Edgar Filing: ONEOK INC /NEW/

oke_10-q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2009

___ 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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes No __

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

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

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

Yes __ No X

On April 27, 2009, the Company had 105,301,805 shares of common stock outstanding.

ONEOK, Inc.

QUARTERLY REPORT ON FORM 10-Q

Part I.	Financial Information	Page No.
Item 1.	Financial Statements (Unaudited)
	Consolidated Statements of Income - Three Months Ended March 31, 2009 and 2008	5
	Consolidated Balance Sheets - March 31, 2009 and December 31, 2008	6-7
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2009 and 2008	9
	Consolidated Statement of Shareholders’ Equity - Three Months Ended March 31, 2009	10-11
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2009 and 2008	12
	Notes to Consolidated Financial Statements	13-29
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30-49
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50
Item 4.	Controls and Procedures	51
Part II.	Other Information
Item 1.	Legal Proceedings	51
Item 1A.	Risk Factors	51
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	52
Item 3.	Defaults Upon Senior Securities	52
Item 4.	Submission of Matters to a Vote of Security Holders	52
Item 5.	Other Information	52
Item 6.	Exhibits	52
Signature		53

As used in this Quarterly Report on Form 10-Q, 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 on Form 10-Q 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,” “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 on Form 10-Q and under Part I, Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2008.

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GLOSSARY

The abbreviations, acronyms and industry terminology used in this Quarterly Report on Form 10-Q are defined as follows:

AFUDC

Allowance for funds used during construction

ARB	Accounting Research Bulletin

Bbl	Barrels, 1 barrel is equivalent to 42 United States gallons

Bbl/d

Barrels per day

BBtu/d

Billion British thermal units per day

Bcf	Billion cubic feet

Bcf/d

Billion cubic feet per day

Btu	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

EBITDA

Earnings before interest, taxes, depreciation and amortization

EITF	Emerging Issues Task Force

Exchange Act

Securities Exchange Act of 1934, as amended

FASB	Financial Accounting Standards Board

FERC	Federal Energy Regulatory Commission

Fort Union Gas Gathering

Fort Union Gas Gathering, L.L.C.

FSP	FASB Staff Position

GAAP	Accounting principles generally accepted in the United States of America

Guardian Pipeline

Guardian Pipeline, L.L.C.

KCC	Kansas Corporation Commission

KDHE	Kansas Department of Health and Environment

LDC	Local Distribution Company

LIBOR

London Interbank Offered Rate

MBbl	Thousand barrels

MBbl/d

Thousand barrels per day

Mcf	Thousand cubic feet

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 Partners

ONEOK Partners, L.P.

ONEOK Partners GP

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

sole general partner of ONEOK Partners, L.P.

OPIS	Oil Price Information Service

Overland Pass Pipeline Company

Overland Pass Pipeline Company LLC

S&P	Standard & Poor’s Rating Group

SEC	Securities and Exchange Commission

Statement

Statement of Financial Accounting Standards

AVAILABLE INFORMATION

We make available on our Web site copies of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, 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.

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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)		2009			2008
	(Thousands of dollars, except per share amounts)

Revenues		$	2,789,827		$	4,902,076
Cost of sales and fuel			2,238,416			4,316,164
Net Margin			551,411			585,912
Operating Expenses
Operations and maintenance			161,719			167,992
Depreciation and amortization			72,126			59,479
General taxes			25,227			25,331
Total Operating Expenses			259,072			252,802
Gain (Loss) on Sale of Assets			664			13
Operating Income			293,003			333,123
Equity earnings from investments (Note L)			21,222			27,783
Allowance for equity funds used during construction			9,003			8,496
Other income			1,665			3,232
Other expense			(3,944	)		(4,608	)
Interest expense			(77,961	)		(62,861	)
Income before Income Taxes			242,988			305,165
Income taxes			(79,439	)		(92,368	)
Net Income			163,549			212,797
Net income attributable to noncontrolling interests			(41,264	)		(68,960	)
Net Income Attributable to ONEOK		$	122,285		$	143,837

Earnings Per Share of Common Stock (Note M)
Net Earnings Per Share, Basic		$	1.16		$	1.38
Net Earnings Per Share, Diluted		$	1.16		$	1.36

Average Shares of Common Stock (Thousands)
Basic			105,162			104,170
Diluted			105,733			105,821

Dividends Declared Per Share of Common Stock		$	0.40		$	0.38
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	March 31,		December 31,
(Unaudited)	2009		2008
Assets	(Thousands of dollars)

Current Assets
Cash and cash equivalents	$	76,753	$	510,058
Accounts receivable, net		1,014,142		1,265,300
Gas and natural gas liquids in storage		443,244		858,966
Commodity exchanges and imbalances		49,734		56,248
Energy marketing and risk management assets (Notes B and C)		280,962		362,808
Deposits		102,355		105,798
Other current assets		71,539		218,424
Total Current Assets		2,038,729		3,377,602

Property, Plant and Equipment
Property, plant and equipment		9,688,778		9,476,619
Accumulated depreciation and amortization		2,252,123		2,212,850
Net Property, Plant and Equipment (Note J)		7,436,655		7,263,769

Investments and Other Assets
Goodwill and intangible assets		1,036,309		1,038,226
Energy marketing and risk management assets (Notes B and C)		60,550		45,900
Investments in unconsolidated affiliates (Note L)		747,990		755,492
Other assets		619,731		645,073
Total Investments and Other Assets		2,464,580		2,484,691
Total Assets	$	11,939,964	$	13,126,062
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	March 31,			December 31,
(Unaudited)	2009			2008
Liabilities and Shareholders’ Equity	(Thousands of dollars)

Current Liabilities
Current maturities of long-term debt (Note G)	$	18,200		$	118,195
Notes payable (Note F)		986,700			2,270,000
Accounts payable		798,625			1,122,761
Commodity exchanges and imbalances		130,199			188,030
Energy marketing and risk management liabilities (Notes B and C)		77,084			175,006
Other current liabilities		436,702			319,772
Total Current Liabilities		2,447,510			4,193,764

Long-term Debt, excluding current maturities (Note G)		4,602,756			4,112,581

Deferred Credits and Other Liabilities
Deferred income taxes		866,497			890,815
Energy marketing and risk management liabilities (Notes B and C)		16,892			46,311
Other deferred credits		765,176			715,052
Total Deferred Credits and Other Liabilities		1,648,565			1,652,178

Commitments and Contingencies (Note I)

Shareholders’ Equity

ONEOK Shareholders’ Equity
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 122,103,602 shares
and outstanding 105,293,253 shares at March 31, 2009;
issued 121,647,007 shares and outstanding 104,845,231
shares at December 31, 2008		1,221			1,216
Paid in capital		1,301,849			1,301,153
Accumulated other comprehensive loss (Note D)		(56,152	)		(70,616	)
Retained earnings		1,633,238			1,553,033
Treasury stock, at cost: 16,810,349 shares at March 31,
2009 and 16,801,776 shares at December 31, 2008		(696,863	)		(696,616	)
Total ONEOK Shareholders’ Equity		2,183,293			2,088,170

Noncontrolling Interests in Consolidated Subsidiaries		1,057,840			1,079,369

Total Shareholders’ Equity		3,241,133			3,167,539
Total Liabilities and Shareholders’ Equity	$	11,939,964		$	13,126,062
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)	2009			2008
Operating Activities	(Thousands of dollars)
Net income	$	163,549		$	212,797
Depreciation and amortization		72,126			59,479
Allowance for equity funds used during construction		(9,003	)		(8,496	)
Gain on sale of assets		(664	)		(13	)
Equity earnings from investments		(21,222	)		(27,783	)
Distributions received from unconsolidated affiliates		25,187			24,040
Deferred income taxes		23,624			29,362
Stock-based compensation expense		4,173			7,982
Allowance for doubtful accounts		(822	)		2,035
Changes in assets and liabilities (net of acquisition and disposition effects):
Accounts receivable		251,980			(7,065	)
Gas and natural gas liquids in storage		404,416			488,214
Deposits		3,443			(52,052	)
Accounts payable		(311,252	)		119,795
Commodity exchanges and imbalances, net		(51,317	)		(24,686	)
Energy marketing and risk management assets and liabilities		(32,921	)		33,626
Accrued interest		38,623			50,293
Unrecovered purchased gas costs		42,445			26,802
Fair value of firm commitments		153,391			(50,686	)
Other assets and liabilities		35,102			(13,129	)
Cash Provided by Operating Activities		790,858			870,515
Investing Activities
Changes in investments in unconsolidated affiliates		3,362			3,311
Acquisitions		-			2,450
Capital expenditures (less allowance for equity funds used during construction)		(243,027	)		(339,531	)
Proceeds from sale of assets		1,083			161
Cash Used in Investing Activities		(238,582	)		(333,609	)
Financing Activities
Borrowing (repayment) of notes payable, net		(813,300	)		63,000
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	)		-
Payment of debt		(104,037	)		(405,504	)
Repurchase of common stock		(247	)		(15	)
Issuance of common stock		2,509			1,533
Issuance of common units, net of discounts		-			140,369
Dividends paid		(42,080	)		(39,536	)
Distributions to noncontrolling interests		(52,751	)		(47,118	)
Cash Used in Financing Activities		(985,581	)		(287,271	)
Change in Cash and Cash Equivalents		(433,305	)		249,635
Cash and Cash Equivalents at Beginning of Period		510,058			19,105
Cash and Cash Equivalents at End of Period	$	76,753		$	268,740
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY


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

December 31, 2008		121,647,007		$	1,216	$	1,301,153	$	(70,616	)
Net income		-			-		-		-
Other comprehensive income (loss) (Note D)		-			-		-		14,464
Repurchase of common stock		-			-		-		-
Common stock issued		456,595			5		696		-
Common stock dividends -
$0.40 per share		-			-		-		-
Distributions paid		-			-		-		-
March 31, 2009		122,103,602		$	1,221	$	1,301,849	$	(56,152	)
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
(Continued)

	ONEOK Shareholders							Noncontrolling Interests in Consolidated Subsidiaries

											Total
		Retained			Treasury						Shareholders’
		Earnings			Stock						Equity
	(Thousands of dollars)

December 31, 2008		$	1,553,033		$	(696,616	)	$	1,079,369		$	3,167,539
Net income			122,285			-			41,264			163,549
Other comprehensive income (loss) (Note D)			-			-			(10,042	)		4,422
Repurchase of common stock			-			(247	)		-			(247	)
Common stock issued			-			-			-			701
Common stock dividends -
$0.40 per share			(42,080	)		-			-			(42,080	)
Distributions paid			-			-			(52,751	)		(52,751	)
March 31, 2009		$	1,633,238		$	(696,863	)	$	1,057,840		$	3,241,133

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	Three Months Ended
	March 31,
(Unaudited)	2009			2008
	(Thousands of dollars)

Net income	$	163,549		$	212,797
Other comprehensive income (loss), net of tax
Unrealized gains (losses) on energy marketing and risk management
assets/liabilities, net of tax		60,497			(52,321	)
Unrealized holding gains (losses) arising during the period, net of tax		188			(4,764	)
Realized gains in net income, net of tax		(53,919	)		(7,267	)
Change in pension and postretirement benefit plan liability, net of tax		(2,534	)		(2,469	)
Other		190			-
Total other comprehensive income (loss), net of tax (Note D)		4,422			(66,821	)
Comprehensive Income		167,971			145,976
Comprehensive income attributable to noncontrolling interests		31,222			70,247
Comprehensive Income Attributable to ONEOK	$	136,749		$	75,729
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

A. SUMMARY OF 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 2008 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 on Form 10-K for the year ended December 31, 2008. Due to the seasonal nature of our business, the results of operations for the three months ended March 31, 2009, are not necessarily indicative of the results that may be expected for a 12-month period.

