FORM 10-Q
Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


FORM 10-Q

 


 

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

For the quarterly period ended June 30, 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 001-13643

 


ONEOK, Inc.

(Exact name of registrant as specified in its charter)

 


 

Oklahoma   73-1520922

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

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

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

 


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

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

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

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

On July 31, 2006, the Company had 117,557,407 shares of common stock outstanding.

 



Table of Contents

ONEOK, Inc.

QUARTERLY REPORT ON FORM 10-Q

 

          Page No.

Part I.

  

Financial Information

  
Item 1.   

Financial Statements (Unaudited)

  
  

Consolidated Statements of Income - Three and Six Months Ended June 30, 2006 and 2005

   3
  

Consolidated Balance Sheets - June 30, 2006 and December 31, 2005

   4-5
  

Consolidated Statements of Cash Flows - Six Months Ended June 30, 2006 and 2005

   7
  

Consolidated Statements of Shareholders’ Equity and Comprehensive Income - Six Months Ended June 30, 2006

   8-9
  

Notes to Consolidated Financial Statements

   10-30
Item 2.   

Management’s Discussion and Analysis of Financial Condition and Results of Operations

   31-53
Item 3.   

Quantitative and Qualitative Disclosures About Market Risk

   54-56
Item 4.   

Controls and Procedures

   56

Part II.

  

Other Information

  
Item 1.   

Legal Proceedings

   57-58

Item 1A.

  

Risk Factors

   58
Item 2.   

Unregistered Sales of Equity Securities and Use of Proceeds

   59
Item 3.   

Defaults Upon Senior Securities

   59
Item 4.   

Submission of Matters to a Vote of Security Holders

   60
Item 5.   

Other Information

   60
Item 6.   

Exhibits

   61
Signature       62

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.

 

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Part I - FINANCIAL INFORMATION

Item 1. Financial Statements

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME

 

     Three Months Ended
June 30,
   

Six Months Ended

June 30,

(Unaudited)    2006     2005     2006     2005
     (Thousands of dollars, except per share amounts)

Revenues

        

Operating revenues, excluding energy trading revenues

   $ 2,427,795     $ 2,089,574     $ 6,176,064     $ 4,787,422

Energy trading revenues, net

     4,112       (8,784 )     11,482       408
                              

Total Revenues

     2,431,907       2,080,790       6,187,546       4,787,830
                              

Cost of sales and fuel

     2,030,258       1,850,812       5,281,367       4,187,456
                              

Net Margin

     401,649       229,978       906,179       600,374
                              

Operating Expenses

        

Operations and maintenance

     160,173       118,475       320,923       241,977

Depreciation, depletion and amortization

     67,094       43,673       123,420       86,889

General taxes

     19,901       15,648       38,283       32,947
                              

Total Operating Expenses

     247,168       177,796       482,626       361,813
                              

Gain on Sale of Assets

     114,904       —         115,892       —  
                              

Operating Income

     269,385       52,182       539,445       238,561
                              

Other income

     26,266       3,938       63,279       9,236

Other expense

     5,898       3,939       11,734       4,722

Interest expense

     59,603       23,991       115,188       50,081
                              

Income before Minority Interest and Income Taxes

     230,150       28,190       475,802       192,994
                              

Minority interest in income of consolidated subsidiaries

     100,567       —         136,339       —  

Income taxes

     51,638       11,116       131,779       74,142
                              

Income from Continuing Operations

     77,945       17,074       207,684       118,852

Discontinued operations, net of taxes (Note C)

        

Income (loss) from operations of discontinued components, net of tax

     (150 )     7,778       (397 )     13,664
                              

Net Income

   $ 77,795     $ 24,852     $ 207,287     $ 132,516
                              

Earnings Per Share of Common Stock (Note O)

        

Basic:

        

Earnings per share from continuing operations

   $ 0.66     $ 0.17     $ 1.85     $ 1.16

Earnings per share from operations of discontinued components, net of tax

     —         0.08       —         0.13
                              

Net earnings per share, basic

   $ 0.66     $ 0.25     $ 1.85     $ 1.29
                              

Diluted:

        

Earnings per share from continuing operations

   $ 0.65     $ 0.16     $ 1.80     $ 1.08

Earnings per share from operations of discontinued components, net of tax

     —         0.07       —         0.12
                              

Net earnings per share, diluted

   $ 0.65     $ 0.23     $ 1.80     $ 1.20
                              

Average Shares of Common Stock (Thousands)

        

Basic

     117,423       101,143       112,283       102,404

Diluted

     119,026       109,062       114,891       110,031
                              

Dividends Declared Per Share of Common Stock

   $ 0.30     $ 0.56     $ 0.58     $ 0.81
                              

See accompanying Notes to Consolidated Financial Statements.

 

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

 

(Unaudited)   

June 30,

2006

   December 31,
2005
     (Thousands of dollars)

Assets

     

Current Assets

     

Cash and cash equivalents

   $ 645,349    $ 7,915

Trade accounts and notes receivable, net

     971,855      2,202,895

Gas and natural gas liquids in storage

     905,098      911,393

Commodity exchanges

     203,187      133,159

Energy marketing and risk management assets (Note D)

     172,738      765,157

Other current assets

     326,100      385,274
             

Total Current Assets

     3,224,327      4,405,793
             

Property, Plant and Equipment

     

Property, plant and equipment

     6,534,378      5,575,365

Accumulated depreciation, depletion and amortization

     1,823,874      1,581,138
             

Net Property, Plant and Equipment

     4,710,504      3,994,227
             

Deferred Charges and Other Assets

     

Goodwill and intangibles (Note E)

     1,027,336      683,211

Energy marketing and risk management assets (Note D)

     22,869      150,026

Investments and other

     1,127,460      716,298
             

Total Deferred Charges and Other Assets

     2,177,665      1,549,535
             

Assets of Discontinued Component

     63,608      63,911
             

Total Assets

   $ 10,176,104    $ 10,013,466
             

See accompanying Notes to Consolidated Financial Statements.

 

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

 

(Unaudited)   

June 30,

2006

    December 31,
2005
 
     (Thousands of dollars)  

Liabilities and Shareholders’ Equity

  

Current Liabilities

    

Current maturities of long-term debt

   $ 18,485     $ 6,546  

Notes payable

     1,364,000       1,541,500  

Accounts payable

     943,194       1,756,307  

Commodity exchanges

     337,765       238,176  

Energy marketing and risk management liabilities (Note D)

     255,559       814,803  

Other

     403,020       438,009  
                

Total Current Liabilities

     3,322,023       4,795,341  
                

Long-term Debt, excluding current maturities

     2,630,320       2,024,070  

Deferred Credits and Other Liabilities

    

Deferred income taxes

     572,738       603,835  

Energy marketing and risk management liabilities (Note D)

     149,596       442,842  

Other deferred credits

     330,669       350,157  
                

Total Deferred Credits and Other Liabilities

     1,053,003       1,396,834  
                

Liabilities of Discontinued Component

     2,359       2,464  

Commitments and Contingencies (Note K)

    

Minority Interests in Consolidated Subsidiaries

     802,407       —    

Shareholders’ Equity

    

Common stock, $0.01 par value: authorized 300,000,000 shares; issued 119,677,784 shares and outstanding 117,522,979 shares at June 30, 2006; issued 107,973,436 shares and outstanding 97,654,697 shares at December 31, 2005

     1,197       1,080  

Paid in capital

     1,236,695       1,044,283  

Unearned compensation

     —         (105 )

Accumulated other comprehensive loss (Note F)

     (43,701 )     (56,991 )

Retained earnings

     1,230,621       1,085,845  

Treasury stock, at cost: 2,154,805 shares at June 30, 2006 and 10,318,739 shares at December 31, 2005

     (58,820 )     (279,355 )
                

Total Shareholders’ Equity

     2,365,992       1,794,757  
                

Total Liabilities and Shareholders’ Equity

   $ 10,176,104     $ 10,013,466  
                

See accompanying Notes to Consolidated Financial Statements.

 

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

    

Six Months Ended

June 30,

 
(Unaudited)    2006     2005  
     (Thousands of Dollars)  

Operating Activities

  

Net income

   $ 207,287     $ 132,516  

Depreciation, depletion, and amortization

     123,420       86,889  

Gain on sale of assets

     (115,892 )     526  

Minority interest in income of consolidated subsidiaries

     136,339       —    

Distributions received from unconsolidated affiliates

     69,819       570  

Income from equity investments

     (49,817 )     (5,649 )

Deferred income taxes

     9,982       17,471  

Stock-based compensation expense

     8,495       5,983  

Allowance for doubtful accounts

     6,575       8,188  

Changes in assets and liabilities (net of acquisition and disposition effects):

    

Accounts and notes receivable

     1,270,248       494,362  

Inventories

     2,141       42,347  

Unrecovered purchased gas costs

     (51,135 )     1,326  

Commodity exchanges

     29,561       —    

Deposits

     (5,652 )     (44,413 )

Regulatory assets

     12,427       (4,435 )

Accounts payable and accrued liabilities

     (841,045 )     (250,332 )

Energy marketing and risk management assets and liabilities

     (135,401 )     38,782  

Other assets and liabilities

     110,851       (101,085 )
                

Cash Provided by Operating Activities

     788,203       423,046  
                

Investing Activities

    

Changes in other investments, net

     (6,222 )     (30,779 )

Acquisitions

     (128,485 )     —    

Capital expenditures

     (132,593 )     (122,687 )

Proceeds from sale of assets

     298,802       (334 )

Increase in cash and cash equivalents for previously unconsolidated subsidiaries

     1,334       —    

Decrease in cash and cash equivalents for previously consolidated subsidiaries

     (22,039 )     —    

Other investing activities

     (2,376 )     (2,215 )
                

Cash Provided by (Used in) Investing Activities

     8,421       (156,015 )
                

Financing Activities

    

Borrowing (repayment) of notes payable, net

     (384,000 )     (532,500 )

Issuance of debt, net of issuance costs

     —         798,792  

Termination of interest rate swaps

     —         (22,565 )

Payment of debt

     (31,955 )     (335,456 )

Equity unit conversion

     402,448       —    

Repurchase of common stock

     (2,276 )     (112,507 )

Issuance of common stock

     2,657       7,857  

Debt reacquisition costs

     —         —    

Dividends paid

     (62,564 )     (54,576 )

Distributions to minority interests

     (78,594 )     —    

Other financing activities

     (47,996 )     (8,931 )
                

Cash Used in Financing Activities

     (202,280 )     (259,886 )
                

Change in Cash and Cash Equivalents

     594,344       7,145  

Cash and Cash Equivalents at Beginning of Period

     7,915       9,458  

Effect of Accounting Change on Cash and Cash Equivalents

     43,090       —    
                

Cash and Cash Equivalents at End of Period

   $ 645,349     $ 16,603  
                

See accompanying Notes to Consolidated Financial Statements.

 

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

 

(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

   495,350      5      6,503      —    

Stock-based employee compensation expense

   —        —        8,337      158  

Common stock dividends - $0.58 per share

   —        —        —        (53 )
                           

June 30, 2006

   119,677,784    $ 1,197    $ 1,236,695    $ —    
                           

See accompanying Notes to Consolidated Financial Statements.

 

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (Continued)

 

(Unaudited)    Accumulated Other
Comprehensive
Loss
    Retained
Earnings
    Treasury
Stock
    Total  
     (Thousands of Dollars)  

December 31, 2005

   $ (56,991 )   $ 1,085,845     $ (279,355 )   $ 1,794,757  

Net income

     —         207,287       —         207,287  

Other comprehensive income

     13,290       —         —         13,290  
              

Total comprehensive income

           220,577  
              

Equity unit conversion

     —         —         224,764       402,448  

Repurchase of common stock

     —         —         (4,229 )     (4,229 )

Common stock issuance pursuant to various plans

     —         —         —         6,508  

Stock-based employee compensation expense

     —         —         —         8,495  

Common stock dividends - $0.58 per share

     —         (62,511 )     —         (62,564 )
                                

June 30, 2006

   $ (43,701 )   $ 1,230,621     $ (58,820 )   $ 2,365,992  
                                

 

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ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

A. SUMMARY OF ACCOUNTING POLICIES

Our accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America 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 six months ended June 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 A of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2005, except as described below.

