Edgar Filing: ONEOK INC /NEW/

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2007

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 checkmark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer X Accelerated filer Non-accelerated filer __

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

Yes No X

On April 30, 2007, the Company had 111,037,707 shares of common stock outstanding.

ONEOK, Inc.

QUARTERLY REPORT ON FORM 10-Q


Part I.	Financial Information	Page No.

Item 1.	Financial Statements (Unaudited)

	Consolidated Statements of Income - Three Months Ended March 31, 2007 and 2006	5

	Consolidated Balance Sheets - March 31, 2007 and December 31, 2006	6-7

	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2007 and 2006	9

	Consolidated Statements of Shareholders’ Equity and Comprehensive Income - Three Months Ended March 31, 2007	10-11

	Notes to Consolidated Financial Statements	12-23

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24-42

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42-45

Item 4.	Controls and Procedures	46

Part II.	Other Information

Item 1.	Legal Proceedings	46

Item 1A.	Risk Factors	46

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47

Item 3.	Defaults Upon Senior Securities	47

Item 4.	Submission of Matters to a Vote of Security Holders	47

Item 5.	Other Information	48

Item 6.	Exhibits	48

Signature		49

As used in this Quarterly Report on Form 10-Q, the terms “we,” “our” or “us” mean ONEOK, Inc., an Oklahoma corporation, and its predecessors and subsidiaries, unless the context indicates otherwise.

The statements in this Quarterly Report on Form 10-Q that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast” 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 our goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part II, Item 1A, “Risk Factors,” in this Quarterly Report on Form 10-Q and under Part I, Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2006.

Glossary

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


AFUDC		Allowance for funds used during construction
Bbl		Barrels, equivalent to 42 United States gallons
Bbl/d		Barrels per day
BBtu/d		Billion British thermal units per day
Bcf		Billion cubic feet
Bcf/d		Billion cubic feet per day
Btu		British thermal units
EITF		Emerging Issues Task Force
Exchange Act		Securities Exchange Act of 1934, as amended
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FIN		FASB Interpretations
Fort Union Gas Gathering		Fort Union Gas Gathering, L.L.C.
GAAP		United States Generally Accepted Accounting Principles
Guardian Pipeline		Guardian Pipeline, L.L.C.
KCC		Kansas Corporation Commission
KDHE		Kansas Department of Health and Environment
LDC		Local distribution company
LIBOR		London Interbank Offered Rate
MBbl/d		Thousand barrels per day
Mcf		Thousand cubic feet
Midwestern Gas Transmission		Midwestern Gas Transmission Company
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 Investor Service, Inc.
NGL		Natural gas liquids
Northern Border Pipeline		Northern Border Pipeline Company
NYMEX		New York Mercantile Exchange
NYSE		New York Stock Exchange
OBPI		ONEOK Bushton Processing Inc.
OCC		Oklahoma Corporation Commission
ONEOK		ONEOK, Inc.
ONEOK Partners		ONEOK Partners, L.P., formerly known as Northern Border Partners, L.P.
ONEOK Partners GP		ONEOK Partners GP, L.L.C., formerly known as Northern Plains Natural Gas Company, LLC, a ONEOK subsidiary
Overland Pass Pipeline Company		Overland Pass Pipeline Company LLC
S&P		Standard & Poor’s Rating Group
SEC		Securities and Exchange Commission
Statement		Statement of Financial Accounting Standards
TC PipeLines		TC PipeLines Intermediate Limited Partnership, a subsidiary of TC PipeLines, LP
TransCanada		TransCanada Corporation

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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended March 31,
(Unaudited)		2007		2006
		(Thousands of dollars, except per share amounts)

Revenues
Operating revenues, excluding energy trading revenues	$	3,797,658	$	3,840,334
Energy trading revenues, net		1,348		7,370
Total Revenues		3,799,006		3,847,704
Cost of sales and fuel		3,234,379		3,346,419
Net Margin		564,627		501,285
Operating Expenses
Operations and maintenance		158,420		157,506
Depreciation, depletion and amortization		56,450		56,325
General taxes		23,659		18,383
Total Operating Expenses		238,529		232,214
Gain on Sale of Assets		2,203		1,305
Operating Income		328,301		270,376
Equity earnings from investments (Note M)		24,055		31,641
Other income		6,341		4,480
Other expense		645		5,260
Interest expense		62,012		55,585
Income before Minority Interests and Income Taxes		296,040		245,652
Minority interests in income of consolidated subsidiaries		45,313		35,772
Income taxes		97,847		80,141
Income from Continuing Operations		152,880		129,739
Discontinued operations, net of taxes (Note C)
Income (loss) from operations of discontinued components, net of tax		-		(247	)
Net Income	$	152,880	$	129,492

Earnings Per Share of Common Stock (Note N)
Net earnings per share, basic	$	1.38	$	1.21
Net earnings per share, diluted	$	1.36	$	1.17

Average Shares of Common Stock (Thousands)
Basic		110,868		107,143
Diluted		112,724		110,756

Dividends Declared Per Share of Common Stock	$	0.34	$	0.28

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS


(Unaudited)		March 31, 2007		December 31, 2006
Assets		(Thousands of dollars)

Current Assets
Cash and cash equivalents	$	225,510	$	68,268
Short-term investments		538,030		31,125
Trade accounts and notes receivable, net		1,286,444		1,348,490
Gas and natural gas liquids in storage		499,058		925,194
Commodity exchanges		67,514		53,433
Energy marketing and risk management assets (Note D)		137,726		401,670
Other current assets		326,066		296,781
Total Current Assets		3,080,348		3,124,961

Property, Plant and Equipment
Property, plant and equipment		6,816,441		6,724,759
Accumulated depreciation, depletion and amortization		1,914,845		1,879,838
Net Property, Plant and Equipment (Note A)		4,901,596		4,844,921

Deferred Charges and Other Assets
Goodwill and intangible assets (Note E)		1,049,523		1,051,440
Energy marketing and risk management assets (Note D)		44,715		91,133
Investments in unconsolidated affiliates		746,383		748,879
Other assets		526,346		529,748
Total Deferred Charges and Other Assets		2,366,967		2,421,200
Total Assets	$	10,348,911	$	10,391,082

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS


(Unaudited)		March 31, 2007			December 31, 2006
Liabilities and Shareholders’ Equity		(Thousands of dollars)

Current Liabilities
Current maturities of long-term debt	$	420,466		$	18,159
Notes payable		-			6,000
Accounts payable		1,073,934			1,076,954
Commodity exchanges and imbalances		183,064			176,451
Energy marketing and risk management liabilities (Note D)		308,445			306,658
Other		357,923			366,316
Total Current Liabilities		2,343,832			1,950,538

Long-term Debt, excluding current maturities		3,627,043			4,030,855

Deferred Credits and Other Liabilities
Deferred income taxes		762,637			707,444
Energy marketing and risk management liabilities (Note D)		57,071			137,312
Other deferred credits		548,674			548,330
Total Deferred Credits and Other Liabilities		1,368,382			1,393,086

Commitments and Contingencies (Note J)

Minority Interests in Consolidated Subsidiaries		798,878			800,645

Shareholders’ Equity
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 120,637,951 shares and outstanding 110,982,237 shares at March 31, 2007; issued 120,333,908 shares and outstanding 110,678,499 shares at December 31, 2006		1,206			1,203
Paid in capital		1,263,112			1,258,717
Accumulated other comprehensive income (loss) (Note F)		(65,373	)		39,532
Retained earnings		1,371,948			1,256,759
Treasury stock, at cost: 9,655,714 shares at March 31, 2007 and 9,655,409 shares at December 31, 2006		(360,117	)		(340,253	)
Total Shareholders’ Equity		2,210,776			2,215,958


Total Liabilities and Shareholders’ Equity	$	10,348,911		$	10,391,082

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Three Months Ended March 31,
(Unaudited)		2007			2006
Operating Activities		(Thousands of dollars)
Net income	$	152,880		$	129,492
Depreciation, depletion, and amortization		56,450			56,325
Gain on sale of assets		(2,203	)		(1,305	)
Minority interests in income of consolidated subsidiaries		45,313			35,772
Distributions received from unconsolidated affiliates		26,455			40,708
Income from equity investments		(24,055	)		(31,641	)
Deferred income taxes		19,499			38,623
Stock-based compensation expense		8,212			1,510
Allowance for doubtful accounts		1,974			4,182
Changes in assets and liabilities (net of acquisition and disposition effects):
Accounts and notes receivable		60,072			669,231
Inventories		425,279			280,054
Unrecovered purchased gas costs		19,911			(27,081	)
Commodity exchanges and imbalances, net		(7,468	)		(16,554	)
Deposits		79,641			48,202
Regulatory assets		(8	)		7,632
Accounts payable and accrued liabilities		42,407			(364,945	)
Energy marketing and risk management assets and liabilities		61,128			(62,480	)
Other assets and liabilities		(91,272	)		(10,075	)
Cash Provided by Operating Activities		874,215			797,650
Investing Activities
Changes in investments in unconsolidated affiliates		(141	)		(5,711	)
Capital expenditures		(107,035	)		(54,552	)
Purchase of short-term investments		(506,905	)		-
Proceeds from sale of assets		3,707			-
Increase in cash and cash equivalents for previously unconsolidated subsidiaries		-			1,334
Decrease in cash and cash equivalents for previously consolidated subsidiaries		-			(22,039	)
Other investing activities		-			1,102
Cash Used in Investing Activities		(610,374	)		(79,866	)
Financing Activities
Borrowing (repayment) of notes payable, net		-			(135,500	)
Short-term financing payments		(6,000	)		(1,110,000	)
Short-term financing borrowings		-			237,000
Payment of debt		(520	)		(32,241	)
Equity unit conversion		-			402,447
Repurchase of common stock		(20,089	)		(1,408	)
Issuance of common stock		2,680			1,333
Dividends paid		(37,691	)		(27,344	)
Distributions to minority interests		(44,979	)		(35,711	)
Other financing activities		-			(44,895	)
Cash Used in Financing Activities		(106,599	)		(746,319	)
Change in Cash and Cash Equivalents		157,242			(28,535	)
Cash and Cash Equivalents at Beginning of Period		68,268			7,915
Effect of Accounting Change on Cash and Cash Equivalents		-			43,090
Cash and Cash Equivalents at End of Period	$	225,510		$	22,470

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME


(Unaudited)	Common Stock Issued		Common Stock		Paid in Capital			Accumulated Other Comprehensive Income (Loss)
	(Shares)				Thousands of dollars
December 31, 2006	120,333,908	$	1,203	$	1,258,717		$	39,532
Net income	-		-		-			-
Other comprehensive income (loss)	-		-		-			(104,905	)
Total comprehensive income
Repurchase of common stock (Note G)	-		-		-			-
Common stock issued pursuant to various plans	304,043		3		(3,592	)		-
Stock-based employee compensation expense	-		-		7,987			-
Common stock dividends - $0.34 per share	-		-		-			-
March 31, 2007	120,637,951	$	1,206	$	1,263,112		$	(65,373	)

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(Continued)


(Unaudited)	Retained Earnings	Treasury Stock	Total
	Thousands of dollars
December 31, 2006	$ 1,256,759	$ (340,253)	$ 2,215,958
Net income	152,880	-	152,880
Other comprehensive income (loss)	-	-	(104,905)

Total comprehensive income			47,975

Repurchase of common stock (Note G)	-	(20,089)	(20,089)
Common stock issued pursuant to various plans	-	-	(3,589)
Stock-based employee compensation expense	-	225	8,212
Common stock dividends - $0.34 per share	(37,691)	-	(37,691)
March 31, 2007	$ 1,371,948	$ (360,117)	$ 2,210,776

ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

A.	SUMMARY OF ACCOUNTING POLICIES

Our accompanying unaudited consolidated financial statements have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair presentation of the results for the interim periods presented. All such adjustments are of a normal recurring nature. Due to the seasonal nature of our business, the results of operations for the three months ended March 31, 2007, are not necessarily indicative of the results that may be expected for a 12-month period. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2006.

Our accounting policies are consistent with those disclosed in Note A of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2006, except as described below.

Significant Accounting Policies

Short-Term Investments - Our short-term investments consist of auction-rate securities, which are corporate or municipal bonds that have underlying long-term maturities. The interest rates are reset through auctions that are typically held every 7-35 days, at which time the securities can be sold. We invest in auction-rate securities for a portion of our short-term liquidity needs.

Property - The following table sets forth our property, by segment, for the periods presented.


	March 31, 2007		December 31, 2006
		(Thousands of dollars)
Non-Regulated
ONEOK Partners	$	1,917,775	$	1,894,529
Energy Services		7,688		7,689
Other		168,623		166,430
Regulated
ONEOK Partners		1,582,450		1,529,923
Distribution		3,139,905		3,126,188
Property, plant and equipment		6,816,441		6,724,759
Accumulated depreciation, depletion and amortization		1,914,845		1,879,838
Net property, plant and equipment	$	4,901,596	$	4,844,921

Income Taxes - In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109,” which was effective for our year beginning January 1, 2007. This interpretation was issued to clarify the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 requires the recognition of penalties and interest on any unrecognized tax benefits. Our policy is to reflect penalties and interest as part of income tax expense as they become applicable. The adoption of FIN 48 had an immaterial impact on our consolidated financial statements.

We file numerous consolidated and separate income tax returns in the United States federal jurisdiction and in many state jurisdictions. We also file returns in Canada. No returns are currently under audit and no extensions of statute of limitations have been granted.

Other

Pension and Postretirement Employee Benefits - In September 2006, the FASB issued Statement 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” which required us to record a balance sheet liability equal to the difference between our benefit obligations and plan assets. Statement 158 was effective for our year ending December 31, 2006, except for the measurement date change from September 30 to December 31, which will be effective for our year ending December 31, 2007.