Our accounting policies are consistent with those disclosed in Note A of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008. The following recently issued accounting pronouncements will affect our consolidated financial statements during 2009.

Noncontrolling Interests - In December 2007, the FASB issued Statement 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51,” which requires noncontrolling interest (previously referred to as minority interest) to be reported as a component of equity. Statement 160 was effective for our year beginning January 1, 2009, and requires retroactive adoption of the presentation and disclosure requirements for existing minority interests.

Derivative Instruments and Hedging Activities - In March 2008, the FASB issued Statement 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment to FASB Statement No. 133,” which required enhanced disclosures about how derivative and hedging activities affect our financial position, financial performance and cash flows. Statement 161 was effective for our year beginning January 1, 2009, and was applied prospectively. See Note C for applicable disclosures.

Fair Value Measurements - As of January 1, 2009, we have applied the provisions of Statement 157, “Fair Value Measurements,” to assets and liabilities that are measured at fair value on a nonrecurring basis subsequent to initial recognition, and the impact was not material. See Note B for disclosures of our fair value measurements.

Interim Disclosures about Fair Value - In April 2009, the FASB issued FSP 107-1 and Accounting Principles Board (APB) Opinion No. 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” which amends Statement 107, “Disclosures about Fair Value of Financial Instruments,” and also amends APB Opinion No. 28, “Interim Financial Reporting.” FSP 107-1 and APB 28-1 require disclosures of fair value of financial instruments for interim reporting periods and will be effective for our June 30, 2009, Quarterly Report on Form 10-Q.

Postretirement Benefit Plan Assets - In December 2008, the FASB issued FSP 132R-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets,” which amends Statement 132R, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” to require enhanced disclosures about our plan assets, including our investment policies, major categories of plan assets, significant concentrations of risk within plan assets, and inputs and valuation techniques used to measure the fair value of plan assets. FSP 132R-1 is effective for our fiscal year ending December 31, 2009, and will be applied prospectively.

Reclassifications

Certain amounts in our consolidated financial statements have been reclassified to conform to the 2009 presentation. These reclassifications did not impact previously reported net income.

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B. FAIR VALUE MEASUREMENTS

Refer to Notes A and C of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008, for a discussion of our fair value measurements and the fair value hierarchy.

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

	March 31, 2009
	Level 1			Level 2			Level 3			Netting (a)			Total
	(Thousands of dollars)
Assets
Derivatives	$	93,065		$	471,127		$	540,937		$	(763,617	)	$	341,512
Trading securities		5,813			-			-			-			5,813
Available-for-sale investment securities		1,971			-			-			-			1,971
Total assets	$	100,849		$	471,127		$	540,937		$	(763,617	)	$	349,296

Liabilities
Derivatives	$	(121,694	)	$	(350,648	)	$	(370,699	)	$	749,065		$	(93,976	)
Fair value of firm commitments		-			-			(111,212	)		-			(111,212	)
Total liabilities	$	(121,694	)	$	(350,648	)	$	(481,911	)	$	749,065		$	(205,188	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities, including cash collateral in accordance with FSP FIN 39-1, when a legally enforceable master netting arrangement exists between us and the counterparty to a derivative contract. At March 31, 2009, we held $94.6 million of cash collateral and had posted $80.1 million of cash collateral with various counterparties.

	December 31, 2008
	Level 1			Level 2			Level 3			Netting (a)			Total
	(Thousands of dollars)
Assets
Derivatives	$	580,029		$	215,116		$	454,377		$	(840,814	)	$	408,708
Trading securities		4,910			-			-			-			4,910
Available-for-sale investment securities		1,665			-			-			-			1,665
Fair value of firm commitments		-			-			42,179			-			42,179
Total assets	$	586,604		$	215,116		$	496,556		$	(840,814	)	$	457,462

Liabilities
Derivatives	$	(501,726	)	$	(55,705	)	$	(412,022	)	$	748,136		$	(221,317	)
Long-term debt swapped to floating		-			-			(171,455	)		-			(171,455	)
Total liabilities	$	(501,726	)	$	(55,705	)	$	(583,477	)	$	748,136		$	(392,772	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities, including cash collateral in accordance with FSP FIN 39-1, when a legally enforceable master netting arrangement exists between us and the counterparty to a derivative contract. At December 31, 2008, we held $92.7 million of cash collateral.

In accordance with Statement 157, “Fair Value Measurements,” we categorize derivatives for which fair value is determined based on 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 that are utilized to determine the fair value of certain non-exchange traded financial instruments, including natural gas and crude oil swaps.

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Our Level 3 inputs are based on over-the-counter quotes, market volatilities derived from NYMEX-settled prices, internally developed basis curves incorporating observable and unobservable market data, modeling techniques using observable market data and historical correlations of NGL product prices to crude oil, and spot and forward LIBOR curves. The derivatives categorized as Level 3 include over-the-counter swaps and options for natural gas and crude oil, NGL swaps and physical forward contracts, natural gas basis and swing swaps and physical forward contracts, and interest-rate swaps. Also included in Level 3 are the fair values of firm commitments and long-term debt that have been hedged.

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				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.

	Derivative Assets (Liabilities)				Fair Value of Firm Commitments			Long-Term Debt				Total
	(Thousands of dollars)
January 1, 2008	$	(54,582	)		$	42,684		$	(338,538	)		$	(350,436	)
Total realized/unrealized gains (losses):
Included in earnings		(100,626	)	(a)		92,854	(a)		(9,167	)	(b)		(16,939	)
Included in other comprehensive income (loss)		23,266				-			-				23,266
Transfers in and/or out of Level 3		-				-			-				-
March 31, 2008	$	(131,942	)		$	135,538		$	(347,705	)		$	(344,109	)

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, 2008 (a)	$	(83,533	)		$	84,903		$	(9,167	)		$	(7,797	)
(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 fair value 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 terminated during the period. Transfers into Level 3 represent existing assets or liabilities that were previously categorized at a higher level for which the inputs to our models became unobservable. Transfers out of Level 3 represent existing assets and liabilities that were previously classified as Level 3 for which the inputs became observable in accordance with our hierarchy policy discussed in Note A of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K.

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Investment Securities - The following table sets forth our investment securities classified as available for sale for the periods indicated.

		March 31,		December 31,
		2009		2008
	(Thousands of dollars)
Available-for-sale securities held
Aggregate fair value		$	1,971	$	1,665
Reported in accumulated other comprehensive income (loss) for net unrealized holding gains, net of tax		$	188	$	815

For the three months ended March 31, 2009, we recorded a gain of $0.6 million, net of tax, which represents the total mark-to-market effect of trading securities still held as of March 31, 2009.

C. RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

Energy Marketing and Risk Management Activities

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 for capacity-demand payments.

Currency exchange rate risk - As a result of our operations 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 since 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 and crude oil at a specified price, requiring delivery on or settlement through the sale or purchase of an offsetting contract by a specified future date under the provisions of exchange regulations.

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

·	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, 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;

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·	locking in price differentials 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 generally executed 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 certain of our Texas jurisdictions.

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. Fixed-rate swaps may be used to reduce our risk of increased interest costs during periods of rising interest rates. Floating-rate swaps may be used to convert the fixed rates of long-term borrowings into short-term variable rates. 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 account for derivative instruments and hedging activities in accordance with Statement 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Under Statement 133, entities are required to 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.

Accounting		Recognition and Measurement
Treatment		Balance Sheet		Income Statement
Normal purchases and normal sales exception	-	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

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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.

As required by Statement 133, 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.

We evaluate the presentation of revenues from our different types of activities to determine which amounts should be reported on a gross or net basis in accordance with the following literature:

·	EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3;”

·	EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities;” and

·	EITF 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.”

In accordance with this guidance, 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 for the normal purchase or sale exception as defined in Statement 133 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.

Fair Values of Derivative Instruments

Statement 157 defines fair value as the price that would be received to sell an asset or transfer a liability in an orderly transaction between market participants at the measurement date. See Note B for a discussion of the inputs associated with our fair value measurements and our fair value hierarchy disclosures.

The following table sets forth the fair values of our derivative instruments for the period indicated.

	March 31, 2009
	Fair Values of Derivatives (a)
	Assets		(Liabilities)
	(Thousands of dollars)
Derivative commodity contracts designated as hedging
instruments	$	724,942	$	(466,111	)

Derivatives not designated as hedging instruments
Commodity contracts		380,187		(375,050	)
Foreign exchange contracts		-		(1,880	)
Total derivatives not designated as hedging instruments	$	380,187	$	(376,930	)
Total derivatives	$	1,105,129	$	(843,041	)

(a) - Included in energy marketing and risk management assets and liabilities on our Consolidated Balance Sheet.

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The following table sets forth the notional quantities for derivative instruments held for the period indicated.

	March 31, 2009
	Contract Type	Purchased/ Payor		Sold/ Receiver
Derivatives designated as hedging instruments:
Cash flow hedges
Fixed price
- Natural gas (Bcf)	Exchange futures		15.6		(30.4	)
	Swaps		28.5		(56.5	)
- Crude oil and NGLs (MMBbl)	Swaps		-		(1.8	)
Basis
- Natural gas (Bcf)	Swaps		39.3		(83.3	)
Fair value hedges
Basis
- Natural gas (Bcf)	Forwards and swaps		441.0		(389.9	)

Derivatives not designated as hedging instruments:
Fixed price
- Natural gas (Bcf)	Exchange futures		33.9		(17.9	)
	Forwards and swaps		103.3		(115.7	)
	Options		90.6		(78.5	)
- Foreign currency (Millions of dollars)	Swaps	$	9.8	$	-
Basis
- Natural gas (Bcf)	Forwards and swaps		955.2		(977.7	)
Index
- Natural gas (Bcf)	Forwards and swaps		92.2		(34.6	)

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, 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, 2009, includes gains of approximately $47.2 million, net of tax, related to these hedges that will be realized within the next 24 months as the forecasted transactions affect earnings. If prices remain at current levels, we will recognize $48.4 million in net gains over the next 12 months, and we will recognize net losses of $1.2 million thereafter.