Significant Accounting Policies

Consolidation - The consolidated financial statements include the accounts of ONEOK, Inc. and our subsidiaries over which we have control. All significant intercompany accounts and transactions have been eliminated in consolidation. Investments in affiliates are accounted for on the equity method if we have the ability to exercise significant influence over operating and financial policies 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.

In June 2005, the Financial Accounting Standards Board (FASB) ratified the consensus reached in Emerging Issues Task Force (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. Effective January 1, 2006, we were required to consolidate Northern Border Partners, L.P.’s (renamed ONEOK Partners, L.P. on May 17, 2006) 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, L.P. (ONEOK Partners).

We reflect our 45.7 percent share of ONEOK Partners’ accumulated other comprehensive loss at June 30, 2006, in our consolidated accumulated other comprehensive loss. The remaining 54.3 percent is reflected as an adjustment to minority interests in partners’ equity.

Share-Based Payment - In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123R, “Share-Based Payment” (Statement 123R). Statement 123R 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 of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure” (Statement 148) 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.

 

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

 

     June 30,
2006
   December 31,
2005
     (Thousands of dollars)

Distribution

   $ 3,071,227    $ 3,016,668

Energy Services

     7,688      7,690

ONEOK Partners

     3,299,795      2,412,679

Other

     155,668      138,328
             

Property, plant and equipment

     6,534,378      5,575,365

Accumulated depreciation, depletion and amortization

     1,823,874      1,581,138
             

Net property, plant and equipment

   $ 4,710,504    $ 3,994,227
             

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 bases 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 Oklahoma Corporation Commission (OCC), Kansas Corporation Commission (KCC), Texas Railroad Commission (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 Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), which clarified the accounting for uncertainty in income taxes recognized in the financial statements in accordance with FASB Statement 109, “Accounting for Income Taxes.” FIN 48 is effective for our year ending December 31, 2006. We are currently reviewing the applicability of FIN 48 to our operations and its potential impact on our consolidated financial statements.

Regulation - Our intrastate natural gas transmission pipelines 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 Federal Energy Regulatory Commission (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 of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 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 of the regulatory authorities could have an effect on the amount recovered from rate payers. Any difference in the amount recoverable and the amount deferred would be recorded as income or expense at the time of the regulatory action. If all or a portion 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.

Other

Pension and Postretirement Employee Benefits - In March 2006, the FASB issued an exposure draft on accounting for pension and postretirement medical benefits. The final standard for the first phase of this project is expected to be issued in the third quarter of 2006, with implementation required for years ending after December 15, 2006. Based on the exposure draft, we could be required to record a balance sheet liability equal to the difference between our benefit obligations and plan assets. If this requirement had been in place 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.

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 shareholders’ equity. Prior periods have been adjusted to reflect the sale of our Production segment and the pending sale of our Spring Creek power plant as discontinued operations. See Note C for additional information.

 

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B. ACQUISITIONS AND DIVESTITURES

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 LLC (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 barrels per day of natural gas liquids (NGLs), which can be increased to approximately 150,000 barrels per day with additional pump facilities. A subsidiary of ONEOK Partners owns 99 percent of the joint venture, 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 ONEOK Partners its 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 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. At the project’s inception, ONEOK Partners paid $11.4 million to Williams for initial capital expenditures incurred. 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 Northern Plains Natural Gas Company, L.L.C. (renamed ONEOK Partners GP, L.L.C. on May 15, 2006), from an affiliate of TransCanada Corporation (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. In June 2006, ONEOK Partners recorded a $63.2 million estimated purchase price adjustment to the acquired assets related to a working capital settlement which is reflected as a reduction of the value of the Class B units. The working capital settlement has not been finalized; however, we do not expect material adjustments.

In April 2006, in connection with the transactions described immediately above, our ONEOK Partners segment completed the sale of its 20 percent partnership interest in Northern Border Pipeline Company (Northern Border Pipeline) to TC PipeLines Intermediate Limited Partnership (TC PipeLines), an affiliate of TransCanada, for approximately $297 million. Our ONEOK Partners segment recorded a gain on 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 operator of the pipeline in April 2007. Under Statement of Financial Accounting Standards No. 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 we nor TC PipeLines will have control of Northern Border Pipeline, as control will be shared equally through Northern Border Pipeline’s Management Committee. Following the completion of the transactions, ONEOK Partners no longer consolidates Northern Border Pipeline in its financial statements. Instead, its interest in Northern Border Pipeline is accounted for as an investment under the equity method. This change is reflected by ONEOK Partners retroactive to January 1, 2006. 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.

In April 2006, our ONEOK Partners segment acquired a 66  2/3 percent interest in Guardian Pipeline L.L.C. (Guardian Pipeline) for approximately $77 million, increasing our 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 is retroactive to January 1, 2006. Prior to the transaction, our 33  1/3 interest in Guardian Pipeline was accounted for as an investment under the equity method.

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 the 160,000 barrel per day 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. (VESCO). These assets are included in our consolidated financial statements beginning on July 1, 2005.

 

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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.

 

    

Pro Forma

Three Months Ended
June 30, 2005

  

Pro Forma

Six Months Ended
June 30, 2005

     (Thousand of dollars, except per share amounts)

Net margin

   $ 263,914    $ 671,452

Net income

   $ 26,148    $ 139,928

Net earnings per share, basic

   $ 0.26    $ 1.37

Net earnings per share, diluted

   $ 0.24    $ 1.27

C. DISCONTINUED OPERATIONS

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 requires FERC approval and is expected to be completed in 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 proceeds from this sale will be used to purchase other assets, repurchase ONEOK shares or retire debt.

These components of our business are accounted for as discontinued operations in accordance with Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (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 amounts of revenue, costs and income taxes reported in discontinued operations are as follows.

 

     Three Months Ended
June 30,
   Six Months Ended
June 30,
 
     2006     2005    2006     2005  
     (Thousands of dollars)  

Operating revenues

   $ 3,315     $ 40,330    $ 5,164     $ 86,153  

Cost of sales and fuel

     2,386       6,977      3,504       23,631  
                               

Net margin

     929       33,353      1,660       62,522  

Operating costs

     266       8,412      492       16,089  

Depreciation, depletion and amortization

     —         8,492      —         16,772  
                               

Operating income

     663       16,449      1,168       29,661  
                               

Other income (expense), net

     —         5      —         (1 )

Interest expense

     904       3,910      1,808       7,622  

Income taxes

     (91 )     4,766      (243 )     8,374  
                               

Income (loss) from operations of discontinued components, net

   $ (150 )   $ 7,778    $ (397 )   $ 13,664  
                               

 

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The following table discloses the major classes of discontinued assets and liabilities included in our Consolidated Balance Sheet for the periods indicated.

 

     June 30,
2006
   December 31,
2005
     (Thousands of dollars)

Assets

     

Property, plant and equipment, net

   $ 50,937    $ 50,937

Other assets

     12,671      12,974
             

Assets of Discontinued Component

   $ 63,608    $ 63,911
             

Liabilities

     

Accounts payable

   $ 712    $ 1,043

Other liabilities

     1,647      1,421
             

Liabilities of Discontinued Component

   $ 2,359    $ 2,464
             

D.  ENERGY MARKETING AND RISK MANAGEMENT ACTIVITIES AND FAIR VALUE OF FINANCIAL INSTRUMENTS

Accounting Treatment - We account for derivative instruments and hedging activities in accordance with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133). 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 in 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. 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 and is subsequently reclassified into 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, for additional discussion.

Fair Value Hedges

In prior years, we 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 six months ended June 30, 2006 for all terminated swaps was $5.1 million and the remaining net savings for all terminated swaps will be recognized over the following periods:

 

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     ONEOK    ONEOK
Partners
   Total
     (Millions of dollars)

Remainder of 2006

   $ 3.3    $ 1.6    $ 4.9

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, $490 million of fixed rate debt is swapped to floating. Interest on the floating rate debt is based on both the three- and six-month London InterBank Offered Rate (LIBOR), depending upon the swap. Based on the actual performance through June 30, 2006, the weighted average interest rate on the $490 million of debt increased from 6.64 percent to 7.18 percent. At June 30, 2006, we recorded a net liability of $30.2 million to recognize the interest rate swaps at fair value. Long-term debt was decreased by $30.2 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 $3.9 million for the three months ended June 30, 2006, and was immaterial for the three months ended June 30, 2005. The ineffectiveness related to these hedges was $9.3 million for the six months ended June 30, 2006 and was immaterial for the six months ended June 30, 2005.

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 loss at June 30, 2006, includes losses of approximately $28.9 million, net of tax, related to these hedges that will be realized within the next 35 months. If prices remain at current levels, we will recognize $4.1 million in net gains over the next 12 months, and we will recognize net losses of $33.0 million thereafter.

Net gains and losses are reclassified out of accumulated other comprehensive loss to operating revenues or cost of sales and fuel when the anticipated purchase or sale occurs. Ineffectiveness related to our cash flow hedges resulted in a gain of approximately $2.3 million and $9.5 million for the three and six months ended June 30, 2006, respectively. Ineffectiveness related to these cash flow hedges for the three and six months ended June 30, 2005, resulted in a gain of approximately $0.6 million and a loss of approximately $0.1 million, respectively. There were no losses during the six months ended June 30, 2006 and 2005, respectively, due to the discontinuance of cash flow hedge treatment.

Our ONEOK Partners segment periodically enters into derivative instruments to hedge the cash flows associated with our exposure to changes in the price of natural gas, NGLs and condensate. If prices remain at current levels, our ONEOK Partners segment expects to reclassify losses of approximately $2.2 million from accumulated other comprehensive loss to the income statement within the next six months.

Our Distribution segment also uses derivative instruments from time to time. Gains or losses associated with these derivative instruments are included in, and recoverable through, the monthly purchased gas adjustment. At June 30, 2006, Kansas Gas Service had derivative instruments in place to hedge the cost of natural gas purchases for 2.7 Bcf, which represents part of its gas purchase requirements for the 2006/2007 winter heating months. At June 30, 2006, Texas Gas Service had derivative instruments in place to hedge the cost of natural gas purchases for 1.0 Bcf, which represents part of its gas purchase requirements for the 2006/2007 winter heating months.

E. GOODWILL AND INTANGIBLES

Goodwill - In accordance with EITF 04-5, we consolidated our ONEOK Partners segment beginning January 1, 2006.

We performed our annual test of goodwill as of January 1, 2006, for our Energy Services segment, Distribution segment, and portions of our ONEOK Partners segment and there was no impairment indicated. The annual test for goodwill for the remaining portions of our ONEOK Partners segment was performed as of October 1, 2005, and there was no impairment indicated.

 

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During the second quarter of 2006, ONEOK Partners assessed its Black Mesa Pipeline coal slurry pipeline operation. 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 2006. The reduction to our net income, net of minority interest and income taxes, was $3.0 million.

ONEOK Partners also assessed the impact of the sale of its 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 on goodwill and concluded that there was no impairment indicated. The following table reflects the changes in the carrying amount of goodwill for the periods indicated.

 

     Balance
December 31, 2005
   Additions    Adjustments     Adoption of
EITF 04-5
   Balance
June 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
                                   

Goodwill additions in our ONEOK Partners segment include $7.5 million related to our consolidation of Guardian Pipeline, of which $5.7 million relates to the purchase of the additional 66  2/3 percent interest, and $2.1 million related to the incremental one percent acquisition in an affiliate that was previously accounted for under the equity method. Following our acquisition of the additional one percent interest, we began consolidating the entity.

Goodwill adjustments include an $8.4 million reduction related to the Black Mesa Pipeline impairment, offset by $6.4 million in purchase price adjustments. See Note K for discussion of Black Mesa Pipeline impairment.

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 which was previously recorded as our equity investment in ONEOK Partners.

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.

Intangibles - Intangible assets primarily relate to contracts acquired through our acquisition of the natural gas liquids businesses from Koch currently held in our ONEOK Partners segment which 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. Amortization expense for intangible assets for the three and six months ended June 30, 2006 was $1.9 million and $3.8 million, respectively. The following table reflects the gross carrying amount and accumulated amortization of intangibles at June 30, 2006 and December 31, 2005.

