2,365			-			2,365
Common stock dividends		(63,375	)		-			(63,375	)		(55,651	)		-			(55,651	)
Issuance of common units of ONEOK Partners		(51,100	)		510,835			459,735			-			-			-
Distributions to noncontrolling interests		-			(72,852	)		(72,852	)		-			(68,041	)		(68,041	)
Other		(20,648	)		-			(20,648	)		-			-			-
Ending balance	$	2,256,152		$	2,123,303		$	4,379,455		$	2,499,084		$	1,457,934		$	3,957,018

Stock Split - On February 15, 2012, our Board of Directors authorized a two-for-one split of our common stock, subject to shareholder approval of a proposal to increase the number of authorized shares of our common stock to 600 million from 300 million.  The proposal will be voted on at our 2012 annual meeting of shareholders on May 23, 2012.

Dividends - Fourth-quarter 2011 and first-quarter 2012 dividends paid on our common stock to shareholders of record at the close of business on January 31, 2012, and April 30, 2012, respectively, were $0.61 per share for each period.

See Note L for a discussion of the issuance of common units and distributions to noncontrolling interests.

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ONEOK PARTNERS (Tables)

3 Months Ended

Mar. 31, 2012

ONEOK PARTNERS [Abstract]

Ownership interest in ONEOK Partners

Ownership Interest in ONEOK Partners - Our ownership interest in ONEOK Partners is shown in the table below as of March 31, 2012:

General partner interest	2.0%
Limited partner interest (a)	41.4%
Total ownership interest	43.4%
(a) - Represents 19.8 million common units and approximately 73.0 million Class B units, which are convertible, at our option, into common units.

ONEOK Partners' Distributions Paid

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

	Three Months Ended
	March 31,
	2012		2011
	(Thousands, except per unit amounts)
Distribution per unit	$	0.61	$	0.57
General partner distributions	$	3,281	$	2,956
Incentive distributions		36,472		28,645
Distributions to general partner		39,753		31,601
Limited partner distributions to ONEOK		51,721		48,329
Limited partner distributions to noncontrolling interest		72,609		67,846
Total distributions paid	$	164,083	$	147,776

ONEOK Partners' Distributions Declared

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
	March 31,
	2012		2011
	(Thousands, except per unit amounts)
Distribution per unit	$	0.635	$	0.575
General partner distributions	$	3,759	$	2,996
Incentive distributions		44,610		29,624
Distributions to general partner		48,369		32,620
Limited partner distributions to ONEOK		58,921		48,753
Limited partner distributions to noncontrolling interest		80,662		68,441
Total distributions declared	$	187,952	$	149,814

ONEOK Partners' transactions

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.  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.

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COMMITMENTS AND CONTINGENCIES (Details)	Mar. 31, 2012
COMMITMENTS AND CONTINGENCIES [Abstract]
Number of former manufactured gas sites in Kansas where we own or retain legal responsibility for environmental conditions	12
Number of sites where soil remediation has begun	11
Number of sites where regulatory closure has been achieved	3
Number of sites soil remediation is completed or near completion	8
Number of years of consideration for EPA lowering threshold levels for greenhouse gas emissions	5
Number of years over which capital expenditures are expected to be required to meet administrative standards	2
Minimum percentage yield of high consequence pipeline areas	30.00%

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ONEOK PARTNERS

3 Months Ended

Mar. 31, 2012

ONEOK PARTNERS [Abstract]

ONEOK PARTNERS

L.           ONEOK PARTNERS

Unit Split - In July 2011, ONEOK Partners completed a two-for-one split of its common and Class B units, and its Partnership Agreement was amended to adjust the formula for distributing available cash among its general partner and limited partners to reflect the unit split.  As a result, all unit and per-unit amounts contained herein have been adjusted to be presented on a post-split basis.

