ONEOK (OKE) 10-Q 2010 Q1 Quarterly report

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, 2010

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 Web site, if any, every

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

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

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

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

Yes __ No X

On April 22, 2010, the Company had 106,295,263 shares of common stock outstanding.

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, 2010 and 2009	5
	Consolidated Balance Sheets - March 31, 2010 and December 31, 2009	6-7
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2010 and 2009	9
	Consolidated Statement of Shareholders’ Equity - Three Months Ended March 31, 2010	10-11
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2010 and 2009	12
	Notes to Consolidated Financial Statements	13-30
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31-50
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50-51
Item 4.	Controls and Procedures	51
Part II.	Other Information
Item 1.	Legal Proceedings	52
Item 1A.	Risk Factors	52
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	53
Item 3.	Defaults Upon Senior Securities	53
Item 4.	(Removed and Reserved)	53
Item 5.	Other Information	53
Item 6.	Exhibits	54
Signature		55

As used in this Quarterly Report, references to “we,” “our” or “us” refer to ONEOK, Inc., an Oklahoma corporation, and its predecessors and subsidiaries, unless the context indicates otherwise.

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

INFORMATION AVAILABLE ON OUR WEB SITE

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

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

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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, 2009

ASU................................................................... Accounting Standards Update

Bbl...................................................................... Barrels, one barrel is equivalent to 42 United States gallons

Bbl/d.................................................................. Barrels per day

BBtu/d............................................................... Billion British thermal units per day

Bcf..................................................................... Billion cubic feet

Bcf/d.................................................................. Billion cubic feet per day

Btu(s)................................................................ British thermal units, a measure of the amount of heat required to raise the  temperature of one pound of water one degree Fahrenheit

Bushton Plant.................................................. Bushton Gas Processing Plant

Clean Air Act................................................... Federal Clean Air Act, as amended

Clean Water Act.............................................. Federal Water Pollution Control Act Amendments of 1972, as amended

EBITDA............................................................ Earnings before interest, taxes, depreciation and amortization

EPA................................................................... United States Environmental Protection Agency

Exchange Act................................................... Securities Exchange Act of 1934, as amended

FASB................................................................. Financial Accounting Standards Board

FERC................................................................. Federal Energy Regulatory Commission

GAAP................................................................ Accounting principles generally accepted in the United States of America

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

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.

NGL products.................................................. Marketable natural gas liquid purity products, such as ethane, ethane/propane mix,   propane, iso-butane, normal butane and natural gasoline

NGL(s)............................................................... Natural gas liquid(s)

Northern Border Pipeline............................... Northern Border Pipeline Company

NYMEX............................................................ New York Mercantile Exchange

OBPI.................................................................. ONEOK Bushton Processing Inc.

OCC................................................................... Oklahoma Corporation Commission

ONEOK............................................................. ONEOK, Inc.

ONEOK Credit Agreement............................. ONEOK’s $1.2 billion Amended and Restated Credit Agreement dated July 14,  2006

ONEOK Partners............................................. ONEOK Partners, L.P.

ONEOK Partners Credit Agreement............. ONEOK Partners’ $1.0 billion Amended and Restated Revolving Credit  Agreement dated March 30, 2007

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

OPIS.................................................................. Oil Price Information Service

Overland Pass Pipeline Company................. Overland Pass Pipeline Company LLC

Quarterly Report(s)......................................... Quarterly Report(s) on Form 10-Q

S&P................................................................... Standard & Poor’s Rating Group

SEC.................................................................... Securities and Exchange Commission

Securities Act.................................................. Securities Act of 1933, as amended

XBRL................................................................. eXtensible Business Reporting Language

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PART I - FINANCIAL INFORMATION
ITEM 1.  FINANCIAL STATEMENTS
ONEOK, Inc. and Subsidiaries
CONSOLIDATED  STATEMENTS OF INCOME
	Three Months Ended
	March 31,
(Unaudited)	2010			2009
	(Thousands of dollars, except per share amounts)
Revenues	$	3,923,967		$	2,789,827
Cost of sales and fuel		3,304,648			2,238,416
Net margin		619,319			551,411
Operating expenses
Operations and maintenance		180,272			161,719
Depreciation and amortization		77,856			72,126
General taxes		23,073			25,227
Total operating expenses		281,201			259,072
Gain (loss) on sale of assets		(786	)		664
Operating income		337,332			293,003
Equity earnings from investments (Note J)		21,116			21,222
Allowance for equity funds used during construction		247			9,003
Other income		2,909			1,665
Other expense		(1,053	)		(3,944	)
Interest expense		(76,520	)		(77,961	)
Income before income taxes		284,031			242,988
Income taxes		(97,311	)		(79,439	)
Net income		186,720			163,549
Less: Net income attributable to noncontrolling interests		32,181			41,264
Net income attributable to ONEOK	$	154,539		$	122,285
Earnings per share of common stock (Note K)
Net earnings per share, basic	$	1.46		$	1.16
Net earnings per share, diluted	$	1.44		$	1.16
Average shares of common stock (thousands)
Basic		106,132			105,162
Diluted		107,410			105,733
Dividends declared per share of common stock	$	0.44		$	0.40
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	March 31,		December 31,
(Unaudited)	2010		2009
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	167,433	$	29,399
Accounts receivable, net		1,202,293		1,437,994
Gas and natural gas liquids in storage		397,254		583,127
Commodity imbalances		96,487		186,015
Energy marketing and risk management assets (Notes B and C)		156,086		113,039
Other current assets		89,175		238,890
Total current assets		2,108,728		2,588,464
Property, plant and equipment
Property, plant and equipment		10,205,835		10,145,800
Accumulated depreciation and amortization		2,411,431		2,352,142
Net property, plant and equipment		7,794,404		7,793,658
Investments and other assets
Goodwill and intangible assets		1,028,643		1,030,560
Energy marketing and risk management assets (Notes B and C)		22,547		23,125
Investments in unconsolidated affiliates		762,435		765,163
Other assets		612,435		626,713
Total investments and other assets		2,426,060		2,445,561
Total assets	$	12,329,192	$	12,827,683
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	March 31,			December 31,
(Unaudited)	2010			2009
Liabilities and shareholders' equity	(Thousands of dollars)
Current liabilities
Current maturities of long-term debt	$	493,220		$	268,215
Notes payable (Note E)		310,000			881,870
Accounts payable		965,015			1,240,207
Commodity imbalances		246,540			394,971
Energy marketing and risk management liabilities (Notes B and C)		75,119			65,162
Other current liabilities		581,622			488,487
Total current liabilities		2,671,516			3,338,912
Long-term debt, excluding current maturities		4,103,333			4,334,204
Deferred credits and other liabilities
Deferred income taxes		1,033,396			1,037,665
Energy marketing and risk management liabilities (Notes B and C)		13,115			8,926
Other deferred credits		628,191			662,514
Total deferred credits and other liabilities		1,674,702			1,709,105
Commitments and contingencies (Note H)
Shareholders' equity (Note F)
ONEOK shareholders' equity:
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 122,545,085 shares and outstanding
106,283,759 shares at March 31, 2010; issued 122,394,015 shares and
outstanding 105,906,776 shares at December 31, 2009		1,225			1,224
Paid-in capital		1,365,591			1,322,340
Accumulated other comprehensive loss (Note D)		(105,564	)		(118,613	)
Retained earnings		1,793,548			1,685,710
Treasury stock, at cost: 16,261,326 shares at March 31, 2010 and
16,487,239 shares at December 31, 2009		(674,103	)		(683,467	)
Total ONEOK shareholders' equity		2,380,697			2,207,194
Noncontrolling interests in consolidated subsidiaries		1,498,944			1,238,268
Total shareholders' equity		3,879,641			3,445,462
Total liabilities and shareholders' equity	$	12,329,192		$	12,827,683
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)		2010			2009
	(Thousands of dollars)
Operating activities
Net income		$	186,720		$	163,549
Depreciation and amortization			77,856			72,126
Allowance for equity funds used during construction			(247	)		(9,003	)
Loss (gain) on sale of assets			786			(664	)
Equity earnings from investments			(21,116	)		(21,222	)
Distributions received from unconsolidated affiliates			21,998			25,187
Deferred income taxes			19,542			23,624
Share-based compensation expense			4,566			4,173
Allowance for doubtful accounts			(221	)		(822	)
Changes in assets and liabilities:
Accounts receivable			235,922			251,980
Gas and natural gas liquids in storage			177,305			404,416
Accounts payable			(268,987	)		(311,252	)
Commodity imbalances, net			(58,903	)		(51,317	)
Unrecovered purchased gas costs			98,783			42,445
Accrued interest			43,133			38,623
Energy marketing and risk management assets and liabilities			24,522			(32,921	)
Fair value of firm commitments			(23,023	)		153,391
Other assets and liabilities			40,081			38,545
Cash provided by operating activities			558,717			790,858
Investing activities
Changes in investments in unconsolidated affiliates			1,334			3,362
Capital expenditures (less allowance for equity funds used during construction)			(68,273	)		(243,027	)
Proceeds from sale of assets			563			1,083
Cash used in investing activities			(66,376	)		(238,582	)
Financing activities
Repayment of notes payable, net			(571,870	)		(813,300	)
Repayment of notes payable with maturities over 90 days			-			(470,000	)
Issuance of debt, net of discounts			-			498,325
Long-term debt financing costs			-			(4,000	)
Repayment of debt			(3,333	)		(104,037	)
Repurchase of common stock			(5	)		(247	)
Issuance of common stock			4,663			2,509
Issuance of common units of ONEOK Partners, net of discounts			322,721			-
Dividends paid			(46,701	)		(42,080	)
Distributions to noncontrolling interests			(59,782	)		(52,751	)
Cash used in financing activities			(354,307	)		(985,581	)
Change in cash and cash equivalents			138,034			(433,305	)
Cash and cash equivalents at beginning of period			29,399			510,058
Cash and cash equivalents at end of period		$	167,433		$	76,753
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
	ONEOK Shareholders' Equity
									Accumulated
	Common								Other
	Stock			Common		Paid-in			Comprehensive
(Unaudited)	Issued			Stock		Capital			Income (Loss)
	(Shares)		(Thousands of dollars)
December 31, 2009		122,394,015		$	1,224	$	1,322,340		$	(118,613	)
Net income		-			-		-			-
Other comprehensive income		-			-		-			13,049
Repurchase of common stock		-			-		-			-
Common stock issued		151,070			1		(7,480	)		-
Common stock dividends -
$0.44 per share		-			-		-			-
Issuance of common units of ONEOK Partners		-			-		50,731			-
Distributions to noncontrolling interests		-			-		-			-
March 31, 2010		122,545,085		$	1,225	$	1,365,591		$	(105,564	)
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(Continued)
	ONEOK Shareholders' Equity
								Noncontrolling
								Interests in			Total
		Retained			Treasury			Consolidated			Shareholders'
(Unaudited)		Earnings			Stock			Subsidiaries			Equity
	(Thousands of dollars)
December 31, 2009		$	1,685,710		$	(683,467	)	$	1,238,268		$	3,445,462
Net income			154,539			-			32,181			186,720
Other comprehensive income			-			-			16,287			29,336
Repurchase of common stock			-			(5	)		-			(5	)
Common stock issued			-			9,369			-			1,890
Common stock dividends -
$0.44 per share			(46,701	)		-			-			(46,701	)
Issuance of common units of ONEOK Partners			-			-			271,990			322,721
Distributions to noncontrolling interests			-			-			(59,782	)		(59,782	)
March 31, 2010		$	1,793,548		$	(674,103	)	$	1,498,944		$	3,879,641

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	Three Months Ended
	March 31,
(Unaudited)	2010			2009
	(Thousands of dollars)
Net income	$	186,720		$	163,549
Other comprehensive income (loss), net of tax
Unrealized gains on energy marketing and risk management
assets/liabilities, net of tax of $(18,839) and $(38,232), respectively		43,489			60,497
Realized gains in net income, net of tax of $8,022 and
$27,678, respectively		(10,058	)		(53,919	)
Unrealized holding gains (losses) on available-for-sale securities,
net of tax of $62 and $(118), respectively		(97	)		188
Change in pension and postretirement benefit plan liability, net of tax
of $2,533 and $1,599, respectively		(4,016	)		(2,534	)
Other, net of tax of $(11) and $(51), respectively		18			190
Total other comprehensive income, net of tax		29,336			4,422
Comprehensive income		216,056			167,971
Less: Comprehensive income attributable to noncontrolling interests		48,468			31,222
Comprehensive income attributable to ONEOK	$	167,588		$	136,749
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

A.           SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our accompanying unaudited consolidated financial statements have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair presentation of the results for the interim periods presented.  All such adjustments are of a normal recurring nature.  The 2009 year-end consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP.  These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements in our Annual Report.  Due to the seasonal nature of our business, the results of operations for the three months ended March 31, 2010, 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 Updates

The following recently issued accounting standards updates affect our consolidated financial statements and related disclosures:

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

Our policy for calculating transfers between levels of the fair value hierarchy recognizes the transfer as of the end of each reporting period.  Prior to January 1, 2010, our policy of calculating transfers recognized transfers in at the end of the reporting period and transfers out at the beginning of the reporting period.  Therefore, transfers into and out of Level 3 and included in earnings may not be comparable with prior periods.

