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

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

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. YesX 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.

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

On ~~October 31, 2006,~~April 30, 2007, the Company had ~~110,214,774~~111,037,707 shares of common stock outstanding.

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,” ~~“plan,”~~ “expect,” “project,” “intend,” “plan,” “believe,” ~~“should”~~“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 ~~our~~this Quarterly ~~Reports~~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, ~~2005.~~2006.

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

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 ~~and nine~~ months ended ~~September 30, 2006~~March 31, 2007, are not necessarily indicative of the results that may be expected for a ~~twelve-month~~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, ~~2005.~~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, ~~2005,~~2006, except as described below.

~~Consolidation~~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 ~~consolidated financial statements include~~interest rates are reset through auctions that are typically held every 7-35 days, at which time the ~~accounts of ONEOK, Inc. and our subsidiaries over which we have control. All significant intercompany accounts and transactions have been eliminated~~securities can be sold. We invest in ~~consolidation. Investments in affiliates are accounted~~auction-rate securities for ~~on the equity method if we have the ability to exercise significant influence over operating and financial policies~~a portion of our ~~investee. Investments in affiliates are accounted for on the cost method if we do not have the ability to exercise significant influence over operating and financial policies of our investee.~~short-term liquidity needs.

In June 2005, the FASB ratified the consensus reached in EITF Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights” (EITF 04-5), which presumes that a general partner controls a limited partnership and therefore should consolidate the partnership in the financial statements of the general partner. Effective January 1, 2006, we were required to consolidate ONEOK Partners’ operations in our consolidated financial statements, and we elected to use the prospective method. Accordingly, prior period financial statements have not been restated. The adoption of EITF 04-5 did not have an impact on our net income; however, reported revenues, costs and expenses reflect the operating results of ONEOK Partners. Additionally, we record a minority interest liability in our consolidated balance sheet to recognize the 54.3 percent of ONEOK Partners that we do not own. We reflect our 45.7 percent share of ONEOK Partners’ accumulated other comprehensive income at September 30, 2006, in our consolidated accumulated other comprehensive income. The remaining 54.3 percent is reflected as an adjustment to minority interests in consolidated subsidiaries.

~~Share-Based Payment~~ - In December 2004, the FASB issued Statement 123R, “Share-Based Payment,” which requires companies to expense the fair value of share-based payments net of estimated forfeitures. We adopted Statement 123R as of January 1, 2006, and elected to use the modified prospective method. Statement 123R did not have a material impact on our financial statements as we have been expensing share-based payments since our adoption of Statement 148, “Accounting for Stock-Based Compensation - Transition and Disclosure,” on January 1, 2003. Awards granted after the adoption of Statement 123R are expensed under the requirements of Statement 123R, while equity awards granted prior to the adoption of Statement 123R will continue to be expensed under Statement 148. We recognized other income of $1.7 million upon adoption of Statement 123R.

~~Inventory~~ - In September 2005, the FASB ratified the consensus reached in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (EITF 04-13). EITF 04-13 defines when a purchase and a sale of inventory with the same party that operates in the same line of business should be considered a single nonmonetary transaction. EITF 04-13 is effective for new arrangements that a company enters into in periods beginning after March 15, 2006. We completed our review of the applicability of EITF 04-13 to our operations and determined that its impact was immaterial to our consolidated financial statements.

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

Income Taxes - Deferred income taxes are recognized for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The effect on deferred taxes of a change in tax rates is deferred and amortized for operations regulated by the OCC, KCC, RRC and various municipalities in Texas. For all other operations, the effect is recognized in income in the period that includes the enactment date. We continue to amortize previously deferred investment tax credits for ratemaking purposes over the period prescribed by the OCC, KCC, RRC and various municipalities in Texas.

In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109,” which ~~clarified~~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 ~~accordance with Statement 109, “Accounting for Income Taxes.”~~a tax return. FIN 48 requires the recognition of penalties and interest on any unrecognized tax benefits. Our policy is ~~effective for our year beginning January 1, 2007. We are currently reviewing the applicability~~to reflect penalties and interest as part of income tax expense as they become applicable. The adoption of FIN 48 ~~to our operations and its potential~~had an immaterial impact on our consolidated financial statements.

~~Regulation~~ ~~- Our intrastate natural gas transmission pipelines~~We file numerous consolidated and distribution operations are subject to the rate regulation and accounting requirements of the OCC, KCC, RRC and various municipalities in Texas. Other transportation activities are subject to regulation by the FERC. Oklahoma Natural Gas, Kansas Gas Service, Texas Gas Service and portions of our ONEOK Partners segment follow the accounting and reporting guidance contained in Statement 71, “Accounting for the Effects of Certain Types of Regulation.” During the rate-making process, regulatory authorities may require us to defer recognition of certain costs to be recovered through rates over time as opposed to expensing such costs as incurred. This allows us to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. Accordingly, actions of the regulatory authorities could have an effect on the amount recovered from rate payers. Any differenceseparate income tax returns in the ~~amount recoverable~~United States federal jurisdiction and ~~the amount deferred would be recorded as income or expense at the time~~in many state jurisdictions. We also file returns in Canada. No returns are currently under audit and no extensions of ~~the regulatory action. If all or a portion~~statute of ~~the regulated operations becomes no longer subject to the provisions of Statement 71, a write-off of regulatory assets and stranded costs may be required.~~limitations have been granted.

Pension and Postretirement Employee Benefits - In September 2006, the FASB issued Statement 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” which ~~will require~~required us to record a balance sheet liability equal to the difference between our benefit obligations and plan assets. If Statement 158 had been effective at December 31, 2005, we would have been required to record unrecognized losses of $124.8 million and $78.8 million for pension and postretirement benefits, respectively, on our consolidated balance sheet as accumulated other comprehensive loss. Statement 158 iswas effective for our year ending December 31, 2006, except for the measurement date change from September 30 to December 31, which will ~~not go into effect until~~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 ~~2006~~2007 presentation. These reclassifications did not impact previously reported net income or shareholders’ equity. During preparation of our 2005 Annual Report on Form 10-K, we identified and disclosed a software system error impacting our accounting for hedging instruments, and subsequently restated our third quarter 2005 results to reflect an increase in cost of sales and fuel of $13.2 million. It was determined that no other prior periods were affected. For further information, refer to Part II, Item 9A, “Controls and Procedures,” in our Annual Report on Form 10-K for the year ended December 31, 2005.

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. Overland Pass Pipeline~~ Company ~~will build~~for the purpose of building a 750-mile natural gas liquids pipeline from Opal, Wyoming, to the ~~Mid-continent~~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 if customers contract for that capacity.~~facilities. A subsidiary of ONEOK Partners owns 99 percent of the joint venture and will manage the construction project, ~~will~~ advance all costs associated with construction and ~~will~~ operate the pipeline. Within two years of the pipeline becoming operational, Williams ~~has~~will have the option to increase its ownership up to 50 percent by reimbursing ONEOK Partners for its proportionate share of all construction ~~costs and, upon~~costs. If Williams exercises its option to increase its ownership to the full ~~exercise of that option,~~50 percent, Williams would have the option to become operator. ~~Construction~~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 ~~is expected~~ to begin in the ~~summer~~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. In May~~million, excluding AFUDC. During 2006, ONEOK Partners paid ~~$11.4~~$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 ~~$173~~$216 million, excluding AFUDC, to expand its existing fractionation capabilities and the capacity of its natural gas liquids distribution pipelines. ONEOK Partners’ financing for ~~both~~the projects may include a combination of short- or long-term debt or equity. ~~The project requires the approval of various state and regulatory authorities.~~

ONEOK Partners - In April 2006, we sold certain assets comprising our former ~~Gathering~~gathering and ~~Processing, Natural Gas Liquids,~~processing, natural gas liquids, and ~~Pipelines~~pipelines and ~~Storage~~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, ~~its~~ 17.5 percent of the general partner interest in ONEOK Partners for $40 million. This purchase resulted in our owning ~~100 percent of~~ the ~~two~~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 ~~100~~the entire 2 percent ~~of the two percent ONEOK Partners’~~ general partner ~~interest.~~interest and control the partnership. Our overall interest in ONEOK Partners, including the ~~two~~2 percent general partner interest, has increased to 45.7 percent. ONEOK Partners recorded a $63.6 million purchase price adjustment to the acquired assets related to a working capital settlement, which is reflected as an increase to the value of the Class B units. In the third quarter of 2006, the working capital settlement was finalized, subject to approval by ONEOK Partners’ Audit Committee, resulting in no material adjustments.

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, ~~with~~and an affiliate of TransCanada ~~becoming~~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 no longer consolidates Northern Border Pipeline as of January 1, 2006. Instead, its~~Partners’ interest in Northern Border Pipeline is accounted for as an investment under the equity ~~method. This change does not affect previously reported net income or shareholders’ 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 ~~remaining 66~~²/66-2/3 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~~included Guardian Pipeline in our consolidated financial statements. This change was accounted for on a retroactive basis to January 1, 2006. ~~Prior to the transaction, ONEOK Partners’ 33~~¹/3 ~~percent interest in Guardian Pipeline was accounted for as an investment under the equity method.~~

~~Acquisition of Koch Industries Natural Gas Liquids Business~~ - In July 2005, we completed our acquisition of the natural gas liquids businesses owned by Koch Industries, Inc. (Koch) for approximately $1.33 billion, net of working capital and cash received. This transaction included Koch Hydrocarbon, L.P.’s entire Mid-continent natural gas liquids fractionation business; Koch Pipeline Company, L.P.’s natural gas liquids pipeline distribution systems; Chisholm Pipeline Holdings, Inc., which has a 50 percent ownership interest in Chisholm Pipeline Company; MBFF, L.P., which owns an 80 percent interest in a 160,000 Bbl/d

fractionator at Mont Belvieu, Texas; and Koch VESCO Holdings, L.L.C., an entity that owns a 10.2 percent interest in Venice Energy Services Company, L.L.C. These assets are included in our consolidated financial statements beginning on July 1, 2005.

The unaudited pro forma information in the table below presents a summary of our consolidated results of operations as if our acquisition of the Koch natural gas liquids businesses had occurred at the beginning of the periods presented. The results do not necessarily reflect the results that would have been obtained if our acquisition had actually occurred on the dates indicated or results that may be expected in the future.

In September 2005, we completed the sale of our Production segment to TXOK Acquisition, Inc. for $645 million, before adjustments, and recognized a pre-tax gain on the sale of approximately $240.3 million. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold. The proceeds from the sale were used to reduce debt. Our Board of Directors authorized management to pursue the sale during July 2005, which resulted in our Production segment being classified as held for sale beginning July 1, 2005.

~~Additionally, 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.

~~These components~~This component of our business ~~are~~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 ~~all periods shown~~the three months ended March 31, 2006, relating to ~~our Production segment and~~ our power generation business are reflected as discontinued operations.

~~The amounts of revenue, costs and income taxes reported in discontinued operations are as follows.~~

~~The following table discloses the major classes of discontinued assets and liabilities included in our consolidated balance sheets for the periods indicated.~~

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 induring 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.~~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 ~~reclassified into~~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, ~~2005,~~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 ~~nine~~three months ended ~~September 30, 2006,~~March 31, 2007, for all terminated swaps was ~~$7.6 million. The~~$2.6 million, and the remaining net savings for all terminated swaps will be recognized over the ~~periods set forth in~~following periods.

   ONEOK
ONEOK
Partners    Total
   (Millions of dollars)
Remainder of 2006
   $ 1.7    $ 0.8    $ 2.5
2007
   6.6    3.4    10.0
2008
   6.6    3.6    10.2
2009
   5.6    3.8    9.4
2010
   5.5    4.0    9.5
Thereafter
   15.3    0.8    16.1

~~Currently,~~interest on $490 million of ~~fixed rate~~fixed-rate debt is swapped to ~~floating. Interest on the~~ floating using interest rate ~~debt~~swaps. The floating-rate is based on both the three- and six-month LIBOR, depending upon the swap. Based on the actual performance through ~~September 30, 2006,~~March 31, 2007, the weighted average interest rate ~~on the $490 million of debt~~ increased from 6.64 percent to ~~7.16~~6.79 percent. At ~~September 30, 2006,~~March 31, 2007, we recorded a net liability of ~~$13.9~~$11.9 million to recognize the interest rate swaps at fair value. Long-term debt was decreased by ~~$13.9~~$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 ~~was a $1.0~~were losses of $2.5 million ~~gain~~ and ~~a $1.7~~$5.3 million ~~gain~~ for the three months ended ~~September 30,~~March 31, 2007 and 2006, respectively, which were recorded as cost of sales and ~~2005, respectively. The ineffectiveness related to these hedges was an $8.3 million loss and a $1.4 million gain for the nine months ended September 30, 2006 and 2005, respectively.~~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 ~~September 30, 2006,~~March 31, 2007, includes ~~gains~~losses of approximately ~~$47.8~~$8.3 million, net of tax, related to these hedges that will be realized within the next 3226 months. If prices remain at current levels, we will recognize ~~$62.7~~$9.0 million in net ~~gains~~losses over the next 12 months, and we will recognize net ~~losses~~gains of ~~$14.9~~$0.7 million thereafter.

~~Net gains and~~ In accordance with Statement 133, the actual losses that are reclassified ~~out~~into earnings will be based on the referenced floating price at each designated pricing period, along with the realization of ~~accumulated other comprehensive income (loss) to operating revenues~~the gains or ~~cost of sales and fuel when~~losses on the ~~anticipated purchase or sale occurs. Ineffectiveness~~ related ~~to our cash flow hedges resulted~~physical volumes, which are not reflected in ~~a gain of approximately $4.5 million and $14.0 million for~~ the three and nine months ended September 30, 2006, respectively. Ineffectiveness related to these cash flow hedges for the three and nine months ended September 30, 2005, resulted in a loss of approximately $7.0 million and a loss of approximately $7.1 million, respectively. There were no losses during the nine months ended September 30, 2006 and 2005, respectively, due to the discontinuance of cash flow hedge treatment.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’s~~segment will recognize $2.6 million in net losses, all of which will be recognized over the next 12 months.

~~Our Distribution segment also uses derivative instruments from time~~reclassified out of accumulated other comprehensive income (loss) to ~~time. Gains~~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 ~~associated with these derivative instruments are included in,~~during the three months ended March 31, 2007 and ~~recoverable through,~~2006, due to the ~~monthly purchased gas adjustment. At September 30, 2006, Kansas Gas Service had derivative instruments in place to~~discontinuance of cash flow hedge the cost of natural gas purchases for 5.6 Bcf, which represents part of its gas purchase requirements for the 2006/2007 winter heating months. At September 30, 2006, Texas Gas Service had derivative instruments in place to hedge the cost of natural gas purchases for 1.1 Bcf, which represents part of its gas purchase requirements for the 2006/2007 winter heating months.

Carrying Amounts - The ~~following table reflects the changes in the carrying~~ amount of goodwill ~~for the periods indicated.~~

~~Goodwill additions in~~recorded on our ~~ONEOK Partners segment include $7.5 million related to the consolidation~~Consolidated Balance Sheets as of ~~Guardian Pipeline, of which $5.7 million relates to the purchase of the additional 66 2/3 percent interest,~~March 31, 2007, and ~~$2.1 million related to the incremental one percent acquisition in an affiliate that~~December 31, 2006, was ~~previously accounted for under the equity method. Following ONEOK Partners’ acquisition of the additional one percent interest, we began consolidating the entity.~~

~~Goodwill adjustments in our ONEOK Partners segment include an $8.4 million reduction related to the Black Mesa Pipeline impairment, offset by $6.4 million in purchase price adjustments.~~

In accordance with EITF 04-5, we consolidated our ONEOK Partners segment beginning January 1, 2006. The adoption of EITF 04-5 resulted in $152.8 million of ONEOK Partners’ goodwill being included in our consolidated balance sheet and $32.0 million of goodwill that was previously recorded as our equity investment in ONEOK Partners.$600.7 million.

Equity Method Goodwill - For the investments we account for under the equity method, ~~of accounting,~~ the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill. ~~At September 30, 2006, $185.6 million of equity method goodwill was included in our investment~~Investment in unconsolidated affiliates on our ~~consolidated balance sheet.~~

~~Impairment Test~~ ~~- We adopted Statement 142 “Goodwill and Other Intangible Assets,” on January 1, 2002, with a January 1 annual~~accompanying Consolidated Balance Sheets includes equity method goodwill ~~impairment testing date. In the third quarter~~ of ~~2006, we changed our annual goodwill impairment testing date to July 1. Prior to the change we had segments, and companies within segments, performing the annual goodwill impairment test~~$185.6 million as of ~~the fourth quarter~~March 31, 2007, and ~~as of January 1. The multiple testing dates were the result of:~~December 31, 2006.

~~the consolidation of ONEOK Partners, in accordance with EITF 04-5, which had a fourth quarter annual goodwill impairment testing date;~~

~~our sale of certain assets comprising our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments to ONEOK Partners in April 2006, which resulted in the~~

Intangible Assets

Our ONEOK Partners segment including assets with two impairment testing dates since our former Gathering and Processing and Pipelines and Storage segments used a January 1 testing date, while all the legacy ONEOK Partners assets used a fourth quarter testing date; and

~~our former Natural Gas Liquids segment was comprised~~had $293.2 million of ~~assets primarily acquired in a July 2005 acquisition from Koch and due to the recent acquisition, no date had been selected for testing.~~

We believe that this change in accounting principle is preferable because (1) the test would be performed at the same time for all our segments, (2) performing the test as of the first day of the third quarter allows adequate time to complete the test while still providing time to report the impact of the test in our periodic filings for the third quarter, and (3) the third quarter is outside the normal operating cycle of most of our segments and coincides with our annual budget process, which results in more detailed budgeting and forecasting information available for use in the impairment analysis. There were no impairment charges resulting from the July 1, 2006, impairment testing, and no events indicating an impairment has occurred subsequent to that date.