For the three months ended March 31, 2009, cost of sales and fuel in our Consolidated Statement of Income includes $11.3 million in order to reflect inventory at the lower of cost or market. As required by Statement 133, 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 period indicated.

Derivatives in Cash Flow	Three Months Ended
Hedging Relationships	March 31, 2009
	(Thousands of dollars)
Commodity contracts		$	98,608
Interest rate contracts			121
Amount of Gain (Loss) Recognized in Other Comprehensive Income (Loss) on Derivatives (Effective Portion)		$	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 period indicated.

	Location of Gain (Loss) Reclassified from
Derivatives in Cash Flow	Accumulated Other Comprehensive Income (Loss)	Three Months Ended
Hedging Relationships	into Income (Effective Portion)	March 31, 2009
		(Thousands of dollars)
Commodity contracts	Revenues		$	82,715
Commodity contracts	Cost of sales and fuel			(1,554	)
Interest rate contracts	Interest expense			436
Total Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Income on Derivatives (Effective Portion)			$	81,597

	Location of Gain (Loss) Recognized in Income on
Derivatives in Cash Flow	Derivatives (Ineffective Portion and Amount	Three Months Ended
Hedging Relationships	Excluded from Effectiveness Testing)	March 31, 2009
		(Thousands of dollars)
Commodity contracts	Revenues		$	3,048
Commodity contracts	Cost of sales and fuel			(530	)
Total Amount of Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing)			$	2,518

Ineffectiveness related to our cash flow hedges resulted in losses of approximately $1.2 million for the three months ended March 31, 2008. 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. There were no gains or losses due to the discontinuance of cash flow hedge treatment during the three months ended March 31, 2009 and 2008, respectively.

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 period indicated.

Derivatives Not Designated as		Three Months Ended
Hedging Instruments	Location of Gain (Loss)	March 31, 2009
		(Thousands of dollars)
Commodity contracts - trading	Revenues		$	3,305
Commodity contracts - non-trading (a)	Cost of gas and fuel			(539	)
Foreign exchange contracts	Revenues			(262	)
Total Amount of Gain (Loss) Recognized in Income on Derivatives			$	2,504
(a) - For the three months ended March 31, 2009, we recognized $2.1 million 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 are being recognized in interest expense over the terms of the debt instruments originally hedged. Interest expense savings for the three months ended March 31, 2009, from amortization of terminated swaps were $2.6 million, and the remaining amortization of terminated swaps will be recognized over the following periods.

			ONEOK
	ONEOK		Partners		Total
	(Millions of dollars)
Remainder of 2009	$	4.8	$	2.8	$	7.6
2010	$	6.4	$	3.7	$	10.1
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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Based on the actual performance, during the three months ended March 31, 2009, the weighted-average interest rate on the swapped debt decreased to 5.99 percent from 6.17 percent. We and ONEOK Partners had no interest-rate swap agreements at March 31, 2009.

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 losses of $0.8 million and gains of $1.0 million for the three months ended March 31, 2009 and 2008, respectively.

For the three months ended March 31, 2009, we recognized a gain of $131.7 million related to the effect of fair value hedges as cost of sales and fuel in our Consolidated Statements of Income. The amount recognized in income from our firm commitments, which are the hedged items in our fair value hedging relationships, was a loss of $132.5 million during the first quarter of 2009.

Risk Policy and Oversight - We control the scope of risk management, marketing and trading operations through a comprehensive set of policies and procedures involving senior levels of management. The Audit Committee of our Board of Directors has oversight responsibilities for our risk management policies. Our Risk Oversight and Strategy Committee (ROSC), comprised of executive and business segment senior officers, is responsible for ensuring commodity and currency risk is monitored within the comprehensive risk management framework and that marketing, trading and hedging strategies are developed and implemented to mitigate and manage this exposure.

We have a risk control organization that is assigned responsibility for establishing and enforcing the policies and procedures and monitoring certain risk metrics. Key risk control activities include validation of transactions, portfolio valuation, value-at-risk (VAR), collateral and liquidity stress testing, and monitoring of various risk metrics. Certain VAR, mark-to-market and other thresholds have been established by the ROSC that reflect our risk tolerance. These thresholds are reviewed periodically and are set based on a number of factors, including market environment, price volatility and liquidity, and our business strategy. Our risk control organization monitors and reports on our positions and risk metrics, including timely notification to the ROSC of any thresholds that have been exceeded.

Credit Risk - We monitor the creditworthiness of our counterparties and compliance with management’s risk tolerance as determined by the ROSC. 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 which allow us to net the positive and negative exposures associated with a single counterparty. We have counterparties that are not publicly 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 derivative instruments with contingent features related to credit risk that were in a net liability position as of March 31, 2009, was $86.4 million for which ONEOK has posted collateral of $80.1 million in the normal course of business. If the contingent features underlying these agreements were triggered on March 31, 2009, we would be required to post an additional $6.3 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.

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The following table sets forth the net credit exposure from our derivative contracts for the period indicated.

	March 31, 2009
	Investment		Non-investment			Not
	Grade			Grade		Rated
Counterparty Sector	(Thousands of dollars)
Gas and electric utilities	$	134,408		$	12,632	$	22,691
Oil and gas		100,063			505		13,186
Industrial		22,244			-		376
Financial		34,159			-		-
Other		-			72		1,176
Total	$	290,874		$	13,209	$	37,429

D. OTHER COMPREHENSIVE INCOME (LOSS)

The following table sets forth the gross amount of other comprehensive income (loss) and related tax (expense) benefit for the periods indicated.

	Three Months Ended												Three Months Ended
	March 31, 2009									March 31, 2008
	Gross			Tax (Expense) or Benefit			Net			Gross			Tax (Expense) or Benefit			Net
	(Thousands of dollars)
Unrealized gains (losses) on energy marketing and risk management assets/liabilities	$	98,729		$	(38,232	)	$	60,497		$	(88,959	)	$	36,638		$	(52,321	)
Less: Gains on energy marketing and risk management assets/liabilities recognized in net income		81,597			(27,678	)		53,919			14,257			(6,990	)		7,267
Unrealized holding gains (losses) on investment securities arising during the period		306			(118	)		188			(7,769	)		3,005			(4,764	)
Change in pension and postretirement benefit plan liability		(4,133	)		1,599			(2,534	)		(4,025	)		1,556			(2,469	)
Other		241			(51	)		190			-			-			-
Other comprehensive income (loss)	$	13,546		$	(9,124	)	$	4,422		$	(115,010	)	$	48,189		$	(66,821	)
Other comprehensive income (loss) attributable to noncontrolling interests		(10,042	)		-			(10,042	)		1,287			-			1,287
Total other comprehensive income (loss) attributable to ONEOK	$	23,588		$	(9,124	)	$	14,464		$	(116,297	)	$	48,189		$	(68,108	)

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, 2008		$	27,913		$	814	$	(99,343)		$	(70,616)
Other comprehensive income (loss) attributable to ONEOK			16,810			188		(2,534)			14,464
March 31, 2009		$	44,723		$	1,002	$	(101,877)		$	(56,152)

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E. CAPITAL STOCK

Dividends - Quarterly dividends paid on our common stock to shareholders of record as of the close of business on January 30, 2009, were $0.40 per share. Additionally, a quarterly dividend of $0.40 per share was declared effective in April 2009, payable in the second quarter of 2009.

F. CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

ONEOK’s $1.2 billion amended and restated credit agreement dated July 14, 2006 (ONEOK Credit Agreement), which expires in July 2011, and ONEOK Partners’ $1.0 billion amended and restated revolving credit agreement dated March 30, 2007 (ONEOK Partners Credit Agreement), which expires in March 2012, contain certain financial and other typical covenants as discussed in Note H of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008. At March 31, 2009, ONEOK’s stand-alone debt-to-capital ratio, as calculated under the terms of the ONEOK Credit Agreement, was 47.6 percent, and ONEOK was in compliance with all covenants under the ONEOK Credit Agreement and the $400 million 364-day revolving credit facility dated August 6, 2008 (364-Day Facility). At March 31, 2009, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA (EBITDA as adjusted for all non-cash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) was 4.2 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement.

In August 2008, ONEOK entered into the 364-Day Facility. The interest rate is based, at ONEOK’s election, on either (i) the higher of prime or one-half of one percent above the Federal Funds Rate or (ii) the Eurodollar rate plus a set number of basis points based on ONEOK’s current long-term unsecured debt ratings by Moody’s and S&P. The 364-Day Facility is being used as an additional back-up to ONEOK’s commercial paper program and for working capital, capital expenditures and other general corporate purposes. The 364-Day Facility contains substantially similar affirmative and negative covenants as the ONEOK Credit Agreement, and will expire in August 2009.

At March 31, 2009, ONEOK had no commercial paper outstanding, $550 million in borrowings outstanding and $28.5 million in letters of credit issued under the ONEOK Credit Agreement, and no borrowings outstanding under the 364-Day Facility. At March 31, 2009, we had approximately $1.0 billion of credit available under the ONEOK Credit Agreement and 364-Day Facility.

At March 31, 2009, ONEOK Partners had $436.7 million in borrowings outstanding and $563.3 million of credit available under the ONEOK Partners Credit Agreement. ONEOK Partners had a total of $49.2 million issued in letters of credit outside of the ONEOK Partners Credit Agreement.

Borrowings under the ONEOK Credit Agreement, 364-Day Facility and the ONEOK Partners Credit Agreement are short-term in nature, ranging from one day to six months. Accordingly, these borrowings are classified as short-term notes payable.

G. LONG-TERM DEBT

In February 2009, ONEOK repaid $100 million of maturing long-term debt with cash from operations and short-term borrowings.

ONEOK Partners’ Debt Issuance - In March 2009, ONEOK Partners completed an underwritten public offering of $500 million aggregate principal amount of 8.625 percent Senior Notes due 2019 (2019 Notes). The 2019 Notes were issued under ONEOK Partners’ existing shelf registration statement filed with the SEC.

ONEOK Partners may redeem the 2019 Notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the 2019 Notes plus accrued and unpaid interest to the redemption date. The 2019 Notes 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 its non-guarantor subsidiaries. The 2019 Notes are nonrecourse to ONEOK.

The net proceeds from the 2019 Notes, after deducting underwriting discounts and commissions and expenses, of approximately $494.3 million were used to repay indebtedness outstanding under the ONEOK Partners Credit Agreement.

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The 2019 Notes are fully and unconditionally guaranteed on a senior unsecured basis by ONEOK Partners Intermediate Limited Partnership (Intermediate Partnership). The guarantee ranks equally in right of payment to all of the Intermediate Partnership’s existing and future unsecured senior indebtedness.

The terms of the 2019 Notes are governed by an indenture, dated as of September 25, 2006, between ONEOK Partners, L.P. and Wells Fargo Bank, N.A., as trustee, as supplemented by the Fifth Supplemental Indenture, dated March 3, 2009 (Indenture). The Indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The Indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and to sell and lease back its property.