Equity Issuance -In March 2012, ONEOK Partners completed an underwritten public offering of 8,000,000 common units at a public offering price of $59.27 per common unit, generating net proceeds of approximately $460 million.  ONEOK Partners also sold 8,000,000 common units to us in a private placement, generating net proceeds of approximately $460 million.  In conjunction with the issuances, we contributed $19.1 million in order to maintain our 2-percent general partner interest in ONEOK Partners.  ONEOK Partners used the net proceeds from the offering to repay approximately $295 million under its $1.2 billion commercial paper program, to repay amounts on the maturity of its $350 million, 5.9-percent senior notes due April 2012 and for other general partnership purposes, including capital expenditures.  As a result of these transactions, our aggregate ownership interest in ONEOK Partners increased to 43.4 percent from 42.8 percent.

We account for the difference between the carrying amount of our investment in ONEOK Partners and the underlying book value arising from issuance of common units by ONEOK Partners as an equity transaction.  As a result of ONEOK Partners’ issuance of common units, we recognized a decrease in paid-in capital of approximately $51.1 million during the three months ended March 31, 2012.

Ownership Interest in ONEOK Partners - Our ownership interest in ONEOK Partners is shown in the table below as of March 31, 2012:

General partner interest	2.0%
Limited partner interest (a)	41.4%
Total ownership interest	43.4%
(a) - Represents 19.8 million common units and approximately 73.0 million Class B units, which are convertible, at our option, into common units.

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.  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
	March 31,
	2012		2011
	(Thousands, except per unit amounts)
Distribution per unit	$	0.61	$	0.57
General partner distributions	$	3,281	$	2,956
Incentive distributions		36,472		28,645
Distributions to general partner		39,753		31,601
Limited partner distributions to ONEOK		51,721		48,329
Limited partner distributions to noncontrolling interest		72,609		67,846
Total distributions paid	$	164,083	$	147,776

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
	March 31,
	2012		2011
	(Thousands, except per unit amounts)
Distribution per unit	$	0.635	$	0.575
General partner distributions	$	3,759	$	2,996
Incentive distributions		44,610		29,624
Distributions to general partner		48,369		32,620
Limited partner distributions to ONEOK		58,921		48,753
Limited partner distributions to noncontrolling interest		80,662		68,441
Total distributions declared	$	187,952	$	149,814

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 the distributions we receive.  Distributions are declared quarterly by ONEOK Partners’ general partner based on the terms of the ONEOK Partners partnership agreement.  See Note N 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 Natural Gas 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.

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
	March 31,
	2012		2011
	(Thousands of dollars)
Revenues	$	75,705	$	96,793
Expenses
Cost of sales and fuel	$	9,275	$	10,731
Administrative and general expenses		56,361		56,295
Total expenses	$	65,636	$	67,026

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DISCONTINUED OPERATIONS (Tables)

3 Months Ended

Mar. 31, 2012

DISCONTINUED OPERATIONS [Abstract]

Discontinued Operations

The amounts of revenue, costs and income taxes reported in discontinued operations are set forth in the table below for the periods indicated:

	One Month Ended			Three Months Ended
	January 31,			March 31,
	2012			2011
	(Thousands of dollars)
Operating revenues	$	27,607			$	106,289
Cost of sales and fuel		25,961				102,617
Net margin		1,646				3,672
Operating costs		408				1,933
Depreciation, depletion and amortization		8				32
Operating income		1,230				1,707
Other income (expense), net		-				16
Income taxes		(468	)			(662	)
Income from discontinued operations, net	$	762			$	1,061
Gain on sale of discontinued operation, net of tax of $8,119	$	13,250			$	-

The following table discloses the major classes of discontinued assets and liabilities included on our Consolidated Balance Sheets for the period indicated:

		December 31,
		2011
Assets	(Thousands of dollars)
Cash and cash equivalents		$	8,859
Accounts receivable, net			47,967
Gas in storage			2,101
Energy marketing and risk management assets			15,016
Other assets			193
Assets of discontinued operations		$	74,136
Liabilities
Accounts payable		$	11,435
Energy marketing and risk management liabilities			629
Other liabilities			751
Liabilities of discontinued operations		$	12,815