Embedded Credit Derivatives - In March 2010, the FASB issued ASU 2010-11, “Scope Exception Related to Embedded Credit Derivatives,” which clarified that disclosures required for credit derivatives do not apply to an embedded derivative’s feature related to the transfer of credit risk that is only in the form of subordination of one financial instrument to another.  This guidance will be effective for our September 30, 2010, Quarterly Report and will be applied prospectively.  We are currently reviewing the applicability of ASU 2010-11 to our consolidated financial statement and related disclosures.

B.           FAIR VALUE MEASUREMENTS

Determining Fair Value - We define fair value as the price that would be received from the sale of an asset or the transfer of a liability in an orderly transaction between market participants at the measurement date.  We use the market and income approaches to determine the fair value of our assets and liabilities and consider the markets in which the transactions are executed.  While many of the contracts in our portfolio are executed in liquid markets where price transparency exists, some contracts are executed in markets for which market prices may exist but the market may be relatively inactive.  This results in limited price transparency that requires management’s judgment and assumptions to estimate fair values.  Inputs into our fair value estimates include commodity exchange prices, over-the-counter quotes, volatility, historical correlations of pricing data and LIBOR and other liquid money market instrument rates.  We also utilize internally developed basis curves that incorporate observable and unobservable market data.  We validate our valuation inputs with third-party information and 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

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and U.S. Treasury swaps.  We also take into consideration the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions.  We consider current market data in evaluating counterparties’, as well as our own, nonperformance risk, net of collateral, by using specific and sector bond yields and also monitoring the credit default swap markets.  Although we use our best estimates to determine the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ from our estimates, and the differences could be material.

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

	March 31, 2010
	Level 1			Level 2			Level 3			Netting			Total
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity Contracts
Exchange-traded contracts	$	134,991		$	-		$	-		$	-		$	134,991
Over-the-counter financial contracts		-			62,962			518,619			-			581,581
Physical contracts		-			12,734			52,007			-			64,741
Foreign Exchange Contracts		73			-			-			-			73
Netting		-			-			-			(602,753	)		(602,753	)
Total derivatives		135,064			75,696			570,626			(602,753	)		178,633
Trading securities (b)		7,458			-			-			-			7,458
Available-for-sale investment securities (c)		2,529			-			-			-			2,529
Total assets	$	145,051		$	75,696		$	570,626		$	(602,753	)	$	188,620
Liabilities
Derivatives (a)
Commodity Contracts
Exchange-traded contracts	$	(140,926	)	$	-		$	-		$	-		$	(140,926	)
Over-the-counter financial contracts		-			(56,685	)		(401,329	)		-			(458,014	)
Physical contracts		-			(4,423	)		(21,724	)		-			(26,147	)
Netting		-			-			-			536,853			536,853
Total derivatives		(140,926	)		(61,108	)		(423,053	)		536,853			(88,234	)
Fair value of firm commitments (d)		-			-			(111,597	)		-			(111,597	)
Total liabilities	$	(140,926	)	$	(61,108	)	$	(534,650	)	$	536,853		$	(199,831	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk management assets and liabilities on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At March 31, 2010, we held $70.5 million of cash collateral and had posted $4.6 million of cash collateral with various counterparties.
(b) - Our trading securities are presented in our Consolidated Balance Sheets as other current assets.
(c) - Our available-for-sale investment securities are presented in our Consolidated Balance Sheets as other assets.
(d) - Our fair value of firm commitments are presented in our Consolidated Balance Sheets as other current liabilities and other deferred credits.

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	December 31, 2009
	Level 1			Level 2			Level 3			Netting			Total
	(Thousands of dollars)
Assets
Derivatives (a)	$	149,034		$	4,898		$	672,631		$	(690,399	)	$	136,164
Trading securities (b)		7,927			-			-			-			7,927
Available-for-sale investment securities (c)		2,688			-			-			-			2,688
Total assets	$	159,649		$	4,898		$	672,631		$	(690,399	)	$	146,779
Liabilities
Derivatives (a)	$	(109,713	)	$	(8,481	)	$	(535,937	)	$	580,043		$	(74,088	)
Fair value of firm commitments (d)		-			-			(134,620	)		-			(134,620	)
Total liabilities	$	(109,713	)	$	(8,481	)	$	(670,557	)	$	580,043		$	(208,708	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk management assets and liabilities on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2009, we held $136.5 million of cash collateral and had posted $26.1 million of cash collateral with various counterparties.
(b) - Our trading securities are presented in our Consolidated Balance Sheets as other current assets.
(c) - Our available-for-sale investment securities are presented in our Consolidated Balance Sheets as other assets.
(d) - Our fair value of firm commitments are presented in our Consolidated Balance Sheets as other current liabilities and other deferred credits.

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

Our Level 1 fair value measurements are based on NYMEX-settled prices, actively quoted prices for equity securities and foreign currency forward exchange rates.  These balances are predominantly comprised 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 and foreign currency forwards.

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

For the three months ended March 31, 2010, there were no transfers between levels 1 and 2.

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

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

	Derivative Assets (Liabilities)			Fair Value of Firm Commitments			Total
	(Thousands of dollars)
January 1, 2010	$	136,694		$	(134,620	)	$	2,074
Total realized/unrealized gains (losses):
Included in earnings (a)		(4,496	)		23,023			18,527
Included in other comprehensive income (loss)		13,222			-			13,222
Transfers into Level 3		1,468			-			1,468
Transfers out of Level 3		685			-			685
March 31, 2010	$	147,573		$	(111,597	)	$	35,976
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, 2010 (a)	$	18,458		$	(7,046	)	$	11,412
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.

	Derivative Assets (Liabilities)				Fair Value of Firm Commitments				Long-Term Debt				Total
	(Thousands of dollars)
January 1, 2009	$	42,355			$	42,179			$	(171,455	)		$	(86,921	)
Total realized/unrealized gains (losses):
Included in earnings		110,002		(a)		(153,391	)	(a)		1,455		(b)		(41,934	)
Included in other comprehensive income (loss)		(7,730	)			-				-				(7,730	)
Maturities		-				-				100,000				100,000
Terminations prior to maturity		-				-				70,000				70,000
Transfers in and/or out of Level 3		25,611				-				-				25,611
March 31, 2009	$	170,238			$	(111,212	)		$	-			$	59,026
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, 2009 (a)	$	136,563			$	(138,637	)		$	-			$	(2,074	)
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.
(b) - Reported in interest expense 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 and fixed-rate debt swapped to a floating rate.  Maturities represent the long-term debt associated with an interest-rate swap that matured during the period.  Terminations prior to maturity represent the long-term debt associated with an interest-rate swap that was terminated during the period.  Transfers into Level 3 represent existing assets or liabilities that were previously categorized at a higher level for which the unobservable inputs became a more significant portion of the fair value estimates.  Transfers out of Level 3 represent existing assets and liabilities that were previously classified as Level 3 for which the observable inputs became a more significant portion of the fair value estimates.

Other Financial Instruments -The approximate fair value of cash and cash equivalents, accounts receivable and accounts payable is equal to book value, due to the short-term nature of these items.  The fair value of notes payable approximates the carrying value since the interest rates, prescribed by each borrowing’s respective credit agreement, are periodically adjusted to reflect current market conditions.

The estimated fair value of long-term debt, including current maturities, was $4.9 billion at March 31, 2010, and $4.8 billion at December 31, 2009.  The book value of long-term debt, including current maturities, was $4.6 billion at March 31, 2010, and $4.6 billion at December 31, 2009.  The estimated fair value of long-term debt has been determined using quoted market prices of the same or similar issues with similar terms and maturities.

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C.           RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

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

·   Commodity price risk - We are exposed to the risk of loss in cash flows and future earnings arising from adverse changes in the price of natural gas, NGLs and crude oil.  We use commodity derivative instruments such as futures, physical forward contracts, swaps and options to mitigate 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;

·   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 gas at a pipeline receipt point and sell gas at a pipeline delivery point.  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; and

·   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 U.S. 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 U.S. dollars for Canadian dollars with another party.

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 or crude oil at a specified price, requiring delivery on or settlement through the sale or purchase of an offsetting contract by a specified future date under the provisions of exchange regulations;

·   Forward contracts - Commitments to purchase or sell natural gas, crude oil or NGLs for delivery at some specified time in the future.  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 non-exchange traded;

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

·   reducing our exposure to fluctuations in foreign currency exchange rates.

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

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We are also subject to fluctuation in interest rates.  We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps.  Interest-rate swaps are agreements to exchange an interest payment at some future point based on the differential between two interest rates.

Accounting Treatment

We record derivative instruments at fair value, with the exception of normal purchases and normal sales that are expected to result in physical delivery.  The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a 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 non-trading derivative transactions, which are economic hedges of our accrual transactions, such as our storage and transportation contracts, do not qualify for hedge accounting treatment.

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

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

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

We formally document all relationships between hedging instruments and hedged items, as well as risk management objectives, strategies for undertaking various hedge transactions and methods for assessing and testing correlation and hedge ineffectiveness.  We specifically identify the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item.  We assess the effectiveness of hedging relationships quarterly by performing a regression 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 which 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 non-derivative 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 Consolidated Statements of Cash Flows category as the cash flows from the related hedged items.

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Fair Values of Derivative Instruments

See Note B for a discussion of the inputs associated with our fair value measurements.

The following table sets forth the fair values of our derivative instruments for the periods indicated:

	March 31, 2010						December 31, 2009
	Fair Values of Derivatives (a)						Fair Values of Derivatives (a)
	Assets			(Liabilities)			Assets			(Liabilities)
	(Thousands of dollars)
Derivatives designated as hedging instruments
Energy Services - fair value hedges	$	156,762		$	(45,178	)	$	197,037		$	(59,731	)
Energy Services - cash flow hedges		68,437	(b)		(40,377	)		115,215	(c)		(53,265	)
ONEOK Partners - cash flow hedges		21,483			(10,198	)		459			(18,772	)
Total derivatives designated as hedging instruments		246,682			(95,753	)		312,711			(131,768	)
Derivatives not designated as hedging instruments
Commodity contracts
Non-trading instruments
Natural gas
Exchange-traded contracts		2,586			(24,183	)		24,692			(20,657	)
Over-the-counter financial contracts		368,439			(382,695	)		382,783			(427,057	)
Physical contracts		63,713			(25,868	)		46,598			(16,234	)
Trading instruments
Natural gas
Exchange-traded contracts		26,953			(16,447	)		15,151			(16,153	)
Over-the-counter financial contracts		72,940			(80,141	)		44,600			(42,181	)
Total commodity contracts		534,631			(529,334	)		513,824			(522,282	)
Energy Services - foreign exchange contracts		73			-			28			(81	)
Total derivatives not designated as hedging instruments		534,704			(529,334	)		513,852			(522,363	)
Total derivatives	$	781,386		$	(625,087	)	$	826,563		$	(654,131	)
(a) - Included on a net basis in energy marketing and risk management assets and liabilities on our Consolidated Balance Sheets.
(b) - Includes $11.3 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.
(c) - Includes $37.7 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 the periods indicated:

		March 31, 2010					December 31, 2009
	Contract Type	Purchased/ Payor		Sold/ Receiver			Purchased/ Payor		Sold/ Receiver
Derivatives designated as hedging instruments:
Cash flow hedges
Fixed price
- Natural gas (Bcf)	Exchange futures		2.8		(9.6	)		6.4		(20.7	)
	Swaps		14.5		(49.5	)		18.1		(80.7	)
- Crude oil and NGLs (MMBbl)	Swaps		-		(2.4	)		-		(2.4	)
Basis
- Natural gas (Bcf)	Forwards and swaps		16.3		(55.3	)		23.7		(99.6	)
Fair value hedges
Basis
- Natural gas (Bcf)	Forwards and swaps		166.8		(166.8	)		210.4		(210.4	)
Derivatives not designated as hedging instruments:
Fixed price
- Natural gas (Bcf)	Exchange futures		27.3		(20.9	)		38.8		(22.7	)
	Forwards and swaps		96.0		(106.9	)		100.6		(117.4	)
	Options		67.5		(44.2	)		102.6		(80.6	)
- Foreign currency (Millions of dollars)	Swaps	$	2.6	$	-		$	4.6	$	-
Basis
- Natural gas (Bcf)	Forwards and swaps		868.8		(869.8	)		940.7		(947.1	)
Index
- Natural gas (Bcf)	Forwards and swaps		63.7		(13.6	)		66.4		(33.1	)

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, 2010, includes gains of approximately $13.2 million, net of tax, related to these hedges that will be realized within the next 21 months as the forecasted transactions affect earnings.  If prices remain at current levels, we will recognize $11.6 million in net gains over the next 12 months, and we will recognize net gains of $1.6 million thereafter.