 

     Gross
Intangibles
   Accumulated
Amortization
    Net
Intangibles
     (Thousands of dollars)

June 30, 2006

   $ 462,214    $ (7,666 )   $ 454,548

December 31, 2005

   $ 306,650    $ (3,833 )   $ 302,817

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 additional general partner incentive distribution rights acquired through the purchase of TransCanada’s 17.5 percent general partner interest. The intangibles have an indefinite life and accordingly, are not subject to amortization, but are subject to impairment testing.

 

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F. COMPREHENSIVE INCOME

The tables below give an overview of comprehensive income for the periods indicated.

 

     Three Months Ended June 30,  
     2006     2005  
     (Thousands of dollars)  

Net income

     $ 77,795       $ 24,852  

Unrealized gains (losses) on derivative instruments

   $ 5,361       $ (3,421 )  

Realized gains (losses) in net income

     (74,257 )       1,901    
                    

Other comprehensive loss before taxes

     (68,896 )       (1,520 )  

Income tax benefit on other comprehensive loss

     25,700         588    
                    

Other comprehensive loss

       (43,196 )       (932 )
                    

Comprehensive income

     $ 34,599       $ 23,920  
                    
     Six Months Ended June 30,  
     2006     2005  
     Thousands of dollars  

Net income

     $ 207,287       $ 132,516  

Unrealized gains (losses) on derivative instruments

   $ 86,196       $ (84,548 )  

Unrealized holding losses arising during the period

     —           (606 )  

Realized losses in net income

     (62,975 )       (10,018 )  
                    

Other comprehensive income (loss) before taxes

     23,221         (95,172 )  

Income tax benefit (provision) on other comprehensive income (loss)

     (9,931 )       36,800    
                    

Other comprehensive income (loss)

       13,290         (58,372 )
                    

Comprehensive income

     $ 220,577       $ 74,144  
                    

Accumulated other comprehensive loss at June 30, 2006 and 2005, primarily includes unrealized gains and losses on derivative instruments and minimum pension liability adjustments.

G. CAPITAL STOCK

Stock Repurchase Plan - A total of 7.5 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. During the six months ended June 30, 2006, we did not repurchase shares of our common stock under this plan.

Dividends - Quarterly dividends paid on our common stock for shareholders of record as of the close of business on January 31, 2006 and May 1, 2006, were $0.28 per share and $0.30 per share, respectively. Additionally, a quarterly dividend of $0.32 per share was declared in July, payable in the third 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.

 

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H.  LINES OF CREDIT AND SHORT-TERM NOTES PAYABLE

ONEOK Short-term Bridge Financing Agreement - On July 1, 2005, we borrowed $1.0 billion under a new short-term bridge financing agreement to assist in financing our acquisition of assets from Koch. We funded the remaining acquisition cost through our commercial paper program. During the three months ended March 31, 2006, we repaid the remaining $900 million under our short-term bridge financing agreement.

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 new amendment included 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 rate applicable to extensions of credit is 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. ONEOK’s five-year credit agreement includes a $500 million sublimit for the issuance of standby letters of credit. ONEOK’s five-year credit agreement also has a limitation on our debt-to-capital ratio, which may not exceed 67.5 percent at the end of any calendar quarter, a covenant 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 June 30, 2006, we had no borrowings outstanding under this agreement.

ONEOK Partners - 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 June 30, 2006, ONEOK Partners had borrowings of $311.0 million under the 2006 Partnership Credit Agreement and a $15.0 million letter of credit outstanding at a weighted average interest rate of 5.75 percent.

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 to finance a portion of its purchase of certain assets comprising our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments. Amounts outstanding under the Bridge Facility must be paid in full on or before April 5, 2007. ONEOK Partners must make mandatory prepayments on any outstanding balance under the Bridge 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 under the Bridge Facility may, at ONEOK Partners’ option, be the lender’s base rate or an adjusted LIBOR plus a spread that is based upon its 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, 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 minority interests in net income, 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 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.

Guardian Pipeline - ONEOK Partners’ 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 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 the 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.

 

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Guardian Pipeline’s revolving note agreement contains 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 agreements may become due and payable immediately.

General - ONEOK’s five-year credit agreement and ONEOK Partners’ 2006 Partnership Credit Agreement and $1.1 billion 364-day credit agreements contain 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 June 30, 2006, ONEOK and ONEOK Partners were in compliance with all credit agreement covenants.

At June 30, 2006, ONEOK had $143.5 million in letters of credit and no commercial paper outstanding. At June 30, 2006, ONEOK Partners had $15.0 million in letters of credit outstanding.

I. LONG-TERM DEBT

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

 

     June 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

     92,760       92,921  

6.5% due 2028

     92,020       92,246  

6.875% due 2028

     100,000       100,000  

6.0% due 2035

     400,000       400,000  

Other

     5,489       5,732  
                
     1,992,572       1,993,202  
                

ONEOK Partners

    

8.875% due 2010

     250,000       —    

7.10% due 2011

     225,000       —    
                
     475,000       —    
                

Guardian

    

Average 7.85%, due 2022

     151,537       —    
                

Total long-term notes payable

     2,619,109       1,993,202  

Change in fair value of hedged debt

     29,946       39,211  

Unamortized debt premium

     (250 )     (1,797 )

Current maturities

     (18,485 )     (6,546 )
                

Long-term debt

   $ 2,630,320     $ 2,024,070  
                

 

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As of June 30, 2006, current maturities outstanding are $6.6 million for ONEOK and $11.9 million for Guardian Pipeline. The aggregate maturities of long-term debt outstanding for years 2007 through 2010 are shown below.

 

    ONEOK   ONEOK
Partners
  Guardian   Total
    (Millions of dollars)
2007   $ 6.6   $ —     $ 11.9   $ 18.5
2008     408.9     —       11.9     420.8
2009     107.5     —       11.9     119.4
2010     6.3     250.0     11.9     268.2

Additionally, $184.8 million of ONEOK’s debt is callable at par at our option from now until maturity, which is 2019 for $92.8 million and 2028 for $92.0 million. Certain debt agreements have negative covenants that relate to liens and sale/leaseback transactions.

Guardian Pipeline Master Shelf Agreement - ONEOK Partners’ acquisition of an additional 66  2/3 percent interest in Guardian Pipeline resulted in the inclusion of $151.5 million of debt in our consolidated balance sheet. The senior 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 which are the same as Guardian Pipeline’s revolving note agreement, as described in Note H.

J. EMPLOYEE BENEFIT PLANS

The tables below provide the components of net periodic benefit cost for our pension and other postretirement benefit plans.

 

    

Pension Benefits

Three Months Ended
June 30,

   

Pension Benefits

Six Months Ended
June 30,

 
     2006     2005     2006     2005  
     (Thousands of dollars)  

Components of Net Periodic Benefit Cost

  

Service cost

   $ 5,267     $ 4,941     $ 10,532     $ 9,882  

Interest cost

     10,871       10,758       21,742       21,516  

Expected return on assets

     (14,396 )     (14,927 )     (28,794 )     (29,854 )

Amortization of unrecognized prior service cost

     378       361       756       722  

Amortization of loss

     3,353       2,126       6,708       4,252  
                                

Net periodic benefit cost

   $ 5,473     $ 3,259     $ 10,944     $ 6,518  
                                
     Postretirement Benefits
Three Months Ended
June 30,
    Postretirement Benefits
Six Months Ended
June 30,
 
     2006     2005     2006     2005  
     (Thousands of dollars)  

Components of Net Periodic Benefit Cost

  

Service cost

   $ 1,583     $ 1,765     $ 3,166     $ 3,530  

Interest cost

     3,539       3,567       7,078       7,134  

Expected return on assets

     (1,141 )     (1,086 )     (2,282 )     (2,172 )

Amortization of unrecognized net asset at adoption

     797       864       1,595       1,728  

Amortization of unrecognized prior service cost

     (571 )     118       (1,143 )     236  

Amortization of loss

     2,271       1,617       4,542       3,234  
                                

Net periodic benefit cost

   $ 6,478     $ 6,845     $ 12,956     $ 13,690  
                                

Contributions - For the six months ended June 30, 2006, contributions of $0.8 million and $14.6 million were made to our pension plan and other postretirement benefit plan, respectively. For 2006, we anticipate total contributions to our defined benefit pension plan and postretirement benefit plan to be $1.5 million and $17.3 million, respectively. Our pay-as-you-go other

 

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postretirement benefit plan costs were $5.2 million for the six months ended June 30, 2006, and we expect our total pay-as-you-go costs for 2006 to be $14.0 million.

K. COMMITMENTS AND CONTINGENCIES

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

 

     ONEOK    ONEOK
Partners
   Total
     (Millions of dollars)

Remainder of 2006

   $ 24.0    $ 2.3    $ 26.3

2007

     32.7      3.1      35.8

2008

     30.8      2.3      33.1

2009

     28.3      0.9      29.2

2010

     26.1      0.8      26.9

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 - 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 results of operations. If an accidental leak or spill of hazardous materials occurs from our lines or facilities, in the process of transporting natural gas or NGLs, or at any facility that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including investigation and clean up costs, which could materially affect our results of operations and cash flows. In addition, emission controls required under the Federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial condition and results of operations.

We own or retain legal responsibility for the environmental conditions at 12 former manufactured gas sites in Kansas. Our expenditures for environmental evaluation and remediation to date have not been significant in relation to the results of operations, and there have been no material effects upon earnings during 2006 related to compliance with environmental regulations. See Note K in our Annual Report on Form 10-K for the year ended December 31, 2005, for additional discussion. There has been no material change to the status of the manufactured gas sites since December 31, 2005.

Black Mesa Pipeline - On December 31, 2005, our ONEOK Partners segment’s Black Mesa Pipeline was temporarily shut down due to the expiration of its coal slurry transportation contract. Pending resolution of the issues confronting Mohave Generating Station, its owners requested that Black Mesa Pipeline remain prepared to resume coal slurry operations. In accordance with an agreement reached with a co-owner of Mohave Generating Station, Black Mesa Pipeline was reimbursed for its standby costs. In June 2006, a co-owner of Mohave Generating Station announced that the owners would no longer pursue resumption of plant operations. As a result Black Mesa Pipeline is no longer receiving reimbursement for its standby costs. Accordingly, 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.

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.

 

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L. SEGMENTS

Our business segments and the accounting policies of our business segments are the same as those described in Note M and the Summary of Significant Accounting Policies 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. 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. We have 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.

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. 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.

The following tables set forth certain selected financial information for our operating segments for the periods indicated.