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UNCONSOLIDATED AFFILIATES (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Schedule of Equity Method Investments [Line Items]
Equity earnings from investments	$ 34,620	$ 32,092
Income Statement
Operating revenues	127,924	123,301
Operating expenses	54,568	54,236
Net income	65,254	63,165
Distributions paid to us	40,941	32,511
Northern Border Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Equity earnings from investments	20,231	20,852
Overland Pass Pipeline Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity earnings from investments	5,317	4,376
Fort Union Gas Gathering, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Equity earnings from investments	4,208	2,965
Bighorn Gas Gathering L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Equity earnings from investments	1,165	1,493
Other Unconsolidated Affiliate [Member]
Schedule of Equity Method Investments [Line Items]
Equity earnings from investments	$ 3,699	$ 2,406

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RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES Part 1 (Details) (USD $)	3 Months Ended																												1 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011	Mar. 31, 2012 Cash Flow Hedging [Member] Fixed Price [Member] Natural Gas [Member] Swaps [Member] Purchasor [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Fixed Price [Member] Natural Gas [Member] Swaps [Member] Purchasor [Member]	Mar. 31, 2012 Cash Flow Hedging [Member] Fixed Price [Member] Natural Gas [Member] Swaps [Member] Sellor [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Fixed Price [Member] Natural Gas [Member] Swaps [Member] Sellor [Member]	Mar. 31, 2012 Cash Flow Hedging [Member] Fixed Price [Member] Natural Gas [Member] Exchange Futures [Member] Purchasor [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Fixed Price [Member] Natural Gas [Member] Exchange Futures [Member] Purchasor [Member]	Mar. 31, 2012 Cash Flow Hedging [Member] Fixed Price [Member] Natural Gas [Member] Exchange Futures [Member] Sellor [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Fixed Price [Member] Natural Gas [Member] Exchange Futures [Member] Sellor [Member]	Mar. 31, 2012 Cash Flow Hedging [Member] Fixed Price [Member] Crude oil and NGLs [Member] Swaps [Member] Purchasor [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Fixed Price [Member] Crude oil and NGLs [Member] Swaps [Member] Purchasor [Member]	Mar. 31, 2012 Cash Flow Hedging [Member] Fixed Price [Member] Crude oil and NGLs [Member] Swaps [Member] Sellor [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Fixed Price [Member] Crude oil and NGLs [Member] Swaps [Member] Sellor [Member]	Mar. 31, 2012 Cash Flow Hedging [Member] Basis [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Purchasor [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Basis [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Purchasor [Member]	Mar. 31, 2012 Cash Flow Hedging [Member] Basis [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Sellor [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Basis [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Sellor [Member]	Mar. 31, 2012 Cash Flow Hedging [Member] Interest Rate Contract [Member] Forward Starting Swaps [Member] Purchasor [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Interest Rate Contract [Member] Forward Starting Swaps [Member] Purchasor [Member]	Mar. 31, 2012 Cash Flow Hedging [Member] Interest Rate Contract [Member] Forward Starting Swaps [Member] Sellor [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Interest Rate Contract [Member] Forward Starting Swaps [Member] Sellor [Member]	Jan. 31, 2012 Cash Flow Hedging [Member] Oneok Inc [Member] Forward Starting Interest Rate Swap [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Oneok Inc [Member] Forward Starting Interest Rate Swap [Member]	Apr. 30, 2012 Cash Flow Hedging [Member] Oneok Partners [Member] Forward Starting Interest Rate Swap [Member]	Mar. 31, 2012 Cash Flow Hedging [Member] Oneok Partners [Member] Forward Starting Interest Rate Swap [Member]	Dec. 31, 2011 Cash Flow Hedging [Member] Oneok Partners [Member] Forward Starting Interest Rate Swap [Member]	Jan. 31, 2012 Cash Flow Hedging [Member] Notes Payables Due 2022 [Member] Forward Starting Interest Rate Swap [Member]	Mar. 31, 2012 Fair Value Hedging [Member] Basis [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Purchasor [Member]	Dec. 31, 2011 Fair Value Hedging [Member] Basis [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Purchasor [Member]	Mar. 31, 2012 Fair Value Hedging [Member] Basis [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Sellor [Member]	Dec. 31, 2011 Fair Value Hedging [Member] Basis [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Sellor [Member]	Mar. 31, 2012 Not Designated as Hedging Instrument [Member] Fixed Price [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Purchasor [Member]	Dec. 31, 2011 Not Designated as Hedging Instrument [Member] Fixed Price [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Purchasor [Member]	Mar. 31, 2012 Not Designated as Hedging Instrument [Member] Fixed Price [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Sellor [Member]	Dec. 31, 2011 Not Designated as Hedging Instrument [Member] Fixed Price [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Sellor [Member]	Mar. 31, 2012 Not Designated as Hedging Instrument [Member] Fixed Price [Member] Natural Gas [Member] Options [Member] Purchasor [Member]	Dec. 31, 2011 Not Designated as Hedging Instrument [Member] Fixed Price [Member] Natural Gas [Member] Options [Member] Purchasor [Member]	Mar. 31, 2012 Not Designated as Hedging Instrument [Member] Fixed Price [Member] Natural Gas [Member] Options [Member] Sellor [Member]	Dec. 31, 2011 Not Designated as Hedging Instrument [Member] Fixed Price [Member] Natural Gas [Member] Options [Member] Sellor [Member]	Mar. 31, 2012 Not Designated as Hedging Instrument [Member] Fixed Price [Member] Natural Gas [Member] Exchange Futures [Member] Purchasor [Member]	Dec. 31, 2011 Not Designated as Hedging Instrument [Member] Fixed Price [Member] Natural Gas [Member] Exchange Futures [Member] Purchasor [Member]	Mar. 31, 2012 Not Designated as Hedging Instrument [Member] Fixed Price [Member] Natural Gas [Member] Exchange Futures [Member] Sellor [Member]	Dec. 31, 2011 Not Designated as Hedging Instrument [Member] Fixed Price [Member] Natural Gas [Member] Exchange Futures [Member] Sellor [Member]	Mar. 31, 2012 Not Designated as Hedging Instrument [Member] Basis [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Purchasor [Member]	Dec. 31, 2011 Not Designated as Hedging Instrument [Member] Basis [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Purchasor [Member]	Mar. 31, 2012 Not Designated as Hedging Instrument [Member] Basis [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Sellor [Member]	Dec. 31, 2011 Not Designated as Hedging Instrument [Member] Basis [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Sellor [Member]	Mar. 31, 2012 Not Designated as Hedging Instrument [Member] Index [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Purchasor [Member]	Dec. 31, 2011 Not Designated as Hedging Instrument [Member] Index [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Purchasor [Member]	Mar. 31, 2012 Not Designated as Hedging Instrument [Member] Index [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Sellor [Member]	Dec. 31, 2011 Not Designated as Hedging Instrument [Member] Index [Member] Natural Gas [Member] Forward and Swaps Contracts [Member] Sellor [Member]	Mar. 31, 2012 Designated as Hedging Instrument [Member] Energy Marketing and Risk Managment Assets and Liabilities, Net [Member]	Dec. 31, 2011 Designated as Hedging Instrument [Member] Energy Marketing and Risk Managment Assets and Liabilities, Net [Member]	Mar. 31, 2012 Not Designated as Hedging Instrument [Member]	Dec. 31, 2011 Not Designated as Hedging Instrument [Member]	Mar. 31, 2012 Commodity Contract [Member] Designated as Hedging Instrument [Member] Financial Derivative Instrument [Member]	Dec. 31, 2011 Commodity Contract [Member] Designated as Hedging Instrument [Member] Financial Derivative Instrument [Member]	Mar. 31, 2012 Commodity Contract [Member] Designated as Hedging Instrument [Member] Physical Derivative Instrument [Member]	Dec. 31, 2011 Commodity Contract [Member] Designated as Hedging Instrument [Member] Physical Derivative Instrument [Member]	Mar. 31, 2012 Commodity Contract [Member] Not Designated as Hedging Instrument [Member] Financial Derivative Instrument [Member] Trading [Member]	Dec. 31, 2011 Commodity Contract [Member] Not Designated as Hedging Instrument [Member] Financial Derivative Instrument [Member] Trading [Member]	Mar. 31, 2012 Commodity Contract [Member] Not Designated as Hedging Instrument [Member] Financial Derivative Instrument [Member] Non-trading [Member]	Dec. 31, 2011 Commodity Contract [Member] Not Designated as Hedging Instrument [Member] Financial Derivative Instrument [Member] Non-trading [Member]	Mar. 31, 2012 Commodity Contract [Member] Not Designated as Hedging Instrument [Member] Physical Derivative Instrument [Member] Non-trading [Member]	Dec. 31, 2011 Commodity Contract [Member] Not Designated as Hedging Instrument [Member] Physical Derivative Instrument [Member] Non-trading [Member]	Mar. 31, 2012 Interest Rate Contracts [Member] Designated as Hedging Instrument [Member]	Dec. 31, 2011 Interest Rate Contracts [Member] Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets	$ 676,518,000		$ 630,847,000																																																			$ 147,303,000	$ 184,246,000	$ 529,215,000	$ 446,601,000	$ 146,928,000	$ 184,184,000	$ 375,000	$ 62,000	$ 156,786,000	$ 111,920,000	$ 345,662,000	$ 295,948,000	$ 26,767,000	$ 38,733,000	$ 0	$ 0
(Liabilities)	(683,715,000)		(637,241,000)																																																			(166,042,000)	(202,356,000)	(517,673,000)	(434,885,000)	(102,526,000)	(73,346,000)	(43,000)	(344,000)	(154,843,000)	(110,050,000)	(362,653,000)	(323,170,000)	(177,000)	(1,665,000)	(63,473,000)	(128,666,000)
Inventory cash flow hedges derivative assets	11,100,000		88,900,000
Inventory cash flow hedges derivative liabilities	31,600,000
Derivative [Line Items]
Derivative nonmonetary notional amount				18.4	19.5	(95.2)	(111.9)	21.0	21.2	(20.9)	(23.4)	0	0	(3.6)	(2.9)	4.1	3.2	(49.6)	(82.8)											109.1	76.5	(109.1)	(77.0)	197.3	(235.8)	(200.6)	(253.4)	146.1	33.6	(141.1)	(14.3)	56.7	76.9	(53.4)	(59.6)	184.0	216.9	(186.1)	(219.3)	51.8	29.3	(22.7)	(22.1)
Notional amount of cash flow hedge instruments																				750,000,000	1,250,000,000	0	0	200,000,000	500,000,000	250,000,000	750,000,000	750,000,000
Face Amount	350,000,000																												700,000,000
Interest rates (in hundredths)																													4.25%
Amount of loss amortized to interest expense																													44,100,000
Natural gas cash flow hedge losses	$ 29,861,000	$ 0