For the three months ended March 31, 2010 and 2009, cost of sales and fuel in our Consolidated Statements of Income includes $11.3 million in each period, reflecting an adjustment to inventory at the lower of cost or market value.  In each period, we reclassified $11.3 million of deferred gains, before income taxes, on associated cash flow hedges from accumulated other comprehensive income (loss) into 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,
	2010		2009
	(Thousands of dollars)
Commodity contracts	$	62,328	$	98,608
Interest rate contracts		-		121
Total gain recognized in other comprehensive    income (loss) on derivatives (effective portion)	$	62,328	$	98,729

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

	Location of Gain (Loss) Reclassified from	Three Months Ended
Derivatives in Cash Flow Hedging Relationships	Accumulated Other Comprehensive Income	March 31,
	(Loss) into Net Income (Effective Portion)	2010			2009
		(Thousands of dollars)
Commodity contracts	Revenues	$	29,956		$	82,715
Commodity contracts	Cost of sales and fuel		(12,097	)		(1,554	)
Interest rate contracts	Interest expense		221			436
Total gain (loss) reclassified from accumulated other comprehensive    income (loss) into net income on derivatives (effective portion)		$	18,080		$	81,597

	Location of Gain (Loss) Recognized in Income on	Three Months Ended
Derivatives in Cash Flow Hedging Relationships	Derivatives (Ineffective Portion and Amount	March 31,
	Excluded from Effectiveness Testing)	2010			2009
		(Thousands of dollars)
Commodity contracts	Revenues	$	1,016		$	3,048
Commodity contracts	Cost of sales and fuel		(877	)		(530	)
Total gain (loss) recognized in income on derivatives (ineffective    portion and amount excluded from effectiveness testing)		$	139		$	2,518

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, 2010 and 2009, there were no gains or losses due to the discontinuance of cash flow hedge treatment since the underlying transactions were no longer probable.

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

		Three Months Ended
Derivatives Not Designated as Hedging Instruments	Location of Gain	March 31,
		2010			2009
		(Thousands of dollars)
Commodity contracts - trading	Revenues	$	2,028		$	3,305
Commodity contracts - non-trading (a)	Cost of gas and fuel		(41	)		(539	)
Foreign exchange contracts	Revenues		59			(262	)
Total gain recognized in income on derivatives		$	2,046		$	2,504
(a) - For the three months ended March 31, 2010 and 2009, we recognized $3.9 million and $2.1 million, respectively, of losses associated with the fair value of derivative instruments entered into by our Distribution segment that were deferred as they are included in, and recoverable through, the monthly purchased-gas cost mechanism.

Fair Value Hedges - In prior years, we terminated various interest-rate swap agreements.  The net savings from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged.  Interest expense savings from the amortization of terminated swaps for the three months ended March 31, 2010 and 2009, were $2.5 million and $2.6 million, respectively.  The remaining amortization of terminated swaps will be recognized over the following periods:

			ONEOK
	ONEOK		Partners		Total
	(Millions of dollars)
Remainder of 2010	$	4.8	$	2.8	$	7.6
2011	$	3.4	$	0.9	$	4.3
2012	$	1.7	$	-	$	1.7
2013	$	1.7	$	-	$	1.7
2014	$	1.7	$	-	$	1.7
Thereafter	$	23.6	$	-	$	23.6

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ONEOK and ONEOK Partners had no interest-rate swap agreements at March 31, 2010.

Our Energy Services segment uses basis swaps to hedge the fair value of location price differentials related to certain firm transportation commitments.  Net gains or losses from the fair value hedges and ineffectiveness are recorded to cost of sales and fuel.  The ineffectiveness related to these hedges included gains of $1.3 million and losses of $0.8 million for the three months ended March 31, 2010 and 2009, respectively.

For the three months ended March 31, 2010, cost of sales and fuel in our Consolidated Statements of Income includes gains of $10.8 million related to the change in fair value of derivatives declared as fair value hedges.  Revenues include losses of $9.6 million for the three months ended March 31, 2010, to recognize the change in fair value of the hedged firm commitments.

Credit Risk - We monitor the creditworthiness of our counterparties and compliance with management’s risk tolerance as determined 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, 2010, was $14.0 million for which we have posted collateral of $4.6 million in the normal course of business.  If the contingent features underlying these agreements were triggered on March 31, 2010, we would have been required to post an additional $9.4 million of collateral to our counterparties.

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

The following table sets forth the net credit exposure from our derivative assets for the period indicated:

	March 31, 2010								December 31, 2009
	Investment		Non-investment		Not				Investment		Non-investment		Not
	Grade		Grade		Rated		Total		Grade		Grade		Rated		Total
Counterparty sector	(Thousands of dollars)
Gas and electric utilities	$	49,961	$	2,803	$	3,142	$	55,906	$	26,964	$	2,668	$	7,972	$	37,604
Oil and gas		62,115		-		1,825		63,940		54,578		224		10,084		64,886
Industrial		2		-		7,210		7,212		689		-		3		692
Financial		51,524		-		15		51,539		32,880		-		7		32,887
Other		-		23		13		36		-		55		40		95
Total	$	163,602	$	2,826	$	12,205	$	178,633	$	115,111	$	2,947	$	18,106	$	136,164

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D.           ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

	Unrealized Gains (Losses) on Energy Marketing and Risk Management Assets/Liabilities		Unrealized Holding Gains (Losses) on Investment Securities	Pension and Postretirement Benefit Plan Obligations		Accumulated Other Comprehensive Income (Loss)
		(Thousands of dollars)
December 31, 2009	$	(6,151)	$1,441	$	(113,903)	$(118,613)
Other comprehensive income (loss)    attributable to ONEOK		17,162	(97)		(4,016)	13,049
March 31, 2010	$	11,011	$1,344	$	(117,919)	$(105,564)

E.           CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

ONEOK Credit Agreement - Under the ONEOK Credit Agreement, which expires July 2011, ONEOK is required to comply with certain financial, operational and legal covenants.  Among other things, these requirements include:

·   a $400 million sublimit for the issuance of standby letters of credit;

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

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

·   a limit on new investments in master limited partnerships.

The ONEOK 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 prevents ONEOK from restricting its subsidiaries’ ability to pay dividends.

The debt covenant calculations in the ONEOK Credit Agreement exclude the debt of ONEOK Partners.  Upon breach of any covenant by ONEOK, amounts outstanding under the ONEOK Credit Agreement may become immediately due and payable.  At March 31, 2010, ONEOK’s stand-alone debt-to-capital ratio, as defined by the ONEOK Credit Agreement, was 38.5 percent, and ONEOK was in compliance with all covenants under the ONEOK Credit Agreement.

At March 31, 2010, ONEOK had no commercial paper outstanding and $37.0 million in letters of credit issued under the ONEOK Credit Agreement, leaving approximately $1.2 billion of credit available under the ONEOK Credit Agreement.  At December 31, 2009, ONEOK had $358.9 million in commercial paper outstanding and $37.0 million in letters of credit issued under the ONEOK Credit Agreement, leaving $804.1 million of credit available under the ONEOK Credit Agreement.

ONEOK had no outstanding short-term debt at March 31, 2010.  The average interest rate on ONEOK’s commercial paper outstanding at December 31, 2009, was 0.30 percent.

ONEOK Partners Credit Agreement - Under the ONEOK Partners Credit Agreement, which expires March 2012, ONEOK Partners is required to comply with certain financial, operational and legal covenants.  Among other things, these requirements include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in the ONEOK Partners Credit Agreement, adjusted for all non-cash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5 to 1.  If ONEOK Partners consummates one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will be increased to 5.5 to 1 for the three calendar quarters following the acquisitions.  Upon breach of any covenant, discussed above, amounts outstanding under the ONEOK Partners Credit Agreement may become immediately due and payable.  At March 31, 2010, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 4.3 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement.  Borrowings under the ONEOK Partners Credit Agreement are nonrecourse to ONEOK.

At March 31, 2010, and December 31, 2009, ONEOK Partners had $310 million and $523 million, respectively, in borrowings outstanding under the ONEOK Partners Credit Agreement and under the most restrictive provisions of the ONEOK Partners Credit Agreement had $558 million and $367 million, respectively, of credit available.  At March 31, 2010,

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and December 31, 2009, ONEOK Partners had a total of $24.2 million issued in letters of credit outside of the ONEOK Partners Credit Agreement.

The average interest rate of short-term debt outstanding under the ONEOK Partners Credit Agreement was 0.54 percent at March 31, 2010, and December 31, 2009.

Borrowings under the ONEOK Credit Agreement and the ONEOK Partners Credit Agreement are typically short term in nature, ranging from one day to six months.  Accordingly, these borrowings are classified as short-term notes payable. 

F.           SHAREHOLDERS’ EQUITY

The following table sets forth the changes in shareholders’ 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, 2010									March 31, 2009
	ONEOK Shareholders' Equity			Noncontrolling Interests in Consolidated Subsidiaries			Total Shareholders' Equity			ONEOK Shareholders' Equity			Noncontrolling Interests in Consolidated Subsidiaries			Total Shareholders' Equity
	(Thousands of dollars)
Beginning balance	$	2,207,194		$	1,238,268		$	3,445,462		$	2,088,170		$	1,079,369		$	3,167,539
Net income		154,539			32,181			186,720			122,285			41,264			163,549
Other comprehensive income (loss)		13,049			16,287			29,336			14,464			(10,042	)		4,422
Repurchase of common stock		(5	)		-			(5	)		(247	)		-			(247	)
Common stock issued		1,890			-			1,890			701			-			701
Common stock dividends		(46,701	)		-			(46,701	)		(42,080	)		-			(42,080	)
Issuance of common units of ONEOK Partners		50,731			271,990			322,721			-			-			-
Distributions to noncontrolling interests		-			(59,782	)		(59,782	)		-			(52,751	)		(52,751	)
Ending balance	$	2,380,697		$	1,498,944		$	3,879,641		$	2,183,293		$	1,057,840		$	3,241,133

Dividends - Fourth-quarter 2009 and first-quarter 2010 dividends paid on our common stock to shareholders of record at the close of business on January 30, 2010, and April 30, 2010, respectively, were $0.44 per share.

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

G.           EMPLOYEE BENEFIT PLANS

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

	Pension Benefits						Postretirement Benefits
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2010			2009			2010			2009
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	4,819		$	4,984		$	1,231		$	1,293
Interest cost		14,536			15,205			3,911			4,230
Expected return on assets		(18,413	)		(16,508	)		(1,974	)		(1,702	)
Amortization of unrecognized net asset at adoption		-			-			797			797
Amortization of unrecognized prior service cost		320			391			(501	)		(501	)
Amortization of net loss		6,889			6,814			1,752			2,415
Net periodic benefit cost	$	8,151		$	10,886		$	5,216		$	6,532

Our Distribution segment recovers certain pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers.  In September 2009, the KCC authorized us to defer the difference between current GAAP pension and post-retirement expenses and the level of these expenses incorporated in base rates as either a regulatory asset or liability.  Amortization and recovery of the accumulated deferrals will begin with the effective date of our next rate change and will continue for a period not to exceed five years.  The impact from the KCC order was not material for the three months ended March 31, 2010.

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In March 2010, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (collectively, the Health Care Acts) were signed into law.  Based on our preliminary analysis of the Health Care Acts, we do not expect a significant impact to our benefit plans or their related costs.  We do not participate in the federal retiree prescription drug subsidy program, for which the tax treatment was changed as a result of the Health Care Acts, and accordingly, are not impacted by the change in tax treatment of the subsidy.  With the exception of increasing our dependent care age requirement to age 26 from age 24, our health plans provide coverage levels that meet the near-term minimum requirements outlined in the Health Care Acts.  We continue to evaluate the implications of the provisions of the Health Care Acts and expect to continue to provide benefit plan options that meet the provisions outlined by the Health Care Acts. 

H.           COMMITMENTS AND CONTINGENCIES

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

We own or retain legal responsibility for the environmental conditions at 12 former manufactured 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 two locations, and we have completed or are near completion of soil remediation at nine sites.  We have begun site assessment at the remaining site where no active remediation has occurred.

