Edgar Filing: ONEOK INC /NEW/

form_10-q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2010

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

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

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

Yes __ No X

On October 29, 2010, the Company had 106,491,549 shares of common stock outstanding.

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ONEOK, Inc.

TABLE OF CONTENTS

Part I.	Financial Information	Page No.

Item 1.	Financial Statements (Unaudited)

	Consolidated Statements of Income - Three and Nine Months Ended September 30, 2010 and 2009	5

	Consolidated Balance Sheets - September 30, 2010, and December 31, 2009	6-7
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2010 and 2009	9
	Consolidated Statement of Changes in Equity - Nine Months Ended September 30, 2010	10-11

	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2010 and 2009	12
	Notes to Consolidated Financial Statements	13-35
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36-59
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	59-60
Item 4.	Controls and Procedures	60
Part II.	Other Information

Item 1.	Legal Proceedings	61
Item 1A.	Risk Factors	61
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	61
Item 3.	Defaults Upon Senior Securities	62
Item 4.	(Removed and Reserved)	62
Item 5.	Other Information	62
Item 6.	Exhibits	62-63
Signature		64

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

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

INFORMATION AVAILABLE ON OUR WEB SITE

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

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

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GLOSSARY

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

AFUDC.............................................................

Allowance for funds used during construction

Annual Report.................................................

Annual Report on Form 10-K/A, Amendment No.1 for the year ended

December 31, 2009

ASU...................................................................

Accounting Standards Update

Bbl.....................................................................

Barrels, one barrel is equivalent to 42 United States gallons

Bbl/d..................................................................

Barrels per day

BBtu/d...............................................................

Billion British thermal units per day

Bcf.....................................................................

Billion cubic feet

Bcf/d..................................................................

Billion cubic feet per day

Btu(s)................................................................

British thermal units, a measure of the amount of heat required to raise the

temperature of one pound of water one degree Fahrenheit

Bushton Plant..................................................

Bushton Gas Processing Plant

Clean Air Act...................................................

Federal Clean Air Act, as amended

Clean Water Act..............................................

Federal Water Pollution Control Act Amendments of 1972, as amended

EBITDA............................................................

Earnings before interest, taxes, depreciation and amortization

EPA...................................................................

United States Environmental Protection Agency

Exchange Act...................................................

Securities Exchange Act of 1934, as amended

FASB.................................................................

Financial Accounting Standards Board

FERC.................................................................

Federal Energy Regulatory Commission

GAAP................................................................

Accounting principles generally accepted in the United States of America

KCC...................................................................

Kansas Corporation Commission

LDCs.................................................................

Local distribution companies

LIBOR...............................................................

London Interbank Offered Rate

MBbl.................................................................

Thousand barrels

MBbl/d..............................................................

Thousand barrels per day

Mcf....................................................................

Thousand cubic feet

MDth/d.............................................................

Thousand dekatherms per day

MMBbl.............................................................

Million barrels

MMBtu.............................................................

Million British thermal units

MMBtu/d.........................................................

Million British thermal units per day

MMcf................................................................

Million cubic feet

MMcf/d............................................................

Million cubic feet per day

Moody’s...........................................................

Moody’s Investors Service, Inc.

NGL products..................................................

Marketable natural gas liquid purity products, such as ethane, ethane/propane mix,

propane, iso-butane, normal butane and natural gasoline

NGL(s)...............................................................

Natural gas liquid(s)

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

Northern Border Pipeline Company

NYMEX............................................................

New York Mercantile Exchange

OBPI..................................................................

ONEOK Bushton Processing Inc.

OCC...................................................................

Oklahoma Corporation Commission

ONEOK.............................................................

ONEOK, Inc.

ONEOK Credit Agreement.............................

ONEOK's $1.2 billion Amended and Restated Credit Agreement dated

July 14, 2006

ONEOK Partners.............................................

ONEOK Partners, L.P.

ONEOK Partners Credit Agreement.............

ONEOK Partners’ $1.0 billion Amended and Restated Revolving Credit

Agreement dated March 30, 2007

ONEOK Partners GP.......................................

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

sole general partner of ONEOK Partners

OPIS..................................................................

Oil Price Information Service

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

Overland Pass Pipeline Company LLC

Quarterly Report(s).........................................

Quarterly Report(s) on Form 10-Q

SEC....................................................................

Securities and Exchange Commission

Securities Act..................................................

Securities Act of 1933, as amended

Viking Gas Transmission...............................

Viking Gas Transmission Company

XBRL.................................................................

eXtensible Business Reporting Language

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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Unaudited)	2010			2009			2010			2009
	(Thousands of dollars, except per share amounts)

Revenues	$	2,942,703		$	2,364,736		$	9,673,802		$	7,382,190
Cost of sales and fuel		2,491,333			1,912,882			8,145,035			5,946,499
Net margin		451,370			451,854			1,528,767			1,435,691
Operating expenses
Operations and maintenance		183,893			179,678			542,643			526,271
Depreciation and amortization		77,234			72,318			230,600			215,693
General taxes		19,465			24,900			67,643			75,388
Total operating expenses		280,592			276,896			840,886			817,352
Gain (loss) on sale of assets		16,126			(1,180	)		15,068			3,246
Operating income		186,904			173,778			702,949			621,585
Equity earnings from investments (Note J)		29,390			20,054			71,182			55,464
Allowance for equity funds used during construction		266			7,290			748			25,761
Other income		6,710			8,950			4,966			18,554
Other expense		(2,097	)		(995	)		(5,338	)		(6,338	)
Interest expense		(70,907	)		(72,689	)		(222,788	)		(224,042	)
Income before income taxes		150,266			136,388			551,719			490,984
Income taxes		(29,965	)		(34,080	)		(158,324	)		(143,777	)
Net income		120,301			102,308			393,395			347,207
Less: Net income attributable to noncontrolling interests		65,006			54,266			141,837			135,201
Net income attributable to ONEOK	$	55,295		$	48,042		$	251,558		$	212,006

Earnings per share of common stock (Note K)
Net earnings per share, basic	$	0.52		$	0.46		$	2.37		$	2.01
Net earnings per share, diluted	$	0.51		$	0.45		$	2.34		$	2.00

Average shares of common stock (thousands)
Basic		106,443			105,420			106,310			105,306
Diluted		107,651			106,488			107,415			106,061

Dividends declared per share of common stock	$	0.46		$	0.42		$	1.34		$	1.22
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	September 30,		December 31,
(Unaudited)	2010		2009
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	50,483	$	29,399
Accounts receivable, net		858,819		1,437,994
Gas and natural gas liquids in storage		703,677		583,127
Commodity imbalances		98,274		186,015
Energy marketing and risk management assets (Notes B and C)		99,180		113,039
Other current assets		178,343		238,890
Total current assets		1,988,776		2,588,464

Property, plant and equipment
Property, plant and equipment		9,629,389		10,145,800
Accumulated depreciation and amortization		2,490,417		2,352,142
Net property, plant and equipment		7,138,972		7,793,658

Investments and other assets
Goodwill and intangible assets		1,024,810		1,030,560
Energy marketing and risk management assets (Notes B and C)		9,956		23,125
Investments in unconsolidated affiliates		1,194,087		765,163
Other assets		573,152		626,713
Total investments and other assets		2,802,005		2,445,561
Total assets	$	11,929,753	$	12,827,683
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	September 30,			December 31,
(Unaudited)	2010			2009
Liabilities and equity	(Thousands of dollars)
Current liabilities
Current maturities of long-term debt	$	643,231		$	268,215
Notes payable (Note E)		326,385			881,870
Accounts payable		885,017			1,240,207
Commodity imbalances		235,983			394,971
Energy marketing and risk management liabilities (Notes B and C)		36,774			65,162
Other current liabilities		469,551			488,487
Total current liabilities		2,596,941			3,338,912

Long-term debt, excluding current maturities		3,692,043			4,334,204

Deferred credits and other liabilities
Deferred income taxes		1,127,023			1,037,665
Energy marketing and risk management liabilities (Notes B and C)		2,045			8,926
Other deferred credits		616,306			662,514
Total deferred credits and other liabilities		1,745,374			1,709,105

Commitments and contingencies (Note H)

Equity (Note F)
ONEOK shareholders' equity:
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 122,725,272 shares and outstanding
106,466,921 shares at September 30, 2010; issued 122,394,015 shares and
outstanding 105,906,776 shares at December 31, 2009		1,227			1,224
Paid-in capital		1,382,657			1,322,340
Accumulated other comprehensive loss (Note D)		(90,268	)		(118,613	)
Retained earnings		1,794,842			1,685,710
Treasury stock, at cost: 16,258,351 shares at September 30, 2010 and
16,487,239 shares at December 31, 2009		(673,979	)		(683,467	)
Total ONEOK shareholders' equity		2,414,479			2,207,194

Noncontrolling interests in consolidated subsidiaries		1,480,916			1,238,268

Total equity		3,895,395			3,445,462
Total liabilities and equity	$	11,929,753		$	12,827,683
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Nine Months Ended
	September 30,
(Unaudited)	2010			2009
	(Thousands of dollars)
Operating activities
Net income	$	393,395		$	347,207
Depreciation and amortization		230,600			215,693
Allowance for equity funds used during construction		(748	)		(25,761	)
Gain on sale of assets		(15,068	)		(3,246	)
Equity earnings from investments		(71,182	)		(55,464	)
Distributions received from unconsolidated affiliates		69,889			56,896
Deferred income taxes		94,997			72,199
Share-based compensation expense		15,949			15,233
Other		3,853			701
Changes in assets and liabilities:
Accounts receivable		567,141			532,950
Gas and natural gas liquids in storage		(158,873	)		192,398
Accounts payable		(363,285	)		(347,374	)
Commodity exchange imbalances, net		(71,840	)		(10,388	)
Energy marketing and risk management assets and liabilities		118,319			84,379
Fair value of firm commitments		(91,575	)		198,516
Other assets and liabilities		38,459			(3,002	)
Cash provided by operating activities		760,031			1,270,937
Investing Activities
Contributions to unconsolidated affiliates		(1,313	)		(46,070	)
Distributions received from unconsolidated affiliates		9,342			26,192
Capital expenditures (less allowance for equity funds used during construction)		(356,289	)		(614,757	)
Proceeds from sale of assets		424,740			10,507
Other		2,968			2,569
Cash provided by (used in) investing activities		79,448			(621,559	)
Financing Activities
Borrowing (repayment) of notes payable, net		(555,485	)		(576,000	)
Borrowing (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		(259,648	)		(111,506	)
Repurchase of common stock		(5	)		(252	)
Issuance of common stock		9,357			6,739
Issuance of common units, net of discounts		322,701			241,643
Dividends paid		(142,426	)		(128,467	)
Distributions to noncontrolling interests		(192,889	)		(163,738	)
Cash used in financing activities		(818,395	)		(1,107,256	)
Change in cash and cash equivalents		21,084			(457,878	)
Cash and cash equivalents at beginning of period		29,399			510,058
Cash and cash equivalents at end of period	$	50,483		$	52,180
See accompanying Notes to Consolidated Financial Statements.

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


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

December 31, 2009		122,394,015		$	1,224	$	1,322,340	$	(118,613	)
Net income		-			-		-		-
Other comprehensive income		-			-		-		28,345
Repurchase of common stock		-			-		-		-
Common stock issued		331,257			3		9,586		-
Common stock dividends -
$1.34 per share		-			-		-		-
Issuance of common units of ONEOK Partners		-			-		50,731		-
Distributions to noncontrolling interests		-			-		-		-
Other		-			-		-		-
September 30, 2010		122,725,272		$	1,227	$	1,382,657	$	(90,268	)
See accompanying Notes to Consolidated Financial Statements.

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

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

December 31, 2009		$	1,685,710		$	(683,467	)	$	1,238,268		$	3,445,462
Net income			251,558			-			141,837			393,395
Other comprehensive income			-			-			21,758			50,103
Repurchase of common stock			-			(5	)		-			(5	)
Common stock issued			-			9,493			-			19,082
Common stock dividends -
$1.34 per share			(142,426	)		-			-			(142,426	)
Issuance of common units of ONEOK Partners			-			-			271,970			322,701
Distributions to noncontrolling interests			-			-			(192,889	)		(192,889	)
Other			-			-			(28	)		(28	)
September 30, 2010		$	1,794,842		$	(673,979	)	$	1,480,916		$	3,895,395

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Unaudited)	2010			2009			2010			2009
	(Thousands of dollars)

Net income	$	120,301		$	102,308		$	393,395		$	347,207
Other comprehensive income (loss), net of tax
Unrealized gains (losses) on energy marketing and risk management
assets/liabilities, net of tax of $(24,044), $12,104, $(47,571) and
$(16,237), respectively		39,808			(19,464	)		97,334			19,004
Realized gains in net income, net of tax of $13,119, $8,283, $21,889
and $41,135, respectively		(23,091	)		(20,193	)		(34,866	)		(90,907	)
Unrealized holding gains (losses) on available-for-sale securities,
net of tax of $65, $9, $234 and $(310), respectively		(104	)		(14	)		(370	)		491
Change in pension and postretirement benefit plan liability, net of tax
of $2,533, $2,057, $7,599 and $5,712, respectively		(4,016	)		(3,260	)		(12,048	)		(9,055	)
Other, net of tax of $(11), $(11), $(34) and $(71), respectively		18			18			53			228
Total other comprehensive income (loss), net of tax		12,615			(42,913	)		50,103			(80,239	)
Comprehensive income		132,916			59,395			443,498			266,968
Less: Comprehensive income attributable to noncontrolling interests		64,403			46,933			163,595			102,886
Comprehensive income attributable to ONEOK	$	68,513		$	12,462		$	279,903		$	164,082
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

A. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our accompanying unaudited consolidated financial statements have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair presentation of the results for the interim periods presented. All such adjustments are of a normal recurring nature. The 2009 year-end consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements in our Annual Report. Due to the seasonal nature of our business, the results of operations for the three and nine months ended September 30, 2010, are not necessarily indicative of the results that may be expected for a 12-month period.

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

Goodwill and Indefinite-lived Intangible Assets Impairment Tests - We assess our goodwill and indefinite-lived intangible assets for impairment at least annually on July 1. Our July 1, 2010, estimates of the fair value of each of our reporting units and indefinite-lived assets significantly exceeded their carrying values. Accordingly, no impairment charges were necessary.

