Edgar Filing: ONEOK INC /NEW/

form_10-q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2012

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

For the transition period from __________ to __________.

Commission file number 001-13643

ONEOK, Inc.

(Exact name of registrant as specified in its charter)

Oklahoma	73-1520922
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

100 West Fifth Street, Tulsa, OK	74103
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code (918) 588-7000

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No __

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes X No __

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

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

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

Yes __ No X

On July 27, 2012, the Company had 205,056,209 shares of common stock outstanding.

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Table of Contents

ONEOK, Inc.

TABLE OF CONTENTS

Part I.	Financial Information	Page No.
Item 1.	Financial Statements (Unaudited)
	Consolidated Statements of Income - Three and Six Months Ended June 30, 2012 and 2011	6
	Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2012 and 2011	7
	Consolidated Balance Sheets - June 30, 2012, and December 31, 2011	8-9
	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2012 and 2011	11
	Consolidated Statement of Changes in Equity - Six Months Ended June 30, 2012	12-13
	Notes to Consolidated Financial Statements	14-36
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37-62
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	62-63
Item 4.	Controls and Procedures	63
Part II.	Other Information
Item 1.	Legal Proceedings	64
Item 1A.	Risk Factors	64
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	64
Item 3.	Defaults Upon Senior Securities	64
Item 4.	Mine Safety Disclosures	64
Item 5.	Other Information	64
Item 6.	Exhibits	65
Signature		66

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

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

INFORMATION AVAILABLE ON OUR WEBSITE

We make available, free of charge, on our website (www.oneok.com) copies of our Annual Reports, Quarterly Reports, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of our Code of Business Conduct, Corporate Governance Guidelines and Director Independence Guidelines are also available on our website, and we will provide copies of these documents upon request. Our website and any contents thereof are not incorporated by reference into this report.

We also make available on our website the Interactive Data Files required to be submitted and posted pursuant to Rule 405 of Regulation S-T.

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GLOSSARY

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

AFUDC

Allowance for funds used during construction

Annual Report

Annual Report on Form 10-K for the year ended December 31, 2011

ASU

Accounting Standards Update

Bbl

Barrels, 1 barrel is equivalent to 42 United States gallons

Bbl/d

Barrels per day

BBtu/d

Billion British thermal units per day

Bcf

Billion cubic feet

Bcf/d

Billion cubic feet per day

Btu(s)

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

temperature of one pound of water one degree Fahrenheit

CFTC

Commodities Futures Trading Commission

Clean Air Act

Federal Clean Air Act, as amended

Clean Water Act

Federal Water Pollution Control Act Amendments of 1972, as amended

Dodd-Frank Act

Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010

DOT

United States Department of Transportation

EBITDA

Earnings before interest expense, income taxes, depreciation and amortization

EPA

United States Environmental Protection Agency

Exchange Act

Securities Exchange Act of 1934, as amended

FASB

Financial Accounting Standards Board

FERC

Federal Energy Regulatory Commission

GAAP

Accounting principles generally accepted in the United States of America

Intermediate Partnership

ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary

of ONEOK Partners, L.P.

KCC

Kansas Corporation Commission

KDHE

Kansas Department of Health and Environment

LDCs

Local distribution companies

LIBOR

London Interbank Offered Rate

MBbl

Thousand barrels

MBbl/d

Thousand barrels per day

Mcf

Thousand cubic feet

MDth/d

Thousand dekatherms per day

MMBbl

Million barrels

MMBtu

Million British thermal units

MMBtu/d

Million British thermal units per day

MMcf

Million cubic feet

MMcf/d

Million cubic feet per day

Moody’s

Moody’s Investors Service, Inc.

Natural Gas Policy Act

Natural Gas Policy Act of 1978, as amended

NGL products

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

mix, propane, iso-butane, normal butane and natural gasoline

NGL(s)

Natural gas liquid(s)

NYMEX

New York Mercantile Exchange

OCC

Oklahoma Corporation Commission

ONEOK

ONEOK, Inc.

ONEOK 2011 Credit Agreement

ONEOK’s five-year, $1.2 billion revolving credit agreement dated April 5, 2011

ONEOK Partners

ONEOK Partners, L.P.

ONEOK Partners 2011 Credit Agreement

ONEOK Partners’ five-year, $1.2 billion revolving credit agreement dated

August 1, 2011

ONEOK Partners GP

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

general partner of ONEOK Partners

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Quarterly Report(s)

Quarterly Report(s) on Form 10-Q

POP

Percent of Proceeds

S&P

Standard & Poor’s Rating Services

SEC

Securities and Exchange Commission

Securities Act

Securities Act of 1933, as amended

XBRL

eXtensible Business Reporting Language

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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(Unaudited)	2012			2011			2012			2011
	(Thousands of dollars, except per share amounts)

Revenues	$	2,529,260		$	3,444,798		$	5,943,860		$	7,205,398
Cost of sales and fuel		1,980,298			2,925,965			4,751,311			6,056,688
Net margin		548,962			518,833			1,192,549			1,148,710
Operating expenses
Operations and maintenance		204,126			197,772			397,007			390,531
Depreciation and amortization		84,586			78,793			167,995			158,150
Goodwill impairment		-			-			10,255			-
General taxes		27,137			25,837			58,314			54,759
Total operating expenses		315,849			302,402			633,571			603,440
Gain (loss) on sale of assets		966			(212	)		1,023			(722	)
Operating income		234,079			216,219			560,001			544,548
Equity earnings from investments (Note K)		29,169			29,544			63,789			61,636
Allowance for equity funds used during construction		1,849			400			2,824			866
Other income		686			340			6,446			3,692
Other expense		(4,898	)		(772	)		(3,071	)		(3,057	)
Interest expense		(71,535	)		(75,498	)		(147,350	)		(154,847	)
Income before income taxes		189,350			170,233			482,639			452,838
Income taxes		(40,412	)		(35,904	)		(114,251	)		(120,224	)
Income from continuing operations		148,938			134,329			368,388			332,614
Income from discontinued operations, net of tax (Note B)		-			437			762			1,498
Gain on sale of discontinued operations, net of tax (Note B)		267			-			13,517			-
Net income		149,205			134,766			382,667			334,112
Less: Net income attributable to noncontrolling interests		88,212			79,624			198,809			148,840
Net income attributable to ONEOK	$	60,993		$	55,142		$	183,858		$	185,272

Amounts attributable to ONEOK:
Income from continuing operations	$	60,726		$	54,705		$	169,579		$	183,774
Income from discontinued operations		267			437			14,279			1,498
Net income	$	60,993		$	55,142		$	183,858		$	185,272

Basic earnings per share:
Income from continuing operations (Note I)	$	0.29		$	0.26		$	0.82		$	0.87
Income from discontinued operations		-			-			0.07			-
Net income	$	0.29		$	0.26		$	0.89		$	0.87

Diluted earnings per share:
Income from continuing operations (Note I)	$	0.29		$	0.25		$	0.80		$	0.85
Income from discontinued operations		-			-			0.07			-
Net income	$	0.29		$	0.25		$	0.87		$	0.85

Average shares (thousands)
Basic		207,292			210,674			207,454			212,358
Diluted		211,784			216,060			211,818			217,210

Dividends declared per share of common stock	$	0.330		$	0.260		$	0.635		$	0.520
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(Unaudited)	2012			2011			2012			2011
	(Thousands of dollars)

Net income	$	149,205		$	134,766		$	382,667		$	334,112
Other comprehensive income (loss), net of tax
Unrealized gains (losses) on energy marketing and risk-management
assets/liabilities, net of tax of $4,773, $(5,028), $(14,229) and
$(3,614), respectively		(12,634	)		16,819			34,939			(69	)
Realized (gains) losses in net income, net of tax of $8,449, $(301),
$6,835 and $11,934, respectively		(22,556	)		3,407			(23,736	)		(16,709	)
Unrealized holding gains (losses) on available-for-sale securities,
net of tax of $65, $31, $(76) and $94, respectively		(104	)		(49	)		120			(148	)
Change in pension and postretirement benefit plan liability, net of tax
of $3,644, $2,947, $7,288 and $5,895, respectively		(5,777	)		(4,672	)		(11,554	)		(9,345	)
Other, net of tax of $0, $39, $0 and $50, respectively		-			(62	)		-			(80	)
Total other comprehensive income (loss), net of tax		(41,071	)		15,443			(231	)		(26,351	)
Comprehensive income		108,134			150,209			382,436			307,761
Less: Comprehensive income attributable to noncontrolling interests		73,936			91,196			198,097			144,953
Comprehensive income attributable to ONEOK	$	34,198		$	59,013		$	184,339		$	162,808
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	June 30,		December 31,
(Unaudited)	2012		2011
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	114,920	$	65,953
Accounts receivable, net		793,842		1,339,933
Gas and natural gas liquids in storage		561,802		549,915
Commodity imbalances		37,716		63,452
Energy marketing and risk management assets (Notes C and D)		90,335		40,280
Other current assets		208,704		185,143
Assets of discontinued operations (Note B)		-		74,136
Total current assets		1,807,319		2,318,812

Property, plant and equipment
Property, plant and equipment		11,953,916		11,177,934
Accumulated depreciation and amortization		2,855,863		2,733,601
Net property, plant and equipment		9,098,053		8,444,333

Investments and other assets
Investments in unconsolidated affiliates (Note K)		1,210,268		1,223,398
Goodwill and intangible assets		1,000,039		1,014,127
Other assets		701,512		695,965
Total investments and other assets		2,911,819		2,933,490
Total assets	$	13,817,191	$	13,696,635
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	June 30,			December 31,
(Unaudited)	2012			2011
Liabilities and equity	(Thousands of dollars)
Current liabilities
Current maturities of long-term debt	$	12,262		$	364,391
Notes payable (Note E)		595,931			841,982
Accounts payable		911,977			1,341,718
Commodity imbalances		201,515			202,206
Energy marketing and risk management liabilities (Notes C and D)		138,028			137,680
Other current liabilities		396,964			345,383
Liabilities of discontinued operations (Note B)		-			12,815
Total current liabilities		2,256,677			3,246,175

Long-term debt, excluding current maturities (Note F)		5,224,623			4,529,551

Deferred credits and other liabilities
Deferred income taxes		1,457,896			1,446,591
Other deferred credits		672,007			674,586
Total deferred credits and other liabilities		2,129,903			2,121,177

Commitments and contingencies (Note M)

Equity (Note G)
ONEOK shareholders' equity:
Common stock, $0.01 par value:
authorized 600,000,000 shares; issued 245,811,180 shares and outstanding
205,041,894 shares at June 30, 2012; issued 245,809,848 shares and
outstanding 206,509,960 shares at December 31, 2011		2,458			2,458
Paid-in capital		1,326,204			1,417,185
Accumulated other comprehensive loss (Note H)		(205,640	)		(206,121	)
Retained earnings		2,017,460			1,960,374
Treasury stock, at cost: 40,769,286 shares at June 30, 2012, and
39,299,888 shares at December 31, 2011		(1,050,942	)		(935,323	)
Total ONEOK shareholders' equity		2,089,540			2,238,573

Noncontrolling interests in consolidated subsidiaries		2,116,448			1,561,159

Total equity		4,205,988			3,799,732
Total liabilities and equity	$	13,817,191		$	13,696,635
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Six Months Ended
	June 30,
(Unaudited)	2012			2011
	(Thousands of dollars)
Operating activities
Net income	$	382,667		$	334,112
Depreciation and amortization		168,003			158,215
Impairment of goodwill		10,255			-
Gain on sale of discontinued operations		(13,517	)		-
Reclassified loss on energy price risk management assets and liabilities		29,861			-
Equity earnings from investments		(63,789	)		(61,636	)
Distributions received from unconsolidated affiliates		69,490			55,302
Deferred income taxes		111,172			108,504
Share-based compensation expense		16,928			29,615
Allowance for equity funds used during construction		(2,824	)		(866	)
Loss (gain) on sale of assets		(1,023	)		722
Other		(1,308	)		(1,013	)
Changes in assets and liabilities:
Accounts receivable		541,053			209,112
Gas and natural gas liquids in storage		(11,445	)		134,760
Accounts payable		(404,006	)		(20,199	)
Commodity imbalances, net		25,045			(12,452	)
Energy marketing and risk management assets and liabilities		(56,590	)		(4,437	)
Other assets and liabilities		(147,362	)		(54,140	)
Cash provided by operating activities		652,610			875,599

Investing activities
Capital expenditures (less allowance for equity funds used during construction)		(780,697	)		(523,772	)
Proceeds from sale of discontinued operations, net of cash sold		32,008			-
Contributions to unconsolidated affiliates		(7,237	)		(1,655	)
Distributions received from unconsolidated affiliates		14,705			15,750
Proceeds from sale of assets		1,828			788
Other		942			-
Cash used in investing activities		(738,451	)		(508,889	)

Financing activities
Borrowing (repayment) of notes payable, net		(246,051	)		(30,222	)
Issuance of debt, net of discounts		699,657			1,295,450
Long-term debt financing costs		(5,395	)		(10,986	)
Repayment of debt		(356,173	)		(631,316	)
Repurchase of common stock		(150,000	)		(300,105	)
Issuance of common stock		4,591			4,920
Issuance of common units, net of issuance costs		459,680			-
Dividends paid		(126,772	)		(111,356	)
Distributions to noncontrolling interests		(153,588	)		(136,556	)
Cash provided by financing activities		125,949			79,829
Change in cash and cash equivalents		40,108			446,539
Change in cash and cash equivalents included in discontinued operations		8,859			(4,701	)
Change in cash and cash equivalents from continuing operations		48,967			441,838
Cash and cash equivalents at beginning of period		65,953			30,341
Cash and cash equivalents at end of period	$	114,920		$	472,179
See accompanying Notes to Consolidated Financial Statements.

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


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

December 31, 2011			245,809,848		$	2,458	$	1,417,185		$	(206,121	)
Net income			-			-		-			-
Other comprehensive income			-			-		-			481
Repurchase of common stock			-			-		-			-
Common stock issued			1,332			-		(27,829	)		-
Common stock dividends -
$0.61 per share			-			-		-			-
Issuance of common units of ONEOK Partners			-			-		(51,100	)		-
Distributions to noncontrolling interests			-			-		-			-
Other			-			-		(12,052	)		-
June 30, 2012			245,811,180		$	2,458	$	1,326,204		$	(205,640	)
See accompanying Notes to Consolidated Financial Statements.

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

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

December 31, 2011		$	1,960,374		$	(935,323	)		$	1,561,159		$	3,799,732
Net income			183,858			-				198,809			382,667
Other comprehensive income			-			-				(712	)		(231	)
Repurchase of common stock			-			(150,000	)			-			(150,000	)
Common stock issued			-			34,381				-			6,552
Common stock dividends -
$0.61 per share			(126,772	)		-				-			(126,772	)
Issuance of common units of ONEOK Partners			-			-				510,780			459,680
Distributions to noncontrolling interests			-			-				(153,588	)		(153,588	)
Other			-			-				-			(12,052	)
June 30, 2012		$	2,017,460		$	(1,050,942	)		$	2,116,448		$	4,205,988

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ONEOK, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our accompanying unaudited consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. These statements have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair presentation of the results for the interim periods presented. All such adjustments are of a normal recurring nature. The 2011 year-end consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements in our Annual Report. Due to the seasonal nature of our business, the results of operations for the three and six months ended June 30, 2012, are not necessarily indicative of the results that may be expected for a 12-month period.

Stock Split - In June 2012, we completed our previously announced two-for-one split of our common stock. The two-for-one split was effected by a distribution on June 1, 2012, of one share of stock for each share outstanding and held by shareholders of record on May 24, 2012. We have adjusted all share and per-share amounts contained herein, to be presented on a post-split basis.

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

Recently Issued Accounting Standards Update - In May 2011, the FASB issued ASU 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRS),” which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and IFRS. This new guidance changes some fair value measurement principles and disclosure requirements. We adopted this guidance with our March 31, 2012, Quarterly Report, and the impact was not material. See Note C for information on our fair value measurements.

In June 2011, the FASB issued ASU 2011-05, “Presentation of Comprehensive Income,” which provides two options for presenting items of net income, other comprehensive income and total comprehensive income either by creating one continuous statement of comprehensive income or two separate consecutive statements, and requires certain other disclosures. In December 2011, the FASB issued ASU 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05,” which deferred certain presentation requirements in ASU 2011-05 for items reclassified out of accumulated other comprehensive income. We adopted this guidance, except for the portions deferred by ASU 2011-12, with our March 31, 2012, Quarterly Report, and the impact was not material.

In July 2012, the FASB issued ASU 2012-02, “Testing Indefinite-lived Intangible Assets for Impairment,” which allows companies to perform a “qualitative” assessment to determine whether further impairment testing of indefinite-lived intangible assets is necessary. Under the revised standard, an entity is not required to calculate the fair value of an indefinite-lived intangible asset and perform the quantitative impairment test unless the entity determines that it is more likely than not that the asset is impaired. An entity has the option to bypass the qualitative assessment and perform the quantitative impairment test for any indefinite-lived intangible assets in any period. We are evaluating the impact of this recently issued guidance, which is required to be adopted for our annual assessments beginning in 2013.

B. DISCONTINUED OPERATIONS

On February 1, 2012, we sold ONEOK Energy Marketing Company, our retail natural gas marketing business, to Constellation Energy Group, Inc. for $22.5 million plus working capital. We received net proceeds of approximately $32.9 million, $0.9 million of which was received in July 2012, and recognized a gain on the sale of approximately $13.5 million, net of taxes of $8.3 million. The proceeds from the sale were used to reduce short-term borrowings. The financial information of ONEOK Energy Marketing Company is reflected as discontinued operations in this Quarterly Report. All prior periods presented have been recast to reflect the discontinued operations.