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Current assets
Cash and cash equivalents	$ 781,192	$ 65,953
Accounts receivable, net	1,154,951	1,339,933
Gas and natural gas liquids in storage	299,130	549,915
Commodity imbalances	163,939	63,452
Energy marketing and risk management assets (Notes C and D)	54,368	40,280
Other current assets	155,695	185,143
Assets of discontinued operations (Note B)	0	74,136
Total current assets	2,609,275	2,318,812
Property, plant and equipment	11,495,219	11,177,934
Accumulated depreciation and amortization	2,794,183	2,733,601
Net property, plant and equipment	8,701,036	8,444,333
Investments and other assets
Goodwill and intangible assets	1,001,956	1,014,127
Investments in unconsolidated affiliates (Note K)	1,219,635	1,223,398
Other assets	720,174	695,965
Total investments and other assets	2,941,765	2,933,490
Total assets	14,252,076	13,696,635
Current liabilities
Current maturities of long-term debt	364,397	364,391
Notes payable (Note E)	419,757	841,982
Accounts payable	1,110,108	1,341,718
Commodity imbalances	201,089	202,206
Energy marketing and risk management liabilities (Notes C and D)	94,573	137,680
Other current liabilities	410,399	345,383
Liabilities of discontinued operations (Note B)	0	12,815
Total current liabilities	2,600,323	3,246,175
Long-term debt, excluding current maturities (Note F)	5,225,849	4,529,551
Deferred credits and other liabilities
Deferred income taxes	1,408,420	1,446,591
Other deferred credits	638,029	674,586
Total deferred credits and other liabilities	2,046,449	2,121,177
Commitments and contingencies (Note M)
ONEOK shareholders' equity:
Common stock, $0.01 par value: authorized 300,000,000 shares; issued 122,905,591 shares and outstanding 103,922,403 shares at March 31, 2012; issued 122,904,924 shares and outstanding 103,254,980 shares at December 31, 2011	1,229	1,229
Paid-in capital	1,317,489	1,418,414
Accumulated other comprehensive loss (Note H)	(178,845)	(206,121)
Retained earnings	2,019,864	1,960,374
Treasury stock, at cost: 18,983,188 shares at March 31, 2012, and 19,649,944 shares at December 31, 2011	(903,585)	(935,323)
Total ONEOK shareholders' equity	2,256,152	2,238,573
Noncontrolling interests in consolidated subsidiaries	2,123,303	1,561,159
Total equity	4,379,455	3,799,732
Total liabilities and equity	$ 14,252,076	$ 13,696,635