Recently Issued Accounting Standards Update

The following recently issued accounting standards update affects our consolidated financial statements and related disclosures:

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

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

B. FAIR VALUE MEASUREMENTS

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

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

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

	September 30, 2010
	Level 1			Level 2			Level 3			Netting			Total
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	197,199		$	6,813		$	226,632		$	-		$	430,644
Physical contracts		-			32,427			21,901			-			54,328
Netting		-			-			-			(375,867	)		(375,867	)
Foreign exchange contracts		-			31			-			-			31
Total derivatives		197,199			39,271			248,533			(375,867	)		109,136
Trading securities (b)		6,145			-			-			-			6,145
Available-for-sale investment securities (c)		2,084			-			-			-			2,084
Total assets	$	205,428		$	39,271		$	248,533		$	(375,867	)	$	117,365

Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(107,262	)	$	(1,573	)	$	(175,205	)	$	-		$	(284,040	)
Physical contracts		-			(5,711	)		(8,745	)		-			(14,456	)
Netting		-			-			-			259,677			259,677
Foreign exchange contracts		-			-			-			-			-
Total derivatives		(107,262	)		(7,284	)		(183,950	)		259,677			(38,819	)
Fair value of firm commitments (d)		-			-			(43,045	)		-			(43,045	)
Total liabilities	$	(107,262	)	$	(7,284	)	$	(226,995	)	$	259,677		$	(81,864	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk management assets and liabilities on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At September 30, 2010, we held $117.7 million of cash collateral and had posted $1.5 million of cash collateral with various counterparties.
(b) - Our trading securities are presented in our Consolidated Balance Sheets as other current assets.
(c) - Our available-for-sale investment securities are presented in our Consolidated Balance Sheets as other assets.
(d) - Our fair value of firm commitments are presented in our Consolidated Balance Sheets as other current liabilities and other deferred credits.

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	December 31, 2009
	Level 1			Level 2			Level 3			Netting			Total
	(Thousands of dollars)
Assets
Derivatives (a)	$	149,034		$	4,898		$	672,631		$	(690,399	)	$	136,164
Trading securities (b)		7,927			-			-			-			7,927
Available-for-sale investment securities (c)		2,688			-			-			-			2,688
Total assets	$	159,649		$	4,898		$	672,631		$	(690,399	)	$	146,779

Liabilities
Derivatives (a)	$	(109,713	)	$	(8,481	)	$	(535,937	)	$	580,043		$	(74,088	)
Fair value of firm commitments (d)		-			-			(134,620	)		-			(134,620	)
Total liabilities	$	(109,713	)	$	(8,481	)	$	(670,557	)	$	580,043		$	(208,708	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk management assets and liabilities on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2009, we held $136.5 million of cash collateral and had posted $26.1 million of cash collateral with various counterparties.
(b) - Our trading securities are presented in our Consolidated Balance Sheets as other current assets.
(c) - Our available-for-sale investment securities are presented in our Consolidated Balance Sheets as other assets.
(d) - Our fair value of firm commitments are presented in our Consolidated Balance Sheets as other current liabilities and other deferred credits.

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

Our Level 1 fair value measurements are based on NYMEX-settled prices and actively quoted prices for equity securities. 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.

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

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

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

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

Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of September 30, 2010 (a)	$	15,542			$	(8,655	)		$	6,887
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.

	Derivative Assets (Liabilities)				Fair Value of Firm Commitments				Total
	(Thousands of dollars)
July 1, 2009	$	170,414			$	(137,403	)		$	33,011
Total realized/unrealized gains (losses):
Included in earnings		(1,815	)	(a)		(18,934	)	(a)		(20,749	)
Included in other comprehensive income (loss)		(13,137	)			-				(13,137	)
Transfers in and/or out of Level 3		16,577				-				16,577
September 30, 2009	$	172,039			$	(156,337	)		$	15,702

Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of September 30, 2009 (a)	$	59,180			$	(43,737	)		$	15,443
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.

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

Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of September 30, 2010 (a)	$	15,513		$	208		$	15,721
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.

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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		194,085		(a)		(198,516	)	(a)		1,455		(b)		(2,976	)
Included in other comprehensive income (loss)		(73,197	)			-				-				(73,197	)
Maturities		-				-				100,000				100,000
Terminations prior to maturity		-				-				70,000				70,000
Transfers in and/or out of Level 3		8,796				-				-				8,796
September 30, 2009	$	172,039			$	(156,337	)		$	-			$	15,702

Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of September 30, 2009 (a)	$	212,621			$	(182,093	)		$	-			$	30,528
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.
(b) - Reported in interest expense in our Consolidated Statements of Income.

Realized/unrealized gains (losses) include the realization of our derivative contracts through maturity and changes in fair value of our hedged firm commitments and fixed-rate debt swapped to a floating rate. Maturities represent the long-term debt associated with an interest-rate swap that matured during the period. Terminations prior to maturity represent the long-term debt associated with an interest-rate swap that was terminated during the period. Transfers into Level 3 represent existing assets or liabilities that were previously categorized at a higher level for which the unobservable inputs became a more significant portion of the fair value estimates. Transfers out of Level 3 represent existing assets and liabilities that were previously classified as Level 3 for which the observable inputs became a more significant portion of the fair value estimates.

Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable, notes payable and accounts payable is equal to book value, due to the short-term nature of these items.

The estimated fair value of long-term debt, including current maturities, was $4.8 billion at September 30, 2010, and December 31, 2009. The book value of long-term debt, including current maturities, was $4.3 billion at September 30, 2010, and $4.6 billion at December 31, 2009. The estimated fair value of long-term debt has been determined using quoted market prices of the same or similar issues with similar terms and maturities.

C. RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

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

Commodity price risk - We are exposed to the risk of loss in cash flows and future earnings arising from adverse changes in the price of natural gas, NGLs and crude oil. We use commodity derivative instruments such as futures, physical forward contracts, swaps and options to mitigate the commodity price risk associated with a portion of the forecasted purchases and sales of commodities and natural gas and natural gas liquids in storage;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Accounting Treatment

We record derivative instruments at fair value, with the exception of normal purchases and normal sales that are expected to result in physical delivery. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it.

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

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

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

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

We formally document all relationships between hedging instruments and hedged items, as well as risk management objectives, strategies for undertaking various hedge transactions and methods for assessing and testing correlation and hedge ineffectiveness. We specifically identify the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item. We assess the effectiveness of hedging relationships quarterly by performing a regression analysis on our cash flow and fair value hedging relationships to determine whether the hedge relationships are highly effective on a retrospective and prospective basis. We also document our normal purchases and normal sales transactions that we expect to result in physical delivery and that we elect to exempt from derivative accounting treatment.

The presentation of settled derivative instruments on either a gross or net basis in our Consolidated Statements of Income is dependent on the relevant facts and circumstances of our different types of activities rather than based solely on the terms of the individual contracts. All financially settled derivative instruments, as well as derivative instruments considered held for trading purposes that result in physical delivery, are reported on a net basis in revenues in our Consolidated Statements of Income. The realized revenues and purchase costs of derivative instruments that are not considered held for trading purposes and non-derivative contracts are reported on a gross basis. Derivatives that qualify as normal purchases or normal sales that are expected to result in physical delivery are also reported on a gross basis.

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

Cash flows from futures, forwards, options and swaps that are accounted for as hedges are included in the same Consolidated Statements of Cash Flows category as the cash flows from the related hedged items.

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Fair Values of Derivative Instruments

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

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

		September 30, 2010					December 31, 2009
		Fair Values of Derivatives (a)					Fair Values of Derivatives (a)
		Assets			(Liabilities)		Assets			(Liabilities)
		(Thousands of dollars)
Derivatives designated as hedging instruments
Commodity contracts
Financial contracts	$	210,239	(b)	$	(29,856)	$	311,009	(c)	$	(130,831)
Physical contracts		32			(246)		1,702			(937)
Total derivatives designated as hedging instruments		210,271			(30,102)		312,711			(131,768)
Derivatives not designated as hedging instruments
Commodity contracts
Non-trading instruments
Financial contracts		182,231			(219,448)		407,475			(447,714)
Physical contracts		54,295			(14,212)		46,598			(16,234)
Trading instruments
Financial contracts		38,175			(34,734)		59,751			(58,334)
Total commodity contracts		274,701			(268,394)		513,824			(522,282)
Foreign exchange contracts		31			-		28			(81)
Total derivatives not designated as hedging instruments		274,732			(268,394)		513,852			(522,363)
Total derivatives	$	485,003		$	(298,496)	$	826,563		$	(654,131)
(a) - Included on a net basis in energy marketing and risk management assets and liabilities on our Consolidated Balance Sheets.
(b) - Includes $58.7 million of derivative assets associated with cash flow hedges of inventory that were adjusted to reflect the lower of cost or market value. The deferred gains associated with these assets have been reclassified from accumulated other comprehensive loss.
(c) - Includes $37.7 million of derivative assets associated with cash flow hedges of inventory that were adjusted to reflect the lower of cost or market value. The deferred gains associated with these assets have been reclassified from accumulated other comprehensive loss.

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Notional Quantities for Derivative Instruments

The following table sets forth the notional quantities for derivative instruments held for the periods indicated:

		September 30, 2010					December 31, 2009
Contract Type		Purchased/ Payor		Sold/ Receiver			Purchased/ Payor		Sold/ Receiver
Derivatives designated as hedging instruments:
Cash flow hedges
Fixed price
- Natural gas (Bcf)	Exchange futures		1.2		(12.0	)		6.4		(20.7	)
	Swaps		4.0		(64.2	)		18.1		(80.7	)
- Crude oil and NGLs (MMBbl)	Swaps		-		(1.2	)		-		(2.4	)
Basis
- Natural gas (Bcf)	Forwards and swaps		4.2		(69.8	)		23.7		(99.6	)
Fair value hedges
Basis
- Natural gas (Bcf)	Forwards and swaps		129.9		(129.9	)		210.4		(210.4	)

Derivatives not designated as hedging instruments:
Fixed price
- Natural gas (Bcf)	Exchange futures		32.1		(16.3	)		38.8		(22.7	)
	Forwards and swaps		85.5		(107.5	)		100.6		(117.4	)
	Options		106.5		(42.2	)		102.6		(80.6	)
- Crude and NGLs (MBbl)	Exchange futures		0.1		(0.1	)		-		-
	Forwards and swaps		1.0		(1.4	)		-		-
- Foreign currency (Millions of dollars)	Swaps	$	0.6	$	-		$	4.6	$	-
Basis
- Natural gas (Bcf)	Forwards and swaps		562.9		(582.1	)		940.7		(947.1	)
Index
- Natural gas (Bcf)	Forwards and swaps		39.4		(8.5	)		66.4		(33.1	)

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

Cash Flow Hedges - Our Energy Services and ONEOK Partners segments use derivative instruments to hedge the cash flows associated with anticipated purchases and sales of natural gas, NGLs and condensate and cost of fuel used in the transportation of natural gas. Accumulated other comprehensive income (loss) at September 30, 2010, includes gains of approximately $37.0 million, net of tax, related to these hedges that will be realized within the next 15 months as the forecasted transactions affect earnings. If prices remain at current levels, we will recognize $34.5 million in net gains over the next 12 months, and we will recognize net gains of $2.5 million thereafter.

For the three months ended September 30, 2010, cost of sales and fuel in our Consolidated Statements of Income includes $47.4 million, reflecting an adjustment to natural gas in inventory at the lower of cost or market value. We reclassified $47.4 million of deferred gains, before income taxes, on associated cash flow hedges from accumulated other comprehensive income (loss) into earnings. For the three months ended September 30, 2009, we did not have an adjustment to natural gas in inventory at the lower of cost or market.

For the nine months ended September 30, 2010 and 2009, cost of sales and fuel in our Consolidated Statements of Income includes $58.7 million and $11.3 million in each period, reflecting adjustments to natural gas in inventory at the lower of cost or market value. In each period, we reclassified $58.7 million and $11.3 million of deferred gains, before income taxes, on associated cash flow hedges from accumulated other comprehensive income (loss) into earnings.

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

	Three Months Ended							Nine Months Ended
Derivatives in Cash Flow Hedging Relationships	September 30,							September 30,
Derivatives in Cash Flow Hedging Relationships	2010			2009				2010			2009
	(Thousands of dollars)
Commodity contracts		$	63,852		$	(32,603	)		$	144,905		$	33,642
Interest rate contracts			-			1,035				-			1,599
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)		$	63,852		$	(31,568	)		$	144,905		$	35,241

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

	Location of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)
			Three Months Ended
Derivatives in Cash Flow			September 30,
Hedging Relationships			2010		2009
			(Thousands of dollars)
Commodity contracts	Revenues	$	9,830	$	37,640
Commodity contracts	Cost of sales and fuel		26,587		(9,529)
Interest rate contracts	Interest expense		(207)		365
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)		$	36,210	$	28,476

	Location of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)
			Nine Months Ended
Derivatives in Cash Flow			September 30,
Hedging Relationships			2010		2009
			(Thousands of dollars)
Commodity contracts	Revenues	$	11,243	$	151,512
Commodity contracts	Cost of sales and fuel		45,276		(20,707)
Interest rate contracts	Interest expense		236		1,237
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)		$	56,755	$	132,042

	Location of Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing)
			Three Months Ended
Derivatives in Cash Flow			September 30,
Hedging Relationships			2010		2009
			(Thousands of dollars)
Commodity contracts	Revenues	$	308	$	(1,597)
Commodity contracts	Cost of sales and fuel		115		120
Total gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)		$	423	$	(1,477)

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	Location of Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing)
			Nine Months Ended
Derivatives in Cash Flow			September 30,
Hedging Relationships			2010		2009
			(Thousands of dollars)
Commodity contracts	Revenues	$	1,421	$	1,223
Commodity contracts	Cost of sales and fuel		(703)		(627)
Total gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)		$	718	$	596

In the event that it becomes probable that a forecasted transaction will not occur, we will discontinue cash flow hedge treatment, which will affect earnings. For the nine months ended September 30, 2010 and 2009, there were no gains or losses due to the discontinuance of cash flow hedge treatment since the underlying transactions were no longer probable.