 

Three Months Ended June 30, 2006

   Distribution    Energy
Services
    ONEOK
Partners
   Other and
Eliminations
    Total  
     (Thousands of dollars)  

Sales to unaffiliated customers

   $ 317,109    $ 1,103,904     $ 998,070    $ 8,712     $ 2,427,795  

Energy trading revenues, net

     —        4,112       —        —         4,112  

Intersegment sales

     —        86,763       161,280      (248,043 )     —    
                                      

Total Revenues

   $ 317,109    $ 1,194,779     $ 1,159,350    $ (239,331 )   $ 2,431,907  
                                      

Net margin

   $ 119,631    $ 64,327     $ 215,200    $ 2,491     $ 401,649  

Operating costs

     91,524      10,304       77,199      1,047       180,074  

Depreciation, depletion and amortization

     27,161      529       39,282      122       67,094  

Gain on sale of assets

     —        —         113,877      1,027       114,904  
                                      

Operating income

   $ 946    $ 53,494     $ 212,596    $ 2,349     $ 269,385  
                                      

Loss from operations of discontinued components

   $ —      $ (150 )   $ —      $ —       $ (150 )

Income from equity investments

   $ —      $ —       $ 18,075    $ —       $ 18,075  

Capital expenditures

   $ 41,017    $ —       $ 35,799    $ 1,106     $ 77,922  

 

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Table of Contents

Three Months Ended June 30, 2005

   Distribution     Energy
Services
    ONEOK
Partners
   Other and
Eliminations
    Total  
     (Thousands of dollars)  

Sales to unaffiliated customers

   $ 339,794     $ 1,383,473     $ 263,140    $ 103,167     $ 2,089,574  

Energy trading revenues, net

     —         (8,784 )     —        —         (8,784 )

Intersegment sales

     —         171,257       181,409      (352,666 )     —    
                                       

Total Revenues

   $ 339,794     $ 1,545,946     $ 444,549    $ (249,499 )   $ 2,080,790  
                                       

Net margin

   $ 106,492     $ 11,248     $ 114,298    $ (2,060 )   $ 229,978  

Operating costs

     83,477       7,783       44,898      (2,035 )     134,123  

Depreciation, depletion and amortization

     30,014       569       12,978      112       43,673  
                                       

Operating income

   $ (6,999 )   $ 2,896     $ 56,422    $ (137 )   $ 52,182  
                                       

Income (loss) from operations of discontinued components

   $ —       $ (593 )   $ —      $ 8,371     $ 7,778  

Income from equity investments

   $ —       $ —       $ 337    $ 2,496     $ 2,833  

Capital expenditures

   $ 36,323     $ 132     $ 14,035    $ 13,885     $ 64,375  

Six Months Ended June 30, 2006

   Distribution     Energy
Services
    ONEOK
Partners
   Other and
Eliminations
    Total  
     (Thousands of dollars)  

Sales to unaffiliated customers

   $ 1,104,352     $ 3,123,799     $ 1,802,613    $ 145,300     $ 6,176,064  

Energy trading revenues, net

     —         11,482       —        —         11,482  

Intersegment sales

     —         282,650       526,566      (809,216 )     —    
                                       

Total Revenues

   $ 1,104,352     $ 3,417,931     $ 2,329,179    $ (663,916 )   $ 6,187,546  
                                       

Net margin

   $ 315,072     $ 167,481     $ 420,141    $ 3,485     $ 906,179  

Operating costs

     182,037       19,564       155,802      1,803       359,206  

Depreciation, depletion and amortization

     55,314       1,104       66,752      250       123,420  

Gain on sale of assets

     —         —         114,865      1,027       115,892  
                                       

Operating income

   $ 77,721     $ 146,813     $ 312,452    $ 2,459     $ 539,445  
                                       

Income (loss) from operations of discontinued components

   $ —       $ (397 )   $ —      $ —       $ (397 )

Income from equity investments

   $ —       $ —       $ 49,954    $ —       $ 49,954  

Total assets

   $ 2,628,453     $ 1,689,530     $ 5,040,491    $ 817,630     $ 10,176,104  

Capital expenditures

   $ 77,692     $ —       $ 53,575    $ 1,326     $ 132,593  

 

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Table of Contents

Six Months Ended June 30, 2005

   Distribution    Energy
Services
    ONEOK
Partners
   Other and
Eliminations
    Total
     (Thousands of dollars)

Sales to unaffiliated customers

   $ 1,117,924    $ 2,919,829     $ 537,701    $ 211,968     $ 4,787,422

Energy trading revenues, net

     —        408       —        —         408

Intersegment sales

     —        377,165       359,040      (736,205 )     —  
                                    

Total Revenues

   $ 1,117,924    $ 3,297,402     $ 896,741    $ (524,237 )   $ 4,787,830
                                    

Net margin

   $ 307,712    $ 72,443     $ 222,785    $ (2,566 )   $ 600,374

Operating costs

     174,105      15,826       88,698      (3,705 )     274,924

Depreciation, depletion and amortization

     60,003      970       25,692      224       86,889
                                    

Operating income

   $ 73,604    $ 55,647     $ 108,395    $ 915     $ 238,561
                                    

Income (loss) from operations of discontinued components

   $ —      $ (1,441 )   $ —      $ 15,105     $ 13,664

Income from equity investments

   $ —      $ —       $ 636    $ 5,013     $ 5,649

Total assets

   $ 2,660,904    $ 1,300,637     $ 1,899,394    $ 835,935     $ 6,696,870

Capital expenditures

   $ 64,009    $ 159     $ 25,155    $ 33,364     $ 122,687

M. SUPPLEMENTAL CASH FLOW INFORMATION

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

 

     Six Months Ended June 30,
     2006    2005
     (Thousands of dollars)

Cash paid during the period

     

Interest, including amounts capitalized

   $ 125,670    $ 104,149

Income taxes

   $ 159,628    $ 55,260

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

N. SHARE-BASED PAYMENT PLANS

General

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 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 $5.2 million for the six months ended June 30, 2006, net of tax benefit of $2.0 million. No compensation cost was capitalized for the six months ended June 30, 2006.

Cash received from the exercise of awards under all share-based payment arrangements was $3.6 million for the six months ended June 30, 2006. The actual tax benefit realized for the anticipated tax deductions of the exercise of share-based payment arrangements totaled $1.5 million for the six months ended June 30, 2006. No cash was used to settle awards granted under share-based payment arrangements.

 

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Table of Contents

Share-Based Payment Plan Descriptions

The ONEOK, Inc. Long-Term Incentive Plan (the LTIP), 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.

Stock Option Activity

The total fair value of stock options vested during the six months ended June 30, 2006, was $3.6 million. The following table sets forth the stock option activity for employees and non-employee directors for the periods indicated.

 

     Number of
Shares
    Weighted
Average
Exercise Price

Outstanding December 31, 2005

   1,952,415     $ 22.51

Exercised

   (359,256 )   $ 21.39

Expired

   (2,166 )   $ 19.39

Restored

   115,667     $ 31.83
            

Outstanding June 30, 2006

   1,706,660     $ 23.38
            

Exercisable June 30, 2006

   1,582,692     $ 22.72
            

 

     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)

$13.44 to $20.16

   767,172    5.51    $ 17.10    $ 12,996    765,630    5.51    $ 17.10    $ 12,970

$20.17 to $30.26

   667,819    4.42    $ 26.01    $ 5,363    554,822    4.43    $ 24.98    $ 5,027

$30.27 to $35.49

   271,669    3.80    $ 34.40    $ —      262,240    3.78    $ 34.38    $ —  

The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value based on our closing stock price of $34.04 as of June 30, 2006, that would have been received by the option holders had all option holders exercised their options as of that date.

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.

 

Volatility (a)

   13.88% to 31.06 %

Dividend Yield

   2.78% to 8.93 %

Risk-free Interest Rate

   2.52% to 6.53 %

(a) - Volatility was based on historical volatility over six months using daily stock price observations.

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 June 30, 2006, the amount of unrecognized compensation cost related to nonvested stock options was not material.

 

     June 30, 2006

Weighted average grant date fair value (per share)

   $ 5.66

Intrinsic value of options exercised (thousands of dollars)

   $ 3,884

Fair value of shares granted (thousands of dollars)

   $ 655

 

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Table of Contents

Restricted Stock 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 six months ended June 30, 2006, was $5.7 million.

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

 

     Number of
Shares
    Weighted
Average
Exercise 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 June 30, 2006

   369,687     $ 22.61
            

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

 

     Number
of Shares
    Weighted
Average
Exercise
Price

Nonvested December 31, 2005

   119,514     $ 22.44

Released to participants

   (4,086 )   $ 21.55

Forfeited

   (2,912 )   $ 23.19
            

Nonvested June 30, 2006

   112,516     $ 22.45
            

As of June 30, 2006, there was $4.5 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 1.5 years.

 

     June 30, 2006

Weighted average grant date fair value (per share)

   $ 23.82

Fair value of shares granted (thousands of dollars)

   $ 3,448

Performance Unit Activity

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.

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 six months ended June 30, 2006, was $4.9 million.

 

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

 

     Number of
Units
    Weighted
Average
Exercise Price

Nonvested December 31, 2005

   581,847     $ 21.13

Granted

   479,000     $ 25.98

Released to participants

   (158,365 )   $ 15.31

Forfeited

   (16,324 )   $ 23.96
            

Nonvested June 30, 2006

   886,158     $ 24.74
            

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

 

     February 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.

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

 

     Number of
Units
    Weighted
Average
Exercise Price

Nonvested December 31, 2005

   212,311     $ 23.31

Released to participants

   (166 )   $ 23.36

Forfeited

   (7,894 )   $ 23.89
            

Nonvested June 30, 2006

   204,251     $ 23.29
            

 

     January 1, 2006     June 30, 2006  

Volatility (a)

   19.00 %   20.50 %

Dividend Yield

   3.70 %   3.87 %

Risk-free Interest Rate

   4.37 %   5.13 %

(a) - Volatility was based on historical volatility over three years using daily stock price observations.

As of June 30, 2006, there was $14.0 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 1.8 years.

 

     June 30, 2006

Weighted average grant date fair value (per share)

   $ 25.98

Fair value of shares granted (thousands of dollars)

   $ 12,444

 

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Table of Contents

O. EARNINGS PER SHARE INFORMATION

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

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

 

     Three Months Ended June 30, 2006
     Income    Shares    Per Share
Amount
     (Thousands, except per share amounts)

Basic EPS from continuing operations

        

Income from continuing operations available for common stock

   $ 77,945    117,423    $ 0.66

Diluted EPS from continuing operations

        

Effect of options and other dilutive securities

      1,603   
              

Income from continuing operations available for common stock and common stock equivalents

   $ 77,945    119,026    $ 0.65
              
     Three Months Ended June 30, 2005
     Income    Shares    Per Share
Amount
     (Thousands, except per share amounts)

Basic EPS from continuing operations

        

Income from continuing operations available for common stock

   $ 17,074    101,143    $ 0.17

Diluted EPS from continuing operations

        

Effect of dilutive securities:

        

Mandatory convertible units

     —      6,840   

Options and other dilutive securities

     —      1,079   
              

Income from continuing operations available for common stock and common stock equivalents

   $ 17,074    109,062    $ 0.16
              
     Six Months Ended June 30, 2006
     Income    Shares    Per Share
Amount
     (Thousands, except per share amounts)

Basic EPS from continuing operations

        

Income from continuing operations available for common stock

   $ 207,684    112,283    $ 1.85

Diluted EPS from continuing operations

        

Effect of dilutive securities:

        

Mandatory convertible units

     —      1,259   

Options and other dilutive securities

     —      1,349   
              

Income from continuing operations available for common stock and common stock equivalents

   $ 207,684    114,891    $ 1.80
              

 

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     Six Months Ended June 30, 2005
     Income    Shares    Per Share
Amount
     (Thousands, except per share amounts)

Basic EPS from continuing operations

        

Income from continuing operations available for common stock

   $ 118,852    102,404    $ 1.16

Diluted EPS from continuing operations

        

Effect of dilutive securities:

        

Mandatory convertible units

     —      6,569   

Options and other dilutive securities

     —      1,058   
              

Income from continuing operations available for common stock and common stock equivalents

   $ 118,852    110,031    $ 1.08
              

There were 341,300 and 21,964 option shares excluded from the calculation of diluted EPS for the three months ended June 30, 2006 and 2005, respectively, since their inclusion would have been antidilutive for each period. There were 390,112 and 24,977 option shares excluded from the calculation of diluted EPS for the six months ended June 30, 2006 and 2005, respectively, since their inclusion would be antidilutive for each period.

P. ONEOK PARTNERS

General Partner Interest - See Note B for discussion of the April 2006 acquisition of the additional general partner interest in ONEOK Partners. The limited partner units we received from ONEOK Partners were newly created Class B 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. 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.

At June 30, 2006 and 2005, our investment in ONEOK Partners consisted of the following:

 

     June 30,
2006
    June 30,
2005
 

General partner interest

   2.00 %   1.650 %

Limited partner interest

   43.70 %(a)   1.050 %(b)
            

Total ownership interest

   45.70 %   2.700 %
            

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

Under the ONEOK Partners’ partnership agreement, distributions are made to their 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 percent to limited partners and 2.0 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.

 

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ONEOK Partners’ income is allocated to the general and limited partners in accordance with their respective partnership 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’ distributions that were due to the general partners for the periods ending June 30, 2006 and 2005.