Fair Value Measurements - In September 2006, the FASB issued Statement 157, “Fair Value Measurements,” which establishes a framework for measuring fair value and requires additional disclosures about fair value measurements. Statement 157 is effective for our year beginning January 1, 2008. We are currently reviewing the applicability of Statement 157 to our operations and its potential impact on our consolidated financial statements.

In February 2007, the FASB issued Statement 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which allows companies to elect to measure specified financial assets and liabilities, firm commitments, and nonfinancial warranty and insurance contracts at fair value on a contract-by-contract basis, with changes in fair value recognized in earnings each reporting period. Statement 159 is effective for our year beginning January 1, 2008. We are currently reviewing the applicability of Statement 159 to our operations and its potential impact on our consolidated financial statements.

Reclassifications - Our ONEOK Partners’ segment deconsolidated Northern Border Pipeline and consolidated Guardian Pipeline retroactive to January 1, 2006, as a result of the April 2006 transactions. Our consolidated financial statements for the quarter ended March 31, 2006, have been restated on a retroactive basis to reflect the accounting impact of these transactions. See Note B for additional information.

Certain other amounts in our consolidated financial statements have been reclassified to conform to the 2007 presentation. These reclassifications did not impact previously reported net income or shareholders’ equity.

B.	ACQUISITIONS AND DIVESTITURES

Overland Pass Pipeline Company - In May 2006, a subsidiary of ONEOK Partners entered into an agreement with a subsidiary of The Williams Companies, Inc. (Williams) to form a joint venture called Overland Pass Pipeline Company for the purpose of building a 750-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas. The pipeline will be designed to transport approximately 110,000 Bbl/d of NGLs, which can be increased to approximately 150,000 Bbl/d with additional pump facilities. A subsidiary of ONEOK Partners owns 99 percent of the joint venture and will manage the construction project, advance all costs associated with construction and operate the pipeline. Within two years of the pipeline becoming operational, Williams will have the option to increase its ownership up to 50 percent by reimbursing ONEOK Partners for its proportionate share of all construction costs. If Williams exercises its option to increase its ownership to the full 50 percent, Williams would have the option to become operator. This project requires the approval of various state and federal regulatory authorities. Assuming Overland Pass Pipeline Company obtains the required regulatory approvals, ONEOK Partners currently expects construction of the pipeline to begin in the fall of 2007, with start-up scheduled for early 2008.

As part of a long-term agreement, Williams dedicated its NGL production from two of its gas processing plants in Wyoming to the joint-venture company. Subsidiaries of ONEOK Partners will provide downstream fractionation, storage and transportation services to Williams. The pipeline project is currently estimated to cost approximately $433 million, excluding AFUDC. During 2006, ONEOK Partners paid $11.6 million to Williams for acquisition of its interest in the joint venture and for reimbursement of initial capital expenditures. In addition, ONEOK Partners plans to invest approximately $216 million, excluding AFUDC, to expand its existing fractionation capabilities and the capacity of its natural gas liquids distribution pipelines. ONEOK Partners’ financing for the projects may include a combination of short- or long-term debt or equity.

ONEOK Partners - In April 2006, we sold certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. We also purchased, through ONEOK Partners GP, from an affiliate of TransCanada, 17.5 percent of the general partner interest in ONEOK Partners for $40 million. This purchase resulted in our owning the entire 2 percent general partner interest in ONEOK Partners. Following the completion of the transactions, we own approximately 37.0 million common and Class B limited partner units and the entire 2 percent general partner interest and control the partnership. Our overall interest in ONEOK Partners, including the 2 percent general partner interest, has increased to 45.7 percent.

Disposition of 20 Percent Interest in Northern Border Pipeline - In April 2006, in connection with the transactions described immediately above, our ONEOK Partners segment completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million. Our ONEOK Partners segment recorded a gain on sale of approximately $113.9 million in the second quarter of 2006. ONEOK Partners and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, and an affiliate of TransCanada became operator of the pipeline in April 2007. Under Statement 94, “Consolidation of All Majority Owned Subsidiaries,” a majority-owned subsidiary is not consolidated if control is likely to be temporary or if it does not rest with the majority owner. Neither ONEOK Partners nor TC PipeLines has control of Northern Border Pipeline, as control is shared equally through Northern Border Pipeline’s Management Committee. As a result of this transaction, ONEOK Partners’ interest in Northern Border Pipeline is accounted for as an investment under the equity method, applied on a retroactive basis to January 1, 2006. TransCanada paid us $10 million for expenses associated with the transfer of operating responsibility of Northern Border Pipeline to them.

Acquisition of Guardian Pipeline Interests - In April 2006, our ONEOK Partners segment acquired the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners for approximately $77 million, increasing its ownership interest to 100 percent. ONEOK Partners used borrowings from its credit facility to fund the acquisition of the additional interest in Guardian Pipeline. Following the completion of the transaction, we included Guardian Pipeline in our consolidated financial statements. This change was accounted for on a retroactive basis to January 1, 2006.

C.	DISCONTINUED OPERATIONS

In the third quarter of 2005, we made the decision to sell our Spring Creek power plant, located in Oklahoma, and exit the power generation business. We entered into an agreement to sell our Spring Creek power plant to Westar Energy, Inc. for approximately $53 million. The transaction received FERC approval, and the sale was completed on October 31, 2006. The 300-megawatt gas-fired merchant power plant was built in 2001 to supply electrical power during peak periods using gas-powered turbine generators.

This component of our business is accounted for as discontinued operations in accordance with Statement 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Accordingly, amounts in our consolidated financial statements and related notes for the three months ended March 31, 2006, relating to our power generation business are reflected as discontinued operations.

D.	ENERGY MARKETING AND RISK MANAGEMENT ACTIVITIES

Accounting Treatment - We account for derivative instruments and hedging activities in accordance with Statement 133, “Accounting for Derivative Instruments and Hedging Activities.” Under Statement 133, entities are required to record all derivative instruments at fair value. 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 the derivative instrument does not qualify or is not designated as part of a hedging relationship, we account for changes in fair value of the derivative instrument in earnings as they occur. We record changes in the fair value of derivative instruments that are considered “held for trading purposes” as energy trading revenues, net and derivative instruments considered not “held for trading purposes” as cost of sales and fuel in our Consolidated Statements of Income. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposure to changes in fair values, cash flows or foreign currencies. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings during the period of change together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. The difference between the change in fair value of the derivative instrument and the change in fair value of the hedged item represents hedge ineffectiveness, which is reported in earnings during the period the ineffectiveness occurs. For hedges of exposure to changes in cash flow, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated other comprehensive income (loss) and is subsequently recorded in earnings when the forecasted transaction affects earnings.

As required by Statement 133, we formally document all relationships between hedging instruments and hedged items, as well as risk management objectives, strategies for undertaking various hedge transactions and methods for assessing and testing correlation and hedge ineffectiveness. We specifically identify the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item. We assess the effectiveness of hedging relationships, both at the inception of the hedge and on an ongoing basis.

Refer to Note D of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2006, for additional discussion.

Fair Value Hedges - In prior years, we and ONEOK Partners terminated various interest rate swap agreements. The net savings from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged. Net interest expense savings for the three months ended March 31, 2007, for all terminated swaps was $2.6 million, and the remaining net savings for all terminated swaps will be recognized over the following periods.


		ONEOK		ONEOK Partners		Total
		(Millions of dollars)
Remainder of 2007	$	5.0	$	2.7	$	7.7
2008		6.6		3.7		10.3
2009		5.5		3.7		9.2
2010		5.4		3.7		9.1
2011		2.5		0.9		3.4
Thereafter		12.8		-		12.8

Currently, the interest on $490 million of fixed-rate debt is swapped to floating using interest rate swaps. The floating-rate is based on both the three- and six-month LIBOR, depending upon the swap. Based on the actual performance through March 31, 2007, the weighted average interest rate increased from 6.64 percent to 6.79 percent. At March 31, 2007, we recorded a net liability of $11.9 million to recognize the interest rate swaps at fair value. Long-term debt was decreased by $11.9 million to recognize the change in the fair value of the related hedged liability.

Our Energy Services segment uses basis swaps to hedge the fair value of certain firm transportation commitments. Net gains or losses from the fair value hedges are recorded to cost of sales and fuel. The ineffectiveness related to these hedges were losses of $2.5 million and $5.3 million for the three months ended March 31, 2007 and 2006, respectively, which were recorded as cost of sales and fuel.

Cash Flow Hedges - Our Energy Services segment uses futures and swaps to hedge the cash flows associated with our anticipated purchases and sales of natural gas and cost of fuel used in transportation of natural gas. Accumulated other comprehensive income (loss) at March 31, 2007, includes losses of approximately $8.3 million, net of tax, related to these hedges that will be realized within the next 26 months. If prices remain at current levels, we will recognize $9.0 million in net losses over the next 12 months, and we will recognize net gains of $0.7 million thereafter. In accordance with Statement 133, the actual losses that are reclassified into earnings will be based on the referenced floating price at each designated pricing period, along with the realization of the gains or losses on the related physical volumes, which are not reflected in the amounts above.

Our ONEOK Partners segment periodically enters into derivative instruments to hedge the cash flows associated with its exposure to changes in the price of natural gas, NGLs and condensate. If prices remain at current levels, our ONEOK Partners segment will recognize $2.6 million in net losses, all of which will be recognized over the next 12 months.

For all of our segments, net gains and losses are reclassified out of accumulated other comprehensive income (loss) to operating revenues or cost of sales and fuel in the period the ineffectiveness occurs. Ineffectiveness related to our cash flow hedges resulted in a loss of approximately $0.2 million and a gain of approximately $7.2 million for the three months ended March 31, 2007 and 2006, respectively. There were no material gains or losses during the three months ended March 31, 2007 and 2006, due to the discontinuance of cash flow hedge treatment.

E.	GOODWILL AND INTANGIBLE ASSETS

Goodwill

Carrying Amounts - The amount of goodwill recorded on our Consolidated Balance Sheets as of March 31, 2007, and December 31, 2006, was $600.7 million.

Equity Method Goodwill - For the investments we account for under the equity method, the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill. Investment in unconsolidated affiliates on our accompanying Consolidated Balance Sheets includes equity method goodwill of $185.6 million as of March 31, 2007, and December 31, 2006.

Intangible Assets

Our ONEOK Partners segment had $293.2 million of intangible assets related to contracts acquired through our acquisition of the natural gas liquids businesses from Koch, which are being amortized over an aggregate weighted-average period of 40 years. The remaining intangible asset balance has an indefinite life. The aggregate amortization expense for each of the next five years is estimated to be approximately $7.7 million. Amortization expense for intangible assets for the three months ended March 31, 2007 and 2006 was $1.9 million. The following table reflects the gross carrying amount and accumulated amortization of intangible assets at March 31, 2007 and December 31, 2006.


		Gross Intangible Assets		Accumulated Amortization			Net Intangible Assets
		(Thousands of dollars)
March 31, 2007	$	462,214	$	(13,416	)	$	448,798
December 31, 2006	$	462,214	$	(11,499	)	$	450,715

F.	COMPREHENSIVE INCOME

The tables below show the gross amount of comprehensive income (loss) and related tax (expense) benefit for the periods indicated.


	Three Months Ended March 31, 2007						Three Months Ended March 31, 2006
		Gross		Tax (Expense) Benefit		Net		Gross		Tax Expense		Net
		(Thousands of dollars)
Unrealized gains (losses) on energy marketing and risk management assets/liabilities	$	(67,265)	$	25,335	$	(41,930)	$	80,835	$	(31,267)	$	49,568
Unrealized holding gains arising during the period		2,124		(822)		1,302		-		-		-
Realized (gains) losses recognized in net income		(103,036)		39,854		(63,182)		11,282		(4,364)		6,918
Pension and postretirement benefit plan amortization		(1,786)		691		(1,095)		-		-		-
Other comprehensive income (loss)	$	(169,963)	$	65,058	$	(104,905)	$	92,117	$	(35,631)	$	56,486

The table below shows the balance in accumulated other comprehensive income (loss) for the periods indicated.


		Unrealized Gains (Losses) on Energy Marketing and Risk Management Assets/Liabilities		Unrealized Gains on Available-for- Sale Securities		Pension and Postretirement Benefit Plan Obligations		Accumulated Other Comprehensive Income (Loss)
		(Thousands of dollars)
December 31, 2006	$	89,971	$	12,614	$	(63,053)	$	39,532
Other comprehensive income (loss)		(105,112)		1,302		(1,095)		(104,905)
March 31, 2007	$	(15,141)	$	13,916	$	(64,148)	$	(65,373)

G.	CAPITAL STOCK

shares subsequently repurchased by UBS over the course of the repurchase period. The price adjustment could have been settled, at our option, in cash or in shares of our common stock. In accordance with EITF Issue No. 99-7, “Accounting for an Accelerated Share Repurchase Program,” the repurchase was accounted for as two separate transactions: (1) as shares of common stock acquired in a treasury stock transaction recorded on the acquisition date and (2) as a forward contract indexed to our common stock. Additionally, we classified the forward contract as equity under EITF Issue No. 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock.” In February 2007, the forward purchase contract settled for a cash payment of $20.1 million, which was recorded in equity. We currently have no remaining shares authorized for repurchase under our stock repurchase plan.

Dividends - Quarterly dividends paid on our common stock for shareholders of record as of the close of business on January 31, 2007, were $0.34 per share. Additionally, a quarterly dividend of $0.34 per share was declared in April, payable in the second quarter of 2007.