~~Our~~ intangible assets ~~primarily relate~~related to contracts acquired through our acquisition of the natural gas liquids businesses from Koch, which are ~~recorded in our ONEOK Partners segment. Those contracts 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 ~~and nine~~ months ended ~~September 30,~~March 31, 2007 and 2006 was $1.9

~~million and $5.7 million, respectively.~~ million. The following table reflects the gross carrying amount and accumulated amortization of ~~intangibles~~intangible assets at ~~September 30, 2006~~March 31, 2007 and December 31, ~~2005.~~2006.

The adoption of EITF 04-5 resulted in the addition of $123.0 million of intangibles, which was previously recorded as our equity investment in ONEOK Partners. An additional $32.5 million was recorded related to the general partner incentive distribution rights acquired through the purchase of TransCanada’s 17.5 percent general partner interest. These intangibles have an indefinite life and accordingly, are not subject to amortization, but are subject to impairment testing.

The tables below show the gross amount of comprehensive income (loss) and related tax (expense) or 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.

Stock Repurchase Plan - A total of 15 million shares have been repurchased to date pursuant to a plan approved by our Board of Directors. The plan, originally approved by our Board of Directors in January 2005, was extended in November 2005 to allow us to purchase up to a total of 15 million shares of our common stock on or before November 2007. 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, which completed the plan approved by our Board of Directors.~~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 ~~will purchase~~purchased shares in the open market to settle its short position. Our repurchase iswas 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 ~~can be~~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 ~~ONEOK~~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.” ~~At September 30, 2006, we did not owe UBS~~In February 2007, the forward purchase contract settled for a ~~price adjustment.~~cash payment of $20.1 million, which was recorded in equity. We currently have no remaining shares ~~available~~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, ~~2006, May 1, 2006 and July 31, 2006,~~2007, were ~~$0.28~~$0.34 per ~~share, $0.30 per share and $0.32 per share, respectively.~~share. Additionally, a quarterly dividend of ~~$0.32~~$0.34 per share was declared in ~~October,~~April, payable in the ~~fourth~~second quarter of ~~2006.~~

~~Equity Units~~ - On February 16, 2006, we successfully settled our 16.1 million equity units with 19.5 million shares of our common stock. Of this amount, 8.3 million shares were issued from treasury stock and approximately 11.2 million shares were newly issued. Holders of the equity units received 1.2119 shares of our common stock for each equity unit they owned. The number of shares that we issued for each stock purchase contract was determined based on our average closing price over the 20 trading day period ending on the third trading day prior to February 16, 2006. With the settlement, we received $402.4 million in cash, which was used to pay down our short-term bridge financing agreement.2007.

~~ONEOK Short-Term Bridge Financing Agreement~~General - On ~~July~~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 ~~2005, we borrowed $1.0 billion under a new short-term bridge financing agreement~~(from 4.75 to ~~assist in financing our acquisition~~1), (v) increased the swingline sub-facility commitments from $15 million to $50 million and (vi) changed the permitted amount of ~~assets~~subsidiary indebtedness from ~~Koch. We funded the remaining acquisition cost through our commercial paper program. During the three months ended March 31, 2006, we repaid the facility in full, and it was terminated according~~$35 million to ~~its terms.~~10 percent of ONEOK Partners’ consolidated indebtedness.

~~ONEOK Five-Year Credit Agreement~~ ~~- In April 2006, we amended ONEOK’s 2004~~Except as discussed above, our $1.2 billion five-year credit agreement, to accommodate the transaction with ONEOK Partners. This amendment included changes to the material adverse effect representation, the burdensome agreement representation and the covenant regarding maintenance of control of ONEOK Partners.

~~In July 2006, we~~as amended and restated ~~ONEOK’s 2004 $1.2 billion five-year credit agreement. The amended agreement includes revised pricing, an extension~~in 2006, and ONEOK Partners’ 2007 Partnership Credit Agreement contain typical covenants as discussed in Note H of the ~~maturity date from 2009~~Notes to ~~2011, an option for additional extensions of the maturity date with the consent of the lenders, and an option to request an increase~~Consolidated Financial Statements in ~~the commitments of the lenders of up to an additional $500 million. The interest rates applicable to extensions of credit under this agreement are based, at~~ our ~~election,~~Annual Report on ~~either (i) the higher~~

~~of prime or one-half of one percent above the Federal Funds Rate, which is the rate that banks charge each other~~Form 10-K for the ~~overnight borrowing of funds, or (ii) the Eurodollar rate plus a set number of basis points based on our current long-term unsecured debt ratings.~~

~~Under the five-year credit agreement, ONEOK is required to comply with certain financial, operational~~year ended December 31, 2006. At March 31, 2007, we and ~~legal covenants. Among other things, these requirements include:~~

~~a $500 million sublimit for the issuance of standby letters of credit,~~

~~a limitation on our debt-to-capital ratio, which may not exceed 67.5 percent at the end of any calendar quarter,~~

~~a requirement that we maintain the power to control the management and policies of~~ ONEOK Partners ~~and~~

~~a limit on new investments in master limited partnerships.~~

~~The debt covenant calculations in ONEOK’s five-year credit agreement exclude the debt of ONEOK Partners. At September 30, 2006, we had no borrowings outstanding under this agreement.~~

ONEOK’s five-year credit agreement also contains customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in our businesses, changes in the nature of our businesses, transactions with affiliates, the use of proceeds and a covenant that prevents us from restricting our subsidiaries’ ability to pay dividends. At September 30, 2006, ONEOK waswere in compliance with ~~these~~all covenants.

At ~~September 30, 2006, ONEOK~~March 31, 2007, we had ~~$88.4~~$37.9 million in letters of credit ~~no commercial paper outstanding~~issued and no ~~loans~~borrowings outstanding under ~~the Credit Agreement.~~

~~ONEOK Partners Five-Year Credit Agreement~~ ~~- In March 2006, ONEOK Partners entered into a five-year $750 million amended~~our various credit agreements, and ~~restated revolving credit agreement (2006 Partnership Credit Agreement) with certain financial institutions and terminated its $500 million revolving credit agreement. At September 30, 2006,~~ ONEOK Partners had ~~$15~~$10 million in letters of credit ~~outstanding~~issued, and no borrowings outstanding under ~~the 2006~~its 2007 Partnership Credit Agreement.

~~Under the 2006 Partnership Credit Agreement, ONEOK Partners is required to comply with certain financial, operational and legal covenants. Among other things, these requirements include:~~

~~maintaining a ratio of EBITDA (net income plus interest expense, income taxes, and depreciation and amortization) to interest expense of greater than 3 to 1, and~~

~~maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA adjusted for pro forma operating results of acquisitions made during the year) of no more than 4.75 to 1.~~

If ONEOK Partners consummates one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will be increased to 5.25 to 1 for two calendar quarters following the acquisitions. Upon any breach of these covenants, amounts outstanding under the 2006 Partnership Credit Agreement may become immediately due and payable. At September 30, 2006, ONEOK Partners was in compliance with these covenants.

~~ONEOK Partners Bridge Facility~~ - In April 2006, ONEOK Partners entered into a $1.1 billion 364-day credit agreement (Bridge Facility) with a syndicate of banks and borrowed $1.05 billion under this agreement to finance a portion of its purchase of certain assets comprising our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments. In September 2006, ONEOK Partners repaid the amounts outstanding under the Bridge Facility using proceeds from the issuance of senior notes, which resulted in the Bridge Facility being terminated according to its terms. See Note I for further discussion regarding the issuance of senior notes.

~~The following table sets forth our long-term debt for the periods indicated.~~

~~The aggregate maturities of long-term debt outstanding for the remainder of 2006 and for years ending December 31, 2007 through 2010 are shown below.~~

Additionally, $184.4 million of ONEOK’s debt is callable at par at our option from now until maturity, which is 2019 for $92.6 million and 2028 for $91.8 million. Certain debt agreements have negative covenants that relate to liens and sale/leaseback transactions.

~~ONEOK Partners Debt Issuance~~ - In September 2006, ONEOK Partners completed an underwritten public offering of (i) $350 million aggregate principal amount of 5.90 percent Senior Notes due 2012 (the “2012 Notes”), (ii) $450 million aggregate principal amount of 6.15 percent Senior Notes due 2016 (the “2016 Notes”) and (iii) $600 million aggregate principal amount of 6.65 percent Senior Notes due 2036 (the “2036 Notes” and collectively with the 2012 Notes and the 2016 Notes, the “Notes”). ONEOK Partners registered the sale of the Notes with the SEC pursuant to a registration statement filed on September 19, 2006.

The Notes are guaranteed on a senior unsecured basis by the Intermediate Partnership. The guarantee ranks equally in right of payment to all of the Intermediate Partnership’s existing and future unsecured senior indebtedness.

ONEOK Partners may redeem the Notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount of the Notes, plus accrued interest, unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the relevant Notes plus accrued and unpaid interest. The Notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and effectively junior to all of the existing debt and other liabilities of its non-guarantor subsidiaries. The Notes are non-recourse to us.

The net proceeds from the Notes of approximately $1.39 billion, after deducting underwriting discounts and commissions and expenses, but before offering expenses, were used to repay all of the amounts outstanding under the Bridge Facility and to repay $335 million of indebtedness outstanding under the 2006 Partnership Credit Agreement. The terms of the Notes are governed by the Indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., as trustee, as supplemented by the First Supplemental Indenture (with respect to the 2012 Notes), the Second Supplemental Indenture (with respect to the 2016 Notes) and the Third Supplemental Indenture (with respect to the 2036 Notes), each dated September 25, 2006. The Indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The Indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and sell and lease back its property.

The 2012 Notes, 2016 Notes and 2036 Notes will mature on April 1, 2012, October 1, 2016 and October 1, 2036, respectively. ONEOK Partners will pay interest on the Notes on April 1 and October 1 of each year. The first payment of interest on the Notes will be made on April 1, 2007. Interest on the Notes accrues from September 25, 2006, which was the issuance date of the Notes.

~~Guardian Pipeline Master Shelf Agreement~~ - ONEOK Partners’ acquisition of the remaining 66 2/3 percent interest in Guardian Pipeline resulted in the inclusion of $148.6 million of long-term debt in our consolidated balance sheet. These notes were issued under a master shelf agreement with certain financial institutions. Principal payments are due annually through 2022. Interest rates on the notes range from 7.61 percent to 8.27 percent, with an average rate of 7.85 percent.

Guardian Pipeline’s Master Shelf agreement contains financial covenants that require the maintenance of a ratio of (1) EBITDAR (net income plus interest expense, income taxes, operating lease expense and depreciation and amortization) to the sum of interest expense plus operating lease expense of not less than 1.5 to 1 and (2) total indebtedness to EBITDAR of not greater than 6.75 to 1. Upon any breach of these covenants, all amounts outstanding under the master shelf agreement may become due and payable immediately. Beginning in December 2007, the rate of total indebtedness to EBITDAR may not be greater than 5.75 to 1. At September 30, 2006, Guardian Pipeline was in compliance with its financial covenants.

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

Contributions - For the ~~nine~~three months ended ~~September 30, 2006,~~March 31, 2007, contributions of ~~$1.1 million and $14.6~~$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, respectively. For 2006, we anticipate total contributions to~~plan. Additionally, the 2007 expected benefit payments from our ~~defined benefit pension plan and~~ postretirement benefit plan are estimated to be $1.5 million and $17.3 million, respectively. Our pay-as-you-go other postretirement benefit plan costs were $8.8 million for the nine months ended September 30, 2006, and we expect our total pay-as-you-go costs for 2006 to be $14.0$22.1 million.

~~Operating Leases and Agreements~~ - Our operating leases include a gas processing plant, office buildings, vehicles and equipment. The following table sets forth the future minimum lease payments as of September 30, 2006 under non-cancelable operating leases for each of the following years.

~~The amounts in the ONEOK column above include the minimum lease payments relating to the lease of a gas processing plant for which we have a liability as a result of uneconomic lease terms.~~

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 ~~the~~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~~clean-up costs, which could materially affect our results of operations and cash flows. In addition, emission controls required under the ~~Federal~~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 ~~eleven~~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 ~~three sites.~~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 ~~$5.8~~$6.6 million and have accrued an additional ~~$6.0~~$5.4 million related to the sites where we have commenced or will soon commence remediation. ~~We have recorded estimates~~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.

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 ~~business segments~~Distribution segment is comprised of regulated public utilities, and ~~the~~portions of our ONEOK Partners segment are regulated.

Accounting Policies - The accounting policies of ~~our business~~the segments are the same as those described in Note A and Note M ~~and~~of the ~~Summary of Significant Accounting Policies~~Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, ~~2005, with the exception of the segments described below. Our Distribution segment is comprised of regulated public utilities.~~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 ~~have~~had no single external customer from which we received 10 percent or more of our consolidated gross ~~revenues for the periods covered by this Quarterly Report on Form 10-Q.~~revenues.

Effective January 1, 2006, we were required to consolidate ONEOK Partners’ operations in our consolidated financial statements under EITF 04-5 and we elected to use the prospective method. 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. These former segments are now included in our ONEOK Partners segment. All periods presented have been restated to reflect this change. Our ONEOK Partners segment gathers, processes, transports and stores natural gas; gathers, treats, stores, and fractionates NGLs; and provides NGL gathering and distribution services. The primary customers for our ONEOK Partners segment include major and independent oil and gas production companies, gathering and processing companies, petrochemical and refining companies, natural gas producers, marketers, industrial facilities, local distribution companies and electric power generating plants.

In September 2005, we completed the sale of our Production segment. Additionally, in the third quarter of 2005, we made the decision to sell our Spring Creek power plant and exit the power generation business. The sale was completed on October 31, 2006. These components of our business are accounted for as discontinued operations in accordance with Statement 144. Our Production segment is included in our Other segment in the 2005 tables below, while our power generation business is included in our Energy Services segment in the tables below.

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

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

~~Cash paid for interest includes swap terminations and treasury rate-lock terminations of $22.6 million for the nine months ended September 30, 2005.~~

Effective January 1, 2006, we adopted Statement 123R. See Note A for additional information. We used a three percent forfeiture rate for all awards outstanding based on historical forfeitures under our share-based payment plans. We use a combination of issuances from treasury stock and repurchases in the open market to satisfy our share-based payment obligations.

The compensation cost expensed for our share-based payment plans described below was $7.8 million for the nine months ended September 30, 2006, net of a $3.0 million tax benefit. No compensation cost was capitalized for the nine months ended September 30, 2006.

Cash received from the exercise of awards under all share-based payment arrangements was $6.6 million for the nine months ended September 30, 2006. The actual tax benefit realized for the anticipated tax deductions of the exercise of share-based payment arrangements totaled $2.6 million for the nine months ended September 30, 2006. No cash was used to settle awards granted under share-based payment arrangements.

The ONEOK, Inc. Long-Term Incentive Plan (the LTIP), the ONEOK, Inc. Equity Compensation Plan (Equity Compensation Plan) and the ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors (the DSCP) are described in Note P in our Annual Report on Form 10-K for the year ended December 31, 2005.

The total fair value of stock options vested during the nine months ended September 30, 2006, was $4.0 million. The following table sets forth the stock option activity for employees and non-employee directors for the periods indicated.

Stock Options Outstanding Stock Options Exercisable
Range of
Exercise Prices
Number
of Awards Remaining
Life (yrs) Weighted
Average
Exercise Price
Aggregate
Intrinsic
Value
(in 000’s)
Number
of Awards Remaining
Life (yrs) Weighted
Average
Exercise Price
  Aggregate
Intrinsic Value
      (in 000’s)
$14.58 to $21.87
693,270 5.33 $ 17.06 $ 14,371 691,728 5.33 $ 17.06 $ 14,340
$21.88 to $32.82
565,688 4.15 $ 25.86 $ 6,749 497,305 4.18 $ 24.98 $ 6,370
$32.83 to $38.83
337,481 3.80 $ 35.63 $ 729 216,037 3.78 $ 34.52 $ 706

The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value, based on our closing stock price of $37.79 as of September 30, 2006, that would have been received by the option holders had all option holders exercised their options as of September 30, 2006.

~~The fair value of each option granted was estimated on the date of grant based on the Black-Scholes model using the assumptions in the table below.~~

The expected life of outstanding options ranged from one to ten years based upon experience to date and the make-up of the optionees. As of September 30, 2006, the amount of unrecognized compensation cost related to nonvested stock options was not material. The following table sets forth various statistics relating to our stock option activity.

Awards granted in 2006 and 2003 vest over a three-year period and entitle the grantee to receive shares of our common stock. Awards granted in 2005 and 2004 entitle the grantee to receive two-thirds of the grant in our common stock and one-third of the grant in cash. The equity awards are measured at fair value as if they were vested and issued on the grant date, generally reduced by expected dividend payments, and adjusted for estimated forfeitures.The portion of the grants that are settled in cash are classified as liability awards with fair value based on the fair market value of our common stock, reduced by expected dividend payments and adjusted for estimated forfeitures, at each reporting date. The total fair value of shares vested during the nine months ended September 30, 2006, was $5.7 million.

