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

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

For the quarterly period ended ~~June~~September 30, 2006

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

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

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. YesxX 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~~ xfilerX Accelerated ~~Filer~~ ¨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¨NoxX

On ~~July~~October 31, 2006, the Company had ~~117,557,407~~110,214,774 shares of common stock outstanding.

ONEOK, Inc.

QUARTERLY REPORT ON FORM 10-Q


Part I.	Financial Information	Page No.
~~Part I.~~	~~Financial Information~~

Item 1.	Financial Statements (Unaudited)

	Consolidated Statements of Income - Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2006 and 2005	34

	Consolidated Balance Sheets - ~~June~~ September 30, 2006 and December 31, 2005	~~4-5~~5-6

	Consolidated Statements of Cash Flows - ~~Six~~ Nine Months Ended ~~June~~September 30, 2006 and 2005	78

	Consolidated Statements of Shareholders’ Equity and Comprehensive Income - ~~Six~~Nine Months Ended ~~June~~September 30, 2006	~~8-9~~9-10

	Notes to Consolidated Financial Statements	~~10-30~~11-34

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	~~31-53~~35-61

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	~~54-56~~61-63

Item 4.	Controls and Procedures	5663

Part II.	Other Information

Item 1.	Legal Proceedings	~~57-58~~63-65

Item 1A.	Risk Factors	5865-66

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	5966-67

Item 3.	Defaults Upon Senior Securities	5967

Item 4.	Submission of Matters to a Vote of Security Holders	6067

Item 5.	Other Information	6067

Item 6.	Exhibits	67

~~Exhibits~~Signature		61

~~Signature~~		6268

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

The statements in this Quarterly Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may include words such as “anticipate,” “estimate,” “plan,” “expect,” “project,” “intend,” “believe,” “should” and other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that our goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part II, Item 1A, “Risk Factors,” in our Quarterly Reports and under Part I, Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2005.

Glossary

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


Bbl		Barrels, equivalent to 42 United States gallons
Bbl/d		Barrels per day
BBtu/d		Billion British thermal units per day
Bcf		Billion cubic feet
Bcf/d		Billion cubic feet per day
Black Mesa		Black Mesa Pipeline, Inc.
Btu		British thermal units
EITF		Emerging Issues Task Force
Exchange Act		Securities Exchange Act of 1934, as amended
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FIN		FASB Interpretations
GAAP		Generally Accepted Accounting Principles in the United States
Guardian Pipeline		Guardian Pipeline, L.L.C.
Intermediate Partnership		ONEOK Partners Intermediate Limited Partnership, a wholly-owned subsidiary of ONEOK Partners, L.P.
KCC		Kansas Corporation Commission
KDHE		Kansas Department of Health and Environment
LIBOR		London Interbank Offered Rate
MBbl/d		Thousand barrels per day
Mcf		Thousand cubic feet
Midwestern Gas Transmission		Midwestern Gas Transmission Company
MMBtu		Million British thermal units
MMBtu/d		Million British thermal units per day
MMcf		Million cubic feet
MMcf/d		Million cubic feet per day
NGL		Natural gas liquids
Northern Border Pipeline		Northern Border Pipeline Company
NYMEX		New York Mercantile Exchange
NYSE		New York Stock Exchange
OCC		Oklahoma Corporation Commission
ONEOK		ONEOK, Inc.
ONEOK Partners		ONEOK Partners, L.P., formerly known as Northern Border Partners, L.P.
Overland Pass Pipeline Company		Overland Pass Pipeline Company LLC
RRC		Texas Railroad Commission
SCE		Southern California Edison Company
SEC		Securities and Exchange Commission
Statement		Statement of Financial Accounting Standards
TC PipeLines		TC PipeLines Intermediate Limited Partnership, a subsidiary of TC PipeLines, LP
TransCanada		TransCanada Corporation

~~Part~~PART I - FINANCIAL INFORMATION

~~Item~~ITEM 1. ~~Financial Statements~~FINANCIAL STATEMENTS

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME

Three Months Ended
September 30,

Nine Months Ended
September 30,

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

Operating revenues, excluding energy trading revenues
   $         2,649,312 $ 3,181,592 $         8,825,377 $ 7,969,014
Energy trading revenues, net
   (8,435 ) 10,615 3,047 11,023
Total Revenues
   2,640,877 3,192,207 8,828,424 7,980,037
Cost of sales and fuel
   2,291,891 2,862,888 7,579,939 7,050,344
Net Margin
   348,986 329,319 1,248,485 929,693
Operating Expenses

Operations and maintenance
   154,501 153,008 468,743 394,985
Depreciation, depletion and amortization
   55,468 48,131 178,889 135,020
General taxes
   19,482 18,114 57,765 51,061
Total Operating Expenses
   229,451 219,253 705,397 581,066
Gain on Sale of Assets
   -   -   115,892 -
Operating Income
   119,535 110,066 658,980 348,627
Equity earnings from investments (Note O)
   22,788 2,822 72,750 8,472
Other income
   8,418 4,428 21,735 8,014
Other expense
   861 3,365 12,595 8,087
Interest expense
   61,460 41,601 176,648 91,682
Income before Minority Interest and Income Taxes
   88,420 72,350 564,222 265,344
Minority interests in income of consolidated subsidiaries
   48,281 -   184,620 -
Income taxes
   15,726 27,736 147,505 101,878
Income from Continuing Operations
   24,413 44,614 232,097 163,466
Discontinued operations, net of taxes (Note C)

Income (loss) from operations of discontinued
components, net of tax
   (13 ) (19,582 ) (410 ) (5,918 )
Gain on sale of discontinued component, net of tax
   -   151,355 -   151,355
Net Income
   $ 24,400 $ 176,387 $ 231,687 $ 308,903

Earnings Per Share of Common Stock (Note P)

Basic:

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

Diluted:

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

Average Shares of Common Stock(Thousands)

Basic
   113,200 99,894 112,589 101,568
Diluted
   114,920 108,602 114,901 109,555

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

See accompanying Notes to Consolidated Financial Statements.
ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS

   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

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

    Cash and cash equivalents
   $                 247,475      $              7,915
    Trade accounts and notes receivable, net
   944,732      2,202,895
    Gas and natural gas liquids in storage
   1,028,007      911,393
    Commodity exchanges
   191,184      133,159
    Energy marketing and risk management assets (Note D)
   408,093      399,439
    Deposits
   161,572      150,608
    Other current assets
   95,835      234,666
        Total Current Assets
   3,076,898      4,040,075

Property, Plant and Equipment

    Property, plant and equipment
   6,634,992      5,575,365
    Accumulated depreciation, depletion and amortization
   1,867,565      1,581,138
        Net Property, Plant and Equipment (Note A)
   4,767,427      3,994,227
Deferred Charges and Other Assets

    Goodwill and intangibles (Note E)
   1,025,420      683,211
    Energy marketing and risk management assets (Note D)
   111,122      55,713
    Investments (Note O)
   755,772      245,009
    Other assets
   388,982      471,289
        Total Deferred Charges and Other Assets
   2,281,296      1,455,222
Assets of Discontinued Component
   62,897      63,911
                Total Assets
   $            10,188,518      $        9,553,435

See accompanying Notes to Consolidated Financial Statements.
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

(Unaudited)
   September 30,
2006
December 31,
2005

Liabilities and Shareholders’ Equity
   (Thousands of dollars)
Current Liabilities

Current maturities of long-term debt
   $                18,183 $              6,546
Notes payable
   4,500 1,541,500
Accounts payable
   1,021,732 1,756,307
Commodity exchanges
   291,095 238,176
Energy marketing and risk management liabilities (Note D)
   375,620 449,085
Other
   412,214 438,009
Total Current Liabilities
   2,123,344 4,429,623
Long-term Debt, excluding current maturities (Note I)
   4,036,127 2,024,070
Deferred Credits and Other Liabilities

Deferred income taxes
   577,591 603,835
Energy marketing and risk management liabilities (Note D)
   154,019 348,529
Other deferred credits
   330,068 350,157
Total Deferred Credits and Other Liabilities
   1,061,678 1,302,521
Liabilities of Discontinued Component
   1,683 2,464
Commitments and Contingencies (Note K)

Minority Interests in Consolidated Subsidiaries
   810,089 -
Shareholders’ Equity

Common stock, $0.01 par value:

    authorized 300,000,000 shares; issued 119,825,128 shares
        and outstanding 110,169,874 shares at September 30, 2006;
        issued 107,973,436 shares and outstanding 97,654,697
        shares at December 31, 2005
   1,198 1,080
Paid in capital
   1,243,981 1,044,283
Unearned compensation
   —   (105 )
Accumulated other comprehensive income (loss) (Note F)
   33,251 (56,991 )
Retained earnings
   1,217,404 1,085,845
Treasury stock, at cost: 9,655,254 shares at September 30, 2006
        and 10,318,739 shares at December 31, 2005
   (340,237 ) (279,355 )
Total Shareholders’ Equity
   2,155,597 1,794,757

Total Liabilities and Shareholders’ Equity
   $            10,188,518 $        9,553,435

See accompanying Notes to Consolidated Financial Statements.
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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS

Nine Months Ended
September 30,

(Unaudited)
   2006 2005
Operating Activities
   (Thousands of Dollars)
Net income
   $ 231,687 $ 308,903
Depreciation, depletion, and amortization
   178,889 135,020
Impairment expense for discontinued component
   - 52,226
Gain on sale of discontinued component
   - (151,355 )
Gain on sale of assets
   (115,892 ) -
Minority interest in income of consolidated subsidiaries
   184,620 -
Distributions received from unconsolidated affiliates
   93,209 8,135
Income from equity investments
   (72,750 ) (8,472 )
Deferred income taxes
   18,056 40,128
Stock-based compensation expense
   13,052 9,903
Allowance for doubtful accounts
   8,220 9,723
Changes in assets and liabilities (net of acquisition and disposition effects):

Accounts and notes receivable
   1,295,726 5,339
Inventories
   (121,031 ) (284,653 )
Unrecovered purchased gas costs
   (75,227 ) 45,547
Commodity exchanges
   (5,106 ) 130,260
Deposits
   (10,964 ) (55,227 )
Regulatory assets
   12,922 (5,490 )
Accounts payable and accrued liabilities
   (779,425 ) 216,008
Energy marketing and risk management assets and liabilities
   (194,761 ) 121,718
Other assets and liabilities
   183,989 (334,840 )
Cash Provided by Operating Activities
   845,214 242,873
Investing Activities

Changes in other investments, net
   (6,458 ) (20,800 )
Acquisitions
   (128,485 ) (1,328,572 )
Capital expenditures
   (243,968 ) (189,930 )
Proceeds from sale of discontinued component
   - 630,214
Proceeds from sale of assets
   298,838 27,520
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
   (3,685 ) (3,866 )
Cash Used in Investing Activities
   (104,463 ) (885,434 )
Financing Activities

Borrowing (repayment) of notes payable, net
   (641,500 ) (341,500 )
Short term financing payments
   (2,632,000 ) (100,000 )
Short term financing borrowings
   1,530,000 1,000,000
Issuance of debt, net of issuance costs
   1,397,328 798,792
Long-term debt financing costs
   (12,027 ) -
Termination of interest rate swaps
   - (22,565 )
Payment of debt
   (41,214 ) (335,808 )
Equity unit conversion
   402,448 -
Repurchase of common stock
   (281,420 ) (188,770 )
Issuance of common stock
   3,986 3,291
Dividends paid
   (100,181 ) (82,834 )
Distributions to minority interests
   (120,803 ) -
Other financing activities
   (48,898 ) (11,343 )
Cash Provided by (Used in) Financing Activities
   (544,281 ) 719,263
Change in Cash and Cash Equivalents
   196,470 76,702
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
   $ 247,475 $ 86,160

See accompanying Notes to Consolidated Financial Statements.
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.~~
~~ONEOK, Inc. and Subsidiaries~~
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(Unaudited)
Common
Stock
Issued
   Common
Stock    Paid in
Capital    Unearned
Compensation    Common
Stock
Issued    Common
Stock    Paid in Capital    Unearned
Compensation
   (Shares)    (Thousands of Dollars)    (Shares)    (Thousands of Dollars)
December 31, 2005
   107,973,436    $ 1,080    $ 1,044,283    $ (105 )    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    —      11,208,998    112    177,572    -
Repurchase of common stock
   —      —      —      —      -        -        -        -
Common stock issuance pursuant to various plans
   495,350    5    6,503    —      642,694    6    9,232    -
Stock-based employee compensation expense
   —      —      8,337    158    -        -        12,894    158
Common stock dividends - $0.58 per share
   —      —      —      (53 )
Common stock dividends - $0.90 per share
   -        -        -        (53)
September 30, 2006
   119,825,128    $            1,198    $1,243,981    $            -

June 30, 2006
   119,677,784    $ 1,197    $ 1,236,695    $ —

See accompanying Notes to Consolidated Financial Statements.
ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
(Continued)

(Unaudited)    Accumulated Other
Comprehensive
Loss Retained
Earnings Treasury
Stock Total    Accumulated
Other
Comprehensive
Income (Loss)    Retained
Earnings    Treasury Stock    Total
   (Thousands of Dollars)    (Thousands of Dollars)
December 31, 2005
   $ (56,991 ) $ 1,085,845 $ (279,355 ) $ 1,794,757    $            (56,991)    $            1,085,845    $            (279,355)    $            1,794,757
Net income
   —   207,287 —   207,287    -        231,687    -        231,687
Other comprehensive income
   13,290 —   —   13,290    90,242    -        -        90,242

Total comprehensive income
   220,577             321,929

Equity unit conversion
   —   —   224,764 402,448    -        -        224,764    402,448
Repurchase of common stock
   —   —   (4,229 ) (4,229 )    -        -        (285,646)    (285,646)
Common stock issuance pursuant to various plans
   —   —   —   6,508    -        -        -        9,238
Stock-based employee compensation expense
   —   —   —   8,495    -        -        -        13,052
Common stock dividends - $0.58 per share
   —   (62,511 ) —   (62,564 )
Common stock dividends - $0.90 per share
   -        (100,128)    -        (100,181)
September 30, 2006
   $            33,251    $            1,217,404    $            (340,237)    $            2,155,597

June 30, 2006
   $ (43,701 ) $ 1,230,621 $ (58,820 ) $ 2,365,992

ONEOK, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
~~A. SUMMARY OF ACCOUNTING POLICIES~~
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~~GAAP and reflect all adjustments that, in our opinion, are necessary for a fair presentation of the results for the interim periods presented. All such adjustments are of a normal recurring nature. Due to the seasonal nature of our business, the results of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2006 are not necessarily indicative of the results that may be expected for a twelve-month period. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2005.
Our accounting policies are consistent with those disclosed in Note 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)~~FASB ratified the consensus reached in ~~Emerging Issues Task Force (EITF)~~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~~, 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 ~~Northern Border Partners, L.P.’s (renamed~~ ONEOK ~~Partners, L.P. on May 17, 2006)~~Partners’ operations in our consolidated financial statements, and we elected to use the prospective method. Accordingly, prior period financial statements have not been restated. The adoption of EITF 04-5 did not have an impact on our net income; however, reported revenues, costs and expenses reflect the operating results of ONEOK Partners. Additionally, we record a minority interest liability in our consolidated balance sheet to recognize the 54.3 percent of ONEOK Partners ~~L.P. (ONEOK Partners).~~
that we do not own. We reflect our 45.7 percent share of ONEOK Partners’ accumulated other comprehensive ~~loss~~income at ~~June~~September 30, 2006, in our consolidated accumulated other comprehensive ~~loss.~~income. The remaining 54.3 percent is reflected as an adjustment to minority interests in ~~partners’ equity.~~consolidated subsidiaries.
Share-Based Payment - In December 2004, the FASB issued Statement ~~of Financial Accounting Standards No.~~ 123R, “Share-Based ~~Payment” (Statement 123R). Statement 123R~~Payment,” which requires companies to expense the fair value of share-based payments net of estimated forfeitures. We adopted Statement 123R as of January 1, 2006, and elected to use the modified prospective method. Statement 123R did not have a material impact on our financial statements as we have been expensing share-based payments since our adoption of Statement ~~of Financial Accounting Standards No.~~ 148, “Accounting for Stock-Based Compensation - Transition and ~~Disclosure” (Statement 148)~~Disclosure,” on January 1, 2003. Awards granted after the adoption of Statement 123R are expensed under the requirements of Statement 123R, while equity awards granted prior to the adoption of Statement 123R will continue to be expensed under Statement 148. We recognized other income of $1.7 million upon adoption of Statement 123R.
Inventory - In September 2005, the FASB ratified the consensus reached in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (EITF 04-13). EITF 04-13 defines when a purchase and a sale of inventory with the same party that operates in the same line of business should be considered a single nonmonetary transaction. EITF 04-13 is effective for new arrangements that a company enters into in periods beginning after March 15, 2006. We completed our review of the applicability of EITF 04-13 to our operations and determined that its impact was immaterial to our consolidated financial statements.
Property - The following table sets forth our property, by segment, for the periods presented.