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position or results of operations, and our expenditures related to environmental matters had no material effect upon earnings or cash flows during the three months ended March 31, 2010 or 2009.

The EPA is proposing to finalize the “Tailoring Rule” that will regulate greenhouse gas emissions at certain facilities that emit more than 25,000 tons of greenhouse gas emissions per year.  Under the Prevention of Significant Deterioration requirement for existing facilities, upon making a major modification to a facility, the facility would be required to obtain permits that demonstrate it has installed the best available technology to control greenhouse gas emissions.  The rule is expected to be phased in beginning January 2011 and could impact some of our facilities.  At this time, potential costs, fees or expenses associated with the proposed “Tailoring Rule” are unknown.

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

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

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Overland Pass Pipeline Company - - Overland Pass Pipeline Company is a joint venture between ONEOK Partners and a subsidiary of The Williams Companies, Inc. (Williams).  A subsidiary of ONEOK Partners owns 99 percent of the joint venture and operates the pipeline.  On or before November 17, 2010, Williams has the option to increase its ownership in Overland Pass Pipeline Company up to a total of 50 percent, with the purchase price being determined in accordance with the joint venture’s operating agreement.  If Williams exercises its option to increase its ownership to 50 percent, Williams would have the option to become operator.  Should Williams exercise its option to obtain a 50 percent ownership interest, ONEOK Partners may be required to deconsolidate Overland Pass Pipeline Company and account for it under the equity method of accounting.

I.           SEGMENTS

Segment Descriptions - Our operations are divided into three reportable business segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment.  These segments are as follows: (i) our ONEOK Partners segment gathers, processes, transports, stores and sells natural gas and gathers, treats, fractionates, stores, distributes and markets NGLs; (ii) our Distribution segment, which includes our retail marketing operations, delivers natural gas to residential, commercial, municipal and industrial customers and transports natural gas; and (iii) our Energy Services segment markets natural gas to wholesale customers.  Our Distribution segment is primarily comprised of regulated public utilities, and portions of our ONEOK Partners segment are also regulated.  Other and eliminations consists 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.

In the first quarter of 2010, responsibility for our retail marketing business was transferred to our Distribution segment from our Energy Services segment.  As a result, we have revised our reportable segments to reflect this change in responsibility.  Prior-period amounts have been recast to reflect this transfer.

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, storage and transportation costs.

Customers - For the three months ended March 31, 2010 and 2009, we had no single external customer from which we received 10 percent or more of our consolidated revenues.

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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, 2010	ONEOK Partners (a)			Distribution (b)		Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	2,067,075		$	997,908	$	858,232	$	752		$	3,923,967
Intersegment revenues		136,931			3,491		335,602		(476,024	)		-
Total revenues	$	2,204,006		$	1,001,399	$	1,193,834	$	(475,272	)	$	3,923,967
Net margin	$	261,125		$	246,826	$	110,618	$	750		$	619,319
Operating costs		96,306			99,776		7,426		(163	)		203,345
Depreciation and amortization		43,871			33,345		153		487			77,856
Loss on sale of assets		(786	)		-		-		-			(786	)
Operating income	$	120,162		$	113,705	$	103,039	$	426		$	337,332
Equity earnings from investments	$	21,116		$	-	$	-	$	-		$	21,116
Investments in unconsolidated   affiliates	$	762,435		$	-	$	-	$	-		$	762,435
Total assets	$	7,697,369		$	3,092,696	$	666,812	$	872,315		$	12,329,192
Noncontrolling interests in   consolidated subsidiaries	$	5,387		$	-	$	-	$	1,493,557		$	1,498,944
Capital expenditures	$	35,827		$	31,378	$	52	$	1,016		$	68,273
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $152.1 million, net margin of $125.6 million and operating income of $69.4 million.
(b) - Our Distribution segment has regulated and non-regulated operations. Our Distribution segment's regulated operations had revenues of $857.6 million, net margin of $242.6 million and operating income of 111.3 million.

Three Months Ended March 31, 2009	ONEOK Partners (a)		Distribution (b)		Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	1,106,730	$	849,354	$	832,984	$	759		$	2,789,827
Intersegment revenues		144,135		2,310		289,085		(435,530	)		-
Total revenues	$	1,250,865	$	851,664	$	1,122,069	$	(434,771	)	$	2,789,827
Net margin	$	253,541	$	238,953	$	58,174	$	743		$	551,411
Operating costs		89,446		91,438		6,146		(84	)		186,946
Depreciation and amortization		39,940		31,626		131		429			72,126
Gain on sale of assets		664		-		-		-			664
Operating income	$	124,819	$	115,889	$	51,897	$	398		$	293,003
Equity earnings from investments	$	21,222	$	-	$	-	$	-		$	21,222
Capital expenditures	$	192,494	$	44,652	$	-	$	5,881		$	243,027
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $119.5 million, net margin of $95.5 million and operating income of $45.3 million.
(b) - Our Distribution segment has regulated and non-regulated operations. Our Distribution segment's regulated operations had revenues of $754.4 million, net margin of $234.6 million and operating income of $112.9 million.

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J.           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,
	2010		2009
	(Thousands of dollars)
Northern Border Pipeline	$	14,846	$	16,038
Bighorn Gas Gathering, L.L.C.		237		2,086
Fort Union Gas Gathering, L.L.C.		3,558		2,210
Lost Creek Gathering Company, L.L.C.		1,402		890
Other		1,073		(2	)
Equity earnings from investments	$	21,116	$	21,222

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

	Three Months Ended
	March 31,
	2010		2009
	(Thousands of dollars)
Income Statement
Operating revenues	$	99,231	$	106,066
Operating expenses	$	44,715	$	44,803
Net income	$	46,911	$	50,516
Distributions paid to us	$	23,529	$	33,331

Distributions paid to us are classified as operating activities on our Consolidated Statements of Cash Flows until the cumulative distributions exceed our proportionate share of income from the unconsolidated affiliate since the date of our initial investment.  The amount of cumulative distributions paid to us that exceeds our cumulative proportionate share of income in each period represents a return of investment and is classified as an investing activity on our Consolidated Statements of Cash Flows.  Distributions paid to us include a $1.5 million and $8.1 million return of investment for the three months ended March 31, 2010 and 2009, respectively.

K.           EARNINGS PER SHARE INFORMATION

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

	Three Months Ended March 31, 2010
						Per Share
		Income		Shares		Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Net income attributable to ONEOK available for common stock		$	154,539		106,132	$	1.46
Diluted EPS from continuing operations
Effect of options and other dilutive securities			-		1,278
Net income attributable to ONEOK available for common stock
and common stock equivalents		$	154,539		107,410	$	1.44

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	Three Months Ended March 31, 2009
						Per Share
		Income		Shares		Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Net income attributable to ONEOK available for common stock		$	122,285		105,162		$	1.16
Diluted EPS from continuing operations
Effect of options and other dilutive securities			-		571
Net income attributable to ONEOK available for common stock
and common stock equivalents		$	122,285		105,733		$	1.16

There were no option shares excluded from the calculation of diluted EPS for the three months ended March 31, 2010, and 265,043 option shares excluded from the calculation of diluted EPS for the three months ended March 31, 2009.

L.           ONEOK PARTNERS

Ownership Interest in ONEOK Partners - Our ownership interest in ONEOK Partners is shown in the following table for the periods indicated.

	March 31,			December 31,
	2010			2009
General partner interest		2.0	%		2.0	%
Limited partner interest (a)		40.8	%		43.1	%
Total ownership interest		42.8	%		45.1	%
(a) - Represents 5.9 million common units and approximately 36.5 million Class B units, which are convertible, at our option, into common units.

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

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.  If ONEOK Partners issues common units at a price different than our carrying value per unit, we account for the premium or deficiency as an adjustment to paid-in capital.  As a result of ONEOK Partners’ issuance of common units at a premium to our carrying value per unit, we recognized an increase to paid-in capital of $50.7 million during the three months ended March 31, 2010.

Cash Distributions - The following table sets forth ONEOK Partners’ general partner and incentive distributions declared for the periods indicated:

		Three Months Ended
		March 31,
		2010		2009
	(Thousands of dollars)
General partner distributions		$	2,833	$	2,419
Incentive distributions			25,710		20,320
Total distributions to general partner		$	28,543	$	22,739

The quarterly distribution paid by ONEOK Partners to limited partners in the first quarter of 2010 was $1.10 per unit.  The quarterly distribution paid by ONEOK Partners to limited partners in the first quarter of 2009 was $1.08 per unit.

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For the three months ended March 31, 2010 and 2009, cash distributions paid by ONEOK Partners to us totaled $72.7 million and $68.5 million, respectively.

In April 2010, a cash distribution from ONEOK Partners of $1.11 per unit payable in the second quarter was declared.  On May 14, 2010, we will receive the related incentive distribution of $25.7 million for the first quarter of 2010, which is included in the table above.

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

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

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

ONEOK Partners has certain contractual rights to our Bushton Plant through a Processing and Services Agreement with us, which sets out the terms for processing and related services we provide at the Bushton Plant through 2012.  ONEOK Partners has contracted for all of the capacity of the Bushton Plant from our wholly owned subsidiary, OBPI.  In exchange, ONEOK Partners pays OBPI for all costs and expenses necessary for the operation and maintenance of the Bushton Plant, and reimburses us for a portion of our obligations under equipment leases covering the Bushton Plant.

We provide a variety of services to our affiliates, including cash management and financial services, administrative services provided by our employees and management, insurance and office space leased in our headquarters building and other field locations.  Where costs are specifically incurred 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, earnings before interest and taxes and payroll expense.  It is not practicable to determine what these general overhead costs would be on a stand-alone basis.

The following table sets forth transactions with ONEOK Partners for the periods indicated:

	Three Months Ended
	March 31,
	2010		2009
	(Thousands of dollars)
Revenues	$	136,931	$	144,135
Expenses
Cost of sales and fuel	$	17,759	$	16,638
Administrative and general expenses		51,025		48,623
Total expenses	$	68,784	$	65,261

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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, 2010, are not necessarily indicative of the results that may be expected for a 12-month period.

EXECUTIVE SUMMARY

Outlook - We expect a moderate economic recovery in 2010, with inflationary pressures beginning in 2011.  Although recent volatility in the financial markets could limit our access to financial markets on a timely basis or increase our cost of capital in the future, we anticipate improved credit markets during 2010, compared with 2009; however, inflation risks may increase the cost of capital.  We anticipate the consolidation of underperforming assets in the industry, particularly those with high commodity price exposure and/or high levels of debt.  Additionally, we anticipate an improving commodity price environment during 2010, compared with 2009.

Recent Developments - In April 2010, ONEOK Partners announced that it will invest approximately $405 million to $470 million for projects in the Bakken Shale in the Williston Basin in North Dakota and in the Woodford Shale in Oklahoma, which will enable ONEOK Partners to meet the rapidly growing needs of producers in these areas.  These investments include construction of a new 100 MMcf/d natural gas processing facility, the Garden Creek plant, in eastern McKenzie County, North Dakota.  The plant and related expansions are estimated to cost between $150 million and $210 million and will double ONEOK Partners’ natural gas processing capacity in the Williston Basin.  These projects are expected to be completed in the fourth quarter of 2011.  In addition, ONEOK Partners will invest an additional $200 million to $205 million during 2010 and 2011 for new well connections, expansions and upgrades to its existing natural gas gathering infrastructure in the Bakken Shale.

ONEOK Partners will invest an additional $55 million in the Woodford Shale in Oklahoma for new well connections in 2010 and 2011 and to connect its existing gathering system to its existing Maysville, Oklahoma, natural gas processing facility, as well as the connection of a new plant to ONEOK Partners’ NGL gathering system.

Operating Results - Diluted earnings per share of common stock from continuing operations (EPS) were $1.44 and $1.16 for the three months ended March 31, 2010 and 2009, respectively.  Operating income for the three months ended March 31, 2010, increased to $337.3 million from $293.0 million for the same period last year.  This increase in operating income is due primarily to increased net margins in our Energy Services segment, due primarily to higher realized storage differentials and marketing margins, net of hedging activities, offset partially by decreased premium-services margins.

ONEOK Partners’ Equity Issuance - In February 2010, ONEOK Partners completed an underwritten public offering of 5,500,900 common units, including the partial exercise by the underwriters of their over-allotment option, at a public offering price of $60.75 per common unit, generating net proceeds of approximately $322.7 million.  In conjunction with the offering, ONEOK Partners GP contributed $6.8 million in order to maintain its 2 percent general partner interest.  ONEOK Partners used the proceeds from the sale of common units and the general partner contribution to repay borrowings under the ONEOK Partners Credit Agreement and for general partnership purposes.  We currently hold a 42.8 percent aggregate equity interest in ONEOK Partners.