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

		Three Months Ended				Nine Months Ended
Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss)	September 30,				September 30,
Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss)	2010		2009		2010		2009
		(Thousands of dollars)
Commodity contracts - trading	Revenues	$	2,053	$	46	$	5,438	$	3,455
Commodity contracts - non-trading (a)	Cost of sales and fuel		2,559		7,441		4,931		9,378
Foreign exchange contracts	Revenues		27		462		17		785
Total gain (loss) recognized in income on derivatives		$	4,639	$	7,949	$	10,386	$	13,618
(a) - Amounts are presented net of deferred losses associated with derivatives entered into by our Distribution segment.

Our Distribution segment held natural gas call options with premiums paid totaling $21.4 million and $18.2 million, at September 30, 2010, and December 31, 2009, respectively. The premiums are recorded in other current assets as these contracts are included in, and recoverable through, the monthly purchased-gas cost mechanism. We recorded losses associated with the decline in value of option contracts totaling approximately $16.6 million and $0.5 million in the three months ended September 30, 2010 and 2009, respectively, which were deferred as part of our unrecovered gas costs. We recorded losses associated with the decline in value and expiration of option contracts totaling approximately $22.0 million and $3.8 million in the nine months ended September 30, 2010 and 2009, respectively, which were deferred as part of our unrecovered gas costs.

Fair Value Hedges - In prior years, we terminated various interest-rate swap agreements. The net savings from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged. Interest expense savings from the amortization of terminated swaps for the three months ended September 30, 2010 and 2009, were $2.5 million in each period, and for the nine months ended September 30, 2010 and 2009, were $7.6 million and $7.7 million, respectively. The remaining amortization of terminated swaps will be recognized over the following periods:

			ONEOK
	ONEOK		Partners		Total
	(Millions of dollars)
Remainder of 2010	$	1.6	$	0.9	$	2.5
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

ONEOK and ONEOK Partners had no interest-rate swap agreements at September 30, 2010.

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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 not material for the three and nine months ended September 30, 2010 and 2009, respectively.

For the three and nine months ended September 30, 2010, cost of sales and fuel in our Consolidated Statements of Income includes gains of $4.6 million and $0.7 million, respectively, related to the change in fair value of derivatives designated as fair value hedges. Revenues include losses of $5.3 million and $1.2 million for the three and nine months ended September 30, 2010, respectively, to recognize the change in fair value of the hedged firm commitments.

For the three and nine months ended September 30, 2009, cost of sales and fuel in our Consolidated Statements of Income include gains of $53.4 million and $231.7 million, respectively, related to the change in fair value of derivatives designated as fair value hedges. Revenues include losses of $52.2 million and $231.3 million for the three and nine months ended September 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 policies and limits established by our Risk Oversight and Strategy Committee. We maintain credit policies with regard to our counterparties that we believe minimize overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings, bond yields and credit default swap rates), collateral requirements under certain circumstances and the use of standardized master-netting agreements that allow us to net the positive and negative exposures associated with a single counterparty. We have counterparties whose credit is not rated, and for those customers we use internally developed credit ratings.

Some of our derivative instruments contain provisions that require us to maintain an investment-grade credit rating from S&P and/or Moody’s. If our credit ratings on senior unsecured long-term debt were to decline below investment grade, we would be in violation of these provisions, and the counterparties to the derivative instruments could request collateralization on derivative instruments in net liability positions. The aggregate fair value of all financial derivative instruments with contingent features related to credit risk that were in a net liability position as of September 30, 2010, was $8.5 million for which we have posted collateral of $1.5 million in the normal course of business. If the contingent features underlying these agreements were triggered on September 30, 2010, we would have been required to post an additional $7.0 million of collateral to our counterparties.

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

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


	September 30, 2010
	Investment		Non-investment		Not
	Grade		Grade		Rated		Total
Counterparty sector	(Thousands of dollars)
Gas and electric utilities	$	46,572	$	1,859	$	1,316	$	49,747
Oil and gas		25,213		-		912		26,125
Industrial		27		-		13,720		13,747
Financial		19,474		-		-		19,474
Other		-		4		39		43
Total	$	91,286	$	1,863	$	15,987	$	109,136

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	December 31, 2009
	Investment		Non-investment		Not
	Grade		Grade		Rated		Total
Counterparty sector	(Thousands of dollars)
Gas and electric utilities	$	26,964	$	2,668	$	7,972	$	37,604
Oil and gas		54,578		224		10,084		64,886
Industrial		689		-		3		692
Financial		32,880		-		7		32,887
Other		-		55		40		95
Total	$	115,111	$	2,947	$	18,106	$	136,164

D. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

	Unrealized Gains (Losses) on Energy Marketing and Risk Management Assets/Liabilities				Unrealized Holding Gains (Losses) on Investment Securities		Pension and Postretirement Benefit Plan Obligations				Accumulated Other Comprehensive Income (Loss)
		(Thousands of dollars)
December 31, 2009	$	(6,151	)	$	1,441		$	(113,903	)	$	(118,613)
Other comprehensive income (loss) attributable to ONEOK		40,763			(370	)		(12,048	)		28,345
September 30, 2010	$	34,612		$	1,071		$	(125,951	)	$	(90,268)

E. CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

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

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

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

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

·	a limit on new investments in master limited partnerships.

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

The debt covenant calculations in the ONEOK Credit Agreement exclude the debt of ONEOK Partners. Upon breach of any covenant by ONEOK, amounts outstanding under the ONEOK Credit Agreement may become immediately due and payable. At September 30, 2010, ONEOK’s stand-alone debt-to-capital ratio, as defined by the ONEOK Credit Agreement, was 38.1 percent, and ONEOK was in compliance with all covenants under the ONEOK Credit Agreement.

At September 30, 2010, ONEOK had no commercial paper outstanding and $32.0 million in letters of credit issued under the ONEOK Credit Agreement, leaving approximately $1.2 billion of credit available under the ONEOK Credit Agreement. At December 31, 2009, ONEOK had $358.9 million in commercial paper outstanding and $37.0 million in letters of credit issued under the ONEOK Credit Agreement.

ONEOK Partners Credit Agreement - Under the ONEOK Partners Credit Agreement, which expires March 2012, ONEOK Partners is required to comply with certain financial, operational and legal covenants. Among other things, these requirements include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in the ONEOK Partners Credit Agreement, adjusted for all non-cash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5 to 1. If ONEOK Partners consummates one or more acquisitions in which the

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aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will increase to 5.5 to 1 for the three calendar quarters following the acquisitions. Upon breach of any covenant, discussed above, amounts outstanding under the ONEOK Partners Credit Agreement may become immediately due and payable. At September 30, 2010, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 3.8 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement. Borrowings under the ONEOK Partners Credit Agreement are nonrecourse to ONEOK.

In June 2010, ONEOK Partners initiated a commercial paper program under which ONEOK Partners may issue unsecured commercial paper notes up to a maximum amount outstanding of $1.0 billion to fund ONEOK Partners’ short-term borrowing needs. The maturities of the commercial paper notes vary but may not exceed 270 days from the date of issue. The commercial paper notes are sold at a negotiated discount from par or bear interest at a negotiated rate.

The ONEOK Partners Credit Agreement is available to repay the commercial paper notes, if necessary. Amounts outstanding under ONEOK Partners’ commercial paper program reduce the borrowing capacity under the ONEOK Partners Credit Agreement. In July 2010, ONEOK Partners repaid all borrowings outstanding under the ONEOK Partners Credit Agreement with proceeds from the issuance of commercial paper.

At September 30, 2010, ONEOK Partners had $326.4 million in commercial paper outstanding and no borrowings outstanding under the ONEOK Partners Credit Agreement, leaving approximately $673.6 million of credit available under the ONEOK Partners Credit Agreement. At December 31, 2009, ONEOK Partners had $523.0 million in borrowings outstanding under the ONEOK Partners Credit Agreement. At September 30, 2010, and December 31, 2009, ONEOK Partners had $24.2 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 typically short term in nature, ranging from one day to nine months. Accordingly, these borrowings are classified as short-term notes payable. Neither ONEOK nor ONEOK Partners guarantees the debt or other similar commitments to unaffiliated parties, and ONEOK does not guarantee the debt or other similar commitments of ONEOK Partners.

F. EQUITY

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

	Three Months Ended									Three Months Ended
	September 30, 2010									September 30, 2009
	ONEOK Shareholders' Equity			Noncontrolling Interests in Consolidated Subsidiaries			Total Equity			ONEOK Shareholders' Equity			Noncontrolling Interests in Consolidated Subsidiaries			Total Equity
	(Thousands of dollars)
Beginning balance	$	2,387,229		$	1,483,345		$	3,870,574		$	2,162,393		$	1,250,473		$	3,412,866
Net income		55,295			65,006			120,301			48,042			54,266			102,308
Other comprehensive income (loss)		13,218			(603	)		12,615			(35,580	)		(7,333	)		(42,913	)
Repurchase of common stock		-			-			-			(2	)		-			(2	)
Common stock issued		7,691			-			7,691			9,027			-			9,027
Common stock dividends		(48,954	)		-			(48,954	)		(44,265	)		-			(44,265	)
Issuance of common units of ONEOK Partners		-			(3	)		(3	)		-			21,185			21,185
Distributions to noncontrolling interests		-			(66,801	)		(66,801	)		-			(58,431	)		(58,431	)
Other		-			(28	)		(28	)		-			-			-
Ending balance	$	2,414,479		$	1,480,916		$	3,895,395		$	2,139,615		$	1,260,160		$	3,399,775

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		Nine Months Ended						Nine Months Ended
		September 30, 2010						September 30, 2009
		ONEOK Shareholders' Equity		Noncontrolling Interests in Consolidated Subsidiaries		Total Equity		ONEOK Shareholders' Equity		Noncontrolling Interests in Consolidated Subsidiaries		Total Equity
		(Thousands of dollars)
Beginning balance	$	2,207,194	$	1,238,268	$	3,445,462	$	2,088,170	$	$1,079,369	$	3,167,539
Net income		251,558		141,837		393,395		212,006		135,201		347,207
Other comprehensive income (loss)		28,345		21,758		50,103		(47,924)		(32,315)		(80,239)
Repurchase of common stock		(5)		-		(5)		(252)		-		(252)
Common stock issued		19,082		-		19,082		16,082		-		16,082
Common stock dividends		(142,426)		-		(142,426)		(128,467)		-		(128,467)
Issuance of common units of ONEOK Partners		50,731		271,970		322,701		-		241,643		241,643
Distributions to noncontrolling interests		-		(192,889)		(192,889)		-		(163,738)		(163,738)
Other		-		(28)		(28)		-		-		-
Ending balance	$	2,414,479	$	1,480,916	$	3,895,395	$	$2,139,615	$	$1,260,160	$	3,399,775

Stock Repurchase Program - In October 2010, our Board of Directors authorized a three-year stock repurchase program to buy up to $750 million of our common stock currently issued and outstanding, subject to the limitation that purchases will not exceed $300 million in any one calendar year. If shares are repurchased, they will be acquired from time to time in open-market transactions or through privately negotiated transactions at our discretion, subject to market conditions and other factors. The purchases will be funded by our available cash and short-term borrowings. The program will terminate upon completion of the repurchase of $750 million of common stock or on December 31, 2013, whichever occurs first.

Dividends - Fourth-quarter 2009 and first-quarter 2010 dividends paid on our common stock to shareholders of record at the close of business on January 30, 2010, and April 30, 2010, were $0.44 per share. A second-quarter 2010 dividend of $0.46 per share was declared for shareholders of record on July 30, 2010, and paid on August 13, 2010. Additionally, a third-quarter 2010 dividend of $0.48 per share was declared for shareholders of record at the close of business on October 29, 2010, payable on November 12, 2010.

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

G. EMPLOYEE BENEFIT PLANS

The following tables set 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							Nine Months Ended
	September 30,							September 30,
		2010			2009			2010			2009
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost		$	4,819		$	4,983		$	14,457		$	14,951
Interest cost			14,536			13,456			43,608			42,115
Expected return on assets			(18,413	)		(16,510	)		(55,239	)		(49,526	)
Amortization of unrecognized prior service cost			319			392			959			1,174
Amortization of net loss			6,889			4,331			20,666			15,475
Net periodic benefit cost		$	8,150		$	6,652		$	24,451		$	24,189

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	Postretirement Benefits							Postretirement Benefits
	Three Months Ended							Nine Months Ended
	September 30,							September 30,
		2010			2009			2010			2009
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost		$	1,231		$	1,293		$	3,694		$	3,880
Interest cost			3,911			4,229			11,733			12,688
Expected return on assets			(1,974	)		(1,703	)		(5,922	)		(5,107	)
Amortization of unrecognized net asset at adoption			797			798			2,392			2,392
Amortization of unrecognized prior service cost			(500	)		(500	)		(1,502	)		(1,502	)
Amortization of net loss			1,752			2,415			5,256			7,245
Net periodic benefit cost		$	5,217		$	6,532		$	15,651		$	19,596

Our Distribution segment recovers certain pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers. In September 2009, the KCC authorized us to defer the difference between current GAAP pension and post-retirement expenses and the level of these expenses incorporated in base rates as either a regulatory asset or liability. Amortization and recovery of the accumulated deferrals will begin with the effective date of our next rate change and will continue for a period not to exceed five years. The impact from the KCC order was not material for the nine months ended September 30, 2010.

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

H. COMMITMENTS AND CONTINGENCIES

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

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

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

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Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position or results of operations, and our expenditures related to environmental matters had no material effect upon earnings or cash flows during the three and nine months ended September 30, 2010 or 2009.

In May 2010, the EPA finalized the “Tailoring Rule” that will regulate greenhouse gas emissions at new or modified facilities that meet certain criteria. Affected facilities will be required to review best available control technology, conduct air-quality analysis, impact analysis and public reviews with respect to such emissions. The rule will be phased in beginning January 2011 and, at current emission threshold levels, will have a minimal impact on our existing facilities. The EPA has stated it will consider lowering the threshold levels over the next five years, which could increase the impact on our existing facilities; however, potential costs, fees or expenses associated with the potential adjustments are unknown.

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

I. SEGMENTS

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

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

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

Customers - For the three and nine months ended September 30, 2010 and 2009, we had no single customer from which we received 10 percent or more of our consolidated revenues.

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

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

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

Equity earnings from investments	$	29,390		$	-	$	-	$	-		$	29,390
Capital expenditures	$	104,079		$	67,353	$	-	$	5,153		$	176,585
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment's regulated operations had revenues of $150.6 million, net margin of $111.1 million and operating income of $57 million.
(b) - Our Distribution segment has regulated and non-regulated operations. Our Distribution segment's regulated operations had revenues of $237.8 million, net margin of $148.9 million and operating income of $19.9 million.