   June 30,
2006    December 31,
2005    September 30,
2006    December 31,
2005
   (Thousands of dollars)    (Thousands of dollars)
Distribution
   $ 3,071,227    $ 3,016,668    $   3,106,388    $   3,016,668
Energy Services
   7,688    7,690    7,688    7,690
ONEOK Partners
   3,299,795    2,412,679    3,355,534    2,412,679
Other
   155,668    138,328    165,382    138,328

Property, plant and equipment
   6,534,378    5,575,365    6,634,992    5,575,365
Accumulated depreciation, depletion and amortization
   1,823,874    1,581,138    1,867,565    1,581,138

Net property, plant and equipment
   $ 4,710,504    $ 3,994,227    $ 4,767,427    $ 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~~basis of existing assets and liabilities. The effect on deferred taxes of a change in tax rates is deferred and amortized for operations regulated by the ~~Oklahoma Corporation Commission (OCC), Kansas Corporation Commission (KCC), Texas Railroad Commission (RRC)~~OCC, KCC, RRC and various municipalities in Texas. For all other operations, the effect is recognized in income in the period that includes the enactment date. We continue to amortize previously deferred investment tax credits for ratemaking purposes over the period prescribed by the OCC, KCC, RRC and various municipalities in Texas.
In June 2006, the FASB issued ~~Interpretation No.~~FIN 48, “Accounting for Uncertainty in Income ~~Taxes” (FIN 48),~~Taxes,” 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.~~beginning January 1, 2007. We are currently reviewing the applicability of FIN 48 to our operations and its potential impact on our consolidated financial statements.
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).~~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).~~Regulation.” During the rate-making process, regulatory authorities may require us to defer recognition of certain costs to be recovered through rates over time as opposed to expensing such costs as incurred. This allows us to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. Accordingly, actions of the regulatory authorities could have an effect on the amount recovered from rate payers. Any 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~~September 2006, the FASB issued ~~an exposure draft on accounting~~Statement 158, “Employers’ Accounting for ~~pension~~Defined Benefit 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 requiredOther Postretirement Plans,” which will require us to record a balance sheet liability equal to the difference between our benefit obligations and plan assets. If ~~this requirement~~Statement 158 had been ~~in place~~effective at December 31, 2005, we would have been required to record unrecognized losses of $124.8 million and $78.8 million for pension and postretirement benefits, respectively, on our consolidated balance sheet as accumulated other comprehensive loss. Statement 158 is effective for our year ending December 31, 2006, except for the measurement date change from September 30 to December 31 which will not go into effect until our year ending December 31, 2007.
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~~During preparation of our 2005 Annual Report on Form 10-K, we identified and disclosed a software system error impacting our accounting for hedging instruments, and subsequently restated our third quarter 2005 results to reflect an increase in cost of sales and fuel of $13.2 million. It was determined that no other prior periods were affected. For further information, refer to Part II, Item 9A, “Controls and Procedures,” in our Annual Report on Form 10-K for the ~~sale of our Production segment and the pending sale of our Spring Creek power plant as discontinued operations. See Note C for additional information.~~year ended December 31, 2005.
B. ACQUISITIONS AND DIVESTITURES
~~B. ACQUISITIONS AND DIVESTITURES~~
Overland Pass Pipeline Company - In May 2006, a subsidiary of ONEOK Partners entered into an agreement with a subsidiary of The Williams Companies, Inc. (Williams) to form a joint venture called Overland Pass Pipeline ~~Company LLC (Overland Pass Pipeline Company).~~Company. Overland Pass Pipeline Company will build a 750-mile natural gas liquids pipeline from Opal, Wyoming to the ~~mid-continent~~Mid-continent natural gas liquids market center in Conway, Kansas. The pipeline will be designed to transport approximately 110,000 ~~barrels per day~~Bbl/d of ~~natural gas liquids (NGLs),~~NGLs, which can be increased to approximately 150,000 ~~barrels per day~~Bbl/d with additional pump ~~facilities.~~facilities if customers contract for that capacity. A subsidiary of ONEOK Partners owns 99 percent of the joint venture, will manage the construction project, will advance all costs associated with construction, and will operate the pipeline. Within two years of the pipeline becoming operational, Williams ~~will have~~has the option to increase its ownership up to 50 percent by reimbursing ONEOK Partners its proportionate share of all construction costs and, upon full exercise of that option, Williams would have the option to become ~~operator within two years of the pipeline becoming operational.~~operator. Construction of the pipeline is expected to begin in the summer of 2007, with start-up scheduled for early 2008. As part of a long-term agreement, Williams dedicated its NGL production from two of its gas processing plants in Wyoming to the joint-venture company. Subsidiaries of ONEOK Partners will provide downstream fractionation, storage and transportation services to Williams. The pipeline project is estimated to cost approximately $433 million. ~~At the project’s inception,~~In May 2006, ONEOK Partners paid $11.4 million to Williams for reimbursement of initial capital ~~expenditures incurred.~~expenditures. In addition, ONEOK Partners plans to invest approximately $173 million to expand its existing fractionation capabilities and the capacity of its natural gas liquids distribution pipelines. ONEOK Partners’ financing for both projects may include a combination of short- or long-term debt or equity. The project requires the approval of various state and regulatory authorities.
ONEOK Partners - In April 2006, we sold certain assets comprising our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. We also purchased, through ~~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~~$63.6 million ~~estimated~~ purchase price adjustment to the acquired assets related to a working capital settlement, which is reflected as ~~a reduction of~~an increase to the value of the Class B units. ~~The~~In the third quarter of 2006, the working capital settlement ~~has not been finalized; however, we do not expect~~was finalized, subject to approval by ONEOK Partners’ Audit Committee, resulting in no material adjustments.
Disposition of 20 Percent Interest in Northern Border Pipeline - In April 2006, in connection with the transactions described immediately above, our ONEOK Partners segment completed the sale of ~~its~~a 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. WeONEOK Partners and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, with an affiliate of TransCanada becoming operator of the pipeline in April 2007. 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 weONEOK Partners nor TC PipeLines ~~will have~~has control of Northern Border Pipeline, as control ~~will be~~is 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.~~as of January 1, 2006. 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.
Acquisition of Guardian Pipeline Interests - In April 2006, our ONEOK Partners segment acquired athe remaining 66²/3 percent interest in Guardian Pipeline ~~L.L.C. (Guardian Pipeline)~~ for approximately $77 million, increasing ~~our~~its ownership interest to 100 percent. ONEOK Partners used borrowings from its credit facility to fund the acquisition of the additional interest in Guardian Pipeline. Following the completion of the transaction, we consolidated Guardian Pipeline in our consolidated financial statements. This change iswas retroactive to January 1, 2006. Prior to the transaction, ~~our~~ONEOK Partners’ 33¹/3 percent interest in Guardian Pipeline was accounted for as an investment under the equity method.
Acquisition of Koch Industries Natural Gas Liquids Business - In July 2005, we completed our acquisition of the natural gas liquids businesses owned by Koch Industries, Inc. (Koch) for approximately $1.33 billion, net of working capital and cash received. This transaction included Koch Hydrocarbon, L.P.’s entire ~~mid-continent~~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~~a 160,000 ~~barrel per day~~ Bbl/d
fractionator at Mont Belvieu, Texas; and Koch VESCO Holdings, L.L.C., an entity that owns a 10.2 percent interest in Venice Energy Services Company, L.L.C. ~~(VESCO).~~ These assets are included in our consolidated financial statements beginning on July 1, 2005.
The unaudited pro forma information in the table below presents a summary of our consolidated results of operations as if our acquisition of the Koch natural gas liquids businesses had occurred at the beginning of the periods presented. The results do not necessarily reflect the results that would have been obtained if our acquisition had actually occurred on the dates indicated or results that may be expected in the future.


Pro Forma
Three Months Ended
June 30, 2005

Pro Forma
Six Months Ended
June 30, 2005


Pro Forma
Nine Months Ended
September 30, 2005
   (Thousand of dollars, except per share amounts)
(Thousands of dollars, except per share amounts)
(Thousands of dollars, except per share amounts)

Net margin
   $ 263,914    $ 671,452    $ 1,000,771
Net income
   $ 26,148    $ 139,928    $ 316,666
Net earnings per share, basic
   $ 0.26    $ 1.37    $ 3.12
Net earnings per share, diluted
   $ 0.24    $ 1.27    $ 2.89
~~C. DISCONTINUED OPERATIONS~~
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~~received FERC approval and ~~is expected to be~~the sale was completed inon October 31, 2006. The 300-megawatt gas-fired merchant power plant was built in 2001 to supply electrical power during peak periods using gas-powered turbine generators. ~~The 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).~~Assets.” 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,    Three Months Ended
September 30, Nine Months Ended
September 30,
   2006 2005    2006 2005    2006 2005 2006 2005
   (Thousands of dollars)    (Thousands of dollars)
Operating revenues
   $ 3,315 $ 40,330    $ 5,164 $ 86,153    $     4,890 $     45,917 $     10,055 $     131,629
Cost of sales and fuel
   2,386 6,977    3,504 23,631    3,695 11,900 7,199 35,532

Net margin
   929 33,353    1,660 62,522    1,195 34,017 2,856 96,097
Impairment expense
   -   52,226 -   52,226
Operating costs
   266 8,412    492 16,089    237 8,383 729 24,025
Depreciation, depletion and amortization
   —   8,492    —   16,772    -   1,146 -   17,919

Operating income
   663 16,449    1,168 29,661    958 (27,738 ) 2,127 1,927

Other income (expense), net
   —   5    —   (1 )    -   170 -   252
Interest expense
   904 3,910    1,808 7,622    904 3,947 2,712 11,657
Income taxes
   (91 ) 4,766    (243 ) 8,374    67 (11,933 ) (175 ) (3,560 )
Income (loss) from operations of discontinued component
   $ (13 ) $ (19,582 ) $ (410 ) $ (5,918 )

Income (loss) from operations of discontinued components, net
   $ (150 ) $ 7,778    $ (397 ) $ 13,664
Gain on sale of discontinued component, net of tax of $90.7 million
   $ -   $ 151,355 $ -   $ 151,355

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

   June 30,
2006    December 31,
2005
   (Thousands of dollars)
September 30,
2006
December 31,
2005
Assets
         (Thousands of dollars)
Property, plant and equipment, net
   $ 50,937    $ 50,937    $     50,937    $     50,937
Other assets
   12,671    12,974    11,960    12,974

Assets of Discontinued Component
   $ 63,608    $ 63,911    $ 62,897    $ 63,911

Liabilities

Accounts payable
   $ 712    $ 1,043    $ 35    $ 1,043
Other liabilities
   1,647    1,421    1,648    1,421

Liabilities of Discontinued Component
   $ 2,359    $ 2,464    $ 1,683    $ 2,464

~~D.  ENERGY MARKETING AND RISK MANAGEMENT ACTIVITIES AND FAIR VALUE OF FINANCIAL INSTRUMENTS~~
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).~~Activities.” Under Statement 133, entities are required to record all derivative instruments at fair value. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it. If the derivative instrument does not qualify or is not designated as part of a hedging relationship, we account for changes in fair value of the derivative instrument in earnings as they occur. We record changes in the fair value of derivative instruments that are considered “held for trading purposes” as energy trading revenues, net and derivative instruments considered not “held for trading purposes” as cost of sales and fuel in our Consolidated Statements of Income. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposure to changes in fair values, cash flows or foreign currencies. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings 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~~income (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~~nine months ended ~~June~~September 30, 2006, for all terminated swaps was ~~$5.1 million and the~~$7.6 million. The remaining net savings for all terminated swaps will be recognized over the periods set forth in the following ~~periods:~~table.
   ONEOK    ONEOK
Partners    Total    ONEOK
ONEOK
Partners    Total
   (Millions of dollars)    (Millions of dollars)
Remainder of 2006
   $ 3.3    $ 1.6    $ 4.9    $ 1.7    $ 0.8    $ 2.5
2007
   6.6    3.4    10.0    6.6    3.4    10.0
2008
   6.6    3.6    10.2    6.6    3.6    10.2
2009
   5.6    3.8    9.4    5.6    3.8    9.4
2010
   5.5    4.0    9.5    5.5    4.0    9.5
Thereafter
   15.3    0.8    16.1    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),~~LIBOR, depending upon the swap. Based on the actual performance through ~~June~~September 30, 2006, the weighted average interest rate on the $490 million of debt increased from 6.64 percent to ~~7.18~~7.16 percent. At ~~June~~September 30, 2006, we recorded a net liability of ~~$30.2~~$13.9 million to recognize the interest rate swaps at fair value. Long-term debt was decreased by ~~$30.2~~$13.9 million to recognize the change in the fair value of the related hedged liability.
Our Energy Services segment uses basis swaps to hedge the fair value of certain firm transportation commitments. Net gains or losses from the fair value hedges are recorded to cost of sales and fuel. The ineffectiveness related to these hedges was ~~$3.9~~a $1.0 million gain and a $1.7 million gain for the three months ended ~~June~~September 30, 2006 and ~~was immaterial for the three months ended June 30, 2005.~~2005, respectively. The ineffectiveness related to these hedges was ~~$9.3~~an $8.3 million loss and a $1.4 million gain for the ~~six~~nine months ended ~~June~~September 30, 2006 and ~~was immaterial for the six months ended June 30, 2005.~~2005, respectively.
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~~income (loss) at ~~June~~September 30, 2006, includes ~~losses~~gains of approximately ~~$28.9~~$47.8 million, net of tax, related to these hedges that will be realized within the next 3532 months. If prices remain at current levels, we will recognize ~~$4.1~~$62.7 million in net gains over the next 12 months, and we will recognize net losses of ~~$33.0~~$14.9 million thereafter.
Net gains and losses are reclassified out of accumulated other comprehensive ~~loss~~income (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~~$4.5 million and ~~$9.5~~$14.0 million for the three and ~~six~~nine months ended ~~June~~September 30, 2006, respectively. Ineffectiveness related to these cash flow hedges for the three and ~~six~~nine months ended ~~June~~September 30, 2005, resulted in a ~~gain~~loss of approximately ~~$0.6~~$7.0 million and a loss of approximately ~~$0.1~~$7.1 million, respectively. There were no losses during the ~~six~~nine months ended ~~June~~September 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~~its 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.~~segment’s net gains are immaterial.
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~~September 30, 2006, Kansas Gas Service had derivative instruments in place to hedge the cost of natural gas purchases for ~~2.7~~5.6 Bcf, which represents part of its gas purchase requirements for the 2006/2007 winter heating months. At ~~June~~September 30, 2006, Texas Gas Service had derivative instruments in place to hedge the cost of natural gas purchases for ~~1.0~~1.1 Bcf, which represents part of its gas purchase requirements for the 2006/2007 winter heating months.
E. E. GOODWILL AND INTANGIBLES
Goodwill
~~Goodwill~~Carrying Amounts - ~~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.
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    Balance
December 31, 2005    Additions    Adjustments Adoption of
EITF 04-5    Balance
September 30, 2006
   (Thousands of dollars)    (Thousands of dollars)
Distribution
   $ 157,953    $ —      $ —   $ —      $ 157,953    $     157,953    $     -      $     -   $     -      $     157,953
Energy Services
   10,255    —      —   —      10,255    10,255    -      -   -      10,255
ONEOK Partners
   211,087    9,552    (2,001 ) 184,843    403,481    211,087    9,552    (2,001 ) 184,843    403,481
Other
   1,099    —      —   —      1,099    1,099    -      -   -      1,099

Goodwill
   $ 380,394    $ 9,552    $ (2,001 ) $ 184,843    $ 572,788    $     380,394    $     9,552    $ (2,001 ) $ 184,843    $     572,788

Goodwill additions in our ONEOK Partners segment include $7.5 million related to ~~our~~the consolidation of Guardian Pipeline, of which $5.7 million relates to the purchase of the additional 66²/ 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~~ONEOK Partners’ acquisition of the additional one percent interest, we began consolidating the entity.
Goodwill adjustments in our ONEOK Partners segment include an $8.4 million reduction related to the Black Mesa Pipeline impairment, offset by $6.4 million in purchase price adjustments. ~~See Note K for discussion of Black Mesa Pipeline impairment.~~
In accordance with EITF 04-5, we consolidated our ONEOK Partners segment beginning January 1, 2006. The adoption of EITF 04-5 resulted in $152.8 million of ONEOK ~~Partners~~Partners’ goodwill being included in our consolidated balance sheet and $32.0 million of goodwill ~~which~~that 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.~~Goodwill - For the investments we account for under the equity method of accounting, ~~this~~the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill. At ~~June~~September 30, 2006, $185.6 million of equity method goodwill was included in our investment in unconsolidated affiliates on our consolidated balance sheet.
~~Intangibles~~Impairment Test - We adopted Statement 142 “Goodwill and Other Intangible Assets,” on January 1, 2002, with a January 1 annual goodwill impairment testing date. In the third quarter of 2006, we changed our annual goodwill impairment testing date to July 1. Prior to the change we had segments, and companies within segments, performing the annual goodwill impairment test as of the fourth quarter and as of January 1. The multiple testing dates were the result of:
the consolidation of ONEOK Partners, in accordance with EITF 04-5, which had a fourth quarter annual goodwill impairment testing date;
our sale of certain assets comprising our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments to ONEOK Partners in April 2006, which resulted in the ONEOK Partners segment including assets with two impairment testing dates since our former Gathering and Processing and Pipelines and Storage segments used a January 1 testing date, while all the legacy ONEOK Partners assets used a fourth quarter testing date; and
our former Natural Gas Liquids segment was comprised of assets primarily acquired in a July 2005 acquisition from Koch and due to the recent acquisition, no date had been selected for testing.
We believe that this change in accounting principle is preferable because (1) the test would be performed at the same time for all our segments, (2) performing the test as of the first day of the third quarter allows adequate time to complete the test while still providing time to report the impact of the test in our periodic filings for the third quarter, and (3) the third quarter is outside the normal operating cycle of most of our segments and coincides with our annual budget process, which results in more detailed budgeting and forecasting information available for use in the impairment analysis. There were no impairment charges resulting from the July 1, 2006, impairment testing, and no events indicating an impairment has occurred subsequent to that date.
Intangibles
Our intangible assets primarily relate to contracts acquired through our acquisition of the natural gas liquids businesses from Koch ~~currently held~~which are recorded in our ONEOK Partners ~~segment which~~segment. Those contracts 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~~nine months ended ~~June~~September 30, 2006 was $1.9
million and ~~$3.8~~$5.7 million, respectively. The following table reflects the gross carrying amount and accumulated amortization of intangibles at ~~June~~September 30, 2006 and December 31, 2005.

