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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2006

OR

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

For the transition period from              to             .

Commission file number 1-12202

ONEOK PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

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

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

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

Large accelerated filer  x                                                      Accelerated filer  ¨                                                 Non-accelerated filer  ¨

Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No   x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

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ONEOK PARTNERS, L.P.

QUARTERLY REPORT ON FORM 10-Q

In this Quarterly Report, references to “we,” “us,” “our” or the “Partnership” refer to ONEOK Partners, L.P. and its subsidiary, ONEOK Partners Intermediate Limited Partnership and its subsidiaries, formerly known as Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership, respectively.

The statements in this Quarterly Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may include words such as “anticipate,” “estimate,” “plan,” “expect,” “project,” “intend,” “believe,” “should” 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 Quarterly Reports and under Part I, Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2005.

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Glossary

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

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PART I-FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ONEOK Partners, L.P. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME

See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' EQUITY AND COMPREHENSIVE INCOME

See accompanying Notes to Consolidated Financial Statements.

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ONEOK Partners, L.P. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

ONEOK Partners, L.P. is a publicly traded Delaware limited partnership that was formed in 1993. Our common units are listed on the NYSE under the trading symbol “OKS.”

Reorganization Agreement - On September 15, 2006, we entered into a Reorganization Agreement with the Intermediate Partnership, ONEOK Partners GP, our general partner, and the ILP GP. The Reorganization Agreement was entered into so that the Intermediate Partnership, as a 100 percent owned subsidiary, would not be subject to SEC reporting requirements; therefore, avoiding the administration burden and costs associated with being a reporting entity. Pursuant to the Reorganization Agreement, the equity ownership structure of the Intermediate Partnership was reorganized so that we became the 100 percent owner of the Intermediate Partnership. Subsequent to the formation of the ILP GP:

ONEOK Partners, L.P. Amended and Restated Partnership Agreement - Effective September 15, 2006, our general partner entered into a Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. (MLP Partnership Agreement) to amend and restate our previously existing partnership agreement, the principal differences of which are as follows:

In May 2006, our sole general partner, ONEOK Partners GP, entered into the Second Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. to amend and restate our previously existing partnership agreement, the principal differences of which are as follows. The amendment to the Partnership Agreement:

ONEOK Partners Intermediate Limited Partnership Amended and Restated Partnership Agreement - Effective September 15, 2006, the ILP GP, as the successor general partner of the Intermediate Partnership, entered into Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of ONEOK Partners Intermediate Limited Partnership (“Amendment No. 1”) to amend the previously existing partnership agreement, the principal differences of which are as follows:

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ONEOK Partners GP, our sole general partner, is a wholly owned subsidiary of ONEOK. ONEOK owns an approximate 45.7 percent interest in us.

Overland Pass Pipeline Company - In May 2006, we 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. As the 99 percent owner of the joint venture, we will manage the construction project, advance all costs associated with construction and 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 us for our 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. We will provide downstream fractionation, storage and transportation services to Williams. The pipeline project is estimated to cost approximately $433 million. In May 2006, we paid $11.4 million to Williams for reimbursement of initial capital expenditures. In addition, we plan to invest approximately $173 million to expand our existing fractionation capabilities and the capacity of our natural gas liquids distribution pipelines. 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.

The ONEOK Transactions - In April 2006, we completed the acquisition of certain companies comprising ONEOK’s former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments, collectively referred to as the “ONEOK Energy Assets,” and several related transactions, which are collectively referred to as the “ONEOK Transactions.” As part of the ONEOK Transactions, ONEOK acquired ONEOK NB, formerly known as Northwest Border Pipeline Company, an affiliate of TransCanada that held a 0.35 percent general partner interest in us, under a Purchase and Sale Agreement between an affiliate of ONEOK and an affiliate of TransCanada. As a result, ONEOK owns our entire two percent general partner interest.