Three Months Ended September 30, 2009	ONEOK Partners (a)			Distribution (b)			Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	1,443,421			$	264,924	$	655,664	$	727		$	2,364,736
Intersegment revenues		116,582				936		63,519		(181,037	)		-
Total revenues	$	1,560,003			$	265,860	$	719,183	$	(180,310	)	$	2,364,736

Net margin	$	292,879			$	131,539	$	26,689	$	747		$	451,854
Operating costs		105,108				92,499		6,848		123			204,578
Depreciation and amortization		41,857				29,930		135		396			72,318
Gain (loss) on sale of assets		(1,180	)			-		-		-			(1,180	)
Operating income	$	144,734			$	9,110	$	19,706	$	228		$	173,778

Equity earnings from investments	$	20,054			$	-	$	-	$	-		$	20,054
Capital expenditures	$	169,396			$	33,603	$	-	$	4,158		$	207,157
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment's regulated operations had revenues of $148.1 million, net margin of $110.4 million and operating income of $54.1 million.
(b) - Our Distribution segment has regulated and non-regulated operations. Our Distribution segment's regulated operations had revenues of $214.3 million, net margin of $128.4 million and operating income of $7.6 million.

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

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

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

Nine Months Ended September 30, 2009	ONEOK Partners (a)		Distribution (b)			Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	3,839,638		$	1,443,347	$	2,096,948	$	2,257		$	7,382,190
Intersegment revenues		368,287			5,010		466,469		(839,766	)		-
Total revenues	$	4,207,925		$	1,448,357	$	2,563,417	$	(837,509	)	$	7,382,190

Net margin	$	808,402		$	516,895	$	108,137	$	2,257		$	1,435,691
Operating costs		295,061			285,085		21,842		(329	)		601,659
Depreciation and amortization		121,750			92,289		396		1,258			215,693
Gain (loss) on sale of assets		2,760			486		-		-			3,246
Operating income	$	394,351		$	140,007	$	85,899	$	1,328		$	621,585

Equity earnings from investments	$	55,464		$	-	$	-	$	-		$	55,464
Capital expenditures	$	491,256		$	110,887	$	-	$	12,614		$	614,757
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment's regulated operations had revenues of $382.3 million, net margin of $303.6 million and operating income of $140.8 million.
(b) - Our Distribution segment has regulated and non-regulated operations. Our Distribution segment's regulated operations had revenues of $1,240.7 million, net margin of $502.6 million and operating income of $130.3 million.

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J. UNCONSOLIDATED AFFILIATES

Overland Pass Pipeline Company - In September 2010, ONEOK Partners completed a transaction to sell a 49 percent ownership interest in Overland Pass Pipeline Company to a subsidiary of Williams Partners L. P. (Williams), resulting in each joint-venture member now owning 50 percent of Overland Pass Pipeline Company. In accordance with the joint-venture agreement, ONEOK Partners received approximately $423.7 million in cash at closing. As a result of the transaction, ONEOK Partners no longer controls Overland Pass Pipeline Company and began accounting for the investment under the equity method of accounting in September 2010. In connection with the deconsolidation of Overland Pass Pipeline Company, ONEOK Partners recognized approximately $16.3 million in gain on sale of assets, primarily attributable to the remeasurement of its retained investment in Overland Pass Pipeline Company to its fair value, and has recorded its retained investment of approximately $438.0 million in investments in unconsolidated affiliates. The estimate of the fair value of ONEOK Partners’ retained interest in Overland Pass Pipeline Company was based upon the income and market valuation approaches.

Northern Border Pipeline - Northern Border Pipeline anticipates requiring an additional equity contribution of approximately $102 million from its partners in 2011, of which ONEOK Partners’ share will be approximately $51 million based on its 50 percent equity interest.

Equity Earnings from Investments - The following table sets forth our equity earnings from investments for the periods indicated. All amounts in the table below are equity earnings from investments in our ONEOK Partners segment:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(Thousands of dollars)
Northern Border Pipeline	$	21,183	$	10,882	$	48,401	$	32,374
Fort Union Gas Gathering, L.L.C.		3,633		4,397		10,772		10,412
Bighorn Gas Gathering, L.L.C.		1,664		1,935		3,712		5,845
Lost Creek Gathering Company, L.L.C.		1,156		1,445		4,012		3,647
Overland Pass Pipeline Company		1,011		-		1,011		-
Other		743		1,395		3,274		3,186
Equity earnings from investments	$	29,390	$	20,054	$	71,182	$	55,464

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(Thousands of dollars)
Income Statement
Operating revenues	$	119,205	$	101,987	$	316,513	$	296,004
Operating expenses	$	48,566	$	49,312	$	138,177	$	138,544
Net income	$	63,588	$	42,929	$	156,454	$	125,574

Distributions paid to us	$	29,587	$	19,615	$	79,231	$	83,088

Distributions paid to us are classified as operating activities on our Consolidated Statements of Cash Flows until the cumulative distributions exceed our proportionate share of income from the unconsolidated affiliate since the date of our initial investment. The amount of cumulative distributions paid to us that exceeds our cumulative proportionate share of income in each period represents a return of investment and is classified as an investing activity on our Consolidated Statements of Cash Flows.

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K. EARNINGS PER SHARE INFORMATION

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

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

		Three Months Ended September 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	$	48,042	105,420			0.46
Diluted EPS from continuing operations
	Effect of options and other dilutive securities		-	1,068
	Net income attributable to ONEOK available for common stock
and common stock equivalents		$	48,042	106,488		$	0.45

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

		Nine Months Ended September 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	$	$212,006	105,306		$	2.01
Diluted EPS from continuing operations
	Effect of options and other dilutive securities		-	755
	Net income attributable to ONEOK available for common stock
and common stock equivalents		$	$212,006	106,061		$	2.00

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There were no anti-dilutive option shares excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2010, and 231,453 and 251,574 anti-dilutive option shares excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2009, respectively.

L. ONEOK PARTNERS

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

	September 30,		December 31,
	2010		2009
General partner interest	2.0	%		2.0	%
Limited partner interest (a)	40.8	%		43.1	%
Total ownership interest	42.8	%		45.1	%
(a) - Represents 5.9 million common units and approximately 36.5 million Class B units, which are convertible, at our option, into common units.

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

We account for the difference between the carrying amount of our investment in ONEOK Partners and the underlying book value arising from issuance of common units by ONEOK Partners as an equity transaction. If ONEOK Partners issues common units at a price different than our carrying value per unit, we account for the premium or deficiency as an adjustment to paid-in capital. As a result of ONEOK Partners’ issuance of common units at a premium to our carrying value per unit, we recognized an increase to paid-in capital of $50.7 million during the nine months ended September 30, 2010.

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

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2010		2009		2010		2009
		(Thousands of dollars)
General partner distributions	$	2,915	$	2,603	$	8,622	$	7,586
Incentive distributions		27,667		22,471		80,066		64,337
Total distributions to general partner	$	30,582	$	25,074	$	88,688	$	71,923

The quarterly distributions paid by ONEOK Partners to limited partners in the first, second and third quarters of 2010 were $1.10 per unit, $1.11 per unit and $1.12 per unit, respectively. The quarterly distributions paid by ONEOK Partners to limited partners in each of the first, second and third quarters of 2009 were $1.08 per unit in each period.

For the three months ended September 30, 2010 and 2009, cash distributions paid to us totaled $77.0 million and $69.9 million, respectively. For the nine months ended September 30, 2010 and 2009, cash distributions paid by ONEOK Partners to us totaled $225.3 million and $206.9 million, respectively.

In October 2010, a cash distribution from ONEOK Partners of $1.13 per unit payable in the fourth quarter was declared. On November 12, 2010, we will receive the related incentive distribution of $27.7 million for the third quarter of 2010, which is included in the table above.

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

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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 contract with ONEOK Partners for natural gas transportation and storage services. ONEOK Partners also purchases natural gas from our Energy Services segment for its natural gas liquids and natural gas gathering and processing operations.

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

We provide a variety of services to our affiliates, including cash management and financial services, legal and administrative services provided by our employees and management, insurance and office space leased in our headquarters building and other field locations. Where costs are specifically incurred on behalf of an affiliate, the costs are billed directly to the affiliate by us. In other situations, the costs may be allocated to the affiliates through a variety of methods, depending upon the nature of the expenses and the activities of the affiliates. For example, a service that applies equally to all employees is allocated based upon the number of employees in each affiliate; however, an expense benefiting the consolidated company but having no direct basis for allocation is allocated by the modified Distrigas method, a method using a combination of ratios that includes 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, which have been eliminated in consolidation for the periods indicated:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(Thousands of dollars)
Revenues	$	117,985	$	116,582	$	363,004	$	368,287

Expenses
Cost of sales and fuel	$	12,402	$	10,267	$	41,377	$	36,321
Administrative and general expenses		47,703		43,800		150,702		142,278
Total expenses	$	60,105	$	54,067	$	192,079	$	178,599

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ITEM 2.

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

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and the Notes to Consolidated Financial Statements in this Quarterly Report, as well as our Annual Report. Due to the seasonal nature of our business, the results of operations for the three and nine months ended September 30, 2010, are not necessarily indicative of the results that may be expected for a 12-month period.

RECENT DEVELOPMENTS

Growth Projects - In 2010, ONEOK Partners announced approximately $1.3 billion to $1.6 billion in growth projects primarily in the Williston Basin in North Dakota that will enable ONEOK Partners to meet the rapidly growing needs of crude oil and natural gas producers as they increase their drilling activities. Drilling rig counts in Dunn, McKenzie and Williams counties in North Dakota have increased dramatically since the beginning of the year. The development of the reserves in the Bakken Shale and Three Forks formations in the Williston Basin are being driven primarily by crude oil economics with the associated natural gas production having a high NGL content. Current natural gas processing and NGL infrastructure in the Williston Basin is being expanded to accommodate the additional production from the increased development activities.

ONEOK Partners is the largest independent gatherer and processor of natural gas in the Williston Basin. With its natural gas gathering and processing business’ existing infrastructure and acreage dedications, ONEOK Partners is well positioned to provide critical midstream services to crude oil and natural gas producers as they develop Bakken Shale and Three Forks reserves. Additional NGL infrastructure is also needed due to the continued NGL production growth that has saturated the area’s current truck and railcar transportation capacity and market. The following provides additional details about the individual projects:

Williston Basin Processing Plants and related projects - ONEOK Partners announced plans to construct two new 100 MMcf/d natural gas processing facilities, the Garden Creek plant in eastern McKenzie County, North Dakota, and the Stateline I plant in western Williams County, North Dakota. In addition, ONEOK Partners plans to make investments in related NGL infrastructure, expansions and upgrades to its existing gathering and compression infrastructure and new well connections associated with these plants. The Garden Creek plant and related projects are expected to be in service by the end of 2011 and cost approximately $350 million to $415 million, excluding AFUDC. The Stateline I plant and related projects are expected to be completed during the third quarter of 2012 and cost approximately $300 million to $355 million, excluding AFUDC. These projects are in ONEOK Partners’ natural gas gathering and processing business.

Bakken Pipeline and related projects - ONEOK Partners announced plans to build a 525- to 615-mile natural gas liquids pipeline that will transport unfractionated NGLs from the Williston Basin in North Dakota to the Overland Pass Pipeline. The Bakken Pipeline will initially transport up to 60 MBbl/d of unfractionated NGL production from ONEOK Partners’ natural gas gathering and processing assets in the Williston Basin and from third-party natural gas processing plants south through western North Dakota and eastern Montana to Wyoming, where it will connect to the Overland Pass Pipeline near Cheyenne, Wyoming. The unfractionated NGLs will then be delivered to ONEOK Partners’ existing NGL fractionation and distribution infrastructure in the Mid-Continent. Additional pump facilities could increase the new pipeline’s capacity to 110 MBbl/d. Supply commitments for the Bakken Pipeline will be anchored by NGL production from ONEOK Partners’ natural gas processing plants. ONEOK Partners is also discussing NGL supply commitments with third-party processors. Following receipt of all necessary permits, construction of the 12-inch diameter pipeline is expected to begin in the second quarter of 2012 and be completed during the first half of 2013. Project costs for the new pipeline are estimated to be $450 million to $550 million, excluding AFUDC.

The unfractionated NGLs from the Bakken Pipeline and other supply sources under development in the Rockies will require additional pump stations and the expansion of existing pump stations on the Overland Pass Pipeline. These additions and expansions will increase the capacity of Overland Pass Pipeline to 255 MBbl/d. ONEOK Partners’ anticipated share of the costs for this project is estimated to be $35 million to $40 million, excluding AFUDC.

ONEOK Partners also announced plans to invest $110 million to $140 million, excluding AFUDC, to expand and upgrade its existing fractionation capacity at Bushton, Kansas, increasing capacity to 210 MBbl/d from 150 MBbl/d. The Bakken Pipeline and related projects are in ONEOK Partners’ natural gas liquids business.

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Sterling I Pipeline Expansion - ONEOK Partners will install seven additional pump stations for approximately $36 million along its existing Sterling I natural gas liquids distribution pipeline, increasing its capacity by 15 MBbl/d, which will be supplied by ONEOK Partners’ Mid-Continent NGL infrastructure. The Sterling I pipeline transports NGL purity products from ONEOK Partners’ fractionator in Medford, Oklahoma, to the Mont Belvieu, Texas, market center and is currently operating at capacity. The pump stations are expected to be completed in the second half of 2011. This project is in ONEOK Partners’ natural gas liquids business.

Woodford Shale projects - ONEOK Partners will invest $55 million in the Woodford Shale development in Oklahoma for new well connections in 2010 and 2011, which includes connecting its natural gas gathering system to its Maysville, Oklahoma, natural gas processing facility and connecting a new third-party processing plant to its NGL gathering system in Oklahoma. These projects are in ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses, respectively.

For a discussion of capital expenditure financing, see “Capital Expenditures” in “Liquidity and Capital Resources” on page 53.

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

ONEOK Partners’ Commercial Paper Program - In June 2010, ONEOK Partners established a commercial paper program providing for the issuance of up to $1.0 billion of unsecured commercial paper notes. Amounts outstanding under the commercial paper program reduce the borrowings available under the ONEOK Partners Credit Agreement. In July 2010, ONEOK Partners repaid all borrowings outstanding under the ONEOK Partners Credit Agreement with proceeds from the issuance of commercial paper.