   Gross
Intangibles    Accumulated
Amortization Net
Intangibles
   (Thousands of dollars)    Gross
Intangibles    Accumulated
Amortization Net
Intangibles
June 30, 2006
   $ 462,214    $ (7,666 ) $ 454,548
   (Thousands of dollars)
September 30, 2006
   $    462,214    $    (9,582) $    452,632
December 31, 2005
   $ 306,650    $ (3,833 ) $ 302,817    $    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~~These intangibles have an indefinite life and accordingly, are not subject to amortization, but are subject to impairment testing.
~~F. COMPREHENSIVE INCOME~~
F. COMPREHENSIVE INCOME
The tables below ~~give an overview~~show the gross amount of comprehensive income (loss) and related tax (expense) or benefit 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


Three Months Ended
September 30, 2006

Nine Months Ended
September 30, 2006

   Gross

Tax
(Expense) or
Benefit

Net Gross

Tax
(Expense) or
Benefit

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

~~Accumulated~~

Three Months Ended
September 30, 2005

Nine Months Ended
September 30, 2005

   Gross

Tax
(Expense) or
Benefit

Net Gross

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

The table below shows the balance in accumulated other comprehensive ~~loss at June 30, 2006 and 2005, primarily includes unrealized gains and losses on derivative instruments and minimum pension liability adjustments.~~income (loss) for the periods indicated.
~~G. CAPITAL STOCK~~


Unrealized gains
(losses) on energy
marketing and
risk management
assets/liabilities

Minimum pension
liability adjustment

Accumulated other
comprehensive income
(loss)

   (Thousands of dollars)
December 31, 2005
   $ (49,194 ) $ (7,797 ) $ (56,991 )
Year to date change
   90,242 -   90,242
September 30, 2006
   $ 41,048 $ (7,797 ) $ 33,251

G. CAPITAL STOCK
Stock Repurchase Plan - A total of ~~7.5~~15 million shares have been repurchased to date pursuant to a plan approved by our Board of Directors. The plan, originally approved by our Board of Directors in January 2005, was extended in November 2005 to allow us to purchase up to a total of 15 million shares of our common stock on or before November 2007. ~~During~~On August 7, 2006, we repurchased 7.5 million shares of our outstanding common stock under an accelerated share repurchase agreement with UBS Securities LLC (UBS) at an initial price of $37.52 per share for a total of $281.4 million, which completed the ~~six months ended June~~plan approved by our Board of Directors. Under the terms of the accelerated repurchase agreement, we repurchased 7.5 million shares immediately from UBS. UBS then borrowed 7.5 million of our shares and will purchase shares in the open market to settle its short position. Our repurchase is subject to a financial adjustment based on the volume-weighted average price, less a discount, of the shares subsequently repurchased by UBS over the course of the repurchase period. The price adjustment can be settled, at our option, in cash or in shares of our common stock. In accordance with EITF Issue No. 99-7, “Accounting for an Accelerated Share Repurchase Program,” the repurchase was accounted for as two separate transactions: (1) as shares of common stock acquired in a treasury stock transaction recorded on the acquisition date and (2) as a forward contract indexed to ONEOK common stock. Additionally, we classified the forward contract as equity under EITF Issue No. 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock.” At September 30, 2006, we did not owe UBS for a price adjustment. We have no remaining shares available for repurchase ~~shares of~~under our ~~common~~ stock ~~under this~~repurchase 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 and July 31, 2006, were $0.28 per share, $0.30 per share and ~~$0.30~~$0.32 per share, respectively. Additionally, a quarterly dividend of $0.32 per share was declared in ~~July,~~October, payable in the ~~third~~fourth 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.
~~H.  LINES OF CREDIT AND SHORT-TERM NOTES PAYABLE~~
H. LINES OF CREDIT AND SHORT-TERM NOTES PAYABLE
ONEOK ~~Short-term~~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.~~facility in full, and it was terminated according to its terms.
ONEOK ~~Five-year~~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~~amended agreement includes revised pricing, an extension of the maturity date from 2009 to 2011, an option for additional extensions of the maturity date with the consent of the lenders, and an option to request an increase in the commitments of the lenders of up to an additional $500 million. The interest ~~rate~~rates applicable to extensions of credit isunder this agreement are based, at our election, on either (i) the higher
of prime or one-half of one percent above the Federal Funds Rate, which is the rate that banks charge each other for the overnight borrowing of funds, or (ii) the Eurodollar rate plus a set number of basis points based on our current long-term unsecured debt ratings. ~~ONEOK’s~~
Under the five-year credit agreement, ~~includes~~ ONEOK is required to comply with certain financial, operational and legal covenants. Among other things, these requirements include:
a $500 million sublimit for the issuance of standby letters of ~~credit. 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~~requirement that we maintain the power to control the management and policies of ONEOK Partners, and
a limit on new investments in master limited partnerships.
The debt covenant calculations in ONEOK’s five-year credit agreement exclude the debt of ONEOK Partners. At ~~June~~September 30, 2006, we had no borrowings outstanding under this agreement.
ONEOK’s five-year credit agreement also contains customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in our businesses, changes in the nature of our businesses, transactions with affiliates, the use of proceeds and a covenant that prevents us from restricting our subsidiaries’ ability to pay dividends. At September 30, 2006, ONEOK was in compliance with these covenants.
At September 30, 2006, ONEOK had $88.4 million in letters of credit, no commercial paper outstanding and no loans outstanding under the Credit Agreement.
ONEOK Partners Five-Year Credit Agreement - In March 2006, ONEOK Partners entered into a five-year $750 million amended and restated revolving credit agreement (2006 Partnership Credit Agreement) with certain financial institutions and terminated its $500 million revolving credit agreement. At ~~June~~September 30, 2006, ONEOK Partners had $15 million in letters of credit outstanding and no borrowings ~~of $311.0 million~~outstanding 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.~~Agreement.
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.~~acquisitions. Upon any breach of these covenants, amounts outstanding under the 2006 Partnership Credit Agreement ~~and the Bridge Facility~~ may become immediately due and payable. At September 30, 2006, ONEOK Partners was in compliance with these covenants.
~~Guardian Pipeline~~ONEOK Partners Bridge Facility - In April 2006, ONEOK ~~Partners’ acquisition~~Partners entered into a $1.1 billion 364-day credit agreement (Bridge Facility) with a syndicate of ~~an additional 66~~²/3 ~~percent interest in Guardian Pipeline resulted in the inclusion of outstanding amounts~~banks and borrowed $1.05 billion under ~~Guardian Pipeline’s revolving note~~this 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~~finance a portion of ~~the borrowings to be covered by the specific interest rate options~~its purchase of certain assets comprising our former Gathering and ~~specify~~Processing, Natural Gas Liquids, and Pipelines and Storage segments. In September 2006, ONEOK Partners repaid 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, changesBridge Facility using proceeds from the issuance of senior notes, which resulted in the ~~nature~~Bridge Facility being terminated according to its terms. See Note I for further discussion regarding the issuance 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.senior notes.
~~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~~
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


September 30,
2006
December 31,
2005
   (Thousands of dollars)
ONEOK

    5.51% due 2008
   $ 402,303      $ 402,303
    6.0% due 2009
   100,000      100,000
    7.125% due 2011
   400,000      400,000
    5.2% due 2015
   400,000      400,000
    6.4% due 2019
   92,623      92,921
    6.5% due 2028
   91,788      92,246
    6.875% due 2028
   100,000      100,000
    6.0% due 2035
   400,000      400,000
    Other
   3,270      5,732

   1,989,984      1,993,202

ONEOK Partners

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

   1,875,000      -

Guardian Pipeline

    Average 7.85%, due 2022
   148,555      -

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

~~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 the remainder of 2006 and for years ending December 31, 2007 through 2010 are shown below.

ONEOK ONEOK
Partners Guardian Total    ONEOK
ONEOK
Partners    Guardian    Total
(Millions of dollars)    (Millions of dollars)
Remainder of 2006
   $ 6.3    $ -      $ 3.0    $ 9.3
2007 $ 6.6 $ —   $ 11.9 $ 18.5    6.2    -      11.9    18.1
2008 408.9 —   11.9 420.8    408.6    -      11.9    420.5
2009 107.5 —   11.9 119.4    106.3    -      11.9    118.2
2010 6.3 250.0 11.9 268.2    6.3    250.0    11.9    268.2
Additionally, ~~$184.8~~$184.4 million of ONEOK’s debt is callable at par at our option from now until maturity, which is 2019 for ~~$92.8~~$92.6 million and 2028 for ~~$92.0~~$91.8 million. Certain debt agreements have negative covenants that relate to liens and sale/leaseback transactions.
ONEOK Partners Debt Issuance - In September 2006, ONEOK Partners completed an underwritten public offering of (i) $350 million aggregate principal amount of 5.90 percent Senior Notes due 2012 (the “2012 Notes”), (ii) $450 million aggregate principal amount of 6.15 percent Senior Notes due 2016 (the “2016 Notes”) and (iii) $600 million aggregate principal amount of 6.65 percent Senior Notes due 2036 (the “2036 Notes” and collectively with the 2012 Notes and the 2016 Notes, the “Notes”). ONEOK Partners registered the sale of the Notes with the SEC pursuant to a registration statement filed on September 19, 2006.
The Notes are guaranteed on a senior unsecured basis by the Intermediate Partnership. The guarantee ranks equally in right of payment to all of the Intermediate Partnership’s existing and future unsecured senior indebtedness.
ONEOK Partners may redeem the Notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount of the Notes, plus accrued interest, unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the relevant Notes plus accrued and unpaid interest. The Notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and effectively junior to all of the existing debt and other liabilities of its non-guarantor subsidiaries. The Notes are non-recourse to us.
The net proceeds from the Notes of approximately $1.39 billion, after deducting underwriting discounts and commissions and expenses, but before offering expenses, were used to repay all of the amounts outstanding under the Bridge Facility and to repay $335 million of indebtedness outstanding under the 2006 Partnership Credit Agreement. The terms of the Notes are governed by the Indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., as trustee, as supplemented by the First Supplemental Indenture (with respect to the 2012 Notes), the Second Supplemental Indenture (with respect to the 2016 Notes) and the Third Supplemental Indenture (with respect to the 2036 Notes), each dated September 25, 2006. The Indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The Indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and sell and lease back its property.
The 2012 Notes, 2016 Notes and 2036 Notes will mature on April 1, 2012, October 1, 2016 and October 1, 2036, respectively. ONEOK Partners will pay interest on the Notes on April 1 and October 1 of each year. The first payment of interest on the Notes will be made on April 1, 2007. Interest on the Notes accrues from September 25, 2006, which was the issuance date of the Notes.
Guardian Pipeline Master Shelf Agreement - ONEOK Partners’ acquisition of ~~an additional~~the remaining 66²/ 2/3 percent interest in Guardian Pipeline resulted in the inclusion of ~~$151.5~~$148.6 million of long-term debt in our consolidated balance sheet. ~~The senior~~These notes were issued under a master shelf agreement with certain financial institutions. Principal payments are due annually through 2022. Interest rates on the notes range from 7.61 percent to 8.27 percent, with an average rate of 7.85 percent.
Guardian Pipeline’s ~~master shelf~~Master Shelf agreement contains financial covenants ~~which are~~that require the ~~same as~~maintenance of a ratio of (1) EBITDAR (net income plus interest expense, income taxes, operating lease expense and depreciation and amortization) to the sum of interest expense plus operating lease expense of not less than 1.5 to 1 and (2) total indebtedness to EBITDAR of not greater than 6.75 to 1. Upon any breach of these covenants, all amounts outstanding under the master shelf agreement may become due and payable immediately. Beginning in December 2007, the rate of total indebtedness to EBITDAR may not be greater than 5.75 to 1. At September 30, 2006, Guardian ~~Pipeline’s revolving note agreement, as described~~Pipeline was in ~~Note H.~~compliance with its financial covenants.
~~J. EMPLOYEE BENEFIT PLANS~~
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
Pension Benefits
Three Months Ended
September 30,

Pension Benefits
Nine Months Ended
September 30,
   (Thousands of dollars)      2006    2005      2006    2005
Components of Net Periodic Benefit Cost
        (Thousands of dollars)
Service cost
   $ 5,267 $ 4,941 $ 10,532 $ 9,882      $ 5,204    $ 4,941      $ 15,736    $ 14,823
Interest cost
   10,871 10,758 21,742 21,516      10,826    10,758      32,569    32,273
Expected return on assets
   (14,396 ) (14,927 ) (28,794 ) (29,854 )      (14,396 )    (14,927 )      (43,189 )    (44,780 )
Amortization of unrecognized prior service cost
   378 361 756 722      378    361      1,133    1,082
Amortization of loss
   3,353 2,126 6,708 4,252      3,278    2,126      9,985    6,377

Net periodic benefit cost
   $ 5,473 $ 3,259 $ 10,944 $ 6,518      $ 5,290    $ 3,259      $ 16,234    $ 9,775

   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


Postretirement Benefits
Three Months Ended
September 30,

Postretirement Benefits
Nine Months Ended
September 30,
   2006 2005    2006 2005
Components of Net Periodic Benefit Cost
   (Thousands of dollars)
Service cost
   $ 1,583 $ 1,765    $ 4,749 $ 5,294
Interest cost
   3,539 3,567    10,617 10,702
Expected return on assets
   (1,141 ) (1,086 )    (3,423 ) (3,258 )
Amortization of unrecognized net asset at adoption
   797 864    2,392 2,592
Amortization of unrecognized prior service cost
   (571 ) 118    (1,715 ) 354
Amortization of loss
   2,271 1,617    6,814 4,852
Net periodic benefit cost
   $ 6,478 $ 6,845    $ 19,434 $ 20,536

Contributions - For the ~~six~~nine months ended ~~June~~September 30, 2006, contributions of ~~$0.8~~$1.1 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
postretirement benefit plan costs were ~~$5.2~~$8.8 million for the ~~six~~nine months ended ~~June~~September 30, 2006, and we expect our total pay-as-you-go costs for 2006 to be $14.0 million.
~~K. COMMITMENTS AND CONTINGENCIES~~
K. COMMITMENTS AND CONTINGENCIES
Operating Leases and Agreements - Our operating leases include a gas processing plant, office buildings, vehicles and equipment. The following table sets forth the future minimum lease payments as of September 30, 2006 under non-cancelable operating leases for each of the following years.

