Edgar Filing: ONEOK INC /NEW/

form_10-q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes X No __

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

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

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

Yes __ No X

On July 31, 2009, the Company had 105,394,349 shares of common stock outstanding.

Table of Contents

ONEOK, Inc.

QUARTERLY REPORT ON FORM 10-Q

Part I.	Financial Information	Page No.
Item 1.	Financial Statements (Unaudited)
	Consolidated Statements of Income - Three and Six Months Ended June 30, 2009 and 2008	5
	Consolidated Balance Sheets - June 30, 2009 and December 31, 2008	6-7
	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2009 and 2008	9
	Consolidated Statement of Shareholders’ Equity - Six Months Ended June 30, 2009	10-11
	Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2009 and 2008	12
	Notes to Consolidated Financial Statements	13-32
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33-54
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	54-55
Item 4.	Controls and Procedures	55-56
Part II.	Other Information
Item 1.	Legal Proceedings	56
Item 1A.	Risk Factors	56
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	57
Item 3.	Defaults Upon Senior Securities	57
Item 4.	Submission of Matters to a Vote of Security Holders	57
Item 5.	Other Information	57
Item 6.	Exhibits	58
Signature		59

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

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

INFORMATION AVAILABLE ON OUR WEB SITE

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

We also make available on our Web site the Interactive Data Files required to be submitted and posted pursuant to Rule 405 of Regulation S-T. In accordance with Rule 402 of Regulation S-T, the Interactive Data Files shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933 or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

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GLOSSARY

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

AFUDC

Allowance for funds used during construction

Annual Report

Annual Report on Form 10-K for the year ended December 31, 2008

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(s)

British thermal units, a measure of the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit

Bushton Plant

Bushton Gas Processing Plant

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

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

MMBbl

Million barrels

MMBtu

Million British thermal units

MMBtu/d

Million British thermal units per day

MMcf	Million cubic feet

MMcf/d

Million cubic feet per day

Moody’s

Moody’s Investors Service, Inc.

NGL products

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

NGL(s)

Natural gas liquid(s)

Northern Border Pipeline

Northern Border Pipeline Company

NYMEX

New York Mercantile Exchange

OBPI	ONEOK Bushton Processing Inc.

OCC	Oklahoma Corporation Commission

ONEOK

ONEOK, Inc.

ONEOK 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

Quarterly Report(s)

Quarterly Report(s) on Form 10-Q

S&P	Standard & Poor’s Rating Group

SEC	Securities and Exchange Commission

Statement

Statement of Financial Accounting Standards

XBRL	eXtensible Business Reporting Language

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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(Unaudited)	2009			2008			2009			2008
	(Thousands of dollars, except per share amounts)

Revenues	$	2,227,627		$	4,172,866		$	5,017,454		$	9,074,942
Cost of sales and fuel		1,795,201			3,752,038			4,033,617			8,068,202
Net margin		432,426			420,828			983,837			1,006,740
Operating expenses
Operations and maintenance		184,874			171,431			346,593			339,423
Depreciation and amortization		71,249			59,701			143,375			119,180
General taxes		25,261			16,680			50,488			42,011
Total operating expenses		281,384			247,812			540,456			500,614
Gain (loss) on sale of assets		3,762			(4	)		4,426			9
Operating income		154,804			173,012			447,807			506,135
Equity earnings from investments (Note L)		14,188			17,610			35,410			45,393
Allowance for equity funds used during construction		9,468			11,676			18,471			20,172
Other income		7,939			704			9,604			3,936
Other expense		(1,399	)		(407	)		(5,343	)		(5,015	)
Interest expense		(73,392	)		(59,059	)		(151,353	)		(121,920	)
Income before income taxes		111,608			143,536			354,596			448,701
Income taxes		(30,258	)		(30,574	)		(109,697	)		(122,942	)
Net income		81,350			112,962			244,899			325,759
Less: Net income attributable to noncontrolling interests		39,671			71,097			80,935			140,057
Net income attributable to ONEOK	$	41,679		$	41,865		$	163,964		$	185,702

Earnings per share of common stock (Note M)
Net earnings per share, basic	$	0.40		$	0.40		$	1.56		$	1.78
Net earnings per share, diluted	$	0.39		$	0.39		$	1.55		$	1.75

Average shares of common stock (thousands)
Basic		105,335			104,340			105,249			104,255
Diluted		105,950			106,072			105,848			105,947

Dividends declared per share of common stock	$	0.40		$	0.38		$	0.80		$	0.76
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	June 30,		December 31,
(Unaudited)	2009			2008
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	47,038		$	510,058
Accounts receivable, net		771,196			1,265,300
Gas and natural gas liquids in storage		564,530			858,966
Commodity exchanges and imbalances		53,417			56,248
Energy marketing and risk management assets (Notes B and C)		168,457			362,808
Other current assets		189,277			324,222
Total current assets		1,793,915			3,377,602

Property, plant and equipment
Property, plant and equipment		9,880,620			9,476,619
Accumulated depreciation and amortization		2,289,760			2,212,850
Net property, plant and equipment (Note J)		7,590,860			7,263,769

Investments and other assets
Goodwill and intangible assets		1,034,393			1,038,226
Energy marketing and risk management assets (Notes B and C)		47,163			45,900
Investments in unconsolidated affiliates (Note L)		735,394			755,492
Other assets		631,998			645,073
Total investments and other assets		2,448,948			2,484,691
Total assets	$	11,833,723		$	13,126,062
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	June 30,			December 31,
(Unaudited)	2009				2008
Liabilities and shareholders’ equity	(Thousands of dollars)
Current liabilities
Current maturities of long-term debt (Note G)	$	268,205			$	118,195
Notes payable (Note F)		689,910				2,270,000
Accounts payable		826,414				1,122,761
Commodity exchanges and imbalances		166,847				188,030
Energy marketing and risk management liabilities (Notes B and C)		41,485				175,006
Other current liabilities		444,182				319,772
Total current liabilities		2,437,043				4,193,764

Long-term debt, excluding current maturities (Note G)		4,346,285				4,112,581

Deferred credits and other liabilities
Deferred income taxes		867,015				890,815
Energy marketing and risk management liabilities (Notes B and C)		8,301				46,311
Other deferred credits		762,213				715,052
Total deferred credits and other liabilities		1,637,529				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 122,180,571 shares and outstanding
105,371,561 shares at June 30, 2009; issued 121,647,007 shares and
outstanding 104,845,231 shares at December 31, 2008		1,222				1,216
Paid in capital		1,308,141				1,301,153
Accumulated other comprehensive loss (Note D)		(82,960	)			(70,616	)
Retained earnings		1,632,795				1,553,033
Treasury stock, at cost: 16,809,010 shares at June 30, 2009 and
16,801,776 shares at December 31, 2008		(696,805	)			(696,616	)
Total ONEOK shareholders’ equity		2,162,393				2,088,170

Noncontrolling interests in consolidated subsidiaries		1,250,473				1,079,369

Total shareholders’ equity		3,412,866				3,167,539
Total liabilities and shareholders’ equity	$	11,833,723			$	13,126,062
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Six Months Ended
	June 30,
(Unaudited)	2009			2008
	(Thousands of dollars)
Operating activities
Net income	$	244,899		$	325,759
Depreciation and amortization		143,375			119,180
Allowance for equity funds used during construction		(18,471	)		(20,172	)
Gain on sale of assets		(4,426	)		(9	)
Equity earnings from investments		(35,410	)		(45,393	)
Distributions received from unconsolidated affiliates		38,233			39,904
Deferred income taxes		40,865			65,374
Stock-based compensation expense		8,551			14,416
Allowance for doubtful accounts		1,663			6,965
Changes in assets and liabilities:
Accounts receivable		492,441			194,146
Gas and natural gas liquids in storage		285,271			(85,083	)
Accounts payable		(324,364	)		261,530
Commodity exchanges and imbalances, net		(18,352	)		53,881
Energy marketing and risk management assets and liabilities		35,373			77,033
Unrecovered purchased gas costs		42,766			18,185
Fair value of firm commitments		179,582			(350,626	)
Other assets and liabilities		(36,144	)		(140,285	)
Cash provided by operating activities		1,075,852			534,805

Investing activities
Changes in investments in unconsolidated affiliates		17,393			6,480
Capital expenditures (less allowance for equity funds used during construction)		(407,600	)		(640,048	)
Proceeds from sale of assets		10,029			201
Proceeds from insurance		-			9,792
Acquisitions		-			2,450
Cash used in investing activities		(380,178	)		(621,125	)

Financing activities
Borrowing (repayment) of notes payable, net		(710,090	)		598,893
Repayment of notes payable with maturities over 90 days		(870,000	)		-
Issuance of debt, net of discounts		498,325			-
Long-term debt financing costs		(4,000	)		-
Payment of debt		(107,970	)		(408,789	)
Repurchase of common stock		(250	)		(29	)
Issuance of common stock		4,342			5,786
Issuance of common units, net of discounts		220,458			146,969
Dividends paid		(84,202	)		(79,212	)
Distributions to noncontrolling interests		(105,307	)		(97,659	)
Cash provided by (used in) financing activities		(1,158,694	)		165,959
Change in cash and cash equivalents		(463,020	)		79,639
Cash and cash equivalents at beginning of period		510,058			19,105
Cash and cash equivalents at end of period	$	47,038		$	98,744
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)		-			-		-		(12,344	)
Repurchase of common stock		-			-		-		-
Common stock issued		533,564			6		6,988		-
Common stock dividends -
$0.80 per share		-			-		-		-
Issuance of equity units		-			-		-		-
Distributions paid		-			-		-		-
June 30, 2009		122,180,571		$	1,222	$	1,308,141	$	(82,960	)
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’
(Unaudited)		Earnings			Stock						Equity
	(Thousands of dollars)

December 31, 2008		$	1,553,033		$	(696,616	)	$	1,079,369		$	3,167,539
Net income			163,964			-			80,935			244,899
Other comprehensive income (loss) (Note D)			-			-			(24,982	)		(37,326	)
Repurchase of common stock			-			(250	)		-			(250	)
Common stock issued			-			61			-			7,055
Common stock dividends -
$0.80 per share			(84,202	)		-			-			(84,202	)
Issuance of equity units			-			-			220,458			220,458
Distributions paid			-			-			(105,307	)		(105,307	)
June 30, 2009		$	1,632,795		$	(696,805	)	$	1,250,473		$	3,412,866

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(Unaudited)	2009			2008			2009			2008
	(Thousands of dollars)

Net income	$	81,350		$	112,962		$	244,899		$	325,759
Other comprehensive income (loss), net of tax
Unrealized gains (losses) on energy marketing and risk management
assets/liabilities, net of tax		(22,177	)		(66,249	)		38,469			(118,570	)
Realized (gains) losses in net income, net of tax		(16,793	)		11,267			(70,713	)		4,000
Unrealized holding gains (losses) arising during the period, net of tax		318			(682	)		505			(5,446	)
Change in pension and postretirement benefit plan liability, net of tax		(3,260	)		(2,468	)		(5,795	)		(4,937	)
Other		18			-			208			-
Total other comprehensive income (loss), net of tax (Note D)		(41,894	)		(58,132	)		(37,326	)		(124,953	)
Comprehensive income		39,456			54,830			207,573			200,806
Less: Comprehensive income attributable to noncontrolling interests		24,731			51,184			55,953			121,431
Comprehensive income attributable to ONEOK	$	14,725		$	3,646		$	151,620		$	79,375
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. Due to the seasonal nature of our business, the results of operations for the three and six months ended June 30, 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. The following recently issued accounting pronouncements will affect our consolidated financial statements during 2009.

