ONEOK Partners, L.P. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND MANAGEMENT

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

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.”

ONEOK Partners, L.P. Amended and Restated Partnership Agreement – In May 2006, our sole general partner, ONEOK Partners GP, entered into a Second 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. The MLP Partnership Agreement:

ONEOK Partners Intermediate Limited Partnership Amended and Restated Partnership Agreement – In May 2006, the sole general partner of ONEOK Partners Intermediate Limited Partnership (ILP), ONEOK Partners GP, and we, the sole limited partner of ILP, entered into a Second Amended and Restated Agreement of Limited Partnership of ONEOK Partners Intermediate Limited Partnership (ILP Partnership Agreement) to amend and restate the previously existing partnership agreement, the principal differences of which are as follows. The ILP Partnership Agreement:

ONEOK Partners GP, the sole general partner of us and the sole general partner of the ILP, is a wholly owned subsidiary of ONEOK. ONEOK Partners GP and its affiliates own an approximate 45.7 percent interest in us.

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2. ACQUISITIONS AND DIVESTITURES

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 a $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 SFAS No. 141, “Business Combinations.” Accordingly, ONEOK’s historical cost basis in the ONEOK 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:

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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 $177.0 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 ONEOK’s effective rate. Income tax liabilities and provisions for income tax expense for the ONEOK Energy Assets, as presented herein, were calculated on a stand-alone basis. Our consolidated statement of income for the six months ended June 30, 2006, includes income tax expense recorded by 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 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.

In June 2006, we recorded a $63.2 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 and a receivable from ONEOK in our consolidated balance sheet. The working capital settlement has not been finalized; however, we do not expect material adjustments.

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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 a newly created Class B limited partner unit with the same distribution rights as the outstanding common units, but have limited voting rights and are subordinated related to cash distributions to the common units. Distributions on the Class B units will be prorated from the date of issuance. We will hold a special election for holders of common units as soon as practical but within 12 months, subject to extension, of issuing the Class B units, to approve the conversion of the Class B units into common units and to approve certain amendments to our 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 common unit holders do not approve the conversion and amendments, the Class B unit distribution rights will increase to 115 percent of the distributions paid on the common units. 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. If the common unit holders 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 Class B units distribution rights would continue to be subordinated in the manner described above unless and until the conversion described above has been approved, at which time the amount payable on such Class B units would increase to 125 percent of the distributions payable with respect to the common units.

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. 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, and an affiliate of TransCanada will become the operator of the pipeline effective April 1, 2007. Under SFAS No. 94, “Consolidation of All Majority Owned Subsidiaries,” a majority-owned subsidiary shall not be consolidated if control is likely to be temporary or if it does not rest with the majority owner. Neither we nor TC PipeLines will have control of Northern Border Pipeline, as control will be 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.

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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 a 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.

Overland Pass Natural Gas Liquids Pipeline Joint Venture – 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 Midcontinent natural gas liquids market center in Conway, Kansas. The pipeline will be designed to transport approximately 110,000 Bbl/d of natural gas liquids, which can be increased to approximately 150,000 Bbl/d with additional pump facilities. 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. Williams will have 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, would become operator within two years of the pipeline becoming operational. 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 natural gas liquids 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. At the project’s inception, we paid $11.4 million to Williams for initial capital expenditures incurred. 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.

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3. SUMMARY OF ACCOUNTING POLICIES

We prepared the consolidated financial statements included in this Quarterly Report on Form 10-Q without audit pursuant to the rules and regulations of the SEC. The consolidated financial statements reflect all normal and recurring adjustments that are, in the opinion of management, necessary for a fair presentation of the financial results for the interim periods presented. Certain information and notes normally included in financial statements prepared in accordance with GAAP are condensed or omitted pursuant to such rules and regulations. However, we believe that the disclosures are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2005.

The preparation of financial statements in conformity with GAAP requires management to make assumptions and use estimates that affect the reported amount of the assets, liabilities, revenue and expenses as well as the disclosure of contingent assets and liabilities during the reporting period. Actual results could differ from these estimates if the underlying assumptions are incorrect.

Except as described below, our accounting polices are consistent with those disclosed in Note 2 of the consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2005.

Reclassifications – Certain reclassifications have been made to the 2005 financial statements to conform to the current year presentation. Such reclassifications did not have an impact on previously reported net income or partners’ equity.

Inventories – Inventories are valued at the lower of cost or market. The values of current natural gas and natural gas liquids 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.

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 which 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. SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), as amended by SFAS No. 137 and SFAS No. 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 SFAS No. 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 the current period earnings unless we elect hedge accounting at inception 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. Commodity price volatility may have a significant impact on the gain or loss 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 natural gas liquids. 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 circumstances change. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.

Revenue Recognition – We recognize revenue when services are rendered or product is delivered. The Gathering and Processing segment records operating revenue when gas is processed in or transported through company facilities. Operating revenue of the Gathering and Processing segment is derived from percent-of-proceeds, keep-whole and fee-based contracts. Operating revenue for our Interstate Natural Gas Pipelines segment is recognized based upon contracted capacity and actual volumes transported under transportation service agreements.

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 SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). 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 SFAS No. 71, a write-off of regulatory assets and stranded costs may be required.

At June 30, 2006, we had regulatory assets in the amount of $8.3 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.

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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 differences are expected to be recovered or settled. Except for the companies whose accounting policies conform to SFAS No. 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 SFAS No. 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.

4. CREDIT FACILITIES

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 June 30, 2006, we had borrowings of $311 million and a $15 million letter of credit outstanding under the 2006 Partnership Credit Agreement at a weighted average interest rate of 5.75 percent.