~~The following table sets forth activity for the restricted stock equity awards.~~

~~The following table sets forth activity for the restricted stock liability awards.~~

As of September 30, 2006, there was $4.0 million of total unrecognized compensation cost related to our nonvested restricted stock awards, which is expected to be recognized over a weighted-average period of 1.2 years. The following table sets forth various statistics relating to our restricted stock awards.

If paid the performance unit awards granted in 2005 and 2004 entitle the grantee to receive two-thirds of the grant in shares of our common stock and one-third of the grant in cash, while awards granted in 2003 entitle the grantee to receive common stock only. These awards vest over a three-year period. The fair values of these performance units that are classified as equity awards were calculated as of the date of grant and remain fixed as equity units upon adoption of Statement 123R. The fair values of the one-third liability portion of the performance units are estimated at each reporting date based on a Monte Carlo model.

If paid the awards granted in 2006 entitle the grantee to receive the grant in shares of our common stock. Under Statement 123R, our 2006 performance unit awards are equity awards with a market based condition, which results in the compensation cost for these awards being recognized over the requisite service period, provided that the requisite service period is rendered, regardless of when, if ever, the market condition is satisfied. The fair value of these performance units was estimated on the grant date based on a Monte Carlo model. The compensation expense on these awards will only be adjusted for changes in forfeitures.

~~The total fair value of shares vested during the nine months ended September 30, 2006, was $4.9 million.~~

~~The following table sets forth activity for the performance unit equity awards.~~

~~The following table sets forth the assumptions used in the valuation of the 2006 grants.~~

~~The following tables set forth activity for the performance unit liability awards and the assumptions used in the valuations.~~

As of September 30, 2006, there was $14.1 million of total unrecognized compensation cost related to the nonvested performance unit awards, which is expected to be recognized over a weighted-average period of 1.5 years. The following table sets forth various statistics relating to our performance units.

~~Investments in Unconsolidated Affiliates~~ ~~- The following table sets forth our investments in unconsolidated affiliates for the periods indicated.~~

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.

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

We compute earnings per common share (EPS) as described in Note QR of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, ~~2005.~~2006.

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

There were ~~49,775~~18,403 and ~~21,681~~438,924 option shares excluded from the calculation of diluted EPS for the three months ended ~~September 30,~~March 31, 2007, and 2006, ~~and 2005,~~ respectively, since their inclusion would have been antidilutive for each period. There were 276,666 and 48,062 option shares excluded from the calculation of diluted EPS for the nine months ended September 30, 2006 and 2005, respectively, since their inclusion would be antidilutive for each period.

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 ~~with~~are no longer subordinated to distributions on our common units, and generally have the same ~~distribution~~voting rights as ~~the outstanding~~our common ~~units, but which have limited voting rights and which are subordinated to the common units with respect to payment of minimum quarterly distributions.~~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.

Cash Distributions - Under the ONEOK Partners’ partnership agreement, distributions are made to ~~their~~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 ~~98.0~~98 percent to limited partners and ~~2.0~~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 ~~we received for~~related to the periods ~~ended September 30, 2006 and 2005.~~

The quarterly distributions paid by ONEOK Partners to limited partners in the first ~~second and third~~ quarters of March 31, 2007 and 2006 were $0.98 per unit and $0.80 per unit, ~~$0.88 per unit and $0.95 per unit,~~ respectively.

In ~~October 2006,~~April 2007, ONEOK Partners declared a cash distribution of ~~$0.97~~$0.99 per unit payable in the ~~fourth~~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 ~~process natural gas at~~ the Bushton ~~Kansas processing plant (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 ~~will~~ provide at the Bushton Plant through 2012. In exchange, ~~for such services,~~ ONEOK Partners ~~will pay~~pays us for all direct costs and expenses of ~~operating~~ 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 ~~benefit~~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 ~~through a~~by the modified Distrigas method, a method using a combination of ratios ofthat include gross plant and investment, operating income and wages.

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

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.

The following discussion highlights some of our achievements and significant issues affecting us this past quarter. Please refer to the Financial and Operating ~~income~~Results section of Management’s Discussion and Analysis of Financial Condition and Results of Operation and the Financial Statements for ~~our third quarter~~a complete explanation of the following items. As a result of the April 2006 was $119.5 million, an increase of $9.5 million, or nine percent, compared with the same period in 2005. For the first nine months of 2006, operating income was $659.0 million, an increase of $310.4 million, or 89 percent, from the same period last year. The increase in operating income, excluding the gain on sale of assets, was $194.5 million for the nine-month period. The gain on sale of assets primarily relates totransactions, our ONEOK ~~Partners (formerly Northern Border Partners, L.P.) segment’s sale of its 20 percent partnership interest in~~Partners’ segment deconsolidated Northern Border Pipeline and consolidated Guardian Pipeline retroactive to ~~TC PipeLines, an affiliate~~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 ~~TransCanada, in April 2006.~~these transactions.

Diluted earnings per share of common stock from continuing operations (EPS) ~~decreased~~increased to ~~21 cents~~$1.36 for the ~~third quarter of 2006 from 41 cents~~three months ended March 31, 2007, compared with $1.17 for the same period in ~~2005. For~~2006. During the ~~nine-month period, EPS~~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 ~~$2.02~~$328.3 million from ~~$1.49~~$270.4 million for the same period ~~last year.~~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.

In April 2006, we sold certain assets comprising our former ~~Gathering~~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. We also purchased the remaining 17.5 percent general partner interest, which increased our general partner interest to 100 percent of the two percent general partner interest in ONEOK Partners. Prior periods have been restated to show our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments as part of our newly formed ONEOK Partners segment. The legacy operations of ONEOK Partners accounted for the 2006 operating income increases in our ONEOK Partners segment since we consolidated ONEOK Partners beginning January 1, 2006, in accordance with EITF Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights.” See Impact of New Accounting Standards on page 37 for additional information on the consolidation of ONEOK Partners. In addition, the acquisition of theprocessing, natural gas liquids, businesses owned by Koch Industries, Inc. (Koch) in July 2005, contributed to operating income increases in our ONEOK Partners segment. Our legacy operations in the ONEOK Partners segment benefited from strong commodity prices, wider gross processing spreads and ~~increased natural gas transportation revenues. These increases were slightly offset by decreases in our ONEOK Partners segment resulting from the sale of natural gas gathering~~pipelines and ~~processing assets located in Texas in December 2005.~~

Operating income for our Energy Services segment decreased $20.5 million for the three-month period and increased $70.7 million for the nine-month period. The decrease for the three-month period was primarily related to lower storage and marketing margins resulting from reduced storage opportunities in the third quarter 2006 compared with the same period in 2005. The increase for the nine-month period was primarily due to the effect of improved natural gas basis differentials on transportation contracts.

ONEOK Partners declared an increase in its cash distribution to $0.97 per unit in October 2006, an increase of approximately two percent over the $0.95 paid in the third quarter, an increase of approximately 10 percent over the $0.88 paid in the second quarter and an increase of approximately 21 percent over the $0.80 paid in the first quarter.

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. Overland Pass Pipeline Company will build 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 if customers contract for that capacity. A subsidiary of ONEOK Partners owns 99 percent of the joint venture, will manage the construction project, will advance all costs associated with construction, and will operate the pipeline. Within two years of the pipeline becoming operational, Williams has the option to increase its ownership up to 50 percent by reimbursing ONEOK Partners its proportionate share of all construction costs and, upon full exercise of that option, Williams would have the option to become operator. Construction of the pipeline is expected to begin in the summer 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 estimated to cost approximately $433 million. In May 2006, ONEOK Partners paid $11.4 million to Williams for reimbursement of initial capital expenditures. In addition, ONEOK Partners plans to invest approximately $173 million to expand its existing fractionation capabilities and the capacity of its natural gas liquids distribution pipelines. ONEOK Partners’ financing for both projects may include a combination of short- or long-term debt or equity. The project requires the approval of various state and regulatory authorities.

~~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, ~~its~~ 17.5 percent of the general partner interest in ONEOK Partners for $40 million. This purchase resulted in our owning ~~100 percent of~~ the ~~two~~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 ~~100~~the entire 2 percent ~~of the two percent ONEOK Partners’~~ general partner ~~interest.~~interest and control the partnership. Our overall interest in ONEOK Partners, including the ~~two~~2 percent general partner interest, has increased to 45.7 percent. ONEOK Partners recorded a $63.6 million purchase price adjustment to the acquired assets related to a working capital settlement, which is reflected as an increase to the value of the Class B units. In the third quarter of 2006, the working capital settlement was finalized, subject to approval by ONEOK Partners’ Audit Committee, resulting in no material adjustments.

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, ~~with~~and an affiliate of TransCanada ~~becoming~~became operator of the pipeline in April 2007. As a result of this transaction, ONEOK ~~Partners no longer consolidates Northern Border Pipeline as of January 1, 2006. Instead, its~~Partners’ interest in Northern Border Pipeline is accounted for as an investment under the equity ~~method. This change does not affect previously reported net income or shareholders’ 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 ~~remaining 66 2/~~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. ~~Prior to the transaction, ONEOK Partners’ 33~~

¹/3 ~~percent interest in Guardian Pipeline was accounted for as an investment under the equity method.~~CAPITAL PROJECTS

Overland Pass Pipeline - In ~~December 2005, we sold our natural gas gathering and processing assets located in Texas to~~May 2006, a subsidiary of ~~Eagle Rock Energy, Inc. for approximately $527.2 million and recorded a pre-tax gain of $264.2 million.~~

~~In October 2005, we~~ONEOK Partners entered into an agreement with a subsidiary of The Williams Companies, Inc. (Williams) 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. The financial information related to the properties held for sale is reflected asform a ~~discontinued component in this Quarterly Report on Form 10-Q. All periods presented have been restated to reflect the discontinued component.~~

In September 2005, we completed the sale of our Production segment to TXOK Acquisition, Inc. for $645 million, before adjustments, and recognized a pre-tax gain on the sale of approximately $240.3 million. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold. The proceeds from the sale were used to reduce debt. The financial information related to the properties sold is reflected as a discontinued component in this Quarterly Report on Form 10-Q. All periods presented have been restated to reflect the discontinued component.

In July 2005, we completed our acquisition of the natural gas liquids businesses owned by Koch for approximately $1.33 billion, net of working capital and cash received. This transaction included Koch Hydrocarbon, L.P.’s entire Mid-continent natural gas liquids fractionation business; Kochjoint venture called Overland Pass Pipeline Company ~~L.P.’s~~for the purpose of building a 750-mile natural gas liquids pipeline ~~distribution systems; Chisholm Pipeline Holdings, Inc.,~~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 ~~has a~~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 ~~interest~~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 ~~Chisholm Pipeline Company; MBFF, L.P., which owns an 80 percent~~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 ~~fractionator at~~of raw natural gas liquids and will interconnect with our existing Mid-Continent infrastructure and our fractionation facility in Mont Belvieu, ~~Texas;~~Texas, and ~~Koch VESCO Holdings,~~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., ~~an entity~~a subsidiary of ONEOK Partners, announced that ~~owns a 10.2 percent interest~~Fort Union Gas Gathering will double its existing gathering pipeline capacity by adding 148 miles of new gathering lines resulting in ~~Venice Energy Services Company, L.L.C. These assets are included~~649 MMcf/d of additional capacity in ~~our consolidated financial statements beginning on July 1, 2005.~~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.

Several regulatory initiatives impacted the earnings and future earnings potential for our Distribution ~~segment and our ONEOK Partners~~ segment. See discussion of our Distribution segment’s regulatory initiatives ~~beginning~~ on page ~~44 and discussion of our ONEOK Partners segment’s regulatory initiative beginning on page 49.~~33.

Pension and Postretirement Employee Benefits - In September 2006, the FASB issued Statement 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” which ~~will require~~required us to record a balance sheet liability equal to the difference between our benefit obligations and plan assets. If Statement 158 had been effective at December 31, 2005, we would have been required to record unrecognized losses of $124.8 million and $78.8 million for pension and postretirement benefits, respectively, on our consolidated balance sheet as accumulated other comprehensive loss. Statement 158 iswas effective for our year ending December 31, 2006, except for the measurement date change from September 30 to December 31 which will ~~not go into effect until~~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 ~~clarified~~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 ~~accordance with Statement 109, “Accounting for Income Taxes.”~~a tax return. FIN 48 requires the recognition of penalties and interest on any unrecognized tax benefits. Our policy is ~~effective for our year beginning January 1, 2007. We are currently reviewing the applicability~~to reflect penalties and interest as part of income tax expense as they become applicable. The adoption of FIN 48 ~~to our operations and its potential~~had an immaterial impact on our consolidated financial statements.

~~In December 2004,~~We file numerous consolidated and separate income tax returns in the ~~FASB issued Statement 123R, “Share-Based Payment,” which requires companies to expense the fair value~~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 ~~share-based payments net~~statute of estimated forfeitures. We adopted Statement 123R as of January 1, 2006, and elected to use the modified prospective method. Statement 123R did not have a material impact on our financial statements as welimitations have been expensing share-based payments since our adoption of Statement 148, “Accounting for Stock-Based Compensation—Transition and Disclosure,” on January 1, 2003. Awards granted after the adoption of Statement 123R are expensed under the requirements of Statement 123R, while equity awards granted prior to the adoption of Statement 123R will continue to be expensed under Statement 148. We recognized other income of $1.7 million upon adoption of Statement 123R. As of September 30, 2006, there was $4.0 million of total unrecognized compensation cost related to our nonvested restricted stock awards, which is expected to be recognized over a weighted-average period of 1.2 years. There was $14.1 million of unrecognized compensation cost related to our performance unit awards as of September 30, 2006, which is expected to be recognized over a weighted-average period of 1.5 years. The total unrecognized compensation cost related to nonvested stock options was not material.granted.

In September 2005, the FASB ratified the consensus reached in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (EITF 04-13). EITF 04-13 defines when a purchase and a sale of inventory with the same party that operates in the same line of business should be considered a single nonmonetary transaction. EITF 04-13 is effective for new arrangements that a company enters into in periods beginning after March 15, 2006. We completed our review of the applicability of EITF 04-13 to our operations and determined that its impact was immaterial to our consolidated financial statements.

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions ~~which~~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 from our estimates.~~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.~~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 6144 for amounts in our portfolio at ~~September 30, 2006,~~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, ~~and~~ 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 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. 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 ~~loss~~income (loss) and is subsequently ~~reclassified into~~recorded to earnings when the forecasted transaction affects earnings. Any ineffectiveness of designated hedges is reported in earnings ~~during~~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 ~~therefore~~ exempt from fair value accounting treatment.

Impairment of Long-Lived Assets, Goodwill and ~~Long-Lived~~Intangible Assets - We assess our goodwill for impairment at least annually based on Statement 142, “Goodwill and Other Intangible Assets.” In the third quarter of 2006, we changed our annual goodwill impairment testing date to July 1. See Note E to our Consolidated Financial Statements in our Quarterly Report on Form 10-Q for additional discussion. 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 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 will record an impairment charge. At September 30, 2006, we had $572.8 million of goodwill recorded on our consolidated balance sheet as shown below.



		*~~(Thousands of dollars)~~*
~~Distribution~~		~~$ 157,953~~
~~Energy Services~~		~~10,255~~
~~ONEOK Partners~~		~~403,481~~
~~Other~~		~~1,099~~
~~Total goodwill~~		~~$ 572,788~~

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.

~~In June 2006, we recorded a~~We assess our goodwill and ~~asset~~non-amortizing intangible assets for impairment ~~related~~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 ~~ONEOK Partners segment’s Black Mesa Pipeline. For further discussion of this impairment, see page 50.~~ carrying value in accordance with APB Opinion No. 18.

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

~~Intangibles~~ - Intangibles are also accounted for in accordance with Statement 142. Intangibles with a finite useful life are amortized over their estimated useful life, while intangibles with an indefinite useful life are not amortized. All intangibles are subject to impairment testing.

Pension and Postretirement Employee Benefits - We have a defined benefit pension ~~plan~~plans covering substantially all full-time employees. Nonbargaining unit employees ~~and~~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.~~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 ~~the~~ costs, assumptions can change from period to period and result in material changes in the costs and liabilities we recognize. ~~For additional information, see~~See Note J of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, ~~2005.~~2006 for additional information.

During ~~2005,~~2006, we recorded ~~net periodic benefit costs of $13.0 million related to our defined benefit pension plans and $27.4 million related to postretirement benefits. We estimate that in 2006 we will record~~ 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 ~~$25.9~~$26.7 million related to postretirement benefits. In determining our estimated expenses for ~~2006,~~2007, our actuarial consultant assumed an 8.75 percent expected return on plan assets and a discount rate of ~~5.75~~6.00 percent. A decrease in our expected return on plan assets to 8.50 percent would increase our ~~2006~~2007 estimated net periodic benefit costs by approximately ~~$1.6~~$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 ~~5.25~~5.75 percent would increase our ~~2006~~2007 estimated net periodic benefit costs by approximately ~~$4.9~~$2.2 million for our defined benefit pension plan and ~~$1.6~~$0.8 million for our postretirement benefit plan. For ~~2006,~~2007, we anticipate our total contributions to fund future benefits for our defined benefit pension plan and postretirement benefit plan to be ~~$1.5~~$4.2 million and ~~$17.3~~$5.5 million, respectively, and the expected benefit payments from our ~~pay-as-you-go other~~ postretirement benefit plan ~~costs~~are estimated to be ~~$14.0~~$22.1 million. See Note JI 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 ~~exposures~~ 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, “Accounting for Contingencies.”~~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 ~~Part II,~~ 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, ~~2005.~~2006.