We acquired the ONEOK Energy Assets for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. ONEOK now owns approximately 37.0 million of our limited partner units which, when combined with its general partner interest, increases its total interest in us to 45.7 percent. We used $1.05 billion drawn under our $1.1 billion, 364-day credit agreement (Bridge Facility), coupled with the proceeds from the sale of a 20 percent partnership interest in Northern Border Pipeline, to finance the transaction.

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). EITF 04-5 presumes that a general partner controls a limited partnership and therefore should consolidate the partnership in the financial statements of the general partner. Our Partnership Agreement provides for the right to replace the general partner by a vote of greater than a simple majority of the limited partner interests not held by the general partner and, accordingly, under the guidance in EITF 04-5, ONEOK is deemed to have control for accounting purposes. ONEOK elected to use the prospective method and began to consolidate our operations in their consolidated financial statements as of January 1, 2006. As ONEOK is deemed to control us under the requirements of EITF 04-5, the ONEOK Transactions are accounted for as a transaction between entities under common control and the transaction is excluded from the accounting indicated by Statement 141, “Business Combinations.” Accordingly, ONEOK’s historical cost basis in the ONEOK

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Energy Assets is transferred to us in a manner similar to a pooling of interests. The difference between the historical cost basis of the net assets acquired of $2.7 billion and the cash paid has been assigned to the value of the Class B limited partner units issued to ONEOK and their general partner interest in us. These assets and their related operations are included in our consolidated financial statements as of January 1, 2006. The following table shows the impact to our consolidated balance sheet for the ONEOK Energy Assets as of December 31, 2005.

Since the ONEOK Transactions were not completed until April 2006, the income and cash flow from the ONEOK Energy Assets for the first quarter of 2006 were retained by ONEOK. In our consolidated statements of cash flows, we reported cash flow retained by ONEOK of $177.5 million, which represents the cash flows generated from these companies while they were owned by ONEOK. The following table shows the impact to our consolidated statements of income for the ONEOK Energy Assets prior to our acquisition.

Prior to the acquisition, the ONEOK Energy Assets were included in the consolidated state and federal income tax returns of ONEOK and, accordingly, current taxes payable were allocated to the ONEOK Energy Assets based on

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ONEOK’s effective tax rate. Income tax liabilities and provisions for income tax expense for the ONEOK Energy Assets, as presented in the preceding table, were calculated on a stand-alone basis. Our consolidated statement of income for the nine months ended September 30, 2006, includes income tax expense recorded for the ONEOK Energy Assets of $22.2 million for the first quarter of 2006. In conjunction with the ONEOK Transactions, all income tax liabilities of ONEOK Energy Assets for the first quarter of 2006 were retained by ONEOK.

Income from the ONEOK Energy Assets for the first quarter of 2006 also reflects interest expense of $21.3 million, which represents interest charged on long-term debt owed to ONEOK. The interest rate on the debt was calculated periodically based upon ONEOK’s weighted average cost of debt. This debt was retained by ONEOK as part of the ONEOK Transactions.

We recorded a $63.6 million purchase price adjustment related to a working capital settlement under the terms of the ONEOK Transactions. The working capital settlement 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 of our Audit Committee, resulting in no material adjustments.

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

The units issued to ONEOK are the newly created Class B limited partner units with the same distribution rights as the outstanding common units. The Class B units have limited voting rights and are subordinated to the common units with respect to the minimum quarterly distributions. We will 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 our MLP Partnership Agreement. The proposed amendments to our MLP Partnership Agreement would grant voting rights for common units held by our general partner if a vote is held to remove our 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 the common unitholders, the Class B units will be eligible to convert into common units on a one-for-one basis and the Class B units will no longer be outstanding. If the common unitholders do not approve both the conversion and amendments, then the Class B unit distribution would increase to 115 percent of the distributions paid on the common units, including distributions paid upon liquidation. If the common unitholders vote to remove ONEOK or its affiliates as our general partner at any time prior to the approval of the conversion and certain amendments to our partnership agreement, 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.