The 2019 Notes will mature on March 1, 2019. ONEOK Partners will pay interest on the 2019 Notes on March 1 and September 1 of each year. The first payment of interest on the 2019 Notes will be made on September 1, 2009. Interest on the 2019 Notes accrues from March 3, 2009, which was the issuance date.

H. 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,
		2009			2008			2009			2008
	(Thousands of dollars)
Components of Net Periodic Benefit Cost
Service cost		$	4,984		$	5,041		$	1,293		$	1,419
Interest cost			15,205			12,451			4,230			4,475
Expected return on assets			(16,508	)		(15,317	)		(1,702	)		(1,855	)
Amortization of unrecognized net asset at adoption			-			-			797			797
Amortization of unrecognized prior service cost			391			388			(501	)		(501	)
Amortization of net loss			6,814			2,386			2,415			2,743
Net periodic benefit cost		$	10,886		$	4,949		$	6,532		$	7,078

I. COMMITMENTS AND CONTINGENCIES

Investment in Northern Border Pipeline - In March 2009, ONEOK Partners made an equity contribution of $4.3 million to Northern Border Pipeline. Northern Border Pipeline anticipates requiring an additional equity contribution of approximately $76 million from its partners in the third quarter of 2009, of which ONEOK Partners’ share will be approximately $38 million based on its 50 percent equity interest.

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 lines 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 federal 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.

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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 commenced 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 and remediation to date have not been significant in relation to our results of operations, and there were no material effects upon earnings during the three months ended March 31, 2009 or 2008 related to compliance with environmental regulations.

J. PROPERTY, PLANT AND EQUIPMENT

The following table sets forth our property, plant and equipment, by segment, for the periods indicated.

	March 31,		December 31
	2009		2008
	(Thousands of dollars)
Non-Regulated
ONEOK Partners	$	2,494,611	$	2,465,369
Energy Services		7,907		7,907
Other		230,478		225,479
Regulated
ONEOK Partners		3,487,274		3,343,310
Distribution		3,468,508		3,434,554
Property, plant and equipment		9,688,778		9,476,619
Accumulated depreciation and amortization		2,252,123		2,212,850
Net property, plant and equipment	$	7,436,655	$	7,263,769

Property, plant and equipment on our Consolidated Balance Sheets includes construction work in process for capital projects that have not yet been put in service and therefore are not being depreciated. The following table sets forth our construction work in process, by segment, for the periods indicated.

		March 31,		December 31,
		2009		2008
	(Millions of dollars)
ONEOK Partners		$	727.3	$	810.0
Distribution			35.7		57.0
Other			15.8		11.0
Total construction work in process		$	778.8	$	878.0

K. SEGMENTS

Segment Descriptions - We have divided our operations into four 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 delivers natural gas to residential, commercial and industrial customers, and transports natural gas; (iii) our Energy Services segment markets natural gas to wholesale and retail customers; and (iv) our Other segment primarily consists of the operating and leasing operations of our headquarters building and a related parking facility. Our Distribution segment is comprised of regulated public utilities, and portions of our ONEOK Partners segment are also regulated.

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Accounting Policies - The accounting policies of the segments are the same as those described in Note A and Note M of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008. Intersegment sales are recorded on the same basis as sales to unaffiliated customers and are discussed in further detail in Note N.

Customers - For the three months ended March 31, 2009 and 2008, we had no single external customer from which we received 10 percent or more of our consolidated revenues.

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

Three Months Ended March 31, 2009	ONEOK Partners (a)		Distribution (b)		Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	1,106,730	$	754,355	$	927,981	$	761		$	2,789,827
Intersegment revenues		144,135		2		185,413		(329,550	)		-
Total revenues	$	1,250,865	$	754,357	$	1,113,394	$	(328,789	)	$	2,789,827

Net margin	$	253,541	$	234,559	$	62,568	$	743		$	551,411
Operating costs		89,446		90,077		7,506		(83	)		186,946
Depreciation and amortization		39,940		31,612		145		429			72,126
Gain (loss) on sale of assets		664		-		-		-			664
Operating income	$	124,819	$	112,870	$	54,917	$	397		$	293,003

Equity earnings from investments	$	21,222	$	-	$	-	$	-		$	21,222
Investments in unconsolidated affiliates	$	747,990	$	-	$	-	$	-		$	747,990
Total assets	$	7,144,904	$	2,824,012	$	1,174,411	$	796,637		$	11,939,964
Noncontrolling interests in consolidated subsidiaries	$	5,617	$	-	$	-	$	1,052,223		$	1,057,840
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 $119.2 million, net margin of $95.9 million and operating income of $45.6 million.
(b) - All of our Distribution segment's operations are regulated.

Three Months Ended March 31, 2008	ONEOK Partners (a)		Distribution (b)			Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	1,875,700	$	913,661		$	2,111,844	$	871		$	4,902,076
Intersegment revenues		183,335		2			231,959		(415,296	)		-
Total revenues	$	2,059,035	$	913,663		$	2,343,803	$	(414,425	)	$	4,902,076

Net margin	$	268,525	$	231,688		$	84,865	$	834		$	585,912
Operating costs		88,082		94,182			10,165		894			193,323
Depreciation and amortization		29,942		28,950			378		209			59,479
Gain (loss) on sale of assets		31		(18	)		-		-			13
Operating income	$	150,532	$	108,538		$	74,322	$	(269	)	$	333,123

Equity earnings from investments	$	27,783	$	-		$	-	$	-		$	27,783
Investments in unconsolidated affiliates	$	754,304	$	-		$	-	$	-		$	754,304
Total assets	$	6,495,955	$	2,889,487		$	1,423,526	$	430,866		$	11,239,834
Noncontrolling interests in consolidated subsidiaries	$	5,851	$	-		$	-	$	959,611		$	965,462
Capital expenditures	$	267,058	$	30,649		$	-	$	41,824		$	339,531
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment's regulated operations had revenues of $115.8 million, net margin of $81.9 million and operating income of $37.6 million.
(b) - All of our Distribution segment's operations are regulated.

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L. 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,
	2009			2008
	(Thousands of dollars)
Northern Border Pipeline	$	16,038		$	19,782
Fort Union Gas Gathering		2,210			2,295
Bighorn Gas Gathering, L.L.C.		2,086			2,318
Lost Creek Gathering Company, L.L.C.		890			1,285
Other		(2	)		2,103
Equity Earnings From Investments	$	21,222		$	27,783

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,
	2009		2008
	(Thousands of dollars)
Income Statement
Operating revenue	$	106,066	$	111,395
Operating expenses	$	44,803	$	43,344
Net income	$	50,516	$	55,821

Distributions paid to us	$	33,331	$	27,413

M. 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, 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

	Three Months Ended March 31, 2008
						Per Share
		Income		Shares		Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Net income attributable to ONEOK available for common stock		$	143,837		104,170		$	1.38
Diluted EPS from continuing operations
Effect of options and other dilutive securities			-		1,651
Net income attributable to ONEOK available for common stock
and common stock equivalents		$	143,837		105,821		$	1.36

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There were 265,043 option shares excluded from the calculation of diluted EPS for the three months ended March 31, 2009, since their inclusion would have been anti-dilutive. There were no anti-dilutive option shares for the three months ended March 31, 2008.

N. ONEOK PARTNERS

The following table sets forth ONEOK Partners’ general partner and incentive distributions declared for the periods indicated.

	Three Months Ended
	March 31,
		2009		2008
	(Thousands of dollars)
General partner distributions		$	2,419	$	2,273
Incentive distributions			20,320		16,828
Total distributions to general partner		$	22,739	$	19,101

The quarterly distributions paid by ONEOK Partners to limited partners in the first quarters of 2009 and 2008 were $1.08 per unit and $1.025 per unit, respectively. In April 2009, ONEOK Partners declared a first-quarter 2009 cash distribution of $1.08 per unit payable in the second quarter.

Relationship - We own 47.7 percent of ONEOK Partners and 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. For the three months ended March 31, 2009 and 2008, cash distributions declared from ONEOK Partners to us totaled $68.5 million and $63.2 million, respectively. See Note K 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 direct costs and expenses of the Bushton Plant, including reimbursement of 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 are 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.

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

	Three Months Ended
	March 31,
	2009		2008
	(Thousands of dollars)
Revenues	$	144,135	$	183,335

Expenses
Cost of sales and fuel	$	16,638	$	35,329
Administrative and general expenses		48,623		46,901
Total expenses	$	65,261	$	82,230

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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 on Form 10-Q, as well as our Annual Report on Form 10-K for the year ended December 31, 2008. Due to the seasonal nature of our business, the results of operations for the three months ended March 31, 2009, are not necessarily indicative of the results that may be expected for a 12-month period.

EXECUTIVE SUMMARY

The following discussion highlights some of our achievements and significant issues affecting us for the periods presented. Please refer to the “Capital Projects,” “Financial Results and Operating Information,” and “Liquidity and Capital Resources” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements for additional information.

Outlook - We expect challenging economic conditions for the remainder of 2009, relative to 2008, when we experienced unprecedented drilling activity, supply growth and commodity price levels for natural gas, NGLs and crude oil. We anticipate that lower commodity prices will result in reduced drilling activity, and current economic conditions will reduce demand for NGL products from the petrochemical industry. We also expect continued volatility and disruption in the financial markets that could result in an increased cost of capital. We expect depressed commodity prices and tighter capital markets to also result in the sale or consolidation of underperforming assets in the industry, which may present opportunities for us.

Operating Results - Diluted earnings per share of common stock from continuing operations (EPS) decreased to $1.16 for the three months ended March 31, 2009, compared with $1.36 for the same period in 2008. Operating income for the three months ended March 31, 2009, decreased to $293.0 million from $333.1 million for the same period in 2008, primarily due to lower realized commodity prices and narrower NGL product location price differentials in our ONEOK Partners segment and decreases in storage, marketing and transportation margins, net of hedging activities, in our Energy Services segment. These decreases were partially offset by increased throughput from the completion of the Overland Pass Pipeline and related expansion projects, and new NGL supply connections in our ONEOK Partners segment.

ONEOK Partners Debt Issuance - In March 2009, ONEOK Partners completed an underwritten public offering of $500 million aggregate principal amount of 8.625 percent Senior Notes due 2019.

Dividends/Distributions - We declared a quarterly dividend of $0.40 per share ($1.60 per share on an annualized basis) in April 2009, an increase of approximately 5 percent over the $0.38 per share declared in April 2008. ONEOK Partners declared a cash distribution of $1.08 per unit ($4.32 per unit on an annualized basis) in April 2009, an increase of approximately 4 percent over the $1.04 per unit declared in April 2008.

Capital Projects - ONEOK Partners placed the following projects in service during the first quarter of 2009:

·	Guardian Pipeline’s expansion and extension project;

·	D-J Basin lateral pipeline; and

·	Williston Basin gas processing plant expansion.