   ONEOK    ONEOK
Partners    Total    ONEOK
ONEOK
Partners    Total
   (Millions of dollars)    (Millions of dollars)
Remainder of 2006
   $ 24.0    $ 2.3    $ 26.3    $ 12.0    $ 1.2    $ 13.2
2007
   32.7    3.1    35.8    32.7    3.3    36.0
2008
   30.8    2.3    33.1    30.8    2.7    33.5
2009
   28.3    0.9    29.2    28.3    0.9    29.2
2010
   26.1    0.8    26.9    26.1    0.5    26.6
The amounts in the ONEOK column above include the minimum lease payments relating to the lease of a gas processing plant for which we have a liability as a result of uneconomic lease terms.
Environmental Liabilities - We are subject to multiple environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid wastes and hazardous material and substance management. These laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to the 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~~Kansas that we acquired in November 1997. These sites contain potentially harmful materials that are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE presently governs all work at these sites. The terms of the consent agreement allow us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of contaminated soils and may involve removal
of structures and monitoring and/or remediation of groundwater. We have commenced remediation on eleven sites, with regulatory closure achieved at two of these locations. Of the remaining nine sites, we have completed or are near completion of soil remediation at six sites, and we expect to commence soil remediation on the other three sites. We have begun site assessment at the remaining site where no active remediation has occurred.
To date, we have incurred remediation costs of $5.8 million and have accrued an additional $6.0 million related to the sites where we have commenced or will soon commence remediation. We have recorded estimates of future remediation costs for these sites based on our environmental ~~evaluation~~assessments and remediation plans approved by the KDHE. These estimates are recorded on an undiscounted basis. For the site that is currently in the assessment phase, we have completed some analysis, but are unable at this point to accurately estimate aggregate costs that may be required to satisfy our remedial obligations at this site. Until the site assessment is complete and the KDHE approves the remediation plan, we will not have complete information available to us to accurately estimate remediation costs.
The costs associated with these sites do not include other potential expenses that might be incurred, such as unasserted property damage claims, personal injury or natural resource claims, unbudgeted legal expenses or other costs for which we may be held liable but with respect to which we cannot reasonably estimate an amount. As of this date, we have no knowledge of any of these types of claims. The foregoing estimates do not consider potential insurance recoveries, recoveries through rates or recoveries from unaffiliated parties, to which we may be entitled. We have filed claims with our insurance carriers relating to these sites and we have recovered a portion of our costs incurred to date. We have not ~~been significant~~recorded any amounts for potential insurance recoveries or recoveries from unaffiliated parties, and we are not recovering any environmental amounts in ~~relation~~rates. As more information related to the site investigations and remediation activities becomes available, and to the extent such amounts are expected to exceed our current estimates, additional expenses could be recorded. Such amounts could be material to our results of operations and ~~there have been no material effects upon earnings during 2006 related~~cash flows depending on the remediation and number of years over which the remediation is required 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.be completed.
Other - We are a party to other litigation matters and claims, which are normal in the course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or liquidity.
~~L. SEGMENTS~~
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~~NGLs; and provides NGL gathering and distribution services. The primary customers for our ONEOK Partners segment include major and independent oil and gas production companies, gathering and processing companies, petrochemical and refining companies, natural gas producers, marketers, industrial facilities, local distribution companies and electric power generating plants.
In September 2005, we completed the sale of our Production segment. Additionally, in the third quarter of 2005, we made the decision to sell our Spring Creek power plant and exit the power generation business. The sale was completed on October 31, 2006. These components of our business are accounted for as discontinued operations in accordance with Statement 144. Our Production segment is included in our Other segment in the 2005 tables below, while our power generation business is included in our Energy Services segment in the tables below.
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
Three Months Ended
September 30, 2006
   Distribution
Energy
Services

ONEOK
Partners

Other and
Eliminations
Total
   (Thousands of dollars)
   (Thousands of dollars)
Sales to unaffiliated customers
   $ 317,109    $ 1,103,904 $ 998,070    $ 8,712 $ 2,427,795    $   252,261 $   1,350,802 $   1,045,634 $ 615 $   2,649,312
Energy trading revenues, net
   —      4,112 —      —   4,112    -   (8,435 ) -   -   (8,435 )
Intersegment sales
   —      86,763 161,280    (248,043 ) —      -   51,892 168,949 (220,841 ) -

Total Revenues
   $ 317,109    $ 1,194,779 $ 1,159,350    $ (239,331 ) $ 2,431,907    $ 252,261 $ 1,394,259 $ 1,214,583 $ (220,226 ) $ 2,640,877

Net margin
   $ 119,631    $ 64,327 $ 215,200    $ 2,491 $ 401,649    $ 106,942 $ 30,725 $ 210,682 $ 637 $ 348,986
Operating costs
   91,524    10,304 77,199    1,047 180,074    88,821 8,637 75,529 996 173,983
Depreciation, depletion and amortization
   27,161    529 39,282    122 67,094    27,307 524 27,516 121 55,468
Gain on sale of assets
   —      —   113,877    1,027 114,904    -   -   -   -   -

Operating income
   $ 946    $ 53,494 $ 212,596    $ 2,349 $ 269,385    $ (9,186 ) $ 21,564 $ 107,637 $ (480 ) $ 119,535

Loss from operations of discontinued components
   $ —      $ (150 ) $ —      $ —   $ (150 )    $ -   $ (13 ) $ -   $ -   $ (13 )
Income from equity investments
   $ —      $ —   $ 18,075    $ —   $ 18,075
Equity earnings from investments
   $ -   $ -   $ 22,788 $ -   $ 22,788
Capital expenditures
   $ 41,017    $ —   $ 35,799    $ 1,106 $ 77,922    $ 37,154 $ -   $ 61,213 $ 13,008 $ 111,375
Three Months Ended
September 30, 2005
   Distribution
Energy
Services

ONEOK
Partners

Other and
Eliminations
Total
   (Thousands of dollars)
Sales to unaffiliated customers
   $ 316,021 $ 1,897,038 $ 1,222,324 $ (253,791 ) $ 3,181,592
Energy trading revenues, net
   -   10,615 -   -   10,615
Intersegment sales
   -   110,083 186,632 (296,715 ) -
Total Revenues
   $ 316,021 $ 2,017,736 $ 1,408,956 $ (550,506 ) $ 3,192,207
Net margin
   $ 105,104 $ 55,040 $ 168,734 $ 441 $ 329,319
Operating costs
   91,596 12,451 66,785 290 171,122
Depreciation, depletion and amortization
   26,298 533 21,175 125 48,131
Gain on sale of assets
   -   -   -   -   -
Operating income
   $ (12,790 ) $ 42,056 $ 80,774 $ 26 $ 110,066
Income (loss) from operations of discontinued components
   $ -   $ (32,972 ) $ -   $ 13,390 $ (19,582 )
Equity earnings from investments
   $ -   $ -   $ (39 ) $ 2,861 $ 2,822
Capital expenditures
   $ 39,069 $ -   $ 8,949 $ 13,939 $ 61,957
Three Months Ended June 30, 2005
   Distribution Energy
Services ONEOK
Partners    Other and
Eliminations Total
Nine Months Ended
September 30, 2006
   Distribution
Energy
Services

ONEOK
Partners
Other and
Eliminations
Total
   (Thousands of dollars)    (Thousands of dollars)
Sales to unaffiliated customers
   $ 339,794 $ 1,383,473 $ 263,140    $ 103,167 $ 2,089,574    $     1,356,613    $     4,485,343 $     2,983,875    $ (454 ) $     8,825,377
Energy trading revenues, net
   —   (8,784 ) —      —   (8,784 )    -      3,047 -      -   3,047
Intersegment sales
   —   171,257 181,409    (352,666 ) —      -      323,800 559,888    (883,688 ) -

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    $ 1,356,613    $ 4,812,190 $ 3,543,763    $ (884,142 ) $ 8,828,424

Net margin
   $ 315,072 $ 167,481 $ 420,141    $ 3,485 $ 906,179    $ 422,014    $ 198,206 $ 624,143    $ 4,122 $ 1,248,485
Operating costs
   182,037 19,564 155,802    1,803 359,206    270,858    28,201 224,650    2,799 526,508
Depreciation, depletion and amortization
   55,314 1,104 66,752    250 123,420    82,621    1,628 94,269    371 178,889
Gain on sale of assets
   —   —   114,865    1,027 115,892    -      -   114,865    1,027 115,892

Operating income
   $ 77,721 $ 146,813 $ 312,452    $ 2,459 $ 539,445    $ 68,535    $ 168,377 $ 420,089    $ 1,979 $ 658,980

Income (loss) from operations of discontinued components
   $ —   $ (397 ) $ —      $ —   $ (397 )    $ -      $ (410 ) $ -      $ -   $ (410 )
Income from equity investments
   $ —   $ —   $ 49,954    $ —   $ 49,954
Equity earnings from investments
   $ -      $ -   $ 72,750    $ -   $ 72,750
Total assets
   $ 2,628,453 $ 1,689,530 $ 5,040,491    $ 817,630 $ 10,176,104    $ 2,606,379    $ 1,987,476 $ 5,030,429    $ 564,234 $ 10,188,518
Capital expenditures
   $ 77,692 $ —   $ 53,575    $ 1,326 $ 132,593    $ 114,846    $ -   $ 114,788    $ 14,334 $ 243,968
Nine Months Ended
September 30, 2005
   Distribution
Energy
Services

ONEOK
Partners
Other and
Eliminations
Total
   (Thousands of dollars)
Sales to unaffiliated customers
   $ 1,433,945    $ 4,816,867 $ 1,444,788    $ 273,414 $ 7,969,014
Energy trading revenues, net
   -      11,023 -      -   11,023
Intersegment sales
   -      487,248 860,909    (1,348,157 ) -
Total Revenues
   $ 1,433,945    $ 5,315,138 $ 2,305,697    $ (1,074,743 ) $ 7,980,037
Net margin
   $ 412,816    $ 127,483 $ 391,519    $ (2,125 ) $ 929,693
Operating costs
   265,701    28,277 155,483    (3,415 ) 446,046
Depreciation, depletion and amortization
   86,301    1,503 46,867    349 135,020
Gain on sale of assets
   -      -   -      -   -
Operating income
   $ 60,814    $ 97,703 $ 189,169    $ 941 $ 348,627
Income (loss) from operations of discontinued components
   $ -      $ (34,413 ) $ -      $ 28,495 $ (5,918 )
Equity earnings from investments
   $ -      $ -   $ 597    $ 7,875 $ 8,472
Total assets
   $ 2,661,119    $ 3,105,229 $ 4,036,790    $ 559,317 $ 10,362,455
Capital expenditures
   $ 103,078    $ 159 $ 39,390    $ 47,303 $ 189,930

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~~
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      Nine Months Ended September 30,
   (Thousands of dollars)      2006    2005
Cash paid during the period
           (Thousands of dollars)
Interest, including amounts capitalized
   $ 125,670    $ 104,149      $        163,426    $          141,868
Income taxes
   $ 159,628    $ 55,260      $        214,187    $            55,797
Cash paid for interest includes swap terminations and treasury rate-lock terminations of $22.6 million for the ~~six~~nine months ended ~~June~~September 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 stock and repurchases in the open market to satisfy our share-based payment obligations.
The compensation cost expensed for our share-based payment plans described below was ~~$5.2~~$7.8 million for the ~~six~~nine months ended ~~June~~September 30, 2006, net of a $3.0 million tax ~~benefit of $2.0 million.~~benefit. No compensation cost was capitalized for the ~~six~~nine months ended ~~June~~September 30, 2006.
Cash received from the exercise of awards under all share-based payment arrangements was ~~$3.6~~$6.6 million for the ~~six~~nine months ended ~~June~~September 30, 2006. The actual tax benefit realized for the anticipated tax deductions of the exercise of share-based payment arrangements totaled ~~$1.5~~$2.6 million for the ~~six~~nine months ended ~~June~~September 30, 2006. No cash was used to settle awards granted under share-based payment arrangements.
Share-Based Payment Plan Descriptions
The ONEOK, Inc. Long-Term Incentive Plan (the LTIP), the ONEOK, Inc. Equity Compensation Plan (Equity Compensation Plan) and the ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors (the DSCP) are described in Note P in our Annual Report on Form 10-K for the year ended December 31, 2005.
Stock Option Activity
The total fair value of stock options vested during the ~~six~~nine months ended ~~June~~September 30, 2006, was ~~$3.6~~$4.0 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    Number of
Shares

Weighted
Average
Price
Outstanding December 31, 2005
   1,952,415 $ 22.51    1,952,415 $ 22.51
Exercised
   (359,256 ) $ 21.39    (590,921 ) $ 23.04
Expired
   (2,166 ) $ 19.39    (2,166 ) $ 19.39
Restored
   115,667 $ 31.83    237,111 $ 35.03
Outstanding September 30, 2006
   1,596,439 $ 24.17

Outstanding June 30, 2006
   1,706,660 $ 23.38
Exercisable September 30, 2006
   1,405,070 $ 22.55

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    $ —
Stock Options Outstanding Stock Options Exercisable
Range of
Exercise Prices
Number
of Awards Remaining
Life (yrs) Weighted
Average
Exercise Price
Aggregate
Intrinsic
Value
(in 000’s)
Number
of Awards Remaining
Life (yrs) Weighted
Average
Exercise Price
  Aggregate
Intrinsic Value
      (in 000’s)
$14.58 to $21.87
693,270 5.33 $ 17.06 $ 14,371 691,728 5.33 $ 17.06 $ 14,340
$21.88 to $32.82
565,688 4.15 $ 25.86 $ 6,749 497,305 4.18 $ 24.98 $ 6,370
$32.83 to $38.83
337,481 3.80 $ 35.63 $ 729 216,037 3.78 $ 34.52 $ 706
The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value, based on our closing stock price of ~~$34.04~~$37.79 as of ~~June~~September 30, 2006, that would have been received by the option holders had all option holders exercised their options as of ~~that date.~~September 30, 2006.
The fair value of each option granted was estimated on the date of grant based on the Black-Scholes model using the assumptions in the table below.

Volatility (a)
   ~~13.88%~~13.88 % to ~~31.06~~ %31.06%
Dividend Yield
   ~~2.78%~~2.78 % to ~~8.93~~ %8.5%
Risk-free Interest Rate
   ~~2.52%~~2.52 % to ~~6.53~~ %6.11%
(a) -
Volatility was based on historical volatility over ~~six~~nine
        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~~September 30, 2006, the amount of unrecognized compensation cost related to nonvested stock options was not material. The following table sets forth various statistics relating to our stock option activity.

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

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

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    Number of
Shares

    Weighted
Average
Price
Nonvested December 31, 2005
   119,514 $ 22.44    119,514 $ 22.44
Released to participants
   (4,086 ) $ 21.55    (4,086 ) $ 21.55
Forfeited
   (2,912 ) $ 23.19    (2,912 ) $ 23.19
Nonvested September 30, 2006
   112,516 $ 22.45

Nonvested June 30, 2006
   112,516 $ 22.45

As of ~~June~~September 30, 2006, there was ~~$4.5~~$4.0 million of total unrecognized compensation cost related to our nonvested restricted stock awards, which is expected to be recognized over a weighted-average period of ~~1.5~~1.2 years. The following table sets forth various statistics relating to our restricted stock awards.

   June 30, 2006    September 30, 2006
Weighted average grant date fair value (per share)
   $ 23.82    $ 23.82
Fair value of shares granted (thousands of dollars)
   $ 3,448    $ 3,448
Performance Unit Activity
~~Performance~~If paid the performance unit awards granted in 2005 and 2004 entitle the grantee to receive two-thirds of the grant in shares of our common stock and one-third of the grant in cash, while awards granted in 2003 entitle the grantee to receive common stock only. These awards vest over a three-year period. The fair values of these performance units that are classified as equity awards were calculated as of the date of grant and remain fixed as equity units upon adoption of Statement 123R. The fair values of the one-third liability portion of the performance units are estimated at each reporting date based on a Monte Carlo model.
~~Awards~~If paid the awards granted in 2006 entitle the grantee to receive the grant in shares of our common stock. Under Statement 123R, our 2006 performance unit awards are equity awards with a market based condition, which results in the compensation cost for these awards being recognized over the requisite service period, provided that the requisite service period is rendered, regardless of when, if ever, the market condition is satisfied. The fair value of these performance units was estimated on the grant date based on a Monte Carlo model. The compensation expense on these awards will only be adjusted for changes in forfeitures.
The total fair value of shares vested during the ~~six~~nine months ended ~~June~~September 30, 2006, was $4.9 million.
The following table sets forth activity for the performance unit equity awards.

   Number of
Units Weighted
Average
Exercise Price    Number of
Units

    Weighted
Average
Price
Nonvested December 31, 2005
   581,847 $ 21.13    581,847 $ 21.13
Granted
   479,000 $ 25.98    479,000 $ 25.98
Released to participants
   (158,365 ) $ 15.31    (158,365 ) $ 15.31
Forfeited
   (16,324 ) $ 23.96    (20,654 ) $ 24.29
Nonvested September 30, 2006
   881,828 $ 24.74

Nonvested June 30, 2006
   886,158 $ 24.74

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

   ~~February~~January 19,
2006
Volatility (a)
   ~~18.80~~ %18.80%
Dividend Yield
   ~~3.70~~ %3.70%
Risk-free Interest Rate
   ~~4.32~~ %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    Number of
Units

    Weighted
Average
Price
Nonvested December 31, 2005
   212,311 $ 23.31    212,311 $ 23.31
Released to participants
   (166 ) $ 23.36    (166 ) $ 23.36
Forfeited
   (7,894 ) $ 23.89    (8,309 ) $ 23.89
Nonvested September 30, 2006
   203,836 $ 23.29

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

As of ~~June~~September 30, 2006, there was ~~$14.0~~$14.1 million of total unrecognized compensation cost related to the nonvested performance unit awards, which is expected to be recognized over a weighted-average period of ~~1.8~~1.5 years. The following table sets forth various statistics relating to our performance units.