Disposition of 20 Percent Partnership Interest in Northern Border Pipeline - In April 2006, we completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million to help finance the acquisition of the ONEOK Energy Assets. We recorded a gain on the sale of approximately $113.9 million in the second quarter of 2006. We and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, with an affiliate of TransCanada becoming the operator of the pipeline in April 2007. Under Statement 94, “Consolidation of All Majority Owned Subsidiaries,” a majority-owned subsidiary shall not be

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consolidated if control is likely to be temporary or if it does not rest with the majority owner. Neither we nor TC PipeLines has control of Northern Border Pipeline, as control is shared equally through Northern Border Pipeline’s Management Committee. We are no longer consolidating Northern Border Pipeline as of January 1, 2006, the effective date of the sale. The amounts we previously reported as assets, liabilities and equity associated with Northern Border Pipeline were reclassified as an investment under the equity method. This change does not affect previously reported net income or shareholders’ equity.

The following table shows the reconciliation of our investment in Northern Border Pipeline at December 31, 2005.

Acquisition of Guardian Pipeline Interests - In April 2006, we acquired the remaining 66-2/3 percent interest in Guardian Pipeline for approximately $77 million, increasing our ownership to 100 percent. We used borrowings from our 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, our 33-1/3 percent interest in Guardian Pipeline was accounted for as an investment under the equity method.

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, are not necessarily indicative of the results that may be expected for a twelve-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.

Our accounting policies are consistent with those disclosed in Note 2 in our Annual Report on Form 10-K for the year ended December 31, 2005, except as described below.

Significant Accounting Policies

Share-Based Payments - In December 2004, the FASB issued Statement 123R, “Share-Based Payment,” which requires companies to expense the fair value of share-based payments and includes changes related to the expense calculation for share-based payments. ONEOK Partners GP and NBP Services adopted Statement 123R as of

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January 1, 2006, and charged us for our proportionate share of the recorded expense. Adopting Statement 123R did not have a material impact on our results of operations or financial position.

Inventory, Natural Gas Imbalances and Commodity Exchanges - Inventory is valued at the lower of cost or market. The values of current natural gas and NGLs in storage are determined using the weighted average cost method. Noncurrent natural gas in storage is classified as property and valued at cost. Materials and supplies are valued at average cost.

Natural gas imbalances occur when the actual amount of natural gas delivered from or received by a pipeline system or storage facility differs from the contractual amount of natural gas to be delivered or received. Imbalances due to or from shippers and operators are valued at market. Imbalances are settled in cash or made up in-kind, subject to the terms of the pipelines’ tariffs. Commodity exchange assets and liabilities are valued at market.

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 it did not have a material impact on our results of operations or financial position.

Derivatives and Risk Management Activities - We use financial instruments in the management of our interest rate and commodity price exposure. A control environment has been established that includes policies and procedures for risk assessment and the approval, reporting and monitoring of financial instrument activities. We do not use these instruments for trading purposes. Statement 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by Statement 137 and Statement 138, requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. Many of the purchase and sale agreements that otherwise would have been required to follow derivative accounting qualify as normal purchases and normal sales under Statement 133 and are therefore exempt from fair value accounting treatment.

We determine the fair value of a derivative instrument by the present value of its future cash flows based on market prices from third party sources. We record changes in the derivative’s fair value in current period earnings unless we elect hedge accounting and specific hedge accounting criteria are met. Accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the income statement, and requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. Commodity price volatility may have a significant impact on the gain or loss of the derivative in any given period.

To minimize the risk of price fluctuations, we periodically enter into futures transactions, collars and swaps in order to hedge anticipated purchases and sales of natural gas, condensate and NGLs. Under certain conditions, we designate these derivative instruments as a hedge of exposure to changes in cash flow. For hedges of exposure to changes in cash flow, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income and subsequently reclassified into earnings when the forecasted transaction affects earnings. Any ineffectiveness of designated hedges is reported in earnings in the period the ineffectiveness occurs.