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

Derivative Instruments and Hedging Activities - Statement 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment to FASB Statement No. 133,” requires 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 - FSP 107-1 and Accounting Principles Board (APB) Opinion No. 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” require disclosures of fair value of financial instruments for interim reporting periods, which were effective for our quarter ended June 30, 2009. These disclosures are included in Note B.

Postretirement Benefit Plan Assets - FSP 132R-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets,” requires 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, is effective for our fiscal year ending December 31, 2009, and will be applied prospectively.

Subsequent Events - Statement 165, “Subsequent Events,” establishes standards of accounting for and disclosures of events that occur after the balance sheet date but before consolidated financial statements are issued. We have evaluated subsequent events through August 6, 2009, the date our consolidated financial statements were issued, and all required disclosures have been made.

FASB Accounting Standards Codification - Statement 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles,” establishes the FASB Accounting Standards Codification as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP. Statement 168 will change the manner in which we reference authoritative accounting principles in our consolidated financial statements and will be effective for our September 30, 2009, Quarterly Report.

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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 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.

	June 30, 2009
	Level 1			Level 2			Level 3			Netting (a)			Total
	(Thousands of dollars)
Assets
Derivatives	$	258,603		$	103,849		$	635,094		$	(781,926	)	$	215,620
Trading securities		7,341			-			-			-			7,341
Available-for-sale investment securities		2,489			-			-			-			2,489
Total assets	$	268,433		$	103,849		$	635,094		$	(781,926	)	$	225,450

Liabilities
Derivatives	$	(230,180	)	$	(38,227	)	$	(464,680	)	$	683,301		$	(49,786	)
Fair value of firm commitments		-			-			(137,403	)		-			(137,403	)
Total liabilities	$	(230,180	)	$	(38,227	)	$	(602,083	)	$	683,301		$	(187,189	)
(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, when a legally enforceable master netting arrangement exists between us and the counterparty to a derivative contract. At June 30, 2009, we held $127.1 million of cash collateral and had posted $28.5 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, 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, 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 market volatilities derived from the NYMEX natural gas volatility curve, internally developed basis curves incorporating observable and unobservable market data, a pricing service for NGL products, historical correlations of NGL product prices to crude oil, forward NYMEX curves for crude oil, spot and forward LIBOR curves, and adjustments for the credit risk of our counterparties. The derivatives categorized as Level 3 include over-the-counter basis and swing swaps, physical forward contracts and options for natural gas, NGL swaps and interest-rate swaps. Also included in Level 3 are the fair values of firm commitments and long-term debt that have been hedged. We corroborate the data on which our fair value estimates are based using quotes from an independent broker of natural gas, our market knowledge of recent transactions and analysis of historical relationships of data from the pricing service compared with actual settlements and correlations. We do not believe that our Level 3 fair value estimates have a material impact on our results of operations, as the majority of our derivatives are accounted for as hedges for which ineffectiveness is not material.

The 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)
April 1, 2009	$	170,238			$	(111,212	)		$	-	$	59,026
Total realized/unrealized gains (losses):
Included in earnings		34,202		(a)		(26,191	)	(a)		-		8,011
Included in other comprehensive income (loss)		(52,330	)			-				-		(52,330	)
Transfers in and/or out of Level 3		18,304				-				-		18,304
June 30, 2009	$	170,414			$	(137,403	)		$	-	$	33,011

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 June 30, 2009 (a)	$	57,041			$	(44,189	)			-	$	12,852
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.

	Derivative Assets (Liabilities)				Fair Value of Firm Commitments			Long-Term Debt				Total
	(Thousands of dollars)
April 1, 2008	$	(131,942	)		$	135,538		$	(347,705	)		$	(344,109	)
Total realized/unrealized gains (losses):
Included in earnings		(283,285	)	(a)		257,772	(a)		7,497	(	b)		(18,016	)
Included in other comprehensive income (loss)		(27,272	)			-			-				(27,272	)
Transfers in and/or out of Level 3		32,138				-			-				32,138
June 30, 2008	$	(410,361	)		$	393,310		$	(340,208	)		$	(357,259	)

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 June 30, 2008 (a)	$	(260,918	)		$	275,631		$	7,497			$	22,210
(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.

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	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		188,038		(a)		(179,582	)	(a)		1,455		(b)		9,911
Included in other comprehensive income (loss)		(60,060	)			-				-				(60,060	)
Maturities		-				-				100,000				100,000
Terminations prior to maturity		-				-				70,000				70,000
Transfers in and/or out of Level 3		81				-				-				81
June 30, 2009	$	170,414			$	(137,403	)		$	-			$	33,011

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 June 30, 2009 (a)	$	189,866			$	(162,734	)		$	-			$	27,132
(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		(356,375	)	(a)		350,626	(a)		(1,670	)	(b)		(7,419	)
Included in other comprehensive income (loss)		(4,007	)			-			-				(4,007	)
Transfers in and/or out of Level 3		4,603				-			-				4,603
June 30, 2008	$	(410,361	)		$	393,310		$	(340,208	)		$	(357,259	)

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 June 30, 2008 (a)	$	(373,399	)		$	351,150		$	(1,670	)		$	(23,919	)
(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 was terminated during the period. Transfers into Level 3 represent existing assets or liabilities that were previously categorized at a higher level for which the inputs to our fair value estimates 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.

Investment Securities - Net unrealized holding gains, net of tax, for our investment securities classified as available for sale and reported in accumulated other comprehensive income (loss) were $1.3 million and $0.8 million as of June 30, 2009, and December 31, 2008, respectively. For the three and six months ended June 30, 2009, net unrealized holding gains on available-for-sale securities included in other comprehensive income were immaterial. For the three and six months ended June 30, 2009, we recorded net gains of $1.5 million and $2.4 million, respectively, which represents the total mark-to-market effect of trading securities still held as of June 30, 2009.

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

The estimated fair value of long-term debt, including current maturities, was $4.52 billion at June 30, 2009. The book value of long-term debt, including current maturities, was $4.61 billion at June 30, 2009. The estimated fair value of long-term debt has been determined using quoted market prices of the same or similar issues with similar terms and maturities.

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.

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

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

·	Futures contracts - Standardized exchange-traded contracts to purchase or sell natural gas 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;

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

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

Our Energy Services segment also enters into derivative contracts for financial trading purposes primarily to capitalize on opportunities created by market volatility, weather-related events, supply-demand imbalances and market liquidity

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

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

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

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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.

	June 30, 2009
	Fair Values of Derivatives (a)
	Assets		(Liabilities)
	(Thousands of dollars)

Derivative commodity contracts designated as hedging instruments	$	731,942	$	(467,630	)

Derivatives not designated as hedging instruments
Commodity contracts		265,604		(264,693	)
Foreign exchange contracts		-		(764	)
Total derivatives not designated as hedging instruments	$	265,604	$	(265,457	)
Total derivatives	$	997,546	$	(733,087	)

(a) - Included on a net basis 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.

	June 30, 2009
	Contract Type	Purchased/ Payor		Sold/ Receiver
Derivatives designated as hedging instruments:
Cash flow hedges
Fixed price
- Natural gas (Bcf)	Exchange futures		6.9		(29.4	)
	Swaps		23.5		(82.8	)
- Crude oil and NGLs (MMBbl)	Swaps		-		(2.0	)
Basis
- Natural gas (Bcf)	Swaps		29.5		(111.1	)
Fair value hedges
Basis
- Natural gas (Bcf)	Forwards and swaps		411.4		(411.3	)

Derivatives not designated as hedging instruments:
Fixed price
- Natural gas (Bcf)	Exchange futures		31.7		(13.0	)
	Forwards and swaps		90.1		(109.4	)
	Options		118.6		(95.0	)
- Foreign currency (Millions of dollars)	Swaps	$	7.1	$	-
Basis
- Natural gas (Bcf)	Forwards and swaps		891.0		(914.8	)
Index
- Natural gas (Bcf)	Forwards and swaps		74.4		(34.8	)

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

Cash Flow Hedges - Our Energy Services and ONEOK Partners segments use derivative instruments to hedge the cash flows associated with anticipated purchases and sales of natural gas, NGLs and condensate and cost of fuel used in the transportation of natural gas. Accumulated other comprehensive income (loss) at June 30, 2009, includes gains of approximately $23.3 million, net of tax, related to these hedges that will be realized within the next 21 months as the forecasted transactions affect earnings. If prices remain at current levels, we will recognize $25.4 million in net gains over the next 12 months, and we will recognize net losses of $2.1 million thereafter.

For the six months ended June 30, 2009, cost of sales and fuel in our Consolidated Statements of Income includes $11.3 million reflecting an adjustment to inventory at the lower of cost or market. We reclassified $11.3 million of deferred gains, before income taxes, on associated cash flow hedges from accumulated other comprehensive income (loss) into earnings.

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

	Three Months Ended				Six Months Ended
Derivatives in Cash Flow Hedging Relationships		June 30, 2009			June 30, 2009
		(Thousands of dollars)
Commodity contracts		$	(32,363	)	$	66,245
Interest rate contracts			443			564
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)		$	(31,920	)	$	66,809

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

Derivatives in Cash Flow Hedging Relationships	Location of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)	Three Months Ended June 30, 2009			Six Months Ended June 30, 2009
		(Thousands of dollars)
Commodity contracts	Revenues	$	31,157		$	113,872
Commodity contracts	Cost of sales and fuel		(9,624	)		(11,178	)
Interest rate contracts	Interest expense		436			872
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)		$	21,969		$	103,566

Derivatives in Cash Flow Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Three Months Ended June 30, 2009			Six Months Ended June 30, 2009
		(Thousands of dollars)
Commodity contracts	Revenues	$	(228	)	$	2,820
Commodity contracts	Cost of sales and fuel		(217	)		(747	)
Total gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)		$	(445	)	$	2,073

For the three and six months ended June 30, 2008, ineffectiveness related to our cash flow hedges resulted in losses of approximately $0.6 million and $1.8 million, respectively. 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 and six months ended June 30, 2009 and 2008.