Dividends/Distributions - We declared a quarterly dividend of $0.44 per share ($1.76 per share on an annualized basis) in April 2010, an increase of 10 percent from the $0.40 per share declared in April 2009.  ONEOK Partners declared a cash distribution of $1.11 per unit ($4.44 per unit on an annualized basis) in April 2010, an increase of approximately 3 percent from the $1.08 per unit declared in April 2009.

Retail Marketing - In the first quarter of 2010, responsibility for our retail marketing business was transferred to our Distribution segment from our Energy Services segment.  This transfer enables our Energy Services segment to increase its focus on providing premium services to its wholesale customers.  As a result, we have revised our reportable segments to reflect this change in responsibility.  Prior-period amounts have been recast to reflect this transfer.

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REGULATORY

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

The EPA is proposing to finalize the “Tailoring Rule” that will regulate greenhouse gas emissions at certain facilities that emit more than 25,000 tons of greenhouse gas emissions per year.  Under the Prevention of Significant Deterioration requirement for existing facilities, upon making a major modification to a facility, the facility would be required to obtain permits that demonstrate it has installed the best available technology to control greenhouse gas emissions.  The rule is expected to be phased in beginning January 2011 and could impact some of our facilities.  At this time, potential costs, fees or expenses associated with the proposed “Tailoring Rule” are unknown.

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

Financial Markets Legislation - It is unclear how Congress and the current Administration’s efforts to improve market transparency and stabilize the over-the-counter (OTC) derivative markets will impact our ability to access OTC energy derivatives products and markets, which are critical to our business.  We use the OTC markets to manage business risks including fluctuating commodity prices, interest rates, currency rates and for the hedging of inventory and capacity contracts.  Most of the current proposals before Congress contain exemptions for these activities that would limit the impact on our operations.  Additional matters associated with these proposals that are not yet defined include the potential for increased capital requirements and a reduction in the overall liquidity of the markets.  There may also be an administrative burden of new reporting and record keeping required by one or more of the federal agencies providing market oversight.

Health Care Legislation - In March 2010, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (collectively, the Health Care Acts) were signed into law.  Based on our preliminary analysis of the Health Care Acts, we do not expect a significant impact to our benefit plans or their related costs.  We do not participate in the federal retiree prescription drug subsidy program, for which the tax treatment was changed as a result of the Health Care Acts, and accordingly, are not impacted by the change in tax treatment of the subsidy.  With the exception of increasing our dependent care age requirement to age 26 from age 24, our health plans provide coverage levels that meet the near-term minimum requirements outlined in the Health Care Acts.  We continue to evaluate the implications of the provisions of the Health Care Acts and expect to continue to provide benefit plan options that meet the provisions outlined by the Health Care Acts. 

Other - Several regulatory initiatives impacted the earnings and future earnings potential for our Distribution segment.  See discussion of our Distribution segment’s regulatory initiatives on page 39.

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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:

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

·   ASU 2010-11, “Scope Exception Related to Embedded Credit Derivatives,” which will be effective for our September 30, 2010, Quarterly Report and will be applied prospectively.  We are currently reviewing the applicability of ASU 2010-11 to our consolidated financial statements and related disclosures.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

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

FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

Selected Financial Results - The following table sets forth certain selected consolidated financial results for the periods indicated:

	Three Months Ended						Variances
	March 31,						2010 vs. 2009
Financial Results	2010			2009			Increase (Decrease)
	(Millions of dollars)
Revenues	$	3,923.9		$	2,789.8		$	1,134.1		41	%
Cost of sales and fuel		3,304.6			2,238.4			1,066.2		48	%
Net margin		619.3			551.4			67.9		12	%
Operating costs		203.3			187.0			16.3		9	%
Depreciation and amortization		77.9			72.1			5.8		8	%
Gain (loss) on sale of assets		(0.8	)		0.7			(1.5	)		*
Operating income	$	337.3		$	293.0		$	44.3		15	%
Equity earnings from investments	$	21.1		$	21.2		$	(0.1	)	(0	%)
Allowance for equity funds used    during construction	$	0.2		$	9.0		$	(8.8	)	(98	%)
Interest expense	$	(76.5	)	$	(78.0	)	$	(1.5	)	(2	%)
Net income attributable to    noncontrolling interests	$	(32.2	)	$	(41.3	)	$	(9.1	)	(22	%)
Capital expenditures	$	68.3		$	243.0		$	(174.7	)	(72	%)
* Percentage change is greater than 100 percent.

Energy markets were affected by increased commodity prices during the three months ended March 31, 2010, compared with the same period last year.  This increase in commodity prices had a direct impact on our revenues and cost of sales and fuel.  Net margin increased for the three months ended March 31, 2010, compared with the same period last year, due primarily to the following:

·   increased net margin in our Energy Services segment, due primarily to:

-   higher realized storage differentials and marketing margins, net of hedging activities; offset partially by

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-   decreased premium-services margins, associated primarily with lower demand fees and managing increased demand to meet customer-peaking requirements due to colder weather in the first quarter of 2010, compared with the same period last year;

·   increased net margin in our Distribution segment from increased revenue from various riders and higher transportation and sales volumes; and

·   increased net margin in our ONEOK Partners segment, due primarily to:

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

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

-   lower optimization margins due to less NGL fractionation and transportation capacity available for optimization; and

-   the impact of operational measurement gains and losses as compared with the same period last year.

Operating costs increased for the three months ended March 31, 2010, compared with the same period last year, due to the operation of the recently completed capital projects and higher employee-related costs in our ONEOK Partners segment, and the recognition of previously deferred costs and increased employee-related costs in our Distribution segment.

Depreciation and amortization expense increased for the three months ended March 31, 2010, compared with the same period last year, primarily as a result of  ONEOK Partners’ completed capital projects.

Allowance for equity funds used during construction decreased for the three months ended March 31, 2010, compared with the same period last year, due to the completion of the Arbuckle Pipeline, Piceance lateral and D-J Basin lateral.

Net income attributable to noncontrolling interests for the three months ended March 31, 2010 and 2009, reflects the remaining 57.2 percent and 52.3 percent, respectively, of ONEOK Partners that we do not own.  The decrease in net income attributable to noncontrolling interests is due to the decreased income of our ONEOK Partners segment.

Capital expenditures decreased for the three months ended March 31, 2010, compared with the same period last year, due to the completion of the capital projects in our ONEOK Partners segment.

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

ONEOK Partners

Overview - We currently own approximately 42.4 million common and Class B limited partner units and the entire 2 percent general partner interest, which, together, represent a 42.8 percent ownership interest in ONEOK Partners.  We receive distributions from ONEOK Partners on our common and Class B units and our 2 percent general partner interest.

Our ONEOK Partners segment is engaged in the gathering and processing of natural gas and gathering, primarily in the Mid-Continent and Rocky Mountain regions, which include the Anadarko Basin of Oklahoma, Hugoton and Central Kansas Uplift Basins of Kansas; and the Williston Basin of Montana and North Dakota and the Powder River Basin of Wyoming, respectively.  These operations include the gathering of natural gas produced from crude oil and natural gas wells.  Through gathering systems, natural gas is aggregated and treated or processed for removal of water vapor, solids and other contaminants, and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas.  When the NGLs are separated from the unprocessed natural gas at the processing plants, the NGLs are generally in the form of a mixed, unfractionated NGL stream.  In the Powder River Basin, the natural gas that ONEOK Partners gathers is coal-bed methane, or dry gas, that does not require processing or NGL extraction, in order to be marketable; dry gas is gathered, compressed and delivered into a downstream pipeline or marketed for a fee.

ONEOK Partners also gathers, treats, fractionates, transports and stores NGLs.  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.  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

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products from Oklahoma and Kansas to the market centers in Conway, Kansas, and Mont Belvieu, Texas, as well as the Midwest markets near Chicago, Illinois.

ONEOK Partners operates interstate and intrastate natural gas transmission pipelines, natural gas storage facilities and non-processable natural gas gathering facilities.  ONEOK Partners also provides natural gas transportation and storage services in accordance with Section 311(a) of the Natural Gas Policy Act of 1978, as amended.  ONEOK Partners’ interstate assets transport natural gas through FERC-regulated interstate natural gas 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.

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,						2010 vs. 2009
Financial Results	2010			2009			Increase (Decrease)
	(Millions of dollars)
Revenues	$	2,204.0		$	1,250.9		$	953.1		76	%
Cost of sales and fuel		1,942.9			997.4			945.5		95	%
Net margin		261.1			253.5			7.6		3	%
Operating costs		96.2			89.5			6.7		7	%
Depreciation and amortization		43.9			39.9			4.0		10	%
Gain (loss) on sale of assets		(0.8	)		0.7			(1.5	)		*
Operating income	$	120.2		$	124.8		$	(4.6	)	(4	%)
Equity earnings from investments	$	21.1		$	21.2		$	(0.1	)	(0	%)
Allowance for equity funds used    during construction	$	0.2		$	9.0		$	(8.8	)	(98	%)
Interest expense	$	(54.2	)	$	(50.9	)	$	3.3		6	%
Capital expenditures	$	35.8		$	192.5		$	(156.7	)	(81	%)
* Percentage change is greater than 100 percent.

Net margin increased for the three months ended March 31, 2010, compared with the same period last year, due to the following:

·   an increase of $20.0 million due to higher NGL volumes gathered, fractionated and transported, associated with the completion of the Arbuckle Pipeline, Piceance lateral and D-J Basin lateral, as well as new NGL supply connections; and

·   an increase of $9.2 million from higher natural gas transportation margins from the Guardian Pipeline expansion and extension that was completed in February 2009 and an increase in volumes contracted on Midwestern Gas Transmission; offset partially by

·   a decrease of $14.8 million related to lower optimization margins due to less NGL fractionation and transportation capacity available for optimization;

·   a decrease of $6.8 million due to the impact of operational measurement gains and losses as compared with the same period last year; and

·   a decrease of $4.8 million due to lower natural gas volumes gathered, primarily in the Powder River Basin, and a favorable contract settlement recognized in the first quarter of 2009.

Operating costs increased for the three months ended March 31, 2010, compared with the same period last year, due to the operation of ONEOK Partners’ recently completed capital projects and higher employee-related costs.

Depreciation and amortization expense increased for the three months ended March 31, 2010, compared with the same period last year, as a result of ONEOK Partners’ completed capital projects.

Allowance for equity funds used during construction decreased for the three months ended March 31, 2010, compared with the same period last year, due to the completion of the Arbuckle Pipeline, Piceance lateral and D-J Basin lateral.

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Capital expenditures decreased for the three months ended March 31, 2010, compared with the same period last year, due to the completions of ONEOK Partners’ capital projects discussed in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report.

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	2010			2009
Natural gas gathered (BBtu/d) (a)		1,092			1,163
Natural gas processed (BBtu/d) (a)		664			653
Natural gas transportation capacity contracted (MMcf/d)		5,860			5,247
Transportation capacity subscribed		91	%		79	%
Residue gas sales (BBtu/d) (a)		275			285
NGL sales (MBbl/d)		427			380
NGLs fractionated (MBbl/d)		492			465
NGLs transported-gathering lines (MBbl/d)		441			324
NGLs transported-distribution lines (MBbl/d)		467			445
Conway-to-Mont Belvieu OPIS average price differential
Ethane ($/gallon)	$	0.08		$	0.08
Realized composite NGL net sales prices ($/gallon) (a) (b)	$	0.99		$	0.88
Realized condensate net sales price ($/Bbl) (a) (b)	$	62.39		$	68.45
Realized residue gas net sales price ($/MMBtu) (a) (b)	$	5.20		$	3.58
Realized gross processing spread ($/MMBtu) (a)	$	6.37		$	7.43
(a) - Statistics relate to ONEOK Partners’ natural gas gathering and processing business.
(b) - Includes equity volumes only.

Commodity Price Risk - The following tables set forth hedging information for ONEOK Partners’ natural gas gathering and processing business for the periods indicated, as of April 28, 2010:

	Nine Months Ending
	December 31, 2010
	Volumes Hedged		Average Price			Percentage Hedged
NGLs (Bbl/d) (a)		5,261	$	1.04	/ gallon		68	%
Condensate (Bbl/d) (a)		1,648	$	1.81	/ gallon		76	%
Total (Bbl/d)		6,909	$	1.22	/ gallon		70	%
Natural gas (MMBtu/d)		26,504	$	5.60	/ MMBtu		81	%
(a) - Hedged with fixed-price swaps.