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

	One Month Ended		Three Months Ended				Six Months Ended
	January 31,			June 30,			June 30,
	2012			2011			2011
	(Thousands of dollars)
Revenues	$	27,607		$	69,677		$	175,966
Cost of sales and fuel		25,961			66,862			169,479
Net margin		1,646			2,815			6,487
Operating costs		408			2,084			4,017
Depreciation and amortization		8			33			65
Operating income		1,230			698			2,405
Other income (expense), net		-			(1	)		15
Income taxes		(468	)		(260	)		(922	)
Income from discontinued operations, net	$	762		$	437		$	1,498

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

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

Liabilities
Accounts payable		$	11,435
Energy marketing and risk management liabilities			629
Other liabilities			751

Liabilities of discontinued operations

12,815

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

C. FAIR VALUE MEASUREMENTS

Fair Value Measurements - We define fair value as the price that would be received from the sale of an asset or the transfer of a liability in an orderly transaction between market participants at the measurement date. We use the market and income approaches to determine the fair value of our assets and liabilities and consider the markets in which the transactions are executed. We measure the fair value of groups of financial assets and liabilities consistent with how a market participant would price the net risk exposure at the measurement date.

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

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observable and unobservable market data. We validate our valuation inputs with third-party information and settlement prices from other sources, where available. In addition, as prescribed by the income approach, we compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets and liabilities to present value using interest-rate yields to calculate present-value discount factors derived from LIBOR, Eurodollar futures and interest-rate swaps. We also take into consideration the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions. We consider current market data in evaluating counterparties’, as well as our own, nonperformance risk, net of collateral, by using specific and sector bond yields and also monitor the credit default swap markets. Although we use our best estimates to determine the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ from our estimates, and the differences could be material.

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

	June 30, 2012
	Level 1			Level 2			Level 3			Netting			Total
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	330,358		$	27,248		$	46,636		$	-		$	404,242
Physical contracts		-			12,308			2,944			-			15,252
Netting		-			-			-			(320,001	)		(320,001	)
Total derivatives		330,358			39,556			49,580			(320,001	)		99,493
Trading securities (b)		6,326			-			-			-			6,326
Available-for-sale investment securities (c)		2,145			-			-			-			2,145
Total assets	$	338,829		$	39,556		$	49,580		$	(320,001	)	$	107,964

Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(304,810	)	$	(5,171	)	$	(11,148	)	$	-		$	(321,129	)
Physical contracts		-			(2	)		(687	)		-			(689	)
Netting		-			-			-			299,848			299,848
Interest-rate contracts		-			(116,166	)		-			-			(116,166	)
Total derivatives		(304,810	)		(121,339	)		(11,835	)		299,848			(138,136	)
Fair value of firm commitments (d)		-			-			(4,250	)		-			(4,250	)
Total liabilities	$	(304,810	)	$	(121,339	)	$	(16,085	)	$	299,848		$	(142,386	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk management assets and liabilities and other assets on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At June 30, 2012, we held $21.7 million of cash collateral and had posted $8.4 million of cash collateral with various counterparties.
(b) - Included in our Consolidated Balance Sheets as other current assets.
(c) - Included in our Consolidated Balance Sheets as other assets.
(d) - Included in our Consolidated Balance Sheets as other current liabilities and other deferred credits.

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	December 31, 2011
	Level 1			Level 2			Level 3			Netting			Total
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	545,247		$	13,874		$	32,931		$	-		$	592,052
Physical contracts		-			23,879			14,916			-			38,795
Netting		-			-			-			(569,243	)		(569,243	)
Total derivatives		545,247			37,753			47,847			(569,243	)		61,604
Trading securities (b)		5,749			-			-			-			5,749
Available-for-sale investment securities (c)		1,949			-			-			-			1,949
Total assets	$	552,945		$	37,753		$	47,847		$	(569,243	)	$	69,302

Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(479,073	)	$	(6,498	)	$	(20,995	)	$	-		$	(506,566	)
Physical contracts		-			(261	)		(1,748	)		-			(2,009	)
Netting		-			-			-			497,608			497,608
Interest-rate contracts		-			(128,666	)		-			-			(128,666	)
Total derivatives		(479,073	)		(135,425	)		(22,743	)		497,608			(139,633	)
Fair value of firm commitments (d)		-			-			(7,283	)		-			(7,283	)
Total liabilities	$	(479,073	)	$	(135,425	)	$	(30,026	)	$	497,608		$	(146,916	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk management assets and liabilities, other assets and other deferred credits on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2011, we held $73.3 million of cash collateral and had posted $1.7 million of cash collateral with various counterparties.
(b) - Included in our Consolidated Balance Sheets as other current assets.
(c) - Included in our Consolidated Balance Sheets as other assets.
(d) - Included in our Consolidated Balance Sheets as other current liabilities and other deferred credits.

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

Our Level 1 fair value measurements are based on NYMEX-settled prices and actively quoted prices for equity securities. These balances are comprised predominantly of exchange-traded derivative contracts, including futures and certain options for natural gas and crude oil, which are valued based on unadjusted quoted prices in active markets. Also included in Level 1 are equity securities.

Our Level 2 fair value inputs are based on NYMEX-settled prices for natural gas and crude oil that are utilized to determine the fair value of certain nonexchange-traded financial instruments, including natural gas and crude oil swaps, as well as physical forwards. Also, included in Level 2 are interest-rate swaps that are valued using financial models that incorporate the implied forward LIBOR yield curve for the same period as the future interest swap settlements.

Our Level 3 inputs include internally developed basis curves incorporating observable and unobservable market data, NGL price curves from independent broker quotes, market volatilities derived from the most recent NYMEX close spot prices and forward LIBOR curves, and adjustments for the credit risk of our counterparties. We corroborate the data on which our fair value estimates are based using our market knowledge of recent transactions, analysis of historical correlations and validation with independent broker quotes. The derivatives categorized as Level 3 include natural gas basis swaps, swing swaps, options, other commodity swaps and physical forward contracts. Also included in Level 3 are the fair values of firm commitments. We do not believe that our Level 3 fair value estimates have a material impact on our results of operations, as the majority of our derivatives are accounted for as hedges for which ineffectiveness is not material. The significant unobservable inputs used in the fair value measurement of our swaps, forwards and firm commitments are the unpublished forward basis and index curves. Significant increases or decreases in either of those inputs in isolation would not have a material impact on our fair value measurements.

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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)
April 1, 2012	$	17,948		$	(3,770	)	$	14,178
Total realized/unrealized gains (losses):
Included in earnings (a)		(1,117	)		(480	)		(1,597	)
Included in other comprehensive income (loss)		20,942			-			20,942
Transfers into Level 3		(28	)		-			(28	)
June 30, 2012	$	37,745		$	(4,250	)	$	33,495

Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of June 30, 2012 (a)	$	1,571		$	(1,318	)	$	253
(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)
April 1, 2011	$	30,615		$	(28,991	)	$	1,624
Total realized/unrealized gains (losses):
Included in earnings (a)		(12,329	)		7,779			(4,550	)
Included in other comprehensive income (loss)		1,297			-			1,297
Transfers into Level 3		4,757			-			4,757
Transfers out of Level 3		(482	)		-			(482	)
June 30, 2011	$	23,858		$	(21,212	)	$	2,646

Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of June 30, 2011 (a)	$	11,278		$	(3,672	)	$	7,606
(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, 2012	$	25,104		$	(7,283	)	$	17,821
Total realized/unrealized gains (losses):
Included in earnings (a)		(7,873	)		3,033			(4,840	)
Included in other comprehensive income (loss)		26,727			-			26,727
Sale of discontinued operations		(3,636	)		-			(3,636	)
Transfers out of Level 3		(2,577	)		-			(2,577	)
June 30, 2012	$	37,745		$	(4,250	)	$	33,495

Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of June 30, 2012 (a)	$	(419	)	$	(640	)	$	(1,059	)
(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			Total
	(Thousands of dollars)
January 1, 2011	$	49,266		$	(29,536	)	$	19,730
Total realized/unrealized gains (losses):
Included in earnings (a)		(20,333	)		8,324			(12,009	)
Included in other comprehensive income (loss)		(8,558	)		-			(8,558	)
Transfers into Level 3		4,182			-			4,182
Transfers out of Level 3		(699	)		-			(699	)
June 30, 2011	$	23,858		$	(21,212	)	$	2,646

Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of June 30, 2011 (a)	$	12,524		$	(6,634	)	$	5,890
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.

Realized/unrealized gains (losses) include the realization of our derivative contracts through maturity and changes in fair value of our hedged firm commitments. We recognize transfers into and out of the levels in the fair value hierarchy as of the end of each reporting period. We had no transfers into or out of Level 1 during the periods presented. Transfers into Level 3 represent existing assets or liabilities that were previously categorized at a higher level for which the unobservable inputs became a more significant portion of the fair value estimates. Transfers out of Level 3 represent existing assets and liabilities that were classified previously as Level 3 for which the observable inputs became a more significant portion of the fair value estimates.

Our Level 3 fair value measurements based on unobservable inputs, excluding the portion of our fair value measurements based on third-party pricing information without adjustment, are not material at June 30, 2012.

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

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

Our cash and cash equivalents are comprised of bank and money market accounts and are classified as Level 1. Our notes payable are classified as Level 2 since the estimated fair value of the notes payable can be determined using information available in the commercial paper market. The estimated fair value of our consolidated long-term debt, including current maturities, was $5.9 billion at June 30, 2012, and $5.6 billion at December 31, 2011. The book value of long-term debt, including current maturities, was $5.2 billion and $4.9 billion at June 30, 2012, and December 31, 2011, respectively. The estimated fair value of the aggregate of ONEOK’s and ONEOK Partners’ senior notes outstanding was determined using quoted market prices for similar issues with similar terms and maturities. Our consolidated long-term debt is classified as Level 2.

D. RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

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

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

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forecasted purchases and sales of commodities and natural gas and natural gas liquids in storage. Commodity price volatility may have a significant impact on the fair value of our derivative instruments as of a given date;

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

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

·	Interest-rate risk - We are also subject to fluctuations in interest rates. We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps.

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

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

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

Swaps - Financial trades involving the exchange of payments based on two different pricing structures for a commodity or other instrument. In a typical commodity swap, parties exchange payments based on changes in the price of a commodity or a market index, while fixing the price they effectively pay or receive for the physical commodity. As a result, one party assumes the risks and benefits of movements in market prices, while the other party assumes the risks and benefits of a fixed price for the commodity. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts; and

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

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

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

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

·	reducing our exposure to fluctuations in interest and foreign currency exchange rates; and

·	reducing variability in cash flows from changes in interest rates associated with forecasted debt issuances.

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

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

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

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ONEOK and ONEOK Partners each entered into forward-starting interest-rate swaps designated as cash flow hedges of the variability of interest payments on a portion of forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. ONEOK had interest-rate swaps with notional values totaling $500 million at December 31, 2011. In January 2012, ONEOK entered into additional interest-rate swaps with notional amounts totaling $200 million. Upon issuance in January 2012 of our $700 million, 4.25-percent senior notes due 2022, ONEOK settled all $700 million of its interest-rate swaps and realized a loss of $44.1 million in accumulated other comprehensive income that will be amortized to interest expense over the term of the hedged debt. At June 30, 2012, and December 31, 2011, ONEOK Partners had forward-starting interest-rate swaps with notional amounts totaling $1 billion and $750 million, respectively. In July 2012, ONEOK Partners entered into additional forward-starting interest-rate swaps with settlement dates greater than 12 months that were also designated as cash flow hedges with notional amounts totaling $400 million.

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

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

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

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

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

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

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

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

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

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

	June 30, 2012						December 31, 2011
	Fair Values of Derivatives (a)						Fair Values of Derivatives (a)
	Assets			(Liabilities)			Assets			(Liabilities)
	(Thousands of dollars)
Derivatives designated as hedging instruments
Commodity contracts
Financial contracts	$	136,655	(b)	$	(48,014	)(b)	$	184,184	(c)	$	(73,346	)(c)
Physical contracts		165			(71	)		62			(344	)
Interest-rate contracts		-			(116,166	)		-			(128,666	)
Total derivatives designated as hedging instruments		136,820			(164,251	)		184,246			(202,356	)
Derivatives not designated as hedging instruments
Commodity contracts
Nontrading instruments
Financial contracts		190,780			(197,993	)		295,948			(323,170	)
Physical contracts		15,087			(618	)		38,733			(1,665	)
Trading instruments
Financial contracts		76,807			(75,122	)		111,920			(110,050	)
Total derivatives not designated as hedging instruments		282,674			(273,733	)		446,601			(434,885	)
Total derivatives	$	419,494		$	(437,984	)	$	630,847		$	(637,241	)
(a) - Included on a net basis in energy marketing and risk management assets and liabilities, other assets and other deferred credits on our Consolidated Balance Sheets.
(b) - Includes $7.5 million of derivative assets associated with cash flow purchase hedges tied to injections of inventory into storage that were adjusted to reflect the lower of cost or market value in a prior period. The deferred gains associated with these assets have been reclassified from accumulated other comprehensive loss.
(c) - Includes $88.9 million of derivative assets associated with cash flow hedges of inventory that were adjusted to reflect the lower of cost or market value. The deferred gains associated with these assets have been reclassified from accumulated other comprehensive loss.

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

		June 30, 2012					December 31, 2011
	Contract Type	Purchased/ Payor		Sold/ Receiver			Purchased/ Payor		Sold/ Receiver
Derivatives designated as hedging instruments:
Cash flow hedges
Fixed price
- Natural gas (Bcf)	Exchange futures		8.1		(16.7	)		21.2		(23.4	)
	Swaps		8.5		(90.3	)		19.5		(111.9	)
- Crude oil and NGLs (MMBbl)	Swaps		-		(2.6	)		-		(2.9	)
Basis
- Natural gas (Bcf)	Forwards and swaps		13.7		(45.5	)		3.2		(82.8	)
Interest-rate contracts (Millions of dollars)	Forward-starting swaps	$	1,000.0		-		$	1,250.0		-

Fair value hedges
Basis
- Natural gas (Bcf)	Forwards and swaps		91.0		(91.0	)		76.5		(77.0	)

Derivatives not designated as hedging instruments:
Fixed price
- Natural gas (Bcf)	Exchange futures		56.1		(44.7	)		76.9		(59.6	)
	Forwards and swaps		136.0		(149.2	)		235.8		(253.4	)
	Options		205.0		(205.3	)		33.6		(14.3	)
Basis
- Natural gas (Bcf)	Forwards and swaps		159.3		(164.6	)		216.9		(219.3	)
Index
- Natural gas (Bcf)	Forwards and swaps		34.5		(15.3	)		29.3		(22.1	)

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

Cash Flow Hedges - Our Energy Services and ONEOK Partners segments use derivative instruments to hedge the cash flows associated with anticipated purchases and sales of natural gas, NGLs and condensate and cost of fuel used in the transportation of natural gas. Accumulated other comprehensive income (loss) at June 30, 2012, includes gains of approximately $15.2 million, net of tax, related to these hedges that will be recognized within the next 18 months as the forecasted transactions affect earnings. If prices remain at current levels, we will recognize $8.9 million in net gains over the next 12 months, and we will recognize net gains of $6.3 million thereafter. The remaining amounts deferred in accumulated other comprehensive income (loss) are primarily attributable to our interest-rate swaps, which will be amortized to interest expense over the life of long-term, fixed-rate debt upon issuance of the debt.

For the six months ended June 30, 2012, net margin in our Consolidated Statement of Income includes losses of $29.9 million related to certain financial contracts that were used to hedge forecasted purchases of natural gas. As a result of the continued decline in natural gas prices, the combination of the cost basis of the forecasted purchases of inventory and the financial contracts exceed the amount expected to be recovered through sales of that inventory after considering related sales hedges, which requires reclassification of the loss from accumulated other comprehensive loss to current period earnings.

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

	Three Months Ended					Six Months Ended
Derivatives in Cash Flow	June 30,					June 30,
Hedging Relationships	2012			2011		2012			2011
	(Thousands of dollars)
Commodity contracts	$	35,349		$	21,847	$	80,914		$	3,545
Interest-rate contracts		(52,756	)		-		(31,746	)		-
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	$	(17,407	)	$	21,847	$	49,168		$	3,545

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

	Location of Gain (Loss) Reclassified from	Three Months Ended
Derivatives in Cash Flow	Accumulated Other Comprehensive Income	June 30,
Hedging Relationships	(Loss) into Net Income (Effective Portion)	2012			2011
		(Thousands of dollars)
Commodity contracts	Revenues	$	33,660		$	(3,510	)
Commodity contracts	Cost of sales and fuel		(1,460	)		(108	)
Interest-rate contracts	Interest expense		(1,195	)		(90	)
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)		$	31,005		$	(3,708	)

	Location of Gain (Loss) Reclassified from	Six Months Ended
Derivatives in Cash Flow	Accumulated Other Comprehensive Income	June 30,
Hedging Relationships	(Loss) into Net Income (Effective Portion)	2012			2011
		(Thousands of dollars)
Commodity contracts	Revenues	$	96,030		$	29,877
Commodity contracts	Cost of sales and fuel		(63,437	)		(936	)
Interest-rate contracts	Interest expense		(2,022	)		(298	)
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)		$	30,571		$	28,643

Ineffectiveness related to our cash flow hedges was not material for the three months and six months ended June 30, 2012 and 2011. In the event that it becomes probable that a forecasted transaction will not occur, we will discontinue cash flow hedge treatment, which will affect earnings. For the three and six months ended June 30, 2012 and 2011, there were no gains or losses due to the discontinuance of cash flow hedge treatment as a result of the underlying transactions being no longer probable.