CAPITAL PROJECTS

All of the capital projects discussed below are in our ONEOK Partners segment.

Overland Pass Pipeline - In November 2008, Overland Pass Pipeline Company completed construction of a 760-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas. The Overland Pass Pipeline is designed to transport approximately 110 MBbl/d of unfractionated NGLs and can be increased to approximately 255 MBbl/d with additional pump facilities. 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 is currently operating the pipeline. On or before November 17, 2010, Williams has the option to increase its ownership up to 50 percent, with the purchase price determined in accordance with the joint venture’s operating agreement. If Williams exercises its option to increase its ownership to the full 50 percent, Williams would have the option to become operator. If Williams does not elect to increase its ownership to at least 10 percent, ONEOK Partners

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will have the right, but not the obligation, to purchase Williams’ entire ownership interest, with the purchase price being determined in accordance with the joint venture’s operating agreement. The pipeline project cost approximately $575 million, excluding AFUDC.

As part of a long-term agreement, Williams dedicated its NGL production from two of its natural gas processing plants in Wyoming, estimated to be approximately 60 MBbl/d to the Overland Pass Pipeline. Subsidiaries of ONEOK Partners are providing downstream fractionation, storage and transportation services to Williams. ONEOK Partners has also reached agreements with certain producers for supply commitments from the D-J Basin and Piceance Lateral pipelines for up to an additional 80 MBbl/d, and is negotiating agreements with other producers for supply commitments that could add an additional 60 MBbl/d of supply to this pipeline within the next three to five years.

ONEOK Partners also invested approximately $239 million, excluding AFUDC, to expand its existing fractionation and storage capabilities and to increase the capacity of its natural gas liquids distribution pipelines. Part of this expansion included adding new fractionation facilities at ONEOK Partners’ Bushton location, which increased the total fractionation capacity at the Bushton facility to 150 MBbl/d from 80 MBbl/d. The addition of the new facilities and the upgrade to the existing fractionator was completed in October 2008. Additionally, portions of the natural gas liquids distribution pipeline upgrades were completed in the second and third quarters of 2008.

Piceance Lateral Pipeline - In October 2008, Overland Pass Pipeline Company began construction of a 150-mile lateral pipeline with capacity to transport as much as 100 MBbl/d of unfractionated NGLs from the Piceance Basin in Colorado to the Overland Pass Pipeline. Williams will dedicate its NGL production from an existing natural gas processing plant and a new natural gas processing plant, with estimated volumes totaling approximately 30 MBbl/d, to be transported by the lateral pipeline. ONEOK Partners continues to negotiate with other producers for supply commitments. Construction is expected to be completed during the third quarter of 2009, assuming ONEOK Partners has the necessary regulatory approvals to access the right-of-way during critical construction times. The project is currently estimated to cost in the range of $110 million to $140 million, excluding AFUDC.

D-J Basin Lateral Pipeline - In March 2009, Overland Pass Pipeline Company placed in service the 125-mile natural gas liquids lateral pipeline from the Denver-Julesburg Basin in northeastern Colorado to the Overland Pass Pipeline. The pipeline has capacity to transport as much as 55 MBbl/d of unfractionated NGLs. The project is currently estimated to cost approximately $70 million, excluding AFUDC. ONEOK Partners has supply commitments for up to 33 MBbl/d of unfractionated NGLs with potential for an additional 10 MBbl/d of supply from new drilling and plant upgrades in the next two years.

Arbuckle Natural Gas Liquids Pipeline - Construction continues on the 440-mile Arbuckle Pipeline, a natural gas liquids pipeline from southern Oklahoma through northern Texas and continuing on to the Texas Gulf Coast. The Arbuckle Pipeline will have the capacity to transport 160 MBbl/d of unfractionated NGLs, expandable to 210 MBbl/d with additional pump facilities, and will connect with ONEOK Partners’ existing Mid-Continent infrastructure with its fractionation facility in Mont Belvieu, Texas, and other Gulf Coast region fractionators. ONEOK Partners has supply commitments from producers that it expects will be sufficient to fill the 210 MBbl/d capacity level over the next three to five years. Much of the Oklahoma and north Texas portions of the pipeline are either complete or nearing completion. However, right-of-way acquisition has been challenging, time consuming and expensive, which could affect the completion schedule and final cost of the project. Many of Arbuckle Pipeline’s remaining right-of-way tracts are being acquired through a condemnation process, which adds to the cost and time to construct the pipeline.

The demand for surface easements has increased dramatically in Texas and Oklahoma in the last two years because of increased oil and natural gas exploration and production activities, as well as pipeline construction. As previously reported, ONEOK Partners anticipates project cost will be more expensive than originally estimated due to delays associated with right-of-way acquisition and weather impacts from anticipated spring rains in wet low-lying areas. ONEOK Partners currently expects project costs will be in the range of $395 million to $415 million, excluding AFUDC. ONEOK Partners expects the project to be operational in the second quarter of 2009.

Williston Basin Gas Processing Plant Expansion - The expansion of ONEOK Partners’ Grasslands natural gas processing facility in North Dakota has been placed in service. The expansion increases processing capacity to approximately 100 MMcf/d from its current capacity of 63 MMcf/d and increases fractionation capacity to approximately 12 MBbl/d from 8 MBbl/d. The estimated cost of the project is approximately $46 million, excluding AFUDC.

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Guardian Pipeline Expansion and Extension - In February 2009, ONEOK Partners placed the 119-mile extension of its Guardian Pipeline in full service. The pipeline has capacity to transport 537 MMcf/d of natural gas north from Ixonia, Wisconsin, to the Green Bay, Wisconsin, area. The project is supported by 15-year shipper commitments with We Energies and Wisconsin Public Service Corporation, and the capacity is close to fully subscribed. The project cost approximately $325 million, excluding AFUDC, increasing from ONEOK Partners’ previous estimate due to higher costs associated with delays related to weather and equipment delivery.

REGULATORY

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 38.

IMPACT OF NEW ACCOUNTING STANDARDS

Information about the impact of the following new accounting standards is included in Note A of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q:

·	Statement 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51;”

·	Statement 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment to FASB Statement No. 133;”

·	Statement 157, “Fair Value Measurements;”

·	FSP 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments;” and

·	FSP 132R-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.”

CRITICAL ACCOUNTING 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 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 on Form 10-K for the year ended December 31, 2008.

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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,						2009 vs. 2008
Financial Results	2009			2008			Increase (Decrease)
	(Millions of dollars)
Revenues	$	2,789.8		$	4,902.1		$	(2,112.3	)	(43	%)
Cost of sales and fuel		2,238.4			4,316.2			(2,077.8	)	(48	%)
Net margin		551.4			585.9			(34.5	)	(6	%)
Operating costs		187.0			193.3			(6.3	)	(3	%)
Depreciation and amortization		72.1			59.5			12.6		21	%
Gain (loss) on sale of assets		0.7			-			0.7		100	%
Operating income	$	293.0		$	333.1		$	(40.1	)	(12	%)
Equity earnings from investments	$	21.2		$	27.8		$	(6.6	)	(24	%)
Allowance for equity funds used during construction	$	9.0		$	8.5		$	0.5		6	%
Other income (expense), net	$	(2.3	)	$	(1.4	)	$	(0.9	)	(64	%)
Interest expense	$	(78.0	)	$	(62.9	)	$	15.1		24	%
Net income attributable to noncontrolling interests	$	(41.3	)	$	(69.0	)	$	(27.7	)	(40	%)
Capital expenditures	$	243.0		$	339.5		$	(96.5	)	(28	%)

2009 vs. 2008 - Net margin decreased primarily due to lower realized commodity prices and narrower NGL product location price differentials in our ONEOK Partners segment and a decrease in storage, marketing and transportation margins, net of hedging activities, in our Energy Services segment. These decreases were partially offset by increased throughput from the completion of the Overland Pass Pipeline and related expansion projects and new NGL supply connections in our ONEOK Partners segment, and the implementation of new rate mechanisms in our Distribution segment.

Operating costs decreased primarily due to lower general operating expenses in all segments and lower bad-debt expense in our Distribution segment. These decreases were slightly offset by costs associated with higher operating costs at ONEOK Partners’ fractionation facilities, which included incremental operating expenses associated with the recently expanded Bushton fractionator that began operations in the third quarter of 2008.

Depreciation and amortization increased primarily due to higher depreciation expense associated with ONEOK Partners’ completed capital projects.

Equity earnings from investments decreased primarily due to lower subscription rates on Northern Border Pipeline, of which ONEOK Partners owns a 50 percent interest, and decreased earnings from ONEOK Partners’ various other investments.

Interest expense increased primarily due to increased borrowings to fund ONEOK Partners’ capital projects.

Noncontrolling interests in income of consolidated subsidiaries for the three months ended March 31, 2009 and 2008, primarily reflects the remaining 52.3 percent and 52.2 percent, respectively, of ONEOK Partners that we did not own. The decrease in noncontrolling interests is due to the decrease in income for our ONEOK Partners segment.

Capital expenditures decreased due to the completion of the Overland Pass Pipeline and related projects, the Woodford Shale extension and the Guardian Pipeline expansion and extension in our ONEOK Partners segment. This decrease was partially offset by a one-time payment to terminate vehicle and other equipment leases in our Distribution segment.

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

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ONEOK Partners

Overview - At March 31, 2009, we owned a 47.7 percent equity interest in ONEOK Partners. The remaining interest in ONEOK Partners is reflected as noncontrolling interests in income of consolidated subsidiaries on our Consolidated Statements of Income and in noncontrolling interests in consolidated subsidiaries on our Consolidated Balance Sheet.

Our ONEOK Partners segment is engaged in the gathering and processing of unprocessed natural gas and fractionation of NGLs, primarily in the Mid-Continent and Rocky Mountain regions covering Oklahoma, Kansas, Montana, North Dakota and Wyoming. These operations include the gathering of unprocessed natural gas produced from crude oil and natural gas wells. Through gathering systems, unprocessed 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.

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, the Texas panhandle 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 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. 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 in Oklahoma have access to major natural gas producing areas and transport natural gas throughout the state. ONEOK Partners also has access to the major natural gas producing area in south central Kansas. In Texas, its intrastate natural gas pipelines are connected to the major natural gas producing areas in the Texas panhandle and the Permian Basin, and transport gas to the Waha Hub, where other pipelines may be accessed for transportation east to the Houston Ship Channel market, north into the Mid-Continent market and west to the California market. ONEOK Partners owns or leases storage capacity in underground natural gas storage facilities in Oklahoma, Kansas and Texas.

Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our ONEOK Partners segment for the periods indicated.