	Year Ending
	December 31, 2011
	Volumes Hedged		Average Price			Percentage Hedged
NGLs (Bbl/d) (a)		902	$	1.34	/ gallon		13	%
Condensate (Bbl/d) (a)		596	$	2.12	/ gallon		26	%
Total (Bbl/d)		1,498	$	1.65	/ gallon		16	%
Natural gas (MMBtu/d)		16,616	$	6.29	/ MMBtu		43	%
(a) - Hedged with fixed-price swaps.

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Commodity price risk related to physical sales of commodities for ONEOK Partners’ natural gas gathering and processing business is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at March 31, 2010.  ONEOK Partners’ condensate sales are based on the price of crude oil.  ONEOK Partners estimates the following for its natural gas gathering and processing business:

·   a $0.01 per gallon decrease in the composite price of NGLs would decrease annual net margin by approximately $1.1 million;

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

·   a $0.10 per MMBtu decrease in the price of natural gas would decrease annual net margin by approximately $1.2 million.

The above estimates of commodity price risk exclude the effects of hedging and assume normal operating conditions.  Further, these estimates do not include any effects on demand for 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, affecting gathering and processing margins.

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

Distribution

Overview - Our Distribution segment provides natural gas distribution services to more than two million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively, each a division of ONEOK.  We serve residential, commercial, industrial and transportation customers in all three states.  Our distribution companies in Oklahoma and Kansas serve wholesale customers, and in Texas we serve public authority customers, such as cities, governmental agencies and schools.  In addition, our retail marketing business serves customers primarily in the Mid-Continent region.

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

	Three Months Ended				Variances
	March 31,				2010 vs. 2009
Financial Results	2010		2009		Increase (Decrease)
	(Millions of dollars)
Gas sales	$	962.5	$	813.2	$	149.3		18	%
Transportation revenues		29.6		26.5		3.1		12	%
Cost of gas		754.6		612.7		141.9		23	%
Net margin, excluding other revenues		237.5		227.0		10.5		5	%
Other revenues		9.3		12.0		(2.7	)	(23	%)
Net margin		246.8		239.0		7.8		3	%
Operating costs		99.8		91.4		8.4		9	%
Depreciation and amortization		33.3		31.7		1.6		5	%
Operating income	$	113.7	$	115.9	$	(2.2	)	(2	%)
Capital expenditures	$	31.4	$	44.7	$	(13.3	)	(30	%)

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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,				2010 vs. 2009
Net margin, excluding other revenues	2010		2009		Increase (Decrease)
Gas sales - Regulated	(Millions of dollars)
Residential	$	165.0	$	156.5	$	8.5		5	%
Commercial		36.4		37.4		(1.0	)	(3	%)
Industrial		0.7		0.8		(0.1	)	(13	%)
Wholesale		0.1		0.1		-		0	%
Public Authority		1.5		1.3		0.2		15	%
Gas sales - Retail		4.2		4.4		(0.2	)	(5	%)
Net margin on gas sales		207.9		200.5		7.4		4	%
Transportation margin		29.6		26.5		3.1		12	%
Net margin, excluding other revenues	$	237.5	$	227.0	$	10.5		5	%

Net margin increased for the three months ended March 31, 2010, compared with the same period last year, due to the following:

·   an increase of $3.1 million from various riders;

·   an increase of $2.7 million from higher transportation volumes; and

·   an increase of $2.4 million due to higher sales volumes;

Operating costs increased for the three months ended March 31, 2010, compared with the same period last year, due to the following:

·   an increase of $3.1 million related to the recognition of previously deferred Integrity Management Program costs in Oklahoma that have been approved for recovery in our revenues; and

·   an increase of $2.9 million in employee-related costs.

Capital Expenditures - Our capital expenditure program includes expenditures for extending service to new areas, modifications to customer service lines, increasing system capabilities, general replacements and improvements, including an automated meter reading investment in Oklahoma.  It is our practice to maintain and upgrade facilities to ensure safe, reliable and efficient operations.  Our capital expenditure program included $5.2 million and $11.0 million for new business development for the three months ended March 31, 2010 and 2009, respectively.  Capital expenditures decreased for the three months ended March 31, 2010, compared with the same period last year, primarily as a result of a one-time payment to terminate vehicle and other equipment leases in 2009.

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

	Three Months Ended
	March 31,
Volumes (MMcf)	2010		2009
Gas sales
Residential		62,456		55,357
Commercial		17,178		15,752
Industrial		394		512
Wholesale		241		1,134
Public Authority		1,243		847
Total volumes sold		81,512		73,602
Transportation		62,154		55,964
Total volumes delivered		143,666		129,566

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	Three Months Ended
	March 31,
Number of Customers	2010	2009
Residential	1,930,678	1,913,351
Commercial	157,488	160,450
Industrial	1,296	1,368
Wholesale	35	27
Public Authority	2,622	2,949
Transportation	9,406	10,746
Total customers	2,101,525	2,088,891

Residential volumes increased for the three months ended March 31, 2010, compared with the same period last year, due to colder temperatures across our entire service territory; however, the impact on margin increases was moderated by weather-normalization mechanisms.

Regulatory Initiatives

Oklahoma - In December 2009, the OCC approved a rate increase of $54.5 million, which includes moving existing riders into base rates that effectively reduces the rate increase to a net amount of $25.7 million.  The estimated impact on 2010 operating income is approximately $14 million.  The new rates went into effect on December 18, 2009, and include a higher customer charge that reduces our volumetric exposure.  Under a previous order, Oklahoma Natural Gas is migrating from traditional rates to performance-based rates that will provide for a streamlined annual review of the company’s performance, resulting in smaller, potentially more frequent rate adjustments.

On January 27, 2010, Oklahoma Natural Gas filed an application and supporting testimony requesting recovery of the Integrity Management Program deferral for 2009 and annual adjustments associated with the prior recovery period in the amount of $15.7 million.

Kansas - In December 2009, the KCC approved Kansas Gas Service’s application to increase the Gas System Reliability Surcharge.  In April 2010, the surcharge recovery was slightly reduced as a result of a revised application.  The anticipated impact of the Gas System Reliability Surcharge on 2010 operating income is an increase of $3.4 million.

In December 2009, Kansas Gas Service filed an application with the KCC to become an Efficiency Kansas Loan Program utility partner.  The application seeks to implement the KCC’s Efficiency Kansas Loan Program and a portfolio of energy efficiency programs designed to encourage the purchase of efficient natural gas appliances.  Approval of the request would allow Kansas Gas Service to recover its energy-efficiency program costs, and implement a revenue decoupling mechanism that would maintain authorized revenues as determined in its latest rate case.

Texas - In December 2009, Texas Gas Service filed a statement of intent to increase rates in its El Paso service area by $7.3 million.  On April 13, 2010, the City of El Paso rejected the proposed increase.  We will file an appeal on or before May 13, 2010, with the Railroad Commission of Texas.  The Railroad Commission will have approximately six months to render a decision on our appeal.  Any new rates determined by the Railroad Commission would likely go into effect late in the fourth quarter of this year.

General - Certain costs to be recovered through the ratemaking process have been capitalized as regulatory assets.  Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria for capitalization, and, accordingly, a write-off of regulatory assets and stranded costs may be required.  There were no write-offs of regulatory assets resulting from the failure to meet the criteria for capitalization during the three months ended March 31, 2010 and 2009, respectively.

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Energy Services

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

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

Our Energy Services segment conducts business with our ONEOK Partners and our Distribution segments.  These services are provided under agreements with market-based terms through a competitive bidding process.

Due to the seasonality of natural gas consumption, storage withdrawals and demand for our products and services, earnings are normally higher during the winter months than the summer months.  Natural gas sales volumes are typically higher in the winter heating months than in the summer months, reflecting increased demand due to greater heating requirements and, typically, higher natural gas prices.  During periods of high natural gas demand, we utilize storage capacity to supplement natural gas supply volumes to meet our premium service obligations or market needs.

We utilize our experience to optimize the value of our contracted assets, and we use our risk management and marketing capabilities to both manage risk and generate additional margins.  We apply a combination of cash flow and fair value hedge accounting when implementing hedging strategies that take advantage of favorable market conditions.  See Note C of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.  Additionally, certain non-trading transactions, which are economic hedges of our accrual transactions, such as our storage and transportation contracts, will not qualify for hedge accounting treatment.  These economic hedges receive mark-to-market accounting treatment, as they are derivative contracts and are not designated as part of a hedge relationship.  As a result, the underlying risk being hedged receives accrual accounting treatment, while we use mark-to-market accounting treatment for the economic hedges.  We cannot predict the earnings fluctuations from mark-to-market accounting, and the impact on earnings could be material.

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

	Three Months Ended					Variances
	March 31,					2010 vs. 2009
Financial Results		2010		2009		Increase (Decrease)
	(Millions of dollars)
Revenues		$	1,193.8	$	1,122.1	$	71.7	6	%
Cost of sales and fuel			1,083.2		1,063.9		19.3	2	%
Net margin			110.6		58.2		52.4	90	%
Operating costs			7.4		6.1		1.3	21	%
Depreciation and amortization			0.2		0.2		-	0	%
Operating income		$	103.0	$	51.9	$	51.1	98	%

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

	Three Months Ended					Variances
	March 31,					2010 vs. 2009
		2010		2009		Increase (Decrease)
	(Millions of dollars)
Marketing, storage and transportation, gross		$	163.4	$	111.9	$	51.5		46	%
Storage and transportation costs			54.7		57.0		(2.3	)	(4	%)
Marketing, storage and transportation, net			108.7		54.9		53.8		98	%
Financial trading, net			1.9		3.3		(1.4	)	(42	%)
Net margin		$	110.6	$	58.2	$	52.4		90	%

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

Net margin increased for the three months ended March 31, 2010, compared with the same period last year, due primarily to the following:

·   an increase of $71.6 million from higher realized storage differentials and marketing margins, net of hedging activities;

·   an increase of $4.8 million in transportation margins, net of hedging, due to higher realized Rocky Mountain-to-Mid-Continent transportation margins, resulting from the following:

-   realization of more favorable hedges related to transportation differentials; and

-   favorable unrealized fair-value changes on non-qualifying economic hedge activity and ineffectiveness on qualified hedges; partially offset by

·   a decrease of $22.6 million in premium-services margins, associated primarily with lower demand fees and managing increased demand to meet customer-peaking requirements due to colder weather in the first quarter of 2010, compared with the same period last year; and

·   a decrease of $1.4 million in financial trading margins.

Operating costs increased due to higher employee-related costs.

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

	Three Months Ended
	March 31,
Operating Information	2010		2009
Natural gas marketed (Bcf)		244		304
Natural gas gross margin ($/Mcf)	$	0.46	$	0.20
Physically settled volumes (Bcf)		485		609

Our natural gas in storage at March 31, 2010, was 25.0 Bcf, compared with 45.5 Bcf at March 31, 2009.  At March 31, 2010, our total natural gas storage capacity under lease was 82.8 Bcf, compared with 91.0 Bcf at March 31, 2009.  Our natural gas storage capacity under lease had maximum withdrawal capability of 2.3 Bcf/d and maximum injection capability of 1.4 Bcf/d.  Our current natural gas transportation capacity is 1.7 Bcf/d.

Natural gas volumes marketed and physically settled volumes decreased for the three months ended March 31, 2010, compared with the same period last year, due primarily to lower transported volumes.  Transportation capacity in certain markets was not utilized due to the economics of the transportation spread.

Contingencies

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

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LIQUIDITY AND CAPITAL RESOURCES

General - Part of our strategy is to grow through internally generated growth projects and acquisitions that strengthen and complement our existing assets.  ONEOK and ONEOK Partners have relied primarily on operating cash flow, commercial paper, bank credit facilities, debt issuances and the sale of equity for their liquidity and capital resource requirements.  ONEOK and ONEOK Partners fund their operating expenses, debt service, dividends to shareholders and distributions to unitholders primarily with operating cash flow.  We expect to continue to use these sources for liquidity and capital resource needs on both a short- and long-term basis.  Neither ONEOK nor ONEOK Partners guarantees the debt or other similar commitments to unaffiliated parties, and ONEOK does not guarantee the debt or other similar commitments of ONEOK Partners.

In 2010, ONEOK accessed the commercial paper markets to meet its short-term funding needs.  ONEOK Partners utilized the ONEOK Partners Credit Agreement to fund its short-term liquidity needs.  In February 2010, ONEOK Partners issued common units.  See discussion below under “ONEOK Partners’ Equity Issuance” for more information.