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

3 Months Ended

Mar. 31, 2012

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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 2011 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 months ended March 31, 2012, 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.

Recently Issued Accounting Standards Update -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 adopted this guidance with this Quarterly Report and the impact was not material.  See Note C for information on our fair value measurements.

In June 2011, the FASB issued ASU 2011-05, "Presentation of Comprehensive Income," which provides two options for presenting items of net income, other comprehensive income and total comprehensive income by creating either one continuous statement of comprehensive income or two separate consecutive statements, and requires certain other disclosures.  In December 2011, the FASB issued ASU 2011-12, "Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05," which deferred certain presentation requirements in ASU 2011-05 for items reclassified out of accumulated other comprehensive income.  We adopted this guidance, except for the portions deferred by ASU 2011-12, with this Quarterly Report, and the impact was not material.

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FAIR VALUE MEASUREMENTS (Tables)

3 Months Ended

Mar. 31, 2012

FAIR VALUE MEASUREMENTS [Abstract]

Recurring Fair Value Measurments

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

	March 31, 2012
	Level 1			Level 2			Level 3			Netting			Total
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	601,625		$	20,271		$	27,480		$	-		$	649,376
Physical contracts		-			23,678			3,464			-			27,142
Netting		-			-			-			(603,984	)		(603,984	)
Total derivatives		601,625			43,949			30,944			(603,984	)		72,534
Trading securities (b)		6,826			-			-			-			6,826
Available-for-sale investment securities (c)		2,315			-			-			-			2,315
Total assets	$	610,766		$	43,949		$	30,944		$	(603,984	)	$	81,675
Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(595,397	)	$	(11,766	)	$	(12,859	)	$	-		$	(620,022	)
Physical contracts		-			(83	)		(137	)		-			(220	)
Netting		-			-			-			589,142			589,142
Interest-rate contracts		-			(63,473	)		-			-			(63,473	)
Total derivatives		(595,397	)		(75,322	)		(12,996	)		589,142			(94,573	)
Fair value of firm commitments (d)		-			-			(3,770	)		-			(3,770	)
Total liabilities	$	(595,397	)	$	(75,322	)	$	(16,766	)	$	589,142		$	(98,343	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk-management assets and liabilities and other assets 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 March 31, 2012, we held $15.1 million of cash collateral and had posted $0.3 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.