H.	CREDIT FACILITIES

General - On March 30, 2007, ONEOK Partners entered into an amended and restated five-year revolving credit facility agreement (2007 Partnership Credit Agreement), with several banks and other financial institutions and lenders, which amended and restated ONEOK Partners’ $750 million five-year credit agreement, in the following principal ways: (i) revised the pricing, (ii) extended the maturity by one year to March 2012, (iii) eliminated the interest coverage ratio covenant, (iv) increased the permitted ratio of indebtedness to EBITDA to 5 to 1 (from 4.75 to 1), (v) increased the swingline sub-facility commitments from $15 million to $50 million and (vi) changed the permitted amount of subsidiary indebtedness from $35 million to 10 percent of ONEOK Partners’ consolidated indebtedness.

Except as discussed above, our $1.2 billion five-year credit agreement, as amended and restated in 2006, and ONEOK Partners’ 2007 Partnership Credit Agreement contain typical covenants as discussed in Note H of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2006. At March 31, 2007, we and ONEOK Partners were in compliance with all covenants.

At March 31, 2007, we had $37.9 million in letters of credit issued and no borrowings outstanding under our various credit agreements, and ONEOK Partners had $10 million in letters of credit issued, and no borrowings outstanding under its 2007 Partnership Credit Agreement.

I.	EMPLOYEE BENEFIT PLANS

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


	Pension Benefits Three Months Ended March 31,						Postretirement Benefits Three Months Ended March 31,
		2007			2006			2007			2006
Components of Net Periodic Benefit Cost		(Thousands of dollars)
Service cost	$	5,262		$	5,267		$	1,598		$	1,583
Interest cost		12,152			10,871			3,957			3,539
Expected return on assets		(14,538	)		(14,396	)		(1,597	)		(1,141	)
Amortization of unrecognized net asset at adoption		-			-			797			797
Amortization of unrecognized prior service cost		371			378			(569	)		(571	)
Amortization of net loss		4,035			3,353			2,482			2,271
Net periodic benefit cost	$	7,282		$	5,473		$	6,668		$	6,478

Contributions - For the three months ended March 31, 2007, contributions of $0.6 million were made to our pension plan. Additionally, we made benefit payments for our postretirement benefit plan of $4.3 million in the three months ended March 31, 2007. We presently anticipate our total 2007 contributions to fund future benefits will be $4.2 million for the pension plan and $5.5 million for the other postretirement benefit plan. Additionally, the 2007 expected benefit payments from our postretirement benefit plan are estimated to be $22.1 million.

J.	COMMITMENTS AND CONTINGENCIES

Environmental Liabilities - We are subject to multiple environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid wastes and hazardous material and substance management. These laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. If an accidental leak or spill of hazardous materials occurs from our lines or facilities, in the process of transporting natural gas or NGLs, or at any facility that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including investigation and clean-up costs, which could materially affect our results of operations and cash flows. In addition, emission controls required under the federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial condition and results of operations.

We own or retain legal responsibility for the environmental conditions at 12 former manufactured gas sites in Kansas that we acquired in November 1997. These sites contain potentially harmful materials that are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE presently governs all work at these sites. The terms of the consent agreement allow us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater. We have commenced remediation on 11 sites, with regulatory closure achieved at two of these locations. Of the remaining nine sites, we have completed or are near completion of soil remediation at six sites, have commenced soil remediation at an additional site, and we expect to commence soil remediation on the other two sites in 2007. We have begun site assessment at the remaining site where no active remediation has occurred.

To date, we have incurred remediation costs of $6.6 million and have accrued an additional $5.4 million related to the sites where we have commenced or will soon commence remediation. The $5.4 million estimate of future remediation costs for these sites is based on our environmental assessments and remediation plans approved to date by the KDHE. These estimates are recorded on an undiscounted basis. For the site that is currently in the assessment phase, we have completed some analysis, but are unable at this point to accurately estimate aggregate costs that may be required to satisfy our remedial obligations at this site. Until the site assessment is complete and the KDHE approves the remediation plan, we will not have complete information available to us to accurately estimate remediation costs.

The costs associated with these sites do not include other potential expenses that might be incurred, such as unasserted property damage claims, personal injury or natural resource claims, unbudgeted legal expenses or other costs for which we may be held liable but with respect to which we cannot reasonably estimate an amount. As of this date, we have no knowledge of any of these types of claims. The foregoing estimates do not consider potential insurance recoveries, recoveries through rates or recoveries from unaffiliated parties, to which we may be entitled. We have filed claims with our insurance carriers relating to these sites, and we have recovered a portion of our costs incurred to date. We have not recorded any amounts for potential insurance recoveries or recoveries from unaffiliated parties, and we are not recovering any environmental amounts in rates. As more information related to the site investigations and remediation activities becomes available, and to the extent such amounts are expected to exceed our current estimates, additional expenses could be recorded. Such amounts could be material to our results of operations and cash flows depending on the remediation and number of years over which the remediation is required to be completed.

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

K.	SEGMENTS

Segment Descriptions - We have divided our operations into four reportable segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. These segments are as follows: (1) our ONEOK Partners segment gathers, processes, transports and stores natural gas; gathers, treats, stores, and fractionates NGLs; and provides NGL gathering and distribution services; (2) our Distribution segment delivers natural gas to residential, commercial and industrial customers, and transports natural gas; (3) our Energy Services segment markets natural gas to wholesale and retail customers; and (4) our Other segment primarily consists of the operating and leasing operations of our headquarters building and a related parking facility. Our Distribution segment is comprised of regulated public utilities, and portions of our ONEOK Partners segment are regulated.

Accounting Policies - The accounting policies of the segments are the same as those described in Note A and Note M of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2006. Intersegment gross sales are recorded on the same basis as sales to unaffiliated customers. Corporate overhead costs relating to a reportable segment have been allocated for the purpose of calculating operating income. Our equity method investments do not represent operating segments.

Customers - We had no single external customer from which we received 10 percent or more of our consolidated gross revenues.

Operating Segment Information - The following tables set forth certain operating segment financial data for the periods indicated.

Three Months Ended

March 31, 2007

ONEOK
Partners (a)

Distribution (b)

Energy
Services

Other and
Eliminations

Total

(Thousands of dollars)

Sales to unaffiliated customers

1,005,136

881,022

1,910,547

953

3,797,658

Energy trading revenues, net

1,348

Intersegment sales

156,336

199,811

(356,147

)

Total revenues

1,161,472

881,022

2,111,706

(355,194

)

3,799,006

Net margin

205,147

227,228

131,404

848

564,627

Operating costs

75,461

95,715

10,729

174

182,079

Depreciation, depletion and amortization

27,513

28,275

538

124

56,450

Gain on sale of assets

2,203

Operating income

104,376

103,238

120,137

550

328,301

Equity earnings from investments

24,055

Total assets

5,017,998

2,787,508

1,794,254

749,151

10,348,911

Capital expenditures

77,857

27,037

2,141

107,035

(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment's regulated operations had revenues of $76.2 million, net margin of $66.6 million and operating income of $34.0 million for the three months ended March 31, 2007.

(b) - All of our Distribution segment's operations are regulated.


Three Months Ended March 31, 2006		ONEOK Partners (a)		Distribution (b)		Energy Services		Other and Eliminations			Total
		(Thousands of dollars)

Sales to unaffiliated customers	$	1,018,903	$	787,243	$	2,063,482	$	(29,294	)	$	3,840,334
Energy trading revenues, net		-		-		7,370		-			7,370
Intersegment sales		150,927		-		244,363		(395,290	)		-
Total revenues	$	1,169,830	$	787,243	$	2,315,215	$	(424,584	)	$	3,847,704

Net margin	$	201,695	$	195,441	$	103,154	$	995		$	501,285
Operating costs		75,356		90,514		9,294		725			175,889
Depreciation, depletion and amortization		27,470		28,152		575		128			56,325
Gain on sale of assets		1,305		-		-		-			1,305
Operating income	$	100,174	$	76,775	$	93,285	$	142		$	270,376

Equity earnings from investments	$	31,641	$	-	$	-	$	-		$	31,641
Total assets	$	4,926,456	$	2,740,835	$	2,352,116	$	100,015		$	10,119,422
Capital expenditures	$	17,657	$	36,675	$	-	$	220		$	54,552
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $76.8 million, net margin of $66.5 million and operating income of $34.2 million for the three months ended March 31, 2006.
(b) - All of our Distribution segment’s operations are regulated.

L.	SUPPLEMENTAL CASH FLOW INFORMATION

The following table sets forth supplemental information with respect to our cash flow for the periods indicated.


	Three Months Ended March 31,
		2007			2006
		(Thousands of dollars)
Cash paid (received) during the period
Interest	$	21,269		$	42,829
Income taxes	$	(46,538	)	$	123,877

M.	UNCONSOLIDATED AFFILIATES

Equity Earnings from Investments - The following table sets forth our equity earnings from investments for the periods indicated. All 2007 and 2006 amounts in the table below are equity earnings from investments in our ONEOK Partners segment.


	Three Months Ended March 31,
		2007		2006
		(Thousands of dollars)
Northern Border Pipeline	$	18,040	$	26,147
Bighorn Gas Gathering, L.L.C.		1,691		2,033
Fort Union Gas Gathering		2,587		1,948
Lost Creek Gathering Company, L.L.C.		1,329		1,441
Other		408		72
Equity earnings from investments	$	24,055	$	31,641

Unconsolidated Affiliates Financial Information - Summarized combined financial information of our unconsolidated affiliates is presented below.


	Three Months Ended March 31,
		2007		2006
	(Thousands of dollars)
Income Statement
Operating revenue	$	98,713	$	97,886
Operating expenses		38,357		36,601
Net income		49,157		50,141

Distributions paid to ONEOK Partners	$	26,455	$	40,708

N.	EARNINGS PER SHARE INFORMATION

We compute earnings per common share (EPS) as described in Note R of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2006.

The following tables set forth the computations of the basic and diluted EPS for the periods indicated.


	Three Months Ended March 31, 2007
		Income	Shares		Per Share Amount
Basic EPS from continuing operations		(Thousands, except per share amounts)
Income from continuing operations available for common stock	$	152,880	110,868	$	1.38
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-	1,856
Income from continuing operations available for common stock and common stock equivalents	$	152,880	112,724	$	1.36


	Three Months Ended March 31, 2006
		Income	Shares		Per Share Amount
Basic EPS from continuing operations		(Thousands, except per share amounts)
Income from continuing operations available for common stock	$	129,739	107,143	$	1.21
Diluted EPS from continuing operations
Effect of dilutive securities:
Mandatory convertible units		-	2,518
Options and other dilutive securities		-	1,095
Income from continuing operations available for common stock and common stock equivalents	$	129,739	110,756	$	1.17

There were 18,403 and 438,924 option shares excluded from the calculation of diluted EPS for the three months ended March 31, 2007, and 2006, respectively, since their inclusion would have been antidilutive for each period.

O.	ONEOK PARTNERS

General Partner Interest - See Note B for discussion of the April 2006 acquisition of the additional general partner interest in ONEOK Partners. The limited partner units we received from ONEOK Partners were newly created Class B limited partner units. As of April 7, 2007, the Class B limited partner units are no longer subordinated to distributions on our common units, and generally have the same voting rights as our common units. Under the ONEOK Partners’ partnership agreement and in conjunction with the issuance of additional common units by ONEOK Partners, we, as the general partner, are required to make equity contributions in order to maintain our representative general partner interest.

Our investment in ONEOK Partners is shown in the table below for the periods presented.


	March 31,
	2007		2006
General partner interest	2.00	%	1.650	%
Limited partner interest	43.70	% (a)	1.050	% (b)
Total ownership interest	45.70	%	2.700	%

(a) - Represents approximately 0.5 million common units and 36.5 million Class B units. (b) - Represents approximately 0.5 million common units.

Cash Distributions - Under the ONEOK Partners’ partnership agreement, distributions are made to the partners with respect to each calendar quarter in an amount equal to 100 percent of available cash. Available cash generally consists of all cash receipts adjusted for cash disbursements and net changes to cash reserves. Available cash will generally be distributed 98 percent to limited partners and 2 percent to the general partner. As an incentive, the general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met. Under the incentive distribution provisions, the general partner receives:

•

15 percent of amounts distributed in excess of $0.605 per unit,

•

25 percent of amounts distributed in excess of $0.715 per unit, and

•

50 percent of amounts distributed in excess of $0.935 per unit.

ONEOK Partners’ income is allocated to the general and limited partners in accordance with their respective partnership ownership percentages, after giving effect to any priority income allocations for incentive distributions that are allocated to the general partner. The following table shows ONEOK Partners’ general partner and incentive distributions related to the periods indicated.


	Three Months Ended March 31,
		2007		2006
		(Thousands of dollars)
General partner distributions	$	1,907	$	740
Incentive distributions		11,364		2,581
Total distributions from ONEOK Partners to us	$	13,271	$	3,321

The quarterly distributions paid by ONEOK Partners to limited partners in the first quarters of March 31, 2007 and 2006 were $0.98 per unit and $0.80 per unit, respectively.

In April 2007, ONEOK Partners declared a cash distribution of $0.99 per unit payable in the second quarter.

Relationship - We own 45.7 percent of ONEOK Partners and consolidate ONEOK Partners in our consolidated financial statements; however, we are restricted from the assets and cash flows of ONEOK Partners except for our quarterly distributions. Distributions are declared quarterly by ONEOK Partners based on the terms of its partnership agreement, and for the three months ended March 31, 2007 and 2006, cash distributions declared from ONEOK Partners to us totaled $49.9 million and $3.8 million, respectively. See Note K for more information on ONEOK Partners’ results.