Long-term Debt - In June 2010, ONEOK Partners repaid $250 million of maturing senior notes with available cash and short-term borrowings. With the repayment of these notes, ONEOK Partners no longer has any obligation to offer to repurchase the $225 million senior notes due 2011 in the event that ONEOK Partners’ long-term debt credit ratings fall below investment grade.

Overland Pass Pipeline Company - In September 2010, ONEOK Partners completed a transaction to sell a 49 percent ownership interest in Overland Pass Pipeline Company to a subsidiary of Williams resulting in each joint-venture member now owning 50 percent of Overland Pass Pipeline Company. In accordance with the joint-venture agreement, ONEOK Partners received approximately $423.7 million in cash at closing. ONEOK Partners used the proceeds from the transaction to repay short-term debt and to fund a portion of its recently announced capital projects. Williams has elected to become the operator of Overland Pass Pipeline Company. Williams is expected to fully assume the role of operator by the end of the first quarter of 2011. As a result of the transaction, ONEOK Partners no longer controls Overland Pass Pipeline Company and began accounting for the investment under the equity method of accounting in September 2010. In connection with the deconsolidation of Overland Pass Pipeline Company, ONEOK Partners recognized a gain of approximately $16.3 million.

Stock Repurchase Program - In October 2010, our Board of Directors authorized a three-year stock repurchase program to buy up to $750 million of our common stock currently issued and outstanding, subject to the limitation that purchases will not exceed $300 million in any one calendar year. If shares are repurchased, they will be acquired from time to time in open-market transactions or through privately negotiated transactions at our discretion, subject to market conditions and other factors. The purchases will be funded by our available cash, free cash flow and short-term borrowings. The program will terminate upon completion of the repurchase of $750 million of common stock or on December 31, 2013, whichever occurs first.

Dividends/Distributions - We declared a quarterly dividend of $0.48 per share ($1.92 per share on an annualized basis) in October 2010, an increase of approximately 14 percent from the $0.42 per share declared in October 2009. ONEOK Partners declared a cash distribution of $1.13 per unit ($4.52 per unit on an annualized basis) in October 2010, an increase of approximately 4 percent from the $1.09 per unit declared in October 2009.

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REGULATORY

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

Financial Markets Legislation - In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted, representing a far-reaching overhaul of the framework for regulation of U.S. financial markets. We are currently evaluating the provisions of the Dodd-Frank Act. Additionally, the Dodd-Frank Act calls for various regulatory agencies, including the SEC and the Commodities Futures Trading Commission, to establish regulations for implementation of many of the provisions of the Dodd-Frank Act, which we expect will provide additional clarity regarding the extent of the impact of this legislation on us. We expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest rate risks; however, the costs of doing so may be increased as a result of the new legislation. We may also incur additional costs associated with our compliance with the new regulations and anticipated additional reporting and disclosure obligations.

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

Other - Several regulatory initiatives impacted the earnings and future earnings potential for our Distribution segment. See discussion of our Distribution segment’s regulatory initiatives begining on page 47.

IMPACT OF NEW ACCOUNTING STANDARDS

Information about the impact of new accounting standards is included in Note A of the Notes to Consolidated Financial Statements in this Quarterly Report for ASU 2010-06, “Improving Disclosures about Fair Value Measurements,” which did not have a material impact on our consolidated financial statements and related disclosures. See Note B of the Notes to Consolidated Financial Statements for discussion of our fair value measurements.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

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

Goodwill and Indefinite-lived Intangible Assets Impairment Tests - We assess our goodwill and intangible assets with an indefinite useful life for impairment at least annually as of July 1. There were no impairment charges resulting from our July 1, 2010, impairment test.

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, and assumptions consistent with a market participant’s perspective. 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 discount rates. Under the market approach, we apply multiples to forecasted cash flows. The multiples used are consistent with historical asset transactions. The forecasted cash flows are based on average forecasted cash flows for a reporting unit over a period of years.

Our estimates of fair value significantly exceeded the book value of our reporting units and our indefinite-lived intangible assets in our July 1, 2010, impairment test. Even if the estimated fair values used in our July 1, 2010, impairment test were reduced by 10 percent, no impairment charges would have resulted. At both September 30, 2010, and December 31, 2009, we had $602.8 million of goodwill and $155.6 million of indefinite-lived intangible assets recorded on our Consolidated Balance Sheets.

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						Nine Months Ended						Increase (Decrease)					Increase (Decrease)
	September 30,						September 30,						Three Months					Nine Months
Financial Results	2010			2009			2010			2009			2010 vs. 2009					2010 vs. 2009
	(Millions of dollars)
Revenues	$	2,942.7		$	2,364.7		$	9,673.8		$	7,382.2		$	578.0		24	%	$	2,291.6		31	%
Cost of sales and fuel		2,491.3			1,912.9			8,145.0			5,946.5			578.4		30	%		2,198.5		37	%
Net margin		451.4			451.8			1,528.8			1,435.7			(0.4	)	(0	%)		93.1		6	%
Operating costs		203.4			204.6			610.3			601.7			(1.2	)	(1	%)		8.6		1	%
Depreciation and amortization		77.2			72.3			230.6			215.7			4.9		7	%		14.9		7	%
Gain (loss) on sale of assets		16.1			(1.1	)		15.0			3.3			17.2		*			11.7		*
Operating income	$	186.9		$	173.8		$	702.9		$	621.6		$	13.1		8	%	$	81.3		13	%

Equity earnings from investments	$	29.4		$	20.1		$	71.2		$	55.5		$	9.3		46	%	$	15.7		28	%
Allowance for equity funds used during construction	$	0.3		$	7.3		$	0.7		$	25.8		$	(7.0	)	(96	%)	$	(25.1	)	(97	%)
Interest expense	$	(70.9	)	$	(72.7	)	$	(222.8	)	$	(224.0	)	$	(1.8	)	(2	%)	$	(1.2	)	(1	%)
Net income attributable to noncontrolling interests	$	(65.0	)	$	(54.3	)	$	(141.8	)	$	(135.2	)	$	10.7		20	%	$	6.6		5	%
Capital expenditures	$	176.6		$	207.2		$	356.3		$	614.8		$	(30.6	)	(15	%)	$	(258.5	)	(42	%)
* Percentage change is greater than 100 percent.

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Energy markets were affected by increased commodity prices during the three and nine months ended September 30, 2010, compared with the same periods last year. This increase in commodity prices impacted our revenues and cost of sales and fuel.

Net margin for the three months ended September 30, 2010, is comparable with the same period last year but reflects the following:

·	increased net margin in our Distribution segment from new rates in Oklahoma that increased fixed fees, which lower our volumetric sensitivity; offset by

decreased net margin in our ONEOK Partners segment, due primarily to lower optimization margins in its natural gas liquids business due to narrower NGL product price differentials between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers and limited NGL fractionation and transportation capacity available for optimization activities; and

·	decreased net margin in our Energy Services segment, due primarily to lower realized seasonal storage differentials and marketing margins, net of hedging activities.

Net margin increased for the nine months ended September 30, 2010, compared with the same period last year, due primarily to the following:

·	increased net margin in our Distribution segment from new rates in Oklahoma that increased fixed fees, which lower our volumetric sensitivity;

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

-	higher NGL volumes gathered, fractionated and transported, primarily associated with the completion of the Arbuckle Pipeline, Piceance lateral pipeline and D-J Basin lateral pipeline, as well as new NGL supply connections in its natural gas liquids business;

-	higher natural gas transportation margins from an increase in capacity contracted on Midwestern Gas Transmission and Viking Gas Transmission’s Fargo lateral pipeline and the incremental margin from the Guardian Pipeline expansion and extension project in its natural gas pipelines business; and

-	higher storage margins, primarily as a result of contract renegotiations in its natural gas pipelines and natural gas liquids businesses; offset partially by

-	lower optimization margins due to limited NGL fractionation and transportation capacity available for optimization activities and narrower NGL product price differentials between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers in its natural gas liquids business; and

-	lower natural gas volumes gathered as a result of natural production declines and reduced drilling activity by its customers in the Powder River Basin in its natural gas gathering and processing business; and

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

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

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

Operating costs decreased for the three months ended September 30, 2010, compared with the same period last year, primarily due to the following:

·	lower than estimated ad valorem taxes associated with ONEOK Partners’ capital projects completed in 2009 and decreased outside services costs attributable to maintenance projects at ONEOK Partners’ NGL fractionators in 2009; offset partially by

·	the recognition of previously deferred Integrity Management Program costs in Oklahoma in our Distribution segment.

Operating costs increased for the nine months ended September 30, 2010, compared with the same period last year, primarily due to the following:

·	the recognition of previously deferred Integrity Management Program costs in Oklahoma in our Distribution segment; offset partially by

lower than estimated ad valorem taxes associated with ONEOK Partners’ capital projects completed in 2009 and lower costs for outside services attributable to maintenance projects at ONEOK Partners’ NGL fractionators in 2009, offset partially by higher property insurance costs related to increased coverage for ONEOK Partners’ assets and higher employee labor costs.

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Depreciation and amortization expense increased for the three and nine months ended September 30, 2010, compared with the same periods last year, primarily as a result of ONEOK Partners’ completed capital projects.

Gain (loss) on sale of assets increased for the three and nine months ended September 30, 2010, compared with the same periods last year, due to the gain on sale of a 49 percent ownership interest in Overland Pass Pipeline Company in ONEOK Partners’ natural gas liquids business.

Equity earnings from investments increased for the three and nine months ended September 30, 2010, compared with the same periods last year, as a result of increased contracted capacity on Northern Border Pipeline due to wider natural gas price differentials between the markets it serves. ONEOK Partners owns a 50 percent equity interest in Northern Border Pipeline.

Allowance for equity funds used during construction decreased for the three and nine months ended September 30, 2010, compared with the same periods last year, primarily as a result of ONEOK Partners’ completed capital projects.

Capital expenditures decreased for the three and nine months ended September 30, 2010, compared with the same periods last year, due primarily to ONEOK Partners’ completed capital projects, offset partially by initial expenditures on its recently announced capital projects, primarily in its natural gas gathering and processing and natural gas liquids businesses.

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

ONEOK Partners

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

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

ONEOK Partners’ natural gas pipeline business operates interstate and intrastate natural gas transmission pipelines, natural gas storage facilities and non-processable natural gas gathering facilities. ONEOK Partners also provides natural gas transportation and storage services in accordance with Section 311(a) of the Natural Gas Policy Act of 1978, as amended. ONEOK Partners’ interstate assets transport natural gas through FERC-regulated interstate natural gas pipelines that access supply from Canada and from the Mid-Continent, Rocky Mountain and Gulf Coast regions. ONEOK Partners’ intrastate natural gas pipeline assets are located in Oklahoma, Texas and Kansas, and have access to major natural gas producing areas in those states. ONEOK Partners owns underground natural gas storage facilities in Oklahoma, Kansas and Texas.

ONEOK Partners’ natural gas liquids business gathers, treats, fractionates, transports and stores NGLs. ONEOK Partners’ natural gas liquids gathering pipelines deliver unfractionated NGLs gathered from natural gas processing plants located in Oklahoma, Kansas, Texas and the Rocky Mountain region to fractionators it owns in Oklahoma, Kansas and Texas. The NGLs are then separated through the fractionation process into the individual NGL products to 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.

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Selected Financial Results and Operating Information - ONEOK Partners placed the following projects in service during 2009:

·	February - Guardian Pipeline’s expansion and extension project in its natural gas pipeline business;

·	March - Williston Basin natural gas processing plant expansion in its natural gas gathering and processing business;

·	March - D-J Basin lateral pipeline in its natural gas liquids business;

·	July - Arbuckle Pipeline in its natural gas liquids business; and

·	October - Piceance lateral pipeline in its natural gas liquids business.

Additional discussion of ONEOK Partners’ completed capital projects is included under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Capital Projects” in our Annual Report. The in-service dates of these completed capital projects have impacted the period-to-period comparisons of net margin and operating expenses primarily in ONEOK Partners’ natural gas liquids and natural gas pipelines businesses, as operations associated with these projects have been increasing since being placed in service. The following table sets forth certain selected financial results for our ONEOK Partners segment for the periods indicated:

	Three Months Ended						Nine Months Ended						Increase (Decrease)					Increase (Decrease)
	September 30,						September 30,						Three Months					Nine Months
Financial Results	2010			2009			2010			2009			2010 vs. 2009					2010 vs. 2009
	(Millions of dollars)
Revenues	$	2,070.1		$	1,560.0		$	6,329.3		$	4,207.9		$	510.1		33	%	$	2,121.4		50	%
Cost of sales and fuel		1,784.1			1,267.1			5,494.0			3,399.5			517.0		41	%		2,094.5		62	%
Net margin		286.0			292.9			835.3			808.4			(6.9	)	(2	%)		26.9		3	%
Operating costs		97.8			105.1			292.1			295.0			(7.3	)	(7	%)		(2.9	)	(1	%)
Depreciation and amortization		43.8			41.9			131.7			121.8			1.9		5	%		9.9		8	%
Gain (loss) on sale of assets		16.1			(1.2	)		15.1			2.8			17.3		*			12.3		*
Operating income	$	160.5		$	144.7		$	426.6		$	394.4		$	15.8		11	%	$	32.2		8	%

Equity earnings from investments	$	29.4		$	20.1		$	71.2		$	55.5		$	9.3		46	%	$	15.7		28	%
Allowance for equity funds used during construction	$	0.3		$	7.3		$	0.7		$	25.8		$	(7.0	)	(96	%)	$	(25.1	)	(97	%)
Interest expense	$	(49.1	)	$	(50.4	)	$	(156.6	)	$	(152.2	)	$	(1.3	)	(3	%)	$	4.4		3	%
Capital expenditures	$	104.1		$	169.4		$	202.8		$	491.3		$	(65.3	)	(39	%)	$	(288.5	)	(59	%)
* Percentage change is greater than 100 percent.