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

Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss)	Three Months Ended June 30, 2009		Six Months Ended June 30, 2009
		(Thousands of dollars)
Commodity contracts - trading	Revenues	$	104	$	3,409
Commodity contracts - non-trading (a)	Cost of gas and fuel		2,476		1,937
Foreign exchange contracts	Revenues		585		323
Total gain (loss) recognized in income on derivatives		$	3,165	$	5,669
(a) - For the six months ended June 30, 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 is being recognized in interest expense over the terms of the debt instruments originally hedged. Interest expense savings for the six months ended June 30, 2009, from amortization of terminated swaps was $5.2 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	$	3.2	$	1.8	$	5.0
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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ONEOK and ONEOK Partners had no interest-rate swap agreements at June 30, 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 was immaterial for the six months ended June 30, 2009 and 2008.

For the three and six months ended June 30, 2009, cost of sales and fuel in our Consolidated Statements of Income include gains of $46.6 million and $178.3 million, respectively, related to the change in fair value of derivatives declared as fair value hedges. Revenues include losses of $46.6 million and $179.1 million for the three and six months ended June 30, 2009, respectively, to recognize the change in fair value of the hedged firm commitments.

Credit Risk - We monitor the creditworthiness of our counterparties and compliance with management’s risk tolerance as determined by our Risk Oversight and Strategy Committee. We maintain credit policies with regard to our counterparties that we believe minimize overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings, bond yields and credit default swap rates), collateral requirements under certain circumstances and the use of standardized master netting agreements 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 June 30, 2009, was $30.8 million for which we have posted collateral of $28.5 million in the normal course of business. If the contingent features underlying these agreements were triggered on June 30, 2009, we would be required to post an additional $2.3 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.

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

	June 30, 2009
	Investment		Non-investment		Not
	Grade		Grade		Rated
Counterparty sector	(Thousands of dollars)
Gas and electric utilities	$	87,060	$	7,913	$	7,336
Oil and gas		76,972		467		10,110
Industrial		9,263		-		264
Financial		15,533		-		11
Other		14		29		648
Total	$	188,842	$	8,409	$	18,369

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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
	June 30, 2009									June 30, 2008
	Gross			Tax (Expense) or Benefit			Net			Gross			Tax (Expense) or Benefit		Net
	(Thousands of dollars)
Unrealized losses on energy marketing and risk management assets/liabilities	$	(31,920	)	$	9,743		$	(22,177	)	$	(92,320	)	$	26,071	$	(66,249	)
Less: Gains (losses) on energy marketing and risk management assets/liabilities recognized in net income		21,969			(5,176	)		16,793			(15,217	)		3,950		(11,267	)
Unrealized holding gains (losses) on investment securities arising during the period		518			(200	)		318			(1,112	)		430		(682	)
Change in pension and postretirement benefit plan liability		(5,317	)		2,057			(3,260	)		(4,025	)		1,557		(2,468	)
Other		29			(11	)		18			-			-		-
Other comprehensive income (loss)	$	(58,659	)	$	16,765		$	(41,894	)	$	(82,240	)	$	24,108	$	(58,132	)
Less: Other comprehensive income (loss) attributable to noncontrolling interests		(14,940	)		-			(14,940	)		(19,913	)		-		(19,913	)
Total other comprehensive income (loss) attributable to ONEOK	$	(43,719	)	$	16,765		$	(26,954	)	$	(62,327	)	$	24,108	$	(38,219	)

	Six Months Ended									Six Months Ended
	June 30, 2009									June 30, 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	$	66,809		$	(28,340	)	$	38,469		$	(181,279	)	$	62,709		$	(118,570	)
Less: Gains (losses) on energy marketing and risk management assets/liabilities recognized in net income		103,566			(32,853	)		70,713			(960	)		(3,040	)		(4,000	)
Unrealized holding gains (losses) on investment securities arising during the period		824			(319	)		505			(8,881	)		3,435			(5,446	)
Change in pension and postretirement benefit plan liability		(9,450	)		3,655			(5,795	)		(8,050	)		3,113			(4,937	)
Other		270			(62	)		208			-			-			-
Other comprehensive income (loss)	$	(45,113	)	$	7,787		$	(37,326	)	$	(197,250	)	$	72,297		$	(124,953	)
Less: Other comprehensive income (loss) attributable to noncontrolling interests		(24,982	)		-			(24,982	)		(18,626	)		-			(18,626	)
Total other comprehensive income (loss) attributable to ONEOK	$	(20,131	)	$	7,787		$	(12,344	)	$	(178,624	)	$	72,297		$	(106,327	)

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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		(7,054)		505		(5,795)		(12,344)
June 30, 2009	$	20,859	$	1,319	$	(105,138)	$	(82,960)

E. CAPITAL STOCK

Dividends - Fourth-quarter 2008 and first-quarter 2009 quarterly dividends paid on our common stock to shareholders of record as of the close of business on January 30, 2009, and April 30, 2009, respectively, were $0.40 per share. Additionally, a second-quarter 2009 dividend of $0.42 per share was declared for shareholders of record on July 31, 2009, payable on August 14, 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. Among other things, the ONEOK Credit Agreement’s covenants include a limitation on ONEOK’s stand-alone debt-to-capital ratio, which may not exceed 67.5 percent at the end of any calendar quarter. At June 30, 2009, ONEOK’s stand-alone debt-to-capital ratio, as calculated under the terms of the ONEOK Credit Agreement, was 45.7 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).

ONEOK Partners Credit Agreement’s covenants include, among other things, maintaining a 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) of no more than 5 to 1. At June 30, 2009, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 4.3 to 1. ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement at June 30, 2009.

At June 30, 2009, ONEOK had $329.9 million in commercial paper outstanding and $48.0 million in letters of credit issued under the ONEOK Credit Agreement. At June 30, 2009, ONEOK had approximately $822.1 million of credit available under the ONEOK Credit Agreement and $400.0 million under the 364-Day Facility. The 364-Day Facility expired on August 5, 2009.

At June 30, 2009, ONEOK Partners had $360.0 million in borrowings outstanding and $586.5 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 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.

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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.

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 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 leaseback 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						Pension Benefits
		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2009			2008			2009			2008
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost		$	4,984		$	5,041		$	9,968		$	10,082
Interest cost			13,454			12,451			28,659			24,902
Expected return on assets			(16,508	)		(15,317	)		(33,016	)		(30,634	)
Amortization of unrecognized prior service cost			391			388			782			776
Amortization of net loss			4,330			2,386			11,144			4,772
Net periodic benefit cost		$	6,651		$	4,949		$	17,537		$	9,898

		Postretirement Benefits						Postretirement Benefits
		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2009			2008			2009			2008
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost		$	1,294		$	1,419		$	2,587		$	2,838
Interest cost			4,229			4,475			8,459			8,950
Expected return on assets			(1,702	)		(1,855	)		(3,404	)		(3,710	)
Amortization of unrecognized net asset at adoption			797			797			1,594			1,594
Amortization of unrecognized prior service cost			(501	)		(501	)		(1,002	)		(1,002	)
Amortization of net loss			2,415			2,743			4,830			5,486
Net periodic benefit cost		$	6,532		$	7,078		$	13,064		$	14,156

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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.

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

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

Our expenditures for environmental evaluation, mitigation and remediation to date have not been significant in relation to our financial position or results of operations, and there were no material effects upon earnings or cash flows during the three and six months ended June 30, 2009 and 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.

	June 30,		December 31,
	2009		2008
	(Thousands of dollars)
Non-Regulated
ONEOK Partners	$	2,522,084	$	2,465,369
Energy Services		7,907		7,907
Other		233,078		225,479
Regulated
ONEOK Partners		3,627,600		3,343,310
Distribution		3,489,951		3,434,554
Property, plant and equipment		9,880,620		9,476,619
Accumulated depreciation and amortization		2,289,760		2,212,850
Net property, plant and equipment	$	7,590,860	$	7,263,769

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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.

		June 30,		December 31,
		2009		2008
	(Thousands of dollars)
ONEOK Partners		$	793,885	$	809,978
Distribution			21,291		57,038
Other			12,570		10,984
Total construction work in process		$	827,746	$	878,000

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.

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. Intersegment sales are recorded on the same basis as sales to unaffiliated customers and are discussed in further detail in Note N. Net margin is comprised of total revenues less cost of sales and fuel. Cost of sales and fuel includes commodity purchases, fuel and transportation costs.

Customers - For the three and six months ended June 30, 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 June 30, 2009	ONEOK Partners (a)		Distribution (b)			Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	1,289,487		$	276,599	$	660,772	$	769		$	2,227,627
Intersegment revenues		107,570			2		66,339		(173,911	)		-
Total revenues	$	1,397,057		$	276,601	$	727,111	$	(173,142	)	$	2,227,627

Net margin	$	261,982		$	139,563	$	30,114	$	767		$	432,426
Operating costs		100,507			99,467		10,530		(369	)		210,135
Depreciation and amortization		39,953			30,717		146		433			71,249
Gain (loss) on sale of assets		3,276			486		-		-			3,762
Operating income	$	124,798		$	9,865	$	19,438	$	703		$	154,804

Equity earnings from investments	$	14,188		$	-	$	-	$	-		$	14,188
Capital expenditures	$	129,366		$	32,632	$	-	$	2,575		$	164,573
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment's regulated operations had revenues of $116.6 million, net margin of $96.9 million and operating income of $40.5 million.
(b) - All of our Distribution segment's operations are regulated.

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Three Months Ended June 30, 2008	ONEOK Partners (a)			Distribution (b)			Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	1,939,570			$	374,115	$	1,858,380		$	801		$	4,172,866
Intersegment revenues		204,322				2		167,284			(371,608	)		-
Total revenues	$	2,143,892			$	374,117	$	2,025,664		$	(370,807	)	$	4,172,866

Net margin	$	280,933			$	134,993	$	4,173		$	729		$	420,828
Operating costs		87,158				93,883		8,357			(1,287	)		188,111
Depreciation and amortization		30,033				29,074		198			396			59,701
Gain (loss) on sale of assets		(3	)			-		-			(1	)		(4	)
Operating income	$	163,739			$	12,036	$	(4,382	)	$	1,619		$	173,012

Equity earnings from investments	$	17,610			$	-	$	-		$	-		$	17,610
Capital expenditures	$	257,529			$	39,706	$	15		$	3,267		$	300,517
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment's regulated operations had revenues of $108.2 million, net margin of $79.0 million and operating income of $37.1 million.
(b) - All of our Distribution segment's operations are regulated.