Affiliate Transactions - We have certain transactions with our 45.7 percent owned ONEOK Partners affiliate and its subsidiaries, which comprise our ONEOK Partners segment.

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

As part of the transaction between us and ONEOK Partners, ONEOK Partners acquired certain contractual rights to the Bushton Gas Processing Plant (the Bushton Plant) from us through a Processing and Services Agreement, which sets out the terms for processing and related services we provide at the Bushton Plant through 2012. In exchange, ONEOK Partners pays us for all direct costs and expenses of the Bushton Plant, including reimbursement of a portion of our obligations under equipment leases covering the Bushton Plant. Volumes available for processing at this straddle plant have declined due to contract terminations and natural field declines, which made it more efficient to process the remaining gas at other facilities. As a result, on January 1, 2007, the Bushton Plant was temporarily idled. ONEOK Partners has contracted for all of the capacity of the Bushton Plant from OBPI. ONEOK Partners is in the process of adding new facilities as part of its construction projects and associated expansions.

We provide a variety of services to our affiliates, including cash management and financing services, employee benefits provided through our benefit plans, administrative services provided by our employees and management, insurance and office space leased in our headquarters building and other field locations. Where costs are specifically incurred on behalf of an affiliate, the costs are billed directly to the affiliate by us. In other situations, the costs are allocated to the affiliates through a variety of methods, depending upon the nature of the expenses and the activities of the affiliates. For example, a service that applies equally to all employees is allocated based upon the number of employees in each affiliate. However, an expense benefiting the consolidated company but having no direct basis for allocation is allocated by the modified Distrigas method, a method using a combination of ratios that include gross plant and investment, operating income and wages.

The following table shows transactions with ONEOK Partners for the periods shown.


	Three Months Ended March 31,
		2007		2006
		(Thousands of dollars)
Revenue	$	156,336	$	150,927


Expense
Administrative and general expenses	$	39,803	$	29,853
Interest expense		-		21,281
Total expense	$	39,803	$	51,134

ITEM 2.

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

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

EXECUTIVE SUMMARY

The following discussion highlights some of our achievements and significant issues affecting us this past quarter. Please refer to the Financial and Operating Results section of Management’s Discussion and Analysis of Financial Condition and Results of Operation and the Financial Statements for a complete explanation of the following items. As a result of the April 2006 transactions, our ONEOK Partners’ segment deconsolidated Northern Border Pipeline and consolidated Guardian Pipeline retroactive to January 1, 2006. Our consolidated financial statements for the quarter ended March 31, 2006, have been restated on a retroactive basis to reflect the accounting impact of these transactions.

Diluted earnings per share of common stock from continuing operations (EPS) increased to $1.36 for the three months ended March 31, 2007, compared with $1.17 for the same period in 2006. During the first quarter of 2007, we increased our dividend to $0.34 per share of common stock ($1.36 per share on an annualized basis).

ONEOK Partners declared an increase in its cash distribution to $0.99 per unit ($3.96 per unit on an annualized basis) in April 2007, an increase of approximately 13 percent over the $0.88 paid in the second quarter of 2006.

Operating income for the first quarter of 2007 increased to $328.3 million from $270.4 million for the same period in 2006, a 21 percent increase. Our Distribution segment’s operating income increased $26.5 million for the three-month period, primarily due to the implementation of new rate schedules in Kansas and Texas. Operating income for our Energy Services segment increased $26.9 million for the three-month period, primarily due to increased storage and marketing margins, partially offset by decreased transportation, financial trading and retail margins. Our ONEOK Partners segment’s operating income increased $4.2 million for the three-month period, driven primarily by higher NGL related margins, resulting from higher product price spreads between Mont Belvieu, Texas, and Conway, Kansas; higher isomerization price spreads; wider price spreads between ethane and propane; and increased natural gasoline sales used in the production of ethanol fuel in our natural gas liquids business. These increases were partially offset by decreased operating income in our ONEOK Partners segment’s gathering and processing business, primarily due to lower realized commodity prices on our percent of proceeds (POP) contracts and lower volumes processed due to the anticipated contract terminations at certain processing facilities.

Our income from continuing operations increased to $152.9 million for the first quarter of 2007 from $129.7 million for same period in 2006.

SIGNIFICANT ACQUISITIONS AND DIVESTITURES

In April 2006, we sold certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. We also purchased, through ONEOK Partners GP, from an affiliate of TransCanada, 17.5 percent of the general partner interest in ONEOK Partners for $40 million. This purchase resulted in our owning the entire 2 percent general partner interest in ONEOK Partners. Following the completion of the transactions, we own approximately 37.0 million common and Class B limited partner units and the entire 2 percent general partner interest and control the partnership. Our overall interest in ONEOK Partners, including the 2 percent general partner interest, has increased to 45.7 percent.

In connection with the transactions described immediately above, our ONEOK Partners segment completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million. Our ONEOK Partners segment recorded a gain on sale of approximately $113.9 million in the second quarter of 2006. ONEOK Partners and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, and an affiliate of TransCanada became operator of the pipeline in April 2007. As a result of this transaction, ONEOK Partners’ interest in Northern Border Pipeline is accounted for as an investment under the equity method, applied on a retroactive basis to January 1, 2006. TransCanada paid us $10 million for expenses associated with the transfer of operating responsibility of Northern Border Pipeline to them.

Also in April 2006, our ONEOK Partners segment acquired the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners for approximately $77 million, increasing its ownership interest to 100 percent. ONEOK Partners used borrowings from its credit facility to fund the acquisition of the additional interest in Guardian Pipeline. Following the completion of the transaction, we consolidated Guardian Pipeline in our consolidated financial statements. This change was accounted for on a retroactive basis to January 1, 2006.

CAPITAL PROJECTS

Overland Pass Pipeline - In May 2006, a subsidiary of ONEOK Partners entered into an agreement with a subsidiary of The Williams Companies, Inc. (Williams) to form a joint venture called Overland Pass Pipeline Company for the purpose of building a 750-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas. The pipeline will be designed to transport approximately 110,000 Bbl/d of NGLs, which can be increased to approximately 150,000 Bbl/d with additional pump facilities. A subsidiary of ONEOK Partners owns 99 percent of the joint venture and will manage the construction project, advance all costs associated with construction and operate the pipeline. Within two years of the pipeline becoming operational, Williams will have the option to increase its ownership up to 50 percent by reimbursing ONEOK Partners for its proportionate share of all construction costs. If Williams exercises its option to increase its ownership to the full 50 percent, Williams would have the option to become operator. This project requires the approval of various state and federal regulatory authorities. Assuming Overland Pass Pipeline Company obtains the required regulatory approvals, ONEOK Partners currently expects construction of the pipeline to begin in the fall of 2007, with start-up scheduled for early 2008.

As part of a long-term agreement, Williams dedicated its NGL production from two of its gas processing plants in Wyoming to the joint-venture company. Subsidiaries of ONEOK Partners will provide downstream fractionation, storage and transportation services to Williams. The pipeline project is currently estimated to cost approximately $433 million excluding AFUDC. During 2006, ONEOK Partners paid $11.6 million to Williams for acquisition of its interest in the joint venture and for reimbursement of initial capital expenditures. In addition, ONEOK Partners plans to invest approximately $216 million, excluding AFUDC, to expand its existing fractionation capabilities and the capacity of its natural gas liquids distribution pipelines. ONEOK Partners’ financing for the projects may include a combination of short- or long-term debt or equity.

Piceance Lateral Pipeline - In March 2007, ONEOK Partners announced that Overland Pass Pipeline Company plans to construct a 150-mile lateral pipeline to transport as much as 100,000 Bbl/d of NGLs from the Piceance Basin in Colorado to the Overland Pass Pipeline. Williams announced that it intends to construct a new natural gas processing plant in the Piceance Basin and will dedicate its NGL production from that plant and an existing plant to be delivered into the lateral pipeline. This project requires the approval of various state and federal regulatory authorities. Assuming Overland Pass Pipeline Company obtains the required regulatory approvals, ONEOK Partners currently expect construction of this lateral pipeline extension to begin in the summer of 2008 and be completed in early 2009, at a current cost estimate of approximately $120 million, excluding AFUDC.

Arbuckle Pipeline Natural Gas Liquids Pipeline Project - In March 2007, ONEOK Partners announced plans to build the 440-mile Arbuckle Pipeline, a natural gas liquids pipeline from southern Oklahoma through northern Texas and continuing on to the Texas Gulf Coast, at a cost of $260 million, excluding AFUDC. The Arbuckle Pipeline will have the capacity to transport 160,000 Bbl/d of raw natural gas liquids and will interconnect with our existing Mid-Continent infrastructure and our fractionation facility in Mont Belvieu, Texas, and other Gulf Coast-area fractionators. The expansion project is expected to be complete by early 2009.

Williston Basin Gas Processing Plant Expansion - In March 2007, Bear Paw Energy, LLC, a subsidiary of ONEOK Partners, announced the expansion of our Grasslands natural gas processing facility in North Dakota at a cost of $30 million, excluding AFUDC. The Grasslands facility is our largest natural gas processing plant in the Williston Basin. The expansion will increase processing capacity to approximately 100 MMcf/d from its current capacity of 63 MMcf/d as well as increasing fractionation capacity to approximately 10,000 Bbl/d. The expansion project will come on line in phases starting in the summer of 2007 through the first quarter of 2008.

Fort Union Gas Gathering Expansion Project - In January 2007, Crestone Powder River, L.L.C., a subsidiary of ONEOK Partners, announced that Fort Union Gas Gathering will double its existing gathering pipeline capacity by adding 148 miles of new gathering lines resulting in 649 MMcf/d of additional capacity in the Powder River basin. The expansion is expected to cost approximately $110 million, excluding AFUDC, which will be project financed within the Fort Union Gas Gathering partnership and will occur in two phases, with 240 MMcf/d in service by the fourth quarter of 2007 and 409 MMcf/d by the

first quarter of 2008. The additional capacity has been fully subscribed for 10 years beginning with the in-service date of the expansion. Crestone Powder River, L.L.C. owns approximately 37 percent of Fort Union Gas Gathering.

Guardian Pipeline Expansion and Extension Project - In October 2006, Guardian Pipeline, a subsidiary of ONEOK Partners, filed its application for a certificate of public convenience and necessity with the FERC for authorization to construct and operate approximately 110 miles of new mainline pipe, two compressor stations, seven meter stations and other associated facilities. The pipeline expansion will extend Guardian Pipeline from the Milwaukee, Wisconsin, area to the Green Bay, Wisconsin, area. The project is supported by long-term shipper commitments. The cost of the project is estimated to be $250 million excluding AFUDC, with a targeted in-service date of November 2008.

Midwestern Gas Transmission Eastern Extension Project - In March 2006, Midwestern Gas Transmission, a subsidiary of ONEOK Partners, accepted the certificate of public convenience and necessity issued by the FERC for its Eastern Extension Project. An organization which is opposed to, and includes landowners affected by, the project filed a request for rehearing and for a stay of the March 2006 Order. In August 2006, the FERC denied those requests. The Eastern Extension Project will add 31 miles of pipeline with 120 MDth/d (approximately 120 MMcf/d) of transportation capacity with total capital expenditures estimated to be $41 million excluding AFUDC. The proposed in-service date is the fourth quarter of 2007.

REGULATORY

Several regulatory initiatives impacted the earnings and future earnings potential for our Distribution segment. See discussion of our Distribution segment’s regulatory initiatives on page 33.

IMPACT OF NEW ACCOUNTING STANDARDS

Pension and Postretirement Employee Benefits - In September 2006, the FASB issued Statement 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” which required us to record a balance sheet liability equal to the difference between our benefit obligations and plan assets. Statement 158 was effective for our year ending December 31, 2006, except for the measurement date change from September 30 to December 31 which will be effective for our year ending December 31, 2007.

Income Taxes - In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109,” which is effective for our year beginning January 1, 2007. This interpretation was issued to clarify the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 requires the recognition of penalties and interest on any unrecognized tax benefits. Our policy is to reflect penalties and interest as part of income tax expense as they become applicable. The adoption of FIN 48 had an immaterial impact on our consolidated financial statements.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty and that affect the reported amount of assets and

liabilities, and the disclosure of contingent assets and liabilities at the date of the 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.

Derivatives and Risk Management Activities - We engage in wholesale energy marketing, retail marketing, trading and risk management activities. We account for derivative instruments utilized in connection with these activities and services under the fair value basis of accounting in accordance with Statement 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended.

Under Statement 133, entities are required to record derivative instruments at fair value. The fair value of derivative instruments is determined by commodity exchange prices, over-the-counter quotes, volatility, time value, counterparty credit and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions. Refer to the table on page 44 for amounts in our portfolio at March 31, 2007, that were determined by prices actively quoted, prices provided by other external sources and prices derived from other sources. The majority of our portfolio’s fair values are based on actual market prices. Transactions are also executed in markets for which market prices may exist but the market may be relatively inactive, thereby resulting in limited price transparency that requires management’s subjectivity in estimating fair values.

Market value changes result in a change in the fair value of our derivative instruments. 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 the derivative instrument does not qualify or is not designated as part of a hedging relationship, then we account for changes in fair value of the derivative in earnings as they occur. Commodity price volatility may have a significant impact on the gain or loss in any given period. For more information on fair value sensitivity and a discussion of the market risk of pricing changes, see Item 3, Quantitative and Qualitative Disclosures about Market Risk.