Net margin decreased for the three months ended September 30, 2010, compared with the same period last year, due to the following:

a decrease of $9.9 million related to lower optimization margins due to narrower NGL product price differentials between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers and limited NGL fractionation and transportation capacity available for optimization activities in ONEOK Partners’ natural gas liquids business; offset partially by

·	an increase of $3.8 million due to higher NGL volumes gathered, fractionated and transported, primarily associated with the completion of the Arbuckle Pipeline and Piceance lateral pipeline, as well as new NGL supply connections in ONEOK Partners’ natural gas liquids business.

Net margin increased for the nine months ended September 30, 2010, compared with the same period last year, due to the following:

an increase of $49.2 million due to higher NGL volumes gathered, fractionated and transported, primarily associated with the completion of the Arbuckle Pipeline, Piceance lateral pipeline and D-J Basin lateral pipeline, as well as new NGL supply connections in ONEOK Partners’ natural gas liquids business;

an increase of $11.3 million from higher natural gas transportation margins from an increase in contracted capacity on Midwestern Gas Transmission, Viking Gas Transmission’s Fargo lateral pipeline and the incremental margin from the Guardian Pipeline expansion and extension project in ONEOK Partners’ natural gas pipelines business;

·	an increase of $10.8 million due to higher storage margins, primarily as a result of contract renegotiations in ONEOK Partners’ natural gas pipelines and natural gas liquids businesses; and

·	an increase of $5.6 million from the impact of higher natural gas prices on retained fuel in ONEOK Partners’ natural gas pipelines business; offset partially by

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a decrease of $39.5 million related to lower optimization margins due to limited NGL fractionation and transportation capacity available for optimization activities and narrower NGL product price differentials between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers in ONEOK Partners’ natural gas liquids business; and

·	a decrease of $5.3 million due to lower natural gas volumes gathered as a result of natural production declines and reduced drilling activity by its customers in the Powder River Basin in ONEOK Partners’ natural gas gathering and processing business.

Operating costs decreased for the three months ended September 30, 2010, compared with the same period last year, due primarily to a decrease of $5.4 million resulting from lower than estimated ad valorem taxes associated with ONEOK Partners’ capital projects completed in 2009 and a decrease of $3.1 million in outside services costs primarily attributable to maintenance projects at ONEOK Partners’ fractionators in 2009 in its natural gas liquids business.

Operating costs decreased for the nine months ended September 30, 2010, compared with the same period last year, due to the following:

·	a decrease of $6.0 million resulting from lower than estimated ad valorem taxes associated with ONEOK Partners’ capital projects completed in 2009 in its natural gas liquids business; and

·	a decrease of $2.9 million in outside services costs primarily attributable to maintenance projects at ONEOK Partners’ NGL fractionators in 2009 in its natural gas liquids business; offset partially by

·	an increase of $2.5 million in property insurance costs related to increased coverage for ONEOK Partners’ assets in its natural gas liquids business; and

·	an increase of $1.6 million in higher employee labor costs resulting from the operation of the completed capital projects in ONEOK Partners’ natural gas liquids business.

Depreciation and amortization expense increased for the three and nine months ended September 30, 2010, compared with the same periods last year, as a result of ONEOK Partners’ capital projects completed last year in its natural gas liquids and natural gas pipelines businesses.

Equity earnings from investments increased for the three and nine months ended September 30, 2010, compared with the same periods last year, as a result of increased contracted capacity on Northern Border Pipeline due to wider natural gas price differentials between the markets it serves in ONEOK Partners’ natural gas pipelines business.

Allowance for equity funds used during construction decreased for the three and nine months ended September 30, 2010, compared with the same periods last year, as a result of ONEOK Partners’ completed capital projects.

Capital expenditures decreased for the three and nine months ended September 30, 2010, compared with the same periods last year, due primarily to ONEOK Partners’ completed capital projects, offset partially by intitial expenditures on its recently announced capital projects, primarily in its natural gas gathering and processing and natural gas liquids businesses.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Operating Information	2010			2009			2010			2009
Natural gas gathered (BBtu/d) (a)		1,046			1,100			1,075			1,131
Natural gas processed (BBtu/d) (a)		669			664			674			658
Natural gas transportation capacity contracted (MDth/d) (b)		5,460			5,712			5,627			5,412
Transportation capacity subscribed		84	%		86	%		87	%		82	%
Residue gas sales (BBtu/d) (a)		292			297			286			291
NGL sales (MBbl/d)		449			382			443			388
NGLs fractionated (MBbl/d)		500			496			505			458
NGLs transported-gathering lines (MBbl/d)		436			385			452			358
NGLs transported-distribution lines (MBbl/d)		455			446			468			451
Conway-to-Mont Belvieu OPIS average price differential
Ethane ($/gallon)	$	0.10		$	0.15		$	0.11		$	0.12
Realized composite NGL net sales price ($/gallon) (a) (c)	$	0.87		$	0.89		$	0.92		$	0.87
Realized condensate net sales price ($/Bbl) (a) (c)	$	65.14		$	86.90		$	63.61		$	76.75
Realized residue gas net sales price ($/MMBtu) (a) (c)	$	5.60		$	3.34		$	5.43		$	3.37
Realized gross processing spread ($/MMBtu) (a)	$	5.67		$	6.54		$	5.97		$	6.41
(a) - Statistics relate to ONEOK Partners’ natural gas gathering and processing business.
(b) - Unit of measure converted from MMcf/d in the third quarter of 2010. Prior periods have been recast to reflect this change.
(c) - Presented net of the impact of hedging activities and includes equity volumes only.

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

	Three Months Ending
	December 31, 2010
	Volumes Hedged		Average Price			Percentage Hedged
NGLs (Bbl/d) (a)		5,267	$	1.05	/ gallon		61%
Condensate (Bbl/d) (a)		1,820	$	1.84	/ gallon		79%
Total (Bbl/d)		7,087	$	1.25	/ gallon		65%
Natural gas (MMBtu/d)		24,020	$	5.55	/ MMBtu		99%
(a) - Hedged with fixed-price swaps.

	Year Ending
	December 31, 2011
	Volumes Hedged	Average Price			Percentage Hedged
NGLs (Bbl/d) (a)	1,316	$	1.04	/ gallon		15%
Condensate (Bbl/d) (a)	596	$	2.12	/ gallon		26%
Total (Bbl/d)	1,912	$	1.37	/ gallon		18%
Natural gas (MMBtu/d)	22,541	$	5.72	/ MMBtu		74%
(a) - Hedged with fixed-price swaps.

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

·	a $0.01 per gallon change in the composite price of NGLs would change annual net margin by approximately $1.2 million;

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

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·	a $0.10 per MMBtu change in the price of natural gas would change annual net margin by approximately $1.0 million.

The above estimates of commodity price risk exclude the effects of hedging and assume normal operating conditions. Further, these estimates do not include any effects on demand for ONEOK Partners’ services or processing plant operations that might be caused by, or arise in conjunction with, price changes. For example, a change in the gross processing spread may cause a change in the amount of ethane extracted from the natural gas stream, affecting gathering and processing margins.

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

Distribution

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

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

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

	Three Months Ended				Nine Months Ended				Increase (Decrease)					Increase (Decrease)
	September 30,				September 30,				Three Months					Nine Months
Financial Results	2010		2009		2010		2009		2010 vs. 2009					2010 vs. 2009
	(Millions of dollars)
Gas sales	$	273.6	$	237.6	$	1,549.4	$	1,351.0	$	36.0		15	%	$	198.4		15	%
Transportation revenues		19.0		17.8		67.1		63.6		1.2		7	%		3.5		6	%
Cost of gas		151.9		134.3		1,087.2		931.5		17.6		13	%		155.7		17	%
Net margin, excluding other revenues		140.7		121.1		529.3		483.1		19.6		16	%		46.2		10	%
Other revenues		10.1		10.4		29.8		33.8		(0.3	)	(3	%)		(4.0	)	(12	%)
Net margin		150.8		131.5		559.1		516.9		19.3		15	%		42.2		8	%
Operating costs		98.4		92.5		296.4		285.1		5.9		6	%		11.3		4	%
Depreciation and amortization		32.8		29.9		97.0		92.3		2.9		10	%		4.7		5	%
Gain (loss) on sale of assets		-		-		-		0.5		-		0	%		(0.5	)	(100	%)
Operating income	$	19.6	$	9.1	$	165.7	$	140.0	$	10.5		*		$	25.7		18	%
Capital expenditures	$	67.4	$	33.6	$	145.7	$	110.9	$	33.8		*		$	34.8		31	%
* Percentage change is greater than 100 percent.

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

	Three Months Ended				Nine Months Ended				Increase (Decrease)					Increase (Decrease)
	September 30,				September 30,				Three Months					Nine Months
Net margin, excluding other revenues	2010		2009		2010		2009		2010 vs. 2009					2010 vs. 2009
Gas sales	(Millions of dollars)
Regulated
Residential	$	98.1	$	81.4	$	369.1	$	326.4	$	16.7		21	%	$	42.7		13	%
Commercial		20.6		17.4		79.5		73.9		3.2		18	%		5.6		8	%
Industrial		0.6		0.6		1.9		2.0		-		0	%		(0.1	)	(5	%)
Wholesale		0.1		0.1		0.4		0.3		-		0	%		0.1		33	%
Public Authority		0.6		0.7		2.9		2.7		(0.1	)	(14	%)		0.2		7	%
Retail marketing		1.7		3.1		8.4		14.3		(1.4	)	(45	%)		(5.9	)	(41	%)
Net margin on gas sales		121.7		103.3		462.2		419.6		18.4		18	%		42.6		10	%
Transportation margin		19.0		17.8		67.1		63.5		1.2		7	%		3.6		6	%
Net margin, excluding other revenues	$	140.7	$	121.1	$	529.3	$	483.1	$	19.6		16	%	$	46.2		10	%

Net margin increased for the three months ended September 30, 2010, compared with the same period last year, due to the following:

·	an increase of $18.0 million from new rates in Oklahoma that increased fixed fees, which lower our volumetric sensitivity and provides more consistent revenues each month; and

·	an increase of $1.0 million from increased transportation revenues from end-use customers.

Net margin increased for the nine months ended September 30, 2010, compared with the same period last year, due to the following:

·	an increase of $35.6 million from new rates in Oklahoma that increased fixed fees, which lower our volumetric sensitivity and provides more consistent revenues each month;

·	an increase of $4.6 million from increased rider recoveries in Oklahoma and ad valorem tax surcharge recoveries in Kansas;

·	an increase of $2.9 million from higher gas sales volumes, primarily in the first quarter due to colder weather;

·	an increase of $2.6 million from capital-recovery mechanisms in Kansas; and

·	an increase of $2.6 million from higher transportation volumes; offset partially by

·	a decrease of $5.9 million in retail marketing margins associated primarily with reduced customer risk-management services.

Operating costs increased for the three months ended September 30, 2010, compared with the same period last year, due to the following:

·	an increase of $3.8 million related to the recognition of previously deferred Integrity Management Program costs in Oklahoma that have been approved for recovery in our revenues; and

·	an increase of $1.3 million related to contract and outside services costs.

Operating costs increased for the nine months ended September 30, 2010, compared with the same period last year, due to the following:

·	an increase of $10.7 million related to the recognition of previously deferred Integrity Management Program costs in Oklahoma that have been approved for recovery in our revenues;

·	an increase of $1.9 million related to contract and outside services costs, primarily in Texas due to higher pipeline integrity-management costs and one-time costs related to a customer outage; and

·	an increase of $1.3 million related to increased telecommunications and materials costs; offset partially by

·	a decrease of $5.2 million in employee-related costs due primarly to the capitalization of costs from increased capital spending in Oklahoma.

Depreciation and amortization expense increased for the three and nine months ended September 30, 2010, compared with the same period last year, due primarily to an increase of $1.7 million and $4.8 million, respectively, in regulatory amortization associated with revenue rider recoveries.

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Capital Expenditures - Our capital expenditure program includes expenditures for extending service to new areas, modifications to customer-service lines, increasing system capabilities, general replacements and improvements, including an automated meter reading investment in Oklahoma. It is our practice to maintain and upgrade facilities to ensure safe, reliable and efficient operations. Capital expenditures increased for the three and nine months ended September 30, 2010, compared with the same periods last year, primarily as a result of expenditures related to an investment in automated meter reading in Oklahoma.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Volumes (MMcf)	2010		2009		2010	2009
Gas sales
Residential		7,384		7,820	82,086		76,565
Commercial		3,260		3,204	24,683		23,416
Industrial		315		293	940		960
Wholesale		3,117		4,000	6,591		8,712
Public Authority		319		312	1,949		1,529
Total volumes sold		14,395		15,629	116,249		111,182
Transportation		42,766		43,366	153,074		146,761
Total volumes delivered		57,161		58,995	269,323		257,943

	Three Months Ended			Nine Months Ended
	September 30,			September 30,
Number of Customers	2010		2009	2010		2009
Residential		1,893,290	1,883,674		1,913,622		1,900,565
Commercial		150,748	153,319		154,151		157,077
Industrial		1,258	1,323		1,279		1,353
Wholesale		34	26		35		27
Public Authority		2,679	2,564		2,660		2,790
Transportation		11,357	10,882		11,241		10,235
Total customers		2,059,366	2,051,788		2,082,988		2,072,047

Residential volumes decreased for the three months ended September 30, 2010, compared with the same period last year, due to warmer temperatures across our entire service territory. Residential volumes increased for the nine months ended September 30, 2010, compared with the same period last year, due to colder temperatures across our entire service territory in the first quarter of 2010.

Regulatory Initiatives

Oklahoma - In September 2010, Oklahoma Natural Gas filed an application and supporting testimony with the OCC seeking approval of a demand portfolio of conservation and energy-efficiency programs and authorizing recovery of costs and performance incentives. The proposed programs include: Energy-Efficiency Education Program, Heating System Check-Up Program, Low-Income Energy Efficiency Assistance Program, Water Heater Replacement Program, Space Heating Replacement Program, Clothes Dryer Replacement Program, New Homes Program and Commercial Customer Program. A procedural schedule is currently being developed for this case, and a hearing is expected to be held in February 2011.

In December 2009, the OCC approved a rate increase of $54.5 million, which included moving existing riders into base rates that effectively reduced the rate increase to a net amount of $25.7 million. The new rates went into effect on December 18, 2009, and reduce our volumetric exposure. Under a previous order, Oklahoma Natural Gas migrated from traditional rates to performance-based rates that provide for a streamlined annual review of the company’s performance, resulting in smaller, potentially more frequent rate adjustments.