 

     Three Months
Ended June 30,
   Six Months Ended
June 30,
     2006    2005    2006    2005
     (Thousands of dollars)

Distributions to ONEOK

   $ 9,078    $ 2,300    $ 11,866    $ 4,600

Distributions to other general partner

     —        488      —        976
                           

Total distributions to general partners

   $ 9,078    $ 2,788    $ 11,866    $ 5,576
                           

The quarterly distributions paid by ONEOK Partners to limited partners in the first and second quarters of 2006 were $0.80 per unit and $0.88 per unit, respectively. In July 2006, ONEOK Partners declared a cash distribution of $0.95 per unit payable in the third quarter. At the current cash distribution of $0.95 per unit, our incentive partner distribution and partner allocation is approximately $8.2 million, payable beginning in the third quarter of 2006.

Affiliate Transactions - We have certain transactions with our 45.7 percent owned ONEOK Partners affiliate, which comprises 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 both transportation and storage services.

As part of the transaction between us and ONEOK Partners, ONEOK Partners acquired contractual rights to process natural gas at the Bushton, Kansas processing plant (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 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.

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 that applies equally to all employees is allocated based upon the number of employees in each affiliate. On the other hand, an expense benefiting the consolidated company but having no direct basis for allocation is allocated through a modified Distrigas method, a method using a combination of ratios of gross plant and investment, operating income and wages.

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

 

     Three Months Ended
June 30, 2006
   Six Months Ended
June 30, 2006
     (Thousands of Dollars)

Revenue

   $ 150,538    $ 380,226
             

Expense

     

Administrative and general expenses

   $ 26,476    $ 45,911

Interest expense

     —        21,281
             

Total expense

   $ 26,476    $ 67,192
             

 

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

EXECUTIVE SUMMARY

Operating income for our second quarter of 2006 was $269.4 million, an increase of $217.2 million, or 416 percent, compared with the same period in 2005. For the first six months of 2006, operating income was $539.4 million, an increase of $300.9 million, or 126 percent, from the same period last year. The increase in operating income, excluding the gain on sale of assets, was $102.3 million and $185.0 million for the three- and six-month periods, respectively. The gain on sale of assets primarily relates to our ONEOK Partners L.P. (formerly Northern Border Partners, L.P.) segment’s sale of its 20 percent partnership interest in Northern Border Pipeline Company (Northern Border Pipeline) to TC PipeLines Intermediate Limited Partnership (TC PipeLines), an affiliate of TransCanada Corporation (TransCanada), in April 2006.

Diluted earnings per share of common stock from continuing operations (EPS) increased to 65 cents for the second quarter of 2006 from 16 cents for the same period in 2005. For the six-month period, EPS increased to $1.80 from $1.08 for the same period last year.

In April 2006, we sold certain assets comprising our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments to Northern Border Partners, L.P. (renamed ONEOK Partners, L.P. on May 17, 2006) 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, L.P. (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 increases in our ONEOK Partners segment in 2006 since we consolidated ONEOK Partners beginning January 1, 2006 in accordance with Emerging Issues Task Force (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). See Impact of New Accounting Standards on page 33 for additional information on the consolidation of ONEOK Partners. In addition, the acquisition of the natural gas liquids businesses owned by Koch Industries, Inc. (Koch) in July 2005, contributed to increases in our ONEOK Partners segment. The purchase of the remaining interest in Guardian Pipeline, L.L.C. (Guardian Pipeline) in April 2006, which resulted in its consolidation retroactive to January 1, 2006, also positively impacted our ONEOK Partners segment. Our legacy operations in the ONEOK Partners segment benefited from higher 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 and processing assets located in Texas in December 2005.

Operating income for our Energy Services segment increased $50.6 million and $91.2 million for the three and six months ended June 30, 2006, respectively. Increases of $21.9 million and $32.0 million for the three and six months ended June 30, 2006, respectively, were related to optimization activities and increased demand fees. Additionally, increases of $16.8 million and $45.0 million for the three and six months ended June 30, 2006, respectively, were due to the effect of improved natural gas basis differentials on transportation contracts.

In July 2006, our Board of Directors announced an increase in our quarterly dividend to $0.32 per share, an increase of approximately seven percent over the $0.30 paid in the second quarter and an increase of approximately 14 percent over the $0.28 paid in the first quarter. This increase is a result of the continued evaluation of our dividend payout in relation to both our financial performance and our peer companies.

Additionally, ONEOK Partners declared an increase in its cash distribution to $0.95 per unit in July 2006, an increase of approximately eight percent over the $0.88 paid in the second quarter and an increase of approximately 19 percent over the $0.80 paid in the first quarter.

ACQUISITIONS AND DIVESTITURES

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 LLC (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 barrels per day of natural gas liquids (NGLs), which can be increased to approximately 150,000 barrels per day with additional pump facilities. A

 

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subsidiary of ONEOK Partners owns 99 percent of the joint venture, 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 ONEOK Partners its 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 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. At the project’s inception, ONEOK Partners paid $11.4 million to Williams for initial capital expenditures incurred. 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 Northern Plains Natural Gas Company, L.L.C. (renamed ONEOK Partners GP, L.L.C. on May 15, 2006), from an affiliate of TransCanada Corporation (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. In June 2006, ONEOK Partners recorded a $63.2 million estimated purchase price adjustment to the acquired assets related to a working capital settlement which is reflected as a reduction of the value of the Class B units. The working capital settlement has not been finalized; however, we do not expect material adjustments.

In April 2006, in connection with the transactions described immediately above, our ONEOK Partners segment completed the sale of its 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. We 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. Following the completion of the transactions, ONEOK Partners no longer consolidates Northern Border Pipeline in its financial statements. Instead, its interest in Northern Border Pipeline is accounted for as an investment under the equity method. This change is reflected by ONEOK Partners retroactive to January 1, 2006. 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.

In April 2006, our ONEOK Partners segment acquired the remaining 66  2/3 percent interest in Guardian Pipeline for approximately $77 million, increasing our 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 is 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.

In December 2005, we sold our natural gas gathering and processing assets located in Texas to 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 entered into an agreement to sell our Spring Creek power plant to Westar Energy, Inc. (Westar) for approximately $53 million. The transaction requires Federal Energy Regulatory Commission (FERC) approval and is expected to be completed in 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 as 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.

 

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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; 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 the 160,000 barrel per day 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. (VESCO). These assets are included in our consolidated financial statements beginning on July 1, 2005.

REGULATORY

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 39 and discussion of our ONEOK Partners segment’s regulatory initiative beginning on page 44.

IMPACT OF NEW ACCOUNTING STANDARDS

In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 123R, “Share-Based Payment” (Statement 123R). Statement 123R 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 of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure” (Statement 148) 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 June 30, 2006, there was $4.5 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 1.5 years. There was $14.0 million of unrecognized compensation cost related to our performance unit awards as of June 30, 2006, which is expected to be recognized over a weighted-average period of 1.8 years. The total unrecognized compensation cost related to nonvested stock options was not material.

In June 2005, the FASB ratified the consensus reached in 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.

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.

In March 2006, the FASB issued an exposure draft on accounting for pension and postretirement medical benefits. The final standard for the first phase of this project is expected to be issued in the third quarter of 2006, with implementation required for years ending after December 15, 2006. Based on the exposure draft, we could be required to record a balance sheet liability equal to the difference between our benefit obligations and plan assets. If this requirement had been in place 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.

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), which clarified the accounting for uncertainty in income taxes recognized in the financial statements in accordance with FASB Statement 109, “Accounting for Income Taxes.” FIN 48 is effective for our year ending December 31, 2006. We are currently reviewing the applicability of FIN 48 to our operations and its potential impact on our consolidated financial statements.

 

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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 of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133), 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 54 for amounts in our portfolio at June 30, 2006, 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, 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 and swaps transactions in order to hedge anticipated purchases and sales of natural gas and condensate, 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 in 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 and is 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.

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 are therefore exempt from fair value accounting treatment.

Impairment of Goodwill and Long-Lived Assets - We assess our goodwill for impairment at least annually based on Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (Statement 142). 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 June 30, 2006, we had $572.8 million of goodwill recorded on our 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 of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144). 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.

 

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Examples of long-lived asset impairment indicators include:

 

    a significant decrease in the market price of a long-lived asset or asset group,

 

    a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition,

 

    a significant adverse change in legal factors or in the business climate that could affect the value of a long-lived asset or asset group, including an adverse action or assessment by a regulator that would exclude allowable costs from the rate-making process,

 

    an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset or asset group,

 

    a current-period operating cash flow loss, combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group, and

 

    a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

In June 2006, we recorded a goodwill and asset impairment related to our ONEOK Partners segment’s Black Mesa Pipeline. For further discussion of this impairment, see Note K of the notes to the Consolidated Financial Statements in this Quarterly Report on Form 10-Q. 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, the impact could be significant to our financial condition and results of operations.

Pension and Postretirement Employee Benefits - We have a defined benefit pension plan covering substantially all full-time employees and a postretirement employee benefits plan covering most employees. 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 Note J in our Annual Report on Form 10-K for the year ended December 31, 2005.

During 2005, 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 $21.9 million related to our defined benefit pension plan and $25.9 million related to postretirement benefits. In determining our estimated expenses for 2006, our actuarial consultant assumed an 8.75 percent expected return on plan assets and a discount rate of 5.75 percent. A decrease in our expected return on plan assets to 8.50 percent would increase our 2006 estimated net periodic benefit costs by approximately $1.6 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 percent would increase our 2006 estimated net periodic benefit costs by approximately $4.9 million for our defined benefit pension plan and $1.6 million for our postretirement benefit plan. For 2006, we anticipate our total contributions to our defined benefit pension plan and postretirement benefit plan to be $1.5 million and $17.3 million, respectively, and our pay-as-you-go other postretirement benefit plan costs to be $14.0 million. See Note J of 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 of Financial Accounting Standards No. 5, “Accounting for Contingencies.” 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.

For further discussion of our accounting policies, see Note A of Notes to the Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

 

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FINANCIAL AND OPERATING RESULTS

Consolidated Operations

The following table sets forth certain selected consolidated financial information for the periods indicated.

 

     Three Months Ended
June 30,
   

Six Months Ended

June 30,

Financial Results

   2006     2005     2006     2005
     (Thousands of dollars)

Operating revenues, excluding energy trading revenues

   $ 2,427,795     $ 2,089,574     $ 6,176,064     $ 4,787,422

Energy trading revenues, net

     4,112       (8,784 )     11,482       408

Cost of sales and fuel

     2,030,258       1,850,812       5,281,367       4,187,456
                              

Net margin

     401,649       229,978       906,179       600,374

Operating costs

     180,074       134,123       359,206       274,924

Depreciation, depletion and amortization

     67,094       43,673       123,420       86,889

Gain on sale of assets

     114,904       —         115,892       —  
                              

Operating income

   $ 269,385     $ 52,182     $ 539,445     $ 238,561
                              

Other income

   $ 26,266     $ 3,938     $ 63,279     $ 9,236

Other expense

   $ 5,898     $ 3,939     $ 11,734     $ 4,722

Minority interest in income of consolidated subsidiaries

   $ 100,567     $ —       $ 136,339     $ —  
                              

Discontinued operations, net of taxes:

        

Income (loss) from operations of discontinued components, net of tax

   $ (150 )   $ 7,778     $ (397 )   $ 13,664
                              

Operating Results - Net margin increased for the three and six months ended June 30, 2006, compared with the same periods in 2005 primarily due to:

 

    the consolidation of our investment in ONEOK Partners as required by EITF 04-5,

 

    the effect of the natural gas liquids assets acquired from Koch in our ONEOK Partners segment,

 

    higher commodity prices, wider gross processing spreads and increased natural gas transportation revenue in our ONEOK Partners segment,

 

    the consolidation of Guardian Pipeline in our ONEOK Partners segment,

 

    an increase in optimization activities and demand fees in our Energy Services segment, and

 

    the effect of increased 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 due to the sale of our natural gas gathering and processing assets located in Texas during December 2005.

Consolidated operating costs increased for the three- and six-month periods primarily due to the consolidation of our investment in ONEOK Partners as required by EITF 04-5, the costs related to the natural gas liquids assets acquired from Koch, the costs related to Guardian Pipeline and increased employee benefit costs.