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

Operating Results - Net margin increased for the three months ended ~~September 30, 2006,~~March 31, 2007, compared with the same period in ~~2005~~2006 primarily due to:

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

increased storage and marketing margins, partially offset by decreased transportation, financial trading and retail margins in ~~ONEOK Partners as required by EITF 04-5,~~our Energy Services segment,

~~strong commodity prices,~~

higher ~~gross processing spreads and increased natural gas transportation revenue~~NGL related margins in our ONEOK Partners segment, ~~partially offset by~~

~~lower storage and marketing margins in our Energy Services segment.~~

~~Net margin increased for the nine months ended September 30, 2006, compared with the same period in 2005~~ primarily due ~~to:~~

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 ~~consolidation~~production of ~~our investment~~ethanol fuel in ~~ONEOK Partners as required by EITF 04-5,~~

~~the effect of the~~its natural gas liquids ~~assets acquired from Koch in July 2005~~business, partially offset by

decreased operating income in our ONEOK Partners ~~segment,~~

~~strong~~segment’s gathering and processing business, primarily due to lower realized commodity prices ~~higher gross processing spreads~~on its POP contracts and ~~increased natural gas transportation revenue in our ONEOK Partners segment, and~~

~~improved natural gas basis differentials on transportation contracts in our Energy Services segment.~~

~~These increases in net margin were slightly offset by a decrease in our ONEOK Partners segment~~lower volumes processed due to the ~~sale of our natural gas gathering and~~anticipated contract terminations at certain processing ~~assets located in Texas during December 2005.~~facilities.

Consolidated operating costs increased for the three-month period primarily due to ~~the consolidation of our investment in ONEOK Partners, as required by EITF 04-5, which was partially offset by decreased employee benefit~~increased employee-related costs and ~~bad debt expense for~~property taxes in our Distribution ~~segment and~~segment.

Equity earnings from investments decreased ~~employee benefit costs and litigation expenses for our Energy Services segment.~~

~~Consolidated operating costs~~$7.6 million for the ~~nine-month~~three months ended March 31, 2007, compared with the same period ~~increased due to the consolidation of our investment~~ in ~~ONEOK Partners, as required by EITF 04-5, and the additional six months of costs for the natural gas liquids assets acquired from Koch in July 2005.~~

~~Depreciation, depletion and amortization increased for the three- and nine-month periods~~2006, primarily due to the ~~consolidation of our investment~~decrease in ONEOK ~~Partners, as required by EITF 04-5. Additionally, the nine-month period also increased due to the costs~~

~~associated with the natural gas liquids assets we acquired~~Partners’ interest in Northern Border Pipeline’s earnings from ~~Koch in July 2005 and the Black Mesa Pipeline impairment recorded~~70 percent in the ~~second~~first quarter of ~~2006.~~

~~The gain on sale~~2006 to 50 percent in the first quarter of ~~assets included in operating income is primarily due to $113.9 million related to~~2007. See page 24 for discussion of ONEOK Partners’ ~~sale~~disposition of athe 20 percent partnership interest in Northern Border ~~Pipeline to TC PipeLines in April 2006. For additional information, see discussion on page 35.~~Pipeline.

Minority interest ~~expense relates to~~in net income of consolidated subsidiaries for the ~~portion~~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 ~~during the three and nine months ended September 30,~~until April 2006.

~~The following tables show the components of other income and other expense for the three and nine months ended September 30, 2006 and 2005.~~

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

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.

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.

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 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.

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.

Operating Results - Net margin increased by ~~$1.8~~$31.8 million for the three months ended ~~September 30, 2006,~~March 31, 2007, compared with the same period in ~~2005,~~2006, primarily due to:

an increase of ~~$5.6~~$21.1 million ~~primarily due to~~resulting from the implementation of new rate schedules, which includes $18.9 million in ~~Oklahoma,~~

~~a decrease of~~Kansas and $2.2 million ~~due~~in Texas, and

an increase of $10.6 million from higher customer sales volumes as a result of a return to ~~expiring riders and lower volumetric rider collections~~more normal weather in ~~Oklahoma, and~~our entire service territory.

~~a decrease of $1.5 million due to reduced transport margins in Oklahoma.~~

Operating costs increased ~~by $9.2~~$5.2 million for the ~~nine~~three months ended ~~September 30, 2006,~~March 31, 2007, compared with the same period in ~~2005,~~2006, primarily due to:

an increase of ~~$39.4~~$4.2 million ~~primarily~~in employee-related costs, and

an increase of $1.7 million due to ~~the implementation of new rate schedules in Oklahoma,~~increased property taxes, partially offset by

a decrease of ~~$18.0~~$2.2 million ~~primarily due to expiring riders and lower volumetric rider collections in Oklahoma, and~~

~~a decrease of $12.9 million in customer sales due to warmer weather in our entire service territory.~~

The impact of warmer than normal weather during the nine-month period was moderated by approved weather-protection mechanisms and the implementation of a new two-tier rate structure in Oklahoma. The new Oklahoma rate structure reduces volumetric sensitivity and provides more consistent earnings and cash flow.

Operating costs decreased $2.8 million for the three-month period primarily due to a decrease in labor and employee benefit costs of $2.0 million. The $5.2 million increase for the nine-month period was primarily due to an increase of $7.8 million in labor and employee benefit costs, which were partially offset by a $2.1 million decrease in bad debt expense.

Depreciation, depletion and amortization increased $1.0 million for the three months ended September 30, 2006, due to additional amortization expense in 2006 from our Oklahoma rate case and depreciation expense associated with additional plant and equipment in Oklahoma, Kansas and Texas.

~~Depreciation, depletion and amortization decreased $3.7 million for the nine months ended September 30, 2006, compared with the same period in 2005, primarily due to:~~

~~a decrease of $2.9 million related to the replacement of our field customer service system in Texas during the first quarter of 2005,~~

~~a decrease of $1.8 million in cathodic protection and service line amortization in Oklahoma from a limited issue rider which expired in the second quarter of 2005, and~~

~~an increase of $1.0 million due to additional amortization expense from our Oklahoma rate case and depreciation expenses associated with additional plant and equipment in Oklahoma, Kansas and Texas.~~

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

Residential and commercial volumes ~~decreased~~increased for the ~~nine-month~~three-month period due to ~~warmer~~a return to more normal weather ~~primarily~~from the unseasonably warm weather in ~~the first quarter of~~ 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 ~~and nine~~ months ended ~~September 30,~~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 ~~$13.7~~$9.6 million and ~~$12.3~~$13.5 million for new business development for the three months ended ~~September 30,~~March 31, 2007, and 2006, ~~and 2005, respectively, and $38.4 and $32.2 million for~~respectively. The decrease in new business ~~development~~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 ~~nine~~three months ended ~~September 30,~~March 31, 2007, compared with 2006, ~~and 2005, respectively. Increased spending~~was due to warmer than normal weather in the first quarter of 2006, ~~represents timing differences and~~which favorably impacted construction. We expect our 2007 capital ~~spending related~~expenditures to be consistent with our ~~new customer service and billing system.~~2006 capital expenditures.

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 ~~has~~had invested approximately $170 million in its natural gas distribution system to provide service for 642,000 Kansas customers. ~~This is the company’s first rate increase request in three years. The KCC has 240 days to issue a ruling on Kansas Gas Service’s application.~~ 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 ~~are subject to the approval of~~were approved by the KCC ~~and hearings~~in November 2006. The rate increase is effective for services rendered on ~~the settlement are scheduled to be held on November 6, 2006.~~

~~Texas~~ - Texas Gas Service has received several regulatory approvals to implement rate increases in various municipalities in Texas. A total of $5.5 million in annual rate relief has been approved and implemented in 2006.

~~Bargaining Unit~~ ~~- On October 25, 2006, a four-year labor contract was ratified between Kansas Gas Service and the International Brotherhood of Electrical Workers.~~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.

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 8696 Bcf, with maximum withdrawal capability of ~~2.2 Bcf per day~~2.3 Bcf/d and maximum injection capability of 1.5 ~~Bcf per day.~~Bcf/d. Our current transportation capacity is ~~1.7 Bcf per day.~~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 ~~ongoing~~ business strategies include identifying, developing and delivering specialized services and products ~~for value to~~valued by our customers, which are primarily ~~local distribution companies,~~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.

In September 2006, we announced that we entered into a 20-year fixed-price purchase contract with Power Holdings of Illinois LLC (Power Holdings) for 45,000 MMBtu per day of pipeline-quality synthetic natural gas (SNG). Power Holdings will begin construction on a coal gasification facility next year in southern Illinois, which is expected to be completed by 2011. The facility will utilize environmentally beneficial gasification technology converting coal into SNG. The coal gasification facility will deliver SNG volumes to Natural Gas Pipeline Company of America (NGPL). Our Energy Services segment contracts for transportation and storage services on NGPL, which transports natural gas into the Mid-continent, Gulf Coast and Chicago markets.

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 ~~existing~~favorable market ~~conditions (see~~conditions. See Note D of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q for additional ~~information).~~information. Additionally, certain ~~hedging activity~~non-trading transactions, which are economic hedges of our accrual transactions, such as our storage and transportation contracts, will not qualify for hedge ~~or accrual~~ accounting ~~treatment; therefore, these non-trading transactions are~~

~~economic hedges of our accrual transactions.~~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 ~~central~~ Oklahoma, and exit the power generation business. The transaction received FERC approval, and the sale was completed on October 31, 2006. ~~These assets were held for sale at September 30, 2006, and, accordingly, this~~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 ~~results~~information below. ~~For additional information, see discussion of discontinued operations on page 50.~~

During preparation of our 2005 Annual Report on Form 10-K, we identified and disclosed a software system error impacting our accounting for hedging instruments, and subsequently restated our third quarter 2005 results to reflect an increase in cost of sales and fuel of $13.2 million. It was determined that no other prior periods were affected. As such, the financial results for our Energy Services segment have been restated for the three and nine months ended September 30, 2005. For further information, refer to Part II, Item 9A, “Controls and Procedures,” in our Annual Report on Form 10-K for the year ended December 31, 2005.

Operating Results - Net margin ~~decreased~~increased by ~~$24.3~~$28.3 million for the three months ended ~~September 30, 2006,~~March 31, 2007, compared with the same period in ~~2005,~~2006, primarily due to:

a ~~decrease~~net increase of ~~$34.5~~$60.6 million ~~related to~~in storage and marketing margins primarily due to:

a decrease of $10.2 million in our financial trading margins primarily due to positions in the natural gas option portfolio that benefited from increased natural gas prices and higher volatility in 2005, as compared to 2006,

an increase of $19.2 million related to the mark-to-market gains and losses on unqualified hedges of transportation and storage contracts, which resulted from $6.6 million in gains for the third quarter of 2006 compared with $12.6 million in losses for the same period in 2005, and

~~an increase of $1.6 million in physical transportation margins, net of hedging activities.~~

~~Net margin increased $70.7 million for the nine months ended September 30, 2006, compared with the same period in 2005, primarily due to:~~

~~an increase of $41.3 million in physical transportation margins, net of hedging activities, primarily due to improved natural gas basis differentials between the Mid-continent and Gulf Coast regions,~~

~~an increase of $7.2 million in our natural gas trading operations primarily associated with favorable basis spread movements in the basis trading portfolio,~~

~~an increase of $4.8 million related to storage and marketing margins primarily due to:~~

~~an increase~~

a decrease of ~~$16.6 million related to the mark-to-market gains and losses on unqualified hedges of transportation and storage contracts, which resulted from $4.9~~$22.1 million in ~~gains for~~transportation margins, net of hedging activities, associated with changes in the ~~nine-month period~~fair value of derivatives, and a decrease in ~~2006 compared with $11.7~~realized margins in the Mid-Continent region,

a decrease of $7.9 million in ~~losses for the same period in 2005,~~our financial trading margins, and

~~an increase~~

a decrease of ~~$1.4~~$2.5 million in retail activities from lower physical margins due to ~~improved physical margins.~~market conditions.

Operating costs ~~decreased $3.8~~increased $1.4 million for the three months ended ~~September 30, 2006,~~March 31, 2007, primarily due to ~~decreased litigation expenses of $2.2 million, decreased employee-related costs of $1.1 million and decreased bad debt expenses of $0.5 million.~~

~~Operating costs decreased $0.1 million for the nine months ended September 30, 2006, due to decreased litigation expenses of $3.0 million, offset primarily by~~ increased employee-related ~~costs of $1.7 million and increased letter of credit fees of $0.5 million.~~costs.

Natural gas volumes marketed ~~decreased~~increased for the ~~three- and nine-month periods~~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 ~~2005,~~2006, primarily ~~due to higher storage injections~~occurring in ~~the second and third quarters of 2006 and warmer weather in the majority of~~January 2007, when our service territory experienced a 58 percent increase in ~~the first quarter of 2006, resulting in decreased sales from storage.~~heating degree days compared with January 2006.

Our natural gas in storage at ~~September 30, 2006,~~March 31, 2007, was ~~80.2~~37.3 Bcf compared with ~~60.4~~42.3 Bcf at ~~September 30, 2005.~~March 31, 2006. At ~~September 30,~~March 31, 2007 and 2006, ~~and 2005,~~ our total natural gas storage capacity under lease was 88 Bcf and 86 ~~Bcf.~~Bcf, respectively.

~~For~~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 ~~considered~~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” that result~~purposes,” (2) financially settled, (3) results in physical delivery or services rendered, and (4) qualifies for the ~~indicators~~normal purchase or sale exception as defined in Statement 133. In accordance with EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3) are used to determine the proper accounting treatment. These activities and all financially settled derivative contracts are reported on a net basis.

~~For derivative instruments that are not considered “held for trading purposes” and result in physical delivery, the indicators in EITF Issue No.~~ 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 03-11) and~~02-3,” EITF ~~Issue No.~~ 99-19, “Reporting Revenue Gross as a Principal versus Net as an ~~Agent” (EITF 99-19)~~Agent,” and Statement 133, we report settled derivative instruments as follows:

all financially settled derivative contracts are ~~used to determine the proper accounting treatment. We account~~reported on a net basis,

derivative instruments considered “held for ~~the realized revenues and purchase costs of these contracts~~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. ~~Derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are also reported on a gross basis.~~


	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~~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 includes~~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.

~~Overview~~ - Effective January 1, 2006, we were required to consolidate ONEOK Partners’ operations in our consolidated financial statements under EITF 04-5, and we elected to use the prospective method, which results in our consolidated financial results and operating information including only 2006 data for the legacy ONEOK Partners operations. 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. These former segments are now included in our ONEOK Partners segment and all periods presented have been restated to reflect this change. 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.

We gather and process natural gas and fractionate NGLs primarily in the Mid-continent and Rocky Mountain regions. Our operations include the gathering of natural gas production from crude oil and natural gas wells. Through gathering systems, these volumes are aggregated and treated or processed to remove water vapor, solids and other contaminants and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. When the liquids are separated from the raw natural gas at the processing plants, the liquids are generally in the form of a mixed NGL stream.

We also gather, store, fractionate and treat mixed NGLs, and store NGL purity products produced from gas processing plants located in Oklahoma, Kansas and the Texas panhandle. Our 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.

Most natural gas produced at the wellhead contains a mixture of NGL components such as ethane, propane, iso-butane, normal butane and natural gasoline. 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, which limit NGL content in the natural gas stream due to liquid and Btu content. The NGLs that are separated from the natural gas stream at the natural gas processing plants remain in a mixed, raw form until they are gathered, primarily by pipeline, and delivered to our fractionators. A fractionator, by applying heat and pressure, separates each NGL component into marketable NGL purity products, such as ethane/propane mix, propane, iso-butane, normal butane and natural gasoline (collectively NGL purity products). These NGL purity products can then be stored or distributed to petrochemical, heating and motor gasoline manufacturers.

We operate intrastate and FERC-regulated interstate natural gas transmission pipelines, natural gas storage and FERC-regulated natural gas liquids gathering and distribution pipelines and nonprocessable natural gas gathering facilities. We also provide 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.~~

~~Operating results~~ - We began consolidating our investment in ONEOK Partners as of January 1, 2006, in accordance with EITF 04-5. We elected to use the prospective method, which results in our consolidated financial results and operating information including only 2006 data for the legacy ONEOK Partners operations. See Impact of New Accounting Standards on page 37 for additional information.

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. These former segments are now included in our ONEOK Partners segment.

~~Net margin increased by $41.9 million for the three months ended September 30, 2006, primarily due to:~~

~~an increase of $49.5 million from the legacy ONEOK Partners operations, which were consolidated beginning January 1, 2006,~~

~~an increase of $19.7 million from our legacy operations driven primarily by strong commodity prices, higher gross processing spreads and increased natural gas transportation revenues, and~~

~~a decrease of $25.2 million resulting from the sale of natural gas gathering and processing assets located in Texas in December 2005.~~

~~Net margin increased by $232.6 million for the nine months ended September 30, 2006, primarily due to:~~

~~an increase of $152.6 million from the legacy ONEOK Partners operations, which were consolidated beginning January 1, 2006,~~

~~an increase of $101.8 million related to net margins on natural gas liquids gathering and distribution pipelines acquired from Koch in July 2005,~~

~~an increase of $48.1 million from our legacy operations driven primarily by strong commodity prices, higher gross processing spreads and increased natural gas transportation revenues, and~~

~~a decrease of $64.9 million resulting from the sale of natural gas gathering and processing assets located in Texas in December 2005.~~

The increase in operating costs of $8.7 million for the three-month period, is primarily related to the consolidation of the legacy ONEOK Partners operations, offset by the sale of the Texas natural gas gathering and processing assets in December 2005.