	Three Months Ended				Variances
	March 31,				2009 vs. 2008
Financial Results	2009		2008		Increase (Decrease)
	(Millions of dollars)
Revenues	$	1,250.9	$	2,059.0	$	(808.1	)	(39	%)
Cost of sales and fuel		997.4		1,790.5		(793.1	)	(44	%)
Net margin		253.5		268.5		(15.0	)	(6	%)
Operating costs		89.5		88.1		1.4		2	%
Depreciation and amortization		39.9		29.9		10.0		33	%
Gain on sale of assets		0.7		-		0.7		100	%
Operating income	$	124.8	$	150.5	$	(25.7	)	(17	%)

Equity earnings from investments	$	21.2	$	27.8	$	(6.6	)	(24	%)
Allowance for equity funds used during construction	$	9.0	$	8.5	$	0.5		6	%
Capital expenditures	$	192.5	$	267.1	$	(74.6	)	(28	%)

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	Three Months Ended
	March 31,
Operating Information	2009		2008
Natural gas gathered (BBtu/d) (a)		1,163		1,192
Natural gas processed (BBtu/d) (a)		653		624
Natural gas transported (MMcf/d)		4,200		4,075
Residue gas sales (BBtu/d) (a)		285		277
NGLs gathered (MBbl/d)		324		250
NGL sales (MBbl/d)		380		286
NGLs fractionated (MBbl/d)		465		391
NGLs transported (MBbl/d)		445		303
Conway-to-Mont Belvieu OPIS average price differential
Ethane ($/gallon)	$	0.08	$	0.09
Realized composite NGL sales prices ($/gallon) (a)	$	0.66	$	1.33
Realized condensate sales price ($/Bbl) (a)	$	62.24	$	87.51
Realized residue gas sales price ($/MMBtu) (a)	$	3.59	$	7.40
Realized gross processing spread ($/MMBtu) (a)	$	6.59	$	7.43
(a) - Statistics relate to ONEOK Partners’ natural gas gathering and processing business.

2009 vs. 2008 - Net margin decreased primarily due to the following:

·	a decrease of $27.5 million due to lower realized commodity prices in ONEOK Partners’ natural gas gathering and processing business;

·	a decrease of $16.5 million due to narrower NGL product location price differentials and lower marketing margins due to lower prices in ONEOK Partners’ natural gas liquids gathering and fractionation business; partially offset by

·	an increase of $20.4 million in ONEOK Partners’ natural gas liquids businesses, primarily due to:

o	an increase of $15.3 million in increased throughput associated with the completion of the Overland Pass Pipeline and related expansion projects, as well as new supply connections; and

o	an increase of $5.1 million due to increased throughput on ONEOK Partners’ natural gas liquids distribution pipelines, primarily due to favorable weather patterns increasing propane demand and increased shipments of natural gasoline to meet increased demand in the diluent market;

·	an increase of $8.3 million due to higher volumes processed and sold in ONEOK Partners’ natural gas gathering and processing business; and

·	an increase of $1.8 million due to higher natural gas transportation net margin, primarily as a result of the Guardian Pipeline expansion and extension being placed into service in February 2009 in ONEOK Partners’ natural gas pipelines business.

Operating costs increased primarily due to higher operating costs at ONEOK Partners’ fractionation facilities, which included incremental operating expenses associated with the recently expanded Bushton fractionator that began operations in the third quarter of 2008. These increases were partially offset by lower general operating expenses.

Depreciation and amortization increased primarily due to higher depreciation expense associated with ONEOK Partners’ completed capital projects.

Equity earnings from investments decreased primarily due to lower subscription rates on Northern Border Pipeline and decreased earnings from ONEOK Partners’ various other investments.

Capital expenditures decreased primarily due to the completion of the Overland Pass Pipeline and related projects, the Woodford Shale extension and the Guardian Pipeline expansion and extension.

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Commodity Price Risk - The following tables set forth ONEOK Partners’ hedging information for the remainder of 2009 and for the year ending December 31, 2010, as of April 29, 2009.

		Nine Months Ending
		December 31, 2009
	Volumes Hedged			Average Price			Percentage Hedged
NGLs (Bbl/d) (a)			5,981	$	1.07	/ gallon		69	%
Condensate (Bbl/d) (a)			1,410	$	2.23	/ gallon		68	%
Total (Bbl/d)			7,391	$	1.29	/ gallon		69	%
Natural gas (MMBtu/d)			8,159	$	4.20	/ MMBtu		45	%
(a) - Hedged with fixed-price swaps.

		Year Ending
		December 31, 2010
	Volumes Hedged			Average Price			Percentage Hedged
NGLs (Bbl/d) (a)			150	$	1.54	/ gallon		2	%
Condensate (Bbl/d) (a)			520	$	1.54	/ gallon		24	%
Total (Bbl/d)			670	$	1.54	/ gallon		6	%
Natural gas (MMBtu/d)			7,828	$	5.71	/ MMBtu		39	%
(a) - Hedged with fixed-price swaps.

See Note C of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q for more information on our hedging activities.

Commodity price risks related to estimated physical sales of commodities for ONEOK Partners’ natural gas gathering and processing business are estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at March 31, 2009. 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 $1.2 million;

·	a $1.00 per barrel decrease in the price of crude oil would decrease annual net margin by approximately $1.0 million; and

·	a $0.10 per MMBtu decrease in the price of natural gas would decrease annual net margin by approximately $0.7 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 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.

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Distribution

Overview - Our Distribution segment provides natural gas distribution services to more than two million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively, each a division of ONEOK. We serve residential, commercial, industrial and transportation customers in all three states. In addition, 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.

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,					2009 vs. 2008
Financial Results		2009		2008		Increase (Decrease)
	(Millions of dollars)
Gas sales		$	715.9	$	876.0	$	(160.1	)	(18	%)
Transportation revenues			26.5		27.3		(0.8	)	(3	%)
Cost of gas			519.8		682.0		(162.2	)	(24	%)
Net margin, excluding other revenues			222.6		221.3		1.3		1	%
Other revenues			12.0		10.4		1.6		15	%
Net margin			234.6		231.7		2.9		1	%
Operating costs			90.1		94.2		(4.1	)	(4	%)
Depreciation and amortization			31.6		29.0		2.6		9	%
Operating income		$	112.9	$	108.5	$	4.4		4	%
Capital expenditures		$	44.7	$	30.6	$	14.1		46	%

2009 vs. 2008 - Net margin increased primarily due to:

·	an increase of $3.8 million resulting from the implementation of new rate mechanisms, which includes a $2.4 million increase in Oklahoma, a $0.7 million increase in Kansas and a $0.7 million increase in Texas; and

·	an increase of $1.1 million related to recovery of carrying costs for natural gas in storage, partially offset by

·	a decrease of $1.9 million due to lower sales volumes due to warmer weather in the entire service territory.

Operating costs decreased primarily due to a decrease of $2.9 million in bad-debt expense and a decrease of $1.2 million in employee-related costs.

Depreciation and amortization increased primarily due to:

·	an increase of $1.2 million in depreciation expense related to our investment in property, plant and equipment; and

·	an increase of $1.5 million in regulatory amortization associated with revenue rider recoveries.

Capital Expenditures - Our capital expenditure program includes expenditures for extending service to new areas, modifying customer service lines, increasing system capabilities, general replacements and improvements. It is our practice to maintain and upgrade facilities to assure safe, reliable and efficient operations. Our capital expenditure program included $11.0 million and $11.6 million for new business development for the three months ended March 31, 2009 and 2008, respectively. Capital expenditures increased for the three months ended March 31, 2009, compared with the same period last year, due to a one-time payment to terminate vehicle and other equipment leases.

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Selected Operating Information - The following tables set forth selected operating information for our Distribution segment for the periods indicated.

	Three Months Ended
	March 31,
Volumes (MMcf)	2009		2008
Gas sales
Residential		55,357		61,280
Commercial		15,752		17,770
Industrial		512		586
Wholesale		1,134		226
Public Authority		847		999
Total volumes sold		73,602		80,861
Transportation		55,964		62,116
Total volumes delivered		129,566		142,977

	Three Months Ended
	March 31,
Margin	2009		2008
Gas Sales	(Millions of dollars)
Residential	$	156.5	$	153.9
Commercial		37.4		37.8
Industrial		0.8		0.9
Wholesale		0.1		0.1
Public Authority		1.3		1.3
Net margin on gas sales		196.1		194.0
Transportation revenues		26.5		27.3
Net margin, excluding other revenues	$	222.6	$	221.3

	Three Months Ended
	March 31,
Number of Customers	2009		2008
Residential		1,913,351		1,903,146
Commercial		160,450		164,652
Industrial		1,368		1,444
Wholesale		27		29
Public Authority		2,949		2,938
Transportation		10,746		10,136
Total customers		2,088,891		2,082,345

Residential volumes decreased for the three months ended March 31, 2009, compared with the same period last year, due to warmer temperatures in the entire service territory; however, the impact on margin decreases was moderated by weather-normalization mechanisms.

Wholesale sales represent contracted gas volumes that exceed the needs of our residential, commercial and industrial customer base and are available for sale to other parties. Wholesale volumes increased for the three months ended March 31, 2009, compared with the same period in 2008, due to increased volumes available for sale.

Regulatory Initiatives

Oklahoma - In December 2008, the OCC approved a final order to increase the recovery level of Oklahoma Natural Gas’ capital investment recovery mechanism to $12.6 million from $7.6 million annually. The recovery mechanism allows Oklahoma Natural Gas to collect a rate of return, depreciation and 50 percent of the property tax expense associated with

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incremental capital investments to maintain its facilities since its 2005 rate case. The increased recovery level was effective in January 2009.

The OCC has authorized Oklahoma Natural Gas to defer transmission pipeline Integrity Management Program (IMP) costs incurred (inclusive of operations and maintenance expense, depreciation, property taxes and a rate of return) in compliance with the Federal Pipeline Safety Improvement Act of 2002. An IMP application was made at the OCC on January 30, 2009, covering the IMP deferrals for 2008 and the true-ups associated with the prior recovery period. This filing requests a total of $10.8 million with a new IMP billing rate to be put in place in July 2009. Oklahoma Natural Gas will continue to defer IMP costs as they are incurred and will make future filings to recover those costs.

In December 2008, the OCC issued a final order authorizing Oklahoma Natural Gas to defer the fuel-related portion of bad debts for recovery in the Purchased Gas Adjustment mechanism. The associated deferrals began in January 2009.

In October 2008, a joint application for incentive-based rates was filed by the OCC staff and Oklahoma Natural Gas. This application proposes that the OCC adopt an incentive-based rate design and a more streamlined regulatory process. In April 2009, a joint stipulation was signed and filed that supports an incentive-based rate mechanism for Oklahoma Natural Gas. Upon hearing evidence and testimony supporting the joint stipulation in a hearing on April 23, 2009, the administrative law judge has recommended the OCC approve the application. A Commission Order is expected to be issued in the second quarter of 2009.