Depreciation, depletion and amortization increased for the three- and six-month periods primarily due to the consolidation of our investment in ONEOK Partners as required by EITF 04-5, the costs associated with the natural gas liquids assets we acquired from Koch, the Black Mesa Pipeline impairment and the costs associated with Guardian Pipeline. These increases were partially offset by decreases in our Distribution segment due to a charge in the first quarter of 2005 related to the replacement of our customer service system in Texas and due to cathodic protection and service line amortization in Oklahoma from a limited issue rider which expired in the second quarter of 2005.

The gain on sale of assets included in operating income is primarily due to $113.9 million related to ONEOK Partners’ sale of its 20 percent partnership interest in Northern Border Pipeline to TC PipeLines in April 2006. For additional information, see discussion on page 32.

Minority interest expense primarily relates to the portion of ONEOK Partners that we did not own during the three and six months ended June 30, 2006.

 

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

 

     Three Months Ended
June 30,
   Six Months Ended
June 30,
     2006    2005    2006    2005
     (Thousands of dollars)

Equity income

   $ 18,075    $ 2,833    $ 49,954    $ 5,649

Interest income

     5,374      275      6,243      704

Other

     2,817      830      7,082      2,883
                           

Other Income

   $ 26,266    $ 3,938    $ 63,279    $ 9,236
                           
     Three Months Ended
June 30,
   Six Months Ended
June 30,
     2006    2005    2006    2005
     (Thousands of dollars)

Acquisition expense

   $ 4,995    $ 163    $ 9,560    $ 297

Litigation expense and claims, net

     —        2,250      —        2,250

Donations and civic

     565      250      897      542

Other

     338      1,276      1,277      1,633
                           

Other Expense

   $ 5,898    $ 3,939    $ 11,734    $ 4,722
                           

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

Distribution

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

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

 

     Three Months Ended
June 30,
   

Six Months Ended

June 30,

 

Financial Results

   2006     2005     2006    2005  
     (Thousands of dollars)  

Gas sales

   $ 290,550     $ 313,689     $ 1,041,322    $ 1,055,994  

Transportation revenues

     18,834       19,156       45,187      47,528  

Cost of gas

     197,478       233,302       789,280      810,212  
                               

Gross margin

     111,906       99,543       297,229      293,310  

Other revenues

     7,725       6,949       17,843      14,402  
                               

Net margin

     119,631       106,492       315,072      307,712  

Operating costs

     91,524       83,477       182,037      174,105  

Depreciation, depletion and amortization

     27,161       30,014       55,314      60,003  
                               

Operating income (loss)

   $ 946     $ (6,999 )   $ 77,721    $ 73,604  
                               

Other income (expense), net

   $ (470 )   $ (119 )   $ 633    $ (312 )
                               

Operating Results - Net margin increased by $13.1 million for the three months ended June 30, 2006, compared with the same period in 2005, primarily due to:

 

    an increase of $15.4 million primarily due to the implementation of new rate schedules in Oklahoma and

 

    a decrease of $3.1 million due to expiring riders and lower volumetric rider collections in Oklahoma.

 

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Net margin increased by $7.4 million for the six months ended June 30, 2006, compared with the same period in 2005, primarily due to:

 

    an increase of $30.3 million primarily due to the implementation of new rate schedules in Oklahoma,

 

    a decrease of $15.8 million due to expiring riders and lower volumetric rider collections in Oklahoma,

 

    a decrease of $9.0 million in customer sales due to warmer weather in our entire service territory and

 

    an increase of $2.0 million attributable to return on storage investments in Oklahoma.

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

Operating costs increased $8.0 million for the three-month period primarily due to an increase in labor and employee benefit costs of $7.8 million. The $7.9 million increase for the six-month period was primarily due to an increase of $9.9 million in labor and employee benefit costs, which was offset by a $2.7 million decrease in bad debt expense.

Depreciation, depletion and amortization decreased $2.9 million and $4.7 million for the three and six months ended June 30, 2006, respectively, due to a $2.9 million charge in the first quarter of 2005 related to the replacement of our customer service system in Texas and due to $2.0 million in cathodic protection and service line amortization in Oklahoma from a limited issue rider which expired in the second quarter of 2005.

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

 

    

Three Months Ended

June 30,

  

Six Months Ended

June 30,

Operating Information

   2006    2005    2006    2005

Average number of customers

     2,031,795      2,019,953      2,041,155      2,031,720

Customers per employee

     709      688      710      687

Capital expenditures (Thousands of dollars)

   $ 41,017    $ 36,323    $ 77,692    $ 64,009
    

Three Months Ended

June 30,

  

Six Months Ended

June 30,

Margin

   2006    2005    2006    2005

Gas sales

     (Thousands of dollars)

Residential

   $ 76,810    $ 66,389    $ 205,214    $ 193,380

Commercial

     16,088      14,340      47,967      52,195

Industrial

     750      329      1,608      1,589

Wholesale

     1,943      1,616      2,812      3,196

Public Authority

     460      573      1,280      1,561
                           

Gross margin on gas sales

     96,051      83,247      258,881      251,921

Transportation

     15,855      16,296      38,348      41,389
                           

Gross margin

   $ 111,906    $ 99,543    $ 297,229    $ 293,310
                           

 

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Table of Contents
     Three Months Ended
June 30,
   Six Months Ended
June 30,

Volumes (MMcf)

   2006    2005    2006    2005

Gas sales

           

Residential

   12,506    14,502    64,929    73,047

Commercial

   4,087    5,238    19,394    23,317

Industrial

   384    419    964    1,201

Wholesale

   11,567    9,584    16,507    16,456

Public Authority

   281    323    1,168    1,288
                   

Total volumes sold

   28,825    30,066    102,962    115,309

Transportation

   46,553    58,419    103,512    127,590
                   

Total volumes delivered

   75,378    88,485    206,474    242,899
                   

Residential and commercial volumes decreased for the three- and six-month periods due to warmer weather, primarily 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 increased for the three months ended June 30, 2006 as fewer volumes were required to meet customers’ demands, resulting in additional volume being available for sale to other parties.

Public authority natural gas volumes reflect volumes used by state and local agencies and school districts serviced 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 $11.3 million and $10.4 million for new business development for the three months ended June 30, 2006 and 2005, respectively, and $24.8 and $19.8 million for new business development for the six months ended June 30, 2006 and 2005, respectively. Increased spending in 2006 represents timing differences and capital spending related to our new customer service and billing system.

Regulatory Initiatives

Kansas - On May 15, 2006, Kansas Gas Service announced that it filed a request with the Kansas Corporation Commission (KCC) to increase its annual revenues by $73.3 million. Since its last rate case in 2003, Kansas Gas Service has 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.

Texas - Texas Gas Service has received several regulatory approvals to implement rate increases in various municipalities in Texas. A total of $4.7 million in revenue increases have been agreed upon or approved in 2006 and we expect the new rates to be fully implemented by mid-August 2006.

Union - The contract with the International Brotherhood of Electrical Workers (IBEW) expired June 30, 2006. Negotiations are ongoing.

General - Certain costs to be recovered through the ratemaking process have been recorded as regulatory assets in accordance with Statement 71. 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.

 

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Table of Contents

Energy Services

Overview - Our Energy Services segment’s primary focus is to create value for our customers by delivering physical natural gas products and risk management services through our network of contracted transportation and storage capacity and natural gas supply. These services include meeting our customers’ baseload, swing and peaking natural gas commodity requirements on a year-round basis. To provide these bundled services, we lease storage and transportation capacity. Our total storage capacity under lease is 86 Bcf, with maximum withdrawal capability of 2.2 Bcf per day and maximum injection capability of 1.5 Bcf per day. Our current transportation capacity is 1.5 Bcf per day. The contracted storage and transportation capacity connects the major supply and demand centers throughout the United States and Canada. With these contracted assets, our ongoing business strategies include identifying, developing and delivering specialized services and products for premium value to 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 May 2006, our Energy Services segment was selected to provide subsidiaries of FirstEnergy Corporation (FirstEnergy) with natural gas supply and natural gas management services for its three natural gas-fired electric generation plants located in Richland and West Lorain, Ohio and Sumpter, Michigan. Under the three-year contract, we will serve as the exclusive natural gas commodity and services provider, be FirstEnergy’s agent responsible for managing its transportation and storage capacity, and be responsible for optimizing the delivered cost of the gas to FirstEnergy.

Our Energy Services segment, which consists of wholly owned subsidiaries, regularly provides services to our 45.7 percent owned ONEOK Partners affiliate, which comprises our ONEOK Partners 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.

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. These assets were held for sale at June 30, 2006, and, accordingly, 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 below. For additional information, see discussion of discontinued operations on page 45.

 

     Three Months Ended
June 30,
   

Six Months Ended

June 30,

 

Financial Results

   2006     2005     2006     2005  
     (Thousands of dollars)  

Energy and power revenues

   $ 1,190,666     $ 1,554,534     $ 3,406,333     $ 3,296,592  

Energy trading revenues, net

     4,112       (8,784 )     11,482       408  

Other revenues

     1       196       116       402  

Cost of sales and fuel

     1,130,452       1,534,698       3,250,450       3,224,959  
                                

Net margin

     64,327       11,248       167,481       72,443  

Operating costs

     10,304       7,783       19,564       15,826  

Depreciation, depletion and amortization

     529       569       1,104       970  
                                

Operating income

   $ 53,494     $ 2,896     $ 146,813     $ 55,647  
                                

Other income (expense), net

   $ (3,674 )   $ (1,966 )   $ (6,616 )   $ (3,855 )
                                

 

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Table of Contents
     Three Months Ended
June 30,
   Six Months Ended
June 30,

Operating Information

   2006    2005    2006    2005

Natural gas marketed (Bcf)

     254      275      564      600

Natural gas gross margin ($/Mcf)

   $ 0.25    $ 0.02    $ 0.26    $ 0.09

Physically settled volumes (Bcf)

     536      574      1,138      1,199

Capital expenditures (Thousands of dollars)

   $ —      $ 132    $ —      $ 159

Operating Results - Net margin increased by $53.1 million for the three months ended June 30, 2006, compared with the same period in 2005, primarily due to:

 

    an increase of $21.9 million related to storage and marketing margins primarily due to optimization activities from a favorably priced supply position,

 

    an increase of $16.8 million in 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 $13.3 million in our natural gas trading activities primarily due to improved trading margins in the natural gas option portfolios derived from lower natural gas prices, and

 

    an increase of $1.3 million in retail activities due to improved physical margins.

Net margin increased $95.0 million for the six months ended June 30, 2006 compared with the same period in 2005, primarily due to:

 

    an increase of $45.0 million in 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 $32.0 million related to storage and marketing margins primarily due to an increase in demand fees associated with our peaking and load following services in the first quarter of 2006 and optimization activities in the second quarter of 2006,

 

    an increase of $17.4 million in our natural gas trading operations primarily associated with favorable basis spread movements in the basis trading portfolio and improved trading margins in the option portfolio, and

 

    an increase of $1.5 million in retail activities due to improved physical margins.

Operating costs increased $2.5 million and $3.7 million for the three and six months ended June 30, 2006, respectively, primarily due to increased employee-related costs.

Natural gas volumes marketed decreased for the three- and six-month periods in 2006 compared with 2005, primarily due to higher storage injections in the second quarter of 2006 and warmer weather in the majority of our service territory in the first quarter of 2006 resulting in decreased storage withdrawals.

Our natural gas in storage at June 30, 2006, was 73.3 Bcf compared with 59.0 Bcf at June 30, 2005. At June 30, 2006 and 2005, our total natural gas storage capacity under lease was 86 Bcf.

For derivative instruments considered “held for trading purposes” that result in physical delivery, the indicators in 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” are used to determine the proper 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 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 EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19) are used to determine the proper treatment. We account for the realized revenues and purchase costs of these contracts that result in physical delivery 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.

 

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

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2006     2005     2006     2005  
     (Thousands of dollars)  

Marketing and storage, gross

   $ 95,637     $ 52,952     $ 230,705     $ 144,439  

Less: Storage and transportation costs

     (44,282 )     (40,074 )     (93,541 )     (83,376 )
                                

Marketing and storage, net

     51,355       12,878       137,164       61,063  

Retail marketing

     4,310       3,047       9,759       8,257  

Financial trading

     8,662       (4,677 )     20,558       3,123  
                                

Net margin

   $ 64,327     $ 11,248     $ 167,481     $ 72,443  
                                

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

Retail marketing includes revenues from providing physical marketing and supply services to residential and small commercial and industrial customers.