   June 30, 2006    September 30, 2006
Weighted average grant date fair value (per share)
   $ 25.98    $ 25.98
Fair value of shares granted (thousands of dollars)
   $ 12,444    $ 12,444
O. UNCONSOLIDATED AFFILIATES
Investments in Unconsolidated Affiliates - The following table sets forth our investments in unconsolidated affiliates for the periods indicated.
   Net
Ownership
Interest
September 30,
2006

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

(a) Beginning January 1, 2006, ONEOK Partners’ interest in Northern Border Pipeline is accounted for as an investment under the equity method (Note B). For the first three months of 2006, ONEOK Partners included 70 percent of Northern Border Pipeline’s income in equity earnings from investments. After the sale of a 20 percent interest in Northern Border Pipeline in April 2006, ONEOK Partners includes 50 percent of Northern Border Pipeline’s income in equity earnings from investments.
(b) Equity method goodwill (Note E) was $185.6 million at September 30, 2006.
(c) ONEOK Partners is entitled to receive an incentive allocation of earnings from third-party gathering services revenue recognized by Lost Creek Gathering. As a result of the incentive, ONEOK Partners’ share of Lost Creek Gathering income exceeds the amount its 35 percent ownership interest would otherwise be entitled to.
(d) ONEOK Partners was consolidated beginning January 1, 2006 in accordance with EITF 04-5. Prior to January 1, 2006, ONEOK Partners was accounted for as an investment under the equity method.
~~O. EARNINGS PER SHARE INFORMATION~~Equity Earnings from Investments - The following table sets forth our equity earnings from investments for the periods indicated.

Three Months Ended
September 30,

Nine Months Ended
September 30,
   2006    2005 2006    2005
   (Thousands of dollars)
Northern Border Pipeline
   $     16,841    $ -   $ 55,691    $ -
Bighorn Gas Gathering
   1,959    -   5,780    -
Fort Union Gas Gathering
   2,346    -   6,624    -
Lost Creek Gathering
   1,437    -   4,036    -
Other
   205    (40 ) 619    597
ONEOK Partners
   -      2,862 -      7,875
Total Equity Earnings From Investments
   $     22,788    $     2,822 $     72,750    $     8,472

Unconsolidated Affiliates Financial Information-Summarized combined financial information of our unconsolidated affiliates is presented below.
   September 30, 2006
   (Thousands of dollars)
Balance Sheet

Current assets
   $ 88,879
Property, plant and equipment, net
   $ 1,691,334
Other noncurrent assets
   $ 24,178
Current liabilities
   $ 243,826
Long-term debt
   $ 496,247
Other noncurrent liabilities
   $ 5,493
Accumulated other comprehensive income
   $ 1,244
Owners’ equity
   $ 1,057,581

Nine Months Ended
September 30, 2006
   (Thousands of dollars)
Income Statement

Operating revenue
   $ 287,816
Operating expenses
   $ 118,642
Net income
   $ 135,719
Distributions paid to us
   $ 93,209
P. 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    Three Months Ended September 30, 2006
   (Thousands, except per share amounts)    Income    Shares
Per Share
Amount
Basic EPS from continuing operations
            (Thousands, except per share amounts)
Income from continuing operations available for common stock
   $ 77,945    117,423    $ 0.66    $ 24,413    113,200    $ 0.22
Diluted EPS from continuing operations

Effect of options and other dilutive securities
      1,603       -      1,720

Income from continuing operations available for common stock and common stock equivalents
   $ 77,945    119,026    $ 0.65    $ 24,413    114,920    $ 0.21


   Three Months Ended June 30, 2005
   Income    Shares    Per Share
Amount    Three Months Ended September 30, 2005
   (Thousands, except per share amounts)    Income    Shares
Per Share
Amount
Basic EPS from continuing operations
            (Thousands, except per share amounts)
Income from continuing operations available for common stock
   $ 17,074    101,143    $ 0.17    $ 44,614    99,894    $ 0.45
Diluted EPS from continuing operations

Effect of dilutive securities:

Mandatory convertible units
   —      6,840       -      7,515
Options and other dilutive securities
   —      1,079       -      1,193

Income from continuing operations available for common stock and common stock equivalents
   $ 17,074    109,062    $ 0.16    $ 44,614    108,602    $ 0.41


   Six Months Ended June 30, 2006
   Income    Shares    Per Share
Amount    Nine Months Ended September 30, 2006
   (Thousands, except per share amounts)    Income    Shares
Per Share
Amount
Basic EPS from continuing operations
            (Thousands, except per share amounts)
Income from continuing operations available for common stock
   $ 207,684    112,283    $ 1.85    $ 232,097    112,589    $ 2.06
Diluted EPS from continuing operations

Effect of dilutive securities:

Mandatory convertible units
   —      1,259       -      839
Options and other dilutive securities
   —      1,349       -      1,473

Income from continuing operations available for common stock and common stock equivalents
   $ 207,684    114,891    $ 1.80    $ 232,097    114,901    $ 2.02

   Six Months Ended June 30, 2005
   Income    Shares    Per Share
Amount
Nine Months Ended September 30, 2005 Nine Months Ended September 30, 2005
   (Thousands, except per share amounts)    Income    Shares
Per Share
Amount
Basic EPS from continuing operations
            (Thousands, except per share amounts)
Income from continuing operations available for common stock
   $ 118,852    102,404    $ 1.16    $ 163,466    101,568      $ 1.61
Diluted EPS from continuing operations

Effect of dilutive securities:

Mandatory convertible units
   —      6,569       -      6,884
Options and other dilutive securities
   —      1,058       -      1,103

Income from continuing operations available for common stock and common stock equivalents
   $ 118,852    110,031    $ 1.08    $ 163,466    109,555      $ 1.49

There were ~~341,300~~49,775 and ~~21,964~~21,681 option shares excluded from the calculation of diluted EPS for the three months ended ~~June~~September 30, 2006, and 2005, respectively, since their inclusion would have been antidilutive for each period. There were ~~390,112~~276,666 and ~~24,977~~48,062 option shares excluded from the calculation of diluted EPS for the ~~six~~nine months ended ~~June~~September 30, 2006 and 2005, respectively, since their inclusion would be antidilutive for each period.
~~P. ONEOK PARTNERS~~
Q. 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 which have limited voting rights and which 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~~Our investment in ONEOK Partners ~~consisted of~~is shown in the ~~following:~~table below for the periods presented.

   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.~~
   September 30,
2006      December 31,
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.
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’ general partner and incentive distributions ~~that were due to the general partners~~we received for the periods ~~ending June~~ended September 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

     Three Months Ended
September 30,    Nine Months Ended
September 30,
     2006    2005    2006    2005
     (Thousands of dollars)
General partner distributions
     $ 1,840    $ 658    $ 4,354    $ 1,975
Incentive distributions
     9,772    1,642    20,534    4,925
Total distributions from ONEOK Partners to us
     $ 11,612    $ 2,300    $ 24,888    $ 6,900

The quarterly distributions paid by ONEOK Partners to limited partners in the first, second and ~~second~~third quarters of 2006 were $0.80 per unit, $0.88 per unit and ~~$0.88~~$0.95 per unit, respectively. In ~~July~~October 2006, ONEOK Partners declared a cash distribution of ~~$0.95~~$0.97 per unit payable in the ~~third~~fourth 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 and its subsidiaries, which ~~comprises~~comprise our ONEOK Partners segment.
ONEOK Partners sells natural gas from its gathering and processing operations to our Energy Services segment. In addition, a large portion of ONEOK Partners’ revenues from its pipelines and storage operations are from our Energy Services and Distribution segments, which utilize ~~both~~ONEOK Partners’ 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,~~However, 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


Three Months Ended
September 30, 2006
Nine Months Ended
September 30, 2006
     (Thousands of Dollars)
Revenue
     $ 168,949    $ 549,175

Expense

Administrative and general expenses
     $ 24,890    $ 70,801
Interest expense
     -    21,281
Total expense
     $ 24,890    $ 92,082

ITEM 2. ~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~ MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
EXECUTIVE SUMMARY
Operating income for our ~~second~~third quarter of 2006 was ~~$269.4~~$119.5 million, an increase of ~~$217.2~~$9.5 million, or ~~416~~nine percent, compared with the same period in 2005. For the first ~~six~~nine months of 2006, operating income was ~~$539.4~~$659.0 million, an increase of ~~$300.9~~$310.4 million, or ~~126~~89 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~~$194.5 million for the ~~three- and six-month periods, respectively.~~nine-month period. 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~~decreased to 6521 cents for the ~~second~~third quarter of 2006 from 1641 cents for the same period in 2005. For the ~~six-month~~nine-month period, EPS increased to ~~$1.80~~$2.02 from ~~$1.08~~$1.49 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).~~Partners. Prior periods have been restated to show our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments as part of our newly formed ONEOK Partners segment. The legacy operations of ONEOK Partners accounted for the 2006 operating income increases in our ONEOK Partners segment ~~in 2006~~ since we consolidated ONEOK Partners beginning January 1, 2006, in accordance with ~~Emerging Issues Task Force (EITF)~~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).~~Rights.” See Impact of New Accounting Standards on page 3337 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 operating income 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~~strong commodity prices, wider gross processing spreads and increased natural gas transportation revenues. These increases were slightly offset by decreases in our ONEOK Partners segment resulting from the sale of natural gas gathering and processing assets located in Texas in December 2005.
Operating income for our Energy Services segment ~~increased $50.6 million and $91.2~~decreased $20.5 million for the ~~three~~three-month period and ~~six months ended June 30, 2006, respectively. Increases of $21.9 million and $32.0~~increased $70.7 million for the ~~three and six months ended June 30, 2006, respectively, were~~nine-month period. The decrease for the three-month period was primarily related to ~~optimization activities~~lower storage and ~~increased demand fees. Additionally, increases of $16.8 million and $45.0 million~~marketing margins resulting from reduced storage opportunities in the third quarter 2006 compared with the same period in 2005. The increase for the ~~three and six months ended June 30, 2006, respectively, were~~nine-month period was primarily 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~~$0.97 per unit in ~~July~~October 2006, an increase of approximately ~~eight~~two percent over the $0.95 paid in the third quarter, an increase of approximately 10 percent over the $0.88 paid in the second quarter and an increase of approximately 1921 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).~~Company. Overland Pass Pipeline Company will build a 750-mile natural gas liquids pipeline from Opal, Wyoming to the ~~mid-continent~~Mid-continent natural gas liquids market center in Conway, Kansas. The pipeline will be designed to transport approximately 110,000 ~~barrels per day~~Bbl/d of ~~natural gas liquids (NGLs),~~NGLs, which can be increased to approximately 150,000 ~~barrels per day~~Bbl/d with additional pump ~~facilities.~~facilities if customers contract for that capacity. A
subsidiary of ONEOK Partners owns 99 percent of the joint venture, will manage the construction project, will advance all costs associated with construction, and will operate the pipeline. Within two years of the pipeline becoming operational, Williams ~~will have~~has the option to increase its ownership up to 50 percent by reimbursing ONEOK Partners its proportionate share of all construction costs and, upon full exercise of that option, Williams would have the option to become ~~operator within two years of the pipeline becoming operational.~~operator. Construction of the pipeline is expected to begin in the summer of 2007, with start-up scheduled for early 2008. As part of a long-term agreement, Williams dedicated its NGL production from two
of its gas processing plants in Wyoming to the joint-venture company. Subsidiaries of ONEOK Partners will provide downstream fractionation, storage and transportation services to Williams. The pipeline project is estimated to cost approximately $433 million. ~~At the project’s inception,~~In May 2006, ONEOK Partners paid $11.4 million to Williams for reimbursement of initial capital ~~expenditures incurred.~~expenditures. In addition, ONEOK Partners plans to invest approximately $173 million to expand its existing fractionation capabilities and the capacity of its natural gas liquids distribution pipelines. ONEOK Partners’ financing for both projects may include a combination of short- or long-term debt or equity. The project requires the approval of various state and regulatory authorities.
In April 2006, we sold certain assets comprising our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. We also purchased, through ~~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~~$63.6 million ~~estimated~~ purchase price adjustment to the acquired assets related to a working capital settlement, which is reflected as ~~a reduction of~~an increase to the value of the Class B units. ~~The~~In the third quarter of 2006, the working capital settlement ~~has not been finalized; however, we do not expect~~was finalized, subject to approval by ONEOK Partners’ Audit Committee, resulting in no material adjustments.
In April 2006, in connection with the transactions described immediately above, our ONEOK Partners segment completed the sale of ~~its~~a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million. Our ONEOK Partners segment recorded a gain on sale of approximately $113.9 million in the second quarter of 2006. WeONEOK Partners and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, with an affiliate of TransCanada becoming operator of the pipeline in April 2007. ~~Following the completion of the transactions,~~ ONEOK Partners no longer consolidates Northern Border Pipeline ~~in its financial statements.~~as of January 1, 2006. 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 66²/ 2/3 percent interest in Guardian Pipeline for approximately $77 million, increasing ~~our~~its ownership interest to 100 percent. ONEOK Partners used borrowings from its credit facility to fund the acquisition of the additional interest in Guardian Pipeline. Following the completion of the transaction, we consolidated Guardian Pipeline in our consolidated financial statements. This change iswas retroactive to January 1, 2006. Prior to the transaction, ~~our~~ONEOK Partners’ 33¹/3 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)~~received FERC approval and ~~is expected to be~~the sale was completed inon October 31, 2006. The 300-megawatt gas-fired merchant power plant was built in 2001 to supply electrical power during peak periods using gas-powered turbine generators. The financial information related to the properties held for sale is reflected 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.
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~~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~~Bbl/d fractionator at Mont Belvieu, Texas; and Koch VESCO Holdings, L.L.C., an entity that owns a 10.2 percent interest in Venice Energy Services Company, L.L.C. ~~(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 3944 and discussion of our ONEOK Partners segment’s regulatory initiative beginning on page ~~44.~~49.
IMPACT OF NEW ACCOUNTING STANDARDS
In September 2006, the FASB issued Statement 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” which will require us to record a balance sheet liability equal to the difference between our benefit obligations and plan assets. If Statement 158 had been effective at December 31, 2005, we would have been required to record unrecognized losses of $124.8 million and $78.8 million for pension and postretirement benefits, respectively, on our consolidated balance sheet as accumulated other comprehensive loss. Statement 158 is effective for our year ending December 31, 2006, except for the measurement date change from September 30 to December 31 which will not go into effect until our year ending December 31, 2007.
In September 2006, the FASB issued Statement 157, “Fair Value Measurements,” which establishes a framework for measuring fair value and requires additional disclosures about fair value measurements. Statement 157 is effective for our year beginning January 1, 2008. We are currently reviewing the applicability of Statement 157 to our operations and its potential impact on our consolidated financial statements.
In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes,” which clarified the accounting for uncertainty in income taxes recognized in the financial statements in accordance with Statement 109, “Accounting for Income Taxes.” FIN 48 is effective for our year beginning January 1, 2007. We are currently reviewing the applicability of FIN 48 to our operations and its potential impact on our consolidated financial statements.
In December 2004, the ~~Financial Accounting Standards Board (FASB)~~FASB issued Statement ~~of Financial Accounting Standards No.~~ 123R, “Share-Based ~~Payment” (Statement 123R). Statement 123R~~Payment,” which requires companies to expense the fair value of share-based payments net of estimated forfeitures. We adopted Statement 123R as of January 1, 2006, and elected to use the modified prospective method. Statement 123R did not have a material impact on our financial statements as we have been expensing share-based payments since our adoption of Statement ~~of Financial Accounting Standards No.~~ 148, “Accounting for Stock-Based ~~Compensation -~~ Compensation—Transition and ~~Disclosure” (Statement 148)~~Disclosure,” on January 1, 2003. Awards granted after the adoption of Statement 123R are expensed under the requirements of Statement 123R, while equity awards granted prior to the adoption of Statement 123R will continue to be expensed under Statement 148. We recognized other income of $1.7 million upon adoption of Statement 123R. As of ~~June~~September 30, 2006, there was ~~$4.5~~$4.0 million of total unrecognized compensation cost related to our nonvested restricted stock awards, which is expected to be recognized over a weighted-average period of ~~1.5~~1.2 years. There was ~~$14.0~~$14.1 million of unrecognized compensation cost related to our performance unit awards as of ~~June~~September 30, 2006, which is expected to be recognized over a weighted-average period of ~~1.8~~1.5 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 Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights” (EITF 04-5), which presumes that a general partner controls a limited partnership and therefore should consolidate the partnership in the financial statements of the general partner. Effective January 1, 2006, we were required to consolidate ONEOK Partners’ operations in our consolidated financial statements, and we elected to use the prospective method. Accordingly, prior period financial statements have not been restated. The adoption of EITF 04-5 did not have an impact on our net income; however, reported revenues, costs and expenses reflect the operating results of ONEOK Partners. Additionally, we record a minority interest liability in our consolidated balance sheet to recognize the 54.3 percent of ONEOK Partners that we do not own. We reflect our 45.7 percent share of ONEOK Partners’ accumulated other comprehensive income at September 30, 2006, in our consolidated accumulated other comprehensive income. The remaining 54.3 percent is reflected as an adjustment to minority interests in consolidated subsidiaries.
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.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions which cannot be known with certainty that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from our 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.~~Activities.”
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 5461 for amounts in our portfolio at ~~June~~September 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~~swap 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 induring 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 induring 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).~~Assets.” In the third quarter of 2006, we changed our annual goodwill impairment testing date to July 1. See Note E to our Consolidated Financial Statements in our Quarterly Report on Form 10-Q for additional discussion. An initial assessment is made by comparing the fair value of the operations with goodwill, as determined in accordance with Statement 142, to the book value of each reporting unit. If the fair value is less than the book value, an impairment is indicated, and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the operations with goodwill from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill, we will record an impairment charge. At ~~June~~September 30, 2006, we had $572.8 million of goodwill recorded on our consolidated balance sheet as shown below.