Six Months Ended June 30, 2009	ONEOK Partners (a)		Distribution (b)			Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	2,396,217		$	1,030,954	$	1,588,753	$	1,530		$	5,017,454
Intersegment revenues		251,705			4		251,752		(503,461	)		-
Total revenues	$	2,647,922		$	1,030,958	$	1,840,505	$	(501,931	)	$	5,017,454

Net margin	$	515,523		$	374,122	$	92,682	$	1,510		$	983,837
Operating costs		189,953			189,544		18,036		(452	)		397,081
Depreciation and amortization		79,893			62,329		291		862			143,375
Gain (loss) on sale of assets		3,940			486		-		-			4,426
Operating income	$	249,617		$	122,735	$	74,355	$	1,100		$	447,807

Equity earnings from investments	$	35,410		$	-	$	-	$	-		$	35,410
Investments in unconsolidated affiliates	$	735,394		$	-	$	-	$	-		$	735,394
Total assets	$	7,400,746		$	2,680,850	$	963,681	$	788,446		$	11,833,723
Noncontrolling interests in consolidated subsidiaries	$	5,472		$	-	$	-	$	1,245,001		$	1,250,473
Capital expenditures	$	321,860		$	77,284	$	-	$	8,456		$	407,600
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment's regulated operations had revenues of $235.8 million, net margin of $192.8 million and operating income of $86.1 million.
(b) - All of our Distribution segment's operations are regulated.

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Six Months Ended June 30, 2008	ONEOK Partners (a)		Distribution (b)				Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	3,815,270		$	1,287,776		$	3,970,224	$	1,672		$	9,074,942
Intersegment revenues		387,657			4			399,243		(786,904	)		-
Total revenues	$	4,202,927		$	1,287,780		$	4,369,467	$	(785,232	)	$	9,074,942

Net margin	$	549,458		$	366,681		$	89,038	$	1,563		$	1,006,740
Operating costs		175,240			188,065			18,522		(393	)		381,434
Depreciation and amortization		59,975			58,024			576		605			119,180
Gain (loss) on sale of assets		28			(18	)		-		(1	)		9
Operating income	$	314,271		$	120,574		$	69,940	$	1,350		$	506,135

Equity earnings from investments	$	45,393		$	-		$	-	$	-		$	45,393
Investments in unconsolidated affiliates	$	752,952		$	-		$	-	$	-		$	752,952
Total assets	$	6,869,540		$	2,634,667		$	1,763,545	$	901,320		$	12,169,072
Noncontrolling interests in consolidated subsidiaries	$	5,911		$	-		$	-	$	966,794		$	972,705
Capital expenditures	$	524,587		$	70,355		$	15	$	45,091		$	640,048
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment's regulated operations had revenues of $224.0 million, net margin of $160.9 million and operating income of $74.7 million.
(b) - All of our Distribution segment's operations are regulated.

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				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(Thousands of dollars)
Northern Border Pipeline	$	5,454	$	8,880	$	21,492	$	28,661
Fort Union Gas Gathering, L.L.C.		3,805		3,464		6,015		5,759
Bighorn Gas Gathering, L.L.C.		1,824		2,005		3,910		4,323
Lost Creek Gathering Company, L.L.C.		1,312		1,797		2,202		3,082
Other		1,793		1,464		1,791		3,568
Equity earnings from investments	$	14,188	$	17,610	$	35,410	$	45,393

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(Thousands of dollars)
Income Statement
Operating revenues	$	87,951	$	95,040	$	194,017	$	206,435
Operating expenses	$	44,429	$	45,201	$	89,232	$	88,545
Net income	$	32,129	$	33,927	$	82,645	$	89,748

Distributions paid to us	$	30,142	$	33,214	$	63,473	$	60,627

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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 June 30, 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		$	41,679		105,335		$	0.40
Diluted EPS from continuing operations
Effect of options and other dilutive securities			-		615
Net income attributable to ONEOK available for common stock
and common stock equivalents		$	41,679		105,950		$	0.39

	Three Months Ended June 30, 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		$	41,865		104,340		$	0.40
Diluted EPS from continuing operations
Effect of options and other dilutive securities			-		1,732
Net income attributable to ONEOK available for common stock
and common stock equivalents		$	41,865		106,072		$	0.39

	Six Months Ended June 30, 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		$	163,964		105,249		$	1.56
Diluted EPS from continuing operations
Effect of options and other dilutive securities			-		599
Net income attributable to ONEOK available for common stock
and common stock equivalents		$	163,964		105,848		$	1.55

	Six Months Ended June 30, 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		$	185,702		104,255		$	1.78
Diluted EPS from continuing operations
Effect of options and other dilutive securities			-		1,692
Net income attributable to ONEOK available for common stock
and common stock equivalents		$	185,702		105,947		$	1.75

There were 258,225 and 261,634 option shares excluded from the calculation of diluted EPS for the three and six months ended June 30, 2009, respectively, since their inclusion would have been anti-dilutive. There were no anti-dilutive option shares for the three and six months ended June 30, 2008.

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N. ONEOK PARTNERS

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

	June 30,		December 31,
	2009		2008
General partner interest	2.0%		2.0%
Limited partner interest	43.3%	(a)	45.7%	(a)
Total ownership interest	45.3%	(b)	47.7%
(a) - Represents 5.9 million common units and approximately 36.5 million Class B units, which are convertible, at our option, into common units.
(b) - Following the July 2009 sale of additional ONEOK Partners' units, our interest in ONEOK Partners was 45.1 percent.

In June 2009, ONEOK Partners completed an underwritten public offering of 5,000,000 common units at $45.81 per common unit, generating net proceeds of approximately $219.9 million after deducting underwriting discounts but before offering expenses. In conjunction with ONEOK Partners’ public offering of common units, ONEOK Partners GP contributed $4.7 million to ONEOK Partners in order to maintain its 2 percent general partner interest.

In July 2009, ONEOK Partners sold an additional 486,690 common units at $45.81 per common unit to the underwriters of the public offering upon the partial exercise of their option to purchase additional common units to cover over-allotments. ONEOK Partners received net proceeds of approximately $21.4 million from the sale of the common units after deducting underwriting discounts but before offering expenses. In conjunction with the partial exercise by the underwriters, ONEOK Partners GP contributed $0.5 million to ONEOK Partners in order to maintain its 2 percent general partner interest. Following these transactions, our interest in ONEOK Partners is 45.1 percent.

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

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2009		2008		2009		2008
	(Thousands of dollars)
General partner distributions		$	2,551	$	2,346	$	4,970	$	4,619
Incentive distributions			21,437		18,574		41,757		35,403
Total distributions to general partner		$	23,988	$	20,920	$	46,727	$	40,022

The quarterly distributions paid by ONEOK Partners to limited partners in each of the first and second quarters of 2009 were $1.08 per unit. The quarterly distributions paid by ONEOK Partners to limited partners in the first and second quarters of 2008 were $1.025 per unit and $1.04 per unit, respectively. In July 2009, ONEOK Partners declared a second-quarter 2009 cash distribution of $1.08 per unit payable in the third quarter.

Relationship - We consolidate ONEOK Partners in our consolidated financial statements; however, we are restricted from the assets and cash flows of ONEOK Partners except for our distributions. Distributions are declared quarterly by ONEOK Partners’ general partner based on the terms of the ONEOK Partners partnership agreement. For the three months ended June 30, 2009 and 2008, cash distributions declared from ONEOK Partners to us totaled $69.8 million and $65.9 million, respectively. For the six months ended June 30, 2009 and 2008, cash distributions declared from ONEOK Partners to us totaled $138.3 million and $129.0 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

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also purchases natural gas from our Energy Services segment for its natural gas liquids and natural gas gathering and processing operations.

ONEOK Partners has certain contractual rights to our Bushton Plant through a Processing and Services Agreement with us, which sets out the terms for processing and related services we provide at the Bushton Plant through 2012. ONEOK Partners has contracted for all of the capacity of the Bushton Plant from our wholly owned subsidiary, OBPI. In exchange, ONEOK Partners pays OBPI for all costs and expenses 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. It is not practicable to determine what these general overhead costs would be on a stand-alone basis.

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

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2009		2008		2009		2008
	(Thousands of dollars)
Revenues		$	107,570	$	204,322	$	251,705	$	387,657

Expenses
Cost of sales and fuel		$	9,416	$	24,731	$	26,054	$	60,060
Administrative and general expenses			49,855		43,333		98,478		90,234
Total expenses		$	59,271	$	68,064	$	124,532	$	150,294

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ITEM 2.

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

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and the Notes to Consolidated Financial Statements in this Quarterly Report, as well as our Annual Report. Due to the seasonal nature of our business, the results of operations for the three and six months ended June 30, 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 to persist for the remainder of 2009 and into 2010, compared with 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 continue to result in reduced drilling activity, and current economic conditions will result in reduced demand for NGL products from the petrochemical industry. Although ONEOK has been able to access the commercial paper markets, and ONEOK Partners has been able to access the debt and equity markets for the liquidity and capital resource needs of each in 2009, we expect continued volatility and possible disruption in the financial markets, which could limit our access to those markets or increase the cost of issuing new securities in the future. We expect that depressed commodity prices and tighter capital markets will 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) were $0.39 for the three months ended June 30, 2009, and 2008. For the six-month period, EPS decreased to $1.55 from $1.75 for the same period last year. Operating income for the three months ended June 30, 2009, decreased to $154.8 million from $173.0 million for the same period last year. For the six months ended June 30, 2009, operating income decreased to $447.8 million from $506.1 million for the same period last year. These decreases were primarily due to lower realized commodity prices in our ONEOK Partners segment and were partially offset by increased NGL throughput as a result of the completion of the Overland Pass Pipeline and related expansion projects, as well as new NGL supply connections in our ONEOK Partners segment.

ONEOK Partners Equity Issuance - In June 2009, ONEOK Partners completed an underwritten public offering of 5,000,000 common units at $45.81 per common unit, generating net proceeds of approximately $219.9 million after deducting underwriting discounts but before offering expenses. In conjunction with ONEOK Partners’ public offering of common units, ONEOK Partners GP contributed $4.7 million to ONEOK Partners in order to maintain its 2 percent general partner interest.

As a result of these transactions, our interest in ONEOK Partners is 45.1 percent.

ONEOK Partners used the proceeds from the sale of common units and the general partner contributions to repay borrowings under its $1.0 billion amended and restated revolving credit agreement dated March 30, 2007 (ONEOK Partners Credit Agreement) and for general partnership purposes.

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. ONEOK Partners used the proceeds from the offering to repay indebtedness outstanding under the ONEOK Partners Credit Agreement.

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Dividends/Distributions - We declared a quarterly dividend of $0.42 per share ($1.68 per share on an annualized basis) in July 2009, an increase of approximately 5 percent from the $0.40 per share declared in July 2008. ONEOK Partners declared a cash distribution of $1.08 per unit ($4.32 per unit on an annualized basis) in July 2009, an increase of approximately 2 percent from the $1.06 per unit declared in July 2008.

Capital Projects - ONEOK Partners placed the following projects in service during the first six months 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. At the end of the second quarter 2009, approximately 85 MBbl/d were flowing on Overland Pass Pipeline. 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 in Overland Pass Pipeline Company, which includes the Piceance Lateral and D-J Basin Lateral pipeline projects, up to 50 percent, with the purchase price being determined in accordance with the joint venture’s operating agreement. If Williams exercises its option to increase its ownership to 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 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 70 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, Kansas 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 were 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. 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 cost was approximately $70 million, excluding AFUDC. Volumes are expected to exceed 31 MBbl/d during the third quarter of 2009, with the potential for an additional 10 MBbl/d from new drilling and plant upgrades in the next two years.