Kansas - In December 2008, the KCC approved our request to impose a surcharge designed to annually collect approximately $2.9 million in costs associated with its Gas System Recovery Surcharge (GSRS) mechanism. The GSRS mechanism allows natural gas utilities to earn a return and recover carrying charges associated with investments made to comply with state and federal pipeline safety requirements or costs to relocate existing facilities pursuant to requests made by a government entity. The authorized GSRS collections were billed effective with customer billings on January 1, 2009.

Texas - In February 2009, Texas Gas Service filed a statement of intent to increase rates in its central Texas service area for approximately $3.6 million. If approved, new rates are expected to become effective in June 2009.

In March 2009, Texas Gas Service filed a statement of intent to increase rates in its Rio Grande Valley service area for approximately $3.7 million. If approved, new rates are expected to become effective in August 2009.

General - Certain costs to be recovered through the ratemaking process have been recorded as regulatory assets in accordance with Statement 71, “Accounting for the Effects of Certain Types of Regulation.” Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria of Statement 71, 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 of Statement 71 during the three months ended March 31, 2009 and 2008.

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. These services include meeting our customers’ baseload, swing and peaking natural gas commodity requirements on a year-round basis. Our contracted storage and transportation capacity connects the major supply and demand centers throughout the United States and into Canada. With these contracted assets, our business strategies include identifying, developing and delivering specialized premium products and services valued by our customers, which are primarily LDCs, electric utilities, and commercial and industrial end users. Our storage and transportation capacity allows us opportunities to optimize value through our application of market knowledge and risk management skills.

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

Due to 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. Our Energy Services segment’s margins are subject to fluctuations during the year, primarily due to the impact certain seasonal factors have on sales volumes and the price of natural gas. 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 peak day demand obligations or market needs.

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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 to 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 on Form 10-Q 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,					2009 vs. 2008
Financial Results		2009		2008		Increase (Decrease)
	(Millions of dollars)
Revenues		$	1,113.4	$	2,343.8	$	(1,230.4	)	(53	%)
Cost of sales and fuel			1,050.9		2,258.9		(1,208.0	)	(53	%)
Net margin			62.5		84.9		(22.4	)	(26	%)
Operating costs			7.5		10.2		(2.7	)	(26	%)
Depreciation and amortization			0.1		0.4		(0.3	)	(75	%)
Operating income		$	54.9	$	74.3	$	(19.4	)	(26	%)

2009 vs. 2008 - Energy markets were affected by lower commodity prices during the first quarter of 2009, compared with the same period in 2008. The decrease in commodity prices had a direct impact on our revenues and the cost of sales and fuel.

Net margin decreased due to the following:

a decrease of $16.0 million in transportation margins, net of hedging activities, due to higher realized Mid-Continent-to-Gulf Coast margins in 2008 that resulted from hedging activities when transport spreads were significantly wider, in addition to insurance recoveries in 2008 on our Cheyenne Plains pipeline capacity curtailment;

·	a net decrease of $12.5 million in storage and marketing margins, net of hedging activities, primarily due to:

o	a decrease in storage margins, net of hedging activities, related to lower realized seasonal storage differentials; partially offset by

o	a decrease in costs associated with managing our peaking and load-following services due to warmer weather in 2009, compared with the same period in 2008; and

o	an increase in unrealized fair value gains from ineffectiveness on cash flow hedging activities related to anticipated sales and an increase in marketing margins, primarily from optimization activities; and

·	an increase of $7.0 million in financial trading margins.

Operating costs decreased due to lower employee-related costs.

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

	Three Months Ended
	March 31,
Operating Information	2009		2008
Natural gas marketed (Bcf)		329		340
Natural gas gross margin ($/Mcf)	$	0.19	$	0.17
Physically settled volumes (Bcf)		634		636

Our natural gas in storage at March 31, 2009, was 45.8 Bcf, compared with 14.6 Bcf at March 31, 2008. Our natural gas in storage levels were 31.2 Bcf higher at March 31, 2009, compared with 2008, primarily due to warmer than normal weather in

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2009, compared with 2008. In addition, we utilized flowing gas during the first quarter of 2009 to fulfill certain gas supply commitments, allowing us to forward sell our inventory and lock in margins under our hedging program. At March 31, 2009, our total natural gas storage capacity under lease was 91 Bcf, with maximum withdrawal capability of 2.2 Bcf/d and maximum injection capability of 1.4 Bcf/d. At May 1, 2009, total natural gas storage capacity under lease will decrease by 8.5 Bcf to 82.5 Bcf, and we expect to stay at that level through March 31, 2010. Our current natural gas transportation capacity is 1.9 Bcf/d.

Natural gas volumes marketed decreased for the three months ended March 31, 2009, compared with the same period in 2008, due to lower demand for natural gas resulting from warmer weather, including a nine percent decrease in heating degree days in our service territory.

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

	Three Months Ended
	March 31,
	2009			2008
	(Millions of dollars)
Marketing, storage and transportation, gross	$	111.9		$	137.7
Storage and transportation costs		(57.0	)		(54.3	)
Marketing, storage and transportation, net		54.9			83.4
Retail marketing		4.4			5.2
Financial trading		3.2			(3.7	)
Net margin	$	62.5		$	84.9

Marketing, storage and transportation, net, primarily includes marketing, purchases and sales, firm storage and transportation capacity expense, including the impact of cash flow and fair value hedges and other derivative instruments used to manage our risk associated with these activities. Risk management and operational decisions have a significant impact on the net result of our marketing and storage activities.

Retail marketing includes revenues from providing physical marketing and supply services, coupled with risk management services, to residential, municipal, and small commercial and industrial customers.

Financial trading margin 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.

Contingencies

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

Mont Belvieu Emissions, Texas Commission on Environmental Quality - As previously reported, personnel of ONEOK Hydrocarbon Southwest, L.L.C. (OHSL), a subsidiary of ONEOK Partners, are in discussions with the Texas Commission on Environmental Quality (TCEQ) staff regarding air emissions at ONEOK Partners’ Mont Belvieu fractionator, which may have exceeded the emissions allowed under its air permit. On March 13, 2009, the TCEQ issued a Notice of Enforcement, alleging that OHSL failed to isolate the source of the emissions in a timely manner. In a letter dated April 15, 2009, the TCEQ proposed settling the matter by entering into an Agreed Order with an administrative penalty of $160,000 and requiring OHSL to perform certain preventative procedures. OHSL is evaluating this proposal and preparing a response.

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LIQUIDITY AND CAPITAL RESOURCES

General - Part of our strategy is to grow through acquisitions and internally-generated growth projects that strengthen and complement our existing assets. We have relied primarily on operating cash flow, borrowings from commercial paper and credit agreements, and issuance of debt and equity in the capital markets for our liquidity and capital resource requirements. We expect to continue to use these sources for liquidity and capital resource needs on both a short- and long-term basis. We have no guarantees of debt or other similar commitments to unaffiliated parties or to ONEOK Partners.

During 2008 and continuing into 2009, the capital markets experienced volatility and disruption, which could limit our access to those markets or increase the cost of issuing new securities in the future. Higher commodity prices and wider basis differentials, particularly in 2008, have also resulted in higher collateral requirements and natural gas inventory costs in our Energy Services segment. Throughout this period, ONEOK has continued to have access to its $1.2 billion amended and restated credit agreement dated July 14, 2006 (ONEOK Credit Agreement), which expires in July 2011. ONEOK Partners has continued to have access to its $1.0 billion amended and restated revolving credit agreement dated March 30, 2007 (ONEOK Partners Credit Agreement), which has been adequate to fund its short-term liquidity needs and expires in March 2012. In addition, ONEOK has also had access to its $400 million 364-day revolving credit facility dated August 6, 2008 (364-Day Facility), which will expire in August 2009.

We expect challenging economic conditions in 2009, with downward pressures, relative to 2008, on commodity prices. We also expect continued volatility and disruption in the financial markets. ONEOK and ONEOK Partners’ ability to continue to access capital markets for debt and equity financing under reasonable terms depends on the Company’s and Partnership’s respective financial condition, 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.

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

	March 31,			December 31,
	2009			2008
Long-term debt		59	%		67	%
Equity		41	%		33	%

Debt (including notes payable)		63	%		76	%
Equity		37	%		24	%

ONEOK does not guarantee the debt of ONEOK Partners. For purposes of determining compliance with financial covenants in the ONEOK Credit Agreement and ONEOK’s 364-Day Facility, the debt of ONEOK Partners is excluded. The following table sets forth our capitalization structure, excluding the debt of ONEOK Partners for the periods indicated.

	March 31,			December 31,
	2009			2008
Long-term debt		41	%		44	%
Equity		59	%		56	%

Debt (including notes payable)		49	%		59	%
Equity		51	%		41	%

In February 2009, ONEOK repaid $100 million of maturing long-term debt with cash from operations and short-term borrowings. In February 2008, ONEOK repaid $402.3 million of maturing long-term debt with cash from operations and short-term borrowings.

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 under FERC regulations. Under these cash management

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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, the ONEOK Credit Agreement and the 364-Day Facility, as discussed below. ONEOK also has a commercial paper program that can be utilized for short-term liquidity needs to the extent funds are available under the ONEOK Credit Agreement and the 364-Day Facility. ONEOK Partners’ principal sources of short-term liquidity consist of cash generated from operating activities and borrowings under 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, 2009, ONEOK had no commercial paper outstanding, $550 million in borrowings outstanding, $28.5 million in letters of credit issued under the ONEOK Credit Agreement, no borrowings outstanding under the 364-Day Facility, and available cash and cash equivalents of approximately $75.6 million. Considering outstanding borrowings, commercial paper and letters of credit under the ONEOK Credit Agreement, ONEOK had approximately $1.0 billion of credit available at March 31, 2009, under the ONEOK Credit Agreement and the 364-Day Facility. As of March 31, 2009, ONEOK could have issued $2.7 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, 2009, ONEOK Partners had $436.7 million in borrowings outstanding and $563.3 million of credit available under the ONEOK Partners Credit Agreement, which expires in March 2012, and available cash and cash equivalents of approximately $1.1 million. As of March 31, 2009, ONEOK Partners could have issued $706.4 million of additional short- and long-term debt under the most restrictive provisions of the ONEOK Partners Credit Agreement. ONEOK Partners had a total of $49.2 million in letters of credit outstanding under agreements other than the Partnership Credit Agreement.

The ONEOK Credit Agreement , the 364-Day Facility 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 on Form 10-K, for the year ended December 31, 2008. At March 31, 2009, ONEOK’s stand-alone debt-to-capital ratio, as calculated under the terms of the ONEOK Credit Agreement, was 47.6 percent, and ONEOK was in compliance with all covenants under the ONEOK Credit Agreement and the 364-Day Facility. At March 31, 2009, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA (EBITDA, as adjusted for all non-cash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) was 4.2 to 1, and ONEOK Partners was in compliance with all covenants under 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, and asset securitization, and the sale and leaseback of facilities.

ONEOK and ONEOK Partners are subject, however, to changes in the equity and debt 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 Debt Issuance - In March 2009, ONEOK Partners completed an underwritten public offering of $500 million aggregate principal amount of 8.625 percent Senior Notes due 2019. The 2019 Notes were issued under ONEOK Partners’ existing shelf registration statement filed with the SEC.