We expect a moderate economic recovery in 2010, with inflationary pressures beginning in 2011.  Although recent volatility in the financial markets could limit our access to financial markets or increase our cost of capital in the future, we anticipate improved credit markets during 2010, compared with 2009.  ONEOK’s and ONEOK Partners’ ability to continue to access capital markets for debt and equity financing under reasonable terms depends on ONEOK’s and ONEOK Partners’ respective financial condition and credit ratings, and market conditions.  ONEOK and ONEOK Partners anticipate that cash flow generated from operations, existing capital resources and ability to obtain financing will enable both to maintain current levels of operations and planned operations, collateral requirements and capital expenditures.

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

	March 31,	December 31,
	2010	2009
Long-term debt	54%	57%
Equity	46%	43%
Debt (including notes payable)	56%	61%
Equity	44%	39%

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

	March 31,	December 31,
	2010	2009
Long-term debt	39%	41%
Equity	61%	59%
Debt (including notes payable)	39%	46%
Equity	61%	54%

Cash Management - ONEOK and ONEOK Partners each use similar centralized cash management programs that concentrate the cash assets of their operating subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing, transaction costs and bank fees.  Both centralized cash management programs provide that funds in excess of the daily needs of the operating subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within the respective consolidated groups.  ONEOK Partners’ operating subsidiaries participate in these programs to the extent they are permitted pursuant to FERC regulations or their operating agreements.  Under these cash management programs, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, ONEOK and ONEOK Partners provide cash to their respective subsidiaries or the subsidiaries provide cash to them. 

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 ONEOK Credit Agreement as discussed below.  ONEOK also has a commercial paper program that is utilized for short-term liquidity needs, and to the extent commercial paper is

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unavailable the ONEOK Credit Agreement may be utilized.  ONEOK Partners’ principal sources of short-term liquidity consist of cash generated from operating activities and the ONEOK Partners Credit Agreement.

The total amount of short-term borrowings authorized by ONEOK’s Board of Directors is $2.5 billion.  At March 31, 2010, ONEOK had no commercial paper outstanding, $37.0 million in letters of credit issued under the ONEOK Credit Agreement and approximately $162.0 million of available cash and cash equivalents.  ONEOK had approximately $1.2 billion of credit available at March 31, 2010, under the ONEOK Credit Agreement.  As of March 31, 2010, ONEOK could have issued $3.6 billion of additional short- and long-term debt under the most restrictive provisions contained in its various borrowing agreements.

The total amount of short-term borrowings authorized by the Board of Directors of ONEOK Partners GP, the general partner of ONEOK Partners, is $1.5 billion.  At March 31, 2010, ONEOK Partners had $310.0 million in borrowings outstanding under the ONEOK Partners Credit Agreement and approximately $5.4 million of available cash and cash equivalents.  As of March 31, 2010, ONEOK Partners’ borrowing capacity was limited to $558 million of additional short- and long-term debt under the most restrictive provisions contained in the ONEOK Partners Credit Agreement.  At March 31, 2010, ONEOK Partners had a total of $24.2 million in letters of credit issued outside the ONEOK Partners Credit Agreement.

The ONEOK Credit Agreement and the ONEOK Partners Credit Agreement contain certain financial, operational and legal covenants as discussed in Note H of the Notes to Consolidated Financial Statements in our Annual Report.  Among other things, the ONEOK Credit Agreement’s covenants include a limitation on ONEOK’s stand-alone debt-to-capital ratio, which may not exceed 67.5 percent at the end of any calendar quarter.  At March 31, 2010, ONEOK’s stand-alone debt-to-capital ratio, as calculated under the terms of the ONEOK Credit Agreement, was 38.5 percent, and ONEOK was in compliance with all covenants under the ONEOK Credit Agreement.

The ONEOK Partners Credit Agreement’s covenants include, among other things, maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in the ONEOK Partners Credit Agreement, adjusted for all non-cash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5 to 1.  At March 31, 2010, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 4.3 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement.

ONEOK Partners expects to refinance its $250 million senior notes due June 15, 2010, with the ONEOK Partners Credit Agreement.

Long-term Financing - In addition to the principal sources of short-term liquidity discussed above, options available to ONEOK to meet its longer-term cash requirements include the issuance of equity, issuance of long-term notes, issuance of convertible debt securities, asset securitization and the sale and leaseback of facilities.  Options available to ONEOK Partners to meet its longer-term cash requirements include the issuance of common units, issuance of long-term notes, 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 credit facilities, altering the timing of controllable expenditures, restricting future acquisitions and capital projects, or pursuing other debt or equity financing alternatives.  Some of these alternatives could involve higher costs or negatively affect their respective credit ratings, among other factors.  Based on ONEOK’s and ONEOK Partners’ investment-grade credit ratings, general financial condition and market expectations regarding their future earnings and projected cash flows, ONEOK and ONEOK Partners believe that they will be able to meet their respective cash requirements and maintain their investment-grade credit ratings.

ONEOK Partners’ $250 million and $225 million senior notes, due June 15, 2010, and March 15, 2011, respectively, contain provisions that require ONEOK Partners to offer to repurchase the senior notes at par value if its Moody’s or S&P credit rating falls below investment grade (Baa3 for Moody’s or BBB- for S&P) and the investment-grade rating is not reinstated within a period of 40 days; however, once the $250 million 2010 senior notes have been retired, whether by maturity, redemption or otherwise, ONEOK Partners will no longer have any obligation to offer to repurchase the $225 million 2011 senior notes in the event its credit rating falls below investment grade.  Further, the indentures governing ONEOK Partners’ senior notes due 2010 and 2011 include an event of default upon acceleration of other indebtedness of $25 million or more and the indentures governing the senior notes due 2012, 2016, 2019, 2036 and 2037 include an event of default upon the acceleration of other indebtedness of $100 million or more that would be triggered by such an offer to repurchase.  Such

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events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2010, 2011, 2012, 2016, 2019, 2036 and 2037 to declare those notes immediately due and payable in full.

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

ONEOK Partners’ Equity Issuance - In February 2010, ONEOK Partners completed an underwritten public offering of 5,500,900 common units, including the partial exercise by the underwriters of their over-allotment option, at a public offering price of $60.75 per common unit, generating net proceeds of approximately $322.7 million.  In conjunction with the offering, ONEOK Partners GP contributed $6.8 million in order to maintain its 2 percent general partner interest.  ONEOK Partners used the proceeds from the sale of common units and the general partner contribution to repay borrowings under the ONEOK Partners Credit Agreement and for general partnership purposes.  As a result of these transactions, we hold a 42.8 percent aggregate equity interest in ONEOK Partners.

Capital Expenditures - ONEOK’s and ONEOK Partners’ capital expenditures are typically financed through operating cash flows, short- and long-term debt and the issuance of equity.  Capital expenditures were $68.3 million and $243.0 million for the three months ended March 31, 2010 and 2009, respectively.  Of these amounts, ONEOK Partners’ capital expenditures were $35.8 million and $192.5 million for the three months ended March 31, 2010 and 2009, respectively.  Our capital expenditures are driven primarily by ONEOK Partners’ capital projects.  We classify expenditures that are expected to generate additional revenue or significant operating efficiencies as growth capital expenditures.  Maintenance capital expenditures are those required to maintain existing operations and do not generate additional revenues.

Projected 2010 capital expenditures are significantly lower than 2009 capital expenditures, due to various ONEOK Partners’ projects being completed or placed in service during 2009.  The following table sets forth our 2010 projected capital expenditures, excluding AFUDC:

2010 Projected Capital Expenditures
	(Millions of dollars)
ONEOK Partners	$	362
Distribution		217
Other		24
Total projected capital expenditures	$	603

Overland Pass Pipeline Company - - Overland Pass Pipeline Company is a joint venture between ONEOK Partners and a subsidiary of The Williams Companies, Inc. (Williams).  A subsidiary of ONEOK Partners owns 99 percent of Overland Pass Pipeline Company and operates the pipeline.  On or before November 17, 2010, Williams has the option to increase its ownership in Overland Pass Pipeline Company up to a total of 50 percent, with the purchase price being determined in accordance with the joint venture’s operating agreement.

Credit Ratings - ONEOK’s and ONEOK Partners’ credit ratings as of March 31, 2010, 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 commercial paper is rated P2 by Moody’s and A2 by S&P.  ONEOK’s and ONEOK Partners’ credit ratings, which are currently 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, pretax and after-tax interest coverage, and liquidity.  ONEOK and ONEOK Partners do not currently anticipate their respective credit ratings to be downgraded.  However, if our credit ratings were downgraded, the interest rates on our commercial paper borrowings and borrowings under the ONEOK Credit Agreement would increase, and we could potentially

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lose access to the commercial paper market.  Likewise, ONEOK Partners would see increased borrowing costs under the ONEOK Partners Credit Agreement.  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 Credit Agreement, which expires in July 2011.  An adverse rating change alone is not a default under the ONEOK Credit Agreement or the ONEOK Partners Credit Agreement but could trigger repurchase obligations with respect to certain ONEOK Partners’ long-term debt.  See additional discussion about our credit ratings under “Long-term Financing.”

If ONEOK Partners’ repurchase obligations are triggered, it may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause it to borrow money under its credit facilities, seek alternative financing sources or sell assets to finance the repurchases and repayment.  ONEOK Partners could also face difficulties accessing capital or its borrowing costs could increase, impacting its ability to obtain financing for acquisitions or capital expenditures, to refinance indebtedness and to fulfill its debt obligations.

Our Energy Services segment relies upon the investment-grade credit 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, 2010, ONEOK could have been required to fund approximately $9.4 million in margin requirements related to financial contracts upon such a downgrade.  A decline in ONEOK’s credit rating below investment grade may also significantly impact other business segments.

Other than ONEOK Partners’ note repurchase obligations and the margin requirements for our Energy Services segment described above, we have determined that we do not have significant exposure to rating triggers under ONEOK’s trust indentures, building leases, equipment leases and other various contracts.  Rating triggers are defined as provisions that would create an automatic default or acceleration of indebtedness based on a change in our credit rating.

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

Commodity Prices - We are subject to commodity price volatility.  Significant fluctuations in commodity prices may impact our overall liquidity due to the impact commodity price changes have on our cash flows from operating activities, including the impact on working capital for NGLs and natural gas held in storage, margin requirements and certain energy-related receivables.  We believe that ONEOK’s and ONEOK Partners’ available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity price volatility.  See discussion beginning on page 50 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 is included in Note K of the Notes to Consolidated Financial Statements in our Annual Report.  See Note G of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.

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CASH FLOW ANALYSIS

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

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

	Three Months Ended						Variances
	March 31,						2010 vs. 2009
	2010			2009			Increase (Decrease)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	558.7		$	790.9		$	(232.2	)	(29	%)
Investing activities		(66.4	)		(238.6	)		172.2		72	%
Financing activities		(354.3	)		(985.6	)		631.3		64	%
Change in cash and cash equivalents		138.0			(433.3	)		571.3		*
Cash and cash equivalents at beginning of period		29.4			510.1			(480.7	)	(94	%)
Cash and cash equivalents at end of period	$	167.4		$	76.8		$	90.6		*
* Percentage change is greater than 100 percent.

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

Cash flows from operating activities, before changes in operating assets and liabilities, were $289.9 million for the three months ended March 31, 2010, compared with $257.0 million for the same period in 2009.  The increase was due primarily to higher realized storage differentials and marketing margins in our Energy Services segment and increased volumes gathered, fractionated and transported, primarily associated with the completion of the Arbuckle Pipeline, Piceance lateral and D-J Basin lateral, as well as new NGL supply connections in our ONEOK Partners segment.

The changes in operating assets and liabilities increased operating cash flows $268.8 million for the three months ended March 31, 2010, compared with an increase of $533.9 million for the same period in 2009, primarily as a result of the following:

·a decrease in cash collateral and margin requirements in our Energy Services segment;

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

·the changes in volumes of commodities in storage; and

  ·   the timing of payments for purchases of commodities and other expenses resulting in decreased accounts payable; offset partially by

·   the timing of cash receipts from our revenues resulting in decreased accounts receivable.

Investing Cash Flows - Cash used in investing activities decreased for the three months ended March 31, 2010, compared with the same period in 2009, due primarily to reduced capital expenditures as a result of the completion of ONEOK Partners’ capital projects included under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Capital Projects,” in our Annual Report.

Financing Cash Flows - Net repayments of notes payable were $0.6 billion during the first quarter of 2010, compared with net repayments of $1.3 billion for the first quarter of 2009.

In February 2010, ONEOK Partners completed an underwritten public offering of 5,500,900 common units, including the partial exercise by the underwriters of their over-allotment option, at a public offering price of $60.75 per common unit, generating net proceeds of approximately $322.7 million.  In conjunction with the offering, ONEOK Partners GP contributed $6.8 million in order to maintain its 2 percent general partner interest.  ONEOK Partners used the proceeds from the sale of

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common units and the general partner contribution to repay borrowings under the ONEOK Partners Credit Agreement and for general partnership purposes. 