Financial trading revenues include 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 statement includes certain physical natural gas transactions with our trading counterparties and financial trading margins. Revenues and cost of sales and fuel from such physical transactions are required to be reported on a net basis.

ONEOK Partners

Overview - Our ONEOK Partners segment gathers, processes, transports and stores natural gas; gathers, treats, stores and fractionates NGLs and provides NGL gathering and distribution services.

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 NGLs, and store NGL purity products produced from gas processing plants located in Oklahoma, Kansas and the Texas panhandle. We 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.

 

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

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 

Financial Results

   2006    2005     2006    2005  
     (Thousands of dollars)  

Commodity based revenues

   $ 1,013,383    $ 372,612     $ 2,046,592    $ 756,224  

Fee based revenues

     97,861      69,095       199,201      134,919  

Other revenues

     48,106      2,842       83,386      5,598  

Cost of sales and fuel

     944,150      330,251       1,909,038      673,956  
                              

Net margin

     215,200      114,298       420,141      222,785  

Operating costs

     77,199      44,898       155,802      88,698  

Depreciation, depletion and amortization

     39,282      12,978       66,752      25,692  

Gain on sale of assets

     113,877      —         114,865      —    
                              

Operating income

   $ 212,596    $ 56,422     $ 312,452    $ 108,395  
                              

Other income (expense), net

   $ 16,193    $ (427 )   $ 49,088    $ (262 )

Minority interest in income of consolidated subsidiaries

   $ 519    $ —       $ 2,138    $ —    
                              
     Three Months Ended
June 30,
    Six Months Ended
June 30,
 

Operating Information

   2006    2005     2006    2005  

Total gas gathered (BBtu/d) (b)

     1,142      1,131       1,149      1,121  

Total gas processed (BBtu/d) (b)

     993      1,167       958      1,135  

Natural gas liquids gathered (MBbl/d)

     213      (a )     203      (a )

Natural gas liquids sales (MBbl/d)

     199      87       203      93  

Natural gas liquids fractionated (MBbl/d)

     333      (a )     309      (a )

Natural gas transported (MMcf)

     112,998      108,898       245,533      240,228  

Gas sales (BBtu/d) (b)

     288      353       298      346  

Capital expenditures (Thousands of dollars)

   $ 35,799    $ 14,035     $ 53,575    $ 25,155  

(a) - The acquisition of these assets was completed July 1, 2005.
(b) - BBtu/d is billion British thermal units per day.

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 33 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 $100.9 million and $197.4 million for the three- and six-month periods ended June 30, 2006, respectively, primarily due to:

 

    an increase of $44.1 million and $91.5 million, respectively, from the legacy ONEOK Partners operations which were consolidated beginning January 1, 2006,

 

    an increase of $59.4 million and $101.8 million, respectively, related to net revenues on natural gas liquids gathering and distribution pipelines acquired from Koch in July 2005,

 

    an increase of $12.2 million and $28.4 million, respectively, from our legacy operations driven primarily by higher commodity prices, wider gross processing spreads and increased natural gas transportation revenues,

 

    an increase of $8.5 million and $17.8 million, respectively, resulting from the consolidation of Guardian Pipeline beginning January 1, 2006, and

 

    a decrease of $20.9 million and $39.7 million, respectively, resulting from the sale of natural gas gathering and processing assets located in Texas in December 2005.

 

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The increase in operating costs of $32.3 million and $67.1 million, respectively, for the three- and six-month periods, is primarily related to the consolidation of the legacy ONEOK Partners operations, the natural gas liquids assets acquired in 2005, and the consolidation of Guardian Pipeline beginning January 1, 2006, offset by the sale of the Texas natural gas gathering and processing assets in December 2005.

The increase in depreciation, depletion and amortization of $26.3 million and $41.1 million for the three- and six-month periods, respectively, is primarily related to the consolidation of the legacy ONEOK Partners operations, the acquisition of natural gas liquids assets acquired in 2005, the Black Mesa Pipeline impairment and the consolidation of Guardian Pipeline beginning January 1, 2006, offset by the sale of natural gas gathering and processing assets located in Texas in December 2005.

The increase in other income (expense), net of $16.6 million and $49.3 million for the three- and six-month periods resulted primarily from equity earnings in unconsolidated affiliates representing 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 all 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 for our ONEOK Partners segment.

 

    

Year Ending

December 31, 2006

Product

   Volumes
Hedged
   Average
Price Per Unit

Percent of Proceeds:

     

Condensate (a) (Bbl/d)

   815    $52.00 - $60.00

Natural gas liquids (b) (Bbl/d)

   2,813    $44.13

Natural gas (a) (MMBtu/d)

   5,217    $6.15 - $11.00

Natural gas (b) (MMBtu/d)

   7,000    $7.92

Keep whole:

     

Gross processing spread (MMBtu/d)

   10,550    $6.01

(a) - Hedged with NYMEX-based collars.
(b) - Hedged with fixed price swaps.

Regulatory Initiative - The FERC regulates the rates and charges for transportation on our interstate natural gas pipelines. Interstate natural gas 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.

Other - On December 31, 2005, our ONEOK Partners segment’s Black Mesa Pipeline was temporarily shut down due to the expiration of its coal slurry transportation contract. Pending resolution of the issues confronting Mohave Generating Station, its owners requested that Black Mesa Pipeline remain prepared to resume coal slurry operations. In accordance with an agreement reached with a co-owner of Mohave Generating Station, Black Mesa Pipeline was reimbursed for its standby costs. In June 2006, a co-owner of Mohave Generating Station announced that the owners would no longer pursue resumption of plant operations. As a result Black Mesa Pipeline is no longer receiving reimbursement for its standby costs. Accordingly, 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.

 

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DISCONTINUED OPERATIONS

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 for approximately $53 million. The transaction requires FERC approval and is expected to be completed in 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 proceeds from this sale will be used to purchase other assets, repurchase ONEOK shares or retire debt.

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.

 

     Three Months Ended
June 30,
   Six Months Ended
June 30,
 
     2006     2005    2006     2005  
     (Thousands of dollars)  

Operating revenues

   $ 3,315     $ 40,330    $ 5,164     $ 86,153  

Cost of sales and fuel

     2,386       6,977      3,504       23,631  
                               

Net margin

     929       33,353      1,660       62,522  

Operating costs

     266       8,412      492       16,089  

Depreciation, depletion and amortization

     —         8,492      —         16,772  
                               

Operating income

     663       16,449      1,168       29,661  
                               

Other income (expense), net

     —         5      —         (1 )

Interest expense

     904       3,910      1,808       7,622  

Income taxes

     (91 )     4,766      (243 )     8,374  
                               

Income (loss) from operations of discontinued components, net

   $ (150 )   $ 7,778    $ (397 )   $ 13,664  
                               

LIQUIDITY AND CAPITAL RESOURCES

General - Part of our strategy is to grow through acquisitions that strengthen and complement our existing assets. We have relied primarily on operating cash flow, borrowings from commercial paper and credit agreements, and issuance of debt and equity in the capital markets for our liquidity and capital resource requirements. We expect to continue to use these sources for liquidity and capital resource needs on both a short- and long-term basis. We have no material guarantees of debt or other similar commitments to unaffiliated parties. During 2006 and 2005, our capital expenditures were financed through operating cash flows and short- and long-term debt. Capital expenditures for the first six months of 2006 were $133 million, compared with $123 million for the same period in 2005, exclusive of acquisitions.

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 the issuance of debt and limited partner units.

 

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The total amount of short-term borrowings authorized by the Board of Directors of ONEOK is $2.5 billion. In addition to the short-term bridge financing agreement discussed below, the total amount of short-term borrowings authorized by the Board of Directors of ONEOK Partners GP, L.L.C. is $750 million and an additional $10 million is authorized for Guardian Pipeline. At June 30, 2006, ONEOK had no commercial paper outstanding, $143.5 million in letters of credit issued, and available cash of approximately $620.5 million. At June 30, 2006, ONEOK Partners had $15.0 million in letters of credit issued, $311.0 million outstanding under the 2006 Partnership Credit Agreement at a weighted average interest rate of 5.75 percent and $3.0 million outstanding under the Guardian Pipeline Revolving Note Agreement at a weighted average interest rate of 6.60 percent, and available cash of approximately $24.9 million. As of June 30, 2006, ONEOK could have issued $2.8 billion of additional debt under the most restrictive provisions contained in our various borrowing agreements. As of June 30, 2006, ONEOK Partners could have issued, under the most restrictive provisions of its agreements, $1.7 billion of additional debt.

Short-term Bridge Financing Agreement - On July 1, 2005, we borrowed $1.0 billion under a new short-term bridge financing agreement to assist in financing our acquisition of assets from Koch. See Note B 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 remaining $900 million under our short-term bridge financing program.

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 new amendment included 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 rate applicable to extensions of credit is 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. ONEOK’s five-year credit agreement includes a $500 million sublimit for the issuance of standby letters of credit. ONEOK’s five-year credit agreement also has a limitation on our debt-to-capital ratio, which may not exceed 67.5 percent at the end of any calendar quarter, a covenant 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.

ONEOK Partners - 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 June 30, 2006, ONEOK Partners had borrowings of $311.0 million under the 2006 Partnership Credit Agreement and a $15.0 million letter of credit outstanding at a weighted average interest rate of 5.75 percent.

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 to finance a portion of its purchase of certain assets comprising our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments. Amounts outstanding under the Bridge Facility must be paid in full on or before April 5, 2007. ONEOK Partners must make mandatory prepayments on any outstanding balance under the Bridge 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 under the Bridge Facility may, at ONEOK Partners’ option, be the lender’s base rate or an adjusted LIBOR plus a spread that is based upon its long-term unsecured debt ratings. At June 30, 2006, the weighted average interest rate for borrowings under the Bridge Facility was 5.67 percent. ONEOK Partners intends to refinance the Bridge Facility with long-term financing prior to the maturity date.

Under the 2006 Partnership Credit Agreement and the Bridge Facility, 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 minority interests in net income, 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 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.

 

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Guardian Pipeline - ONEOK Partners’ 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 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 the 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.

Guardian Pipeline’s revolving note agreement contains 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 agreements may become due and payable immediately.

General - ONEOK’s five-year credit agreement and ONEOK Partners’ 2006 Partnership Credit Agreement and $1.1 billion 364-day credit agreements contain 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 June 30, 2006, ONEOK and ONEOK Partners were in compliance with all credit agreement covenants.

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.

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

 

     June 30,
2006
    December 31,
2005
 

Long-term debt

   53 %   53 %

Equity

   47 %   47 %
            

Debt (including Notes payable)

   63 %   67 %

Equity

   37 %   33 %

ONEOK does not guarantee the debt of ONEOK Partners. For purposes of determining compliance with covenants in ONEOK’s five-year credit agreement, the debt of ONEOK Partners is excluded. At June 30, 2006, our capitalization structure, excluding the debt of ONEOK Partners, was 46 percent long-term debt and 54 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 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, L.L.C. 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. In June 2006, ONEOK Partners recorded a $63.2 million estimated purchase price adjustment to the acquired assets related to a working capital settlement which is reflected as a reduction of the value of the Class B units. The working capital settlement has not been finalized; however, we do not expect 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 33 for additional discussion of EITF 04-5.

 

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In April 2006, in connection with the transactions described immediately above, our ONEOK Partners segment completed the sale of its 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. We 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. Following completion of the transactions, ONEOK Partners no longer consolidates Northern Border Pipeline in its financial statements. Instead, its interest in Northern Border Pipeline is accounted for as an investment under the equity method. This change is retroactive to January 1, 2006. 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 will be prorated from the date of issuance. ONEOK Partners is required to hold a special election for holders of common units 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 general partner is removed. If the conversion and the amendments are approved by common unit holders, the Class B units will be eligible to convert into common units on a one-by-one basis. If the common unit holders do not approve both the conversion and amendments within 12 months of the issuance of the Class B units, then the amount payable on such Class B units would increase to 115 percent of the distributions paid on the common units and the Class B distribution rights would continue to be subordinated in the manner described above unless and until the conversion described above has been approved. If the common unit holders 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, 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 and 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 our 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 is 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.