	December 31, 2011
	Level 1			Level 2			Level 3			Netting			Total
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	545,247		$	13,874		$	32,931		$	-		$	592,052
Physical contracts		-			23,879			14,916			-			38,795
Netting		-			-			-			(569,243	)		(569,243	)
Total derivatives		545,247			37,753			47,847			(569,243	)		61,604
Trading securities (b)		5,749			-			-			-			5,749
Available-for-sale investment securities (c)		1,949			-			-			-			1,949
Total assets	$	552,945		$	37,753		$	47,847		$	(569,243	)	$	69,302
Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(479,073	)	$	(6,498	)	$	(20,995	)	$	-		$	(506,566	)
Physical contracts		-			(261	)		(1,748	)		-			(2,009	)
Netting		-			-			-			497,608			497,608
Interest-rate contracts		-			(128,666	)		-			-			(128,666	)
Total derivatives		(479,073	)		(135,425	)		(22,743	)		497,608			(139,633	)
Fair value of firm commitments (d)		-			-			(7,283	)		-			(7,283	)
Total liabilities	$	(479,073	)	$	(135,425	)	$	(30,026	)	$	497,608		$	(146,916	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk-management assets and liabilities, other assets and other deferred credits 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, 2011, we held $73.3 million of cash collateral and had posted $1.7 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.

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation

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)
January 1, 2012	$	25,104		$	(7,283	)	$	17,821
Total realized/unrealized gains (losses):
Included in earnings (a)		(4,801	)		3,513			(1,288	)
Included in other comprehensive income (loss)		5,785			-			5,785
Sale of discontinued operations		(3,636	)		-			(3,636	)
Transfers into Level 3		-			-			-
Transfers out of Level 3		(4,504	)		-			(4,504	)
March 31, 2012	$	17,948		$	(3,770	)	$	14,178
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 March 31, 2012 (a)	$	(4,687	)	$	1,498		$	(3,189	)
(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, 2011	$	49,266		$	(29,536	)	$	19,730
Total realized/unrealized gains (losses):
Included in earnings (a)		(7,696	)		545			(7,151	)
Included in other comprehensive income (loss)		(9,855	)		-			(9,855	)
Transfers into Level 3		6			-			6
Transfers out of Level 3		(1,106	)		-			(1,106	)
March 31, 2011	$	30,615		$	(28,991	)	$	1,624
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 March 31, 2011 (a)	$	2,878		$	(4,191	)	$	(1,313	)
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.

Fair Value, unobservable inputs, quantitative information

The following table provides quantitative information about our Level 3 unobservable inputs, excluding the portion of our fair value measurements based on third-party pricing information without adjustment for the period indicated:

March 31, 2012
	Derivative Assets (Liabilities)		Fair Value of Firm Commitments			Unobservable Inputs	Valuation Process
(Thousands of dollars)
Commodity contracts (a)
Financial	$	126	$	-		Basis and Index Curves	Notional volume x Price Curve
Physical		1,355		(424	)	Basis and Index Curves	Notional volume x Price Curve
Unobservable inputs	$	1,481	$	(424	)
(a) - Unpublished basis and index curves on commodity contracts developed using broker quotes and management estimates.