To minimize the risk of fluctuations in natural gas, NGLs and condensate prices, we periodically enter into futures, options and swap transactions in order to hedge anticipated purchases and sales of natural gas, condensate, NGLs, fuel requirements and NGL inventories. Interest rate swaps are also used to manage interest rate risk. Under certain conditions, we designate these derivative instruments as a hedge of exposure to changes in fair values or cash flows. For hedges of exposure to changes in cash flow, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income (loss) and is subsequently recorded to earnings when the forecasted transaction affects earnings. Any ineffectiveness of designated hedges is reported in earnings in the period the ineffectiveness occurs. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings in the period of change together with the offsetting gain or loss on the hedged item attributable to the risk being hedged.

Many of our purchase and sale agreements that otherwise would be required to follow derivative accounting qualify as normal purchases and normal sales under Statement 133 and therefore, upon election, are exempt from fair value accounting treatment.

Impairment of Long-Lived Assets, Goodwill and Intangible Assets - We assess our long-lived assets for impairment based on Statement 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.

We assess our goodwill and non-amortizing intangible assets for impairment at least annually based on Statement 142, “Goodwill and Other Intangible Assets.” An initial assessment is made by comparing the fair value of the operations with goodwill, as determined in accordance with Statement 142, to the book value of each reporting unit. If the fair value is less than the book value, an impairment is indicated, and we must perform a second test to measure the amount of the impairment. In the second test, we would calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the operations with goodwill from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill, we would record an impairment charge. The amount of goodwill recorded on our Consolidated Balance Sheets as of March 31, 2007, and December 31, 2006, was $600.7 million.

Intangible assets with a finite useful life are amortized over their estimated useful life, while intangible assets with an indefinite useful life are not amortized. For intangible assets subject to amortization, we evaluate the remaining useful life of the assets annually to determine whether events and circumstances warrant a revision to the remaining period of amortization.

Our ONEOK Partners segment had $448.8 million of intangible assets recorded on our Consolidated Balance Sheet as of March 31, 2007, that consisted of $293.2 million which is being amortized over an aggregate weighted-average period of 40 years, while the remaining balance has an indefinite life.

Our total unamortized excess cost over underlying fair value of net assets accounted for under the equity method was $185.6 million as of March 31, 2007, and December 31, 2006. Based on Statement 142, this amount, referred to as equity method goodwill, should continue to be recognized in accordance with APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” Accordingly, we included this amount in investment in unconsolidated affiliates on our accompanying Consolidated Balance Sheets. Equity method goodwill is not subject to amortization but rather to impairment testing pursuant to APB No. 18. The impairment test under APB No. 18 considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. Therefore, we periodically reevaluate the amount at which we carry the excess of cost over fair value of net assets accounted for under the equity method to determine whether current events or circumstances warrant adjustments to our carrying value in accordance with APB Opinion No. 18.

We do not anticipate any goodwill or asset impairments to occur within the next year, but if such events were to occur over the long term, the impact could be significant to our financial condition and results of operations.

Pension and Postretirement Employee Benefits - We have defined benefit pension plans covering substantially all full-time employees. Nonbargaining unit employees hired after December 31, 2004, are not eligible for our defined benefit pension plan; however, they are covered by a profit sharing plan. We also have a postretirement employee benefits plan covering most employees who meet minimum age requirements for retirement with at least five years of service. Nonbargaining unit employees retiring between the ages of 50 and 55, all nonbargaining unit employees hired on or after January 1, 1999, employees who are members of the International Brotherhood of Electrical Workers hired after June 30, 2003, and gas union employees hired after July 1, 2004, who elect postretirement medical coverage, pay 100 percent of the retiree premium for participation in the plan. Additionally, any employees who came to us through various acquisitions may be further limited in their eligibility to participate or receive any contributions from us for postretirement medical benefits. Our actuarial consultant calculates the expense and liability related to these plans and uses statistical and other factors that attempt to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and employment periods. In determining the projected benefit obligations and costs, assumptions can change from period to period and result in material changes in the costs and liabilities we recognize. See Note J of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2006 for additional information.

During 2006, we recorded net periodic benefit costs of $21.6 million related to our defined benefit pension plans and $25.9 million related to postretirement benefits. We estimate that in 2007, we will record net periodic benefit costs of $29.1 million related to our defined benefit pension plan and $26.7 million related to postretirement benefits. In determining our estimated expenses for 2007, our actuarial consultant assumed an 8.75 percent expected return on plan assets and a discount rate of 6.00 percent. A decrease in our expected return on plan assets to 8.50 percent would increase our 2007 estimated net periodic benefit costs by approximately $1.7 million for our defined benefit pension plan and would not have a significant impact on our postretirement benefit plan. A decrease in our assumed discount rate to 5.75 percent would increase our 2007 estimated net periodic benefit costs by approximately $2.2 million for our defined benefit pension plan and $0.8 million for our postretirement benefit plan. For 2007, we anticipate our total contributions to fund future benefits for our defined benefit pension plan and postretirement benefit plan to be $4.2 million and $5.5 million, respectively, and the expected benefit payments from our postretirement benefit plan are estimated to be $22.1 million. See Note I of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with Statement 5. We base our estimates on currently available facts and our estimates of the ultimate outcome or resolution. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings.

Additional information about our critical accounting estimates is included under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies and Estimates,” in our Annual Report on Form 10-K for the year ended December 31, 2006.

FINANCIAL AND OPERATING RESULTS

Consolidated Operations

Selected Financial Information - The following table sets forth certain selected consolidated financial information for the periods indicated.


	Three Months Ended March 31,
Financial Results		2007		2006
		(Thousands of dollars)
Operating revenues, excluding energy trading revenues	$	3,797,658	$	3,840,334
Energy trading revenues, net		1,348		7,370
Cost of sales and fuel		3,234,379		3,346,419
Net margin		564,627		501,285
Operating costs		182,079		175,889
Depreciation, depletion and amortization		56,450		56,325
Gain on sale of assets		2,203		1,305
Operating income	$	328,301	$	270,376

Equity earnings from investments	$	24,055	$	31,641
Minority interests in income of consolidated subsidiaries	$	45,313	$	35,772

Operating Results - Net margin increased for the three months ended March 31, 2007, compared with the same period in 2006 primarily due to:

•

the implementation of new rate schedules in Kansas and Texas in our Distribution segment,

•

increased storage and marketing margins, partially offset by decreased transportation, financial trading and retail margins in our Energy Services segment,

•

higher NGL related margins in our ONEOK Partners segment, primarily due to higher product price spreads between Mont Belvieu, Texas, and Conway, Kansas; higher isomerization price spreads; wider price spreads between ethane and propane; and increased natural gasoline sales used in the production of ethanol fuel in its natural gas liquids business, partially offset by

•

decreased operating income in our ONEOK Partners segment’s gathering and processing business, primarily due to lower realized commodity prices on its POP contracts and lower volumes processed due to the anticipated contract terminations at certain processing facilities.

Consolidated operating costs increased for the three-month period primarily due to increased employee-related costs and property taxes in our Distribution segment.

Equity earnings from investments decreased $7.6 million for the three months ended March 31, 2007, compared with the same period in 2006, primarily due to the decrease in ONEOK Partners’ interest in Northern Border Pipeline’s earnings from 70 percent in the first quarter of 2006 to 50 percent in the first quarter of 2007. See page 24 for discussion of ONEOK Partners’ disposition of the 20 percent partnership interest in Northern Border Pipeline.

Minority interest in net income of consolidated subsidiaries for the three months ended March 31, 2007 and 2006, reflects the remaining 54.3 percent of ONEOK Partners that we do not own. Additionally, minority interest in net income of consolidated subsidiaries for our ONEOK Partners’ segment for the three months ended March 31, 2006, included the 66-2/3 percent interest in Guardian Pipeline that ONEOK Partners did not own until April 2006.

More information regarding our results of operations is provided in the discussion of operating results for each of our segments.

ONEOK Partners

Overview - We own 45.7 percent of ONEOK Partners; the remaining interest in ONEOK Partners is reflected as minority interest in income of consolidated subsidiaries on our Consolidated Statements of Income.

ONEOK Partners gathers and processes natural gas and fractionates NGLs primarily in the Mid-Continent and Rocky Mountain regions. ONEOK Partners’ operations include the gathering of natural gas production from crude oil and natural gas wells. Most natural gas produced at the wellhead contains a mixture of NGL components such as ethane, propane, iso-butane, normal butane and natural gasoline (collectively NGL products). Natural gas processing plants remove the NGLs from the natural gas stream to realize the higher economic value of the NGLs, and to meet natural gas pipeline quality specifications.

The NGLs that are separated from the natural gas stream at the natural gas processing plants remain in a mixed form until they are fractionated. ONEOK Partners gathers, stores, fractionates and treats mixed NGLs, and stores NGL products produced from gas processing plants located in Oklahoma, Kansas and the Texas panhandle. ONEOK Partners’ fractionators, by applying heat and pressure, separate each NGL component into marketable NGL products that can then be stored or distributed to petrochemical, heating and motor gasoline manufacturers. ONEOK Partners’ NGL assets connect the NGL production basins in Oklahoma, Kansas and the Texas panhandle with the key NGL market centers in Conway, Kansas, and Mont Belvieu, Texas.

ONEOK Partners also operates intrastate and FERC-regulated interstate natural gas transmission pipelines, natural gas storage and FERC-regulated and intrastate natural gas liquids gathering and distribution pipelines and non-processable natural gas gathering facilities. ONEOK Partners also provides interstate natural gas transportation service under Section 311(a) of the Natural Gas Policy Act.

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


	Three Months Ended March 31,
Financial Results		2007		2006
	(Thousands of dollars)
Revenues	$	1,161,472	$	1,169,830
Cost of sales and fuel		956,325		968,135
Net margin		205,147		201,695
Operating costs		75,461		75,356
Depreciation and amortization		27,513		27,470
Gain on sale of assets		2,203		1,305
Operating income	$	104,376	$	100,174

Equity earnings from investments	$	24,055	$	31,641
Minority interests in income of consolidated subsidiaries	$	85	$	1,619

	Three Months Ended March 31,
Operating Information		2007		2006
Total gas gathered (BBtu/d)		1,168		1,145
Total gas processed (BBtu/d)		609		931
Natural gas liquids gathered (MBbl/d)		210		193
Natural gas liquids sales (MBbl/d)		220		208
Natural gas liquids fractionated (MBbl/d)		319		281
Natural gas liquids transported (MBbl/d)		205		193
Natural gas transported (MMcf/d)		2,611		2,538
Natural gas sales (BBtu/d)		271		311
Capital expenditures (Thousands of dollars)	$	77,857	$	17,657
Realized composite NGL sales prices ($/gallon)	$	0.82	$	0.87
Realized condensate sales price ($/Bbl)	$	56.53	$	57.67
Realized natural gas sales price ($/MMBtu)	$	6.58	$	7.99
Realized gross processing spread ($/MMBtu)	$	3.59	$	3.43

Operating results - Net margin increased by $3.5 million for the three months ended March 31, 2007, compared with the same period in the prior year, primarily due to:

•

higher NGL related margins in its natural gas liquids business, primarily due to higher product price spreads between Mont Belvieu, Texas, and Conway, Kansas; higher isomerization price spreads; wider price spreads between ethane and propane; and increased natural gasoline sales used in the production of ethanol fuel, partially offset by

•

decreased operating income in its gathering and processing business, primarily due to lower realized commodity prices on its POP contracts and lower volumes processed due to the anticipated contract terminations at certain processing facilities.

Minority interest in income of consolidated subsidiaries decreased for the three months ended March 31, 2007, compared with the same period in 2006, primarily due to Guardian Pipeline. Minority interest in income of consolidated subsidiaries for the three months ended March 31, 2006, included the 66-2/3 percent interest in Guardian Pipeline that ONEOK Partners did not own until April 2006. ONEOK Partners owned 100 percent of Guardian Pipeline beginning in April 2006, resulting in no minority interest in income of consolidated subsidiaries related to Guardian Pipeline for the three months ended March 31, 2007.

The increase in capital expenditures for 2007, compared with 2006, is driven primarily by ONEOK Partners’ capital projects which are discussed beginning on page 25.

Distribution

Overview - Our Distribution segment provides natural gas distribution services to over two million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. We serve residential, commercial, industrial and transportation customers in all three states. In addition, our distribution companies in Oklahoma and Kansas serve wholesale customers, and in Texas we serve public authority customers.

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


	Three Months Ended March 31,
Financial Results		2007		2006
	(Thousands of dollars)
Gas sales	$	843,666	$	750,772
Transportation revenues		28,307		26,353
Cost of gas		653,794		591,802
Margin		218,179		185,323
Other revenues		9,049		10,118
Net Margin		227,228		195,441
Operating costs		95,715		90,514
Depreciation, depletion and amortization		28,275		28,152
Operating income	$	103,238	$	76,775

Operating Results - Net margin increased by $31.8 million for the three months ended March 31, 2007, compared with the same period in 2006, primarily due to:

•

an increase of $21.1 million resulting from the implementation of new rate schedules, which includes $18.9 million in Kansas and $2.2 million in Texas, and

•

an increase of $10.6 million from higher customer sales volumes as a result of a return to more normal weather in our entire service territory.

Operating costs increased $5.2 million for the three months ended March 31, 2007, compared with the same period in 2006, primarily due to:

•

an increase of $4.2 million in employee-related costs, and

•

an increase of $1.7 million due to increased property taxes, partially offset by

•

a decrease of $2.2 million in bad debt expense.