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

Environmental Expenditures - We accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remediation feasibility study. Such accruals are adjusted as further information becomes available or as circumstances change. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.

Revenue Recognition - Our Natural Gas Liquids segment recognizes revenue when services are rendered or product is delivered. Our Gathering and Processing segment records operating revenue when gas is processed in or transported through company facilities. Operating revenue for our Interstate Natural Gas Pipelines segment and Pipeline and Storage segment is recognized based upon contracted capacity and actual volumes transported and stored under service agreements in the month services are provided.

Regulation - Our intrastate natural gas transmission pipelines are subject to the rate regulation and accounting requirements of the Oklahoma Corporation Commission, Kansas Corporation Commission and Texas Railroad Commission. Our interstate natural gas pipelines and natural gas liquids pipelines are subject to regulation by the FERC. Our Interstate Natural Gas Pipelines segment and portions of our Pipelines and Storage 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 by regulatory authorities could have an effect on the amount recovered from rate payers. Any difference in the amount recoverable and the amount deferred is recorded as income or expense at the time of the regulatory action. If all or a portion of the regulated operations are no longer subject to the provisions of Statement 71, a write-off of regulatory assets and stranded costs may be required.

At September 30, 2006, we had regulatory assets in the amount of $8.1 million included in other assets on our consolidated balance sheet. Regulatory assets are being recovered as a result of approved rate proceedings over various time periods.

Income Taxes -We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of our net assets for financial and income tax purposes cannot be readily determined as we do not have access to all information about each partner’s tax attributes related to us.

Our corporate subsidiaries are required to pay federal and state income taxes. Income taxes are accounted for under the asset and liability method. Deferred income tax assets and liabilities are recognized by these entities for the future tax consequences attributable to differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases and operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary

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differences are expected to be recovered or settled. Except for the companies whose accounting policies conform to Statement 71, the effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. For the companies whose accounting policies conform to Statement 71, the effect on deferred tax assets and liabilities of a change in tax rates is recorded as regulatory assets and regulatory liabilities in the period that includes the enactment date.

In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes,” which clarified the accounting for uncertainty in income taxes recognized in the financial statements in accordance with Statement 109, “Accounting for Income Taxes.” FIN 48 is effective for our year beginning January 1, 2007. We are currently reviewing the applicability of FIN 48 to our operations and its potential impact on our consolidated financial statements.

Other

In September 2006, the SEC staff issued SAB Topic 1N, “Financial Statements - Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements” (SAB 108), which addresses how to quantify the effect of an error on the financial statements. SAB 108 is effective for our fiscal year ending December 31, 2006. We are currently reviewing the applicability of SAB 108 to our operations and its potential impact on our consolidated financial statements.

Reclassifications - Certain amounts in our consolidated financial statements have been reclassified to conform to the 2006 presentation. These reclassifications did not impact previously reported net income or partners’ equity.

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

Under the 2006 Partnership Credit Agreement, we are required to comply with certain financial, operational and legal covenants. These requirements include:

If we consummate 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, we were in compliance with these covenants.

Bridge Facility - In April 2006, we entered into a $1.1 billion 364-day credit agreement (Bridge Facility) with a syndicate of banks and borrowed $1.05 billion to finance a portion of the acquisition of the ONEOK Energy Assets. In September 2006, we repaid the amounts outstanding under the Bridge Facility using proceeds from the issuance of senior notes, which resulted in the Bridge Facility being terminated in accordance with its terms. See Note E for further discussion regarding the issuance of the senior notes.