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

		Three Months Ended					Six Months Ended
Derivatives Not Designated as		June 30,					June 30,
Hedging Instruments	Location of Gain (Loss)	2012		2011			2012		2011
		(Thousands of dollars)
Commodity contracts - trading	Revenues	$	491	$	(289	)	$	806	$	117
Commodity contracts - nontrading (a)	Cost of sales and fuel		1,361		7,959			4,324		10,507
Total gain recognized in income on derivatives		$	1,852	$	7,670		$	5,130	$	10,624
(a) - Amounts are presented net of deferred losses associated with derivatives entered into by our Natural Gas Distribution segment.

Our Natural Gas Distribution segment held natural gas call options with premiums totaling $6.3 million and $10.0 million at June 30, 2012, and December 31, 2011, respectively. The premiums are recorded in other current assets as these contracts are included in, and recoverable through, the monthly purchased-gas cost mechanism. Gains and losses associated with the change in value and expiration of these option contracts are deferred as part of our unrecovered purchase-gas costs and are not material for the three- and six-month periods ended June 30, 2012 and 2011.

Fair Value Hedges - Our Energy Services segment uses basis swaps to hedge the fair value of location price differentials related to certain firm transportation commitments. Cost of sales and fuel in our Consolidated Statements of Income includes gains of $1.6 million and $1.1 million for the three and six months ended June 30, 2012, respectively, related to the change in fair value of derivatives designated as fair value hedges. Revenues include losses of $2.2 million and $0.3 million for the three and six months ended June 30, 2012, respectively, to recognize the change in fair value of the related hedged firm commitments. The ineffectiveness related to these hedges was not material for the three and six months ended June 30, 2012.

Cost of sales and fuel in our Consolidated Statements of Income includes gains of $4.2 million and $9.6 million for the three and six months ended June 30, 2011, respectively, related to the change in fair value of derivatives designated as fair value hedges. Revenues include losses of $4.4 million and $9.4 million for the three and six months ended June 30, 2011,

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respectively, to recognize the change in fair value of the related hedged firm commitments. The ineffectiveness related to these hedges was immaterial for the three and six months ended June 30, 2011.

Credit Risk - We monitor the creditworthiness of our counterparties and compliance with policies and limits established by our Risk Oversight and Strategy Committee. We maintain credit policies with regard to our counterparties that we believe minimize overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings, bond yields and credit default swap rates), collateral requirements under certain circumstances and the use of standardized master-netting agreements that allow us to net the positive and negative exposures associated with a single counterparty. We have counterparties whose credit is not rated, and for those customers we use internally developed credit ratings.

Some of our derivative instruments contain provisions that require us to maintain an investment-grade credit rating from S&P and/or Moody’s. If our credit ratings on senior unsecured long-term debt were to decline below investment grade, we would be in violation of these provisions, and the counterparties to the derivative instruments could request collateralization on derivative instruments in net liability positions. The aggregate fair value of all financial derivative instruments with contingent features related to credit risk that were in a net liability position as of June 30, 2012, was $3.1 million. If the contingent features underlying these agreements were triggered on June 30, 2012, we would have been required to post an additional $3.1 million of collateral to our counterparties.

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

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

	June 30, 2012
	Investment		Noninvestment		Not
	Grade		Grade		Rated		Total
Counterparty sector	(Thousands of dollars)
Gas and electric utilities	$	17,911	$	-	$	108	$	18,019
Oil and gas		7,932		-		465		8,397
Financial		72,674		-		2		72,676
Other		-		6		395		401
Total	$	98,517	$	6	$	970	$	99,493

E. CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

ONEOK 2011 Credit Agreement - The ONEOK 2011 Credit Agreement, which is scheduled to expire in April 2016, contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONEOK’s stand-alone debt-to-capital ratio of no more than 67.5 percent at the end of any calendar quarter, limitations on the ratio of indebtedness secured by liens and indebtedness of subsidiaries to consolidated net tangible assets, a requirement that ONEOK maintains the power to control the management and policies of ONEOK Partners, and a limit on new investments in master limited partnerships. The ONEOK 2011 Credit Agreement also contains customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in the nature of ONEOK’s businesses, transactions with affiliates, the use of proceeds and a covenant that limits ONEOK’s ability to restrict its subsidiaries’ ability to pay dividends. The debt covenant calculations in the ONEOK 2011 Credit Agreement exclude the debt of ONEOK Partners. Upon breach of certain covenants by ONEOK, amounts outstanding under the ONEOK 2011 Credit Agreement may become due and payable immediately. At June 30, 2012, ONEOK’s stand-alone debt-to-capital ratio, as defined by the ONEOK 2011 Credit Agreement, was 50.5 percent, and ONEOK was in compliance with all covenants under the ONEOK 2011 Credit Agreement.

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Under the terms of the ONEOK 2011 Credit Agreement, ONEOK may request an increase in the size of the facility to an aggregate of $1.7 billion from $1.2 billion by either commitments from new lenders or increased commitments from existing lenders. The ONEOK 2011 Credit Agreement is available to repay our commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowing capacity under the ONEOK 2011 Credit Agreement.

At June 30, 2012, ONEOK had $571.9 million of commercial paper outstanding, $1.7 million in letters of credit issued under the ONEOK 2011 Credit Agreement and approximately $22.8 million of cash and cash equivalents. ONEOK had approximately $626.4 million of credit available at June 30, 2012, under the ONEOK 2011 Credit Agreement.

ONEOK Partners 2011 Credit Agreement - The ONEOK Partners 2011 Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in the ONEOK Partners 2011 Credit Agreement, adjusted for all noncash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5.0 to 1. If ONEOK Partners consummates one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will increase to 5.5 to 1 for the quarter of the acquisition and the two following quarters. Upon breach of certain covenants by ONEOK Partners in the ONEOK Partners 2011 Credit Agreement, amounts outstanding under the ONEOK Partners 2011 Credit Agreement, if any, may become due and payable immediately. At June 30, 2012, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 2.3 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners 2011 Credit Agreement.

The ONEOK Partners 2011 Credit Agreement includes a $100-million sublimit for the issuance of standby letters of credit and also features an option to request an increase in the size of the facility to an aggregate of $1.7 billion from $1.2 billion by either commitments from new lenders or increased commitments from existing lenders. The ONEOK Partners 2011 Credit Agreement is available to repay ONEOK Partners’ commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowing capacity under the ONEOK Partners 2011 Credit Agreement. At June 30, 2012, ONEOK Partners had $24 million of commercial paper outstanding, no letters of credit issued and no borrowings under the ONEOK Partners 2011 Credit Agreement.

Effective August 1, 2012, ONEOK Partners extended the maturity date of its ONEOK Partners 2011 Credit Agreement from August 1, 2016, to August 1, 2017, pursuant to an extension agreement between ONEOK Partners and its lenders.

Neither ONEOK nor ONEOK Partners guarantees the debt or other similar commitments to unaffiliated parties, and ONEOK does not guarantee the debt or other similar commitments of ONEOK Partners.

F. LONG-TERM DEBT

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

The indenture governing ONEOK’s senior notes due 2022 includes an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2022 to declare those senior notes immediately due and payable in full.

ONEOK may redeem its senior notes due 2022 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting three months before the maturity date. Prior to this date, ONEOK may redeem the senior notes due 2022, in whole or in part, at any time for a redemption price equal to the principal amount plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. ONEOK’s senior notes due 2022 are senior unsecured obligations, ranking equally in right of payment with all of ONEOK’s existing and future unsecured senior indebtedness.

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

For the three-month periods ended June 30, 2012 and 2011, interest expense was net of capitalized interest of $9.7 million and $4.2 million, respectively. For the six-month periods ended June 30, 2012 and 2011, interest expense was net of capitalized interest of $18.7 million and $7.4 million, respectively.

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G. EQUITY

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

	Three Months Ended										Three Months Ended
	June 30, 2012										June 30, 2011
	ONEOK Shareholders' Equity			Noncontrolling Interests in Consolidated Subsidiaries			Total Equity				ONEOK Shareholders' Equity			Noncontrolling Interests in Consolidated Subsidiaries			Total Equity
	(Thousands of dollars)
Beginning balance	$	2,256,152		$	2,123,303			$	4,379,455		$	2,499,084		$	1,457,934			$	3,957,018
Net income		60,993			88,212				149,205			55,142			79,624				134,766
Other comprehensive income (loss)		(26,795	)		(14,276	)			(41,071	)		3,871			11,572				15,443
Repurchase of common stock		(150,000	)		-				(150,000	)		(300,057	)		-				(300,057	)
Common stock issued		3,991			-				3,991			14,754			-				14,754
Common stock dividends		(63,397	)		-				(63,397	)		(55,705	)		-				(55,705	)
Issuance of common units of ONEOK Partners		-			(55	)			(55	)		-			-				-
Distributions to noncontrolling interests		-			(80,736	)			(80,736	)		-			(68,515	)			(68,515	)
Other		8,596			-				8,596			-			-				-
Ending balance	$	2,089,540		$	2,116,448			$	4,205,988		$	2,217,089		$	1,480,615			$	3,697,704

	Six Months Ended										Six Months Ended
	June 30, 2012										June 30, 2011
	ONEOK Shareholders' Equity			Noncontrolling Interests in Consolidated Subsidiaries			Total Equity				ONEOK Shareholders' Equity			Noncontrolling Interests in Consolidated Subsidiaries			Total Equity
	(Thousands of dollars)
Beginning balance	$	2,238,573		$	1,561,159			$	3,799,732		$	2,448,623		$	1,472,218			$	3,920,841
Net income		183,858			198,809				382,667			185,272			148,840				334,112
Other comprehensive income (loss)		481			(712	)			(231	)		(22,464	)		(3,887	)			(26,351	)
Repurchase of common stock		(150,000	)		-				(150,000	)		(300,105	)		-				(300,105	)
Common stock issued		6,552			-				6,552			17,119			-				17,119
Common stock dividends		(126,772	)		-				(126,772	)		(111,356	)		-				(111,356	)
Issuance of common units of ONEOK Partners		(51,100	)		510,780				459,680			-			-				-
Distributions to noncontrolling interests		-			(153,588	)			(153,588	)		-			(136,556	)			(136,556	)
Other		(12,052	)		-				(12,052	)		-			-				-
Ending balance	$	2,089,540		$	2,116,448			$	4,205,988		$	2,217,089		$	1,480,615			$	3,697,704

Dividends - Dividends paid on our common stock to shareholders of record at the close of business on January 31, 2012, and April 30, 2012, each were $0.305 per share. A dividend of $0.33 per share was declared for shareholders of record on August 6, 2012, payable August 15, 2012.

Stock Repurchase Program - In June 2012, we entered into an accelerated share repurchase agreement (the ASR Agreement) with Goldman, Sachs & Co. (Goldman), pursuant to which we paid $150 million to Goldman and received from Goldman approximately 2.9 million shares of our common stock, representing approximately 80 percent of the estimated total number of shares to be repurchased. The ASR Agreement is scheduled to end in September 2012, although the termination date may be accelerated. We expect to receive the balance of the shares at the conclusion of the ASR Agreement. The specific number of shares that we ultimately will repurchase will be based on the volume-weighted-average price per share of our common stock during the repurchase period, subject to other adjustments pursuant to the terms and conditions of the ASR Agreement. At settlement, under certain circumstances, Goldman may be required to deliver additional shares of our common stock to us, or, under certain circumstances, we may be required to deliver shares of our common stock or we may elect to make a cash payment to Goldman. We accounted for the repurchase as two separate transactions: (i) as shares of common stock acquired in a treasury stock transaction recorded on the acquisition date; and (ii) as a forward contract indexed to ONEOK common stock that is classified as equity.

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The ASR Agreement is part of our three-year stock repurchase program that was authorized by our Board of Directors in October 2010 to buy up to $750 million of our common stock, subject to the limitation that purchases will not exceed $300 million in any one calendar year. Following this transaction and our repurchase of $300 million in 2011, an additional $300 million may yet be purchased pursuant to our three-year repurchase program, of which a maximum of $150 million of additional shares of our common stock may be purchased in 2012.

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

H. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

	Unrealized Gains (Losses) on Energy Marketing and Risk Management Assets/Liabilities		Unrealized Holding Gains (Losses) on Investment Securities		Pension and Postretirement Benefit Plan Obligations		Accumulated Other Comprehensive Income (Loss)
		(Thousands of dollars)
December 31, 2011	$	(55,367)	$	987	$	(151,741)	$	(206,121)
Other comprehensive income (loss) attributable to ONEOK		11,915		120		(11,554)		481
June 30, 2012	$	(43,452)	$	1,107	$	(163,295)	$	(205,640)

I. EARNINGS PER SHARE

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

	Three Months Ended June 30, 2012
	Income		Shares		Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK
available for common stock	$	60,726		207,292	$	0.29
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-		4,492
Income from continuing operations attributable to ONEOK
available for common stock and common stock equivalents	$	60,726		211,784	$	0.29

	Three Months Ended June 30, 2011
	Income		Shares		Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK
available for common stock	$	54,705		210,674	$	0.26
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-		5,386
Income from continuing operations attributable to ONEOK
available for common stock and common stock equivalents	$	54,705		216,060	$	0.25

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	Six Months Ended June 30, 2012
	Income		Shares		Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK
available for common stock	$	169,579		207,454	$	0.82
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-		4,364
Income from continuing operations attributable to ONEOK
available for common stock and common stock equivalents	$	169,579		211,818	$	0.80

	Six Months Ended June 30, 2011
	Income		Shares		Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK
available for common stock	$	183,774		212,358	$	0.87
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-		4,852
Income from continuing operations attributable to ONEOK
available for common stock and common stock equivalents	$	183,774		217,210	$	0.85

There were no option shares excluded from the calculation of diluted EPS for the three and six months ended June 30, 2012 and 2011.

J. EMPLOYEE BENEFIT PLANS

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

	Pension Benefits						Pension Benefits
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	5,325		$	5,003		$	10,650		$	10,006
Interest cost		14,809			14,689			29,618			29,378
Expected return on assets		(20,689	)		(18,875	)		(41,378	)		(37,750	)
Amortization of unrecognized prior service cost		242			255			484			509
Amortization of net loss		12,111			8,927			24,222			17,855
Net periodic benefit cost	$	11,798		$	9,999		$	23,596		$	19,998

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	Postretirement Benefits						Postretirement Benefits
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	1,240		$	1,257		$	2,477		$	2,515
Interest cost		3,473			3,958			6,946			7,916
Expected return on assets		(2,671	)		(2,568	)		(5,342	)		(5,136	)
Amortization of unrecognized net asset at adoption		718			797			1,436			1,594
Amortization of unrecognized prior service cost		(2,063	)		(501	)		(4,126	)		(1,002	)
Amortization of net loss		3,296			2,031			6,592			4,062
Net periodic benefit cost	$	3,993		$	4,974		$	7,983		$	9,949

K. UNCONSOLIDATED AFFILIATES

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
	(Thousands of dollars)
Northern Border Pipeline Company	$	16,077	$	16,395	$	36,308	$	37,247
Overland Pass Pipeline		5,979		5,360		11,296		9,736
Fort Union Gas Gathering		3,195		3,711		7,403		6,676
Bighorn Gas Gathering		796		1,845		1,961		3,338
Other		3,122		2,233		6,821		4,639
Equity earnings from investments	$	29,169	$	29,544	$	63,789	$	61,636

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
	(Thousands of dollars)
Income Statement
Operating revenues	$	119,286	$	121,002	$	247,210	$	244,303
Operating expenses	$	57,727	$	51,988	$	112,295	$	106,224
Net income	$	59,812	$	59,244	$	125,066	$	122,409

Distributions paid to ONEOK Partners	$	43,254	$	38,541	$	84,195	$	71,052

L. ONEOK PARTNERS

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

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

Ownership Interest in ONEOK Partners - Our ownership interest in ONEOK Partners is shown in the table below as of June 30, 2012:


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

Cash Distributions - We receive distributions from ONEOK Partners on our common and Class B units and our 2-percent general partner interest, which includes our incentive distribution rights. Under ONEOK Partners’ partnership agreement, as amended, distributions are made to the partners with respect to each calendar quarter in an amount equal to 100 percent of available cash as defined in ONEOK Partners’ partnership agreement, as amended. Available cash generally will be distributed 98 percent to limited partners and 2 percent to the general partner. The general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met during the quarter. Under the incentive distribution provisions, as set forth in ONEOK Partners’ partnership agreement, as amended, the general partner receives:

·	15 percent of amounts distributed in excess of $0.3025 per unit;

·	25 percent of amounts distributed in excess of $0.3575 per unit; and

·	50 percent of amounts distributed in excess of $0.4675 per unit.

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
	(Thousands, except per unit amounts)
Distribution per unit	$	0.635	$	0.575	$	1.245	$	1.145

General partner distributions	$	3,759	$	2,996	$	7,040	$	5,952
Incentive distributions		44,610		29,624		81,082		58,269
Distributions to general partner		48,369		32,620		88,122		64,221
Limited partner distributions to ONEOK		58,921		48,753		110,642		97,083
Limited partner distributions to noncontrolling interest		80,662		68,441		153,271		136,286
Total distributions paid	$	187,952	$	149,814	$	352,035	$	297,590

The following table shows ONEOK Partners’ distributions declared for the periods indicated and paid within 45 days of the end of the period:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
	(Thousands, except per unit amounts)
Distribution per unit	$	0.660	$	0.585	$	1.295	$	1.160

General partner distributions	$	3,979	$	3,078	$	7,738	$	6,074
Incentive distributions		49,886		31,580		94,496		61,204
Distributions to general partner		53,865		34,658		102,234		67,278
Limited partner distributions to ONEOK		61,240		49,601		120,161		98,354
Limited partner distributions to noncontrolling interest		83,838		69,631		164,500		138,072
Total distributions declared	$	198,943	$	153,890	$	386,895	$	303,704

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

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

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

We provide a variety of services to our affiliates, including cash management and financial services, legal and administrative services by our employees and management, insurance and office space leased in our headquarters building and other field locations. Where costs are incurred specifically on behalf of an affiliate, the costs are billed directly to the affiliate by us. In other situations, the costs may be allocated to the affiliates through a variety of methods, depending upon the nature of the expenses and the activities of the affiliates. For example, a service that applies equally to all employees is allocated based upon the number of employees in each affiliate. However, an expense benefiting the consolidated company but having no direct basis for allocation is allocated by the modified Distrigas method, a method using a combination of ratios that include gross plant and investment, operating income and payroll expense. It is not practicable to determine what these general overhead costs would be on a stand-alone basis.