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Arbuckle Natural Gas Liquids Pipeline - In July 2009, ONEOK Partners completed construction of the 440-mile Arbuckle pipeline project, a natural gas liquids pipeline system that delivers unfractionated NGLs from points in southern Oklahoma and Texas to the Texas Gulf Coast. The Arbuckle pipeline system has the capacity to transport 160 MBbl/d of unfractionated NGLs, expandable to 210 MBbl/d with additional pump facilities, and connects with ONEOK Partners’ existing Mid-Continent infrastructure with its fractionation facility in Mont Belvieu, Texas, and other Gulf Coast region fractionators. ONEOK Partners has NGL production dedicated from existing and new natural gas processing plants that it expects will be sufficient to fill the 210 MBbl/d capacity level over the next three to five years.

The demand for surface easements increased dramatically in Texas and Oklahoma over the last two years because of increased oil and natural gas exploration and production activities, as well as pipeline construction. As previously reported, project costs have been more expensive than originally estimated due to delays associated with right-of-way acquisition and difficult construction conditions associated with several weeks of heavy spring rains, resulting in greatly reduced construction productivity. ONEOK Partners has also experienced increased costs due to a number of scope changes, arising primarily from additional supply development opportunities. ONEOK Partners currently estimates project costs will be approximately $490 million, excluding AFUDC. ONEOK Partners began filling the pipeline with product in July 2009, and expects to place the project in service in August 2009, with volumes reaching 65 MBbl/d by the end of the third quarter of 2009.

Williston Basin Gas Processing Plant Expansion - The expansion of ONEOK Partners’ Grasslands natural gas processing facility in North Dakota was placed in service in March 2009. The expansion increased processing capacity to approximately 100 MMcf/d from its previous capacity of 63 MMcf/d and increased fractionation capacity to approximately 12 MBbl/d from 8 MBbl/d. The cost of the project was approximately $46 million, excluding AFUDC.

Guardian Pipeline Expansion and Extension - In February 2009, ONEOK Partners completed the 119-mile extension of its Guardian Pipeline. 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.

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 43.

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:

·	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;”

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

·	Statement 165, “Subsequent Events;” and

·	Statement 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles.”

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.

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Impairment of Goodwill - We assess our goodwill for impairment at least annually. Our July 1, 2009, impairment test will be completed in the third quarter of 2009. As part of our impairment test, an initial assessment is made by comparing the fair value of a reporting unit with its book value, including goodwill. To estimate the fair value of our reporting units, we use two generally accepted valuation approaches, an income approach and a market approach. Under the income approach, we use anticipated cash flows over a period of years plus a terminal value and discount these amounts to their present value using appropriate rates of return. Under the market approach, we apply multiples to forecasted EBITDA amounts. The multiples used are consistent with historical asset transactions, and the EBITDA amounts are based on average EBITDA for a reporting unit over a three-year forecasted period.

There were no impairment charges resulting from our July 1, 2008, impairment test. As a result of events in the financial markets and deteriorating economic conditions following our July 1, 2008, impairment test, we performed subsequent reviews and determined that interim testing of goodwill was not indicated. Our estimates of fair value significantly exceeded the book value of our reporting units in our July 1, 2008, impairment test and our subsequent reviews. Even if the estimated fair values used in our impairment test were reduced by 10 percent, no impairment charges would have resulted from our July 1, 2008 impairment test. At June 30, 2009, and December 31, 2008, we had $602.8 million of goodwill recorded on our Consolidated Balance Sheets.

Derivatives and Risk Management - We utilize financial instruments to reduce our market risk exposure to commodity price and interest rate risk. We do not believe that changes in our fair value estimates of our derivative instruments have a material impact on our results of operations, as the majority of our derivatives are accounted for as hedges for which ineffectiveness is not material. See Notes B and C of the Notes to Consolidated Financial Statements in this Quarterly Report for additional discussion of our fair value measurements and derivatives and risk management activities.

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						Six Months Ended						Increase (Decrease)					Increase (Decrease)
		June 30,						June 30,						Three Months					Six Months
Financial Results		2009			2008			2009			2008			2009 vs. 2008					2009 vs. 2008
	(Millions of dollars)
Revenues		$	2,227.6		$	4,172.9		$	5,017.4		$	9,074.9		$	(1,945.3	)	(47	%)	$	(4,057.5	)	(45	%)
Cost of sales and fuel			1,795.2			3,752.1			4,033.6			8,068.2			(1,956.9	)	(52	%)		(4,034.6	)	(50	%)
Net margin			432.4			420.8			983.8			1,006.7			11.6		3	%		(22.9	)	(2	%)
Operating costs			210.1			188.1			397.1			381.4			22.0		12	%		15.7		4	%
Depreciation and amortization			71.2			59.7			143.4			119.2			11.5		19	%		24.2		20	%
Gain (loss) on sale of assets			3.7			-			4.5			-			3.7		100	%		4.5		100	%
Operating income		$	154.8		$	173.0		$	447.8		$	506.1		$	(18.2	)	(11	%)	$	(58.3	)	(12	%)
Equity earnings from investments		$	14.2		$	17.6		$	35.4		$	45.4		$	(3.4	)	(19	%)	$	(10.0	)	(22	%)
Allowance for equity funds used during construction		$	9.5		$	11.7		$	18.5		$	20.2		$	(2.2	)	(19	%)	$	(1.7	)	(8	%)
Other income (expense)		$	6.5		$	0.3		$	4.3		$	(1.1	)	$	6.2		*		$	5.4		*
Interest expense		$	(73.4	)	$	(59.1	)	$	(151.4	)	$	(121.9	)	$	14.3		24	%	$	29.5		24	%
Net income attributable to noncontrolling interests		$	39.7		$	71.1		$	80.9		$	140.1		$	(31.4	)	(44	%)	$	(59.2	)	(42	%)
Capital expenditures		$	164.6		$	300.5		$	407.6		$	640.0		$	(135.9	)	(45	%)	$	(232.4	)	(36	%)
* Percentage change is greater than 100 percent.

Net margin increased for the three months ended June 30, 2009, compared with the same period last year, primarily due to the following:

·	increased NGL throughput as a result of the completion of the Overland Pass Pipeline and related expansion projects, as well as new NGL supply connections in our ONEOK Partners segment;

·	an increase in transportation margins, net of hedging activities, in our Energy Services segment;

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·	incremental natural gas transportation margins from the Guardian Pipeline expansion and extension that was placed into service in early 2009 in our ONEOK Partners segment; and

·	the implementation of new rate mechanisms in our Distribution segment; partially offset by

·	lower realized commodity prices and narrower NGL product price differentials in our ONEOK Partners segment.

Net margin decreased for the six months ended June 30, 2009, compared with the same period last year, primarily due to the following:

·	lower realized commodity prices and narrower NGL product price differentials in our ONEOK Partners segment; partially offset by

·	increased NGL throughput as a result of the completion of the Overland Pass Pipeline and related expansion projects, as well as new NGL supply connections in our ONEOK Partners segment;

·	incremental natural gas transportation margins from the Guardian Pipeline expansion and extension that was placed into service in early 2009 in our ONEOK Partners segment;

·	higher volumes processed and sold in our ONEOK Partners segment’s gathering and processing business; and

·	the implementation of new rate mechanisms in our Distribution segment.

Operating costs increased for the three and six months ended June 30, 2009, compared with the same periods last year, primarily due to higher operating costs at ONEOK Partners’ NGL fractionation facilities, which included incremental operating expenses associated with the recently expanded Bushton Plant that resumed operations in the third quarter of 2008, the operations of Overland Pass Pipeline that began in the fourth quarter of 2008, and increased employee-related costs in our Distribution and Energy Services segments. These increases were slightly offset by lower bad-debt expense in our Distribution segment.

Depreciation and amortization expense increased for the three and six months ended June 30, 2009, compared with the same periods last year, primarily due to higher depreciation expense associated with ONEOK Partners’ completed capital projects.

Equity earnings from investments decreased for the three and six months ended June 30, 2009, compared with the same periods last year, primarily due to lower subscription volumes and rates on Northern Border Pipeline, of which ONEOK Partners owns a 50 percent interest, and lower volumes gathered in ONEOK Partners’ various other equity investments.

Interest expense increased for the three and six months ended June 30, 2009, compared with the same periods last year, primarily due to increased borrowings by ONEOK Partners to fund its capital projects.

Noncontrolling interests in income of consolidated subsidiaries for the three and six months ended June 30, 2009 and 2008, primarily reflects the remaining 54.7 percent and 52.3 percent, respectively, of ONEOK Partners that we do not own. The decrease in noncontrolling interests is due to the decrease in income for our ONEOK Partners segment.

Capital expenditures decreased for the three and six months ended June 30, 2009, compared with the same periods last year, due to the completion of the Overland Pass Pipeline and related expansion projects, the Williston Basin gas processing plant expansion 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.

ONEOK Partners

Overview - We currently own a 45.1 percent equity interest in ONEOK Partners. The remaining interest in ONEOK Partners is reflected as net income attributable to noncontrolling interests on our Consolidated Statements of Income and in noncontrolling interests in consolidated subsidiaries on our Consolidated Balance Sheets. See Note N of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information on the ONEOK Partners’ equity issuance and related transactions.

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

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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 table sets forth certain selected financial results for our ONEOK Partners segment for the periods indicated.

		Three Months Ended				Six Months Ended				Increase (Decrease)					Increase (Decrease)
		June 30,				June 30,				Three Months					Six Months
Financial Results		2009		2008		2009		2008		2009 vs. 2008					2009 vs. 2008
	(Millions of dollars)
Revenues		$	1,397.1	$	2,143.9	$	2,647.9	$	4,202.9	$	(746.8	)	(35	%)	$	(1,555.0	)	(37	%)
Cost of sales and fuel			1,135.1		1,863.0		2,132.3		3,653.4		(727.9	)	(39	%)		(1,521.1	)	(42	%)
Net margin			262.0		280.9		515.6		549.5		(18.9	)	(7	%)		(33.9	)	(6	%)
Operating costs			100.5		87.2		190.0		175.2		13.3		15	%		14.8		8	%
Depreciation and amortization			40.0		30.0		79.9		60.0		10.0		33	%		19.9		33	%
Gain on sale of assets			3.3		-		3.9		-		3.3		100	%		3.9		100	%
Operating income		$	124.8	$	163.7	$	249.6	$	314.3	$	(38.9	)	(24	%)	$	(64.7	)	(21	%)

Equity earnings from investments		$	14.2	$	17.6	$	35.4	$	45.4	$	(3.4	)	(19	%)	$	(10.0	)	(22	%)
Allowance for equity funds used during construction		$	9.5	$	11.7	$	18.5	$	20.2	$	(2.2	)	(19	%)	$	(1.7	)	(8	%)
Capital expenditures		$	129.4	$	257.5	$	321.9	$	524.6	$	(128.1	)	(50	%)	$	(202.7	)	(39	%)

Net margin decreased for the three months ended June 30, 2009, compared with the same period last year, primarily due to the following:

·	a decrease of $34.0 million due to significantly lower realized commodity prices in ONEOK Partners’ natural gas gathering and processing business;

·	a decrease of $7.4 million due to the impact of lower natural gas prices on retained fuel in ONEOK Partners’ natural gas pipelines businesses; and

·	a decrease of $7.1 million due to narrower NGL product price differentials in ONEOK Partners’ natural gas liquids gathering and fractionation business; partially offset by

·	an increase of $23.5 million in ONEOK Partners’ natural gas liquids businesses primarily due to increased NGL throughput as a result of the completion of the Overland Pass Pipeline and related expansion projects, as well as new NGL supply connections; and

·	incremental net margin of $8.3 million due to the Guardian Pipeline expansion and extension that was placed into service in early 2009 in ONEOK Partners’ natural gas pipelines business.