Guardian Pipeline - Our acquisition of the remaining 66-2/3 percent interest in Guardian Pipeline resulted in the inclusion of outstanding amounts under Guardian Pipeline’s revolving note agreement in our consolidated balance sheet. The revolving note agreement permits Guardian Pipeline to choose rates based on the prime commercial lending rate or LIBOR as the interest rate on its outstanding borrowings, specify the portion of the borrowings to be covered by specific interest rate options and specify the interest rate period. At September 30, 2006, Guardian Pipeline had $4.5 million outstanding under its $10 million revolving note agreement at an interest rate of 6.57 percent, due November 8, 2007.

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Guardian Pipeline’s revolving note agreement contains typical covenants, including 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 note agreement may become due and payable immediately. At September 30, 2006, Guardian Pipeline was in compliance with its financial covenants.

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 2007 through 2010 are shown below.

Debt Issuance - In September 2006, we 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

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of 6.65 percent Senior Notes due 2036 (the “2036 Notes” and collectively with the 2012 Notes and the 2016 Notes, the “Notes”). We registered the sale of the Notes with the SEC pursuant to a shelf registration statement filed on September 19, 2006.

We 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 our existing unsecured senior indebtedness, and effectively junior to all of the existing debt and other liabilities of our non-guarantor subsidiaries. The Notes are non-recourse to our general partner.

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 our 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 September 25, 2006, between us 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 our ability to place liens on our property or assets and sell and lease back our property.

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. We have no significant assets or operations other than our investment in our wholly-owned subsidiary, the Intermediate Partnership, which is also consolidated. The Intermediate Partnership holds a 50 percent interest in Northern Border Pipeline at September 30, 2006, which is accounted for under the equity method.

The Northern Border Pipeline partnership agreement provides that distributions to Northern Border Pipeline’s partners are to be made on a pro rata basis according to each partner’s capital account balance. The Northern Border Pipeline Management Committee determines the amount and timing of such distributions. Any changes to, or suspension of, the cash distribution policy of Northern Border Pipeline requires the unanimous approval of the Northern Border Pipeline Management Committee. Cash distributions are equal to 100 percent of distributable cash flow as determined from Northern Border Pipeline’s financial statements based upon earnings before interest, taxes, depreciation and amortization less interest expense and maintenance capital expenditures. Loans or other advances from Northern Border Pipeline to its partners or affiliates are prohibited under its credit agreement. At September 30, 2006 and December 31, 2005, our equity in the net assets of Northern Border Pipeline was approximately $445 million and $640 million, respectively.

The 2012 Notes, 2016 Notes and 2036 Notes will mature on April 1, 2012, October 1, 2016 and October 1, 2036, respectively. We 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.

Viking Gas Transmission - In March 2006, we borrowed $33 million under our amended and restated revolving credit agreement to redeem all of the outstanding Viking Gas Transmission Series A, B, C and D senior notes and paid a premium of $3.6 million. The net loss from the redemption, including unamortized debt costs associated with the debt, has been capitalized as a regulatory asset and will be amortized to interest expense over the remaining life of the Viking Gas Transmission senior notes, as if such notes had not been redeemed. At September 30, 2006, the unamortized loss on reacquired debt included in other assets on our consolidated balance sheet was $3.5 million.

Guardian Pipeline Master Shelf Agreement - Our 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

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percent. Guardian Pipeline’s master shelf agreement contains covenants which are substantially the same as those contained in Guardian Pipeline’s revolving note agreement, as described further in Note D, except that beginning in December 2007, the rate of total indebtedness to EBITDAR may not be greater than 5.75 to 1.

Northern Border Pipeline - Due to the deconsolidation of Northern Border Pipeline, we are not reporting its long-term debt subsequent to December 31, 2005.

We utilize financial instruments to reduce our market risk exposure to interest rate and commodity price fluctuations and achieve more predictable cash flows. We follow established policies and procedures to assess risk and approve, monitor and report our financial instrument activities. We do not use these instruments for trading purposes.