The following table shows ONEOK Partners’ transactions with us for the periods indicated:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
	(Thousands of dollars)
Revenues	$	81,050	$	98,699	$	156,755	$	195,492

Expenses
Cost of sales and fuel	$	5,769	$	12,440	$	15,044	$	23,171
Administrative and general expenses		62,636		57,214		118,997		113,509
Total expenses	$	68,405	$	69,654	$	134,041	$	136,680

M. COMMITMENTS AND CONTINGENCIES

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

We own or retain legal responsibility for the environmental conditions at 12 former manufactured natural gas sites in Kansas. These sites contain potentially harmful materials that are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE presently governs all work at these sites. The terms of the consent agreement allow us to investigate these sites and set remediation activities based upon the results of the investigations and

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risk analysis. Remediation typically involves the management of contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater.

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

Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been material in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during the three and six months ended June 30, 2012 or 2011.

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

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

In July 2011, the EPA issued a proposed rule that would change the air emission New Source Performance Standards, also known as NSPS, and Maximum Achievable Control Technology requirements applicable to the oil and gas industry, including natural gas production, processing, transmission and underground storage. In April 2012, the EPA released the final rule, which includes new NSPS and air toxic standards for a variety of sources within natural gas processing plants, oil and natural gas production facilities and natural gas transmission stations. The rule also regulates emissions from the hydraulic fracturing of wells for the first time. The EPA’s final rule reflects significant changes from the proposal issued in 2011 and allows for more manageable compliance options. The NSPS final rule will become effective after it is published in the Federal Register. It will require expenditures for updated emissions controls, monitoring and record keeping requirements at affected facilities. We do not expect these expenditures to have a material impact on our results of operations, financial position or cash flows.

Pipeline Safety - We are subject to Pipeline and Hazardous Materials Safety Administration regulations, including integrity- management regulations. The Pipeline Safety Improvement Act of 2002 requires pipeline companies operating high-pressure pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. In January 2012, The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law. The new law increased the maximum penalties for violating federal pipeline safety regulations and directs the DOT and Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us. These issues include but are not limited to:

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

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

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

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

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

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the earlier of the effective date of the final rule defining the referenced terms or December 31, 2012. The CFTC issued the definitional rules in late May and early July 2012 that will become effective 60 days after publication in the Federal Register. We are reviewing the rules to ascertain how we may be affected by them. Based on our assessment of the regulations issued to date and those proposed, we expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest-rate risks; however, the capital requirements and costs of hedging may increase as a result of the legislation. We also may incur additional costs associated with our compliance with the new regulations and anticipated additional record keeping, reporting and disclosure obligations; however, we do not believe the costs will be material. These requirements could affect adversely market liquidity and pricing of derivative contracts making it more difficult to execute our risk-management strategies in the future. Also, the anticipated increased costs of compliance by dealers and counterparties likely will be passed on to customers, which could decrease the benefits of hedging to us and could reduce our profitability and liquidity.

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

N. SEGMENTS

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

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

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

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

Other and Eliminations 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.

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

Customers - For the three and six months ended June 30, 2012, and the six months ended June 30, 2011, we had no single external customer from which we received 10 percent or more of our consolidated gross revenues. For the three months ended June 30, 2011, our ONEOK Partners segment had one single customer from which it received 10 percent of our consolidated gross 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 June 30, 2012	ONEOK Partners (a)		Natural Gas Distribution		Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	2,043,756	$	221,181	$	263,897		$	426		$	2,529,260
Intersegment revenues		81,050		2		5,028			(86,080	)		-
Total revenues	$	2,124,806	$	221,183	$	268,925		$	(85,654	)	$	2,529,260

Net margin	$	401,462	$	157,488	$	(10,412	)	$	424			548,962
Operating costs		123,364		103,774		4,626			(501	)		231,263
Depreciation and amortization		51,014		31,999		77			1,496			84,586
Gain on sale of assets		966		-		-			-			966
Operating income	$	228,050	$	21,715	$	(15,115	)	$	(571	)	$	234,079

Equity earnings from investments	$	29,169	$	-	$	-		$	-		$	29,169
Capital expenditures	$	355,443	$	72,917	$	-		$	3,900		$	432,260
(a) - Our ONEOK Partners segment has regulated and nonregulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $160.2 million, net margin of $100.6 million and operating income of $54.1 million.

Three Months Ended June 30, 2011	ONEOK Partners (a)			Natural Gas Distribution		Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	2,685,520		$	253,917	$	504,756		$	605		$	3,444,798
Intersegment revenues		98,699			3,065		111,273			(213,037	)		-
Total revenues	$	2,784,219		$	256,982	$	616,029		$	(212,432	)	$	3,444,798

Net margin	$	359,540		$	159,141	$	(433	)	$	585		$	518,833
Operating costs		113,581			104,516		5,298			214			223,609
Depreciation and amortization		43,714			34,436		111			532			78,793
Loss on sale of assets		(212	)		-		-			-			(212	)
Operating income	$	202,033		$	20,189	$	(5,842	)	$	(161	)	$	216,219

Equity earnings from investments	$	29,544		$	-	$	-		$	-		$	29,544
Capital expenditures	$	265,333		$	61,899	$	3		$	1,858		$	329,093
(a) - Our ONEOK Partners segment has regulated and nonregulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $153.0 million, net margin of $113.2 million and operating income of $53.5 million.

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Six Months Ended June 30, 2012	ONEOK Partners (a)		Natural Gas Distribution		Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	4,562,139	$	738,104	$	642,595		$	1,022		$	5,943,860
Intersegment revenues		156,755		843		87,138			(244,736	)		-
Total revenues	$	4,718,894	$	738,947	$	729,733		$	(243,714	)	$	5,943,860

Net margin	$	822,552	$	394,836	$	(25,858	)	$	1,019		$	1,192,549
Operating costs		239,234		208,760		9,465			(2,138	)		455,321
Depreciation and amortization		100,270		65,519		206			2,000			167,995
Goodwill impairment		-		-		10,255			-			10,255
Gain on sale of assets		1,023		-		-			-			1,023
Operating income	$	484,071	$	120,557	$	(45,784	)	$	1,157		$	560,001

Equity earnings from investments	$	63,789	$	-	$	-		$	-		$	63,789
Investments in unconsolidated affiliates	$	1,210,268	$	-	$	-		$	-		$	1,210,268
Total assets	$	9,376,537	$	3,153,679	$	549,623		$	737,352		$	13,817,191
Noncontrolling interests in consolidated subsidiaries	$	5,028	$	-	$	-		$	2,111,420		$	2,116,448
Capital expenditures	$	636,236	$	131,365	$	-		$	13,096		$	780,697
(a) - Our ONEOK Partners segment has regulated and nonregulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $331.4 million, net margin of $223.5 million and operating income of $118.7 million.

Six Months Ended June 30, 2011	ONEOK Partners (a)			Natural Gas Distribution		Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	5,088,337		$	933,324	$	1,182,556	$	1,181		$	7,205,398
Intersegment revenues		195,492			7,840		325,212		(528,544	)		-
Total revenues	$	5,283,829		$	941,164	$	1,507,768	$	(527,363	)	$	7,205,398

Net margin	$	689,094		$	402,875	$	55,516	$	1,225		$	1,148,710
Operating costs		222,324			209,213		13,302		451			445,290
Depreciation and amortization		86,444			70,383		259		1,064			158,150
Loss on sale of assets		(722	)		-		-		-			(722	)
Operating income	$	379,604		$	123,279	$	41,955	$	(290	)	$	544,548

Equity earnings from investments	$	61,636		$	-	$	-	$	-		$	61,636
Investments in unconsolidated affiliates	$	1,177,219		$	-	$	-	$	-		$	1,177,219
Total assets	$	8,642,136		$	3,134,134	$	559,976	$	700,087		$	13,036,333
Noncontrolling interests in consolidated subsidiaries	$	5,185		$	-	$	-	$	1,475,430		$	1,480,615
Capital expenditures	$	410,159		$	109,049	$	3	$	4,561		$	523,772
(a) - Our ONEOK Partners segment has regulated and nonregulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $308.5 million, net margin of $229.1 million and operating income of $113.1 million.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and the Notes to Consolidated Financial Statements in this Quarterly Report, as well as our Annual Report. Due to the seasonal nature of our business, the results of operations for the three and six months ended June 30, 2012, are not necessarily indicative of the results that may be expected for a 12-month period.

RECENT DEVELOPMENTS

Growth Projects - Oil and gas producers continue to drill aggressively in crude oil and NGL-rich areas, and related development activities continue to progress in many regions where ONEOK Partners has operations. ONEOK Partners expects continued development of the oil and natural gas reserves in the Bakken Shale and Three Forks formations in the Williston Basin and in the Cana-Woodford Shale, Woodford Shale, Granite Wash and Mississippian Lime areas in the Mid-Continent region. In response to this increased production of crude oil, natural gas and NGLs, and higher demand for NGL products from the petrochemical industry, ONEOK Partners is investing approximately $5.7 billion to $6.6 billion in new capital projects, which includes additional projects announced in July 2012, to meet the needs of oil and natural gas producers and processors in the Bakken Shale, the Cana-Woodford Shale, Woodford Shale, and the Granite Wash and Mississippian Lime areas. In addition, ONEOK Partners is investing in NGL infrastructure projects in the Rocky Mountain, Mid-Continent and Gulf Coast regions. These assets will enhance ONEOK Partners’ ability to distribute NGL products to meet the increasing petrochemical industry and NGL export demand. The execution of these capital investments aligns with ONEOK Partners’ focus to grow fee-based earnings. Acreage dedications and supply commitments from producers and natural gas processors in regions associated with ONEOK Partners’ growth projects will provide incremental and long-term fee-based earnings and cash flows.

In July 2012, ONEOK Partners announced plans to invest an additional $980.0 million to $1.1 billion through 2014 to:

·	Build a new 100 MMcf/d natural gas processing facility, the Garden Creek II plant, in eastern McKenzie County, North Dakota, in the Williston Basin, and related infrastructure;

·	Increase capacity on the Bakken NGL Pipeline to 135 MBbl/d from 60 MBbl/d;

·	Build a new 75 MBbl/d natural gas liquids fractionator, MB-3, at Mont Belvieu, Texas, and related infrastructure; and

·	Build a new 40 MBbl/d Ethane/Propane splitter at Mont Belvieu, Texas.

See discussion of these projects and other ONEOK Partners’ growth projects in the “Financial Results and Operating Information” section for our ONEOK Partners segment.

Dividends/Distributions - We declared a quarterly dividend of $0.33 per share ($1.32 per share on an annualized basis) in July 2012. A cash distribution from ONEOK Partners of $0.66 per unit ($2.64 per unit on an annualized basis) was declared in July 2012 for the second quarter of 2012, an increase of 2.5 cents from the previous quarter. The quarterly dividend and distribution payments will be made August 15, 2012, to shareholders and unitholders of record at the close of business on August 6, 2012.

Retail Marketing Sale - On February 1, 2012, we sold ONEOK Energy Marketing Company, our retail natural gas marketing business, to Constellation Energy Group, Inc. for $22.5 million plus working capital. We received net proceeds of approximately $32.9 million and recognized an after-tax gain on the sale of approximately $13.5 million. The proceeds from the sale were used to reduce short-term borrowings. The financial information of ONEOK Energy Marketing Company is reflected as discontinued operations in this Quarterly Report. All prior periods presented have been recast to reflect the discontinued operations.

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FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

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

	Three Months Ended						Six Months Ended						Three Months					Six Months
	June 30,						June 30,						2012 vs. 2011					2012 vs. 2011
Financial Results	2012			2011			2012			2011			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Revenues	$	2,529.3		$	3,444.8		$	5,943.9		$	7,205.4		$	(915.5	)	(27	%)	$	(1,261.5	)	(18	%)
Cost of sales and fuel		1,980.3			2,926.0			4,751.4			6,056.7			(945.7	)	(32	%)		(1,305.3	)	(22	%)
Net margin		549.0			518.8			1,192.5			1,148.7			30.2		6	%		43.8		4	%
Operating costs		231.3			223.6			455.3			445.3			7.7		3	%		10.0		2	%
Depreciation and amortization		84.6			78.8			168.0			158.2			5.8		7	%		9.8		6	%
Goodwill impairment		-			-			10.3			-			-			-		10.3		100	%
Gain (loss) on sale of assets		1.0			(0.2	)		1.1			(0.7	)		1.2			*		1.8			*
Operating income	$	234.1		$	216.2		$	560.0		$	544.5		$	17.9		8	%	$	15.5		3	%

Interest expense	$	(71.5	)	$	(75.5	)	$	(147.4	)	$	(154.8	)	$	(4.0	)	(5	%)	$	(7.4	)	(5	%)
Net income	$	149.2		$	134.8		$	382.7		$	334.1		$	14.4		11	%	$	48.6		15	%
Net income attributable to noncontrolling interests	$	88.2		$	79.6		$	198.8		$	148.8		$	8.6		11	%	$	50.0		34	%
Net income attributable to ONEOK	$	61.0		$	55.1		$	183.9		$	185.3		$	5.9		11	%	$	(1.4	)	(1	%)
Capital expenditures	$	432.3		$	329.1		$	780.7		$	523.8		$	103.2		31	%	$	256.9		49	%
* Percentage change is greater than 100 percent.

Revenues decreased for the three and six months ended June 30, 2012, compared with the same periods last year, due to lower natural gas and NGL product prices, offset partially by higher NGL sales volumes from ONEOK Partners’ completed capital projects and more favorable NGL price differentials. The increase in natural gas supply resulting from the development of resource areas in North America has caused lower natural gas prices and narrower natural gas location and seasonal price differentials in the markets it serves. NGL prices also have decreased in 2012 due primarily to increased NGL supply from the development of NGL-rich resource areas and lower NGL demand during the second quarter of 2012 because of scheduled maintenance at Gulf Coast petrochemical plants, as well as lower crude oil prices.

Operating income for the three-month period reflects higher results from our ONEOK Partners and Natural Gas Distribution segments, offset by lower results from our Energy Services segment. The six-month period reflects higher results from our ONEOK Partners segment, offset by significantly lower results from our Energy Services segment and slightly lower results from our Natural Gas Distribution segment.

For the three and six month periods, our ONEOK Partners segment’s operating income increased due primarily to higher natural gas and NGL sales volumes from its completed capital projects, including the startup of the new Garden Creek natural gas processing plant in the Williston Basin in December 2011 and more favorable NGL price differentials, offset partially by lower natural gas and NGL product prices in its natural gas gathering and processing business.

For the three-month period, our Natural Gas Distribution segment’s operating income increased 6 percent, compared with the same period last year, due primarily to new rates and surcharge recoveries in Texas and Kansas. Our Natural Gas Distribution segment’s operating income decreased 2 percent for the six months ended June 30, 2012, compared with the same period last year, due primarily to higher depreciation expense from new capital investments, which include its investment in automated meter reading, and reduced transportation margins due to warmer weather, offset partially by new rates and surcharge recoveries in Texas and Kansas.

Our Energy Services segment’s operating income decreased for the three months ended June 30, 2012, compared with the same periods last year, due primarily to lower transportation and premium services margins. During the six-month period, the continued decline in natural gas prices resulted in a required $29.9 million reclassification of deferred losses from accumulated other comprehensive income into earnings on certain financial contracts, a $10.3 million goodwill impairment charge, lower realized seasonal storage price differentials, lower transportation margins and decreases due to unrealized fair value changes on nonqualifying economic hedges in our Energy Services segment.

Interest expense decreased for the three and six months ended June 30, 2012, compared with the same periods last year, primarily as a result of interest capitalized associated with ONEOK Partners’ growth projects, offset partially by interest costs from ONEOK’s $700 million debt issuance in January 2012.

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Net income attributable to noncontrolling interests for the three and six months ended June 30, 2012 and 2011, reflects primarily the portion of ONEOK Partners that we do not own and the increase reflects higher earnings in our ONEOK Partners segment during 2012.

Capital expenditures increased for the three and six months ended June 30, 2012, compared with the same periods last year, due primarily to the growth projects in ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses.

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

ONEOK Partners

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

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

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

Natural gas gathering and processing business - ONEOK Partners’ natural gas gathering and processing business provides nondiscretionary services to producers that include gathering and processing of natural gas produced from crude oil and natural gas wells. ONEOK Partners gathers and processes natural gas in the Mid-Continent region, which includes the NGL-rich Cana-Woodford Shale and Granite Wash formations; the Mississippian Lime formation of Oklahoma and Kansas; and the Hugoton and Central Kansas Uplift Basins of Kansas. It also gathers and/or processes natural gas in two producing basins in the Rocky Mountain region: the Williston Basin, which spans portions of Montana and North Dakota and includes the oil-producing, NGL-rich Bakken Shale and Three Forks formations; and the Powder River Basin of Wyoming. In the Powder River Basin, the natural gas that ONEOK Partners gathers is coal-bed methane, or dry, natural gas that does not require processing or NGL extraction in order to be marketable; dry natural gas is gathered, compressed and delivered into a downstream pipeline or marketed for a fee.

Natural gas pipelines business - ONEOK Partners’ natural gas pipeline business owns and operates regulated natural gas transmission pipelines, natural gas storage facilities and natural gas gathering systems for unprocessed natural gas. ONEOK Partners also provides interstate natural gas transportation and storage services in accordance with Section 311(a) of the Natural Gas Policy Act.