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


	Three Months Ended March 31,
Operating Information		2007		2006
Average number of customers		2,072,811		2,050,494
Customers per employee		745		712
Capital expenditures (Thousands of dollars)	$	27,037	$	36,675

	Three Months Ended March 31,
Volumes *(MMcf)*		2007		2006
Gas sales
Residential		59,657		52,423
Commercial		17,246		15,307
Industrial		532		580
Wholesale		310		4,940
Public Authority		1,029		887
Total volumes sold		78,774		74,137
Transportation		57,609		56,960
Total volumes delivered		136,383		131,097


	Three Months Ended March 31,
Margin		2007		2006
Gas sales		(Thousands of dollars)
Residential	$	154,888	$	128,406
Commercial		36,593		31,877
Industrial		757		858
Wholesale		88		870
Public Authority		1,182		819
Margin on gas sales		193,508		162,830
Transportation		24,671		22,493
Margin	$	218,179	$	185,323

Residential and commercial volumes increased for the three-month period due to a return to more normal weather from the unseasonably warm weather in 2006.

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 decreased for the three months ended March 31, 2007, compared with the same period of 2006 due to reduced volumes available for sale.

Public authority natural gas volumes reflect volumes used by state and local agencies and school districts served by Texas Gas Service.

Capital Expenditures - Our capital expenditure program includes expenditures for extending service to new areas, modifying customer service lines, increasing system capabilities, general replacements and improvements. It is our practice to maintain and periodically upgrade facilities to assure safe, reliable and efficient operations. Our capital expenditure

program included $9.6 million and $13.5 million for new business development for the three months ended March 31, 2007, and 2006, respectively. The decrease in new business capital expenditures during 2007, compared with 2006, resulted from increased customer installations during 2006 in the Austin and El Paso areas of Texas and the Tulsa and Oklahoma City areas of Oklahoma. The remaining decrease in capital expenditures for the three months ended March 31, 2007, compared with 2006, was due to warmer than normal weather in the first quarter of 2006, which favorably impacted construction. We expect our 2007 capital expenditures to be consistent with our 2006 capital expenditures.

Regulatory Initiatives

Oklahoma - On January 31, 2007, Oklahoma Natural Gas filed an application at the OCC seeking recovery of costs incurred in compliance with the federal Pipeline Safety Improvement Act of 2002. In the most recent rate filing, the parties stipulated that transmission pipeline Integrity Management Program (IMP) costs should be addressed in a subsequent proceeding, and in the order issued October 2005, the OCC authorized Oklahoma Natural Gas to defer such costs (inclusive of operations and maintenance expense, depreciation, ad valorem taxes, and a rate of return). The new application seeks recovery of $5.2 million in IMP deferrals. The hearing on the application is scheduled for August 9, 2007.

Kansas - In May 2006, Kansas Gas Service announced that it filed a request with the KCC to increase its annual revenues by $73.3 million. Since its last rate case in 2003, Kansas Gas Service had invested approximately $170 million in its natural gas distribution system to provide service for 642,000 Kansas customers. In October 2006, Kansas Gas Service reached a settlement with the KCC staff and all other involved parties to increase annual revenues by approximately $52 million. The terms of the settlement were approved by the KCC in November 2006. The rate increase is effective for services rendered on or after January 1, 2007.

General - Certain costs to be recovered through the ratemaking process have been recorded as regulatory assets in accordance with Statement 71, “Accounting for the Effects of Certain Types of Regulation.” Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria of Statement 71 and, accordingly, a write-off of regulatory assets and stranded costs may be required.

Energy Services

Overview - Our Energy Services segment’s primary focus is to create value for our customers by delivering physical natural gas products and risk management services through our network of contracted transportation and storage capacity and natural gas supply. These services include meeting our customers’ baseload, swing and peaking natural gas commodity requirements on a year-round basis. To provide these bundled services, we lease storage and transportation capacity. Our total storage capacity under lease through the next storage cycle (April 2007 through March 2008) is 96 Bcf, with maximum withdrawal capability of 2.3 Bcf/d and maximum injection capability of 1.5 Bcf/d. Our current transportation capacity is 1.8 Bcf/d. Our contracted storage and transportation capacity connects the major supply and demand centers throughout the United States and into Canada. With these contracted assets, our business strategies include identifying, developing and delivering specialized services and products valued by our customers, which are primarily LDCs, electric utilities, and commercial and industrial end users. Also, our storage and transportation capacity allows us opportunities to optimize these positions through our application of market knowledge and risk management skills.

Our Energy Services segment regularly conducts business with ONEOK Partners, our 45.7 percent owned affiliate, which comprises our ONEOK Partners segment. This segment also conducts business with our Distribution segment. These services are provided under agreements with market-based terms.

Due to seasonality of natural gas consumption, earnings are normally higher during the winter months than the summer months. Our Energy Services segment’s margins are subject to fluctuations during the year primarily due to the impact certain seasonal factors have on sales volumes and the price of natural gas. Natural gas sales volumes are typically higher in the winter heating months than in the summer months, reflecting increased demand due to greater heating requirements and, typically, higher natural gas prices that occur during the winter heating months. During periods of high natural gas demand, we utilize storage capacity to supplement natural gas supply volumes to meet peak day demand obligations or market needs.

Numerous risk management opportunities and operational strategies exist that can be implemented through the use of storage facilities and transportation capacity. We utilize our industry knowledge and expertise in order to capitalize on opportunities that are provided through market volatility. We utilize our experience to optimize the value of our contracted assets, and we use our risk management and marketing capabilities to both manage risk and to deploy a limited amount of risk capital to generate additional returns. We manage our contracted transportation and storage capacity by utilizing derivative instruments

such as over-the-counter forward, swap and option contracts and NYMEX futures and option contracts. We apply a combination of cash-flow and fair-value hedge accounting when implementing hedging strategies that take advantage of favorable market conditions. See Note D of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q for additional information. Additionally, certain non-trading transactions, which are economic hedges of our accrual transactions, such as our storage and transportation contracts, will not qualify for hedge accounting treatment. These economic hedges receive mark-to-market accounting treatment, as they are derivative contracts and are not designated as part of a hedge relationship.

Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for our Energy Services segment for the periods indicated. In the third quarter of 2005, we made the decision to sell our Spring Creek power plant, located in Oklahoma, and exit the power generation business. The transaction received FERC approval, and the sale was completed on October 31, 2006. This component of our business is accounted for as discontinued operations, in accordance with Statement 144. The discontinued operations are excluded from the financial and operating information below.


	Three Months Ended March 31,
Financial Results		2007		2006
		(Thousands of dollars)
Energy and power revenues	$	2,110,226	$	2,307,730
Energy trading revenues, net		1,348		7,370
Other revenues		132		115
Cost of sales and fuel		1,980,302		2,212,061
Net margin		131,404		103,154
Operating costs		10,729		9,294
Depreciation, depletion and amortization		538		575
Operating income	$	120,137	$	93,285


	Three Months Ended March 31,
Operating Information		2007		2006
Natural gas marketed (Bcf)		337		310
Natural gas gross margin ($/Mcf)	$	0.34	$	0.28
Physically settled volumes (Bcf)		639		602

Operating Results - Net margin increased by $28.3 million for the three months ended March 31, 2007, compared with the same period in 2006, primarily due to:

•

a net increase of $60.6 million in storage and marketing margins primarily due to:

an increase of $48.1 million from improved storage margins, net of hedging activities, related to higher realized seasonal storage spreads and optimization activities,

an increase of $12.5 million from changes in the fair value of derivatives associated with storage and marketing activities, partially offset by

•

a decrease of $22.1 million in transportation margins, net of hedging activities, associated with changes in the fair value of derivatives, and a decrease in realized margins in the Mid-Continent region,

•

a decrease of $7.9 million in our financial trading margins, and

•

a decrease of $2.5 million in retail activities from lower physical margins due to market conditions.

Operating costs increased $1.4 million for the three months ended March 31, 2007, primarily due to increased employee-related costs.

Natural gas volumes marketed increased for the three months ended March 31, 2007, compared with the same period in 2006, due to a 16 percent increase in heating degree days in 2007, compared with 2006, primarily occurring in January 2007, when our service territory experienced a 58 percent increase in heating degree days compared with January 2006.

Our natural gas in storage at March 31, 2007, was 37.3 Bcf compared with 42.3 Bcf at March 31, 2006. At March 31, 2007 and 2006, our total natural gas storage capacity under lease was 88 Bcf and 86 Bcf, respectively.

The acquisition of natural gas storage capacity has become more competitive as a result of new entrants from the financial services sector, the increase in the spread between summer and winter natural gas prices, and natural gas price volatility. The increased demand for storage capacity has resulted in an increase in both the cost of leasing storage capacity and the required term of the lease. Longer terms for our storage capacity leases could result in significant increases in our contractual commitments.

The presentation of settled derivative instruments on either a gross or net basis in our Consolidated Statements of Income is dependent on a number of factors, including whether the derivative instrument is (1) “held for trading purposes,” (2) financially settled, (3) results in physical delivery or services rendered, and (4) qualifies for the normal purchase or sale exception as defined in Statement 133. In accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and not ‘Held for Trading’ as Defined in EITF Issue No. 02-3,” EITF 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent,” and Statement 133, we report settled derivative instruments as follows:

•

all financially settled derivative contracts are reported on a net basis,

•

derivative instruments considered “held for trading purposes” that result in physical delivery are reported on a net basis,

•

derivative instruments not considered “held for trading purposes” that result in physical delivery or services rendered are reported on a gross basis, and

•

derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are reported on a gross basis.

We apply the indicators in EITF 99-19 to determine the appropriate accounting treatment for non-derivative contracts that result in physical delivery.

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


	Three Months Ended March 31,
		2007			2006
		(Thousands of dollars)
Marketing and storage, gross	$	177,106		$	135,068
Less: Storage and transportation costs		(52,713	)		(49,259	)
Marketing and storage, net		124,393			85,809
Retail marketing		2,994			5,449
Financial trading		4,017			11,896
Net margin	$	131,404		$	103,154

Marketing and storage activities, net, primarily include physical marketing, purchases and sales, firm storage and transportation capacity expense, including the impact of cash flow and fair value hedges, and other derivative instruments used to manage our risk associated with these activities. The combination of owning supply, controlling strategic assets and risk management services allows us to provide commodity-diverse products and services to our customers such as peaking and load-following services.

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

Financial trading margin includes activities that are generally executed using financially settled derivatives. These activities are normally short-term in nature, with a focus of capturing short-term price volatility. Energy trading revenues, net, in our Consolidated Income Statements 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 required to be reported on a net basis.

LIQUIDITY AND CAPITAL RESOURCES

General - Part of our strategy is to grow through acquisitions that strengthen and complement our existing assets. We have relied primarily on operating cash flow, borrowings from commercial paper and credit agreements, and issuance of debt and equity in the capital markets for our liquidity and capital resource requirements. We expect to continue to use these sources for liquidity and capital resource needs on both a short- and long-term basis. We have no material guarantees of debt or other similar commitments to unaffiliated parties. During the three months ended March 31, 2007 and 2006, our capital expenditures were financed through operating cash flows and short- and long-term debt. Total capital expenditures for the first three months of 2007 were $107.0 million, compared with $54.6 million for the same period in 2006, exclusive of acquisitions. ONEOK Partners’ capital expenditures for the first three months of 2007 were $77.9 million, compared with $17.7 million for the same period in 2006, exclusive of acquisitions. The increase in capital expenditures for 2007 compared with 2006 is driven primarily by ONEOK Partners’ capital projects, which are discussed beginning on page 25.

Financing - Financing is provided through available cash, our commercial paper program and long-term debt. We also have credit agreements, as discussed below, which are used as a back-up for the commercial paper program and short-term liquidity needs. Other options to obtain financing include, but are not limited to, issuance of equity, issuance of mandatory convertible debt securities, issuance of trust preferred securities by ONEOK Capital Trust I or ONEOK Capital Trust II, asset securitization and sale/leaseback of facilities. ONEOK Partners’ operations are also financed through available cash or the issuance of debt or limited partner units.

The total amount of short-term borrowings authorized by our Board of Directors is $2.5 billion. The total amount of short-term borrowings authorized by the Board of Directors of ONEOK Partners GP, the general partner of ONEOK Partners, is $1.5 billion. At March 31, 2007, we had no commercial paper outstanding, $37.9 million in letters of credit issued and available cash and short-term investments of approximately $667.8 million. At March 31, 2007, ONEOK Partners had $10 million in letters of credit issued, no borrowings outstanding under the 2007 Partnership Credit Agreement, as described in Note H of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q, and available cash and short-term investments of approximately $95.7 million. As of March 31, 2007, we could have issued $2.6 billion of additional debt under the most restrictive provisions contained in our various borrowing agreements. As of March 31, 2007, ONEOK Partners could have issued, under the most restrictive provisions of its agreements, $1.7 billion of additional debt.

Our $1.2 billion five-year credit agreement, as amended and restated in 2006, and ONEOK Partner’s 2007 Partnership Credit Agreement, contain typical covenants as discussed in Note H of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q, and Note H of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K, for the year ended December 31, 2006. At March 31, 2007, we and ONEOK Partners were in compliance with all covenants.

Currently, we have $48.2 million available under a shelf registration statement on Form S-3, for the issuance and sale of shares of our common stock, debt securities, preferred stock, stock purchase contracts and stock purchase units.

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


	March 31, 2007	December 31, 2006
Long-term debt	65%	65%
Equity	35%	35%
Debt (including Notes payable)	65%	65%
Equity	35%	35%

We do not guarantee the debt of ONEOK Partners. For purposes of determining compliance with financial covenants in our five-year credit agreement, the debt of ONEOK Partners is excluded. At both March 31, 2007, and December 31, 2006, our capitalization structure, excluding the debt of ONEOK Partners, was 48 percent debt and 52 percent equity.