The increase in operating costs of $69.2 million for the nine-month period is primarily related to the consolidation of the legacy ONEOK Partners operations and the natural gas liquids assets acquired in 2005, offset by the sale of the Texas natural gas gathering and processing assets in December 2005.

Depreciation, depletion and amortization increased by $6.3 million for the three-month period which is primarily related to the consolidation of the legacy ONEOK Partners operations, offset by the December 2005 sale of natural gas gathering and processing assets located in Texas.

The increase in depreciation, depletion and amortization of $47.4 million for the nine-month period is primarily due to the consolidation of the legacy ONEOK Partners operations, the Black Mesa Pipeline impairment, the acquisition of natural gas liquids assets in 2005, and an offsetting decrease from the December 2005 sale of natural gas gathering and processing assets located in Texas.

The increase in equity earnings from investments of $22.8 million and $72.2 million for the three- and nine-month periods, respectively, resulted primarily from ONEOK Partners’ 50 percent interest in Northern Border Pipeline and gathering and processing joint venture interests in the Powder River and Wind River Basins.

~~Risk Management~~ - We use commodity financial instruments, including NYMEX contracts, fixed price swaps and collars, which are primarily designated as cash flow hedges, to minimize earnings volatility related to natural gas and natural gas liquids price fluctuations. The realized financial impact of the derivative transactions is included in our operating income in the period that the physical transaction occurs. The following table sets forth our hedging information for the remainder of 2006 and all of 2007 for our ONEOK Partners segment.

For the remainder of 2006, our ONEOK Partners segment is approximately 77 percent hedged on its projected percent-of-proceeds NGL volumes, approximately 73 percent hedged on its projected percent-of-proceeds natural gas volumes and approximately 66 percent hedged on its projected keep-whole gross processing spread.

~~Regulatory Initiative~~ - Our natural gas transportation assets in Oklahoma, Kansas and Texas are regulated by the OCC, KCC and RRC, respectively. We have flexibility in establishing natural gas transportation rates with customers. However, there is a maximum rate we can charge our customers in Oklahoma and Kansas. The FERC regulates the rates and charges for

transportation on ONEOK Partners’ interstate natural gas and natural gas liquids pipelines. Interstate pipeline companies may not charge rates that have been determined to be unjust and unreasonable by the FERC. Generally, rates for interstate pipelines are based on the cost of service, including recovery of and a return on the pipeline’s actual prudent historical cost investment. The rates, terms and conditions for service are found in each pipeline’s FERC-approved tariff. Under its tariff, an interstate pipeline is allowed to charge for its services on the basis of stated transportation rates. Transportation rates are established periodically in FERC proceedings known as rate cases. The tariff also allows the interstate pipeline to provide services under negotiated and discounted rates.

~~Black Mesa Pipeline~~ - On December 31, 2005, our ONEOK Partners segment’s Black Mesa Pipeline’s transportation contract with the coal supplier of Mohave Generating Station (Mohave) expired and its coal slurry pipeline operations were shut down as expected. In June 2006, SCE completed a comprehensive study of the water source, coal supply and transportation issues and announced that it would no longer pursue the resumption of plant operations. SCE and the other Mohave co-owners are jointly exploring options for Mohave, including the possibility of selling the plant. Negotiations among various parties involved with Black Mesa are ongoing.

During the second quarter of 2006, ONEOK Partners assessed its coal slurry pipeline operation in accordance with its accounting policies related to the goodwill and asset impairment. Its evaluation of the Black Mesa Pipeline indicated a goodwill and asset impairment of $8.4 million and $3.4 million, respectively, which were recorded as depreciation and amortization in the second quarter of 2006. The reduction to our net income, net of minority interest and income taxes, was $3.0 million.

~~Overview~~ - In September 2005, we completed the sale of our Production segment to TXOK Acquisition, Inc. for $645 million, before adjustments, and recognized a pre-tax gain on the sale of approximately $240.3 million. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold. The proceeds from the sale were used to reduce debt. Our Board of Directors authorized management to pursue the sale during July 2005, which resulted in our Production segment being classified as held for sale beginning July 1, 2005.

Additionally, in the third quarter of 2005, we made the decision to sell our Spring Creek power plant 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.

These components of our business are accounted for as discontinued operations in accordance with Statement 144. Accordingly, amounts in our financial statements and related notes for all periods shown relating to our Production segment and our power generation business are reflected as discontinued operations. The sale of our Production segment and the pending sale of our power generation business are in line with our business strategy to sell assets when deemed less strategic or as other conditions warrant.

~~Selected Financial Information~~ ~~- The amounts of revenue, costs and income taxes reported in discontinued operations are as follows.~~

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 ~~2006~~the three months ended March 31, 2007 and ~~2005,~~2006, our capital expenditures were financed through operating cash flows and short- and long-term debt. ~~Capital~~Total capital expenditures for the first ~~nine~~three months of ~~2006~~2007 were ~~$244~~$107.0 million, compared with ~~$190~~$54.6 million for the same period in ~~2005,~~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 ~~and~~or limited partner units.

The total amount of short-term borrowings authorized by ~~the~~our Board of Directors ~~of ONEOK~~ is $2.5 billion. ~~In addition to the short-term bridge financing agreement discussed below, the~~The total amount of short-term borrowings authorized by the Board of Directors of ONEOK Partners GP, the general partner of ONEOK Partners, is ~~$750 million, and an additional $10 million is authorized for Guardian Pipeline.~~$1.5 billion. At ~~September 30, 2006, ONEOK~~March 31, 2007, we had no commercial paper outstanding, ~~$88.4~~$37.9 million in letters of credit issued and available cash and short-term investments of approximately ~~$191.6~~$667.8 million. At ~~September 30, 2006,~~March 31, 2007, ONEOK Partners had ~~$15~~$10 million in letters of credit issued, no borrowings outstanding under the ~~2006~~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 ~~$55.9~~$95.7 million. As of ~~September 30, 2006, ONEOK~~March 31, 2007, we could have issued ~~$2.4~~$2.6 billion of additional debt under the most restrictive provisions contained in our various borrowing agreements. As of ~~September 30, 2006,~~March 31, 2007, ONEOK Partners could have issued, under the most restrictive provisions of its agreements, ~~$1.4~~$1.7 billion of additional debt.

Our $1.2 billion five-year credit agreement, as amended and restated in 2006, and ONEOK ~~Short-Term Bridge Financing~~Partner’s 2007 Partnership Credit Agreement, ~~- On July 1, 2005, we borrowed $1.0 billion under a new short-term bridge financing agreement to assist~~ contain typical covenants as discussed in ~~financing our acquisition of assets from Koch. See~~ Note BH of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q, for additional information about this acquisition. We funded the remaining acquisition cost through our commercial paper program. During the three months ended March 31, 2006, we repaid the facility in full, and it was terminated according to its terms.

~~ONEOK Five-Year Credit Agreement~~ - In April 2006, we amended ONEOK’s 2004 $1.2 billion five-year credit agreement to accommodate the transaction with ONEOK Partners. This amendment included changes to the material adverse effect representation, the burdensome agreement representation and the covenant regarding maintenance of control of ONEOK Partners.

In July 2006, we amended and restated ONEOK’s 2004 $1.2 billion five-year credit agreement. The amended agreement includes revised pricing, an extension of the maturity date from 2009 to 2011, an option for additional extensions of the maturity date with the consent of the lenders, and an option to request an increase in the commitments of the lenders of up to an additional $500 million. The interest rates applicable to extensions of credit under this agreement are based, at our election, on either (i) the higher of prime or one-half of one percent above the Federal Funds Rate, which is the rate that banks charge each other for the overnight borrowing of funds, or (ii) the Eurodollar rate plus a set number of basis points based on our current long-term unsecured debt ratings.

~~Under the five-year credit agreement, ONEOK is required to comply with certain financial, operational and legal covenants. Among other things, these requirements include:~~

~~a $500 million sublimit for the issuance of standby letters of credit,~~

~~a limitation on our debt-to-capital ratio, which may not exceed 67.5 percent at the end of any calendar quarter,~~

~~a requirement that we maintain the power to control the management and policies of ONEOK Partners, and~~

~~a limit on new investments in master limited partnerships.~~

~~The debt covenant calculations in ONEOK’s five-year credit agreement exclude the debt of ONEOK Partners. At September 30, 2006, we had no borrowings outstanding under this agreement.~~

~~ONEOK Partners Five-Year Credit Agreement~~ - In March 2006, ONEOK Partners entered into a five-year $750 million amended and restated revolving credit agreement (2006 Partnership Credit Agreement) with certain financial institutions and terminated its $500 million revolving credit agreement. At September 30, 2006, ONEOK Partners had $15 million in letters of credit outstanding and no borrowings outstanding under the 2006 Partnership Credit Agreement.

~~Under the 2006 Partnership Credit Agreement, ONEOK Partners is required to comply with certain financial, operational and legal covenants. Among other things, these requirements include:~~

~~maintaining a ratio of EBITDA (net income plus interest expense, income taxes, and depreciation and amortization) to interest expense of greater than 3 to 1, and~~

~~maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA adjusted for pro forma operating results of acquisitions made during the year) of no more than 4.75 to 1.~~

~~ONEOK Partners Bridge Facility~~ - In April 2006, ONEOK Partners entered into the Bridge Facility with a syndicate of banks and borrowed $1.05 billion to finance a portion of its purchase of certain assets comprising our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments. In September 2006, ONEOK Partners repaid the amounts outstanding under the Bridge Facility using proceeds from the issuance of senior notes, which resulted in the Bridge Facility being terminated according to its terms. See “ONEOK Partners Debt Issuance” below and Note IH of the Notes to Consolidated Financial Statements in ~~this Quarterly~~our Annual Report on Form ~~10-Q~~10-K, for ~~further discussion regarding~~ the ~~issuance of senior notes.~~

year ended December 31, 2006. At March 31, 2007, we and ONEOK Partners ~~Debt Issuance~~ ~~- In September 2006, ONEOK Partners completed an underwritten public offering of (i) $350~~were in compliance with all covenants.

Currently, we have $48.2 million aggregate principal amount of 5.90 percent Senior Notes due 2012 (the “2012 Notes”), (ii) $450 million aggregate principal amount of 6.15 percent Senior Notes due 2016 (the “2016 Notes”) and (iii) $600 million aggregate principal amount of 6.65 percent Senior Notes due 2036 (the “2036 Notes” and collectively with the 2012 Notes and the 2016 Notes, the “Notes”). ONEOK Partners registered the sale of the Notes with the SEC pursuant toavailable under a shelf registration statement ~~filed~~ on September 19, 2006. The Notes are guaranteed on a senior unsecured basis by the Intermediate Partnership. The guarantee ranks equally in right of payment to all of the Intermediate Partnership’s existing and future unsecured senior indebtedness.

ONEOK Partners may redeem the Notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount of the Notes, plus accrued interest, unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the relevant Notes plus accrued and unpaid interest. The Notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing unsecured senior indebtedness, and effectively junior to all of the existing debt and other liabilities of its non-guarantor subsidiaries. The Notes are non-recourse to us.

~~Equity Units~~ - On February 16, 2006, we successfully settled our 16.1 million equity units with 19.5 million shares of our common stock. Of this amount, 8.3 million shares were issued from treasury stock and approximately 11.2 million shares were newly issued. Holders of the equity units received 1.2119 shares of our common stock, ~~for each equity unit they owned. The number of shares that we issued for each~~debt securities, preferred stock, stock purchase contract was determined based on our average closing price over the 20 trading day period ending on the third trading day prior to February 16, 2006. With the settlement, we received $402.4 million in cash, which was used to pay down our short-term bridge financing agreement.contracts and stock purchase units.

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

~~ONEOK does~~We do not guarantee the debt of ONEOK Partners. For purposes of determining compliance with financial covenants in ~~ONEOK’s~~our five-year credit agreement, the debt of ONEOK Partners is excluded. At ~~September 30,~~both March 31, 2007, and December 31, 2006, our capitalization structure, excluding the debt of ONEOK Partners, was 48 percent ~~long-term~~ debt and 52 percent ~~equity, compared to 53 percent long-term debt and 47 percent equity at December 31, 2005.~~

~~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 inequity.

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, its 17.5 percent general partner interest in ONEOK Partners for $40 million. This purchase resulted in our owning 100 percent of the two 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 100 percent of the two percent ONEOK Partners’ general partner interest. Our overall interest in ONEOK Partners, including the two percent general partner interest, has increased to 45.7 percent. ONEOK Partners recorded a $63.6 million purchase price adjustment to the acquired assets related to a working capital settlement, which is reflected as an increase to the value of the Class B units. In the third quarter of 2006, the working capital settlement was finalized, subject to approval by ONEOK Partners’ Audit Committee, resulting in no material adjustments.

The sale of certain assets comprising our former Gathering and Processing, Pipelines and Storage, and Natural Gas Liquids segments did not affect our consolidated operating income on our Consolidated Statements of Income or total assets on our consolidated balance sheets under EITF 04-5, as we were already required to consolidate our investment in ONEOK Partners effective January 1, 2006. However, minority interest expense and net income are affected. See Impact of New Accounting Standards on page 37 for additional discussion of EITF 04-5.

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, with an affiliate of TransCanada becoming operator of the pipeline in April 2007. ONEOK Partners no longer consolidates Northern Border Pipeline as of January 1, 2006. Instead, its interest in Northern Border Pipeline is accounted for as an investment under the equity method. This change does not affect previously reported net income or shareholders’ equity. TransCanada paid us $10 million for expenses associated with the transfer of operating responsibility of Northern Border Pipeline to them.

The limited partner units we received from ONEOK Partners were newly created Class B units with the same distribution rights as the outstanding common units, but have limited voting rights and are subordinated to the common units with respect to payment of minimum quarterly distributions. Distributions on the Class B units were prorated from the date of issuance. ONEOK Partners is required to hold a special election for holders of common units as soon as practical, but no later than April 2007, subject to extension, to approve the conversion of the Class B units into common units and to approve certain amendments to ONEOK Partners’ partnership agreement. The proposed amendments would grant voting rights for common units held by the general partner if a vote is held to remove the general partner and require fair market value compensation for the general partner interest if the general partner is removed. If the conversion and the amendments are approved by common unitholders, the Class B units will be eligible to convert into common units on a one-for-one basis. If the common unitholders do not approve both the conversion and amendments, then the amount payable on such Class B units would increase to 115 percent of the distributions paid on the common units, including distributions paid upon liquidation, and the Class B units will no longer be outstanding.. If the common unitholders vote to remove us or our affiliates as the general partner of ONEOK Partners at any time prior to the approval of the conversion and amendment described above, the amount payable on such Class B units would increase to 125 percent of the distributions payable with respect to the common units, including distributions paid upon liquidation. The Class B unit distribution rights would continue to be subordinated in the manner described above unless and until the conversion described above has been approved.

In April 2006, our ONEOK Partners segment acquired the remaining 66 2/3 percent interest in Guardian Pipeline 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 financial statements. This change was retroactive to January 1, 2006. Prior to the transaction, ONEOK Partners’ 33 1/3 percent interest in Guardian Pipeline was accounted for as an investment under the equity method.

~~Capital Projects~~ - In June 2006, ONEOK Partners signed a non-binding letter of intent to form a joint venture with Boardwalk Pipeline Partners, L.P. and Energy Transfer Partners, LP to construct a new interstate pipeline originating in north Texas, crossing Oklahoma and Arkansas and terminating in Dyer County, Tennessee at a new interconnect with Texas Gas Transmission, L.L.C. The proposed interstate pipeline would create new pipeline capacity for constrained wellhead production in north Texas and central Oklahoma and would have initial capacity of up to 1.0 Bcf/d. In August 2006, Energy Transfer Partners, LP withdrew from the joint venture. Formation of the joint venture with Boardwalk Pipeline Partners, LP is subject to negotiation and execution of definitive agreements by the participants.

In May 2006, a subsidiary of ONEOK Partners entered into an agreement with a subsidiary of Williams to form a joint venture called Overland Pass Pipeline Company. Overland Pass Pipeline Company will build 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 if customers contract for that capacity. A subsidiary of ONEOK Partners owns 99 percent of the joint venture, will manage the construction project, will advance all costs associated with construction, and will operate the pipeline. Within two years of the pipeline becoming operational, Williams has the option to increase its ownership up to 50 percent by reimbursing ONEOK Partners its proportionate share of all construction costs and, upon full exercise of that option, Williams would have the option to become operator. Construction of the pipeline is expected to begin in the summer 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 estimated to cost approximately $433 million. In May 2006, ONEOK Partners paid $11.4 million to Williams for reimbursement of initial capital expenditures. In addition, ONEOK Partners plans to invest approximately $173 million to expand its existing fractionation capabilities and the capacity of its natural gas liquids distribution pipelines. ONEOK Partners’ financing for both projects may include a combination of short- or long-term debt or equity. The project requires the approval of various state and regulatory authorities.

On October 13, 2006, Guardian Pipeline 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 pipeline, 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 $260 million with a targeted in-service date of November 2008.

Additionally, ONEOK Partners has $28 million in long-term capital project obligations related to their construction of the Midwestern Gas Transmission Eastern Extension Project which will add 31 miles of natural gas pipeline with approximately 120 MMcf/d of transportation capacity. The proposed in-service date is early 2007. Midwestern Gas Transmission is a bi-directional system that interconnects with Tennessee Gas Transmission near Portland, Tennessee and several interstate pipelines near Joliet, Illinois.