ONEOK Partners’ FERC-regulated interstate assets transport natural gas through pipelines that access supply from Canada and from the Mid-Continent, Rocky Mountain and Gulf Coast regions. ONEOK Partners’ intrastate natural gas pipeline assets are located in Oklahoma, Texas and Kansas, and have access to major natural gas producing areas in those states. ONEOK Partners owns underground natural gas storage facilities in Oklahoma, Kansas and Texas.

Natural gas liquids business - ONEOK Partners’ natural gas liquids business gathers, treats, fractionates, stores and transports NGLs and distributes and stores NGL products. ONEOK Partners’ natural gas liquids gathering pipelines deliver unfractionated NGLs gathered from natural gas processing plants located in Oklahoma, Kansas, Texas and the Rocky Mountain region to fractionators it owns in Oklahoma, Kansas and Texas, as well as to third-party fractionators and pipelines. The NGLs are then separated through the fractionation process into the individual NGL products that realize the greater economic value of the NGL components. The individual NGL products are then stored or distributed to petrochemical manufacturers, heating-fuel users, refineries and propane distributors through ONEOK Partners’ FERC-regulated distribution pipelines that move NGL products from Oklahoma and Kansas to the Mid-Continent and Gulf Coast NGL market centers, as well as the Midwest markets near Chicago, Illinois.

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Growth Projects - Bakken Crude Express Pipeline - In April 2012, ONEOK Partners announced plans to invest $1.5 billion to $1.8 billion to build a 1,300-mile crude-oil pipeline, the Bakken Crude Express Pipeline, with the capacity to transport 200 MBbl/d. The Bakken Crude Express Pipeline will transport light-sweet crude oil primarily from the Bakken Shale and Three Forks formations in the Williston Basin in North Dakota to the Cushing, Oklahoma, market hub.

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

Depending upon supply commitments received prior to construction, the capacity of this pipeline can be increased. More than 80 percent of the proposed pipeline route is expected to parallel ONEOK Partners’ existing and planned natural gas liquids pipelines. Supply commitments for the proposed pipeline are in various stages of negotiation with many of the same producers and natural gas processors that ONEOK Partners serves currently. Following receipt of all necessary permits and compliance with customary regulatory requirements, construction is expected to begin in late 2013 or early 2014 and be completed by early 2015.

Natural gas gathering and processing projects - ONEOK Partners’ natural gas gathering and processing business is investing approximately $1.8 billion to $1.9 billion in growth projects in the Williston Basin and Cana-Woodford Shale areas that will enable ONEOK Partners to meet the rapidly growing needs of crude oil and natural gas producers in those areas.

Williston Basin Processing Plants and related projects - In July 2012, ONEOK Partners announced plans to invest approximately $310 to $345 million to construct the 100 MMcf/d Garden Creek II natural gas processing plant and related infrastructure. The Garden Creek II plant is expected to be in service during the third quarter of 2014. Combined, ONEOK Partners’ projects in this basin include four 100 MMcf/d natural gas processing facilities: the Garden Creek and Garden Creek II plants located in eastern McKenzie County, North Dakota, and the Stateline I and II plants located in western Williams County, North Dakota. ONEOK Partners has acreage dedications of more than 2.7 million acres supporting these plants. In addition, ONEOK Partners is expanding and upgrading its existing natural gas gathering and compression infrastructure and also adding new well connections associated with these plants. The Garden Creek plant was placed in service in December 2011 and cost approximately $360 million, excluding AFUDC. Together, the Stateline I and II plants and related infrastructure projects are expected to cost approximately $560 million to $660 million, excluding AFUDC. The 100 MMcf/d Stateline I natural gas processing facility is expected to be in service during the third quarter of 2012, and the 100 MMcf/d Stateline II natural gas processing facility is expected to be in service during the first half of 2013.

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

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

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

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

Natural gas liquids projects - The growth strategy in ONEOK Partners’ natural gas liquids business is focused around the oil and NGL-rich natural gas drilling activity in shale and other resource areas from the Rocky Mountain region through the Mid-Continent region into Texas. Increasing crude oil, natural gas and NGL production resulting from this activity and higher petrochemical industry demand for NGL products have required ONEOK Partners to make additional capital investments in its infrastructure to bring these commodities from supply basins to market. Expansion of the petrochemical industry in the United States is expected to increase ethane demand significantly over the next five years, and international demand for propane is expected to impact the NGL market in the future. ONEOK Partners’ natural gas liquids business is investing approximately $2.4 billion to $2.9 billion in NGL-related projects through 2014. These investments will accommodate the transportation and fractionation of growing NGL supplies from the shale and other resource areas across ONEOK Partners’ asset base and alleviate infrastructure constraints between the Mid-Continent and Texas Gulf Coast regions to meet the increasing petrochemical industry and NGL export demand in the Gulf Coast. Over time, these growing fee-based NGL volumes will fill a portion of the capacity used to capture the NGL price differentials between the two market centers. In addition, we believe the NGL price differentials between the Mid-Continent and Gulf Coast market centers will narrow over the long term as new fractionators and pipelines, including ONEOK Partners’ growth projects discussed below, begin to alleviate constraints affecting NGL prices and location price differentials between the two market centers.

Sterling III Pipeline - ONEOK Partners plans to build a 570-plus-mile natural gas liquids pipeline, the Sterling III Pipeline, which will have the flexibility to transport either unfractionated NGLs or NGL products from the Mid-Continent to the Texas Gulf Coast. The Sterling III Pipeline will traverse the NGL-rich Woodford Shale that is currently under development, as well as provide transportation capacity for the growing NGL production from the Cana-Woodford Shale and Granite Wash areas, where the pipeline can gather unfractionated NGLs from the new natural gas processing plants that are being built as a result of increased drilling activity in these areas. The Sterling III Pipeline will have an initial capacity to transport up to 193 MBbl/d of production from ONEOK Partners’ natural gas liquids infrastructure at Medford, Oklahoma, to its storage and fractionation facilities in Mont Belvieu, Texas. ONEOK Partners has multi-year supply commitments from producers and natural gas processors for approximately 75 percent of the pipeline’s capacity. Additional pump stations could expand the capacity of the pipeline to 250 MBbl/d. Following the receipt of all necessary permits and the acquisition of rights-of-way, construction is scheduled to begin in 2013, with an expected completion late in the same year.

The investment also includes reconfiguring its existing Sterling I and II pipelines, which currently distribute NGL products between the Mid-Continent and Gulf Coast NGL market centers, to transport either unfractionated NGLs or NGL products.

The project costs for the new pipeline and reconfiguring projects are estimated to be $610 million to $810 million, excluding AFUDC.

MB-2 Fractionator - ONEOK Partners is constructing a 75-MBbl/d fractionator, MB-2, near its storage facility in Mont Belvieu, Texas. The Texas Commission on Environmental Quality (TCEQ) approved the permit application to build this fractionator. Construction began in June 2011 and is expected to be completed in the third quarter of 2013. The cost of the new fractionator is estimated to be $300 million to $390 million, excluding AFUDC. ONEOK Partners has multi-year supply commitments from producers and natural gas processors for all of the fractionator’s capacity.

MB-3 Fractionator - In July 2012, ONEOK Partners announced plans to construct a new 75 MBbl/d fractionator, MB-3, near its storage facility in Mont Belvieu, Texas. In addition, ONEOK Partners plans to expand and upgrade its existing natural gas liquids gathering and pipeline infrastructure, including new connections to natural gas processing facilities and increasing the capacity of the Arbuckle and Sterling II NGL pipelines. The MB-3 fractionator and related infrastructure are expected to cost approximately $525 million to $575 million, excluding AFUDC. The MB-3 fractionator is expected to be completed in the fourth quarter of 2014. Supply commitments from third-party natural gas processors are in various stages of negotiation.

Ethane/Propane Splitter - In July 2012, ONEOK Partners announced plans to construct a new 40 MBbl/d ethane/propane splitter at its Mont Belvieu storage facility to split ethane/propane mix into purity ethane in order to meet the growing needs of petrochemical-industry customers. The facility will be capable of producing 32 MBbl/d of purity ethane and 8 MBbl/d of propane and is expected to be in service during the second quarter of 2014. The ethane/propane splitter is expected to cost approximately $45 million, excluding AFUDC.

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Bakken NGL Pipeline and related projects - ONEOK Partners is building a 525- to 615-mile natural gas liquids pipeline, the Bakken NGL Pipeline, to transport unfractionated NGLs from the Williston Basin to the Overland Pass Pipeline. In July 2012, ONEOK Partners announced plans to invest an additional $100 million to install additional pump stations on the Bakken NGL Pipeline to increase its capacity to 135 MBbl/d from an initial capacity of 60 MBbl/d. The unfractionated NGLs will then be delivered to ONEOK Partners’ existing natural gas liquids fractionation and distribution infrastructure in the Mid-Continent. Project costs for the new pipeline, including the expansion, are estimated to be $550 million to $650 million, excluding AFUDC. NGL supply commitments for the Bakken NGL Pipeline will be anchored by NGL production from ONEOK Partners’ natural gas processing plants and third-party natural gas processors in the Williston Basin. The 12-inch diameter pipeline is expected to be in service during the first half of 2013, and the expansion is expected to be completed in the third quarter of 2014.

The unfractionated NGLs from the Bakken NGL Pipeline and other supply sources under development in the Rocky Mountain region will require installing additional pump stations and expanding existing pump stations on the Overland Pass Pipeline in which ONEOK Partners owns a 50-percent equity interest. These additions and expansions will increase the capacity of Overland Pass Pipeline to 255 MBbl/d. ONEOK Partners’ share of the costs for this project is estimated to be $35 million to $40 million, excluding AFUDC.

Bushton Fractionator expansion - To accommodate the additional volumes from the Bakken NGL Pipeline, ONEOK Partners is investing $110 million to $140 million, excluding AFUDC, to expand and upgrade its existing fractionation capacity at Bushton, Kansas, increasing its capacity to 210 MBbl/d from 150 MBbl/d. This project is expected to be in service during the fourth quarter of 2012.

Cana-Woodford Shale and Granite Wash projects - ONEOK Partners has constructed approximately 230 miles of natural gas liquids pipelines that have expanded its existing Mid-Continent natural gas liquids gathering system in the Cana-Woodford Shale and Granite Wash areas. These pipelines have expanded ONEOK Partners’ capacity to transport unfractionated NGLs from these Mid-Continent supply areas to fractionation facilities in Oklahoma and Texas and distribute NGL products to the Mid-Continent, Gulf Coast and upper Midwest market centers. The pipelines are connected to three new third-party natural gas processing facilities and to three existing third-party natural gas processing facilities that have been expanded. Additionally, ONEOK Partners has installed additional pump stations on the Arbuckle Pipeline to increase its capacity to 240 MBbl/d. These projects are expected to add, through multi-year supply contracts, approximately 75 to 80 MBbl/d of unfractionated NGLs, to ONEOK Partners’ existing natural gas liquids gathering systems. These projects were placed in service in April 2012 and cost approximately $220 million, excluding AFUDC.

Sterling I Pipeline expansion - In 2011, ONEOK Partners installed seven additional pump stations at a cost of approximately $30 million, excluding AFUDC, along its existing Sterling I natural gas liquids distribution pipeline, increasing its capacity by 15 MBbl/d, which is supplied by ONEOK Partners’ Mid-Continent natural gas liquids infrastructure. The Sterling I Pipeline transports NGL products from ONEOK Partners’ fractionator in Medford, Oklahoma, to the Mont Belvieu, Texas, market center.

For a discussion of ONEOK Partners’ capital expenditure financing, see “Capital Expenditures” in “Liquidity and Capital Resources” on page 55.

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

	Three Months Ended					Six Months Ended					Three Months					Six Months
	June 30,					June 30,					2012 vs. 2011					2012 vs. 2011
Financial Results	2012		2011			2012		2011			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Revenues	$	2,124.8	$	2,784.2		$	4,718.9	$	5,283.8		$	(659.4	)	(24	%)	$	(564.9	)	(11	%)
Cost of sales and fuel		1,723.3		2,424.7			3,896.3		4,594.7			(701.4	)	(29	%)		(698.4	)	(15	%)
Net margin		401.5		359.5			822.6		689.1			42.0		12	%		133.5		19	%
Operating costs		123.4		113.6			239.2		222.3			9.8		9	%		16.9		8	%
Depreciation and amortization		51.0		43.7			100.3		86.4			7.3		17	%		13.9		16	%
Gain (loss) on sale of assets		1.0		(0.2	)		1.0		(0.8	)		1.2			*		1.8			*
Operating income	$	228.1	$	202.0		$	484.1	$	379.6		$	26.1		13	%	$	104.5		28	%

Capital expenditures	$	355.4	$	265.3		$	636.2	$	410.2		$	90.1		34	%	$	226.0		55	%
* Percentage change is greater than 100 percent.

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The differential between the composite price of NGL products and the price of natural gas, particularly the differential between the price of ethane and the price of natural gas, may influence the volume of NGLs recovered from natural gas processing plants. When economic conditions warrant, natural gas processors may elect not to recover the ethane component of the natural gas stream, also known as ethane rejection, and instead leave the ethane component in the higher value residue natural gas stream sold at the tailgate of natural gas processing plants. Low commodity prices have resulted in periods of ethane rejection in the Mid-Continent region during 2012. Ethane rejection did not have a material impact on our results for the three months ended June 30, 2012.

Net margin increased for the three months ended June 30, 2012, compared with the same period last year, due primarily to the following:

an increase of $25.7 million due primarily to volume growth in the Williston Basin from the new Garden Creek natural gas processing plant and increased drilling activity resulting in higher natural gas volumes gathered, compressed, processed, transported and sold, and higher fees, offset partially by lower natural gas volumes gathered as a result of continued production decline rates and reduced drilling activity in the Powder River Basin in ONEOK Partners’ natural gas gathering and processing business;

an increase of $18.0 million related to higher NGL volumes gathered in the Mid-Continent and Rocky Mountain regions, and Texas, higher NGL volumes fractionated in the Mid-Continent region and contract renegotiations for higher fees associated with ONEOK Partners’ NGL exchange services activities, offset partially by lower volumes fractionated in Texas due to scheduled maintenance in May 2012 at its Mont Belvieu fractionation facility in its natural gas liquids business;

an increase of $10.9 million in optimization and marketing margins, which resulted from a $24.8 million increase from more favorable NGL price differentials and additional transportation capacity available for optimization activities from ONEOK Partners’ completed expansions of the Arbuckle and Sterling I pipelines that enabled the increased transportation of NGLs between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers. This increase was offset partially by a $13.8 million decrease due primarily to lower NGL product sales and higher NGL inventory held as a result of the scheduled maintenance of its Mont Belvieu fractionation facility. ONEOK Partners expects to fractionate the NGL inventory and realize margins resulting from the physical-forward sale of this inventory by the end of 2012;

·	an increase of $6.0 million due to higher storage margins as a result of contract renegotiations at higher fees in ONEOK Partners’ natural gas liquids business; and

·	an increase of $1.6 million related to higher isomerization margins resulting from wider price differentials between normal butane and iso-butane, offset partially by lower isomerization volumes in ONEOK Partners’ natural gas liquids business; offset partially by

·	a decrease of $10.1 million due to lower natural gas and NGL product prices, particularly ethane and propane, offset partially by higher condensate prices in ONEOK Partners’ natural gas gathering and processing business;

·	a decrease of $8.6 million due primarily to higher compression costs and third-party transportation and processing costs associated with our volume growth primarily in the Williston Basin in ONEOK Partners’ natural gas gathering and processing business; and

·	a decrease of $2.2 million due to the impact of operational measurement losses in ONEOK Partners’ natural gas liquids business.

Net margin increased for the six months ended June 30, 2012, compared with the same period last year, due primarily to the following:

an increase of $71.2 million in optimization and marketing margins, which resulted from a $84.8 million increase from optimization margins in ONEOK Partners’ natural gas liquids business due primarily to favorable NGL price differentials and additional fractionation and transportation capacity available for optimization activities made available by ONEOK Partners’ 60 MBbl/d fractionation-services agreement with Targa Resources Partners that began in the second quarter 2011 and completed expansions of the Arbuckle and Sterling I pipelines that enabled the increased transportation of NGLs between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers. This increase was offset partially by a decrease of $13.8 million due primarily to lower NGL product sales and higher NGL inventory held as a result of the scheduled maintenance of its Mont Belvieu fractionation facility. ONEOK Partners expects to fractionate the NGL inventory and realize margins resulting from the physical-forward sale of this inventory by the end of 2012;

an increase of $52.9 million due primarily to volume growth in the Williston Basin from our new Garden Creek natural gas processing plant and increased drilling activity resulting in higher natural gas volumes gathered, compressed, processed, transported and sold, and higher fees, offset partially by lower natural gas volumes gathered

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as a result of continued production declines and reduced drilling activity by producers in the Powder River Basin in ONEOK Partners’ natural gas gathering and processing business;

an increase of $35.8 million from higher NGL volumes gathered and fractionated in Texas and the Mid-Continent and Rocky Mountain regions, and contract renegotiations for higher fees associated with ONEOK Partners’ NGL exchange services activities, offset partially by higher costs associated with NGL volumes fractionated by third parties in its natural gas liquids business;

·	an increase of $8.7 million due to higher storage margins as a result of contract renegotiations at higher fees in ONEOK Partners’ natural gas liquids business; and

·	an increase of $4.2 million due to the impact of operational measurement gains of approximately $1.1 million in the first six months of 2012, compared with a loss of approximately $5.3 million in the same period last year, in ONEOK Partners’ natural gas liquids business; offset partially by

·	a decrease of $15.3 million due to lower natural gas and NGL product prices, particularly ethane and propane, offset partially by higher condensate prices in ONEOK Partners’ natural gas gathering and processing business;

·	a decrease of $14.6 million due primarily to higher compression costs and third-party transportation and processing costs associated with our volume growth primarily in the Williston Basin in ONEOK Partners’ natural gas gathering and processing business;

·	a decrease of $3.7 million due to lower realized natural gas prices on the retained fuel position of ONEOK Partners’ natural gas pipeline business, offset partially by higher retained volumes; and

·	a decrease of $1.9 million related to lower isomerization volumes, offset partially by wider price differentials between normal butane and iso-butane in ONEOK Partners’ natural gas liquids business.