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The 2019 Notes 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 its non-guarantor subsidiaries. The 2019 Notes are nonrecourse to ONEOK. For more information regarding the 2019 Notes, refer to discussion in Note G of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Debt Covenants - The terms of the 2019 Notes are governed by an indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., as trustee, as supplemented by the Fifth Supplemental Indenture, dated March 3, 2009 (Indenture). The Indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The Indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and to sell and lease back its property.

ONEOK Partners’ $250 million and $225 million senior notes, due 2010 and 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. 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 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.

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. Total capital expenditures were $243.0 million and $369.5 million for the three months ended March 31, 2009 and 2008, respectively. Of these amounts, ONEOK Partners’ capital expenditures were $192.5 million and $267.1 million for the three months ended March 31, 2009 and 2008, respectively. Our capital expenditures are driven primarily by ONEOK Partners’ capital projects discussed beginning on page 30.

Projected 2009 capital expenditures are significantly less than 2008 capital expenditures, primarily due to the completion of the Overland Pass Pipeline and related projects, the Woodford Shale extension and the Guardian Pipeline expansion and extension. The following table sets forth our 2009 projected capital expenditures, excluding AFUDC.

2009 Projected Capital Expenditures
	(Millions of dollars)
ONEOK Partners		$	439
Distribution			137
Other			19
Total projected capital expenditures		$	595

Credit Ratings - ONEOK’s and ONEOK Partners’ credit ratings as of March 31, 2009, 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 anticipate their respective credit ratings to be downgraded. However, if our credit ratings were downgraded, the interest rates on our commercial paper

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borrowings, the ONEOK Credit Agreement and the 364-Day Facility would increase, resulting in an increase in our cost to borrow funds, and we could potentially 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 the ONEOK Credit Agreement, which expires in July 2011, and the 364-Day Facility, which expires in August 2009. An adverse rating change alone is not a default under the ONEOK Credit Agreement, the 364-Day Facility 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 “Debt Covenants.”

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 or seek alternative financing sources 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 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, 2009, ONEOK could have been required to fund approximately $6.4 million in margin requirements related to financial contracts upon such a downgrade. A decline in ONEOK’s credit ratings 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 rating or a significant change in ONEOK’s or ONEOK Partners’ counterparties’ evaluation of our creditworthiness, ONEOK or ONEOK Partners could be asked to provide additional collateral in the form of cash, letters of credit or other negotiable instruments.

Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity prices in either physical or financial energy contracts may impact our overall liquidity due to the impact the 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 J of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008. See Note H of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q 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 on sale of assets, noncontrolling interests in income of consolidated affiliates, undistributed earnings from equity investments in excess of distributions received, deferred income taxes, stock-based compensation expense and allowance for doubtful accounts.

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,						2009 vs. 2008
	2009			2008			Increase (Decrease)
Total cash provided by (used in):	(Millions of dollars)
Operating activities	$	790.9		$	870.5		$	(79.6	)	(9	%)
Investing activities		(238.6	)		(333.6	)		95.0		28	%
Financing activities		(985.6	)		(287.3	)		(698.3	)	*
Change in cash and cash equivalents		(433.3	)		249.6			(682.9	)	*
Cash and cash equivalents at beginning of period		510.1			19.1			491.0		*
Cash and cash equivalents at end of period	$	76.8		$	268.7		$	(191.9	)	(71	%)
* Percentage change is greater than 100 percent.

Operating Cash Flows - Operating cash flows decreased partially due to changes in working capital. These changes increased operating cash flows by $533.9 million for the three months ended March 31, 2009, compared with an increase of $571.1 million for the same period in 2008. The decrease in operating cash flows was also impacted by decreased net income for the three months ended March 31, 2009, compared with the same period in 2008.

Investing Cash Flows - Investing cash flows for the three months ended March 31, 2009, include decreased capital expenditures of $96.5 million, compared with the same period in 2008, due primarily to decreased spending for ONEOK Partners’ capital projects.

Financing Cash Flows - Net notes payable repayments were $1.3 billion for the three months ended March 31, 2009, compared with borrowings of $63.0 million for the same period in 2008. The decrease in notes payable borrowings in 2009 was due to the proceeds received from the senior notes discussed below, and cash generated from operations during the winter heating season.

On March 3, 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 Partnership Credit Agreement.

In February 2009 and 2008, ONEOK repaid $100.0 million and $402.3 million, respectively, of maturing long-term debt with available cash and short-term borrowings.

In the first quarter of 2008, ONEOK Partners’ public sale of 2.5 million common units generated approximately $140.4 million, net of discounts but before offering expenses.

ENVIRONMENTAL AND SAFETY MATTERS

Information about our environmental matters is included in Note I of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Pipeline Safety - We are subject to United States Department of Transportation regulations, including integrity management regulations. The Pipeline Safety Improvement Act requires pipeline companies to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high consequence areas. To our knowledge, we are in compliance with all material requirements associated with the various pipeline safety regulations.

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Further, we cannot assure that existing pipeline safety regulations will not be revised or that new regulations will not be adopted that could result in increased compliance costs or additional operating restrictions.

Air and Water Emissions - The federal Clean Air Act, the federal 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. To our knowledge, we are in compliance with all material requirements associated with the various regulations.

The United States Congress is actively considering legislation to reduce emissions of greenhouse gases, including carbon dioxide and methane. In addition, 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, based on 2007 data, is less than 6 million metric tons of carbon dioxide equivalents on an annual basis. An updated estimate for 2008 will be posted on our Web site when available. We will continue efforts to quantify our direct greenhouse gas emissions and will report such emissions as required by any mandatory reporting rule, including the rules anticipated to be issued by the United States Environmental Protection Agency (EPA) in mid-2009.

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 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. A majority of our facilities were not tiered. We are waiting for Homeland Security’s analysis to determine if any of the tiered facilities will require Site Security Plans and possible physical security enhancements. In addition, the Transportation Security Administration and the Department of Transportation have completed a review and inspection of our “critical facilities” with no material issues.

Climate Change - 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 rules anticipated to be issued by the EPA in mid-2009; (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.

Currently, certain subsidiaries of ONEOK Partners participate in the Processing and Transmission sectors, and LDCs in our Distribution segment participate in the Distribution sector of the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions. A subsidiary in our ONEOK Partners’ segment was honored in 2008 as the “Natural Gas STAR Gathering and Processing Partner of the Year” for its efforts to positively address environmental issues through voluntary implementation of emission-reduction opportunities. In addition, we continue to focus on maintaining low rates of lost-and-unaccounted-for methane gas through expanded implementation of best practices to limit the release of methane 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 2008 during the second quarter of 2009 and will post the information on our Web site when available.

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FORWARD-LOOKING STATEMENTS

Some of the statements contained and incorporated in this Quarterly Report on Form 10-Q are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act, as amended. 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 on Form 10-Q identified by words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” and other words and terms of similar meaning.

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

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

·	competition from other United States and Canadian energy suppliers and transporters, as well as alternative forms of energy, including, but not limited to, 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 refinery-grade 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 to 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;

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

·	the impact and outcome of pending and future litigation;

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

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

-	competitive conditions in the overall energy market;

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

-	availability of additional storage capacity;

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

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

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

·	the mechanical integrity of facilities operated;

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

·	our ability to control operating costs;

·	adverse labor relations;

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

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

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

·	the impact of recently issued and future accounting pronouncements 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 Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2008. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our quantitative and qualitative disclosures about market risk are consistent with those discussed in Part II, Item 7A, Quantitative and Qualitative Disclosures About Market Risk in our Annual Report on Form 10-K for the year ended December 31, 2008.

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 on Form 10-Q for information on our hedging activities.

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 $215.9 million of net liabilities at March 31, 2009, from derivative instruments declared as either fair value or cash flow hedges, for the periods indicated.

Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities
	(Thousands of dollars)
Net fair value of derivatives outstanding at December 31, 2008 (a)		$	3,656
Derivatives reclassified or otherwise settled during the period			(5,807	)
Fair value of new derivatives entered into during the period			(1,399	)
Other changes in fair value			3,903
Net fair value of derivatives outstanding at March 31, 2009 (b)		$	353

(a) - This balance has been adjusted by $255.1 million from the amount reported in our Annual Report on Form 10-K for the year ended December 31, 2008. The adjustment was made in order to exclude from this table the gains on cash flow hedges that were reclassified into earnings from accumulated other comprehensive income (loss) related to the write down of our natural gas in storage to its lower of weighted-average cost or market.
(b) - 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: $2.6 million matures through March 2010, $(2.5) million matures through March 2011 and $0.3 million matures through March 2015.

The change in the net fair value of derivatives outstanding includes the effect of settled energy contracts and current period changes resulting primarily from newly originated transactions and the impact of market movements on the fair value of energy marketing and risk management assets and liabilities. See Note B of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q for further discussion of fair value measurements.

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 on Form 10-K for the year ending December 31, 2008. Also, see Notes B and C of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Value-at-Risk (VAR) Disclosure of Market Risk - The potential impact on our future earnings, as measured by VAR, was $7.0 million and $15.6 million at March 31, 2009 and 2008, 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		2009		2008
	(Millions of dollars)
Average		$	10.1	$	12.4
High		$	14.1	$	24.9
Low		$	6.2	$	4.0

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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, 2009, 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, 2009, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Additional information about our legal proceedings is included under Part I, Item 3, Legal Proceedings, in our Annual Report on Form 10-K for the year ended December 31, 2008.

Gas Index Pricing Litigation - As previously reported, we, 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 18, 2009, the motion to dismiss granted in the Missouri Public Service Commission case was appealed by the plaintiff to the Missouri Court of Appeals, Western District.

Additionally, on March 25, 2009, a new lawsuit, NewPage Wisconsin System Inc. v. CMS Energy Resource Management Company, et al., was filed in the Circuit Court of Wood County, Wisconsin, naming, among others, us and OESC as defendants, with claims and allegations similar to those in the other previously reported cases. We continue to analyze the claims involved in all of the cases and are vigorously defending against them.

ITEM 1A. RISK FACTORS

Our investors should consider the risks set forth in Part I, Item 1A, Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2008, 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 on Form 10-Q, 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 shown.

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, 2009		-		-		-		-
February 1-28, 2009		58	(a)	$25.50		-		-
March 1-31, 2009		-		-		-		-
Total		58		$25.50		-		-

(a) - Represents shares repurchased directly from employees, pursuant to our Employee Stock Award Program.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not Applicable.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not Applicable.

ITEM 5. OTHER INFORMATION

Not Applicable.

ITEM 6. EXHIBITS

The following exhibits are filed as part of this Quarterly Report on Form 10-Q:

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)).

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Table of Contents

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 30, 2009	By:	/s/ Curtis L. Dinan
		Curtis L. Dinan Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

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