   (Thousands of dollars)
Distribution
   $ 157,953
Energy Services
   10,255
ONEOK Partners
   403,481
Other
   1,099

Total goodwill
   $ 572,788

(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).~~Assets.” A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.
~~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.~~page 50. 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.
Intangibles - Intangibles are also accounted for in accordance with Statement 142. Intangibles with a finite useful life are amortized over their estimated useful life, while intangibles with an indefinite useful life are not amortized. All intangibles are subject to impairment testing.
Pension and Postretirement Employee Benefits - We have a defined benefit pension plan 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~~$21.6 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 the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal exposures and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with Statement ~~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~~Additional information about our critical accounting estimates is included under Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies and Estimates,” in our ~~accounting policies, see Note A of Notes to the Consolidated Financial Statements in this Quarterly~~Annual Report on Form ~~10-Q.~~10-K for the year ended December 31, 2005.
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,

Three Months Ended
September 30,

Nine Months Ended
September 30,

Financial Results
   2006 2005 2006 2005    2006 2005 2006 2005
   (Thousands of dollars)    (Thousands of dollars)
Operating revenues, excluding energy trading revenues
   $ 2,427,795 $ 2,089,574 $ 6,176,064 $ 4,787,422    $ 2,649,312 $ 3,181,592 $ 8,825,377 $ 7,969,014
Energy trading revenues, net
   4,112 (8,784 ) 11,482 408    (8,435 ) 10,615 3,047 11,023
Cost of sales and fuel
   2,030,258 1,850,812 5,281,367 4,187,456    2,291,891 2,862,888 7,579,939 7,050,344

Net margin
   401,649 229,978 906,179 600,374    348,986 329,319 1,248,485 929,693
Operating costs
   180,074 134,123 359,206 274,924    173,983 171,122 526,508 446,046
Depreciation, depletion and amortization
   67,094 43,673 123,420 86,889    55,468 48,131 178,889 135,020
Gain on sale of assets
   114,904 —   115,892 —      - - 115,892 -

Operating income
   $ 269,385 $ 52,182 $ 539,445 $ 238,561    $ 119,535 $ 110,066 $ 658,980 $ 348,627

Equity earnings from investments
   $ 22,788 $ 2,822 $ 72,750 $ 8,472
Other income
   $ 26,266 $ 3,938 $ 63,279 $ 9,236    $ 8,418 $ 4,428 $ 21,735 $ 8,014
Other expense
   $ 5,898 $ 3,939 $ 11,734 $ 4,722    $ 861 $ 3,365 $ 12,595 $ 8,087
Minority interest in income of consolidated subsidiaries
   $ 100,567 $ —   $ 136,339 $ —
Minority interests in income of consolidated subsidiaries
   $ 48,281 $ - $ 184,620 $ -

Discontinued operations, net of taxes:

Income (loss) from operations of discontinued components, net of tax
   $ (150 ) $ 7,778 $ (397 ) $ 13,664    $ (13 ) $ (19,582 ) $ (410 ) $ (5,918 )

Gain on sale of discontinued component, net of tax
   $ - $ 151,355 $ - $ 151,355

Operating Results - Net margin increased for the three ~~and six~~ months ended ~~June~~September 30, 2006, compared with the same ~~periods~~period 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~~strong commodity prices, ~~wider~~higher gross processing spreads and increased natural gas transportation revenue in our ONEOK Partners segment, partially offset by
lower storage and marketing margins in our Energy Services segment.
Net margin increased for the nine months ended September 30, 2006, compared with the same period in 2005 primarily due to:
the consolidation of ~~Guardian Pipeline~~our investment in ONEOK Partners as required by EITF 04-5,
the effect of the natural gas liquids assets acquired from Koch in July 2005 in our ONEOK Partners segment,
~~an increase in optimization activities~~strong commodity prices, higher gross processing spreads and ~~demand fees~~increased natural gas transportation revenue in our ~~Energy Services~~ONEOK Partners segment, and
~~the effect of increased~~improved natural gas basis differentials on transportation contracts in our Energy Services segment.
These increases in net margin were slightly offset by a decrease in our ONEOK Partners segment 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-month period primarily due to the consolidation of our investment in ONEOK Partners, as required by EITF 04-5, which was partially offset by decreased employee benefit costs and bad debt expense for our Distribution segment and decreased employee benefit costs and litigation expenses for our Energy Services segment.
Consolidated operating costs for the nine-month period increased due to the consolidation of our investment in ONEOK Partners, as required by EITF 04-5, and the additional six months of costs for the natural gas liquids assets acquired from Koch in July 2005.
Depreciation, depletion and amortization increased for the three- and ~~six-month~~nine-month periods primarily due to the consolidation of our investment in ONEOK Partners, as required by EITF ~~04-5,~~04-5. Additionally, the ~~costs related to the natural gas liquids assets acquired from Koch, the costs related to Guardian Pipeline and~~nine-month period also 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 in July 2005 and 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 expiredrecorded in the second quarter of ~~2005.~~2006.
The gain on sale of assets included in operating income is primarily due to $113.9 million related to ONEOK Partners’ sale of ~~its~~a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines in April 2006. For additional information, see discussion on page ~~32.~~35.
Minority interest expense ~~primarily~~ relates to the portion of ONEOK Partners that we did not own during the three and ~~six~~nine months ended ~~June~~September 30, 2006.
The following tables show the components of other income and other expense for the three and ~~six~~nine months ended ~~June~~September 30, 2006 and 2005.

   Three Months Ended
June 30,    Six Months Ended
June 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
   2006    2005    2006    2005    2006    2005    2006    2005
   (Thousands of dollars)    (Thousands of dollars)
Equity income
   $ 18,075    $ 2,833    $ 49,954    $ 5,649
Interest income
   5,374    275    6,243    704    $ 7,766    $ 303    $ 14,146    $ 1,008
Other
   2,817    830    7,082    2,883    652    4,125    7,589    7,006

Other Income
   $ 26,266    $ 3,938    $ 63,279    $ 9,236    $ 8,418    $ 4,428    $ 21,735    $ 8,014

   Three Months Ended
June 30,    Six Months Ended
June 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
   2006    2005    2006    2005    2006    2005    2006    2005
   (Thousands of dollars)    (Thousands of dollars)
Acquisition expense
   $ 4,995    $ 163    $ 9,560    $ 297    $ 119    $ 32    $ 9,679    $ 328
Litigation expense and claims, net
   —      2,250    —      2,250    -    1,878    -    4,128
Donations and civic
   565    250    897    542    392    771    1,289    1,798
Other
   338    1,276    1,277    1,633    350    684    1,627    1,833

Other Expense
   $ 5,898    $ 3,939    $ 11,734    $ 4,722    $ 861    $ 3,365    $ 12,595    $ 8,087

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,
   Three Months Ended
September 30, Nine Months Ended
September 30,
Financial Results
   2006 2005 2006    2005    2006 2005 2006    2005
   (Thousands of dollars)    (Thousands of dollars)
Gas sales
   $ 290,550 $ 313,689 $ 1,041,322    $ 1,055,994    $ 226,149 $ 289,766 $ 1,267,471    $ 1,345,760
Transportation revenues
   18,834 19,156 45,187    47,528    19,275 20,059 64,462    67,587
Cost of gas
   197,478 233,302 789,280    810,212    145,319 210,917 934,599    1,021,129

Gross margin
   111,906 99,543 297,229    293,310    100,105 98,908 397,334    392,218
Other revenues
   7,725 6,949 17,843    14,402    6,837 6,196 24,680    20,598

Net margin
   119,631 106,492 315,072    307,712    106,942 105,104 422,014    412,816
Operating costs
   91,524 83,477 182,037    174,105    88,821 91,596 270,858    265,701
Depreciation, depletion and amortization
   27,161 30,014 55,314    60,003    27,307 26,298 82,621    86,301

Operating income (loss)
   $ 946 $ (6,999 ) $ 77,721    $ 73,604    $ (9,186 ) $ (12,790 ) $ 68,535    $ 60,814

Other income (expense), net
   $ (470 ) $ (119 ) $ 633    $ (312 )    $ 735 $ (331 ) $ 1,368    $ (643 )

Operating Results - Net margin increased by ~~$13.1~~$1.8 million for the three months ended ~~June~~September 30, 2006, compared with the same period in 2005, primarily due to:
an increase of ~~$15.4~~$5.6 million primarily due to the implementation of new rate schedules in Oklahoma, ~~and~~
a decrease of ~~$3.1~~$2.2 million due to expiring riders and lower volumetric rider collections in Oklahoma, and
a decrease of $1.5 million due to reduced transport margins in Oklahoma.
Net margin increased by ~~$7.4~~$9.2 million for the ~~six~~nine months ended ~~June~~September 30, 2006, compared with the same period in 2005, primarily due to:
an increase of ~~$30.3~~$39.4 million primarily due to the implementation of new rate schedules in Oklahoma,
a decrease of ~~$15.8~~$18.0 million primarily due to expiring riders and lower volumetric rider collections in Oklahoma, and
a decrease of ~~$9.0~~$12.9 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.~~territory.
The impact of warmer than normal weather induring the ~~six-month~~nine-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~~and provides more consistent earnings and cash ~~flow over time.~~flow.
Operating costs ~~increased $8.0~~decreased $2.8 million for the three-month period primarily due to ~~an increase~~a decrease in labor and employee benefit costs of ~~$7.8~~$2.0 million. The ~~$7.9~~$5.2 million increase for the ~~six-month~~nine-month period was primarily due to an increase of ~~$9.9~~$7.8 million in labor and employee benefit costs, which ~~was~~were partially offset by a ~~$2.7~~$2.1 million decrease in bad debt expense.
Depreciation, depletion and amortization ~~decreased $2.9 million and $4.7~~increased $1.0 million for the three ~~and six~~ months ended ~~June~~September 30, 2006, ~~respectively,~~ due to additional amortization expense in 2006 from our Oklahoma rate case and depreciation expense associated with additional plant and equipment in Oklahoma, Kansas and Texas.
Depreciation, depletion and amortization decreased $3.7 million for the nine months ended September 30, 2006, compared with the same period in 2005, primarily due to:
a decrease of $2.9 million ~~charge in the first quarter of 2005~~ related to the replacement of our field customer service system in Texas ~~and due to $2.0~~during the first quarter of 2005,
a decrease of $1.8 million in cathodic protection and service line amortization in Oklahoma from a limited issue rider which expired in the second quarter of ~~2005.~~2005, and
an increase of $1.0 million due to additional amortization expense from our Oklahoma rate case and depreciation expenses associated with additional plant and equipment in Oklahoma, Kansas and Texas.
Selected Operating Data - The following tables set forth certain operating information for our Distribution segment for the periods indicated.


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


Three Months Ended
September 30,
Nine Months Ended
September 30,
Operating Information
   2006    2005    2006    2005
Average number of customers
   2,007,720    1,993,496    2,030,005    2,019,294
Customers per employee
   706    683    709    686
Capital expenditures (Thousands of dollars)
   $ 37,154    $ 39,069    $ 114,846    $ 103,078

Three Months Ended
September 30,
Nine Months Ended
September 30,
Margin
   2006    2005    2006    2005
Gas sales
   (Thousands of dollars)
Residential
   $ 66,429    $ 65,275    $ 271,644    $ 258,655
Commercial
   14,174    13,730    62,140    65,925
Industrial
   503    496    2,111    2,085
Wholesale
   1,449    2,284    4,262    5,480
Public Authority
   416    269    1,695    1,830
Gross margin on gas sales
   82,971    82,054    341,852    333,975
Transportation
   17,134    16,854    55,482    58,243
Gross margin
   $ 100,105    $ 98,908    $ 397,334    $ 392,218

   Three Months Ended
June 30,    Six Months Ended
June 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
Volumes(MMcf)
   2006    2005    2006    2005    2006    2005    2006    2005
Gas sales

Residential
   12,506    14,502    64,929    73,047    7,953    8,266    72,882    81,313
Commercial
   4,087    5,238    19,394    23,317    3,767    3,603    23,161    26,920
Industrial
   384    419    964    1,201    79    706    1,043    1,906
Wholesale
   11,567    9,584    16,507    16,456    7,394    12,204    23,901    28,660
Public Authority
   281    323    1,168    1,288    266    279    1,434    1,567

Total volumes sold
   28,825    30,066    102,962    115,309    19,459    25,058    122,421    140,366
Transportation
   46,553    58,419    103,512    127,590    46,506    57,107    150,018    184,698

Total volumes delivered
   75,378    88,485    206,474    242,899    65,965    82,165    272,439    325,064

Residential and commercial volumes decreased for the ~~three- and six-month periods~~nine-month period 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~~decreased for the three and nine months ended ~~June~~September 30, 2006, ~~as fewer~~due to reduced volumes ~~were required to meet customers’ demands, resulting in additional volume being~~ available for ~~sale to other parties.~~sale.
Public authority natural gas volumes reflect volumes used by state and local agencies and school districts ~~serviced~~served by Texas Gas Service.
Capital Expenditures - Our capital expenditure program includes expenditures for extending service to new areas, modifying customer service lines, increasing system capabilities, general replacements and improvements. It is our practice to maintain and periodically upgrade facilities to assure safe, reliable and efficient operations. Our capital expenditure program included ~~$11.3~~$13.7 million and ~~$10.4~~$12.3 million for new business development for the three months ended ~~June~~September 30, 2006, and 2005, respectively, and ~~$24.8~~$38.4 and ~~$19.8~~$32.2 million for new business development for the ~~six~~nine months ended ~~June~~September 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 - OnIn May ~~15,~~ 2006, Kansas Gas Service announced that it filed a request with the ~~Kansas Corporation Commission (KCC)~~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. In October 2006, Kansas Gas Service reached a settlement with the KCC staff and all other involved parties to increase annual revenues by approximately $52 million. The terms of the settlement are subject to the approval of the KCC and hearings on the settlement are scheduled to be held on November 6, 2006.
Texas - Texas Gas Service has received several regulatory approvals to implement rate increases in various municipalities in Texas. A total of ~~$4.7~~$5.5 million in ~~revenue increases have~~annual rate relief has been ~~agreed upon or~~ approved ~~in 2006~~ and ~~we expect the new rates to be fully~~ implemented ~~by mid-August~~in 2006.
~~Union~~Bargaining Unit - ~~The~~On October 25, 2006, a four-year labor contract ~~with~~was ratified between Kansas Gas Service and the International Brotherhood of Electrical ~~Workers (IBEW) expired June 30, 2006. Negotiations are ongoing.~~Workers.
General - Certain costs to be recovered through the ratemaking process have been recorded as regulatory assets in accordance with Statement ~~71.~~71, “Accounting for the Effects of Certain Types of Regulation.” Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria of Statement 71 and, accordingly, a write-off of regulatory assets and stranded costs may be required.
Energy Services
Overview - Our Energy Services segment’s primary focus is to create value for our customers by delivering physical natural gas products and risk management services through our network of contracted transportation and storage capacity and natural gas supply. These services include meeting our customers’ baseload, swing and peaking natural gas commodity requirements on a year-round basis. To provide these bundled services, we lease storage and transportation capacity. Our total storage capacity under lease 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~~1.7 Bcf per day. ~~The~~Our 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~~September 2006, ~~our~~we announced that we entered into a 20-year fixed-price purchase contract with Power Holdings of Illinois LLC (Power Holdings) for 45,000 MMBtu per day of pipeline-quality synthetic natural gas (SNG). Power Holdings will begin construction on a coal gasification facility next year in southern Illinois, which is expected to be completed by 2011. The facility will utilize environmentally beneficial gasification technology converting coal into SNG. The coal gasification facility will deliver SNG volumes to Natural Gas Pipeline Company of America (NGPL). Our Energy Services segment ~~was selected to provide subsidiaries of FirstEnergy Corporation (FirstEnergy) with natural gas supply and natural gas management services~~contracts 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,~~services on NGPL, which transports natural gas into the Mid-continent, Gulf Coast and ~~be responsible for optimizing the delivered cost of the gas to FirstEnergy.~~Chicago markets.
Our Energy Services segment ~~which consists of wholly owned subsidiaries,~~ regularly ~~provides services to~~conducts business with ONEOK Partners, 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.
We manage our contracted transportation and storage capacity by utilizing derivative instruments such as over-the-counter forward, swap and option contracts and NYMEX futures and option contracts. We apply a combination of cash-flow and fair-value hedge accounting when implementing hedging strategies that take advantage of existing market conditions (see Note D of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q for additional information). Additionally, certain hedging activity will not qualify for hedge or accrual accounting treatment; therefore, these non-trading transactions are
economic hedges of our accrual transactions. These economic hedges receive mark-to-market accounting treatment as they are derivative contracts and are not designated as part of a hedge relationship.
Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for our Energy Services segment for the periods indicated. In the third quarter of 2005, we made the decision to sell our Spring Creek power plant, located in central Oklahoma, and exit the power generation business. The sale was completed on October 31, 2006. These assets were held for sale at ~~June~~September 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.~~50.