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Net margin decreased for the six months ended June 30, 2009, compared with the same period last year, primarily due to the following:

·	a decrease of $61.4 million due to significantly lower realized commodity prices in ONEOK Partners’ natural gas gathering and processing business;

·	a decrease of $28.0 million due to narrower NGL product price differentials in ONEOK Partners’ natural gas liquids gathering and fractionation business;

·	a decrease of $11.7 million due to the impact of lower natural gas prices on retained fuel in ONEOK Partners’ natural gas pipelines business; partially offset by

·	an increase of $47.6 million in ONEOK Partners’ natural gas liquids businesses, primarily due to increased NGL throughput as a result of the completion of the Overland Pass Pipeline and related expansion projects, as well as new NGL supply connections;

·	incremental net margin of $13.2 million due to the Guardian Pipeline expansion and extension that was placed into service in early 2009 in ONEOK Partners’ natural gas pipelines business; and

·	an increase of $7.4 million due to higher volumes processed and sold in ONEOK Partners’ natural gas gathering and processing business.

Operating costs increased for the three and six months ended June 30, 2009, compared with the same periods last year, primarily due to higher operating costs at ONEOK Partners’ fractionation facilities, which included incremental operating expenses associated with the recently expanded Bushton Plant that resumed operations in the third quarter of 2008, and due to the operations of the Overland Pass Pipeline that began in the fourth quarter of 2008.

Equity earnings from investments decreased for the three and six months ended June 30, 2009, compared with the same periods last year, primarily due to lower subscription volumes and rates on Northern Border Pipeline and lower volumes gathered in ONEOK Partners’ various other equity investments.

Capital expenditures decreased for the three and six months ended June 30, 2009, compared with the same periods last year, primarily due to the completion of the Overland Pass Pipeline and related expansion projects, the Williston Basin gas processing plant expansion and the Guardian Pipeline expansion and extension.

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Operating Information	2009		2008		2009		2008
Natural gas gathered (BBtu/d) (a)		1,130		1,185		1,147		1,188
Natural gas processed (BBtu/d) (a)		658		651		655		637
Natural gas transportation capacity contracted (MMcf/d)		5,264		4,816		5,205		4,883
Residue gas sales (BBtu/d) (a)		291		281		288		279
NGLs gathered (MBbl/d)		364		253		344		252
NGL sales (MBbl/d)		401		265		391		275
NGLs fractionated (MBbl/d)		479		371		472		381
NGLs transported (MBbl/d)		461		308		453		305
Conway-to-Mont Belvieu OPIS average price differential
Ethane ($/gallon)	$	0.12	$	0.13	$	0.10	$	0.11
Realized composite NGL sales prices ($/gallon) (a)	$	0.69	$	1.49	$	0.67	$	1.41
Realized condensate sales price ($/Bbl) (a)	$	72.15	$	102.77	$	67.04	$	95.82
Realized residue gas sales price ($/MMBtu) (a)	$	2.79	$	9.42	$	3.18	$	8.41
Realized gross processing spread ($/MMBtu) (a)	$	6.34	$	6.69	$	6.34	$	7.06
(a) - Statistics relate to ONEOK Partners’ natural gas gathering and processing business.

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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 August 4, 2009.

	Six Months Ending
	December 31, 2009
	Volumes Hedged	Average Price		Percentage Hedged
NGLs (Bbl/d) (a)	6,445	$1.08	/ gallon	75%
Condensate (Bbl/d) (a)	1,449	$2.18	/ gallon	72%
Total (Bbl/d)	7,894	$1.29	/ gallon	74%
Natural gas (MMBtu/d)	8,753	$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)	451	$1.37	/ gallon	5%
Condensate (Bbl/d) (a)	1,072	$1.70	/ gallon	49%
Total (Bbl/d)	1,523	$1.60	/ gallon	14%
Natural gas (MMBtu/d)	7,828	$5.71	/ MMBtu	37%
(a) - Hedged with fixed-price swaps.

See Note C of the Notes to Consolidated Financial Statements in this Quarterly Report 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 June 30, 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 or processing plant operations that might be caused by, or arise in conjunction with, price changes. For example, a change in the gross processing spread may cause a change in the amount of ethane extracted from the natural gas stream, affecting gathering and processing margins.

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.

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

		Three Months Ended				Six Months Ended				Increase (Decrease)					Increase (Decrease)
		June 30,				June 30,				Three Months					Six Months
Financial Results		2009		2008		2009		2008		2009 vs. 2008					2009 vs. 2008
	(Millions of dollars)
Gas sales		$	245.9	$	344.9	$	961.8	$	1,220.9	$	(99.0	)	(29	%)	$	(259.1	)	(21	%)
Transportation revenues			19.2		18.8		45.8		46.1		0.4		2	%		(0.3	)	(1	%)
Cost of gas			137.0		239.1		656.8		921.1		(102.1	)	(43	%)		(264.3	)	(29	%)
Net margin, excluding other revenues			128.1		124.6		350.8		345.9		3.5		3	%		4.9		1	%
Other revenues			11.5		10.4		23.3		20.8		1.1		11	%		2.5		12	%
Net margin			139.6		135.0		374.1		366.7		4.6		3	%		7.4		2	%
Operating costs			99.4		93.9		189.5		188.1		5.5		6	%		1.4		1	%
Depreciation and amortization			30.7		29.1		62.3		58.0		1.6		5	%		4.3		7	%
Gain on sale of assets			0.4		-		0.4		-		0.4		100	%		0.4		100	%
Operating income		$	9.9	$	12.0	$	122.7	$	120.6	$	(2.1	)	(17	%)	$	2.1		2	%
Capital expenditures		$	32.6	$	39.7	$	77.3	$	70.4	$	(7.1	)	(18	%)	$	6.9		10	%

Net margin increased for the three months ended June 30, 2009, compared with the same period last year, primarily due to:

·	an increase of $3.7 million resulting from the implementation of new rate mechanisms, which includes a $1.1 million increase in Oklahoma, a $1.9 million increase in Kansas and a $0.7 million increase in Texas; and

·	an increase of $1.2 million related to recovery of carrying costs for natural gas in storage.

Net margin increased for the six months ended June 30, 2009, compared with the same period last year, primarily due to:

·	an increase of $7.9 million resulting from the implementation of new rate mechanisms, which includes a $2.8 million increase in Oklahoma, a $3.6 million increase in Kansas and a $1.5 million increase in Texas; and

·	an increase of $2.3 million related to recovery of carrying costs for natural gas in storage; partially offset by

·	a decrease of $1.6 million due to lower sales volumes due to warmer weather across our entire service territory.

Operating costs increased for the three months and six months ended June 30, 2009, compared with the same periods last year, primarily due to:

·	an increase of $6.8 million and $5.6 million, respectively, in employee related costs;

·	an increase of $1.9 million and $1.8 million, respectively, in property tax expense; partially offset by

·	a decrease of $2.9 million and $5.8 million, respectively, in bad-debt expense that includes the impact of the authorized recovery of the fuel-related portion of bad debts in Oklahoma, effective January 2009.

Depreciation and amortization expense increased for the three and six months ended June 30, 2009, compared with the same periods last year, primarily due to:

·	an increase of $0.9 million and $2.1 million, respectively, in depreciation expense related to our investment in property, plant and equipment; and

·	an increase of $0.7 million and $2.2 million, respectively, in regulatory amortization associated with revenue rider recoveries.

Capital Expenditures - Our capital expenditure program includes expenditures for extending service to new areas, modifications to customer service lines, increasing system capabilities, general replacements and improvements. It is our practice to maintain and upgrade facilities to assure safe, reliable and efficient operations. Our capital expenditure program included $9.5 million and $10.3 million for new business development for the three months ended June 30, 2009 and 2008, respectively, and $20.5 million and $21.9 million for the six months ended June 30, 2009 and 2008, respectively. Capital expenditures decreased for the three months ended June 30, 2009, compared with the same period last year, primarily as a result of lower spending on modifications to customer service lines, general replacements and improvements during 2009. Capital expenditures increased for the six months ended June 30, 2009, compared with the same period last year, due to a one-time payment of $12.2 million to terminate vehicle and other equipment leases in the first quarter of 2009.

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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				Six Months Ended
	June 30,				June 30,
Volumes (MMcf)	2009		2008		2009		2008
Gas sales
Residential		13,388		14,058		68,745		75,339
Commercial		4,459		4,937		20,211		22,708
Industrial		156		388		668		973
Wholesale		3,578		2,333		4,712		2,559
Public Authority		371		336		1,218		1,335
Total volumes sold		21,952		22,052		95,554		102,914
Transportation		47,432		47,118		103,396		109,234
Total volumes delivered		69,384		69,170		198,950		212,148

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Net margin, excluding other revenues	2009		2008		2009		2008
Gas Sales	(Millions of dollars)
Residential	$	88.4	$	85.6	$	244.9	$	239.5
Commercial		19.1		18.6		56.5		56.4
Industrial		0.6		0.8		1.4		1.7
Wholesale		0.1		0.2		0.2		0.3
Public Authority		0.7		0.6		2.0		1.9
Net margin on gas sales		108.9		105.8		305.0		299.8
Transportation revenues		19.2		18.8		45.8		46.1
Net margin, excluding other revenues	$	128.1	$	124.6	$	350.8	$	345.9

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Number of Customers	2009		2008		2009		2008
Residential		1,904,675		1,892,404		1,909,012		1,897,777
Commercial		157,463		160,538		158,957		162,603
Industrial		1,364		1,444		1,368		1,446
Wholesale		27		27		27		29
Public Authority		2,858		3,035		2,903		2,987
Transportation		9,075		10,331		9,911		10,233
Total customers		2,075,462		2,067,779		2,082,178		2,075,075

Residential volumes decreased for both the three and six months ended June 30, 2009, compared with the same periods last year, due to warmer temperatures across our 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 and six months ended June 30, 2009, compared with the same periods last year, due to increased volumes available for sale caused by warmer temperatures across our entire service territory.