Credit Rating - Our credit ratings as of March 31, 2007, 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

Our credit ratings may be affected by a material change in our financial ratios or a material event affecting our business. The most common criteria for assessment of our credit ratings are the debt-to-capital ratio, business risk profile, pretax and after-tax interest coverage and liquidity. If our credit ratings were downgraded, the interest rates on our commercial paper borrowings would increase, resulting in an increase in our cost to borrow funds, and we could potentially lose access to the commercial paper market. In the event that ONEOK is unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we have access to a $1.2 billion five-year credit agreement, which expires July 2011, and ONEOK Partners has access to a $750 million revolving credit agreement, which allows for an option to increase the commitments of the lenders up to an additional $250 million that expires March 2012.

ONEOK Partners’ $250 million and $225 million long-term notes payable, due 2010 and 2011, respectively, contain provisions that require ONEOK Partners to offer to repurchase the senior notes at par value if the Moody’s or S&P credit ratings fall below investment grade (Baa3 for Moody’s and BBB- for S&P) and the investment grade ratings are not reinstated within a period of 40 days. Further, the indentures governing ONEOK Partners’ senior notes due 2010 and 2011 include an event of default upon acceleration of other indebtedness of $25 million or more and the indentures governing the senior notes due 2012, 2016 and 2036 include an event of default upon the acceleration of other indebtedness of $100 million or more that would be triggered by such an offer to repurchase. Such an event of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2010, 2011, 2012, 2016 and 2036 to declare those notes immediately due and payable in full. ONEOK Partners may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause it to borrow money under its credit facilities or seek alternative financing sources to finance the repurchases and repayment. ONEOK Partners could also face difficulties accessing capital or its borrowing costs could increase, impacting its ability to obtain financing for acquisitions or capital expenditures, to refinance indebtedness and to fulfill its debt obligations.

Our Energy Services segment relies upon the investment grade rating of our senior unsecured long-term debt to satisfy credit requirements with most of our counterparties. If our 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. A decline in our credit rating below investment grade may also significantly impact other business segments. At March 31, 2007, we could have been required to fund approximately $95.3 million for counterparties with which we have a Credit Support Annex according to our International Swaps and Derivatives Association Agreements.

Other than ONEOK Partners’ note repurchase obligations and the margin requirement for our Energy Services segment described above, we have determined that we do not have significant exposure to the rating triggers under our commercial paper agreement, trust indentures, building leases, equipment leases, and other various contracts. Rating triggers are defined as provisions that would create an automatic default or acceleration of indebtedness based on a change in our credit rating. Our credit agreements contain provisions that would cause the cost to borrow funds to increase if our credit rating is negatively adjusted. ONEOK Partners’ credit agreements have similar provisions. An adverse rating change is not defined as a default of our credit agreements.

Capital Projects - See the “Capital Projects” section beginning on page 25 for discussion of capital projects.

ONEOK Partners’ Class B Units - The units we received from ONEOK Partners were newly created Class B limited partner units. Distributions on the Class B limited partner units were prorated from the date of issuance. As of April 7, 2007, the Class B limited partner units are no longer subordinated to distributions on our common units and generally have the same voting rights as our common units.

At a special meeting of the holders of common units on March 29, 2007, the unitholders approved a proposal to permit the conversion of the Class B limited partner units into common units at the option of the Class B unitholder. The March 29, 2007, special meeting was adjourned to May 10, 2007, to allow unitholders additional time to vote on a proposal to approve certain amendments to the ONEOK Partners partnership agreement. The proposed amendments to the ONEOK Partners partnership agreement would grant voting rights for units held by its general partner and its affiliates, if a vote is held to

remove its general partner and require fair market value compensation for the general partner interest if the general partner is removed.

If the proposed amendments to the ONEOK Partners Partnership Agreement are approved by the common unitholders at the May 10, 2007, meeting, the Class B limited partner units will automatically convert into common units on a one-for-one basis, and the Class B limited partner units will no longer be outstanding. Effective April 7, 2007, the Class B limited partner units are entitled to increased quarterly distributions and to distributions upon liquidation equal to 110 percent of the distributions paid with respect to the common units. If the common unitholders approve the amendments on May 10, 2007, these increased distribution rights will be eliminated after that date. In addition, if the common unitholders do not approve the proposed amendments, and the common unitholders vote at any time prior to the approval of the proposed amendments, to remove us or our affiliates as the general partner of ONEOK Partners, quarterly distributions payable on Class B limited partner units would increase to 123.5 percent of the distributions payable with respect to the common units, and distributions payable upon liquidation of the Class B limited partner units would increase to 125 percent of the distributions payable with respect to the common units.

Stock Repurchase Plan - On August 7, 2006, we repurchased 7.5 million shares of our outstanding common stock under an accelerated share repurchase agreement with UBS Securities LLC (UBS) at an initial price of $37.52 per share for a total of $281.4 million. Under the terms of the accelerated repurchase agreement, we repurchased 7.5 million shares immediately from UBS. UBS then borrowed 7.5 million of our shares and purchased shares in the open market to settle its short position. Our repurchase was subject to a financial adjustment based on the volume-weighted average price, less a discount, of the shares subsequently repurchased by UBS over the course of the repurchase period. The price adjustment could have been settled, at our option, in cash or in shares of our common stock. In accordance with EITF Issue No. 99-7, “Accounting for an Accelerated Share Repurchase Program,” the repurchase was accounted for as two separate transactions: (1) as shares of common stock acquired in a treasury stock transaction recorded on the acquisition date and (2) as a forward contract indexed to our common stock. Additionally, we classified the forward contract as equity under EITF Issue No. 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock.” In February 2007, the forward purchase contract settled for a cash payment of $20.1 million, which was recorded in equity. We currently have no remaining shares authorized for repurchase under our stock repurchase plan.

Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity price in either physical or financial energy contracts may impact our overall liquidity due to the impact the commodity price change has on items such as the cost of NGLs and gas held in storage, increased margin requirements, the cost of transportation to various market locations, collectibility of certain energy-related receivables and working capital. We believe that our current commercial paper program and ONEOK Partners’ lines of credit are adequate to meet liquidity requirements associated with commodity price volatility.

Pension and Postretirement Benefit Plans - We calculate benefit obligations based upon generally accepted actuarial methodologies using the projected benefit obligation (PBO) for pension plans and the accumulated postretirement benefit obligation for other postretirement plans. Pension costs and other postretirement obligations as of December 31 are determined using a September 30 measurement date. The benefit obligations are the actuarial present value of all benefits attributed to employee service rendered. The PBO is measured using the pension benefit formula and assumptions as to future compensation levels. A plan’s funded status is calculated as the difference between the benefit obligation and the fair value of plan assets. Our funding policy for the pension plans is to make annual contributions in accordance with regulations under the Internal Revenue Code and in accordance with generally accepted actuarial principles. Contributions to fund future benefits for our pension plan and postretirement benefit plan in 2006 were $1.8 million and $5.2 million, respectively. Additionally, we made benefit payments for our postretirement benefit plan of $23.4 million in 2006. For 2007, we anticipate our total contributions to fund future benefits for our pension plan and postretirement benefit plan to be $4.2 million and $5.5 million, respectively, and the expected benefit payments for our postretirement benefit plan are estimated to be $22.1 million. We believe we have adequate resources to fund our obligations under our plans.

ENVIRONMENTAL LIABILITIES

We are subject to multiple environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid wastes and hazardous material and substance management. These laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. If an accidental leak or spill of hazardous materials occurs from our lines or facilities, in the process of transporting natural gas or NGLs, or at any facility that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including investigation and clean-up costs, which could materially affect our results of operations and cash flows. In addition, emission controls required under the federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial condition and results of operations.

The costs associated with these sites do not include other potential expenses that might be incurred, such as unasserted property damage claims, personal injury or natural resource claims, unbudgeted legal expenses or other costs for which we may be held liable but with respect to which we cannot reasonably estimate an amount. As of this date, we have no knowledge of any of these types of claims. The foregoing estimates do not consider potential insurance recoveries, recoveries through rates or recoveries from unaffiliated parties, to which we may be entitled. We have filed claims with our insurance carriers relating to these sites and we have recovered a portion of our costs incurred to date. We have not recorded any amounts for potential insurance recoveries or recoveries from unaffiliated parties, and we are not recovering any environmental amounts in rates. As more information related to the site investigations and remediation activities becomes available, and to the extent such amounts are expected to exceed our current estimates, additional expenses could be recorded. Such amounts could be material to our results of operations and cash flows depending on the remediation and number of years over which the remediation is required to be completed.

CASH FLOW ANALYSIS

Operating Cash Flows - Operating cash flows increased by $76.6 million for the three months ended March 31, 2007, compared with the same period in 2006, primarily as a result of changes in components of working capital. These changes increased operating cash flows by $589.7 million, compared with an increase of $524.0 million for the same period last year, due to increases in accounts receivable, partially offset by increases in accounts payable, decreases in inventory, and decreases in energy marketing and risk management assets and liabilities.

Investing Cash Flows - Cash used in investing activities was $610.4 million for the three months ended March 31, 2007, compared with $79.9 million for the same period in 2006. The increased use of cash was primarily related to increased capital expenditures due to capital projects, and purchases of short-term investments during the first quarter of 2007.

Investing cash flows for 2006 also include the impact of the deconsolidation of Northern Border Pipeline and consolidation of Guardian Pipeline.

Financing Cash Flows - Cash used in financing activities was $106.6 million for the three months ended March 31, 2007, compared with $746.3 million for the same period in 2006, which included the $20.1 million settlement of the forward purchase contract related to our stock repurchase in February 2007.

During the three months ended March 31, 2006, we repaid the remaining $900 million under our short-term bridge financing agreement, which was used to initially finance our acquisition of the assets from Koch. We also paid down $134.5 million in commercial paper during the first quarter of 2006. In March 2006, ONEOK Partners borrowed $33 million under its 2006 Partnership Credit Agreement to redeem all of the outstanding Viking Gas Transmission Series A, B, C and D senior notes and paid a redemption premium of $3.6 million.

On February 16, 2006, we successfully settled our 16.1 million equity units with 19.5 million shares of our common stock. With the settlement, we received $402.4 million in cash, which was used to pay down our short-term bridge financing agreement.

FORWARD-LOOKING STATEMENTS AND RISK FACTORS

Some of the statements contained and incorporated in this Quarterly Report on Form 10-Q are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The forward-looking statements relate to our anticipated financial performance, management’s plans and objectives for our future operations, our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in certain circumstances. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this Quarterly Report on Form 10-Q identified by words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast” or other similar phrases.

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

•

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

•

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

•

competition from other U.S. and Canadian energy suppliers and transporters as well as alternative forms of energy;

•

the capital intensive nature of our businesses;

•

the profitability of assets or businesses acquired by us;

•

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

•

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

•

the risk of a significant slowdown in growth or decline in the U.S. economy or the risk of delay in growth recovery in the U.S. economy;

•

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

•

the timing and extent of changes in commodity prices for natural gas, NGLs, electricity and crude oil;

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

risks associated with adequate supply to our gas gathering and processing, fractionation and pipeline facilities, including production declines which 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 of the outcome of pending and future litigation;

•

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

•

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

•

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

– future demand for and prices of natural gas;

– competitive conditions in the overall natural gas and electricity markets;

– availability of supplies of Canadian and U.S. natural gas;

– availability of additional storage capacity;

– weather conditions; and

– competitive developments by Canadian and U.S. natural gas transmission peers;

•

our ability to successfully transfer ONEOK Partners’ operations from Omaha to Tulsa;

•

performance of contractual obligations by our customers and shippers;

•

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;

•

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

•

our ability to acquire all necessary rights-of-way permits and consents in a timely manner, and our ability to promptly obtain all necessary materials and supplies required for construction, and our ability to construct pipelines without labor or contractor problems;

•

our ability to promptly obtain all necessary materials and supplies required for construction of gathering, processing and transportation facilities;

•

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

•

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

•

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

•

the mechanical integrity of facilities operated;

•

demand for our services in the proximity of our facilities;

•

the impact of potential impairment charges;

•

our ability to control operating costs;

•

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;

•

acts of nature, sabotage, terrorism or other similar acts causing damage to our facilities or our suppliers’ or shippers’ facilities; 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 under Part I, Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2006. 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 on Form 10-K for the year ended December 31, 2006.

COMMODITY PRICE RISK

ONEOK Partners

ONEOK Partners is exposed to commodity price risk as its interstate and intrastate pipelines collect natural gas from its customers for operations or as part of its fee for services provided. When the amount of natural gas consumed in operations by these pipelines differs from the amount provided by its customers, the pipelines must buy or sell natural gas, store or use natural gas from inventory, and are exposed to commodity price risk. At March 31, 2007, there were no hedges in place with respect to natural gas price risk from ONEOK Partners’ interstate and intrastate pipeline operations.

In addition, ONEOK Partners is exposed to commodity price risk primarily as a result of NGLs in storage, spread risk associated with the relative values of the various components of the NGL stream and the relative value of NGL purchases at one location and sales at another location, known as basis risk. ONEOK Partners has not entered into any hedges with respect to its NGL marketing activities.

ONEOK Partners is also exposed to commodity price risk primarily as a result of receiving commodities in exchange for its gathering and processing services. ONEOK Partners’ primary exposure arises from the relative price differential between natural gas and NGLs with respect to its keep-whole processing contracts and the sale of natural gas, NGLs and condensate with respect to its percent of proceeds contracts. To a lesser extent, ONEOK Partners is exposed to the risk of price fluctuations and the cost of intervening transportation at various market locations. ONEOK Partners uses commodity fixed-price physical forwards and derivative contracts, including NYMEX-based futures and over-the-counter swaps, to minimize earnings volatility related to natural gas, NGL and condensate price fluctuations.