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On January 27, 2010, Oklahoma Natural Gas filed an application and supporting testimony requesting recovery of the Integrity Management Program deferral for 2009 and annual adjustments associated with the prior recovery period in the amount of $15.7 million. In May 2010, Oklahoma Natural Gas filed supplemental testimony to increase the total amount of the request to $16.7 million. The OCC approved the recovery of $16.7 million on June 30, 2010, and billing of the new rates began July 1, 2010.

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

In May 2010, Kansas Gas Service was granted a motion to withdraw its application with the KCC to become an Efficiency Kansas Loan Program utility partner and provide a portfolio of energy-efficiency programs designed to encourage the purchase of energy-efficient natural gas appliances. The application was withdrawn as a result of the wide discrepancy between the positions of the parties involved in the case. Kansas Gas Service will continue to explore opportunities to promote energy-efficiency initiatives in a manner that does not penalize Kansas Gas Service and meets regulators’ requirements.

Texas - In December 2009, Texas Gas Service filed a statement of intent to increase rates in its El Paso service area by $7.3 million. On April 13, 2010, the City of El Paso rejected the proposed increase. Texas Gas Service filed an appeal on May 12, 2010, with the Railroad Commission of Texas. The filing updated rate base and cost of service for pension expense and included a statement of intent to increase rates by $5.3 million. Subsequently, rate-case expenses were placed into a separate docket, effectively reducing the requested increase to $4.4 million. The Railroad Commission must take action by December 16, 2010.

General - Certain costs to be recovered through the ratemaking process have been capitalized as regulatory assets. Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria for capitalization, and, accordingly, a write-off of regulatory assets and stranded costs may be required. There were no write-offs of regulatory assets resulting from the failure to meet the criteria for capitalization during the three and nine months ended September 30, 2010 and 2009, respectively.

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 natural gas transportation and storage capacity and natural gas supply. This contracted storage and transportation capacity connects the major supply and demand centers throughout the United States and into Canada. Our customers are primarily LDCs, electric utilities, and commercial and industrial end- users. Our customers’ natural gas needs vary with seasonal changes in weather and are therefore somewhat unpredictable.

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

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

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

We utilize our experience to optimize the value of our contracted assets and use our risk-management and marketing capabilities to both manage risk and generate additional margins. We apply a combination of cash flow and fair value hedge accounting when implementing hedging strategies that take advantage of favorable market conditions. See Note C of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information. Additionally, certain non-

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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				Nine Months Ended				Increase (Decrease)					Increase (Decrease)
	September 30,				September 30,				Three Months					Nine Months
Financial Results	2010		2009		2010		2009		2010 vs. 2009					2010 vs. 2009
	(Millions of dollars)
Revenues	$	773.8	$	719.2	$	2,623.4	$	2,563.4	$	54.6		8	%	$	60.0		2	%
Cost of sales and fuel		759.7		692.5		2,491.0		2,455.3		67.2		10	%		35.7		1	%
Net margin		14.1		26.7		132.4		108.1		(12.6	)	(47	%)		24.3		22	%
Operating costs		7.0		6.8		21.0		21.8		0.2		3	%		(0.8	)	(4	%)
Depreciation and amortization		0.2		0.2		0.5		0.4		-		0	%		0.1		25	%
Operating income	$	6.9	$	19.7	$	110.9	$	85.9	$	(12.8	)	(65	%)	$	25.0		29	%

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

	Three Months Ended				Nine Months Ended				Increase (Decrease)					Increase (Decrease)
	September 30,				September 30,				Three Months					Nine Months
	2010		2009		2010		2009		2010 vs. 2009					2010 vs. 2009
	(Millions of dollars)
Marketing, storage and transportation, gross	$	57.6	$	79.8	$	272.6	$	266.4	$	(22.2	)	(28	%)	$	6.2		2	%
Storage and transportation costs		45.9		53.1		145.8		161.7		(7.2	)	(14	%)		(15.9	)	(10	%)
Marketing, storage and transportation, net		11.7		26.7		126.8		104.7		(15.0	)	(56	%)		22.1		21	%
Financial trading, net		2.4		-		5.6		3.4		2.4		100	%		2.2		65	%
Net margin	$	14.1	$	26.7	$	132.4	$	108.1	$	(12.6	)	(47	%)	$	24.3		22	%

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

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

Net margin decreased for the three months ended September 30, 2010, compared with the same period last year, due to the following:

·	a decrease of $8.7 million from lower realized seasonal storage differentials and marketing margins, net of hedging activities, offset partially by a decrease in storage expense due to reduced contracted storage capacity;

·	a decrease of $3.2 million in premium-services margins, associated primarily with lower demand fees; and

·	a decrease of $3.1 million in transportation margins, net of hedging, due primarily to less favorable unrealized fair value changes on non-qualifying economic hedge activity; offset partially by

·	an increase of $2.4 million in financial trading margins.

Net margin increased for the nine months ended September 30, 2010, compared with the same period last year, due to the following:

·	an increase of $57.0 million from higher realized seasonal storage differentials and marketing margins, net of hedging activities;

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·	an increase of $2.2 million in financial trading margins; offset partially by

·	a decrease of $28.5 million in premium-services margins, associated primarily with lower demand fees and managing increased demand to meet customer-peaking requirements due to colder weather in the first quarter of 2010, compared with the same period last year; and

·	a decrease of $6.4 million in transportation margins, net of hedging, due primarily to lower realized Mid-Continent-to-Gulf Coast transportation margins.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Operating Information	2010		2009		2010		2009
Natural gas marketed (Bcf)		224		254		693		840
Natural gas gross margin ($/Mcf)	$	0.07	$	0.11	$	0.20	$	0.13
Physically settled volumes (Bcf)		470		523		1,414		1,698

Our Energy Services segment has focused its efforts on aligning its contracted natural gas transportation and storage capacity with meeting the needs of our premium-service customers. The effect of this strategy has been a reduction in our contracted natural gas transportation and storage capacity, which also will reduce our working-capital requirements primarily through a reduction in natural gas inventory levels.

Our natural gas in storage at September 30, 2010, was 65.4 Bcf, compared with 79.4 Bcf at September 30, 2009. At September 30, 2010, our total natural gas storage capacity under lease was 76.6 Bcf, compared with 82.8 Bcf at September 30, 2009. Our natural gas storage capacity under lease had maximum withdrawal capability of 2.2 Bcf/d and maximum injection capability of 1.3 Bcf/d. Our natural gas transportation capacity at September 30, 2010, was 1.4 Bcf/d. Our natural gas transportation capacity at November 1, 2010, was 1.2 Bcf/d.

Natural gas volumes marketed and physically settled volumes decreased for the three and nine months ended September 30, 2010, compared with the same periods last year, due primarily to reduced transportation capacity and lower transported volumes. Transportation capacity in certain markets was not utilized due to the unfavorable economics of the location differentials.

Contingencies

Legal Proceedings - We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows. 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 the sale of equity for their liquidity and capital resource requirements. ONEOK and ONEOK Partners fund their operating expenses, debt service, dividends to shareholders and distributions to unitholders primarily with operating cash flow. We expect to continue to use these sources and ONEOK Partners’ recently established commercial paper program, discussed below, for liquidity and capital resource needs on both a short- and long-term basis. Neither ONEOK nor ONEOK Partners guarantees the debt or other similar commitments to unaffiliated parties, and ONEOK does not guarantee the debt or other similar commitments of ONEOK Partners.

In the first nine months of 2010, ONEOK accessed the commercial paper markets to meet its short-term liquidity needs. ONEOK Partners utilized the ONEOK Partners Credit Agreement and accessed the commercial paper markets to fund its short-term liquidity needs during the first nine months of 2010. In February 2010, ONEOK Partners accessed the public equity markets for its long-term financing needs. See discussion below under “ONEOK Partners’ Equity Issuance” for more information.

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In June 2010, ONEOK Partners established a commercial paper program providing for the issuance of up to $1.0 billion of unsecured commercial paper notes to fund its short-term borrowing needs. The maturities of ONEOK Partners’ commercial paper notes vary but may not exceed 270 days from the date of issue. ONEOK Partners’ commercial paper notes are sold at a negotiated discount from par or bear interest at a negotiated rate. The ONEOK Partners Credit Agreement, which expires in March 2012, is available to repay its commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowing capacity under the ONEOK Partners Credit Agreement.

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

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

	September 30,			December 31,
	2010			2009
Long-term debt		53	%		57	%
Total equity		47	%		43	%

Debt (including notes payable)		54	%		61	%
Total equity		46	%		39	%

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

	September 30,			December 31,
	2010			2009
Long-term debt		39	%		41	%
ONEOK shareholders' equity		61	%		59	%

Debt (including notes payable)		39	%		46	%
ONEOK shareholders' equity		61	%		54	%

Stock Repurchase Program - In October 2010, our Board of Directors authorized a three-year stock repurchase program to buy up to $750 million of our common stock currently issued and outstanding, subject to the limitation that purchases will not exceed $300 million in any one calendar year. If shares are repurchased, they will be acquired from time to time in open-market transactions or through privately negotiated transactions at our discretion, subject to market conditions and other factors. The purchases will be funded by our available cash, free cash flow and short-term borrowings. The program will terminate upon completion of the repurchase of $750 million of common stock or on December 31, 2013, whichever occurs first.

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

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recently established commercial paper program. In July 2010, ONEOK Partners repaid all borrowings outstanding under the ONEOK Partners Credit Agreement with proceeds from the issuance of its commercial paper.

The total amount of short-term borrowings authorized by ONEOK’s Board of Directors is $2.5 billion. At September 30, 2010, ONEOK had no commercial paper outstanding, $32.0 million in letters of credit issued under the ONEOK Credit Agreement and approximately $45.5 million of available cash and cash equivalents. ONEOK had approximately $1.2 billion of credit available at September 30, 2010, under the ONEOK Credit Agreement. As of September 30, 2010, ONEOK could have issued $3.7 billion of additional short- and long-term debt under the most restrictive provisions contained in its various borrowing agreements.

The total amount of short-term borrowings authorized by the Board of Directors of ONEOK Partners GP, the general partner of ONEOK Partners, is $1.5 billion. At September 30, 2010, ONEOK Partners had $326.4 million in commercial paper outstanding, no borrowings outstanding under the ONEOK Partners Credit Agreement, leaving approximately $673.6 million of credit available under the ONEOK Partners Credit Agreement, and approximately $5.0 million of available cash and cash equivalents. As of September 30, 2010, ONEOK Partners could have issued $1.0 billion of additional short- and long-term debt under the most restrictive provisions contained in its various borrowing agreements. At September 30, 2010, ONEOK Partners had $24.2 million in letters of credit issued outside the ONEOK Partners Credit Agreement.

The ONEOK Credit Agreement and the ONEOK Partners Credit Agreement contain certain financial, operational and legal covenants as discussed in Note H of the Notes to Consolidated Financial Statements in our Annual Report. Among other things, the ONEOK Credit Agreement’s covenants include a limitation on ONEOK’s stand-alone debt-to-capital ratio, which may not exceed 67.5 percent at the end of any calendar quarter. At September 30, 2010, ONEOK’s stand-alone debt-to-capital ratio, as calculated under the terms of the ONEOK Credit Agreement, was 38.1 percent, and ONEOK was in compliance with all covenants under the ONEOK Credit Agreement.

The ONEOK Partners Credit Agreement’s covenants include, among other things, maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in the ONEOK Partners Credit Agreement, adjusted for all non-cash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5 to 1. If ONEOK Partners consummates one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will increase to 5.5 to 1 for the three calendar quarters following the acquisitions. Upon breach of any covenant, discussed above, amounts outstanding under the ONEOK Partners Credit Agreement may become immediately due and payable. At September 30, 2010, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 3.8 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement.

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

In June 2010, ONEOK Partners repaid $250.0 million of maturing senior notes with available cash and short-term borrowings. With the repayment of these notes, ONEOK Partners no longer has any obligation to offer to repurchase the $225 million senior notes due 2011 in the event that ONEOK Partners’ long-term debt credit ratings fall below investment grade.

The indentures governing ONEOK’s senior notes due 2011, 2019 and 2028 include an event of default upon acceleration of other indebtedness of $15 million or more, and the indentures governing the senior notes due 2015 and 2035 include an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the

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trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2011, 2015, 2019, 2028 and 2035 to declare those notes immediately due and payable in full.

ONEOK may redeem the notes due 2011, 2015, 2028 (6.875 percent) and 2035, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK may redeem the notes due 2019 and 2028 (6.5 percent), in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. The notes due 2011, 2015, 2019, 2028 and 2035 are senior unsecured obligations, ranking equally in right of payment with all of ONEOK’s existing and future unsecured senior indebtedness.

The indentures governing ONEOK Partners’ senior notes due 2011 include an event of default upon acceleration of other indebtedness of $25 million or more, and the indentures governing the senior notes due 2012, 2016, 2019, 2036 and 2037 include an event of default upon the acceleration of other indebtedness of $100 million or more that would be triggered by such an offer to repurchase. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2011, 2012, 2016, 2019, 2036 and 2037 to declare those notes immediately due and payable in full.

ONEOK Partners may redeem the notes due 2011, 2012, 2016, 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. The notes due 2011, 2012, 2016, 2019, 2036 and 2037 are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and effectively junior to all of the existing and future debt and other liabilities of any non-guarantor subsidiaries, and are nonrecourse to ONEOK.

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

Capital Expenditures - ONEOK’s and ONEOK Partners’ capital expenditures are financed through operating cash flows, short- and long-term debt and the issuance of equity. Capital expenditures were $356.3 million and $614.8 million for the nine months ended September 30, 2010 and 2009, respectively. Of these amounts, ONEOK Partners’ capital expenditures were $202.8 million and $491.3 million for the nine months ended September 30, 2010 and 2009, respectively.