Cash Flow Hedges - Our Gathering and Processing segment periodically enters into commodity derivative contracts and fixed-price physical contracts. Our Gathering and Processing segment primarily utilizes NYMEX-based futures, collars and over-the-counter swaps, which are designated as cash flow hedges, to hedge its exposure to volatility in the gross processing spread and the price of natural gas, NGLs and condensate. During the three and nine months ended September 30, 2006, this segment recognized net gains from the settlement of derivative contracts that were immaterial. At September 30, 2006, the accompanying consolidated balance sheet reflected an unrealized gain of $1.3 million in accumulated other comprehensive income, with a corresponding offset in derivative financial instrument assets and liabilities. If prices remain at current levels, the Gathering and Processing segment expects to reclassify approximately $3.3 million from accumulated other comprehensive income as an increase to operating revenue in the remainder of 2006, which would offset lower operating revenues in the physical market. In 2007, if prices remain at current levels, the Gathering and Processing segment expects to reclass approximately $2.0 million from accumulated other comprehensive loss as a decrease to operating revenue, which would offset higher operating revenues in the physical market. Ineffectiveness related to these cash flow hedges resulted in a loss of approximately $0.7 million and a gain of approximately $3.1 million for the three and nine months ended September 30, 2006, respectively. There were no losses during the nine months ended September 30, 2006, and 2005, due to the discontinuance of cash flow hedge treatment.

We record in accumulated other comprehensive income amounts related to terminated interest rate swap agreements for cash flow hedges and amortize these amounts to interest expense over the term of the hedged debt. During the three and nine months ended September 30, 2006, we amortized approximately $0.2 million and $0.5 million, respectively, related to the terminated interest rate swap agreements as a reduction to interest expense from accumulated other comprehensive income. We expect to amortize approximately $0.2 million in the fourth quarter of 2006. As of September 30, 2006, $1.9 million related to the terminated interest swap agreements was included in accumulated other comprehensive income on our consolidated balance sheet.

Fair Value Hedges - Our outstanding interest rate swap agreements, with notional amounts totaling $150 million, expire in March 2011. Under these agreements, we make payments to counterparties at variable rates based on LIBOR and receive payments based on a 7.10 percent fixed rate. At September 30, 2006, the average effective interest rate on our interest rate swap agreements was 7.97 percent. Our interest rate swap agreements are designated as fair value hedges as they hedge the fluctuations in the market value of the senior notes issued by us in 2001. As of September 30, 2006, our consolidated balance sheet reflects long-term derivative financial liabilities of $3.2 million, with a decrease in long-term debt related to our fair value hedges.

We record in long-term debt amounts received or paid related to terminated or amended interest rate swap agreements for fair value hedges and amortize these amounts to interest expense over the remaining life of the interest rate swap agreement. During the three and nine months ended September 30, 2006, we amortized approximately $0.8 million and $2.4 million, respectively, as a reduction to interest expense and expect to amortize approximately $0.8 million in the fourth quarter of 2006.

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Goodwill

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

The acquisition of the ONEOK Energy Assets resulted in $214.8 million of additional goodwill in our consolidated balance sheet.

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 in unconsolidated affiliates on our consolidated balance sheet.

Impairment Test - We adopted Statement 142, “Goodwill and Other Intangible Assets” on January 1, 2002, and elected to use a fourth quarter annual 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 as of the fourth quarter and as of January 1. The multiple testing dates resulted from our acquisition of the ONEOK Energy Assets in April 2006 and were due to ONEOK’s former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments using a January 1 testing date. We believe that this change in accounting principle is preferable because (1) ONEOK, who owns our general partnership interest and who consolidates us under EITF 04-5, is using a July 1 impairment testing date, (2) the test would be performed at the same time for all our segments, (3) 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 (4) 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 have occurred subsequent to that date.