~~Stock Repurchase Plan~~ - A total of 15 million shares have been repurchased to date pursuant to a plan approved by our Board of Directors. The plan, originally approved by our Board of Directors in January 2005, was extended in November 2005, to allow us to purchase up to a total of 15 million shares of our common stock on or before November 2007. 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, which completed the plan approved by our Board of Directors. 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 will purchase shares in the open market to settle its short position. Our repurchase is 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 can be 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 ONEOK 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.” At September 30, 2006, we did not owe UBS for a price adjustment. We have no remaining shares available for repurchase under our stock repurchase plan.

Credit Rating - Our credit ratings as of ~~September 30, 2006, were as follows:~~March 31, 2007, are shown in the table below.

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, ~~ONEOK has~~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 ~~2011.~~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 ~~either~~ the Moody’s or S&P ~~or Moody’s debt rate falls~~credit ratings fall below investment grade (Baa3 for Moody’s and BBB- for S&P) and the investment grade ~~rating is~~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 ~~ONEOK’s~~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. At September 30, 2006, the amount we could have been required to fund for the few counterparties with which we have a Credit Support Annex within our International Swaps and Derivatives Association Agreements is approximately $89.9 million. 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 ~~the~~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, ~~marketing, trading and risk contracts,~~ 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. ~~ONEOK’s~~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 ~~prices~~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 ~~natural~~ 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 ~~ONEOK’s and ONEOK Partners’~~our current commercial paper program and ONEOK Partners’ lines of credit are adequate to meet ~~our~~ 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. ~~We use~~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 ~~made~~ 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 ~~2005 were $1.5 million and $3.1 million, respectively.~~2006. For ~~2006,~~2007, we anticipate our total contributions to fund future benefits for our ~~defined benefit~~ pension plan and postretirement benefit plan to be ~~$1.5~~$4.2 million and ~~$17.3~~$5.5 million, respectively, and the expected benefit payments for our ~~pay-as-you-go other~~ postretirement benefit plan ~~costs~~are estimated to be ~~$14.0~~$22.1 million. We believe ~~that~~ we have adequate resources to fund our obligations under our ~~pension and postretirement benefit~~ plans.

Our Consolidated Statements of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each category. Discontinued operations accounted for approximately $37.0 million in operating cash inflows for the nine months ended September 30, 2005. Discontinued operations accounted for approximately $31.2 million in investing cash outflows for the nine months ended September 30, 2005, and did not account for any financing cash flows. The absence of cash flows from our discontinued operations is not expected to have a significant impact on our future cash flows.

~~Operating Cash Flows~~ - Operating cash flows increased by $602.3 million for the nine months ended September 30, 2006, compared with the same period in 2005. The increase in operating cash flows was primarily the result of a net decrease in working capital of $306.1 million in 2006, compared with a net increase in working capital of $161.3 million in 2005. This decrease in working capital is primarily the result of higher working capital at December 31, 2005 compared with December 31, 2004 and the subsequent collection of receivables in 2006, as well as falling gas prices. The increases in 2006 operating cash flows were also impacted by the consolidation of ONEOK Partners as of January 1, 2006 due to EITF 04-5. During the nine months ended September 30, 2006, we received $93.2 million in distributions primarily from Northern Border Pipeline, compared with distributions primarily from ONEOK Partners of $8.1 million in the prior year.

~~Investing Cash Flows~~ ~~- Our ONEOK Partners segment received $297.0 million for the sale of its 20 percent partnership interest in Northern Border Pipeline in April 2006.~~

Acquisitions in the nine months ending September 30, 2006, primarily relate to our ONEOK Partners segment acquiring the remaining 66 2/3 percent interest in Guardian Pipeline for approximately $77 million. This purchase increased our ownership interest to 100 percent. We also purchased from TransCanada its 17.5 percent general partner interest in ONEOK Partners for $40 million. This purchase resulted in our ownership of the entire two percent general partner interest in ONEOK Partners. Additionally, ONEOK Partners paid $11.4 million to Williams for initial capital expenditures related to the Overland Pass Pipeline Company.

Acquisitions in 2005 primarily represent the cash purchase of the Koch assets. The sale of our Production segment resulted in proceeds from the sale of a discontinued component. The proceeds from the sale of assets in 2005 resulted from the sale of Cimarex Energy Company common stock, formerly Magnum Hunter Resources (MHR) common stock. The MHR common stock was acquired upon exercise of MHR stock purchase warrants in February 2005, resulting in us paying $22.7 million which is included in changes in other investments, net.

~~Financing Cash Flows~~ - The first nine months of 2006 include $120.8 million in distributions to minority interests, which primarily resulted from our consolidation of ONEOK Partners in accordance with EITF 04-5 as of January 1, 2006, and represents distributions to the unitholders of the 54.3 percent of ONEOK Partners that we do not own.

We also paid $281.4 million to repurchase 7.5 million shares of our common stock pursuant to the plan initially approved by our Board of Directors on January 20, 2005 and amended in November 2005. During the first nine months of 2005, we paid $188.7 million to repurchase approximately 6.0 million shares of our stock under the same plan.

In addition, we repaid the remaining $900 million outstanding on our $1.0 billion short-term bridge financing agreement. ONEOK Partners completed the underwritten public offering of senior notes totaling $1.39 billion in net proceeds, before offering expenses, which were used to repay all of the amounts outstanding under ONEOK Partners’ Bridge Facility and to repay $335 million of indebtedness outstanding under the 2006 Partnership Credit Agreement.

In June 2005, we issued $800 million of notes and used a portion of the proceeds to repay commercial paper. The commercial paper had been issued to finance our acquisition of ONEOK Partners GP in November 2004, to repay $335 million of long-term debt that matured on March 1, 2005, and to meet operating needs. We incurred $1.35 billion of notes payable related to the Koch assets acquisition. This increase was partially offset by $643 million in payments on notes payable and commercial paper, which represents the cash received from the sale of our Production segment, and payments made in the normal course of operations.

During the first quarter of 2005, we terminated $400 million of our interest rate swap agreements and paid a net amount of $19.4 million, which included $20.2 million for the present value of future payments at the time of termination, less $0.8 million for interest rate savings through the termination of the swaps. The $20.2 million payment has been recorded as a reduction in long-term debt and will be recognized in the income statement over the term of the debt instruments originally hedged. We paid $2.4 million in the second quarter of 2005 as a result of the termination of $500 million of our treasury rate-lock agreements. This amount, net of tax, has been recorded to accumulated other comprehensive loss and will be recognized in the income statement over the term of the related debt issuances.

The following table sets forth our contractual obligations related to debt, operating leases and other long-term obligations as of September 30, 2006, and reflects the consolidation of ONEOK Partners based on EITF 04-5. For further discussion of the debt and operating lease agreements, see Notes I and K, respectively, of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

~~(a) - No payment amounts are provided for our pension and other postretirement benefit plans in the “Thereafter” column since there~~

~~Interest Payments on Debt~~ ~~- Interest expense is calculated by taking long-term debt and multiplying by the respective coupon rates, adjusted for active swaps.~~

~~Leases~~ - We lease various buildings, facilities and equipment, which are accounted for as operating leases. We lease vehicles which are accounted for as operating leases for financial purposes and capital leases for tax purposes.

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 ~~the~~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~~clean-up costs, which could materially affect our results of operations and cash flows. In addition, emission controls required under the ~~Federal~~federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure ~~our investors~~ 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.

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 ~~eleven~~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 ~~three sites.~~two sites in 2007. We have begun site assessment at the remaining site where no active remediation has occurred.

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 ~~expense~~ 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.

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.

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:~~to our anticipated financial ~~performance;~~performance, management’s plans and objectives for our future ~~operations;~~operations, our business ~~prospects;~~prospects, the outcome of regulatory and legal ~~proceedings;~~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,” ~~“plan,”~~ “estimate,” “expect,” ~~“forecast,~~“project,” “intend,” “plan,” “believe,” ~~“projection,~~“should,” ~~“goal”~~“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 ~~United States~~U.S. natural gas;

– availability of additional storage capacity;

– weather conditions; and

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

~~orders by the FERC that are significantly different than the settlement related to Northern Border Pipeline’s November 2005 rate case;~~

our ability to successfully transfer ONEOK Partners’ operations from Omaha ~~and Denver~~ 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 ~~natural gas liquids;~~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 ~~II, Item 1A, “Risk Factors,” in this Quarterly Report and under Part~~ I, Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, ~~2005.~~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.~~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, ~~2005.~~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. ~~Executory storage and transportation contracts and their related~~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 September 30, 2006													Fair Value of Derivatives at March 31, 2007
Source of Fair Value (a)			Matures through March 2007			Matures through March 2010			Matures through March 2012			Total Fair Value				Matures through March 2008			Matures through March 2011		Matures through March 2013			Total Fair Value
			(Thousands of dollars)													(Thousands of dollars)
Prices actively quoted (b)		$	(159,328	)	$	(19,071	)	$	—		$	(178,399	)		$	(7,455	)	$	107	$	-		$	(7,348	)
Prices provided by other external sources (c)			136,834			27,398			—			164,232				57,676			9,594		(110	)		67,160
Prices derived from quotes, other external sources and other assumptions (d)			(5,072	)		5,106			(105	)		(71	)			(62,559	)		7,296		(27	)		(55,290	)
Total		$	(27,566	)	$	13,433		$	(105	)	$	(14,238	)		$	(12,338	)	$	16,997	$	(137	)	$	4,522

(a) Fair value is the marked-to-market component of forwards, 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 the Consolidated Balance Sheets.
(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.														(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.	(b) Values are derived from energy market price quotes from national commodity trading exchanges that primarily trade futures and option commodity contracts.													(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.	(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.													(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.	(d) Values derived in this category utilize market price information from the other two categories, as well as other assumptions for liquidity and credit.													(d) Values derived in this category utilize market price information from the other two categories, as well as other assumptions for liquidity and credit.

Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities
   (Thousands of dollars )
        Net fair value of derivatives outstanding at December 31, 2005
   $ 30,336
        Derivatives realized or otherwise settled during the period
   (56,090 )
        Fair value of new derivatives when entered into during the period
   (6,666 )
        Other changes in fair value
   18,182
        Net fair value of derivatives outstanding at September 30, 2006
   $ (14,238 )

For further discussion of trading activities and assumptions used in our trading activities, see ~~Accounting Treatment~~“Accounting Treatment” in Note D of the Notes to Consolidated Financial Statements ~~included~~ 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 ~~$17.5~~$7.9 million and ~~$43.9~~$19.0 million at ~~September 30,~~March 31, 2007, and 2006, ~~and 2005,~~ respectively. The following table details the average, high and low daily VAR ~~calculations.~~calculations for the periods indicated.


		Three Months Ended September 30,				Nine Months Ended September 30,			Three Months Ended March 31,
Value-at-Risk		2006		2005		2006		2005		2007		2006
		(Millions of dollars)								(Millions of dollars)
Average	$	10.8	$	16.3	$	19.0	$	13.5	$	13.1	$	32.0
High	$	36.5	$	44.0	$	49.0	$	44.0	$	23.0	$	65.0
Low	$	3.3	$	7.1	$	3.3	$	6.2	$	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 ~~the three months ended September 30, 2006,~~2007, compared with ~~2005, is primarily~~2006, was due to lower ~~volatility in 2006 attributable to changes in basis prices. In particular, there was significant~~average commodity prices and decreased price volatility in 2007.

To the ~~latter part of the third quarter of 2005 due to weather related events. The increase in VAR for the nine months ended September 30, 2006, compared with 2005, was primarily due to higher average~~extent open commodity positions exist, fluctuating commodity prices ~~beginning in~~can impact our financial results and financial position either favorably or unfavorably. As a result, we cannot predict with precision the ~~latter part of the third quarter 2005 and was prevalent into second quarter 2006.~~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 ~~September 30, 2006,~~March 31, 2007, the interest rate on ~~approximately 87.8~~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 ~~September 30, 2006,~~March 31, 2007, a 100 basis point move in the ~~LIBOR~~annual interest rate on our ~~floating rate~~variable-rate long-term debt would change our annual interest expense by ~~approximately~~ $4.9 million before ~~taxes and minority interest.~~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		ONEOK		ONEOK Partners		Total
		(Millions of dollars)						(Millions of dollars)
Remainder of 2006	$	1.7	$	0.8	$	2.5
2007		6.6		3.4		10.0
Remainder of 2007							$	5.0	$	2.7	$	7.7
2008		6.6		3.6		10.2		6.6		3.7		10.3
2009		5.6		3.8		9.4		5.5		3.7		9.2
2010		5.5		4.0		9.5		5.4		3.7		9.1
2011								2.5		0.9		3.4
Thereafter		15.3		0.8		16.1		12.8		-		12.8

Currently, the interest rate on $490 million of ~~fixed rate~~fixed-rate debt is swapped to ~~floating. Interest on the~~ floating using interest rate ~~debt~~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 ~~September 30, 2006,~~March 31, 2007, we recorded a net liability of ~~$13.9~~$11.9 million to recognize the interest rate swaps at fair value. Long-term debt was decreased by ~~$13.9~~$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 ~~$5.9~~$1.9 million for the ~~nine~~three months ended ~~September 30, 2006.~~March 31, 2007. The swaps are expected to net the following savings for the remainder of the year:

interest expense savings of ~~$2.5~~$7.7 million related to the amortization of the swap value at termination, and

approximately ~~$0.6~~$0.5 million in interest expense from the existing $490 million of swapped debt, based on LIBOR rates at ~~September 30, 2006.~~March 31, 2007.

Total net swap savings for ~~2006~~2007 are expected to be ~~$7.8~~$9.1 million, compared ~~to $10.7~~with $7.6 million for ~~2005.~~2006.

CURRENCY RATE RISK

~~With~~As a result of our Energy Services segment’s ~~Canadian~~ 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 ~~September 30, 2006,~~March 31, 2007, our exposure to risk from currency translation was not material, and there ~~was~~were no material currency translation ~~gain~~gains or ~~loss recorded.~~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 ~~Chairman and~~ 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 ~~Rule~~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 ~~this report~~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 ~~September 30, 2006,~~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 ~~Rules~~Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the first quarter ended ~~September 30, 2006,~~March 31, 2007, that have materially affected, or are reasonably likely to materially affect, our internal control over financial ~~reporting, except for those controls described in the following paragraphs.~~reporting.

In connection with the sale of our former Gathering and Processing, Natural Gas Liquids and Pipelines and Storage assets to ONEOK Partners, the operations currently managed in ONEOK Partners’ Omaha, Nebraska, and Denver, Colorado, offices are being moved to Tulsa, Oklahoma. The Denver office operations are anticipated to be completely transitioned to Tulsa by the end of 2006, and the Omaha office operations to be transitioned to Tulsa by April 2007. In July 2005, we completed our acquisition of the Natural Gas Liquids segment that subsequently was transferred to our ONEOK Partners segment. As part of our ongoing integration activities related to both of these transactions, we are in the process of developing and incorporating controls and procedures into our internal controls over financial reporting. Until such controls are more fully developed, we have implemented and are relying on compensating controls and have performed extensive reviews of our reported results. As with any change, there are inherent risks in the timing, development and implementation of internal controls that could negatively impact us; however, we do not believe they will materially affect our internal control over financial reporting.

Our ONEOK Partners segment is in the process of implementing a new contracting and billing system to support its gathering and processing operations by automating certain transactional processes, including scheduling, plant allocations and invoicing, that are currently handled manually. Implementation is scheduled to be completed during the fourth quarter of 2006 and will result in changes to our internal control over financial reporting; however, we do not believe the changes will be material.

PART II - OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

Additional information about our legal proceedings is included under Part ~~II, Item 1, “Legal Proceedings,” in our Quarterly Reports on Form 10-Q for the three months ended March 31, 2006, and the three months ended June 30, 2006, and under Part~~ I, Item 3, “Legal Proceedings,” in our Annual Report on Form 10-K for the year ended December 31, ~~2005.~~

~~Enron Corp. v. Silver Oak Capital, LLC and AG Capital Recovery Partners III, LP, Adversary Proceeding No. 03-93568, relating to Case No. 01-16034, in the United States Bankruptcy Court for the Southern District of New York.~~ The settlements reached in this matter became effective on or about August 7, 2006, upon the expiration of the time to appeal the terms of the settlements under applicable law. This matter is now concluded.

~~Samuel P. Leggett, et al. v. Duke Energy Corporation, et al.,~~ ~~Case No. 13847 in the Chancery Court of Tennessee for the Twenty-Fifth Judicial District at Somerville.~~~~On October 16, 2006, the defendants filed an updated Motion to Dismiss based upon the filed rate doctrine and federal preemption. The Court’s ruling on this motion is pending.~~

~~Learjet, Inc., et al. v. ONEOK, Inc., et al.~~,originally filed in the District Court of Wyandotte County, Kansas (Case No. 05-CV-1500), removed to the United States District Court for the District of Kansas (Case No. 05-CV-2513-CM-JPO), conditionally transferred to MDL-1566 in the United States District Court for the District of Nevada. On August 3, 2006, the Court entered an order denying the Motion to Remand filed by the plaintiffs. On September 28, 2006, the plaintiffs filed a motion with the Judicial Panel for Multidistrict Litigation (the “MDL Panel”) requesting that the MDL Panel create a new multidistrict litigation (“MDL”) matter in the District of Kansas, arguing that the factual and legal bases for recovery in their case makes it markedly different from the other MDL cases pending before the Nevada District Court. On October 11, 2006, the MDL Panel struck plaintiffs’ motion based upon the motion lacking the predicate multidistrict character necessary for the MDL Panel to exercise jurisdiction. On September 29, 2006, the defendants filed a Motion to Dismiss based upon the filed rate doctrine and federal preemption. The Court’s ruling on this motion is pending.