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

Three Months Ended
September 30,

Nine Months Ended
September 30,

Financial Results
   2006 2005 2006 2005    2006 2005 (a) 2006 2005 (a)
   (Thousands of dollars)    (Thousands of dollars)
Energy and power revenues
   $ 1,190,666 $ 1,554,534 $ 3,406,333 $ 3,296,592    $ 1,402,693 $ 2,006,878 $ 4,809,026 $ 5,303,470
Energy trading revenues, net
   4,112 (8,784 ) 11,482 408    (8,435 ) 10,615 3,047 11,023
Other revenues
   1 196 116 402    1 243 117 645
Cost of sales and fuel
   1,130,452 1,534,698 3,250,450 3,224,959    1,363,534 1,962,696 4,613,984 5,187,655

Net margin
   64,327 11,248 167,481 72,443    30,725 55,040 198,206 127,483
Operating costs
   10,304 7,783 19,564 15,826    8,637 12,451 28,201 28,277
Depreciation, depletion and amortization
   529 569 1,104 970    524 533 1,628 1,503

Operating income
   $ 53,494 $ 2,896 $ 146,813 $ 55,647    $ 21,564 $ 42,056 $ 168,377 $ 97,703

Other income (expense), net
   $ (3,674 ) $ (1,966 ) $ (6,616 ) $ (3,855 )    $ (3,475 ) $ (1,503 ) $ (10,091 ) $ (5,358 )

(a) Restated, see paragraph below for additional information.
   Three Months Ended
June 30,    Six Months Ended
June 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
Operating Information
   2006    2005    2006    2005    2006    2005    2006    2005
Natural gas marketed(Bcf)
   254    275    564    600    275    279    839    879
Natural gas gross margin($/Mcf)
   $ 0.25    $ 0.02    $ 0.26    $ 0.09    $ 0.11    $ 0.21    $ 0.21    $ 0.13
Physically settled volumes (Bcf)
   536    574    1,138    1,199    564    560    1,702    1,759
Capital expenditures(Thousands of dollars)
   $ —      $ 132    $ —      $ 159    $ -    $ -    $ -    $ 159
During preparation of our 2005 Annual Report on Form 10-K, we identified and disclosed a software system error impacting our accounting for hedging instruments, and subsequently restated our third quarter 2005 results to reflect an increase in cost of sales and fuel of $13.2 million. It was determined that no other prior periods were affected. As such, the financial results for our Energy Services segment have been restated for the three and nine months ended September 30, 2005. For further information, refer to Part II, Item 9A, “Controls and Procedures,” in our Annual Report on Form 10-K for the year ended December 31, 2005.
Operating Results - Net margin ~~increased~~decreased by ~~$53.1~~$24.3 million for the three months ended ~~June~~September 30, 2006, compared with the same period in 2005, primarily due to:
~~an increase~~a decrease of ~~$21.9~~$34.5 million related to storage and marketing margins primarily due to:
      o a decrease of $20.9 million related to reduced physical storage margins due to weather related events in 2005 that caused higher natural gas price volatility compared with 2006,
      o a decrease of $8.5 million related to reduced marketing optimization efforts due to more favorable natural gas price movement in 2005 compared to 2006, and
      o a decrease of $5.1 million related to power margins associated with a tolling transaction that expired December 31, 2005,
a decrease of $10.2 million in our financial trading margins primarily due to ~~optimization activities~~positions in the natural gas option portfolio that benefited from ~~a favorably priced supply position,~~increased natural gas prices and higher volatility in 2005, as compared to 2006,
an increase of $19.2 million related to the mark-to-market gains and losses on unqualified hedges of transportation and storage contracts, which resulted from $6.6 million in gains for the third quarter of 2006 compared with $12.6 million in losses for the same period in 2005, and
an increase of $1.6 million in physical transportation margins, net of hedging activities.
Net margin increased $70.7 million for the nine months ended September 30, 2006, compared with the same period in 2005, primarily due to:
an increase of ~~$16.8~~$41.3 million in physical transportation margins, net of hedging activities, primarily due to improved natural gas basis differentials between the ~~mid-continent~~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~~$7.2 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~~$4.8 million related to storage and marketing margins primarily due to:
      o an increase of $10.5 million in physical storage and marketing margins primarily due to storage optimization activities in the second quarter of 2006, partially offset by
      o a decrease of $5.7 million related to power margins associated with a tolling transaction that expired December 31, 2005,
an increase of $16.6 million related to the mark-to-market gains and losses on unqualified hedges of transportation and storage contracts, which resulted from $4.9 million in gains for the nine-month period in 2006 compared with $11.7 million in losses for the same period in 2005, and
an increase of $1.4 million in retail activities due to improved physical margins.
Operating costs ~~increased $2.5 million and $3.7~~decreased $3.8 million for the three ~~and six~~ months ended ~~June~~September 30, 2006, ~~respectively, primarily~~ due to decreased litigation expenses of $2.2 million, decreased employee-related costs of $1.1 million and decreased bad debt expenses of $0.5 million.
Operating costs decreased $0.1 million for the nine months ended September 30, 2006, due to decreased litigation expenses of $3.0 million, offset primarily by increased employee-related ~~costs.~~costs of $1.7 million and increased letter of credit fees of $0.5 million.
Natural gas volumes marketed decreased for the three- and ~~six-month~~nine-month periods in 2006 compared with 2005, primarily due to higher storage injections in the second ~~quarter~~and third quarters of 2006 and warmer weather in the majority of our service territory in the first quarter of 2006, resulting in decreased ~~storage withdrawals.~~sales from storage.
Our natural gas in storage at ~~June~~September 30, 2006, was ~~73.3~~80.2 Bcf compared with ~~59.0~~60.4 Bcf at ~~June~~September 30, 2005. At ~~June~~September 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” (EITF 02-3) are used to determine the proper accounting treatment. These activities and all financially settled derivative contracts are reported on a net basis.
For derivative instruments that are not considered “held for trading purposes” and result in physical delivery, the indicators in EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and ~~Not~~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 accounting 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.
The following table shows our margins by activity for the periods indicated.

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

Nine Months Ended
September 30,

   2006 2005 2006 2005    2006 2005 2006 2005
   (Thousands of dollars)    (Thousands of dollars)
Marketing and storage, gross
   $ 95,637 $ 52,952 $ 230,705 $ 144,439    $ 72,303 $ 83,447 $ 303,008 $ 227,886
Less: Storage and transportation costs
   (44,282 ) (40,074 ) (93,541 ) (83,376 )    (43,088 ) (40,263 ) (136,629 ) (123,639 )

Marketing and storage, net
   51,355 12,878 137,164 61,063    29,215 43,184 166,379 104,247
Retail marketing
   4,310 3,047 9,759 8,257    3,442 3,535 13,201 11,792
Financial trading
   8,662 (4,677 ) 20,558 3,123    (1,932 ) 8,321 18,626 11,444

Net margin
   $ 64,327 $ 11,248 $ 167,481 $ 72,443    $ 30,725 $ 55,040 $ 198,206 $ 127,483

Marketing and storage activities, net, primarily include physical marketing, purchases and sales, firm storage and transportation capacity expense, including the impact of cash flow and fair value hedges, and other derivative instruments used to manage our risk associated with these activities. The combination of owning supply, controlling strategic assets and risk management services allows us to provide commodity-diverse products and services to our customers such as peaking and load following services.
Retail marketing includes revenues from providing physical marketing and supply services coupled with risk management services to residential and small commercial and industrial customers.
Financial trading ~~revenues include~~margin includes activities that are generally executed using financially settled derivatives. These activities are normally short-term in nature, with a focus of capturing short-term price volatility. Energy trading revenues, net, in our consolidated income ~~statement~~statements includes financial trading margins as well as certain physical natural gas transactions with our trading ~~counterparties and financial trading margins.~~counterparties. Revenues and cost of sales and fuel from such physical transactions are required to be reported on a net basis.
ONEOK Partners
Overview - ~~Our~~Effective January 1, 2006, we were required to consolidate ONEOK Partners’ operations in our consolidated financial statements under EITF 04-5, and we elected to use the prospective method, which results in our consolidated financial results and operating information including only 2006 data for the legacy ONEOK Partners operations. In April 2006, we sold certain assets comprising our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. These former segments are now included in our ONEOK Partners segment ~~gathers, processes, transports~~ and ~~stores natural gas; gathers, treats, stores and fractionates NGLs and provides NGL gathering and distribution services.~~all periods presented have been restated to reflect this change. We own 45.7 percent of ONEOK Partners; the remaining interest in ONEOK Partners is reflected as minority interest in income of consolidated subsidiaries on our Consolidated Statements of Income.
We gather and process natural gas and fractionate NGLs primarily in the Mid-continent and Rocky Mountain regions. Our operations include the gathering of natural gas production from crude oil and natural gas wells. Through gathering systems, these volumes are aggregated and treated or processed to remove water vapor, solids and other contaminants and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. When the liquids are separated from the raw natural gas at the processing plants, the liquids are generally in the form of a mixed NGL stream.
We also gather, store, fractionate and treat mixed NGLs, and store NGL purity products produced from gas processing plants located in Oklahoma, Kansas and the Texas panhandle. WeOur NGL assets connect the NGL production basins in Oklahoma, Kansas and the Texas panhandle with the key NGL market centers in Conway, Kansas and Mont Belvieu, Texas.
Most natural gas produced at the wellhead contains a mixture of NGL components such as ethane, propane, iso-butane, normal butane and natural gasoline. Natural gas processing plants remove the NGLs from the natural gas stream to realize the higher economic value of the NGLs and to meet natural gas pipeline quality specifications, which limit NGL content in the natural gas stream due to liquid and Btu content. The NGLs that are separated from the natural gas stream at the natural gas processing plants remain in a mixed, raw form until they are gathered, primarily by pipeline, and delivered to our fractionators. A fractionator, by applying heat and pressure, separates each NGL component into marketable NGL purity products, such as ethane/propane mix, propane, iso-butane, normal butane and natural gasoline (collectively NGL purity products). These NGL purity products can then be stored or distributed to petrochemical, heating and motor gasoline manufacturers.
We operate intrastate and FERC-regulated interstate natural gas transmission pipelines, natural gas storage and FERC-regulated natural gas liquids gathering and distribution pipelines and nonprocessable natural gas gathering facilities. We also provide interstate natural gas transportation service under Section 311(a) of the Natural Gas Policy Act.
Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for our ONEOK Partners segment for the periods indicated.

   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.~~

Three Months Ended
September 30,

Nine Months Ended
September 30,

Financial Results    2006    2005 2006    2005
   (Thousands of dollars)
Revenues
   $ 1,214,583    $ 1,408,956 $ 3,543,763    $ 2,305,697
Cost of sales and fuel
   1,003,901    1,240,222 2,919,620    1,914,178
Net margin
   210,682    168,734 624,143    391,519
Operating costs
   75,529    66,785 224,650    155,483
Depreciation, depletion and amortization
   27,516    21,175 94,269    46,867
Gain on sale of assets
   -    - 114,865    -
Operating income
   $ 107,637    $ 80,774 $ 420,089    $ 189,169

Equity earnings from investments
   $ 22,788    $ (39 ) $ 72,750    $ 597
Other income (expense), net
   $ 884    $ (385 ) $ 9    $ (1,283 )
Minority interests in income of
    consolidated subsidiaries
   $ 134    $ - $ 2,272    $ -


Three Months Ended
September 30,

Nine Months Ended
September 30,

Operating Information    2006    2005 2006    2005
Total gas gathered(BBtu/d)
   1,202    1,093 1,165    1,111
Total gas processed(BBtu/d)
   1,017    1,141 980    1,139
Natural gas liquids gathered(MBbl/d)
   208    193 205              (a)
Natural gas liquids sales(MBbl/d)
   210    201 211    129
Natural gas liquids fractionated(MBbl/d)
   326    309 315              (a)
Natural gas liquids transported(MBbl/d)
   199              (a) 200              (a)
Natural gas transported(MMcf/d)
   2,094    1,288 2,241    1,314
Natural gas sales(BBtu/d)
   353    341 318    345
Capital expenditures(Thousands of dollars)
   $ 61,213    $ 8,949 $ 114,788    $ 39,390
Realized composite NGL sales prices($/gallon)
   $ 1.02    $ 0.90 $ 0.95    $ 0.78
Realized condensate sales price($/Bbl)
   $ 51.79    $ 46.18 $ 56.75    $ 44.72
Realized natural gas sales price($/MMBtu)
   $ 5.68    $ 7.35 $ 6.48    $ 6.54
Realized gross processing spread ($/MMBtu)
   $ 6.34    $ 3.65 $ 5.27    $ 2.97
    (a) - The acquisition of these assets was completed July 1, 2005.
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 3337 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~~$41.9 million for the ~~three- and six-month periods~~three months ended ~~June~~September 30, 2006, ~~respectively,~~ primarily due to:
an increase of ~~$44.1~~$49.5 million ~~and $91.5 million, respectively,~~ from the legacy ONEOK Partners operations, which were consolidated beginning January 1, 2006,
an increase of ~~$59.4~~$19.7 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~~strong commodity prices, ~~wider~~higher 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~~$25.2 million ~~and $39.7 million, respectively,~~ resulting from the sale of natural gas gathering and processing assets located in Texas in December 2005.
Net margin increased by $232.6 million for the nine months ended September 30, 2006, primarily due to:
an increase of $152.6 million from the legacy ONEOK Partners operations, which were consolidated beginning January 1, 2006,
an increase of $101.8 million related to net margins on natural gas liquids gathering and distribution pipelines acquired from Koch in July 2005,
an increase of $48.1 million from our legacy operations driven primarily by strong commodity prices, higher gross processing spreads and increased natural gas transportation revenues, and
a decrease of $64.9 million resulting from the sale of natural gas gathering and processing assets located in Texas in December 2005.
The increase in operating costs of ~~$32.3~~$8.7 million ~~and $67.1 million, respectively,~~ for the ~~three- and six-month periods,~~three-month period, 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~~operating costs of ~~$26.3 million and $41.1~~$69.2 million for the ~~three- and six-month periods, respectively,~~nine-month period is primarily related to the consolidation of the legacy ONEOK Partners operations and the ~~acquisition of~~ natural gas liquids assets acquired in 2005, offset by the ~~Black Mesa Pipeline impairment~~sale of the Texas natural gas gathering and processing assets in December 2005.
Depreciation, depletion and amortization increased by $6.3 million for the three-month period which is primarily related to the consolidation of ~~Guardian Pipeline beginning January 1, 2006,~~the legacy ONEOK Partners operations, offset by the December 2005 sale of natural gas gathering and processing assets located in ~~Texas in December 2005.~~Texas.
The increase in ~~other income (expense), net~~depreciation, depletion and amortization of ~~$16.6~~$47.4 million for the nine-month period is primarily due to the consolidation of the legacy ONEOK Partners operations, the Black Mesa Pipeline impairment, the acquisition of natural gas liquids assets in 2005, and an offsetting decrease from the December 2005 sale of natural gas gathering and processing assets located in Texas.
The increase in equity earnings from investments of $22.8 million and ~~$49.3~~$72.2 million for the three- and ~~six-month~~nine-month periods, respectively, 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~~primarily designated as cash flow hedges, to minimize earnings volatility related to natural gas and natural gas liquids price fluctuations. The realized financial impact of the derivative transactions is included in our operating income in the period that the physical transaction occurs. The following table sets forth our hedging information for the remainder of 2006 and all of 2007 for our ONEOK Partners segment.