Operating costs increased for the three months ended June 30, 2012, compared with the same period last year, due primarily to the following:

·	an increase of $4.9 million from higher materials and outside services expenses associated primarily with scheduled maintenance and the growth of ONEOK Partners’ operations related to the completed capital projects in its natural gas liquids business; and

·	an increase of $4.7 million in higher labor costs and employee-related costs associated with growth of ONEOK Partners’ operations and completed capital projects.

Operating costs increased for the six months ended June 30, 2012, compared with the same period last year, due primarily to the following:

·	an increase of $7.7 million from higher materials, utilities and outside services expenses associated primarily with scheduled maintenance and the growth of ONEOK Partners’ operations related to the completed capital projects in its natural gas liquids business; and

·	an increase of $8.5 million in higher labor costs and employee-related costs associated with growth of ONEOK Partners’ operations and completed capital projects.

Depreciation and amortization expense increased for the three and six months ended June 30, 2012, compared with the same periods last year, due primarily to the depreciation associated with ONEOK Partners’ completed capital projects, which includes the completion of its Garden Creek plant, well connections and infrastructure projects supporting the volume growth in the Williston Basin.

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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						Six Months Ended
	June 30,						June 30,
Operating Information	2012			2011			2012			2011
Natural gas gathering and processing business (a)
Natural gas gathered (BBtu/d)		1,079			1,026			1,062			1,009
Natural gas processed (BBtu/d) (b)		823			682			796			661
NGL sales (MBbl/d)		57			47			55			45
Residue gas sales (BBtu/d)		385			300			371			287
Realized composite NGL net sales price ($/gallon) (c)	$	1.01		$	1.09		$	1.05		$	1.09
Realized condensate net sales price ($/Bbl) (c)	$	86.17		$	82.43		$	87.86		$	79.35
Realized residue gas net sales price ($/MMBtu) (c)	$	3.79		$	5.77		$	3.77		$	5.95
Realized gross processing spread ($/MMBtu) (c)	$	8.03		$	8.38		$	8.31		$	8.36

Natural gas pipelines business (a)
Natural gas transportation capacity contracted (MDth/d)		5,236			5,295			5,394			5,466
Transportation capacity subscribed (e)		87	%		88	%		89	%		90	%
Average natural gas price
Mid-Continent region ($/MMBtu)	$	2.17		$	4.18		$	2.27		$	4.14

Natural gas liquids business
NGL sales (MBbl/d)		506			482			508			480
NGLs fractionated (MBbl/d) (d)		529			541			557			518
NGLs transported-gathering lines (MBbl/d) (a)		523			432			511			415
NGLs transported-distribution lines (MBbl/d) (a)		478			462			481			462
Conway-to-Mont Belvieu OPIS average price differential
Ethane in ethane/propane mix ($/gallon)	$	0.23		$	0.20		$	0.24		$	0.17
(a) - For consolidated entities only.
(b) - Includes volumes processed at company-owned and third-party facilities.
(c) - Presented net of the impact of hedging activities and includes equity volumes only.
(d) - Includes volumes fractionated from company-owned and third-party facilities.
(e) - Prior periods have been recast to reflect current estimated capacity.

Natural gas gathered increased for the three and six months ended June 30, 2012, compared with the same periods last year, due to increased drilling activity in the Williston Basin and western Oklahoma, completion of additional gathering lines and compression to support ONEOK Partners’ new Garden Creek plant that was placed in service in December 2011 and the impact of weather-related outages in the first quarter 2011, offset partially by continued production declines and reduced drilling activity in the Powder River Basin in Wyoming.

Low natural gas prices and the relatively higher market prices of crude oil and NGLs compared with natural gas have caused producers primarily to focus development efforts on crude oil and NGL-rich supply basins rather than areas with dry natural gas production, such as the Powder River Basin. The reduced development activities and natural production declines in the Powder River Basin have resulted in lower volumes available to be gathered. While the reserve potential in the Powder River Basin still exists, future drilling and development will be affected by commodity prices and producers’ alternative prospects. A continued decline in volumes in this area may reduce ONEOK Partners’ ability to recover the carrying value of its assets and equity investments in this area and possibly result in noncash charges to earnings.

Natural gas processed, NGL sales and residue gas sales increased for the three and six months ended June 30, 2012, compared with the same periods last year, due to an increase in drilling activity in the Williston Basin and western Oklahoma, placing the new Garden Creek plant into service in December 2011 and the impact of weather-related outages in the first quarter of 2011.

Natural gas transportation capacity contracted decreased for the three and six months ended June 30, 2012, compared with the same periods last year due primarily to lower subscribed capacity on Midwestern Gas Transmission due to narrower natural gas price location differentials between the markets it serves; offset partially by higher subscribed capacity with producers to transport their increasing natural gas supply to market on our intrastate pipelines.

ONEOK Partners’ operating information above does not include its 50-percent interest in Northern Border Pipeline. Substantially all of Northern Border Pipeline’s long-haul transportation capacity has been contracted through March 2013, and two-thirds of its long-haul capacity has been contracted through 2014. Northern Border Pipeline operates pursuant to a 2007 rate case settlement and is required to file a rate case or reach a new settlement with its shippers on or before December 31, 2012, which may impact ONEOK Partners’ future equity earnings from Northern Border Pipeline.

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NGLs fractionated decreased for the three months ended June 30, 2012, compared with the same period last year, due to scheduled maintenance at ONEOK Partners’ Mont Belvieu fractionation facility in May 2012, offset partially by increased production from ONEOK Partners’ Mid-Continent fractionation facilities. NGLs fractionated increased for the six months ended June 30, 2012, compared with the same period last year, due primarily to additional Gulf Coast fractionation capacity made available by ONEOK Partners’ 60 Mbl/d fractionation services agreement with Targa Resources Partners that began in the second quarter of 2011, offset partially by scheduled maintenance at our Mont Belvieu fractionation facility in May 2012.

NGLs gathered increased for the three and six months ended June 30, 2012, compared with the same periods last year, due primarily to increased throughput from existing connections in Texas and the Mid-Continent and Rocky Mountain regions, and new supply connections in the Mid-Continent and Rocky Mountain regions. The increased capacity in the Mid-Continent and Texas was made available through ONEOK Partners’ Cana-Woodford Shale and Granite Wash projects, which were placed in service in April 2012.

NGLs transported on distribution lines increased for the three and six months ended June 30, 2012, compared with the same periods last year, due primarily to the completion of ONEOK Partners’ Sterling I Pipeline expansion.

Commodity Price Risk - The following tables set forth ONEOK Partners’ natural gas gathering and processing business’ hedging information for its equity volumes for the periods indicated, as of June 30, 2012.

	Six Months Ending
	December 31, 2012
	Volumes Hedged		(a)	Average Price		Percentage Hedged
NGLs (Bbl/d)		9,084		$	1.26 / gallon		70%
Condensate (Bbl/d)		1,757		$	2.42 / gallon		74%
Total (Bbl/d)		10,841		$	1.45 / gallon		71%
Natural gas (MMBtu/d)		48,967		$	4.25 / MMBtu		76%
(a) - Hedged with fixed-price swaps.

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

ONEOK Partners expects its commodity price sensitivity in its gathering and processing business to increase in the future as volumes increase under POP contracts with ONEOK Partners’ customers. ONEOK Partners’ commodity price sensitivity is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas, excluding the effects of hedging, and assuming normal operating conditions. ONEOK Partners’ condensate sales are based on the price of crude oil. ONEOK Partners estimates the following:

·	a $0.01 per gallon change in the composite price of NGLs would change annual net margin by approximately $2.5 million;

·	a $1.00 per barrel change in the price of crude oil would change annual net margin by approximately $1.3 million; and

·	a $0.10 per MMBtu change in the price of natural gas would change annual net margin by approximately $2.3 million.

These estimates do not include any effects on demand for ONEOK Partners’ services or processing plant operations that might be caused by, or arise in conjunction with, price changes. For example, a change in the gross processing spread may cause a change in the amount of ethane extracted from the natural gas stream, impacting gathering and processing margins for certain contracts.

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

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Natural Gas Distribution

Overview - Our Natural Gas Distribution segment provides natural gas distribution services to more than 2 million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service. We serve residential, commercial, industrial and transportation customers in all three states. In addition, our LDCs serve wholesale and public authority customers. We operate subject to regulations and oversight of various regulatory agencies. Our regulatory strategy incorporates rate-design features that reduce earnings lag, protect margin and mitigate risks.

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

	Three Months Ended				Six Months Ended				Three Months					Six Months
	June 30,				June 30,				2012 vs. 2011					2012 vs. 2011
Financial Results	2012		2011		2012		2011		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Gas sales	$	194.2	$	228.3	$	675.7	$	872.9	$	(34.1	)	(15	%)	$	(197.2	)	(23	%)
Transportation revenues		18.3		19.0		45.3		48.0		(0.7	)	(4	%)		(2.7	)	(6	%)
Cost of gas		63.6		97.8		344.1		538.3		(34.2	)	(35	%)		(194.2	)	(36	%)
Net margin, excluding other revenues		148.9		149.5		376.9		382.6		(0.6	)	(0	%)		(5.7	)	(1	%)
Other revenues		8.6		9.6		17.9		20.3		(1.0	)	(10	%)		(2.4	)	(12	%)
Net margin		157.5		159.1		394.8		402.9		(1.6	)	(1	%)		(8.1	)	(2	%)
Operating costs		103.8		104.5		208.7		209.2		(0.7	)	(1	%)		(0.5	)		-
Depreciation and amortization		32.0		34.4		65.5		70.4		(2.4	)	(7	%)		(4.9	)	(7	%)
Operating income	$	21.7	$	20.2	$	120.6	$	123.3	$	1.5		7	%	$	(2.7	)	(2	%)
Capital expenditures	$	72.9	$	61.9	$	131.4	$	109.0	$	11.0		18	%	$	22.4		21	%

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

	Three Months Ended				Six Months Ended				Three Months					Six Months
	June 30,				June 30,				2012 vs. 2011					2012 vs. 2011
Net Margin, Excluding Other Revenues	2012		2011		2012		2011		Increase (Decrease)					Increase (Decrease)
Gas sales	(Millions of dollars)
Residential	$	107.9	$	105.9	$	273.0	$	271.1	$	2.0		2	%	$	1.9		1	%
Commercial		21.3		23.2		54.9		59.8		(1.9	)	(8	%)		(4.9	)	(8	%)
Industrial		0.8		0.8		1.4		1.6		-		0	%		(0.2	)	(13	%)
Wholesale/public authority		0.6		0.6		2.3		2.1		-		0	%		0.2		10	%
Net margin on gas sales		130.6		130.5		331.6		334.6		0.1		0	%		(3.0	)	(1	%)
Transportation margin		18.3		19.0		45.3		48.0		(0.7	)	(4	%)		(2.7	)	(6	%)
Net margin, excluding other revenues	$	148.9	$	149.5	$	376.9	$	382.6	$	(0.6	)	(0	%)	$	(5.7	)	(1	%)

Natural gas prices decreased during the three and six months ended June 30, 2012, compared with the same periods last year. The decrease in natural gas prices had a direct impact on our revenues and cost of sales.

Net margin decreased for the three months ended June 30, 2012, compared with the same period last year, due primarily to the following:

a decrease of $4.2 million due to expiration of the Integrity Management Program (IMP) rider, which allowed Oklahoma Natural Gas to recover certain deferred pipeline-integrity costs in Oklahoma. This decrease is offset by lower regulatory amortization in depreciation and amortization expense; offset partially by

·	an increase of $1.9 million from new rates and surcharge recoveries in Texas and Kansas.

Net margin decreased for the six months ended June 30, 2012, compared with the same period last year, due primarily to the following:

·	a decrease of $8.5 million due to expiration of the IMP rider. This decrease is offset by lower regulatory amortization in depreciation and amortization expense; and

·	a decrease of $2.9 million from lower transportation volumes due to weather-sensitive customers in Kansas and Oklahoma; offset partially by

·	an increase of $4.2 million from new rates and surcharge recoveries in Texas and Kansas.

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Operating costs decreased for the three months ended June 30, 2012, compared with the same period last year, due primarily to the following:

·	a decrease of $3.3 million in share-based compensation costs from common stock awarded in the prior year to employees as part of ONEOK’s stock award program and the appreciation in ONEOK’s share price during 2011;

·	a decrease of $1.4 million in bad-debt expense; offset partially by

·	an increase of $1.8 million in legal costs;

·	an increase of $1.4 million in higher outside service costs due primarily to expenses associated with IMP activities, pipeline maintenance and other consulting services; and

·	an increase of $1.0 million in pension costs as a result of the annual change in our estimated discount rate.

Operating costs decreased for the six months ended June 30, 2012, compared with the same period last year, due primarily to the following:

·	a decrease of $10.3 million in share-based compensation costs from common stock awarded in the prior year to employees as part of ONEOK’s stock award program and the appreciation in ONEOK’s share price during 2011; offset partially by

·	an increase of $3.8 million from higher outside service costs due primarily to expenses associated with IMP activities in Oklahoma;

·	an increase of $3.3 million in legal costs; and

·	an increase of $2.0 million in pension costs as a result of the annual change in our estimated discount rate.

Depreciation and amortization expense decreased for the three and six months ended June 30, 2012, due primarily to a decrease of $4.2 million and $8.5 million, respectively, in regulatory amortization associated with the expiration of the IMP rider, which allowed us to defer recognition of certain pipeline-integrity costs in Oklahoma; offset partially by an increase of $1.6 million and $3.4 million, respectively, in higher depreciation expense associated with additional capital expenditures.

Capital Expenditures - Our capital expenditures program includes expenditures for pipeline integrity, automated meter reading, extending service to new areas, modifications to customer-service lines, increasing system capabilities, relocating facilities to accommodate government construction and replacements. It is our practice to maintain and upgrade facilities to ensure safe, reliable and efficient operations.

Capital expenditures increased for the three and six months ended June 30, 2012, compared with the same periods last year, primarily as a result of increased spending on pipeline replacements.

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

	Three Months Ended		Six Months Ended
	June 30,		June 30,
Number of Customers	2012	2011	2012	2011
Residential	1,933,646	1,924,608	1,939,201	1,931,569
Commercial	153,020	153,734	154,457	155,087
Industrial	1,214	1,237	1,232	1,242
Wholesale/public authority	2,750	2,736	2,726	2,760
Transportation	11,911	11,677	11,894	11,643
Total customers	2,102,541	2,093,992	2,109,510	2,102,301

	Three Months Ended		Six Months Ended
	June 30,		June 30,
Volumes (MMcf)	2012	2011	2012	2011
Gas sales
Residential	9,021	12,336	58,718	70,801
Commercial	3,593	4,343	16,690	19,898
Industrial	383	287	725	710
Wholesale/public authority	2,326	393	4,833	1,562
Total volumes sold	15,323	17,359	80,966	92,971
Transportation	45,842	46,433	103,375	108,882
Total volumes delivered	61,165	63,792	184,341	201,853

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Residential and commercial volumes decreased for the three and six months ended June 30, 2012, compared with the same periods last year, due primarily to warmer temperatures in the first and second quarters of 2012; however, the impact on margins was mitigated largely by weather normalization mechanisms. Wholesale sales represent contracted gas volumes that exceed the needs of our residential, commercial and industrial customer base and are available for sale to other parties. Wholesale volumes increased for 2012, compared to 2011; however, the impact to margins was minimal.

Regulatory Initiatives - Oklahoma - In March 2012, Oklahoma Natural Gas filed a Performance Based Rate Change (PBRC) filing seeking to increase base rates by $16.2 million. A Joint Stipulation was approved by the OCC in July 2012. This agreement provides for a $9.5 million rate increase and modifications to Oklahoma Natural Gas’ PBRC tariff. The modified tariff narrows the range of allowed regulated return on equity (ROE) to a range of 10.0 percent to 11.0 percent from our previous range of 9.75 percent to 11.25 percent; increases the ROE reflected in any rate increase resulting from a revenue deficiency to 10.5 percent from 10.25 percent; and reduces the number of allowed pro forma adjustments that can be proposed by Oklahoma Natural Gas.

In May 2011, the OCC approved a portfolio of conservation and energy-efficiency programs and authorized recovery of costs and performance incentives. The agreement allows Oklahoma Natural Gas to pursue key energy-efficiency programs and allows the company to earn up to $1.5 million annually, if program objectives are achieved. Based on customer interest in the rebate programs through June 2012, we anticipate several rebate programs being fully subscribed by customers during calendar 2012.

Kansas - In May 2012, Kansas Gas Service submitted an application to increase its overall annual revenues by $32.7 million. The request includes a $50.7 million increase in base rates and an $18.0 million reduction in amounts currently recovered through surcharges. The KCC has 240 days to issue an order and is expected to make a final ruling by January 14, 2013.

In March 2012, Kansas Gas Service submitted an application to the KCC to approve the implementation of a cast-iron pipeline-replacement program that would accelerate the rate at which we are replacing cast-iron pipe. The application seeks a surcharge that would recover the carrying charges and depreciation expense associated with the investment as the costs are incurred. The total cost of the replacement program is estimated to be $8.8 million annually over an eight-year period.

The KCC approved an application from Kansas Gas Service to increase the Gas System Reliability Surcharge by an additional $2.9 million effective January 2012. This surcharge is a capital-recovery mechanism that allows for rate adjustment, providing recovery of and a return on incremental safety-related and government-mandated capital investments made between rate cases.