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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 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. The OCC approved this application for recovery of $10.5 million in IMP costs in June 2009.

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 performance-based rates was filed by the OCC staff and Oklahoma Natural Gas. This application proposes that the OCC adopt a performance-based rate design and a more streamlined regulatory process. In April 2009, a joint stipulation was signed and filed that supports a performance-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 recommended the OCC approve the application. The Commission adopted the recommendation of the administrative law judge and approved the joint stipulation of the parties on May 7, 2009.

In June 2009, Oklahoma Natural Gas filed an application with the OCC requesting an increase of approximately $66.1 million in base rates, which includes existing riders that would effectively reduce the requested rate increase to a net amount of $37.6 million. If approved as filed, the estimated annual impact on operating income will be approximately $19.0 million. Oklahoma Natural Gas has not had a base rate adjustment since July 2005. Since the 2005 increase, Oklahoma Natural Gas has invested more than $162 million in its rate base. In addition, operating expenses, such as labor and operations and maintenance, have increased since 2005. The rate application continues Oklahoma Natural Gas’ migration from traditional rate cases to performance-based rates under an order previously approved by the OCC. When fully implemented, performance-based rates will provide for a streamlined annual review of Oklahoma Natural Gas’ performance and will result in more frequent rate adjustments than what is experienced when rate cases occur years apart. In accordance with Oklahoma law, the OCC has 180 days to consider Oklahoma Natural Gas’ proposed rate changes.

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 June 2009, Austin and the surrounding cities in our central Texas service area approved an increase in base rates of $1.1 million, which included a $5.0 million decrease in depreciation and amortization expense, plus recovery of the fuel related portion of bad debts and carrying costs for natural gas in storage. The new rates were effective July 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 and six months ended June 30, 2009 and 2008, respectively.

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Energy Services

Overview - Our Energy Services segment’s primary focus is to create value for our customers by delivering physical natural gas products and risk management services through our network of contracted transportation and storage capacity and natural gas supply. 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.

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 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					Six Months Ended				Increase (Decrease)					Increase (Decrease)
		June 30,					June 30,				Three Months					Six Months
Financial Results		2009		2008			2009		2008		2009 vs. 2008					2009 vs. 2008
	(Millions of dollars)
Revenues		$	727.1	$	2,025.7		$	1,840.5	$	4,369.5	$	(1,298.6	)	(64	%)	$	(2,529.0	)	(58	%)
Cost of sales and fuel			697.0		2,021.5			1,747.8		4,280.5		(1,324.5	)	(66	%)		(2,532.7	)	(59	%)
Net margin			30.1		4.2			92.7		89.0		25.9		*			3.7		4	%
Operating costs			10.5		8.4			18.0		18.5		2.1		25	%		(0.5	)	(3	%)
Depreciation and amortization			0.2		0.2			0.3		0.6		-		0	%		(0.3	)	(50	%)
Operating income		$	19.4	$	(4.4	)	$	74.4	$	69.9	$	23.8		*		$	4.5		6	%
* Percentage change is greater than 100 percent.

Energy markets were affected by lower commodity prices during the six months ended June 30, 2009, compared with the same period last year. The decrease in commodity prices had a direct impact on our revenues and the cost of sales and fuel. Our average sales price was 67 percent lower for the three months ended June 30, 2009, and 54 percent lower for the six months ended June 30, 2009, compared with the same periods last year.

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Net margin increased for the three months ended June 30, 2009, compared with the same period last year, due to the following:

·	an increase of $26.1 million in transportation margins, net of hedging activities, due to higher realized Rockies-to-Mid-Continent margins resulting from hedging activities and favorable unrealized fair value changes on derivative financial instruments not qualified in a hedging relationship;

·	an increase of $4.4 million in retail sales margins primarily associated with customer risk management activities; partially offset by

·	a decrease of $4.7 million in financial trading margins.

Net margin increased for the six months ended June 30, 2009, compared with the same period last year, due to the following:

·	an increase of $10.0 million in transportation margins, net of hedging activities, due to higher realized Rockies-to-Mid-Continent margins resulting from hedging activities and favorable unrealized fair value changes on derivative financial instruments not qualified in a hedging relationship;

·	an increase of $3.6 million in retail sales margins, primarily associated with customer risk management activities;

·	an increase of $2.3 million in financial trading margins; partially offset by

a net decrease of $12.3 million in storage and marketing margins, net of hedging activities, primarily due to lower realized seasonal storage differentials, partially offset by increased net margins associated with managing our demand services, due to warmer winter weather in 2009, and higher margins from fair value changes on derivative financial instruments not qualified in a hedging relationship.

Operating costs increased for the three months ended June 30, 2009, compared with the same period last year, due to higher employee-related costs and an increase in bad-debt expense.

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Operating Information	2009		2008		2009		2008
Natural gas marketed (Bcf)		258		265		586		605
Natural gas gross margin ($/Mcf)	$	0.11	$	0.01	$	0.15	$	0.10
Physically settled volumes (Bcf)		544		561		1,178		1,196

Our natural gas in storage at June 30, 2009, was 68.9 Bcf, compared with 41.2 Bcf at June 30, 2008. The increase is primarily due to warmer weather in 2009 compared with colder weather in 2008, which resulted in higher storage withdrawals in 2008. At June 30, 2009, our total natural gas storage capacity under lease was 82.5 Bcf, with maximum withdrawal capability of 2.2 Bcf/d and maximum injection capability of 1.4 Bcf/d. Our current natural gas transportation capacity is 1.7 Bcf/d.

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

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2009			2008			2009			2008
	(Millions of dollars)
Marketing, storage and transportation, gross		$	74.7		$	51.2		$	186.6		$	188.8
Storage and transportation costs			(51.6	)		(54.3	)		(108.6	)		(108.5	)
Marketing, storage and transportation, net			23.1			(3.1	)		78.0			80.3
Retail marketing			6.8			2.4			11.2			7.6
Financial trading			0.2			4.9			3.5			1.1
Net margin		$	30.1		$	4.2		$	92.7		$	89.0

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.

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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 value from 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. Additional information about our legal proceedings is included under Part II, Item 1, Legal Proceedings of this Quarterly Report and under Part I, Item 3, Legal Proceedings, in our Annual Report.

LIQUIDITY AND CAPITAL RESOURCES

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

During 2009, the capital markets have improved significantly from year-end 2008. ONEOK has been able to access the commercial paper markets to meet its short-term funding needs. Additionally, ONEOK Partners has been able to access the debt and equity markets to meet its long-term financing needs for 2009. At current commodity price levels, we do not expect ONEOK’s short-term borrowings to exceed $400 million for the remainder of 2009.

Higher commodity prices and wider basis differentials in 2008 increased collateral requirements and natural gas inventory costs in our Energy Services segment, resulting in peak short-term borrowings of $1.4 billion at December 31, 2008, under ONEOK’s revolving credit facilities. 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. In addition, ONEOK has also had access to its $400 million, 364-day revolving credit facility dated August 6, 2008 (364-Day Facility), which expired on August 5, 2009. ONEOK Partners has continued to have access to its ONEOK Partners Credit Agreement, which has been adequate to fund its short-term liquidity needs and expires in March 2012.

We expect challenging economic conditions to persist for the remainder of 2009 and into 2010, with downward pressures, compared with 2008, on commodity prices. We also expect continued volatility and possible disruption in the financial markets, which could limit our access to those markets or increase the cost of issuing new securities in the future. ONEOK’s 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.

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

	June 30,	December 31,
	2009	2008
Long-term debt	57%	67%
Equity	43%	33%

Debt (including notes payable)	61%	76%
Equity	39%	24%

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

	June 30,	December 31,
	2009	2008
Long-term debt	41%	44%
Equity	59%	56%

Debt (including notes payable)	46%	59%
Equity	54%	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 pursuant to FERC regulations or their operating agreements. Under these cash management programs, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, ONEOK and ONEOK Partners provide cash to their respective subsidiaries or the subsidiaries provide cash to them.

Short-term Liquidity - ONEOK’s principal sources of short-term liquidity consist of cash generated from operating activities, quarterly distributions from ONEOK Partners and the ONEOK Credit Agreement as discussed below. ONEOK also has a commercial paper program that is utilized for short-term liquidity needs to the extent funds are available under the ONEOK Credit Agreement. 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 June 30, 2009, ONEOK had $329.9 million in commercial paper outstanding, $48.0 million in letters of credit issued under the ONEOK Credit Agreement, and available cash and cash equivalents of approximately $15.2 million. ONEOK had approximately $1.2 billion of credit available at June 30, 2009, under the ONEOK Credit Agreement and the 364-Day Facility. The amount of credit available under committed bank lines decreased by $400 million when the 364-Day Facility expired on August 5, 2009. As of June 30, 2009, ONEOK could have issued $2.8 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 June 30, 2009, ONEOK Partners had $360.0 million in borrowings outstanding and $586.5 million of credit available under the ONEOK Partners Credit Agreement, and available cash and cash equivalents of approximately $31.8 million. As of June 30, 2009, ONEOK Partners could have issued $586.5 million of additional short- and long-term debt under the most restrictive provisions of the ONEOK Partners Credit Agreement. At June 30, 2009, ONEOK Partners had a total of $49.2 million in letters of credit issued outside the ONEOK Partners 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. Among other things, the ONEOK Credit Agreement’s covenants include a limitation on ONEOK’s stand-alone debt-to-capital ratio, which may not exceed 67.5 percent at the end of any calendar quarter. At June 30, 2009, ONEOK’s stand-alone debt-to-capital ratio, as calculated under the terms of the ONEOK Credit Agreement, was 45.7 percent, and ONEOK was in compliance with all covenants under the ONEOK Credit Agreement and the 364-Day Facility. ONEOK Partners Credit Agreement’s covenants include, among other things, maintaining a 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) of no more than 5 to 1. At June 30, 2009, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 4.3 to 1. ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement.

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

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

Following completion of these transactions, our interest in ONEOK Partners is 45.1 percent.

ONEOK Partners used the proceeds from the sale of common units and the general partner contributions to repay borrowings under its existing ONEOK Partners Credit Agreement and for general partnership purposes.

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.

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.

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

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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 $407.6 million and $640.0 million for the six months ended June 30, 2009 and 2008, respectively. Of these amounts, ONEOK Partners’ capital expenditures were $321.9 million and $524.6 million for the six months ended June 30, 2009 and 2008, respectively. Our capital expenditures are driven primarily by ONEOK Partners’ capital projects discussed beginning on page 34.