Black Mesa - Black Mesa, which was part of our former Coal Slurry Pipeline segment, consisted of a pipeline that was designed to transport crushed coal suspended in water along 273 miles of pipeline that originates at a coal mine in Kayenta, Arizona, and terminates at Mohave Generating Station (Mohave) in Laughlin, Nevada. The coal slurry pipeline was the sole source of fuel for Mohave and was fully contracted to Peabody Western Coal until December 31, 2005. The water used by the coal slurry pipeline was supplied from an aquifer in the Navajo Nation and Hopi Tribe joint use area until December 31, 2005.

Under a consent decree, Mohave agreed to install pollution control equipment by December 2005. However, due to the uncertainty surrounding the ongoing source of water supply and coal supply negotiations, SCE, a 56 percent owner of Mohave, filed a petition before the CPUC requesting that they either recognize the end of Mohave’s coal-fired operations on December 31, 2005, or authorize expenditures for pollution control activities required for future operation. In December 2004, the CPUC authorized SCE to make the necessary expenditures for critical path

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investments and directed interested parties to continue working toward resolution of essential water and coal supply issues.

On December 31, 2005, Black Mesa’s transportation contract with the coal supplier of Mohave expired and our 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 between various parties involved with Black Mesa are ongoing.

During the second quarter of 2006, we reassessed our coal slurry pipeline operation as a result of the developments described above. We concluded that the likelihood of Black Mesa resuming operations was significantly reduced, and a goodwill and asset impairment of $8.4 million and $3.4 million, respectively, were recorded as depreciation and amortization in the second quarter of 2006. The reduction to net income after income taxes was $10.5 million.

Interstate Natural Gas Pipelines - Our acquisition of the remaining 66-2/3 percent interest in Guardian Pipeline resulted in the recognition of $5.7 million of additional goodwill and reclassification of $1.7 million to goodwill, which had been previously included in our investment in unconsolidated affiliates. The remaining increase in goodwill for the Interstate Natural Gas Pipelines segment is related to OkTex Pipeline Company, L.L.C., which was part of the ONEOK Energy Assets.

Intangibles

Our intangible assets primarily relate to contracts acquired through the acquisition of the natural gas liquids businesses from ONEOK and are being amortized over an aggregate weighted-average period of 40 years. The aggregate amortization expense for each of the next five years is estimated to be approximately $7.7 million. The following tables reflect the gross carrying amount and accumulated amortization of intangibles at September 30, 2006.

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The acquisition of the ONEOK Energy Assets in April 2006 is accounted for in our consolidated financial statements effective January 1, 2006. In connection with these transactions, we formed our Natural Gas Liquids segment and Pipelines and Storage segment.

Our business is divided into four reportable segments, defined as components of the enterprise about which financial information is available and evaluated regularly by our management and the Board of Directors of our general partner. Our reportable segments are strategic business units that offer different services. Each segment is managed separately 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 Gathering and Processing segment, which primarily gathers and processes raw natural gas; (2) our Natural Gas Liquids segment, which primarily treats and fractionates raw NGLs and stores and markets purity NGL products; (3) our Pipelines and Storage segment, which primarily operates regulated intrastate natural gas transmission pipelines, natural gas storage facilities and regulated natural gas liquids gathering and distribution pipelines; and (4) our Interstate Natural Gas Pipelines segment, which primarily operates our interstate natural gas transmission pipelines that are regulated by the FERC. Certain assets of the Pipelines and Storage segment are regulated by the FERC and by the Oklahoma Corporation Commission, Kansas Corporation Commission and Texas Railroad Commission.

The accounting policies of the segments are described in Note C. Intersegment gross sales are recorded on the same basis as sales to unaffiliated customers. Our Gathering and Processing segment sells natural gas to ONEOK and its subsidiaries. A significant portion of our Pipelines and Storage segment’s revenues are from ONEOK and its subsidiaries, which utilize both transportation and storage services. Our Interstate Natural Gas Pipelines segment provides transportation services to ONEOK and its subsidiaries. Corporate overhead costs relating to a reportable segment are allocated for the purpose of calculating operating income.

The following tables set forth certain operating segment financial data for the periods indicated.

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