Capital Projects - In June 2006, ONEOK Partners signed a letter of intent to form a joint venture with Boardwalk Pipeline Partners, L.P. and Energy Transfer Partners, L.P. 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. Formation of the joint venture 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 barrels per day of NGLs, which can be increased to approximately 150,000 barrels per day with additional pump facilities. A subsidiary of ONEOK Partners owns 99 percent of the joint venture, 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 ONEOK Partners its 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 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. At the project’s inception, ONEOK Partners paid $11.4 million to Williams for initial capital expenditures incurred. 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.

 

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In February 2006, Guardian Pipeline announced that it signed precedent agreements with two major Wisconsin utility companies to expand its existing natural gas pipeline system in eastern Wisconsin. The proposed project will expand and extend the existing pipeline approximately 106 miles from its current terminus near Ixomia, Wisconsin to the Green Bay area, adding approximately 537 MMcf/d of capacity. Guardian Pipeline’s capital costs for the project are estimated to range between $220 million and $240 million. Pending all necessary approvals, the target in-service date is November 2008.

Additionally, ONEOK Partners has $25 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 of November 2006 will likely be delayed. 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 7.5 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. Shares are repurchased from time to time in open market transactions or through privately negotiated transactions at our discretion, subject to market conditions and other factors. During the six months ended June 30, 2006, we did not repurchase any shares of our common stock under this plan.

Credit Rating - Our credit ratings as of June 30, 2006, were as follows:

 

    ONEOK   ONEOK Partners
Rating Agency   Rating   Outlook   Rating   Outlook
Moody’s   Baa2   Stable   Baa2   Stable
S&P   BBB   Stable   BBB   Stable
Fitch   (a)   (a)   BBB   Stable

(a) - Fitch does not rate ONEOK, Inc. debt.

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 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 that expires March 2011.

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 S&P or Moody’s debt rate falls below investment grade (Baa3 for Moody’s and BBB- for S&P) and the investment grade rating is not reinstated within a period of 40 days.

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 credit ratings were to decline below investment grade, our ability to participate in energy marketing and trading activities could be significantly limited. Without an investment grade rating, we may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments. At June 30, 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 $126.5 million. A decline in our credit rating below investment grade may also significantly impact other business segments.

Other than the note repurchase obligations 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 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.

 

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Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity prices in either physical or financial energy contracts may impact our overall liquidity due to the impact the commodity price change has on items such as the cost of NGLs and gas held in storage, increased margin requirements, collectibility of certain energy-related receivables and working capital. We believe that ONEOK’s and ONEOK Partners’ current commercial paper program and 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 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 our pension plan and our postretirement benefit plan in 2005 were $1.5 million and $3.1 million, respectively. For 2006, we anticipate our total contributions to our defined benefit pension plan and postretirement benefit plan to be $1.5 million and $17.3 million, respectively, and our pay-as-you-go other postretirement benefit plan costs to be $14.0 million. We believe that we have adequate resources to fund our obligations under our pension and postretirement benefit plans.

CASH FLOW ANALYSIS

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 flows for the six months ended June 30, 2005. Discontinued operations accounted for approximately $(31.2) million in investing cash flows for the six months ended June 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 $365.2 million for the six months ended June 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 $392.0 million in 2006, compared with a net decrease in working capital of $176.6 million in 2005. These decreases primarily related to decreases in accounts receivable, partially offset by decreases in accounts payable. The increases in 2006 operating cash flows was also impacted by the consolidation of ONEOK Partners as of January 1, 2006 due to EITF 04-05 and the consolidation of Guardian Pipeline retroactive to January 1, 2006. During the six months ended June 30, 2006, we received $69.8 million in distributions from Northern Border Pipeline, compared with distributions from ONEOK Partners of $0.6 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 first half of 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 owning 100 percent of the two percent general partner interest in ONEOK Partners. Additionally, ONEOK Partners paid $11.4 million to Williams for initial capital expenditures incurred related to the Overland Pass Pipeline Company.

Financing Cash Flows - The second quarter of 2006 includes $78.6 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.

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 the ONEOK Partners GP, L.L.C. acquisition in November 2004, to repay $335 million of long-term debt that matured on March 1, 2005, and to meet operating needs.

During the first half of 2005, we paid $110.8 million to repurchase approximately 3.7 million shares of our stock pursuant to a plan initially approved by our Board of Directors on January 20, 2005 and amended in November 2005.

 

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We terminated $400 million of our interest rate swap agreements in the first quarter of 2005, which resulted in us paying $19.4 million. This amount 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. In the second quarter of 2005, we terminated $500 million of our treasury rate-lock agreements, which resulted in us paying $2.4 million. 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.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

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.

The following table sets forth our contractual obligations to make future payments under our current debt agreements, operating lease agreements and fixed price contracts. For further discussion of the debt and operating lease agreements, see Notes I and K, respectively, of Notes to the Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

 

     Payments Due by Period

Contractual Obligations

   Total    Remainder of
2006
   2007    2008    2009    2010    Thereafter
     (Thousands of dollars)

ONEOK

                    

Long-term debt

   $ 1,992,572    $ 6,555    $ 6,571    $ 408,891    $ 107,467    $ 6,295    $ 1,456,793

Interest payments on debt

     1,357      58      116      96      87      86      914

Operating leases

     206,972      28,739      41,999      40,159      37,647      26,057      32,371

Storage contracts

     139,840      22,553      49,585      24,940      19,254      13,469      10,039

Firm transportation contracts

     462,575      53,328      88,673      61,220      52,315      46,159      160,880

Pension plan (a)

     10,450      850      2,900      2,100      2,200      2,400      —  

Other postretirement benefit plan (a)

     78,173      8,356      17,052      17,289      17,534      17,943      —  
                                                
   $ 2,891,939    $ 120,439    $ 206,896    $ 554,695    $ 236,504    $ 112,409    $ 1,660,997
                                                

ONEOK Partners

                    

Long-term debt

   $ 626,537    $ 5,965    $ 11,931    $ 11,931    $ 11,931    $ 261,930    $ 322,849

Interest payments on debt

     298,129      55,090      64,822      48,981      48,043      35,088      46,105

Notes payable

     1,364,000      311,000      1,053,000      —        —        —        —  

Operating leases

     13,661      2,261      3,111      2,305      904      828      4,252

Purchase commitments, rights-of-way and other

     86,229      3,603      73,981      1,975      1,787      1,746      3,137

Firm transportation contracts

     43,994      5,878      11,659      11,691      11,087      3,679      —  
                                                
   $ 2,432,550    $ 383,797    $ 1,218,504    $ 76,883    $ 73,752    $ 303,271    $ 376,343
                                                

Total

   $ 5,324,489    $ 504,236    $ 1,425,400    $ 631,578    $ 310,256    $ 415,680    $ 2,037,340
                                                

(a) - No payment amounts are provided for our pension and other postretirement benefit plans in the “Thereafter” column since there is no termination date for these plans.

 

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FORWARD-LOOKING STATEMENTS AND RISK FACTORS

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

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

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 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, and regulatory actions including receipt of expected regulatory clearances involving the Oklahoma Corporation Commission, 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:

 

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    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 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 which are significantly different than our assumptions related to ONEOK Partner’s November 2005 rate case;

 

  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 required regulatory clearances for construction and operation of the Midwestern Gas Transmission Eastern Extension Project;

 

  our ability to acquire all necessary pipeline rights-of-way and obtain agreements for interconnects in a timely manner;

 

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

 

  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;

 

  the impact of potential impairment charges;

 

  developments in the December 2, 2001 filing by Enron of a voluntary petition for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code affecting our settled claims;

 

  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 Securities and Exchange Commission, which are incorporated by reference.

Other factors and assumptions not identified above were also involved in the making of the forward-looking statements. The failure of those assumptions to be realized, as well as other factors, may also cause actual results to differ materially from those projected. We have no obligation and make no undertaking to update publicly or revise any forward-looking information.

 

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2005.

COMMODITY PRICE RISK

Energy Services

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 hedges, except for any ineffectiveness, are not included in the following table.

 

     Fair Value of Derivatives at June 30, 2006  

Source of Fair Value (a)

   Matures
through
March 2007
    Matures
through
March 2010
    Matures
through
March 2012
   

Total

Fair
Value

 
     (Thousands of dollars)  

Prices actively quoted (b)

   $ (62,679 )   $ (6,453 )   $ —       $ (69,132 )

Prices provided by other external sources (c)

     56,899       8,891       248       66,038  

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

     (4,668 )     2,080       (177 )     (2,765 )
                                

Total

   $ (10,448 )   $ 4,518     $ 71     $ (5,859 )
                                

(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.
(b) Values are derived from energy market price quotes from national commodity trading exchanges that primarily trade futures and option commodity contracts.
(c) Values are obtained through energy commodity brokers or electronic trading platforms, whose primary service is to match willing buyers and sellers of energy commodities. Energy price information by location is readily available because of the large energy broker network.
(d) Values derived in this category utilize market price information from the other two categories, as well as other assumptions for liquidity and credit.

 

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

     (48,733 )

Fair value of new derivatives when entered into during the period

     (8,787 )

Other changes in fair value

     21,325  
        

Net fair value of derivatives outstanding at June 30, 2006

   $ (5,859 )
        

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

Value-at-Risk (VAR) Disclosure of Market Risk

The potential impact on our future earnings, as measured by VAR, was $9.4 million and $17.4 million at June 30, 2006, and 2005, respectively. The following table details the average, high and low daily VAR calculations.

 

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     Three Months Ended
June 30,
   Six Months Ended
June 30,

Value-at-Risk

   2006    2005    2006    2005
     (Millions of dollars)

Average

   $ 19.9    $ 11.1    $ 24.4    $ 12.4

High

   $ 36.1    $ 18.1    $ 48.9    $ 27.1

Low

   $ 9.4    $ 6.1    $ 9.4    $ 6.1

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 increase in VAR for the three months ended June 30, 2006, compared with 2005, is primarily due to higher volatility in 2006 attributable to changes in basis prices. The increase in VAR for the six months ended June 30, 2006, compared with 2005, is primarily due to higher average commodity prices during 2006.

INTEREST RATE AND CURRENCY RISK

Interest Rate Risk

General - At June 30, 2006, the interest rate on approximately 81.2 percent of our long-term debt was fixed after considering the impact of interest rate swaps.

At June 30, 2006, a 100 basis point move in the LIBOR rate on our floating rate debt would change annual interest expense by approximately $10.3 million before taxes. This 100 basis point change assumes a parallel shift in the yield curve. If interest rates changed significantly, we would take actions to manage our exposure to the change. Since a specific action and the possible effects are uncertain, no change has been assumed.

Fair Value Hedges - In prior years, we 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 six months ended June 30, 2006 for all terminated swaps was $5.1 million and the remaining net savings for all terminated swaps will be recognized over the following periods:

 

     ONEOK    ONEOK
Partners
   Total
     (Millions of dollars)

Remainder of 2006

   $ 3.3    $ 1.6    $ 4.9

    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, $490 million of fixed rate debt is swapped to floating. Interest on the floating rate debt is based on both the three- and six-month LIBOR, depending upon the swap. At June 30, 2006, we had a net liability of $30.2 million to recognize the interest rate swaps at fair value. Long-term debt was decreased by $30.2 million to recognize the change in fair value of the related hedged liability.

Total savings from the interest rate swaps and amortization of terminated swaps was $4.2 million for the six months ended June 30, 2006. The swaps are expected to net the following savings for the remainder of the year:

 

    interest expense savings of $4.9 million related to the amortization of the swap value at termination, and

 

    up to $1.8 million in interest expense from the existing $490 million of swapped debt, based on LIBOR rates at June 30, 2006.

Total net swap savings for 2006 are expected to be $7.3 million compared to $10.7 million for 2005.

 

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Currency Rate Risk

With our Energy Services segment’s Canadian operations, 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 June 30, 2006, our exposure to risk from currency translation was not material and there was no material currency translation gain or loss recorded.