Projected 2009 capital expenditures are significantly less than 2008 capital expenditures, primarily due to the completion of the Overland Pass Pipeline and related expansion projects, the Williston Basin gas processing plant expansion 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		$	570
Distribution			158
Other			17
Total projected capital expenditures		$	745

Credit Ratings - ONEOK’s and ONEOK Partners’ credit ratings as of June 30, 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 borrowings and the ONEOK Credit Agreement 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 to the ONEOK Credit Agreement, which expires in July 2011. An adverse rating change alone is not a default under the ONEOK Credit Agreement or the ONEOK Partners Credit Agreement, but could trigger repurchase obligations with respect to certain ONEOK Partners’ long-term debt. See additional discussion about our credit ratings under “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 credit rating of ONEOK’s senior unsecured long-term debt to reduce its collateral requirements. If ONEOK’s credit ratings were to decline below investment grade, our ability to participate in energy marketing and trading activities could be significantly limited. Without an investment-grade rating, we

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may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments. At June 30, 2009, ONEOK could have been required to fund approximately $2.3 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 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 may impact our overall liquidity due to the impact commodity price changes have on our cash flows from operating activities, including the impact on working capital for NGLs and natural gas held in storage, margin requirements and certain energy-related receivables. We believe that ONEOK’s and ONEOK Partners’ available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity price volatility. See discussion beginning on page 54 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. See Note H of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.

CASH FLOW ANALYSIS

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

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

	Six Months Ended						Increase (Decrease)
	June 30,						Six Months
	2009			2008			2009 vs. 2008
Total cash provided by (used in):	(Millions of dollars)
Operating activities	$	1,075.9		$	534.8		$	541.1		*
Investing activities		(380.2	)		(621.1	)		240.9		39	%
Financing activities		(1,158.7	)		165.9			(1,324.6	)	*
Change in cash and cash equivalents		(463.0	)		79.6			(542.6	)	*
Cash and cash equivalents at beginning of period		510.0			19.1			490.9		*
Cash and cash equivalents at end of period	$	47.0		$	98.7		$	(51.7	)	(52	%)
* Percentage change is greater than 100 percent.

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

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The changes in operating assets and liabilities increased operating cash flows $656.6 million for the six months ended June 30, 2009, compared with an increase of $28.8 million for the same period last year, primarily as a result of the following:

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

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

· the timing of cash receipts from our revenues resulting in decreased accounts receivable; partially offset by

· the timing of payments for purchases of commodities and other expenses resulting in decreased accounts payable.

Operating cash flows, before changes in operating assets and liabilities, were $419.3 million for the six months ended June 30, 2009, compared with $506.0 million for the same period last year. The decrease was primarily due to lower realized commodity prices and product price differentials in our ONEOK Partners segment, and decreases in storage and marketing 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 an increase in transportation margins, net of hedging activities, in our Energy Services segment.

Investing Cash Flows - Cash used in investing activities decreased for the six months ended June 30, 2009, compared with the same period last year, primarily due to the completion of the Overland Pass Pipeline and related expansion projects, the Williston Basin gas processing plant expansion and the Guardian Pipeline expansion and extension.

Financing Cash Flows - During the six months ended June 30, 2009, we had a net repayment of notes payable of $1.6 billion. The repayments were made with the proceeds ONEOK Partners received from the senior notes and public offering of common units, as discussed below, and cash generated from operations. During the six months ended June 30, 2008, we had net borrowings of $598.9 million, which were used to repay $402.3 million of ONEOK’s maturing long-term debt and fund ONEOK Partners’ capital projects.

In June 2009, ONEOK Partners’ public sale of 5,000,000 common units generated net proceeds of approximately $219.9 million after deducting underwriting discounts but before offering expenses. ONEOK Partners used the proceeds to repay borrowings under the ONEOK Partners Partnership Credit Agreement and for general partnership purposes.

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

During the first six months of 2008, ONEOK Partners’ public sale of 2.6 million common units generated net proceeds of approximately $147 million after deducting underwriting discounts but before offering expenses. ONEOK Partners used a portion of the proceeds to repay borrowings under the ONEOK Partners Partnership Credit Agreement.

Dividends paid were $0.80 per share and $0.76 per share for the six months ended June 30, 2009 and 2008, respectively.

Distributions paid to limited partners by ONEOK Partners were $2.16 per unit and $2.065 per unit for the six months ended June 30, 2009 and 2008, respectively.

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.

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. 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.

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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 greenhouse gas emissions, 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 2008 data, indicates that our emissions are less than 5 million metric tons of carbon dioxide equivalents on an annual basis. We will continue efforts to improve our ability to better quantify 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 late-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 currently 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.

Environmental Footprint - Our environmental and climate change strategy focuses on taking steps to minimize the impact of our operations on the environment. These strategies include: (i) developing and maintaining an accurate greenhouse gas emissions inventory, according to rules anticipated to be issued by the EPA in late 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 2008 calculation of our annual lost-and-unaccounted-for natural gas, for all of our business operations, is less than 1 percent of total throughput.

FORWARD-LOOKING STATEMENTS

Some of the statements contained and incorporated in this Quarterly Report are forward-looking statements within the meaning of Section 27A of the Securities Act 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.

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

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

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

·	competition from other United States and foreign energy suppliers and transporters, as well as alternative forms of energy, including, but not limited to, solar power, wind power, geothermal energy and biofuels such as ethanol and biodiesel;

·	the status of deregulation of retail natural gas distribution;

·	the capital intensive nature of our businesses;

·	the profitability of assets or businesses acquired or constructed by us;

·	our ability to make cost-saving changes in operations;

·	risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties;

·	the uncertainty of estimates, including accruals and costs of environmental remediation;

·	the timing and extent of changes in energy commodity prices;

·	the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, environmental compliance, climate change initiatives, and authorized rates of recovery of gas and gas transportation costs;

the impact on drilling and production by factors beyond our control, including the demand for natural gas and 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;

·	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;

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·	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. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

COMMODITY PRICE RISK

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

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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 $244.9 million of net assets at June 30, 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			(5,905	)
Fair value of new derivatives entered into during the period			(2,234	)
Other changes in fair value			7,904
Net fair value of derivatives outstanding at June 30, 2009 (b)		$	3,421

(a) - This balance has been adjusted by $255.1 million from the amount reported in our Annual Report. 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, $0.6 million matures through March 2011 and $0.2 million matures through March 2015.

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

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

Value-at-Risk (VAR) Disclosure of Market Risk - The potential impact on our future earnings, as measured by VAR, was $6.9 million and $14.9 million at June 30, 2009 and 2008, respectively. The following table sets forth the average, high and low VAR calculations for the periods indicated.

		Three Months Ended				Six Months Ended
		June 30,				June 30,
Value-at-Risk		2009		2008		2009		2008
	(Millions of dollars)
Average		$	9.0	$	12.6	$	9.6	$	12.5
High		$	13.0	$	18.4	$	14.1	$	24.9
Low		$	6.5	$	8.0	$	6.2	$	4.0

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 June 30, 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.

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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 second quarter ended June 30, 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.

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. On May 13, 2009, OHSL submitted its response to the settlement proposal letter. While OHSL’s response remained under consideration by the TCEQ staff, the time for accepting the settlement lapsed, and, in a letter dated June 24, 2009, the Enforcement Division of the TCEQ withdrew its settlement offer and referred the matter to its Litigation Division. This does not foreclose the possibility of a settlement, and OHSL continues to communicate with the TCEQ staff in both divisions regarding resolution of this matter.

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 April 27, 2009, the Tennessee Supreme Court granted the defendants’ (including us and OESC) application to appeal the decision of the Tennessee Court of Appeals that reversed the trial court’s granting of the defendants’ motion to dismiss in the Samuel P. Leggett, et al. v. Duke Energy Corporation, et al., case. Briefing on the appeal has been completed and a hearing before the Tennessee Supreme Court is scheduled for November 2009.

Additionally, on May 6, 2009, the NewPage Wisconsin System Inc. v. CMS Energy Resource Management Company, et al., case was transferred to the multi-district litigation matter MDL-1566 in the United States District Court for the District of Nevada for further proceedings. We continue to vigorously defend all claims made in these cases.

ITEM 1A. RISK FACTORS

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

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

ISSUER PURCHASES OF EQUITY SECURITIES

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

April 1-30, 2009		29	(a)	$25.05		-		-
May 1-31, 2009		71	(a)	$27.64		-		-
June 1-30, 2009		44	(a)	$29.59		-		-
Total		144		$27.71		-		-

(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

We held our 2009 annual meeting of shareholders on May 21, 2009. At this meeting, the individuals set forth below were elected by a majority vote to our Board of Directors to serve for a term of one year.

Director	Votes For	Votes Against	Abstained
James C. Day	92,064,097	4,551,566	432,754
Julie H. Edwards	95,744,855	985,025	318,537
William L. Ford	91,036,062	5,689,013	323,342
John W. Gibson	93,375,749	3,297,750	374,918
David L. Kyle	93,496,965	3,269,074	282,378
Bert H. Mackie	92,096,407	4,583,849	368,161
Jim W. Mogg	91,965,702	4,660,750	421,965
Pattye L. Moore	95,831,806	920,047	296,564
Gary D. Parker	92,317,669	4,407,386	323,362
Eduardo A. Rodriguez	95,624,066	1,056,052	368,299
David J. Tippeconnic	90,168,169	6,420,777	459,471

In addition, at this meeting our shareholders approved the proposal to ratify the selection of PricewaterhouseCoopers LLP as our independent registered public accounting firm for the year ending December 31, 2009, as follows:

Votes For		Votes Against				Abstained
96,269,240			516,911			262,266

ITEM 5. OTHER INFORMATION

Not Applicable.

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ITEM 6. EXHIBITS

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

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

Exhibit No. Exhibit Description

10.1

Letter agreement between ONEOK, Inc. and Sam Combs III, dated June 16, 2009.

31.1

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

31.2

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

32.1

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

32.2

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

101.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Extension Schema Document

101.CAL

XBRL Taxonomy Calculation Linkbase Document

101.DEF

XBRL Taxonomy Extension Definitions Document

101.LAB

XBRL Taxonomy Label Linkbase Document

101.PRE

XBRL Taxonomy Presentation Linkbase Document

Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in XBRL: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three and six months ended June 30, 2009 and 2008; (iii) Consolidated Balance Sheets at June 30, 2009 and December 31, 2008; (iv) Consolidated Statements of Cash Flows for the six months ended June 30, 2009 and 2008; (v) Consolidated Statement of Shareholders’ Equity for the six months ended June 30, 2009; (vi) Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2009 and 2008; and (vii) Notes to Consolidated Financial Statements.

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

In accordance with Rule 402 of Regulation S-T, the XBRL related information in Exhibit 101 to this Quarterly Report shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933 or the Exchange Act, except as shall be expressly set forth by specific reference in such filing. We also make available on our Web site the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report.

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SIGNATURE

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

	ONEOK, Inc. Registrant
Date: August 6, 2009	By:	/s/ Curtis L. Dinan
		Curtis L. Dinan Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

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