~~Breckenridge Brewery of Colorado, LLC, et al. v. ONEOK, Inc., ONEOK Energy Marketing and Trading Company, L.P., et al.~~, originally filed in the District Court of Denver County, Colorado (Case No. 2006-CV-5825), removed to the United States District Court for the District of Colorado (Case No. 06-CV-01110), conditionally transferred to MDL-1566 in the United States District Court for the District of Nevada.~~Plaintiffs’ Motion to Vacate the Conditional Transfer Order was considered by the Judicial Panel for Multidistrict litigation on September 28,~~ 2006. ~~No decision has been issued at this point. Plaintiff’s Motion to Remand is also awaiting decision by the Court.~~

~~J.P. Morgan Trust Company v. ONEOK, Inc., et al~~,originally filed in the District Court of Wyandotte County (Case No. 05-CV-1232), removed to the United States District Court for the District of Kansas (Case No. 05-CV-1331), transferred to MDL-1566 in the United States District Court for the District of Nevada (Case No. 05-CV-1331). On June 22, 2006, the defendants filed a Motion to Dismiss based upon the filed rate doctrine and federal preemption. The Court’s ruling on this motion is pending. On September 28, 2006, the plaintiff filed a motion with the Judicial Panel for Multidistrict Litigation (the “MDL Panel”) requesting that the MDL Panel create a new multidistrict litigation (“MDL”) matter in the District of Kansas, arguing that the factual and legal bases for recovery in its case makes is markedly different from the other MDL cases pending before the Nevada District Court. On October 11, 2006, the MDL Panel struck plaintiff’s motion based upon the motion lacking the predicate multidistrict character necessary for the MDL Panel to exercise jurisdiction.

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. ~~On May 22, 2006, a Motion to Dismiss was filed with~~All payments under the ~~Delaware Chancery Court. The Court’s ruling on~~settlement reached in this ~~motion is pending.~~matter have been made by ONEOK Partners and its insurer. This case has been formally concluded.

~~Missouri Public Service Commission~~Gas Index Pricing Litigation Cases: InSamuel P. Leggett, et al. v. ~~ONEOK, Inc.,~~Duke Energy Corporation, et al.(filed in the Chancery Court for the Twenty-Fifth Judicial District at Somerville, Tennessee, in January 2005), ~~Circuit~~the plaintiffs filed a notice of appeal with the Tennessee Court of ~~Jackson County, Missouri, at Kansas City, Missouri, Civil Action No. 0616-CV27565.On October 6, 2006,~~Appeals on April 4, 2007, appealing the motion to dismiss granted by the trial court.

In addition, a ~~Petition for Damages and Other Relief~~new class action energy trading case was filed ~~by the Missouri Public Service Commission~~ against ~~23 named defendants, including ONEOK, Inc.,~~us, ONEOK Energy Marketing and Trading Company, L.P. ~~(now known as~~(renamed ONEOK Energy Services Company, L.P.), and Kansas Gas Marketing ~~Company.~~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 ~~plaintiff~~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 ~~manipulated~~engaged in a conspiracy to manipulate the ~~natural gas price indices. Plaintiff claims that the defendants violated~~energy trading market in violation of the Missouri ~~antitrust laws, engaged~~Antitrust Law. The plaintiffs seek treble damages. Similar to the other energy trading cases in ~~fraud, and were unjustly enriched by their actions. The plaintiff seeks to recover damages~~which we are involved as reported in our Annual Report on Form 10-K for the ~~difference between what local distribution companies paid~~year ended December 31, 2006, we plan to analyze all of these claims and ~~what they should have paid if the price indices had not been fraudulently manipulated, interest, and attorney fees.~~

~~Notice of Rate Change of Northern Border Pipeline Company, Federal Energy Regulatory Commission, Docket No. RP06-72-000.~~ On September 18, 2006, Northern Border Pipeline (“NBP”) filed a stipulation and agreement pursuant to the settlement reached in its rate case between Northern Border Pipeline and its participant customers. The settlement, supported by the FERC trial staff, establishes maximum long-term rates and charges for transportation on the Northern Border Pipeline system. Beginning in 2007, overall rates will be reduced, compared with rates prior to the filing, by approximately five percent. For the full transportation path from Port of Morgan, Montana to the Chicago area, the previous charge of approximately $0.46 per dekatherm will now be approximately $0.44 per dekatherm, which is comprised of a reservation rate, commodity rate and a compressor usage surcharge. The factors used in calculating depreciation expense for transmission plant are being increased from the current

2.25 percent to 2.40 percent. The settlement provides for seasonal rates for short-term transportation services. Seasonal maximum rates vary on a monthly basis from approximately $0.54 per dekatherm to approximately $0.29 per dekatherm for the full transportation route from Port of Morgan, Montana to the Chicago area. The settlement also includes a three-year moratorium on filing rate cases and participants challenging these rates, and requires that Northern Border Pipeline file a rate case within six years. The non-contested settlement was certified on October 20, 2006 by the administrative law judge presiding over the case and was provided to the FERC for approval. The approval process is expected to be completed by late 2006.

~~United States ex rel. Jack J. Grynberg v. ONEOK, Inc., et al., No. CIV-97-1006-R, United States District Court for the Western District of Oklahoma, transferred,In re Natural Gas Royalties Qui Tam Litigation, MDL Docket No. 1293, United States District Court for the District of Wyoming. On October 20, 2006, the Court entered an order affirming in relevant part the Special Master’s recommendation that all claims~~vigorously defend against ~~us, our subsidiaries, and our Oklahoma Natural Gas division be dismissed. The order remains subject to appeal by Mr. Grynberg.~~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 ~~ending~~ended December 31, ~~2005, and the following risks~~2006, that could affect us and our business. Although we have tried to discuss key factors, ~~please~~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 ~~following~~ 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.”

Our ONEOK Partners segment may not be able to successfully integrate the operations of our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments with their current operations.

The integration of our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments with ONEOK Partners’ current operations will be a complex, time-consuming and costly process. Failure to timely and successfully integrate our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments may have a material adverse effect on our business, financial condition and results of operations. The difficulties of integrating our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments will present challenges to management including:

~~operating a significantly larger combined company with operations in geographic areas in which they have not previously operated;~~

~~managing relationships with new customers for whom they have not previously provided services;~~

~~integrating personnel with diverse backgrounds and organizational cultures;~~

~~experiencing operational interruptions or the loss of key employees, customers or suppliers;~~

working through inefficiencies and complexities that may arise due to our ONEOK Partners segment’s unfamiliarity with the new operations and the businesses associated with them, including with their markets;

~~assimilating the operations, technologies, services and products of our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments into ONEOK Partners;~~

~~assessing the internal controls and procedures for the combined entity that we are required to maintain under the Sarbanes-Oxley Act of 2002;~~

~~consolidating other corporate and administrative functions; and~~

~~the ability of ONEOK Partners to successfully accomplish construction of various pipeline projects and obtain customers.~~

We will also be exposed to risks that are commonly associated with transactions similar to this acquisition, such as unanticipated liabilities and costs, some of which may be material, and diversion of management’s attention. As a result, the anticipated benefits of the integration of our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments into ONEOK Partners may not be fully realized, if at all.

~~A downgrade of ONEOK Partners’ credit rating may require an offer to repurchase certain of their senior notes or may impair ONEOK Partners’ ability to access capital.~~

ONEOK Partners could be required to offer to repurchase certain of its senior notes due 2010 and 2011 at par value, plus any accrued and unpaid interest, if Moody’s Investor Services or Standard & Poor’s Rating Services rates those senior notes below investment grade. Further, the indentures governing ONEOK Partners’ senior notes due 2010, 2011, 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, and 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 the senior notes, which may cause it to borrow money under its credit facilities or seek alternative financing sources to finance the repurchases. 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.

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 ~~equity securities during~~our common stock for the ~~three months ended September 30, 2006.~~periods shown.

Period
   Total Number
of Shares
(or Units)
Purchased    Average Price
Paid per Share
(or Unit)    Total Number of
Shares (or Units)
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
July 1-31, 2006
   7,368 (1)  (2)    $                35.44    -      7,500,000
August 1-31, 2006
   7,550,709 (1)  (2)    $                37.52    7,500,000    -
September 1-30, 2006
   63,816 (1)  (2)    $                38.35    -      -

Total
   7,621,893    $                37.53    7,500,000


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)	~~Includes shares withheld pursuant to attestation of ownership and deemed tendered to us in connection with the exercise of stock options under the ONEOK, Inc. Long-Term Incentive Plan, as follows :~~

~~7,350 shares for the period July 1-31, 2006~~

~~50,484 shares for the period August 1-31, 2006~~

~~63,610 shares for the period September 1-30, 2006~~

~~(2)~~

~~Includes~~Represents shares repurchased directly from employees, pursuant to our Employee Stock Award ~~Program, as follows:~~Program.

~~18 shares for the period July 1-31, 2006~~

~~225 shares for the period August 1-31, 2006~~

~~206 shares for the period September 1-30, 2006~~

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 ~~100,000.~~200,000.

Through ~~September 30, 2006,~~March 31, 2007, a total of ~~63,574~~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 ~~September 30, 2006, under this program.~~March 31, 2007.

Date
   Closing Price
(at or above)    Shares
Issued
July 11, 2006
   $36.00    4,555
July 24, 2006
   $37.00    4,546
August 8, 2006
   $38.00    4,529
August 10, 2006
   $39.00    4,529
Total
      18,159

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 ~~October 17, 2006,~~April 25, 2007, our common stock closed above ~~$40.00~~$47.00 per share, which resulted in ~~4,499~~4,379 shares being issued to eligible employees. On ~~October 23, 2006,~~April 27, 2007, our common stock closed above ~~$41.00~~$48.00 per share, which resulted in ~~4,503~~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		~~Purchase~~Amended and Restated Revolving Credit Agreement dated ~~August 7, 2006, by and between ONEOK, Inc. (the “Issuer”), and UBS AG, London Branch (“UBS”) acting through UBS Securities LLC (“Agent”) as agent.~~

~~10.2~~		~~Underwriting Agreement by and between~~March 30, 2007, among ONEOK Partners, L.P., ~~Citigroup Global Markets Inc.~~as Borrower, the lenders from time to time party thereto, SunTrust Bank, as Administrative Agent, Wachovia Bank, National Association, as Syndication Agent, and ~~SunTrust~~BMO Capital Markets, ~~Inc.~~Barclays Bank PLC, and Citibank, N.A., as ~~representatives of the underwriters dated September 20, 2006 (incorporated by reference to Exhibit 1.1 to ONEOK Partners, L.P.’s Form 8-K filed on September 26, 2006 (File No. 1-12202)).~~

18		~~Preferability Letter of Independent Registered Public Accounting Firm relating to change in accounting principle for annual goodwill impairment test date.~~Co-Documentation Agents.

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

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

32.1		Certification of ~~David L. Kyle~~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 ~~Jim Kneale~~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: ~~November 3, 2006~~May 2, 2007	By:	/s/ ~~Jim Kneale~~Curtis L. Dinan
		~~Jim Kneale~~Curtis L. Dinan ~~Executive~~Senior Vice President, - ~~Finance and Administration~~ ~~and~~ Chief Financial Officer and Treasurer (Principal Financial Officer)

6849


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


Part I.	Financial Information	Page No.

Item 1.	Financial Statements (Unaudited)

	Consolidated Statements of Income - Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005~~	45

	Consolidated Balance Sheets - ~~September 30, 2006~~March 31, 2007 and December 31, ~~2005~~2006	~~5-6~~6-7

	Consolidated Statements of Cash Flows - ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005~~	89

	Consolidated Statements of Shareholders’ Equity and Comprehensive Income - ~~Nine~~Three Months Ended ~~September 30, 2006~~March 31, 2007	~~9-10~~10-11

	Notes to Consolidated Financial Statements	~~11-34~~12-23

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	~~35-61~~24-42

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	~~61-63~~42-45

Item 4.	Controls and Procedures	6346

Part II.	Other Information

Item 1.	Legal Proceedings	~~63-65~~46

Item 1A.	Risk Factors	~~65-66~~46

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	~~66-67~~47

Item 3.	Defaults Upon Senior Securities	6747

Item 4.	Submission of Matters to a Vote of Security Holders	6747

Item 5.	Other Information	6748

Item 6.	Exhibits	6748

Signature	68	49


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
~~Black Mesa~~		~~Black Mesa Pipeline, Inc.~~
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 ~~in the United States~~
Guardian Pipeline		Guardian Pipeline, L.L.C.
~~Intermediate Partnership~~		~~ONEOK Partners Intermediate Limited Partnership, a wholly-owned~~ ~~subsidiary of ONEOK Partners, L.P.~~
KCC		Kansas Corporation Commission
KDHE		Kansas Department of Health and Environment
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
~~RRC~~S&P		~~Texas Railroad Commission~~
~~SCE~~		~~Southern California Edison Company~~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


	Three Months Ended September 30,						Nine Months Ended September 30,
(Unaudited)		2006			2005			2006			2005
		(Thousands of dollars, except per share amounts)

Revenues
Operating revenues, excluding energy trading revenues	$	2,649,312		$	3,181,592		$	8,825,377		$	7,969,014
Energy trading revenues, net		(8,435	)		10,615			3,047			11,023
Total Revenues		2,640,877			3,192,207			8,828,424			7,980,037
Cost of sales and fuel		2,291,891			2,862,888			7,579,939			7,050,344
Net Margin		348,986			329,319			1,248,485			929,693
Operating Expenses
Operations and maintenance		154,501			153,008			468,743			394,985
Depreciation, depletion and amortization		55,468			48,131			178,889			135,020
General taxes		19,482			18,114			57,765			51,061
Total Operating Expenses		229,451			219,253			705,397			581,066
Gain on Sale of Assets		-			-			115,892			-
Operating Income		119,535			110,066			658,980			348,627
Equity earnings from investments (Note O)		22,788			2,822			72,750			8,472
Other income		8,418			4,428			21,735			8,014
Other expense		861			3,365			12,595			8,087
Interest expense		61,460			41,601			176,648			91,682
Income before Minority Interest and Income Taxes		88,420			72,350			564,222			265,344
Minority interests in income of consolidated subsidiaries		48,281			-			184,620			-
Income taxes		15,726			27,736			147,505			101,878
Income from Continuing Operations		24,413			44,614			232,097			163,466
Discontinued operations, net of taxes (Note C)
Income (loss) from operations of discontinued components, net of tax		(13	)		(19,582	)		(410	)		(5,918	)
Gain on sale of discontinued component, net of tax		-			151,355			-			151,355
Net Income	$	24,400		$	176,387		$	231,687		$	308,903

Earnings Per Share of Common Stock (Note P)
Basic:
Earnings per share from continuing operations	$	0.22		$	0.45		$	2.06		$	1.61
Earnings per share from operations of discontinued components, net of tax		-			(0.20	)		-			(0.06	)
Earnings per share from gain on sale of discontinued component, net of tax		-			1.52			-			1.49
Net earnings per share, basic	$	0.22		$	1.77		$	2.06		$	3.04

Diluted:
Earnings per share from continuing operations	$	0.21		$	0.41		$	2.02		$	1.49
Earnings per share from operations of discontinued components, net of tax		-			(0.18	)		-			(0.05	)
Earnings per share from gain on sale of discontinued component, net of tax		-			1.39			-			1.38
Net earnings per share, diluted	$	0.21		$	1.62		$	2.02		$	2.82

Average Shares of Common Stock(Thousands)
Basic		113,200			99,894			112,589			101,568
Diluted		114,920			108,602			114,901			109,555

Dividends Declared Per Share of Common Stock	$	0.32		$	0.28		$	0.90		$	1.09


	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


(Unaudited)	September 30, 2006	December 31, 2005		March 31, 2007		December 31, 2006
Assets	(Thousands of dollars)			(Thousands of dollars)

Current Assets
Cash and cash equivalents	$ 247,475	$ 7,915	$	225,510	$	68,268
Short-term investments				538,030		31,125
Trade accounts and notes receivable, net	944,732	2,202,895		1,286,444		1,348,490
Gas and natural gas liquids in storage	1,028,007	911,393		499,058		925,194
Commodity exchanges	191,184	133,159		67,514		53,433
Energy marketing and risk management assets (Note D)	408,093	399,439		137,726		401,670
Deposits	161,572	150,608
Other current assets	95,835	234,666		326,066		296,781
Total Current Assets	3,076,898	4,040,075		3,080,348		3,124,961


Property, Plant and Equipment
Property, plant and equipment	6,634,992	5,575,365		6,816,441		6,724,759
Accumulated depreciation, depletion and amortization	1,867,565	1,581,138		1,914,845		1,879,838
Net Property, Plant and Equipment (Note A)	4,767,427	3,994,227		4,901,596		4,844,921

Deferred Charges and Other Assets
Goodwill and intangibles (Note E)	1,025,420	683,211
Goodwill and intangible assets (Note E)				1,049,523		1,051,440
Energy marketing and risk management assets (Note D)	111,122	55,713		44,715		91,133
Investments (Note O)	755,772	245,009
Investments in unconsolidated affiliates				746,383		748,879
Other assets	388,982	471,289		526,346		529,748
Total Deferred Charges and Other Assets	2,281,296	1,455,222		2,366,967		2,421,200

Assets of Discontinued Component	62,897	63,911
Total Assets	$ 10,188,518	$ 9,553,435	$	10,348,911	$	10,391,082