In March 2009, ONEOK Partners completed an underwritten public offering of senior notes and received proceeds totaling approximately $498.3 million, net of discounts but before offering expenses.  ONEOK Partners used the net proceeds from the notes to repay borrowings under the ONEOK Partners Credit Agreement.

In February 2009, ONEOK repaid $100.0 million of maturing long-term debt with available cash and short-term borrowings.

Dividends paid were $0.44 per share during the first quarter of 2010, compared with dividends of $0.40 per share during the first quarter of 2009.

Distributions paid to limited partners by ONEOK Partners were $1.10 per unit during the first quarter of 2010, compared with distributions of $1.08 per unit during the first quarter of 2009.

ENVIRONMENTAL AND SAFETY MATTERS

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

Pipeline Safety - We are subject to United States Department of Transportation regulations, including integrity management regulations.  The Pipeline Safety Improvement Act of 2002 requires pipeline companies to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high consequence areas.  We are in compliance with all material requirements associated with the various pipeline safety regulations.  We cannot provide assurance that existing pipeline safety regulations will not be revised or interpreted in a different manner or that new regulations will not be adopted that could result in increased compliance costs or additional operating restrictions.

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

The United States Congress is actively considering legislation to reduce greenhouse gas emissions, including carbon dioxide and methane.  In addition, other federal, state and regional initiatives to regulate greenhouse gas emissions are under way.  We are monitoring federal and state legislation to assess the potential impact on our operations.  We estimate our direct greenhouse gas emissions annually as we collect all applicable greenhouse gas emission data for the previous year.  Our most recent estimate for ONEOK and ONEOK Partners indicates that our emissions are less than 5 million metric tons of carbon dioxide equivalents on an annual basis.  We expect to complete our annual estimate for 2009 during the second quarter of 2010 and will post the information on our Web site when available.  We will continue efforts to improve our ability to quantify our direct greenhouse gas emissions and will report such emissions as required by the EPA’s Mandatory Greenhouse Gas Reporting rule released in September 2009.  The rule requires greenhouse gas emissions reporting for affected facilities on an annual basis, beginning with our 2010 emissions report that will be due in March 2011 and will require us to track the emission equivalents for the gas delivered by us to our distribution customers and emission equivalents for all NGLs delivered to customers of ONEOK Partners.  Also, the EPA has recently released a proposed subpart to the Mandatory Greenhouse Gas Reporting Rule that will require the reporting of vented and fugitive emissions of methane from our facilities.  The new requirements are proposed to begin in January 2011, with the first reporting of fugitive emissions due March 31, 2012.  At this time, no legislation has been enacted as to what costs, fees or expenses will be associated with any of these emissions.

The EPA is proposing to finalize the “Tailoring Rule” that will regulate greenhouse gas emissions at certain facilities that emit more than 25,000 tons of greenhouse gas emissions per year.  Under the Prevention of Significant Deterioration requirement for existing facilities, upon making a major modification to a facility, the facility would be required to obtain permits that demonstrate they have installed the best available technology to control greenhouse gas emissions.  The rule is expected to be phased in beginning January 2011 and could impact some of our facilities.  At this time, potential costs, fees or expenses associated with the proposed “Tailoring Rule” are unknown.

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

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

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

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

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

We continue to focus on maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices to limit the release of natural gas during pipeline and facility maintenance and operations.  Our most recent calculation of our annual lost-and-unaccounted-for natural gas, for all of our business operations, is less than 1 percent of total throughput.  We expect to complete our annual estimate for 2009 during the second quarter of 2010 and will post the information on our Web site when available.

FORWARD-LOOKING STATEMENTS

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

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

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

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could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:

·   the effects of weather and other natural phenomena on our operations, 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, environmental compliance, climate change initiatives, and authorized rates of recovery of gas and gas transportation costs;

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

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

·   the impact of unforeseen changes in interest rates, equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension 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 and receipt of expected clearances involving the OCC, KCC, Texas regulatory authorities or any other local, state or federal regulatory body, including the FERC;

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

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

·   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;

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

·   the risk of a prolonged slowdown in growth or decline in the U.S. economy or the risk of delay in growth recovery in the United States economy, including liquidity risks in United States 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 gas distribution franchises or other adverse effects caused by the actions of municipalities;

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

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

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

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

·   the impact of potential impairment charges;

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

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

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

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

ITEM 3.                      QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

COMMODITY PRICE RISK

See Note C of the Notes to Consolidated Financial Statements and the discussion under 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 Energy Marketing and Risk Management Assets and Liabilities - The following table sets forth the fair value component of our energy marketing and risk management assets and liabilities, excluding $139.6 million of net assets from derivative instruments designated as either fair value or cash flow hedges at March 31, 2010, and $0.6 million of deferred option premiums at March 31, 2010:

Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities
	(Thousands of dollars)
Net fair value of derivatives outstanding at December 31, 2009	$	2,725
Derivatives reclassified or otherwise settled during the period		32
Fair value of new derivatives entered into during the period		3,341
Other changes in fair value		(1,296	)
Net fair value of derivatives outstanding at March 31, 2010 (a)	$	4,802
(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: $3.2 million matures  through March 2011 and $1.6 million matures through March 2012 .

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

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

Value-at-Risk (VAR) Disclosure of Market Risk -We measure commodity price risk in our Energy Services segment using a VAR methodology, which estimates the expected maximum loss of our portfolio over a specified time horizon within a given confidence interval.  Our VAR calculations are based on the Monte Carlo approach.  The quantification of commodity price risk using VAR provides a consistent measure of risk across diverse energy markets and products with different risk factors in order to set overall risk tolerance and to determine risk thresholds.  The use of this methodology requires a number of key assumptions, including the selection of a confidence level and the holding period to liquidation.  Inputs to the calculation include prices, volatilities, positions, instrument valuations and the variance-covariance matrix.  Historical data is used to estimate our VAR with more weight given to recent data, which is considered a more relevant predictor of immediate future commodity market movements.  We rely on VAR to determine the potential reduction in the portfolio values arising from changes in market conditions over a defined period.  While management believes that the referenced assumptions and approximations are reasonable, no uniform industry methodology exists for estimating VAR.  Different assumptions and approximations could produce materially different VAR estimates.

Our VAR exposure represents an estimate of potential losses that would be recognized due to adverse commodity price movements in our Energy Services segment’s portfolio of derivative financial instruments, physical commodity contracts, leased transport, storage capacity contracts and natural gas in storage.  A one-day time horizon and a 95 percent confidence level are used in our VAR data.  Actual future gains and losses will differ from those estimated by the VAR calculation based on actual fluctuations in commodity prices, operating exposures and timing thereof, and the changes in our derivative financial instruments, physical contracts and natural gas in storage.  VAR information should be evaluated in light of these assumptions and the methodology’s other limitations.

The potential impact on our future earnings was $5.8 million and $7.0 million at March 31, 2010 and 2009, 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		2010		2009
	(Millions of dollars)
Average		$	6.4	$	10.1
High		$	9.6	$	14.1
Low		$	3.9	$	6.2

ITEM 4.                      CONTROLS AND PROCEDURES

Quarterly Evaluation of Disclosure Controls and Procedures - As of the end of the period covered by this report, our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer) evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.  Based on their evaluation, they concluded that as of March 31, 2010, our disclosure controls and procedures were effective in ensuring that the information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Changes in Internal Controls Over Financial Reporting - We have made no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the first quarter ended March 31, 2010, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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.

Thomas F. Boles, et al. v. El Paso Corporation, et al. (f/k/a Will Price, et al. v. Gas Pipelines, et al.,  f/k/a Quinque Operating Company, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 99C30 (“Boles I”) - As previously reported, we, our division Oklahoma Natural Gas, and four subsidiaries, ONEOK Partners, Mid-Continent Market Center, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK WesTex Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP, successor to Koch Hydrocarbon Company), as well as approximately 225 other defendants, are defendants in a lawsuit claiming underpayment of gas purchase proceeds.  The plaintiffs initially asserted that the defendants understated both the volume and the heating content of the purchased gas, and sought class certification for gas producers and royalty owners throughout the United States.  The Court refused to certify the class and the plaintiffs amended their petition to limit the purported class to gas producers and royalty owners in Kansas, Colorado and Wyoming, and limited the claim to undermeasurement of volume.  On September 18, 2009, the Court denied the plaintiffs’ motions for class certification, which, in effect, limited the named plaintiffs to pursuing individual claims against only those defendants who purchased or measured their gas.  On October 2, 2009, the plaintiffs filed a motion for reconsideration of the Court’s denial of class certification.  On March 31, 2010, the Court denied the plaintiffs motion for reconsideration.

Thomas F. Boles, et al. v. El Paso Corporation, et al. (f/k/a Will Price and Stixon Petroleum, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 03C232 (“Boles II”) - - As previously reported, 21 groups of defendants, including us, our division Oklahoma Natural Gas, four subsidiaries of ONEOK Partners, Mid-Continent Market Center, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK WesTex Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP, successor to Koch Hydrocarbon Company), are defendants in a lawsuit claiming underpayment of gas producers and royalty owners by allegedly understating the heating content of purchased gas in Kansas, Colorado and Wyoming.  This action was filed by the plaintiffs after the Court denied the initial motion for class status in Boles I, and Boles II was consolidated with Boles I to determine whether either or both cases may properly be certified.  On September 18, 2009, the Court denied the plaintiffs’ motions for class certification, which, in effect, limited the named plaintiffs to pursuing individual claims against only those defendants who purchased or measured their gas.  On October 2, 2009, the plaintiffs filed a motion for reconsideration of the Court’s denial of class certification.  On March 31, 2010, the Court denied the plaintiffs motion for reconsideration.

Gas Index Pricing Litigation -As previously reported, we, our subsidiary ONEOK Energy Services Company, L.P. (“OESC”) and one other affiliate are defending, either individually or together, against multiple lawsuits claiming damages resulting from the alleged market manipulation or false reporting of prices to gas index publications by us and others.  On February 2, 2010, the Missouri Court of Appeals, Western District, denied the plaintiff’s motion for a rehearing on the dismissal granted in the Missouri Public Service Commission v. ONEOK, Inc., et al., case.  On April 20, 2010, the Missouri Supreme Court granted the application of the plaintiff to transfer the case to the Missouri Supreme Court for review of the decision of the Missouri Court of Appeals that affirmed the dismissal of the case by the trial court.  On April 21, 2010, the U.S. Court of Appeals for the Ninth Circuit reversed the dismissal of the Sinclair case and remanded it back to the multi-district litigation matter MDL-1566 in the U.S. District Court for the District of Nevada for further proceedings.  On April 23, 2010, the Tennessee Supreme Court reversed the decision of the Tennessee Court of Appeals in the Leggett case and dismissed the claims of the plaintiffs.  We continue to vigorously defend against the claims involved in each of the remaining cases.

ITEM 1A.                      RISK FACTORS

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

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

Issuer Purchases of Equity Securities

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

Period	Total Number of Shares Purchased		Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Be Purchased Under the Plans or Programs
January 1-31, 2010	3,106	(a), (b)	$19.64		-		-
February 1-28, 2010	7,589	(a)	$23.92		-		-
March 1-31, 2010	105,319	(a)	$27.86		-		-
Total	116,014		$27.39		-		-
(a) - Includes shares withheld pursuant to attestation of ownership and deemed tendered to us in connection with the exercise
of stock options under the ONEOK, Inc. Long-Term Incentive Plan, as follows:
3,000 shares for the period of January 1-31, 2010
7,589 shares for the period of February 1-28, 2010
105,319 shares for the period of March 1-31, 2010
(b) - Includes shares repurchased directly from employees, pursuant to our Employee Stock Award Program, as follows:
106 shares for the period January 1-31, 2010

ITEM 3.                      DEFAULTS UPON SENIOR SECURITIES

Not Applicable.

ITEM 4.                      (REMOVED AND RESERVED)

Not Applicable.

ITEM 5.                      OTHER INFORMATION

Not Applicable.

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ITEM 6.                      EXHIBITS

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

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

Exhibit No.            Exhibit Description

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

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

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

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

101.INS XBRL Instance Document

101.SCH XBRL Taxonomy Extension Schema Document

101.CAL XBRL Taxonomy Calculation Linkbase Document

101.DEF XBRL Taxonomy Extension Definitions Document

101.LAB XBRL Taxonomy Label Linkbase Document

101.PRE XBRL Taxonomy Presentation Linkbase Document

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

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

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

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SIGNATURE

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

	ONEOK, Inc. Registrant
Date: April 29, 2010	By:	/s/ Curtis L. Dinan
		Curtis L. Dinan Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

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