Texas - Texas Gas Service made annual filings for interim rate relief under the Gas Reliability Infrastructure Program (GRIP) statute with the cities of Austin, Texas, and surrounding communities in February 2012 and El Paso, Texas, in April 2012. GRIP is a capital-recovery mechanism that allows for an interim rate adjustment providing recovery and a return on incremental capital investments made between rate cases. In May 2012, the City of Austin, Texas, approved a $3.5 million increase pursuant to this filing. In July 2012, the city of El Paso approved a $1.3 million increase.

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

In the normal course of business, Texas Gas Service has filed rate cases and requests for GRIP and cost-of-service adjustments in various other Texas jurisdictions to address investments in rate base and changes in expense. Annual rate increases totaling $5.3 million associated with these filings have been approved in 2012.

Energy Services

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

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

To ensure natural gas is available when our customers need it, we offer premium services and products that satisfy our customers’ nonuniform supply needs such as swing and peaking natural gas load requirements on a year-round basis. Types of premium services include next-day and no-notice services. Next-day services allow our customers to call on additional gas supply, up to an amount agreed upon in a service contract, and expect delivery the following day. No-notice services allow customers to call on additional natural gas supply and expect immediate delivery. We also provide weather-related protection and other custom solutions based on our customers’ specific needs. Our storage and transportation assets enable us to provide these services and provide us with opportunities to capture daily, monthly and seasonal value due to market inefficiencies. We expect premium-services margins will be lower than the prior year due to lower natural gas prices.

As a result of significant increases in the supply of natural gas, primarily from shale production across North America, location and seasonal price differentials have narrowed significantly, resulting in reduced opportunities to capture margins with our firm transportation and storage capacity. Additionally, price volatility in the natural gas markets remains relatively low as compared with volatility in the past, which, coupled with a fairly flat forward price curve, reduces the value of the demand fee we receive for premium services and further limits opportunities to optimize our assets. We have undertaken several steps to better align fixed costs with the current business environment, including attempts to renegotiate various natural gas storage and transportation contracts. Contract renegotiation activities that we have taken or expect to take include renewing contracts at current market rates at contract expiration, extending contracts in order to negotiate a more favorable rate or paying to terminate contracts in areas that are no longer strategic to our business. For the six months ended June 30, 2012, we recognized charges to our earnings as a result of certain of these actions. As we continue our contract renegotiation activities, it is possible we may recognize additional charges to our earnings in the future. We expect these contractual changes to result in less storage and transportation capacity under lease and a better alignment of our contracted natural gas transportation and storage capacity with the needs of our premium-services customers. We also expect the reduction in our contracted natural gas transportation and storage capacity will reduce our operating costs and working-capital requirements.

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

	Three Months Ended						Six Months Ended					Three Months					Six Months
	June 30,						June 30,					2012 vs. 2011					2012 vs. 2011
Financial Results	2012			2011			2012			2011		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Revenues	$	268.9		$	616.0		$	729.7		$	1,507.8	$	(347.1	)	(56	%)	$	(778.1	)	(52	%)
Cost of sales and fuel		279.3			616.4			755.6			1,452.3		(337.1	)	(55	%)		(696.7	)	(48	%)
Net margin		(10.4	)		(0.4	)		(25.9	)		55.5		(10.0	)		*		(81.4	)		*
Operating costs		4.6			5.3			9.4			13.3		(0.7	)	(13	%)		(3.9	)	(29	%)
Depreciation and amortization		0.1			0.1			0.2			0.2		-		0	%		-			-
Goodwill impairment		-			-			10.3			-		-			-		10.3		100	%
Operating income (loss)	$	(15.1	)	$	(5.8	)	$	(45.8	)	$	42.0	$	(9.3	)		*	$	(87.8	)		*
* Percentage change is greater than 100 percent.

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

	Three Months Ended						Six Months Ended						Three Months					Six Months
	June 30,							June 30,					2012 vs. 2011					2012 vs. 2011
	2012			2011				2012			2011		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Marketing, storage and transportation revenues, gross	$	26.7		$	39.4			$	55.5		$	136.7	$	(12.7	)	(32	%)	$	(81.2	)	(59	%)
Storage and transportation costs		37.6			39.6				82.1			81.4		(2.0	)	(5	%)		0.7		1	%
Marketing, storage and transportation, net		(10.9	)		(0.2	)			(26.6	)		55.3		(10.7	)		*		(81.9	)		*
Financial trading, net		0.5			(0.2	)			0.7			0.2		0.7			*		0.5			*
Net margin	$	(10.4	)	$	(0.4	)		$	(25.9	)	$	55.5	$	(10.0	)		*	$	(81.4	)		*
* Percentage change is greater than 100 percent.

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

Our storage and transportation costs decreased 5 percent for the three months ended June 30, 2012, compared with the three months ended June 30, 2011, due primarily to reduced transportation capacity, offset partially by an increase in storage demand fees and a loss resulting from the release to a third party of contracted transportation capacity that expires in December 2012.

Our storage and transportation costs remained relatively unchanged for the six months ended June 30, 2012, compared with the six months ended June 30, 2011, due primarily to an increase in storage demand fees and a loss resulting from the release to a third party of contracted transportation capacity that expires in December 2012, offset by reduced transportation capacity.

For additional information on transportation and storage capacity refer to “Selected Operating Information” below.

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

Revenues and cost of sales and fuel decreased for the three and six months ended June 30, 2012, compared with the same periods last year, due primarily to lower natural gas prices.

Net margin decreased for the three months ended June 30, 2012, compared with the same period last year, due primarily to the following:

·	a decrease of $8.7 million in transportation margins, net of hedging, due primarily to lower hedge settlements in 2012;

·	a decrease of $2.1 million in premium-services margins, associated primarily with lower demand fees; and

·	storage and marketing margins, net of hedging activities, were relatively unchanged but reflect:

-	an increase of $12.8 million due to higher realized seasonal storage price differentials; offset by

-	a decrease of $6.8 million from unrealized fair value changes on nonqualifying economic hedges;

-	a decrease of $3.7 million due primarily to decreased marketing activities; and

-	a decrease of $1.4 million due to higher demand fees on storage contracts.

Net margin decreased for the six months ended June 30, 2012, compared with the same period last year, due primarily to the following:

·	a decrease of $65.4 million in storage and marketing margins, net of hedging activities, due primarily to the following:

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

-	a decrease of $15.1 million due to lower realized seasonal storage price differentials;

-	a decrease of $9.3 million due to unrealized fair value changes on nonqualifying economic hedges;

-	a decrease of $6.2 million due primarily to decreased marketing activities; and

-	a decrease of $3.7 million due to higher demand fees on storage contracts;

·	a decrease of $13.6 million in transportation margins, net of hedging, due primarily to the following:

-	lower hedge settlements in 2012; and

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

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

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Operating costs decreased for the three and six months ended June 30, 2012, compared with the same periods last year due primarily to lower employee related expenses.

We also recognized an expense of $10.3 million related to the impairment of our goodwill in the first quarter of 2012. Given the continued significant decline in natural gas prices and its effect on location and seasonal price differentials, we performed an interim impairment assessment in the first quarter of 2012 that reduced our goodwill balance to zero.

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
Operating Information	2012			2011		2012			2011
Natural gas marketed (Bcf)		150			192		368			452
Natural gas gross margin ($/Mcf)	$	(0.06	)	$	-	$	(0.06	)	$	0.13
Physically settled volumes (Bcf)		322			405		739			899

Natural gas volumes marketed and physically settled volumes decreased for the three and six months ended June 30, 2012, compared with the same periods last year, due primarily to lower transported volumes and reduced transportation capacity. Transportation capacity in certain markets was not utilized due to the economics of the location differentials as a result of increased supply of natural gas, primarily from shale production, and increased pipeline capacity as a result of pipeline construction.

At June 30, 2012, our natural gas transportation capacity was 1.1 Bcf/d, of which 1.0 Bcf/d was contracted under long-term natural gas transportation contracts, compared with 1.2 Bcf/d of total capacity and 1.2 Bcf/d of long-term capacity at June 30, 2011. Approximately 6 percent of our transportation capacity expires by the end of 2012, and approximately an additional 69 percent expires by the end of 2015.

Approximately 35.0 MMcf/d of transportation capacity expired in the first quarter of 2012, an additional 46.2 MMcf/d expired on April 1, 2012, and 59.8 MMcf/d will expire in the fourth quarter of 2012. We do not expect to renew any of this transportation capacity.

Our natural gas in storage at June 30, 2012, was 58.6 Bcf, compared with 43.3 Bcf at June 30, 2011. At June 30, 2012, our total natural gas storage capacity under lease was 72.4 Bcf, compared with 72.6 Bcf at June 30, 2011. At June 30, 2012, our natural gas storage capacity under lease had a maximum withdrawal capability of 2.3 Bcf/d and maximum injection capability of 1.3 Bcf/d. Approximately 15.2 Bcf of storage capacity expired on April 1, 2012, of which 12.7 Bcf was renewed at market rates. We have no additional storage capacity contracts expiring for the remainder of 2012; approximately 88 percent expires by the end of 2015.

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

CONTINGENCIES

LIQUIDITY AND CAPITAL RESOURCES

General - ONEOK and ONEOK Partners have relied primarily on operating cash flow, commercial paper, bank credit facilities, debt issuances and/or the issuance of equity for their liquidity and capital resource requirements. ONEOK and ONEOK Partners fund operating expenses, debt service, dividends to shareholders and distributions to unitholders primarily with operating cash flow. Capital expenditures are funded by short- and long-term debt, issuances of equity and operating cash flow. We expect to continue to use these sources for our liquidity and capital resource needs. Neither ONEOK nor ONEOK Partners guarantees the debt or other similar commitments to unaffiliated parties, and ONEOK does not guarantee the debt or other similar commitments of ONEOK Partners.

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ONEOK’s and ONEOK Partners’ ability to continue to access capital markets for debt and equity financing under reasonable terms depends on market conditions and ONEOK’s and ONEOK Partners’ respective financial condition and credit ratings. We anticipate that our cash flow generated from operations, existing capital resources, including proceeds from the issuance of our $700 million, 4.25-percent senior notes in January 2012 and distributions from ONEOK Partners will enable us to maintain our current and planned level of operations and fund any share repurchases under our three-year, $750-million stock repurchase program. ONEOK Partners anticipates that its cash flow generated from operations, proceeds from its March 2012 equity offering, existing capital resources and ability to obtain financing will enable it to maintain its current and planned level of operations. Additionally, ONEOK Partners expects to fund its future capital expenditures with short- and long-term debt, the issuance of equity and operating cash flows.

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

	June 30,	December 31,
	2012	2011
Long-term debt	55%	56%
Total equity	45%	44%

Debt (including notes payable)	58%	60%
Total equity	42%	40%

For purposes of determining compliance with financial covenants in the ONEOK 2011 Credit Agreement, which are described below, the debt of ONEOK Partners is excluded. The following table sets forth ONEOK’s capital structure, excluding the debt of ONEOK Partners, for the periods indicated:

	June 30,	December 31,
	2012	2011
Long-term debt	45%	31%
ONEOK shareholders' equity	55%	69%

Debt (including notes payable)	52%	45%
ONEOK shareholders' equity	48%	55%

Stock Repurchase Program - In June 2012, we entered into an accelerated share repurchase agreement (the ASR Agreement) with Goldman, Sachs & Co. (Goldman), pursuant to which we paid $150 million to Goldman and received from Goldman approximately 2.9 million shares of our common stock, representing approximately 80 percent of the estimated total number of shares to be repurchased. The ASR Agreement is scheduled to end in September 2012, although the termination date may be accelerated. We expect to receive the balance of the shares at the conclusion of the ASR Agreement. The specific number of shares that we ultimately will repurchase will be based on the volume weighted average price per share of our common stock during the repurchase period, subject to other adjustments pursuant to the terms and conditions of the ASR Agreement. At settlement, under certain circumstances, Goldman may be required to deliver additional shares of our common stock to us, or, under certain circumstances, we may be required to deliver shares of our common stock or we may elect to make a cash payment to Goldman.

The ASR Agreement is part of our three-year stock repurchase program that was authorized by our Board of Directors on October 21, 2010, to buy up to $750 million of our common stock, subject to the limitation that purchases will not exceed $300 million in any one calendar year. Pursuant to the Board’s authorization, following this transaction and our repurchase of $300 million in 2011, an additional $300 million may yet be purchased pursuant to the program, of which a maximum of $150 million of additional shares of our common stock may be purchased in 2012.

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

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ONEOK maintains the power to control the management and policies of ONEOK Partners, and a limit on new investments in master limited partnerships. The ONEOK 2011 Credit Agreement also contains customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in the nature of ONEOK’s businesses, transactions with affiliates, the use of proceeds and a covenant that limits ONEOK’s ability to restrict its subsidiaries’ ability to pay dividends. The debt covenant calculations in the ONEOK 2011 Credit Agreement exclude the debt of ONEOK Partners. In the event of a breach of certain covenants by ONEOK, amounts outstanding under the ONEOK 2011 Credit Agreement may become due and payable immediately. At June 30, 2012, ONEOK’s stand-alone debt-to-capital ratio, as defined by the ONEOK 2011 Credit Agreement, was 50.5 percent, and ONEOK was in compliance with all covenants under the ONEOK 2011 Credit Agreement.

The total amount of short-term borrowings authorized by ONEOK’s Board of Directors is $2.8 billion. At June 30, 2012, ONEOK had $571.9 million of commercial paper outstanding, $1.7 million in letters of credit issued under the ONEOK 2011 Credit Agreement and approximately $22.8 million of cash and cash equivalents. ONEOK had approximately $626.4 million of credit available at June 30, 2012, under the ONEOK 2011 Credit Agreement. As of June 30, 2012, ONEOK could have issued $2.4 billion of additional short- and long-term debt under the most restrictive provisions contained in its various borrowing agreements.

ONEOK Partners 2011 Credit Agreement - The ONEOK Partners 2011 Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in the ONEOK Partners 2011 Credit Agreement, adjusted for all noncash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5.0 to 1. If ONEOK Partners consummates one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will be increased to 5.5 to 1 for the quarter of the acquisition and the two following quarters. Upon breach of certain covenants by ONEOK Partners in the ONEOK Partners 2011 Credit Agreement, amounts outstanding under the ONEOK Partners 2011 Credit Agreement, if any, may become due and payable immediately. At June 30, 2012, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 2.3 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners 2011 Credit Agreement.

The ONEOK Partners 2011 Credit Agreement includes a $100-million sublimit for the issuance of standby letters of credit and also features an option to request an increase in the size of the facility to an aggregate of $1.7 billion from $1.2 billion by either commitments from new lenders or increased commitments from existing lenders. The ONEOK Partners 2011 Credit Agreement is available to repay ONEOK Partners’ commercial paper notes, if necessary. Amounts outstanding under ONEOK Partners’ commercial paper program reduce the borrowing capacity under the ONEOK Partners 2011 Credit Agreement.

The total amount of short-term borrowings authorized by the Board of Directors of ONEOK Partners GP, the general partner of ONEOK Partners, is $2.5 billion. At June 30, 2012, ONEOK Partners had $24.0 million of commercial paper outstanding, no letters of credit issued, no borrowings outstanding under the ONEOK Partners 2011 Credit Agreement, approximately $92.2 million of cash and $1.2 billion of credit available under the ONEOK Partners 2011 Credit Agreement. As of June 30, 2012, ONEOK Partners could have issued $4.8 billion of short- and long-term debt to meet its liquidity needs under the most restrictive provisions contained in its various borrowing agreements.

Effective August 1, 2012, ONEOK Partners extended the maturity date of its Partnership 2011 Credit Agreement from August 1, 2016, to August 1, 2017, pursuant to an extension agreement between ONEOK Partners and its lenders.

Recent events in the European economy could impact European banks. Various European-based banks participate in the ONEOK 2011 Credit Agreement and ONEOK Partners 2011 Credit Agreement, representing an aggregate of $340 million and $342 million in committed capacity, respectively. These banks are of significant scale and international diversification, which we believe minimizes the risk of these banks being unable to fulfill their commitments to us or ONEOK Partners under our respective credit agreements. Should any of these banks be unable to fund any future borrowings under the credit agreements, we believe other funding sources would likely be available to replace the European banks’ commitments.

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

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

ONEOK Debt Issuance - In January 2012, we completed an underwritten public offering of $700 million, 4.25-percent senior notes due 2022. The net proceeds from the offering, after deducting underwriting discounts and offering expenses, of approximately $694.3 million were used to repay amounts outstanding under our commercial paper program. We will pay interest on the senior notes due 2022 on February 1 and August 1 of each year, beginning August 1, 2012.

The indenture governing ONEOK’s senior notes due 2022 includes an event of default upon acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2022 to declare those senior notes immediately due and payable in full.

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

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

Interest-rate Swaps - ONEOK and ONEOK Partners each entered into forward-starting interest-rate swaps to hedge the variability of interest payments on a portion of forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. ONEOK had interest-rate swaps with notional values totaling $500 million at December 31, 2011. In January 2012, ONEOK entered into additional interest-rate swaps with notional amounts totaling $200 million. Upon issuance in January 2012 of our $700 million, 4.25-percent senior notes due 2022, ONEOK settled all $700 million of its interest-rate swaps and realized a loss of $44.1 million in accumulated other comprehensive income that will be amortized to interest expense over the term of the hedged debt. At June 30, 2012, and December 31, 2011, ONEOK Partners had forward-starting interest-rate swaps with notional amounts totaling $1 billion and $750 million, respectively. In July 2012, ONEOK Partners entered into additional forward-starting interest-rate swaps with settlement dates greater than 12 months with notional amounts totaling $400 million.