The following table sets forth our 2010 projected capital expenditures, excluding AFUDC:

2010 Projected Capital Expenditures
	(Millions of dollars)
ONEOK Partners	$	464
Distribution		215
Other		18
Total projected capital expenditures	$	697

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Credit Ratings - ONEOK’s and ONEOK Partners’ long-term debt credit ratings as of September 30, 2010, are shown in the table below:

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

ONEOK’s and ONEOK Partners’ commercial paper are rated Prime-2 by Moody’s and A2 by S&P. ONEOK’s and ONEOK Partners’ credit ratings, which are currently investment grade, may be affected by a material change in financial ratios or a material event affecting the business. The most common criteria for assessment of credit ratings are the debt-to-capital ratio, business risk profile, pretax and after-tax interest coverage, and liquidity. ONEOK and ONEOK Partners do not currently anticipate their respective credit ratings to be downgraded. However, if ONEOK’s or ONEOK Partners’ credit ratings were downgraded, the interest rates, as applicable, on ONEOK’s and ONEOK Partners’ commercial paper borrowings and borrowings under the ONEOK Credit Agreement or the ONEOK Partners Credit Agreement would increase, and ONEOK or ONEOK Partners could potentially lose access to the commercial paper market. In the event that ONEOK is unable to borrow funds under its commercial paper program and there has not been a material adverse change in its business, ONEOK would continue to have access to the ONEOK Credit Agreement, which expires in July 2011. In the event that ONEOK Partners is unable to borrow funds under its commercial paper program and there has not been a material adverse change in its business, ONEOK Partners would continue to have access to the ONEOK Partners Credit Agreement. An adverse rating change alone is not a default under the ONEOK Credit Agreement or the ONEOK Partners Credit Agreement. See additional discussion about our credit ratings under “Long-term Financing.”

Our Energy Services segment relies upon the investment-grade credit rating of ONEOK’s senior unsecured long-term debt to reduce its collateral requirements. If ONEOK’s credit ratings were to decline below investment grade, our ability to participate in energy marketing and trading activities could be significantly limited. Without an investment-grade rating, we may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments. At September 30, 2010, ONEOK could have been required to fund approximately $7.0 million in margin requirements related to financial contracts upon such a downgrade. A decline in ONEOK’s credit rating below investment grade may also significantly impact other business segments.

Other than 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 or ONEOK Partners’ trust indentures, building leases, equipment leases and other various contracts. Rating triggers are defined as provisions that would create an automatic default or acceleration of indebtedness based on a change in our credit rating.

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

Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity prices may impact our overall liquidity due to the impact commodity price changes have on our cash flows from operating activities, including the impact on working capital for NGLs and natural gas held in storage, margin requirements and certain energy-related receivables. We believe that ONEOK’s and ONEOK Partners’ available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity price volatility. See discussion beginning on page 59 under “Commodity Price Risk” in Item 3, Quantitative and Qualitative Disclosures about Market Risk, for information on our hedging activities.

Pension and Postretirement Benefit Plans - Information about our pension and postretirement benefits plans is included in Note K of the Notes to Consolidated Financial Statements in our Annual Report. See Note G of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.

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

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not result in actual cash receipts or payments during the period. These reconciling items include depreciation and amortization, allowance for equity funds used during construction, gain or loss on sale of assets, deferred income taxes, equity earnings from investments, distributions received from unconsolidated affiliates, deferred income taxes, share-based compensation expense, allowance for doubtful accounts, and changes in our assets and liabilities not classified as investing or financing activities.

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

	Nine Months Ended						Variances
	September 30,						2010 vs. 2009
	2010			2009			Increase (Decrease)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	760.0		$	1,270.9		$	(510.9	)	(40	%)
Investing activities		79.5			(621.6	)		701.1		*
Financing activities		(818.4	)		(1,107.2	)		288.8		26	%
Change in cash and cash equivalents		21.1			(457.9	)		479.0		*
Cash and cash equivalents at beginning of period		29.4			510.1			(480.7	)	(94	%)
Cash and cash equivalents at end of period	$	50.5		$	52.2		$	(1.7	)	(3	%)
* Percentage change is greater than 100 percent.

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

Cash flows from operating activities, before changes in operating assets and liabilities, were $721.7 million for the nine months ended September 30, 2010, compared with $623.4 million for the same period in 2009. The increase was due primarily to changes in net margin and operating expenses discussed in “Consolidated Operations” in Financial Results and Operating Information beginning on page 39.

The changes in operating assets and liabilities increased operating cash flows $38.3 million for the nine months ended September 30, 2010, compared with an increase of $647.5 million for the same period in 2009, primarily as a result of the following:

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

·	the increase in volumes of commodities in storage primarily in our Distribution segment and ONEOK Partners’ natural gas liquids business.

Investing Cash Flows - Cash provided by investing activities increased for the nine months ended September 30, 2010, compared with cash used in investing activities for the same period in 2009, due primarily to the $423.7 million in proceeds ONEOK Partners received from the Overland Pass Pipeline transaction reduced capital expenditures as a result of the completion of ONEOK Partners’ capital projects in 2009; and reduced contributions to and distributions from unconsolidated affiliates.

Financing Cash Flows - Cash used in financing activities decreased for the nine months ended September 30, 2010, compared with the same period last year, due primarily to the following:

·	Net repayments of notes payable were $555.5 million during the first nine months of 2010, compared with net repayments of $1.4 billion for the same period in 2009;

·	In June 2010, ONEOK Partners repaid $250.0 million of maturing long-term debt with available cash and short-term borrowings. In February 2009, ONEOK repaid $100.0 million of maturing long-term debt with available cash and short-term borrowings;

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

·	The change in net proceeds generated from ONEOK Partners’ common unit offerings for the nine months ended September 30, 2010, compared with the same period last year, is due primarily to the following:

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In February 2010, ONEOK Partners’ common unit offering generated net proceeds of approximately $322.7 million. In addition, ONEOK Partners GP contributed $6.8 million in order to maintain its 2 percent general partner interest. ONEOK Partners used the proceeds to repay borrowings under the ONEOK Partners Credit Agreement and for general partnership purposes.

In July 2009, ONEOK Partners’ common unit offering generated net proceeds of approximately $241.6 million. In addition, ONEOK Partners GP contributed $5.1 million in order to maintain its 2 percent general partner interest. ONEOK Partners used the proceeds to repay borrowings under the ONEOK Partners Credit Agreement and for general partnership purposes;

·	Increased ONEOK dividends paid of $1.34 per share for the nine months ended September 30, 2010, compared with $1.22 per share for the same period last year; and

·	Increased ONEOK Partners distributions paid to noncontrolling interests in consolidated subsidiaries of $3.33 per unit for the nine months ended September 30, 2010, compared with $3.24 per unit for the same period last year.

ENVIRONMENTAL AND SAFETY MATTERS

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

Pipeline Safety - We are subject to Pipeline and Hazardous Materials Safety Administration regulations, including integrity management regulations. The Pipeline Safety Improvement Act of 2002 requires pipeline companies to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. We are in compliance with all material requirements associated with the various pipeline safety regulations. Currently, Congress is reauthorizing existing Pipeline Safety legislation, and there are also a number of new bills addressing pipeline safety being considered. We are monitoring activity concerning the reauthorization and proposed new legislation, as well as potential changes in the Pipeline and Hazardous Materials Safety Administration’s regulations, to assess the potential impact on our operations. At this time, no revised or new legislation has been enacted, and potential cost, fees or expenses associated with changes or new legislation are unknown. We cannot provide assurance that existing pipeline safety regulations will not be revised or interpreted in a different manner or that new regulations will not be adopted that could result in increased compliance costs or additional operating restrictions.

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

The United States Congress is actively considering legislation to reduce greenhouse gas emissions, including carbon dioxide and methane. In addition, other federal, state and regional initiatives to regulate greenhouse gas emissions are under way. We are monitoring federal and state legislation to assess the potential impact on our operations. We estimate our direct greenhouse gas emissions annually as we collect all applicable greenhouse gas emission data for the previous year. Our most recent estimate for ONEOK and ONEOK Partners indicates that our 2009 emissions were less than 4.5 million metric tons of carbon dioxide equivalents on an annual basis. We will continue efforts to improve our ability to quantify our direct greenhouse gas emissions and will report such emissions as required by the EPA’s Mandatory Greenhouse Gas Reporting rule adopted in September 2009. The rule requires greenhouse gas emissions reporting for affected facilities on an annual basis, beginning with our 2010 emissions report that will be due in March 2011, and will require us to track the emission equivalents for the gas delivered by us to our distribution customers and emission equivalents for all NGLs delivered to customers of ONEOK Partners. Also, the EPA has recently released a proposed subpart to the Mandatory Greenhouse Gas Reporting Rule that will require the reporting of vented and fugitive emissions of methane from our facilities. The new requirements are proposed to begin in January 2011, with the first reporting of fugitive emissions due March 31, 2012. We do not expect the cost to gather this emission data to have a material impact on our results of operations, financial position or cash flows. At this time, no legislation has been enacted that assesses any costs, fees or expenses on any of these emissions.

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will consider lowering the threshold levels over the next five years, which could increase the impact on our existing facilities. However, potential costs, fees or expenses associated with the potential adjustments are unknown.

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

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

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

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

We continue to focus on maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices to limit the release of natural gas during pipeline and facility maintenance and operations. Our most recent calculation of our annual lost-and-unaccounted-for natural gas, for all of our business operations, is less than 1 percent of total throughput.

FORWARD-LOOKING STATEMENTS

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

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

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

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

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

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

·	the status of deregulation of retail natural gas distribution;

·	the capital intensive nature of our businesses;

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

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

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

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

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

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

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

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

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

·	our indebtedness could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared with our competitors that have less debt, or have other adverse consequences;

·	actions by rating agencies concerning the credit ratings of ONEOK and ONEOK Partners;

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

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

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

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

·	the impact and outcome of pending and future litigation;

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

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

-	competitive conditions in the overall energy market;

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

-	availability of additional storage capacity;

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

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

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

·	the mechanical integrity of facilities operated;

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

·	our ability to control operating costs;

·	adverse labor relations;

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

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

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

·	the impact of recently issued and future accounting updates and other changes in accounting policies;

·	the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions in the Middle East and elsewhere;

·	the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;

·	risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions;

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

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

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

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

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

·	the impact of potential impairment charges;

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

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

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

COMMODITY PRICE RISK

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

Energy Services

Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities - The following table sets forth the fair value component of our energy marketing and risk management assets and liabilities, excluding $159.3 million of net assets from derivative instruments designated as either fair value or cash flow hedges at September 30, 2010:

Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities
	(Thousands of dollars)
Net fair value of derivatives outstanding at December 31, 2009	$	2,725
Derivatives reclassified or otherwise settled during the period		(6,847	)
Fair value of new derivatives entered into during the period		34,242
Other changes in fair value		(21,786	)
Net fair value of derivatives outstanding at September 30, 2010 (a)	$	8,334
(a) - The maturities of derivatives are based on injection and withdrawal periods from April through March, which is consistent with our business strategy. The maturities are as follows: $2.8 million matures through March 2011 and $5.5 million matures through March 2012.

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

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

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

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

The potential impact on our future earnings was $4.1 million and $8.2 million at September 30, 2010 and 2009, respectively. The following table sets forth the average, high and low VAR calculations for the periods indicated:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Value-at-Risk	2010		2009		2010		2009
	(Millions of dollars)
Average	$	4.9	$	6.8	$	6.3	$	8.6
High	$	7.5	$	9.1	$	9.6	$	14.1
Low	$	3.3	$	4.6	$	3.3	$	4.6

ITEM 4. CONTROLS AND PROCEDURES

Quarterly Evaluation of Disclosure Controls and Procedures - Our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer) have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report based on the evaluation of the controls and procedures required by Rules 13a-15(b) of the Exchange Act.

Changes in Internal Controls Over Financial Reporting - There have been no changes in our internal control over financial reporting during the third quarter ended September 30, 2010, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Additional information about our legal proceedings is included under Part I, Item 3, Legal Proceedings, in our Annual Report and in our Quarterly Reports filed for the periods ending June 30, 2010 and March 31, 2010.

Gas Index Pricing Litigation - As previously reported, we, our subsidiary ONEOK Energy Services Company, L.P. (“OESC”) and one other affiliate are defending, either individually or together, against multiple lawsuits claiming damages resulting from the alleged market manipulation or false reporting of prices to gas index publications by us and others. On September 2, 2010, oral argument on the appeal in the Missouri Public Service Commission v. ONEOK, Inc., et al., case was heard by the Missouri Supreme Court. The Missouri Supreme Court issued an Order on September 21, 2010, transferring the case to the Missouri Court of Appeals, Western District. On September 24, 2010, the Missouri Court of Appeals issued an Order readopting its previous opinion in the case that affirmed the trial court’s dismissal of the case. This dismissal is final and formally concludes the case. We continue to vigorously defend against the claims involved in each of the remaining cases.

ITEM 1A. RISK FACTORS

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

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

Issuer Purchases of Equity Securities

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

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

July 1-31, 2010	1,511	(a), (b)	$22.48		-		-
August 1-31, 2010	44,675	(a)	$28.18		-		-
September 1-30, 2010	200	(a)	$22.31		-		-
Total	46,386		$27.97		-		-

(a) - Includes shares withheld pursuant to attestation of ownership and deemed tendered to us in connection with the exercise
of stock options under the ONEOK, Inc. Long-Term Incentive Plan, as follows:
1,500 shares for the period of July 1-31, 2010
44,675 shares for the period of August 1-31, 2010
200 shares for the period of September 1-30, 2010

(b) - Includes shares repurchased directly from employees, pursuant to our Employee Stock Award Program, as follows:
11 shares for the period July 1-31, 2010

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ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not Applicable.

ITEM 4. (REMOVED AND RESERVED)

Not Applicable.

ITEM 5. OTHER INFORMATION

Not Applicable.

ITEM 6. EXHIBITS

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

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

Exhibit No. Exhibit Description

31.1

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

31.2

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

32.1

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

32.2

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

101.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Extension Schema Document

101.CAL

XBRL Taxonomy Calculation Linkbase Document

101.DEF

XBRL Taxonomy Extension Definitions Document

101.LAB

XBRL Taxonomy Label Linkbase Document

101.PRE

XBRL Taxonomy Presentation Linkbase Document

Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in XBRL: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three and nine months ended September 30, 2010 and 2009; (iii) Consolidated Balance Sheets at September 30, 2010, and December 31, 2009; (iv) Consolidated Statements of Cash Flows for the nine months ended September 30, 2010 and 2009; (v) Consolidated Statement of Changes in Equity for the nine months ended September 30, 2010; (vi) Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2010 and 2009; and (vii) Notes to Consolidated Financial Statements.

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

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

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SIGNATURE

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

	ONEOK, Inc. Registrant
Date: November 3, 2010	By:	/s/ Curtis L. Dinan
		Curtis L. Dinan Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)