(Unaudited)	Common Stock Issued	Common Stock	Paid in Capital	Unearned Compensation
	(Shares)	(Thousands of Dollars)
December 31, 2005	107,973,436	$ 1,080	$ 1,044,283	$ (105)
Net income	-	-	-	-
Other comprehensive income	-	-	-	-
Total comprehensive income
Equity unit conversion	11,208,998	112	177,572	-
Repurchase of common stock	-	-	-	-
Common stock issuance pursuant to various plans	642,694	6	9,232	-
Stock-based employee compensation expense	-	-	12,894	158
Common stock dividends - $0.90 per share	-	-	-	(53)
September 30, 2006	119,825,128	$ 1,198	$1,243,981	$ -


(Unaudited)	Accumulated Other Comprehensive Income (Loss)	Retained Earnings	Treasury Stock	Total
	(Thousands of Dollars)
December 31, 2005	$ (56,991)	$ 1,085,845	$ (279,355)	$ 1,794,757
Net income	-	231,687	-	231,687
Other comprehensive income	90,242	-	-	90,242

Total comprehensive income				321,929

Equity unit conversion	-	-	224,764	402,448
Repurchase of common stock	-	-	(285,646)	(285,646)
Common stock issuance pursuant to various plans	-	-	-	9,238
Stock-based employee compensation expense	-	-	-	13,052
Common stock dividends - $0.90 per share	-	(100,128)	-	(100,181)
September 30, 2006	$ 33,251	$ 1,217,404	$ (340,237)	$ 2,155,597


(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


		Pro Forma Nine Months Ended September 30, 2005
(Thousands of dollars, except per share amounts)
Net margin	$	1,000,771
Net income	$	316,666
Net earnings per share, basic	$	3.12
Net earnings per share, diluted	$	2.89


	Balance December 31, 2005		Additions		Adjustments			Adoption of EITF 04-5		Balance September 30, 2006
		(Thousands of dollars)
Distribution	$	157,953	$	-	$	-		$	-	$	157,953
Energy Services		10,255		-		-			-		10,255
ONEOK Partners		211,087		9,552		(2,001	)		184,843		403,481
Other		1,099		-		-			-		1,099
Goodwill	$	380,394	$	9,552	$	(2,001	)	$	184,843	$	572,788


		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


	Three Months Ended September 30, 2006									Nine Months Ended September 30, 2006
		Gross			Tax (Expense) or Benefit			Net			Gross			Tax (Expense) or Benefit			Net
		(Thousands of dollars)									(Thousands of dollars)
Unrealized gains on energy marketing and risk management assets/liabilities	$	152,678		$	(57,650	)	$	95,028		$	238,874		$	(91,940	)	$	146,934
Realized (gains) losses in net income		(29,478	)		11,402			(18,076	)		(92,453	)		35,761			(56,692	)
Other comprehensive income (loss)	$	123,200		$	(46,248	)	$	76,952		$	146,421		$	(56,179	)	$	90,242


	Three Months Ended September 30, 2005									Nine Months Ended September 30, 2005
		Gross			Tax (Expense) or Benefit			Net			Gross			Tax (Expense) or Benefit		Net
		(Thousands of dollars)									(Thousands of dollars)
Unrealized losses on energy marketing and risk management assets/liabilities	$	(326,493	)	$	118,972		$	(207,521	)	$	(392,126	)	$	151,674	$	(240,452	)
Unrealized holding losses arising during the period		-			-			-			(606	)		223		(383	)
Realized (gains) losses in net income		3,374			(1,305	)		2,069			(6,644	)		2,570		(4,074	)
Assumption of energy marketing and risk management assets/liabilities related to sale of discontinued component		(18,915	)		7,316			(11,599	)		(18,915	)		7,316		(11,599	)
Other comprehensive income (loss)	$	(342,034	)	$	124,983		$	(217,051	)	$	(418,291	)	$	161,783	$	(256,508	)


		September 30, 2006		December 31, 2005
		(Thousands of dollars)
ONEOK
5.51% due 2008	$	402,303	$	402,303
6.0% due 2009		100,000		100,000
7.125% due 2011		400,000		400,000
5.2% due 2015		400,000		400,000
6.4% due 2019		92,623		92,921
6.5% due 2028		91,788		92,246
6.875% due 2028		100,000		100,000
6.0% due 2035		400,000		400,000
Other		3,270		5,732

		1,989,984		1,993,202

ONEOK Partners
8.875% due 2010		250,000		-
7.10% due 2011		225,000		-
5.90% due 2012		350,000		-
6.15% due 2016		450,000		-
6.65% due 2036		600,000		-

		1,875,000		-

Guardian Pipeline
Average 7.85%, due 2022		148,555		-

Total long-term notes payable		4,013,539		1,993,202
Change in fair value of hedged debt		43,737		39,211
Unamortized debt premium		(2,966)		(1,797)
Current maturities		(18,183)		(6,546)
Long-term debt	$	4,036,127	$	2,024,070


		ONEOK		ONEOK Partners		Guardian		Total
		(Millions of dollars)
Remainder of 2006	$	6.3	$	-	$	3.0	$	9.3
2007		6.2		-		11.9		18.1
2008		408.6		-		11.9		420.5
2009		106.3		-		11.9		118.2
2010		6.3		250.0		11.9		268.2


		Unrealized gains (losses) on energy marketing and risk management assets/liabilities			Minimum pension liability adjustment			Accumulated other comprehensive income (loss)
		(Thousands of dollars)
December 31, 2005	$	(49,194	)	$	(7,797	)	$	(56,991	)
Year to date change		90,242			-			90,242
September 30, 2006	$	41,048		$	(7,797	)	$	33,251


		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)


	Pension Benefits Three Months Ended September 30,						Pension Benefits Nine Months Ended September 30,
		2006			2005			2006			2005
Components of Net Periodic Benefit Cost		(Thousands of dollars)
Service cost	$	5,204		$	4,941		$	15,736		$	14,823
Interest cost		10,826			10,758			32,569			32,273
Expected return on assets		(14,396	)		(14,927	)		(43,189	)		(44,780	)
Amortization of unrecognized prior service cost		378			361			1,133			1,082
Amortization of loss		3,278			2,126			9,985			6,377
Net periodic benefit cost	$	5,290		$	3,259		$	16,234		$	9,775


	Postretirement Benefits Three Months Ended September 30,						Postretirement Benefits Nine Months Ended September 30,						Pension Benefits Three Months Ended March 31,						Postretirement Benefits Three Months Ended March 31,
		2006			2005			2006			2005			2007			2006			2007			2006
Components of Net Periodic Benefit Cost		(Thousands of dollars)												(Thousands of dollars)
Service cost	$	1,583		$	1,765		$	4,749		$	5,294		$	5,262		$	5,267		$	1,598		$	1,583
Interest cost		3,539			3,567			10,617			10,702			12,152			10,871			3,957			3,539
Expected return on assets		(1,141	)		(1,086	)		(3,423	)		(3,258	)		(14,538	)		(14,396	)		(1,597	)		(1,141	)
Amortization of unrecognized net asset at adoption		797			864			2,392			2,592			-			-			797			797
Amortization of unrecognized prior service cost		(571	)		118			(1,715	)		354			371			378			(569	)		(571	)
Amortization of loss		2,271			1,617			6,814			4,852
Amortization of net loss														4,035			3,353			2,482			2,271
Net periodic benefit cost	$	6,478		$	6,845		$	19,434		$	20,536		$	7,282		$	5,473		$	6,668		$	6,478


Three Months Ended September 30, 2006		Distribution			Energy Services			ONEOK Partners			Other and Eliminations			Total
Three Months Ended March 31, 2007																		ONEOK Partners (a)		Distribution (b)		Energy Services		Other and Eliminations			Total
		(Thousands of dollars)																(Thousands of dollars)

Sales to unaffiliated customers	$	252,261		$	1,350,802		$	1,045,634		$	615		$	2,649,312			$	1,005,136	$	881,022	$	1,910,547	$	953		$	3,797,658
Energy trading revenues, net		-			(8,435	)		-			-			(8,435	)			-		-		1,348		-			1,348
Intersegment sales		-			51,892			168,949			(220,841	)		-				156,336		-		199,811		(356,147	)		-
Total Revenues	$	252,261		$	1,394,259		$	1,214,583		$	(220,226	)	$	2,640,877
Total revenues																	$	1,161,472	$	881,022	$	2,111,706	$	(355,194	)	$	3,799,006

Net margin	$	106,942		$	30,725		$	210,682		$	637		$	348,986			$	205,147	$	227,228	$	131,404	$	848		$	564,627
Operating costs		88,821			8,637			75,529			996			173,983				75,461		95,715		10,729		174			182,079
Depreciation, depletion and amortization		27,307			524			27,516			121			55,468				27,513		28,275		538		124			56,450
Gain on sale of assets		-			-			-			-			-				2,203		-		-		-			2,203
Operating income	$	(9,186	)	$	21,564		$	107,637		$	(480	)	$	119,535			$	104,376	$	103,238	$	120,137	$	550		$	328,301

Loss from operations of discontinued components	$	-		$	(13	)	$	-		$	-		$	(13	)
Equity earnings from investments	$	-		$	-		$	22,788		$	-		$	22,788			$	24,055	$	-	$	-	$	-		$	24,055
Total assets																	$	5,017,998	$	2,787,508	$	1,794,254	$	749,151		$	10,348,911
Capital expenditures	$	37,154		$	-		$	61,213		$	13,008		$	111,375			$	77,857	$	27,037	$	-	$	2,141		$	107,035

Three Months Ended September 30, 2005		Distribution			Energy Services			ONEOK Partners			Other and Eliminations			Total
		(Thousands of dollars)
Sales to unaffiliated customers	$	316,021		$	1,897,038		$	1,222,324		$	(253,791	)	$	3,181,592
Energy trading revenues, net		-			10,615			-			-			10,615
Intersegment sales		-			110,083			186,632			(296,715	)		-
Total Revenues	$	316,021		$	2,017,736		$	1,408,956		$	(550,506	)	$	3,192,207

Net margin	$	105,104		$	55,040		$	168,734		$	441		$	329,319
Operating costs		91,596			12,451			66,785			290			171,122
Depreciation, depletion and amortization		26,298			533			21,175			125			48,131
Gain on sale of assets		-			-			-			-			-
Operating income	$	(12,790	)	$	42,056		$	80,774		$	26		$	110,066

Income (loss) from operations of discontinued components	$	-		$	(32,972	)	$	-		$	13,390		$	(19,582	)
Equity earnings from investments	$	-		$	-		$	(39	)	$	2,861		$	2,822
Capital expenditures	$	39,069		$	-		$	8,949		$	13,939		$	61,957
(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.																(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.																(b) - All of our Distribution segment's operations are regulated.


	Nine Months Ended September 30,
	2006	2005
Cash paid during the period	(Thousands of dollars)
Interest, including amounts capitalized	$ 163,426	$ 141,868
Income taxes	$ 214,187	$ 55,797


	Number of Shares			Weighted Average Price
Outstanding December 31, 2005	1,952,415		$	22.51
Exercised	(590,921	)	$	23.04
Expired	(2,166	)	$	19.39
Restored	237,111		$	35.03
Outstanding September 30, 2006	1,596,439		$	24.17

Exercisable September 30, 2006	1,405,070		$	22.55


	Stock Options Outstanding						Stock Options Exercisable
Range of Exercise Prices	Number of Awards	Remaining Life (yrs)	Weighted Average Exercise Price		Aggregate Intrinsic Value (in 000’s)		Number of Awards	Remaining Life (yrs)	Weighted Average Exercise Price		Aggregate Intrinsic Value (in 000’s)
$14.58 to $21.87	693,270	5.33	$	17.06	$	14,371	691,728	5.33	$	17.06	$	14,340
$21.88 to $32.82	565,688	4.15	$	25.86	$	6,749	497,305	4.18	$	24.98	$	6,370
$32.83 to $38.83	337,481	3.80	$	35.63	$	729	216,037	3.78	$	34.52	$	706



~~Volatility (a)~~	~~13.88~~	~~% to 31.06%~~
~~Dividend Yield~~	~~2.78~~	~~% to 8.5%~~
~~Risk-free Interest Rate~~	~~2.52~~	~~% to 6.11%~~
~~(a) - Volatility was based on historical volatility over nine~~ ~~months using daily stock price observations.~~


		~~September 30, 2006~~
~~Weighted average grant date fair value (per share)~~		~~$ 5.77~~
~~Intrinsic value of options exercised (thousands of dollars)~~		~~$ 6,761~~
~~Fair value of shares granted (thousands of dollars)~~		~~$ 1,368~~


	Number of Shares			Weighted Average Price
Nonvested December 31, 2005	432,856		$	19.58
Granted	144,750		$	23.82
Released to participants	(198,651	)	$	17.07
Forfeited	(11,261	)	$	20.14
Dividends	1,993		$	27.19
Nonvested September 30, 2006	369,687		$	22.61


		September 30, 2006
Weighted average grant date fair value (per share)	$	23.82
Fair value of shares granted (thousands of dollars)	$	3,448


	Number of Units			Weighted Average Price
Nonvested December 31, 2005	581,847		$	21.13
Granted	479,000		$	25.98
Released to participants	(158,365	)	$	15.31
Forfeited	(20,654	)	$	24.29
Nonvested September 30, 2006	881,828		$	24.74


		~~January 19, 2006~~
~~Volatility (a)~~		~~18.80%~~
~~Dividend Yield~~		~~3.70%~~
~~Risk-free Interest Rate~~		~~4.32%~~
~~(a) - Volatility was based on historical volatility over three years~~ ~~using daily stock price observations.~~


	January 1, 2006		September 30, 2006
Volatility (a)	19.00	%	20.40	%
Dividend Yield	3.70	%	4.00	%
Risk-free Interest Rate	4.37	%	4.62	%
(a) - Volatility was based on historical volatility over three years using daily stock price observations.


	Net Ownership Interest		September 30, 2006			December 31, 2005
		(Thousands of dollars)
Northern Border Pipeline (a)	50%	$	445,243		$	-
Bighorn Gas Gathering	49%		98,246			-
Fort Union Gas Gathering	37%		81,605			-
Lost Creek Gathering (c)	35%		73,938			-
Venice Energy Services Co., LLC	10.2%		39,548			-
Other	Various		17,192			66,607
ONEOK Partners (d)			-			178,402
Total Investment		$	755,772	(b)	$	245,009


		September 30, 2006
	(Thousands of dollars)
Balance Sheet
Current assets	$	88,879
Property, plant and equipment, net	$	1,691,334
Other noncurrent assets	$	24,178
Current liabilities	$	243,826
Long-term debt	$	496,247
Other noncurrent liabilities	$	5,493
Accumulated other comprehensive income	$	1,244
Owners’ equity	$	1,057,581

		Nine Months Ended September 30, 2006
		(Thousands of dollars)
Income Statement
Operating revenue	$	287,816
Operating expenses	$	118,642
Net income	$	135,719
Distributions paid to us	$	93,209


	Three Months Ended September 30, 2006
		Income	Shares		Per Share Amount
Basic EPS from continuing operations		(Thousands, except per share amounts)
Income from continuing operations available for common stock	$	24,413	113,200	$	0.22
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-	1,720
Income from continuing operations available for common stock and common stock equivalents	$	24,413	114,920	$	0.21


	Three Months Ended September 30, 2005
		Income	Shares		Per Share Amount
Basic EPS from continuing operations		(Thousands, except per share amounts)
Income from continuing operations available for common stock	$	44,614	99,894	$	0.45
Diluted EPS from continuing operations
Effect of dilutive securities:
Mandatory convertible units		-	7,515
Options and other dilutive securities		-	1,193
Income from continuing operations available for common stock and common stock equivalents	$	44,614	108,602	$	0.41


	Nine Months Ended September 30, 2006
		Income	Shares		Per Share Amount
Basic EPS from continuing operations		(Thousands, except per share amounts)
Income from continuing operations available for common stock	$	232,097	112,589	$	2.06
Diluted EPS from continuing operations
Effect of dilutive securities:
Mandatory convertible units		-	839
Options and other dilutive securities		-	1,473
Income from continuing operations available for common stock and common stock equivalents	$	232,097	114,901	$	2.02


Nine Months Ended September 30, 2005
						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		Income	Shares		Per Share Amount
Basic EPS from continuing operations		(Thousands, except per share amounts)					(Thousands, except per share amounts)
Income from continuing operations available for common stock	$	163,466	101,568	$	1.61	$	129,739	107,143	$	1.21
Diluted EPS from continuing operations
Effect of dilutive securities:
Mandatory convertible units		-	6,884				-	2,518
Options and other dilutive securities		-	1,103				-	1,095
Income from continuing operations available for common stock and common stock equivalents	$	163,466	109,555	$	1.49	$	129,739	110,756	$	1.17


				March 31,
	September 30, 2006	December 31, 2005		2007		2006
General partner interest	2.00%	1.650%		2.00	%	1.650	%
Limited partner interest	43.70% (a)	1.050% (b)		43.70	% (a)	1.050	% (b)
Total ownership interest	45.70%	2.700%		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.
(a) - Represents approximately 0.5 million common units and 36.5 million Class B units. (b) - Represents approximately 0.5 million common units.			(a) - Represents approximately 0.5 million common units and 36.5 million Class B units. (b) - Represents approximately 0.5 million common units.

Gross
Intangibles

Accumulated
Amortization

Net
Intangibles

(Thousands of dollars)

September 30, 2006

December 31, 2005