Capital Expenditures - ONEOK’s and ONEOK Partners’ capital expenditures are financed typically through operating cash flows, short- and long-term debt and the issuance of equity. Capital expenditures were $780.7 million and $523.7 million for the six months ending June 30, 2012 and 2011, respectively, exclusive of acquisitions. Of these amounts, ONEOK Partners’ capital expenditures were $636.2 million and $410.2 million for the six months ended June 30, 2012 and 2011, respectively, exclusive of acquisitions. Capital expenditures for 2012 increased, compared with the same period last year, due primarily to the growth projects in ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses.

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The following table sets forth our 2012 projected capital expenditures, excluding AFUDC:

2012 Projected Capital Expenditures
	(Millions of dollars)
ONEOK Partners	$	2,045
Natural Gas Distribution		272
Other		32
Total projected capital expenditures	$	2,349

Credit Ratings - Our credit ratings as of June 30, 2012, are shown in the table below:

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

ONEOK’s and ONEOK Partners’ commercial paper programs are each rated Prime-2 by Moody’s and A2 by S&P. ONEOK’s and ONEOK Partners’ credit ratings, which currently are investment grade, may be affected by a material change in financial ratios or a material event affecting the business. The most common criteria for assessment of credit ratings are the debt-to-capital ratio, business risk profile, pre-tax and after-tax interest coverage, and liquidity. ONEOK and ONEOK Partners currently do not anticipate their respective credit ratings to be downgraded; however, if ONEOK’s or ONEOK Partners’ credit ratings were downgraded, the cost to borrow funds under their respective commercial paper programs and credit agreements would increase, and ONEOK or ONEOK Partners potentially could lose access to the commercial paper market. In the event that ONEOK is unable to borrow funds under its commercial paper program and there has not been a material adverse change in its business, ONEOK would continue to have access to the ONEOK 2011 Credit Agreement, which expires in April 2016. In the event that ONEOK Partners is unable to borrow funds under its commercial paper program and there has not been a material adverse change in its business, ONEOK Partners would continue to have access to the ONEOK Partners 2011 Credit Agreement, which expires in August 2017. An adverse rating change alone is not a default under the ONEOK 2011 Credit Agreement or the ONEOK Partners 2011 Credit Agreement.

Our Energy Services segment relies upon the investment-grade rating of ONEOK’s senior unsecured long-term debt to reduce its collateral requirements. If ONEOK’s credit ratings were to decline below investment grade, our ability to participate in energy marketing and trading activities could be significantly limited. Without an investment-grade rating, we may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments. At June 30, 2012, ONEOK could have been required to fund approximately $3.1 million in margin requirements related to financial contracts upon such a downgrade. A decline in ONEOK’s credit rating below investment grade also may impact significantly other business segments.

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

Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity prices will impact our overall liquidity due to the impact commodity price changes have on our cash flows from operating activities, including the impact on working capital for NGLs and natural gas held in storage, margin requirements and certain energy-related receivables. We believe that ONEOK’s and ONEOK Partners’ available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity price volatility. See Note D of the Notes to Consolidated Financial Statements; the discussion under ONEOK Partners’ “Commodity Price Risk” in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations; and Energy Services’ discussion under “Commodity Price Risk” in Item 3, Quantitative and Qualitative Disclosures about Market Risk, for information on our hedging activities.

Pension and Postretirement Benefit Plans - Information about our pension and postretirement benefits plans, including anticipated contributions, is included under Note M of the Notes to Consolidated Financial Statements in our Annual Report. See Note J of the Notes to Consolidated Financial Statements in this Quarterly Report for additional information.

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CASH FLOW ANALYSIS

We use the indirect method to prepare our Consolidated Statements of Cash Flows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payments during the period.

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

	Six Months Ended							Variances
	June 30,							2012 vs. 2011
	2012			2011			Increase (Decrease)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	652.6		$	875.6			$ (223.0)
Investing activities		(738.4	)		(508.8	)			(229.6)
Financing activities		125.9			79.8				46.1
Change in cash and cash equivalents		40.1			446.6				(406.5)
Change in cash and cash equivalents included in discontinued operations		8.8			(4.7	)			13.5
Change in cash and cash equivalents from continuing operations		48.9			441.9				(393.0)
Cash and cash equivalents at beginning of period		66.0			30.3				35.7
Cash and cash equivalents at end of period	$	114.9		$	472.2			$ (357.3)

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

Cash flows from operating activities, before changes in operating assets and liabilities, were $705.9 million for the six months ended June 30, 2012, compared with $623.0 million for the same period in 2011. The increase was due primarily to changes in net margin and operating expenses discussed in Financial Results and Operating Information on page 38.

The changes in operating assets and liabilities decreased operating cash flows $53.3 million for the six months ended June 30, 2012, compared with an increase of $252.6 million for the same period last year. The change was due primarily to the collection and payment of trade receivables and payables, resulting from the timing of invoices collected from customers and paid to vendors and suppliers, which vary from period to period; and the change in gas and natural gas liquids in storage primarily at ONEOK Partners’ natural gas liquids business and our Energy Services segment. The change in natural gas and natural gas liquids in storage results from changes in storage levels and the impact of commodity prices on the purchase cost of inventory, both which vary from period to period.

Investing Cash Flows - Cash used in investing activities increased for the six months ended June 30, 2012, compared with cash used in investing activities for the same period in 2011, due primarily to ONEOK Partners’ growth projects in its natural gas gathering and processing and natural gas liquids businesses, offset partially by proceeds from the sale of ONEOK Energy Marketing Company.

Financing Cash Flows - Cash provided by financing activities increased for the six months ended June 30, 2012, compared with the same period in 2011. The change is a result of our January 2012 debt issuance and the ONEOK Partners equity issuances in March 2012, offset partially by increased distributions to noncontrolling interests and increased dividends.

REGULATORY

Financial Markets Legislation - The Dodd-Frank Act represents a far-reaching overhaul of the framework for regulation of United States financial markets. Various regulatory agencies, including the SEC and the CFTC, have proposed regulations for implementation of many of the provisions of the Dodd-Frank Act. The CFTC has issued final regulations for certain provisions of the Dodd-Frank Act, but others remain outstanding. In July 2012, the CFTC issued an order that further defers the effective date of the provisions of the Dodd-Frank Act that require a rulemaking, such as definitions of certain terms, until the earlier of the effective date of the final rule defining the referenced terms or December 31, 2012. The CFTC issued the definitional rules in late May and early July 2012 that will become effective 60 days after publication in the Federal Register. We are reviewing the rules to ascertain how we may be affected by them. Based on our assessment of the regulations issued to date and those proposed, we expect to be able to continue to participate in financial markets for hedging certain risks

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inherent in our business, including commodity and interest-rate risks; however, the capital requirements and costs of hedging may increase as a result of the legislation. We also may incur additional costs associated with our compliance with the new regulations and anticipated additional record keeping, reporting and disclosure obligations; however, we do not believe the costs will be material. These requirements could affect adversely market liquidity and pricing of derivative contracts making it more difficult to execute our risk-management strategies in the future. Also, the anticipated increased costs of compliance by dealers and counterparties likely will be passed on to customers, which could decrease the benefits of hedging to us and could reduce our profitability and liquidity.

Other - Several regulatory initiatives impacted the earnings and future earnings potential for our Natural Gas Distribution segment. See discussion of our Natural Gas Distribution segment’s regulatory initiatives beginning on page 48.

ENVIRONMENTAL AND SAFETY MATTERS

In addition, emission controls required under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

Pipeline Safety - We are subject to Pipeline and Hazardous Materials Safety Administration regulations, including integrity- management regulations. The Pipeline Safety Improvement Act of 2002 requires pipeline companies operating high-pressure pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. In January 2012, The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law. The new law increased maximum penalties for violating federal pipeline safety regulations and directs the DOT and Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us. These issues include but are not limited to:

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

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

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

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

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

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

Federal, state and regional initiatives to measure and regulate greenhouse gas emissions are under way. We are monitoring federal and state legislation to assess the potential impact on our operations. The EPA’s Mandatory Greenhouse Gas Reporting Rule, released in September 2009, requires greenhouse gas emissions reporting for affected facilities on an annual

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basis and requires us to track the emission equivalents for the natural gas delivered by us to our distribution customers and emission equivalents for all NGLs delivered to customers of ONEOK Partners. Our 2010 total reported emissions were less than 66.6 million metric tons of carbon dioxide equivalents. This total includes direct emissions from the combustion of fuel in our equipment, such as compressor engines and heaters, as well as carbon dioxide equivalents from natural gas and NGL products delivered to customers, as if all such fuel and NGL products were combusted with the resulting carbon dioxide injected directly into disposal wells. We reported 2011 greenhouse gas emissions for a portion of our facilities by March 31, 2012, as required by the EPA, and will report for the remainder of our facilities by September 30, 2012. Also, the EPA released a subpart to the Mandatory Greenhouse Gas Reporting Rule that will require the reporting of vented and fugitive emissions of methane from our facilities. The new requirements began in January 2011, with the first reporting of fugitive emissions due September 30, 2012. We do not expect the cost to gather this emission data to have a material impact on our results of operations, financial position or cash flows. In addition, Congress has considered, and may consider in the future, legislation to reduce greenhouse gas emissions, including carbon dioxide and methane. At this time, no rule or legislation has been enacted that assesses any costs, fees or expenses on any of these emissions.

Superfund - The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or Superfund, imposes liability, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of a facility where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the facility. Under CERCLA, these persons may be liable for the costs of cleaning up the hazardous substances released into the environment, damages to natural resources and the costs of certain health studies. Neither we nor ONEOK Partners expect our respective current responsibilities under CERCLA, for this facility and any other, to have a material impact on our respective results of operations, financial position or cash flows.

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

Pipeline Security - Homeland Security’s Transportation Security Administration and the DOT have completed a review and inspection of our “critical facilities” and identified no material security issues. Also, the Transportation Security Administration has released new pipeline security guidelines that include broader definitions for the determination of pipeline “critical facilities.” We have reviewed our pipeline facilities according to the new guideline requirements, and there have been no material changes required to date.

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

ONEOK Partners participates in the EPA’s Natural Gas STAR Program to reduce voluntarily methane emissions. We continue to focus on maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices to limit the release of natural gas during pipeline and facility maintenance and operations. Our most recent calculation of our annual lost-and-unaccounted-for natural gas, for all of our business operations, is less than 1 percent of total throughput.

IMPACT OF NEW ACCOUNTING STANDARDS

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

ESTIMATES AND CRITICAL ACCOUNTING POLICIES

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

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

FORWARD-LOOKING STATEMENTS

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

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

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

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

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

·	the status of deregulation of retail natural gas distribution;

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·	the capital intensive nature of our businesses;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

·	the impact and outcome of pending and future litigation;

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

-	future demand for and prices of natural gas, NGLs and crude oil;

-	competitive conditions in the overall energy market;

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

-	availability of additional storage capacity;

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

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

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

·	the mechanical integrity of facilities operated;

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

·	our ability to control operating costs;

·	adverse labor relations;

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

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

·	the risk of a prolonged slowdown in growth or decline in the United States or international economies, including liquidity risks in United States or foreign credit markets;

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

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

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

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

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

·	the impact of uncontracted capacity in our assets being greater or less than expected;

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

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

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

·	the impact of potential impairment charges;

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

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

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

COMMODITY PRICE RISK

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

Energy Services

Fair Value Component of the Energy Marketing and Risk Management Assets and Liabilities - The following table sets forth the fair value component of the energy marketing and risk management assets and liabilities, excluding $22.1 million and $80.7 million of net assets at June 30, 2012, and December 31, 2011, respectively, from derivative instruments declared as either fair value or cash flow hedges for the periods indicated:

Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities
	(Thousands of dollars)
Net fair value of derivatives outstanding at December 31, 2011	$	12,609
Derivatives reclassified or otherwise settled during the period		(6,300	)
Fair value of new derivatives entered into during the period		6,480
Other changes in fair value		(3,849	)
Net fair value of derivatives outstanding at June 30, 2012 (a)	$	8,940
(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: $7.3 million matures through March 2013 and $1.6 million matures through March 2016.

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

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

Value-at-Risk (VAR) Disclosure of Commodity Price Risk - The potential impact on our future earnings, as measured by VAR, was $3.2 million and $1.8 million at June 30, 2012 and 2011, respectively. The following table sets forth the average, high and low VAR calculations for the periods indicated:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Value-at-Risk	2012		2011		2012		2011
	(Millions of dollars)
Average	$	2.9	$	3.7	$	2.7	$	3.5
High	$	4.0	$	6.6	$	4.0	$	6.6
Low	$	1.8	$	1.6	$	1.8	$	1.6

Our VAR calculation includes derivatives, executory storage and transportation agreements and their related hedges. The variations in the VAR data are reflective of market volatility and changes in our portfolio during the year. The decrease in average VAR for June 30, 2012, compared with June 30, 2011, was due primarily to a decrease in total transportation capacity over the five-year period that VAR is calculated.

To the extent open commodity positions exist, fluctuating commodity prices can impact our financial results and financial position either favorably or unfavorably. As a result, we cannot predict with precision the impact risk-management decisions may have on our business, operating results or financial position.

INTEREST-RATE RISK

We are subject to the risk of interest-rate fluctuation in the normal course of business. We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps. At June 30, 2012, the interest rate on all of ONEOK’s and ONEOK Partners’ long-term debt was fixed.

ONEOK and ONEOK Partners each entered into forward-starting interest-rate swaps to hedge the variability of interest payments on a portion of forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. ONEOK had interest-rate swaps with notional values totaling $500 million at December 31, 2011. In January 2012, ONEOK entered into additional interest-rate swaps with notional amounts totaling $200 million. Upon issuance in January 2012 of our $700 million, 4.25-percent senior notes due 2022, ONEOK settled all $700 million of its interest-rate swaps and realized a loss of $44.1 million in accumulated other comprehensive income that will be amortized to interest expense over the term of the hedged debt. At June 30, 2012, and December 31, 2011, ONEOK Partners had forward-starting interest-rate swaps with notional amounts totaling $1 billion and $750 million, respectively. In July 2012, ONEOK Partners entered into additional forward-starting interest-rate swaps with settlement dates greater than 12 months with notional amounts totaling $400 million.

ITEM 4. CONTROLS AND PROCEDURES

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

Changes in Internal Control Over Financial Reporting - There have been no changes in our internal control over financial reporting during the second quarter ended June 30, 2012, 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.

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

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

April 1-30, 2012	3,200	(a)	$8.44		-
May 1-31, 2012	-		-		-
June 1-30, 2012	3,642,061	(a) (b)	$8.44		3,641,661
Total	3,645,261		$8.44		3,641,661	$	300,000,000	(c)

(a) - Includes shares withheld pursuant to attestation of ownership and deemed tendered to us in connection with the exercise
of stock options under the ONEOK, Inc. Long-Term Incentive Plan.
(b) - Includes an estimated 3,641,661 shares based on the June 11, 2012, closing stock price of $41.19, to be purchased pursuant to
our $150 million accelerated share repurchase agreement discussed under "Liquidity and Capital Resources" in Item 2,
Management's Discussion and Analysis of Financial Condition and Results of Operations in this Quarterly Report. In June
2012, we received approximately 2.9 million shares, representing approximately 80 percent of the estimated total number of
shares to be repurchased. We expect to receive the balance of the shares at the termination of the agreement, which is
scheduled for September, although the termination may be accelerated.
(c) - The maximum approximate dollar value of shares that may yet be purchased pursuant to our approximately $750 million
stock repurchase program that was announced on October 21, 2010, subject to the limitations that purchases will not exceed
$300 million in any one calendar year and that a maximum of $150 million of additional shares of our common stock may be
purchased in 2012. The program will terminate upon the completion of the repurchase of $750 million of common stock or on
December 31, 2013, whichever occurs first.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not Applicable.

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.

ITEM 5. OTHER INFORMATION

Not Applicable.

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ITEM 6. EXHIBITS

Readers of this report should not rely on or assume the accuracy of any representation or warranty or the validity of any opinion contained in any agreement filed as an exhibit to this Quarterly Report, because such representation, warranty or opinion may be subject to exceptions and qualifications contained in separate disclosure schedules, may represent an allocation of risk between parties in the particular transaction, may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes, or may no longer continue to be true as of any given date. All exhibits attached to this Quarterly Report are included for the purpose of complying with requirements of the SEC. 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

3.1

Amendment dated May 23, 2012, to the ONEOK, Inc. Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to ONEOK, Inc.’s Current Report on Form 8-K filed on May 25, 2012).

10.1

Accelerated Share Repurchase Agreement dated June 11, 2012, by and between ONEOK, Inc. and Goldman Sachs & Co.

10.2

ONEOK, Inc. Employee Stock Purchase Plan as amended and restated effective as of May 23, 2012.

10.3

Extension Agreement dated August 1, 2012, among ONEOK Partners, L.P., as Borrower, each of the existing Lenders, and Citibank, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer (incorporated by reference to Exhibit 10.1 to ONEOK Partners, L.P.’s report on Form 10-Q filed on August 1, 2012, (File No. 1-12202)).

31.1

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

31.2

Certification of Robert F. Martinovich pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

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

32.2

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

101.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Extension Schema Document

101.CAL

XBRL Taxonomy Calculation Linkbase Document

101.DEF

XBRL Taxonomy Extension Definitions Document

101.LAB

XBRL Taxonomy Label Linkbase Document

101.PRE

XBRL Taxonomy Presentation Linkbase Document

Attached as Exhibit 101 to this Quarterly Report are the following XBRL-related documents: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three and six months ended June 30, 2012 and 2011; (iii) Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2012 and 2011; (iv) Consolidated Balance Sheets at June 30, 2012, and December 31, 2011; (v) Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011; (vi) Consolidated Statement of Changes in Equity for the six months ended June 30, 2012; and (vii) Notes to Consolidated Financial Statements.

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

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SIGNATURE

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

ONEOK, Inc.

Registrant

Date: August 1, 2012 By: /s/ Robert F. Martinovich

Robert F. Martinovich

Executive Vice President,

Chief Financial Officer and Treasurer

(Principal Financial Officer)