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FAIR VALUE MEASUREMENTS (Details) (USD $)	Mar. 31, 2012	Dec. 31, 2011
Commodity contracts
Energy marketing and risk management assets		$ 15,016,000
Commodity contracts
Energy marketing and risk management liabilities		629,000
Cash collateral held	15,100,000	73,300,000
Cash collateral posted	300,000	1,700,000
Fair Value, Measurements, Recurring [Member]
Commodity contracts
Energy marketing and risk management assets		15,000,000
Commodity contracts
Energy marketing and risk management liabilities		600,000
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Commodity contracts
Financial contracts	601,625,000	545,247,000
Physical contracts	0	0
Netting	0	0
Total derivatives	601,625,000	545,247,000
Trading securities	6,826,000	5,749,000
Available-for-sale investment securities	2,315,000	1,949,000
Total assets	610,766,000	552,945,000
Commodity contracts
Financial contracts	(595,397,000)	(479,073,000)
Physical contracts	0	0
Netting	0	0
Interest-rate contracts	0	0
Total derivatives	(595,397,000)	(479,073,000)
Fair value of firm commitments	0	0
Total liabilities	(595,397,000)	(479,073,000)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Commodity contracts
Financial contracts	20,271,000	13,874,000
Physical contracts	23,678,000	23,879,000
Netting	0	0
Total derivatives	43,949,000	37,753,000
Trading securities	0	0
Available-for-sale investment securities	0	0
Total assets	43,949,000	37,753,000
Commodity contracts
Financial contracts	(11,766,000)	(6,498,000)
Physical contracts	(83,000)	(261,000)
Netting	0	0
Interest-rate contracts	(63,473,000)	(128,666,000)
Total derivatives	(75,322,000)	(135,425,000)
Fair value of firm commitments	0	0
Total liabilities	(75,322,000)	(135,425,000)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Commodity contracts
Financial contracts	27,480,000	32,931,000
Physical contracts	3,464,000	14,916,000
Netting	0	0
Total derivatives	30,944,000	47,847,000
Trading securities	0	0
Available-for-sale investment securities	0	0
Total assets	30,944,000	47,847,000
Commodity contracts
Financial contracts	(12,859,000)	(20,995,000)
Physical contracts	(137,000)	(1,748,000)
Netting	0	0
Interest-rate contracts	0	0
Total derivatives	(12,996,000)	(22,743,000)
Fair value of firm commitments	(3,770,000)	(7,283,000)
Total liabilities	(16,766,000)	(30,026,000)
Fair Value, Measurements, Recurring [Member] | Netting and Collateral [Member]
Commodity contracts
Financial contracts	0	0
Physical contracts	0	0
Netting	(603,984,000)	(569,243,000)
Total derivatives	(603,984,000)	(569,243,000)
Trading securities	0	0
Available-for-sale investment securities	0	0
Total assets	(603,984,000)	(569,243,000)
Commodity contracts
Financial contracts	0	0
Physical contracts	0	0
Netting	589,142,000	497,608,000
Interest-rate contracts	0	0
Total derivatives	589,142,000	497,608,000
Fair value of firm commitments	0	0
Total liabilities	589,142,000	497,608,000
Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Commodity contracts
Financial contracts	649,376,000	592,052,000
Physical contracts	27,142,000	38,795,000
Netting	(603,984,000)	(569,243,000)
Total derivatives	72,534,000	61,604,000
Trading securities	6,826,000	5,749,000
Available-for-sale investment securities	2,315,000	1,949,000
Total assets	81,675,000	69,302,000
Commodity contracts
Financial contracts	(620,022,000)	(506,566,000)
Physical contracts	(220,000)	(2,009,000)
Netting	589,142,000	497,608,000
Interest-rate contracts	(63,473,000)	(128,666,000)
Total derivatives	(94,573,000)	(139,633,000)
Fair value of firm commitments	(3,770,000)	(7,283,000)
Total liabilities	$ (98,343,000)	$ (146,916,000)

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UNCONSOLIDATED AFFILIATES

3 Months Ended

Mar. 31, 2012

UNCONSOLIDATED AFFILIATES [Abstract]

UNCONSOLIDATED AFFILIATES

K.           UNCONSOLIDATED AFFILIATES

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
	March 31,
	2012		2011
	(Thousands of dollars)
Northern Border Pipeline Company	$	20,231	$	20,852
Overland Pass Pipeline		5,317		4,376
Fort Union Gas Gathering		4,208		2,965
Bighorn Gas Gathering		1,165		1,493
Other		3,699		2,406
Equity earnings from investments	$	34,620	$	32,092

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

	Three Months Ended
	March 31,
	2012		2011
	(Thousands of dollars)
Income Statement
Operating revenues	$	127,924	$	123,301
Operating expenses	$	54,568	$	54,236
Net income	$	65,254	$	63,165
Distributions paid to us	$	40,941	$	32,511