ONEOK Partners has reduced its gross processing spread exposure through a combination of physical and financial hedges. ONEOK Partners utilizes a portion of its POP equity natural gas as an offset, or natural hedge, to an equivalent portion of its keep-whole shrink requirements. ONEOK Partners has effectively converted its spread risk to NGL commodity price risk, and uses financial instruments to hedge the sale of NGLs. Through this approach, ONEOK Partners has reduced its gross processing spread exposure by 5,538 MMBtu/d (or 1,647 Bbl/d). The NGLs have been hedged at an average price of $0.79 per gallon in 2007. For 2008, ONEOK Partners has converted the spread risk to NGLs commodity price risk on 1,796 MMBtu/d (or 559 Bbl/d). The NGLs have been hedged at an average price of $0.82 per gallon in 2008.

The following table sets forth ONEOK Partners’ hedging information for the remainder of 2007 and for the year ending December 31, 2008.


	Nine Months Ending December 31, 2007
Product	Volumes Hedged		Average Price Per Unit		Volumes Hedged
Commodity Risk
Natural gas liquids (Bbl/d) (a)	2,692		$0.85	($/gallon)	43	%
Spread Risk
Gross processing spread (MMBtu/d) (a)	6,391		$2.98	($/MMBtu)	28	%
Natural gas liquids (Bbl/d) (a)	1,647	(b)	$0.79	($/gallon)	24	%
(a) Hedged with fixed-priced swaps
(b) 5,538 MMBtu/d equivalent
	Year Ending December 31, 2008
Product	Volumes Hedged		Average Price Per Unit		Volumes Hedged
Commodity Risk
Natural gas liquids (Bbl/d) (a)	503		$ 0.89	($/gallon)	8	%
Spread Risk
Natural gas liquids (Bbl/d) (a)	559	(b)	$0.82	($/gallon)	9	%
(a) Hedged with fixed-price swaps
(b) 1,796 MMBtu/d equivalent

ONEOK Partners’ commodity price risk is estimated as a hypothetical change in the price of natural gas, NGLs and crude oil at March 31, 2007, excluding the effects of hedging. ONEOK Partners’ condensate sales are based on the price of crude oil. ONEOK Partners estimates that a $1.00 per barrel increase in the price of crude oil would increase annual net margin by approximately $0.5 million. ONEOK Partners estimates that a $0.01 per gallon increase in the composite price of NGLs would increase annual net margin by approximately $1.9 million. ONEOK Partners estimates that a $0.10 per MMBtu increase in the price of natural gas would increase annual net margin by approximately $0.2 million. The above estimates of commodity price risk do not include any effects on demand for its services that might be caused by, or arise in conjunction with, price changes. For example, a change in the gross processing spread may cause ethane to be sold in the natural gas stream, impacting gathering and processing margins, NGL exchange margins, natural gas deliveries and NGL volumes shipped.

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 derivative instruments that have been declared as either fair value or cash flow hedges.


Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities
		(Thousands of dollars)
Net fair value of derivatives outstanding at December 31, 2006	$	(13,133	)
Derivatives realized or otherwise settled during the period		12,572
Fair value of new derivatives when entered into during the period		10,355
Other changes in fair value		(5,272	)
Net fair value of derivatives outstanding at March 31, 2007	$	4,522

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. Fair value estimates consider the market in which the transactions are executed. The market in which exchange traded and over-the-counter transactions are executed is a factor in determining fair value. We utilize third-party references for pricing points from NYMEX and third-party over-the-counter brokers to establish the commodity pricing and volatility curves. We believe the reported transactions from these sources are the most reflective

of current market prices. Fair values are subject to change based on valuation factors. The estimate of fair value includes an adjustment for the liquidation of the position in an orderly manner over a reasonable period of time under current market conditions. The fair value estimate also considers the risk of nonperformance based on credit considerations of the counterparty.

Maturity of Energy Trading Contracts - The following table provides a detail of our Energy Services segment’s maturity of derivatives based on injection and withdrawal periods from April through March. This maturity schedule is consistent with our business strategy. Derivative instruments that have been declared as either fair value or cash flow hedges are not included in the following table.

Fair Value of Derivatives at March 31, 2007

Source of Fair Value (a)

Matures
through
March 2008

Matures
through
March 2011

Matures
through
March 2013

Total
Fair
Value

(Thousands of dollars)

Prices actively quoted (b)

(7,455

)

107

(7,348

)

Prices provided by other external sources (c)

57,676

9,594

(110

)

67,160

Prices derived from quotes, other external sources and other assumptions (d)

(62,559

)

7,296

(27

)

(55,290

)

Total

(12,338

)

16,997

(137

)

4,522

(a) Fair value is the marked-to-market component of forwards, futures, swaps, and options, net of applicable reserves. These fair values are reflected as a component of assets and liabilities from energy marketing and risk management activities in our Consolidated Balance Sheets.

(b) Values are derived from energy market price quotes from national commodity trading exchanges that primarily trade futures and option commodity contracts.

(c) Values are obtained through energy commodity brokers or electronic trading platforms, whose primary service is to match willing buyers and sellers of energy commodities. Energy price information by location is readily available because of the large energy broker network.

(d) Values derived in this category utilize market price information from the other two categories, as well as other assumptions for liquidity and credit.

For further discussion of trading activities and assumptions used in our trading activities, see “Accounting Treatment” in Note D of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Value-at-Risk (VAR) Disclosure of Market Risk - The potential impact on our future earnings, as measured by VAR, was $7.9 million and $19.0 million at March 31, 2007, and 2006, respectively. The following table details the average, high and low daily VAR calculations for the periods indicated.


	Three Months Ended March 31,
Value-at-Risk		2007		2006
		(Millions of dollars)
Average	$	13.1	$	32.0
High	$	23.0	$	65.0
Low	$	5.5	$	17.3

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 the portfolios during the year. The decrease in VAR for 2007, compared with 2006, was due to lower average commodity prices and decreased price volatility in 2007.

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

General - 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, at times, interest rate swaps. Fixed rate swaps are used to reduce our risk of increased interest costs during periods of rising interest rates. Floating rate swaps are used to convert the fixed rates of long-term borrowings into short-term variable rates. At March 31, 2007, the interest rate on 82.9 percent of our long-term debt, exclusive of the debt of our ONEOK Partners segment, was fixed after considering the impact of interest rate swaps, while the interest rate on 92.6 percent of ONEOK Partners’ long-term debt was fixed after considering the impact of interest rate swaps.

At March 31, 2007, a 100 basis point move in the annual interest rate on our variable-rate long-term debt would change our annual interest expense by $4.9 million before taxes. This 100 basis point change assumes a parallel shift in the yield curve. If interest rates changed significantly, we would take actions to manage our exposure to the change. Since a specific action and the possible effects are uncertain, no change has been assumed.


		ONEOK		ONEOK Partners		Total
		(Millions of dollars)
Remainder of 2007	$	5.0	$	2.7	$	7.7
2008		6.6		3.7		10.3
2009		5.5		3.7		9.2
2010		5.4		3.7		9.1
2011		2.5		0.9		3.4
Thereafter		12.8		-		12.8

Currently, the interest rate on $490 million of fixed-rate debt is swapped to floating using interest rate swaps. The floating-rate is based on both the three- and six-month LIBOR, depending upon the swap. Based on the actual performance through March 31, 2007, the weighted average interest rate increased from 6.64 percent to 6.79 percent. At March 31, 2007, we recorded a net liability of $11.9 million to recognize the interest rate swaps at fair value. Long-term debt was decreased by $11.9 million to recognize the change in the fair value of the related hedged liability.

Total savings from the interest rate swaps and amortization of terminated swaps was $1.9 million for the three months ended March 31, 2007. The swaps are expected to net the following savings for the remainder of the year:

•

interest expense savings of $7.7 million related to the amortization of the swap value at termination, and

•

approximately $0.5 million in interest expense from the existing $490 million of swapped debt, based on LIBOR rates at March 31, 2007.

Total net swap savings for 2007 are expected to be $9.1 million, compared with $7.6 million for 2006.

CURRENCY RATE RISK

As a result of our Energy Services segment’s operations in Canada, we are subject to currency exposure related to our firm transportation and storage contracts. Our objective with respect to currency risk is to reduce the exposure due to exchange-rate fluctuations. We use physical forward transactions, which result in an actual two-way flow of currency on the settlement date since we exchange U.S. dollars for Canadian dollars with another party. We have not designated these transactions for hedge accounting treatment; therefore, the gains and losses associated with the change in fair value are recorded in net margin. At March 31, 2007, our exposure to risk from currency translation was not material, and there were no material currency translation gains or losses recorded during the three months ended March 31, 2007 or 2006.

ITEM 4.

CONTROLS AND PROCEDURES

Quarterly Evaluation of Disclosure Controls and Procedures - As of the end of the period covered by this report, our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer) evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. Based on their evaluation, they concluded that as of March 31, 2007, our disclosure controls and procedures were effective in ensuring that the information required to be disclosed by us in the reports we file or submit under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Changes in Internal Controls Over Financial Reporting - We have not made any changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the first quarter ended March 31, 2007, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

Additional information about our legal proceedings is included under Part I, Item 3, “Legal Proceedings,” in our Annual Report on Form 10-K for the year ended December 31, 2006.

Richard Manson v. Northern Plains Natural Gas Company, LLC, et. al., Civil Action No. 1973-N, in the Court of Chancery of the State of Delaware in and for New Castle County. All payments under the settlement reached in this matter have been made by ONEOK Partners and its insurer. This case has been formally concluded.

Gas Index Pricing Litigation Cases: In Samuel P. Leggett, et al. v. Duke Energy Corporation, et al. (filed in the Chancery Court for the Twenty-Fifth Judicial District at Somerville, Tennessee, in January 2005), the plaintiffs filed a notice of appeal with the Tennessee Court of Appeals on April 4, 2007, appealing the motion to dismiss granted by the trial court.

In addition, a new class action energy trading case was filed against us, ONEOK Energy Marketing and Trading Company, L.P. (renamed ONEOK Energy Services Company, L.P.), and Kansas Gas Marketing Company as defendants as well as 19 other defendants: Heartland Regional Medical Center, et al. v. ONEOK, Inc., et al (filed in the Circuit Court of Buchanan County, Missouri, in March 2007). The action is alleged to be brought pursuant to the Missouri Antitrust Law on behalf of all persons and entities in the State of Missouri who made direct purchases of natural gas during the period from January 1, 2000, through October 31, 2002. The petition alleges that the defendants falsely reported natural gas prices and engaged in a conspiracy to manipulate the energy trading market in violation of the Missouri Antitrust Law. The plaintiffs seek treble damages. Similar to the other energy trading cases in which we are involved as reported in our Annual Report on Form 10-K for the year ended December 31, 2006, we plan to analyze all of these claims and vigorously defend against them.

ITEM 1A.

RISK FACTORS

Our investors should consider the risks set forth in Part I, Item 1A, “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2006, that could affect us and our business. Although we have tried to discuss key factors, our investors need to be aware that other risks may prove to be important in the future. New risks may emerge at any time and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors should carefully consider the discussion of risks and the other information included or incorporated by reference in this Quarterly Report on Form 10-Q, including Forward-Looking Information, which is included in Part I, Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

ISSUER PURCHASES OF EQUITY SECURITIES

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


Period	Total Number of Shares Purchased				Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
January 1-31, 2007	197	(1	)	$	42.66	-	-
February 1-28, 2007	90	(1	)	$	42.85	-	-
March 1-31, 2007	18	(1	)	$	42.19	-	-

Total	305			$	42.68	-	-

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

EMPLOYEE STOCK AWARD PROGRAM

Under our Employee Stock Award Program, we issued, for no consideration, to all eligible employees (all full-time employees and employees on short-term disability) one share of our common stock when the per-share closing price of our common stock on the NYSE was for the first time at or above $26 per share, and we have issued and will continue to issue, for no consideration, one additional share of our common stock to all eligible employees when the closing price on the NYSE is for the first time at or above each one dollar increment above $26 per share. The total number of shares of our common stock available for issuance under this program is 200,000.

Through March 31, 2007, a total of 95,182 shares had been issued to employees under this program. The following table sets forth information on the number of shares issued during the three months ended March 31, 2007.


Date	Closing Price (at or above)	Shares Issued
March 15, 2007	$45.00	4,528
March 21, 2007	$46.00	4,534
Total		9,062

On April 25, 2007, our common stock closed above $47.00 per share, which resulted in 4,379 shares being issued to eligible employees. On April 27, 2007, our common stock closed above $48.00 per share, which resulted in 4,378 shares being issued to eligible employees.

The issuance of shares under this program has not been registered under the Securities Act of 1933, as amended (1933 Act) in reliance upon SEC releases, including Release No. 6188, dated February 1, 1980, stating that there is no sale of the shares in the 1933 Act sense to employees under this type of program.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

Not Applicable.

ITEM 4.

SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS

Not Applicable.

ITEM 5.

OTHER INFORMATION

Not Applicable.

ITEM 6.

EXHIBITS

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


Exhibit No.		Exhibit Description

10.1		Amended and Restated Revolving Credit Agreement dated March 30, 2007, among ONEOK Partners, L.P., as Borrower, the lenders from time to time party thereto, SunTrust Bank, as Administrative Agent, Wachovia Bank, National Association, as Syndication Agent, and BMO Capital Markets, Barclays Bank PLC, and Citibank, N.A., as Co-Documentation Agents.

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

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

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

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

SIGNATURE

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


	ONEOK, Inc. Registrant

Date: May 2, 2007	By:	/s/ Curtis L. Dinan
		Curtis L. Dinan Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)