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. Amounts outstanding under the Bridge Facility must be repaid on or before April 5, 2007. We must make mandatory prepayments on any outstanding balance under this credit facility with the net cash proceeds of any asset disposition in excess of $10 million or from the net cash proceeds received from any issuance of equity or debt having a term greater than one year. The interest rate applied to amounts outstanding under the Bridge Facility may, at our option, be the lender’s base rate or an adjusted LIBOR plus a spread that is based on our long-term unsecured debt ratings. At June 30, 2006, the weighted average interest rate for borrowings under the Bridge Facility was 5.67 percent.

Under the 2006 Partnership Credit Agreement and the Bridge Facility, we are required to comply with certain financial, operational and legal covenants. Among other things, we are required to maintain a ratio of EBITDA (net income plus minority interests in net income, interest expense, income taxes and depreciation and amortization) to interest expense of greater than 3 to 1. We are also required to maintain 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 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 acquisition. Upon any breach of these covenants, amounts outstanding under the 2006 Partnership Credit Agreement and the Bridge Facility may become immediately due and payable. At June 30, 2006, we were in compliance with these covenants.

The acquisition of an additional 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 June 30, 2006, Guardian Pipeline had $3.0 million outstanding under its $10 million revolving note agreement at an interest rate of 6.60 percent, due November 8, 2007.

5. LONG-TERM DEBT

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. At June 30, 2006, the unamortized loss on reacquired debt included in other assets on the consolidated balance sheet was $3.7 million.

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The acquisition of an additional 66  ² / 3 percent interest in Guardian Pipeline resulted in the inclusion of $152 million of long-term debt in our consolidated balance sheet. The senior notes comprising such debt 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 and revolving note agreement contain financial covenants (1) restricting the incurrence of other indebtedness by Guardian Pipeline and (2) requiring the maintenance of a minimum interest coverage ratio and a maximum debt ratio. The agreements require the maintenance of a ratio of (1) EBITDA (net income plus interest expense, income taxes and depreciation and amortization) to interest expense of not less than 1.5 to 1 and (2) total indebtedness to EBITDA of not greater than 6.75 to 1. Upon any breach of these covenants, amounts outstanding under the note agreement may become due and payable immediately. At June 30, 2006, Guardian Pipeline was in compliance with its financial covenants.

As a result of no longer consolidating Northern Border Pipeline, we are not reporting its long-term debt subsequent to December 31, 2005.

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

Aggregate repayments of long-term debt required for the next five years are as follows: $6.0 million for the remainder of 2006, $11.9 million in 2007, $11.9 million in 2008, $11.9 million in 2009 and $261.9 million in 2010.

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6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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 gross processing spread and natural gas, natural gas liquids and condensate price volatility. During the three and six months ended June 30, 2006, this segment recognized losses of $0.5 million and gains of $1.4 million, respectively, from the settlement of derivative contracts. At June 30, 2006, the accompanying consolidated balance sheet reflected an unrealized loss of $4.8 million in accumulated other comprehensive loss with a corresponding offset in derivative financial instrument liabilities. If prices remain at current levels, the Gathering and Processing segment expects to reclassify approximately $4.8 million from accumulated other comprehensive loss as a decrease to operating revenue in the remainder of 2006. Ineffectiveness related to these cash flow hedges resulted in a gain of approximately $1.7 million and $3.8 million for the three and six months ended June 30, 2006, respectively. There were no losses during the six months ended June 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 six months ended June 30, 2006, we amortized approximately $0.2 million and $0.3 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 each of the remaining quarters of 2006.

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 June 30, 2006, the average effective interest rate on our interest rate swap agreements was 7.62 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 June 30, 2006, our consolidated balance sheet reflects long-term derivative financial liabilities of $6.9 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 six months ended June 30, 2006, we amortized approximately $0.8 million and $1.6 million, respectively, as a reduction to interest expense and expect to amortize approximately $0.8 million in each of the remaining quarters of 2006.

7. GOODWILL AND INTANGIBLES

The acquisition of the ONEOK Energy Assets resulted in $214.8 million of additional goodwill in our consolidated balance sheet. The annual test of goodwill for these assets was performed as of January 1, 2006, and impairment was not indicated at that time.

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.

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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, Southern California Edison Company (SCE), a 56 percent owner of Mohave, filed a petition before the California Public Utility Commission (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 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. Pending resolution of the issues confronting Mohave, its owners requested that Black Mesa remain prepared to resume coal slurry operations. Pursuant to an agreement reached with SCE, Black Mesa was reimbursed for certain of its standby costs. 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. As a result, Black Mesa is no longer receiving reimbursement for its standby costs. SCE and the other Mohave co-owners are jointly exploring options for Mohave, including the possibility of selling the plant. SCE is also conducting discussions with all involved parties regarding Mohave’s future.

In preparation of our financial statements for the three months ended June 30, 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, would need to be recorded as depreciation and amortization in the second quarter of 2006. The reduction to net income after income taxes was $10.5 million.

We also assessed our Interstate Natural Gas Pipelines segment as a result of the sale of a 20 percent partnership interest in Northern Border Pipeline in April 2006 and the acquisition of a 66  ² / 3 percent interest in Guardian Pipeline in April 2006 and concluded that there was no impairment indicated. Our acquisition of the 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 a ONEOK Energy Asset.

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

In accordance with Accounting Principal Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock,” any premium paid by an investor, which is comparable to goodwill, must be identified. For the investments we account for under the equity method of accounting, this premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill. At June 30, 2006, $185.6 million of equity method goodwill was included in our investment in unconsolidated affiliates on our consolidated balance sheet.

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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 June 30, 2006.