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.~~
   Year Ending
December 31, 2006
Year Ending
December 31, 2007
Product    Volumes
Hedged    Average Price Per Unit    Volumes
Hedged    Average
Price Per Unit
Percent-of-proceeds
   ��
Condensate(Bbl/d)(a)
   815    $52.00 -  $60.00    -    -
Natural gas liquids(Bbl/d)(b)
   5,752    $42.11    -    -
Natural gas(MMBtu/d)(a)
   5,217    $6.15 - $11.00    -    -
Natural gas(MMBtu/d)(b)
   16,461    $6.50    -    -
Keep-whole

Gross processing spread(MMBtu/d)(b)
   20,788    $4.60    6,410    $3.06
(a) Hedged with option collars
(b) Hedged with fixed-price swaps

For the remainder of 2006, our ONEOK Partners segment is approximately 77 percent hedged on its projected percent-of-proceeds NGL volumes, approximately 73 percent hedged on its projected percent-of-proceeds natural gas volumes and approximately 66 percent hedged on its projected keep-whole gross processing spread.
Regulatory Initiative - Our natural gas transportation assets in Oklahoma, Kansas and Texas are regulated by the OCC, KCC and RRC, respectively. We have flexibility in establishing natural gas transportation rates with customers. However, there is a maximum rate we can charge our customers in Oklahoma and Kansas. The FERC regulates the rates and charges for
transportation on ~~our~~ONEOK Partners’ interstate natural gas and natural gas liquids 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~~Black Mesa Pipeline - On December 31, 2005, our ONEOK Partners segment’s Black Mesa ~~Pipeline was temporarily shut down due to~~Pipeline’s transportation contract with 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-ownersupplier of Mohave Generating Station ~~Black Mesa Pipeline was reimbursed for~~(Mohave) expired and its ~~standby costs.~~coal slurry pipeline operations were shut down as expected. In June 2006, SCE completed a ~~co-owner~~comprehensive study of ~~Mohave Generating Station~~the water source, coal supply and transportation issues and announced that ~~the owners~~it would no longer pursue the resumption of plant operations. ~~As a result~~SCE and the other Mohave co-owners are jointly exploring options for Mohave, including the possibility of selling the plant. Negotiations among various parties involved with Black Mesa ~~Pipeline is no longer receiving reimbursement for its standby costs. Accordingly,~~are ongoing.
During the second quarter of 2006, ONEOK Partners assessed its coal slurry pipeline operation in accordance with its accounting policies related to the goodwill and asset impairment. Its evaluation of the Black Mesa Pipeline indicated a goodwill and asset impairment of $8.4 million and $3.4 million, respectively, which were recorded as depreciation and amortization in the second quarter of 2006. The reduction to our net income, net of minority interest and income taxes, was $3.0 million.
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 Energy, Inc. for approximately $53 million. The transaction ~~requires~~received FERC approval and ~~is expected to be~~the sale was completed inon October 31, 2006. The 300-megawatt gas-fired merchant power plant was built in 2001 to supply electrical power during peak periods using gas-powered turbine generators. ~~The 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,    Three Months Ended
September 30, Nine Months Ended
September 30,
   2006 2005    2006 2005    2006 2005 2006 2005
   (Thousands of dollars)    (Thousands of dollars)
Operating revenues
   $ 3,315 $ 40,330    $ 5,164 $ 86,153    $     4,890 $ 45,917 $ 10,055 $ 131,629
Cost of sales and fuel
   2,386 6,977    3,504 23,631    3,695 11,900 7,199 35,532

Net margin
   929 33,353    1,660 62,522    1,195 34,017 2,856 96,097
Impairment expense
   - 52,226 - 52,226
Operating costs
   266 8,412    492 16,089    237 8,383 729 24,025
Depreciation, depletion and amortization
   —   8,492    —   16,772    - 1,146 - 17,919

Operating income
   663 16,449    1,168 29,661    958 (27,738 ) 2,127 1,927

Other income (expense), net
   —   5    —   (1 )    - 170 - 252
Interest expense
   904 3,910    1,808 7,622    904 3,947 2,712 11,657
Income taxes
   (91 ) 4,766    (243 ) 8,374    67 (11,933 ) (175 ) (3,560 )

Income (loss) from operations of discontinued components, net
   $ (150 ) $ 7,778    $ (397 ) $ 13,664

Income (loss) from operations of discontinued component
   $ (13 ) $ (19,582 ) $ (410 ) $ (5,918 )
Gain on sale of discontinued component, net of tax
of $90.7 million
   $ - $ 151,355 $ - $ 151,355
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~~nine months of 2006 were ~~$133~~$244 million, compared with ~~$123~~$190 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.
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.~~the general partner of ONEOK Partners, is $750 million, and an additional $10 million is authorized for Guardian Pipeline. At ~~June~~September 30, 2006, ONEOK had no commercial paper outstanding, ~~$143.5~~$88.4 million in letters of credit issued, and available cash of approximately ~~$620.5~~$191.6 million. At ~~June~~September 30, 2006, ONEOK Partners had ~~$15.0~~$15 million in letters of credit issued, ~~$311.0 million~~no borrowings 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~~$55.9 million. As of ~~June~~September 30, 2006, ONEOK could have issued ~~$2.8~~$2.4 billion of additional debt under the most restrictive provisions contained in our various borrowing agreements. As of ~~June~~September 30, 2006, ONEOK Partners could have issued, under the most restrictive provisions of its agreements, ~~$1.7~~$1.4 billion of additional debt.
~~Short-term~~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. See Note B of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q for additional information about this acquisition. We funded the remaining acquisition cost through our commercial paper program. During the three months ended March 31, 2006, we repaid the ~~remaining $900 million under our short-term bridge financing program.~~facility in full, and it was terminated according to its terms.
~~Five-year~~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~~amended agreement includes revised pricing, an extension of the maturity date from 2009 to 2011, an option for additional extensions of the maturity date with the consent of the lenders, and an option to request an increase in the commitments of the lenders of up to an additional $500 million. The interest ~~rate~~rates applicable to extensions of credit isunder this agreement are based, at our election, on either (i) the higher of prime or one-half of one percent above the Federal Funds Rate, which is the rate that banks charge each other for the overnight borrowing of funds, or (ii) the Eurodollar rate plus a set number of basis points based on our current long-term unsecured debt ratings. ~~ONEOK’s~~
Under the five-year credit agreement, ~~includes~~ ONEOK is required to comply with certain financial, operational and legal covenants. Among other things, these requirements include:
a $500 million sublimit for the issuance of standby letters of ~~credit. 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~~requirement that we maintain the power to control the management and policies of ONEOK Partners, and
a limit on new investments in master limited partnerships.
The debt covenant calculations in ONEOK’s five-year credit agreement exclude the debt of ONEOK Partners. At September 30, 2006, we had no borrowings outstanding under this agreement.
ONEOK’s five-year credit agreement also contains customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in our businesses, changes in the nature of our businesses, transactions with affiliates, the use of proceeds and a covenant that prevents us from restricting our subsidiaries’ ability to pay dividends. At September 30, 2006, ONEOK was in compliance with these covenants.
ONEOK Partners Five-Year Credit Agreement - In March 2006, ONEOK Partners entered into a five-year $750 million amended and restated revolving credit agreement (2006 Partnership Credit Agreement) with certain financial institutions and terminated its $500 million revolving credit agreement. At ~~June~~September 30, 2006, ONEOK Partners had $15 million in letters of credit outstanding and no borrowings ~~of $311.0 million~~outstanding 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.~~Agreement.
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.~~acquisitions. Upon any breach of these covenants, amounts outstanding under the 2006 Partnership Credit Agreement ~~and the Bridge Facility~~ may become immediately due and payable. At September 30, 2006, ONEOK Partners was in compliance with these covenants.
ONEOK Partners Bridge Facility - In April 2006, ONEOK Partners entered into the Bridge Facility with a syndicate of banks and borrowed $1.05 billion to finance a portion of its purchase of certain assets comprising our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments. In September 2006, ONEOK Partners repaid the amounts outstanding under the Bridge Facility using proceeds from the issuance of senior notes, which resulted in the Bridge Facility being terminated according to its terms. See “ONEOK Partners Debt Issuance” below and Note I of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q for further discussion regarding the issuance of senior notes.
ONEOK Partners Debt Issuance - In September 2006, ONEOK Partners completed an underwritten public offering of (i) $350 million aggregate principal amount of 5.90 percent Senior Notes due 2012 (the “2012 Notes”), (ii) $450 million aggregate principal amount of 6.15 percent Senior Notes due 2016 (the “2016 Notes”) and (iii) $600 million aggregate principal amount of 6.65 percent Senior Notes due 2036 (the “2036 Notes” and collectively with the 2012 Notes and the 2016 Notes, the “Notes”). ONEOK Partners registered the sale of the Notes with the SEC pursuant to a shelf registration statement filed on September 19, 2006. The Notes are guaranteed on a senior unsecured basis by the Intermediate Partnership. The guarantee ranks equally in right of payment to all of the Intermediate Partnership’s existing and future unsecured senior indebtedness.
ONEOK Partners may redeem the Notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount of the Notes, plus accrued interest, unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the relevant Notes plus accrued and unpaid interest. The Notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing unsecured senior indebtedness, and effectively junior to all of the existing debt and other liabilities of its non-guarantor subsidiaries. The Notes are non-recourse to us.
The net proceeds from the Notes of approximately $1.39 billion, after deducting underwriting discounts and commissions and expenses, but before offering expenses, were used to repay all of the amounts outstanding under the Bridge Facility and to repay $335 million of indebtedness outstanding under the 2006 Partnership Credit Agreement. The terms of the Notes are governed by the Indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., as trustee, as supplemented by the First Supplemental Indenture (with respect to the 2012 Notes), the Second Supplemental Indenture (with respect to the 2016 Notes) and the Third Supplemental Indenture (with respect to the 2036 Notes), each dated September 25, 2006. The Indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The Indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and sell and lease back its property.
The 2012 Notes, 2016 Notes and 2036 Notes will mature on April 1, 2012, October 1, 2016 and October 1, 2036, respectively. ONEOK Partners will pay interest on the Notes on April 1 and October 1 of each year. The first payment of interest on the Notes will be made on April 1, 2007. Interest on the Notes accrues from September 25, 2006, which was the issuance date of the Notes.
Guardian Pipeline Master Shelf Agreement - ONEOK Partners’ acquisition of ~~an additional~~the remaining 66²/ 2/3 percent interest in Guardian Pipeline resulted in the inclusion of ~~outstanding amounts under Guardian Pipeline’s revolving note agreement~~$148.6 million of long-term debt in our consolidated balance sheet. ~~The revolving note~~These notes were issued under a master shelf agreement ~~permits Guardian Pipeline~~with certain financial institutions. Principal payments are due annually through 2022. Interest rates on the notes range from 7.61 percent 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 at8.27 percent, with an ~~interest~~average rate of ~~6.60 percent due November 8, 2007.~~7.85 percent.
Guardian Pipeline’s ~~revolving note~~Master Shelf 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~~that require the maintenance of a ratio of (1) ~~EBITDA~~EBITDAR (net income plus interest expense, income taxes, operating lease expense and depreciation and amortization) to the sum of interest expense plus operating lease expense of not less than 1.5 to 1 and (2) total indebtedness to ~~EBITDA~~EBITDAR of not greater than 6.75 to 1. Upon any breach of these covenants, all amounts outstanding under the ~~note agreements~~master shelf agreement 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 Beginning in December 2007, the rate of total indebtedness 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’ abilityEBITDAR may not be greater than 5.75 to ~~pay dividends.~~1. At ~~June~~September 30, 2006, ~~ONEOK and ONEOK Partners were~~Guardian Pipeline was in compliance with ~~all credit agreement~~its financial 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    September 30,
2006    December 31,
2005
Long-term debt
   53 % 53 %        65%    53%
Equity
   47 % 47 %        35%

   47%


Debt (including Notes payable)
   63 % 67 %        65%    67%
Equity
   37 % 33 %        35%    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~~September 30, 2006, our capitalization structure, excluding the debt of ONEOK Partners, was 4648 percent long-term debt and 5452 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~~$63.6 million ~~estimated~~ purchase price adjustment to the acquired assets related to a working capital settlement, which is reflected as ~~a reduction of~~an increase to the value of the Class B units. ~~The~~In the third quarter of 2006, the working capital settlement ~~has not been finalized; however, we do not expect~~was finalized, subject to approval by ONEOK Partners’ Audit Committee, resulting in no material adjustments.
The sale of certain assets comprising our former Gathering and Processing, Pipelines and Storage, and Natural Gas Liquids segments did not affect our consolidated operating income on our ~~consolidated statements~~Consolidated Statements of ~~income~~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 3337 for additional discussion of EITF 04-5.
In April 2006, in connection with the transactions described immediately above, our ONEOK Partners segment completed the sale of ~~its~~a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million. Our ONEOK Partners segment recorded a gain on sale of approximately $113.9 million in the second quarter of 2006. WeONEOK Partners and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, with an affiliate of TransCanada becoming operator of the pipeline in April 2007. ~~Following completion of the transactions,~~ ONEOK Partners no longer consolidates Northern Border Pipeline ~~in its financial statements.~~as of January 1, 2006. 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~~were prorated from the date of issuance. ONEOK Partners is required to hold a special election for holders of common units ~~within 12 months,~~as soon as practical, but no later than April 2007, 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~~ONEOK Partners’ partnership agreement. The proposed amendments would grant voting rights for common units held by the general partner if a vote is held to remove the general partner and require fair market value compensation for the general partner interest if the general partner is removed. If the conversion and the amendments are approved by common ~~unit holders,~~unitholders, the Class B units will be eligible to convert into common units on a ~~one-by-one~~one-for-one basis. If the common ~~unit holders~~unitholders 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, including distributions paid upon liquidation, and the Class B ~~distribution rights would continue to~~units will no longer be ~~subordinated in the manner described above unless and until the conversion described above has been approved.~~outstanding.. If the common ~~unit holders~~unitholders vote to remove us or our affiliates as the general partner of ONEOK Partners at any time prior to the approval of the conversion and amendment described above, ~~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~~including distributions paid upon liquidation. The Class B unit distribution rights would continue to be subordinated in the manner described above unless and until the conversion described above has been approved.
In April 2006, our ONEOK Partners segment acquired the remaining 66²/ 2/3 percent interest in Guardian Pipeline for approximately $77 million, increasing ~~our~~its ownership interest to 100 percent. ONEOK Partners used borrowings from its credit facility to fund the acquisition of the additional interest in Guardian Pipeline. Following the completion of the transaction, we consolidated Guardian Pipeline in our financial statements. This change iswas retroactive to January 1, 2006. Prior to the transaction, ~~our~~ONEOK Partners’ 33¹/ 1/3 percent interest in Guardian Pipeline was accounted for as an investment under the equity method.
Capital Projects - In June 2006, ONEOK Partners signed a non-binding letter of intent to form a joint venture with Boardwalk Pipeline Partners, L.P. and Energy Transfer Partners, ~~L.P.~~LP to construct a new interstate pipeline originating in north Texas, crossing Oklahoma and Arkansas and terminating in Dyer County, Tennessee at a new interconnect with Texas Gas Transmission, L.L.C. The proposed interstate pipeline would create new pipeline capacity for constrained wellhead production in north Texas and central Oklahoma and would have initial capacity of up to 1.0 Bcf/d. In August 2006, Energy Transfer Partners, LP withdrew from the joint venture. Formation of the joint venture with Boardwalk Pipeline Partners, LP is subject to negotiation and execution of definitive agreements by the participants.
In May 2006, a subsidiary of ONEOK Partners entered into an agreement with a subsidiary of Williams to form a joint venture called Overland Pass Pipeline Company. Overland Pass Pipeline Company will build a 750-mile natural gas liquids pipeline from Opal, Wyoming to the ~~mid-continent~~Mid-continent natural gas liquids market center in Conway, Kansas. The pipeline will be designed to transport approximately 110,000 ~~barrels per day~~Bbl/d of NGLs, which can be increased to approximately 150,000 ~~barrels per day~~Bbl/d with additional pump ~~facilities.~~facilities if customers contract for that capacity. A subsidiary of ONEOK Partners owns 99 percent of the joint venture, will manage the construction project, will advance all costs associated with construction, and will operate the pipeline. Within two years of the pipeline becoming operational, Williams ~~will have~~has the option to increase its ownership up to 50 percent by reimbursing ONEOK Partners its proportionate share of all construction costs and, upon full exercise of that option, Williams would have the option to become ~~operator within two years of the pipeline becoming operational.~~operator. Construction of the pipeline is expected to begin in the summer of 2007, with start-up scheduled for early 2008. As part of a long-term agreement, Williams dedicated its NGL production from two of its gas processing plants in Wyoming to the joint-venture company. Subsidiaries of ONEOK Partners will provide downstream fractionation, storage and transportation services to Williams. The pipeline project is estimated to cost approximately $433 million. ~~At the project’s inception,~~In May 2006, ONEOK Partners paid $11.4 million to Williams for reimbursement of initial capital ~~expenditures incurred.~~expenditures. In addition, ONEOK Partners plans to invest approximately $173 million to expand its existing fractionation capabilities and the capacity of its natural gas liquids distribution pipelines. ONEOK Partners’ financing for both projects may include a combination of short- or long-term debt or equity. The project requires the approval of various state and regulatory authorities.
~~In February~~On October 13, 2006, Guardian Pipeline ~~announced that it signed precedent agreements~~filed its application for a certificate of public convenience and necessity with the FERC for authorization to construct and operate approximately 110 miles of new pipeline, two ~~major~~compressor stations, seven meter stations and other associated facilities. The pipeline expansion will extend Guardian Pipeline from the Milwaukee, 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, Wisconsinarea to the Green Bay, ~~area, adding approximately 537 MMcf/d~~Wisconsin area. The project is supported by long-term shipper commitments. The cost of ~~capacity. Guardian Pipeline’s capital costs for~~ the project ~~are~~is estimated to ~~range between $220~~be $260 million ~~and $240 million. Pending all necessary approvals, the target~~with a targeted in-service date isof November 2008.
Additionally, ONEOK Partners has ~~$25~~$28 million in long-term capital project obligations related to their construction of the Midwestern Gas Transmission Eastern Extension Project which will add 31 miles of natural gas pipeline with approximately 120 MMcf/d of transportation capacity. The proposed in-service date ~~of November 2006 will likely be delayed.~~is early 2007. Midwestern Gas Transmission is a bi-directional system that interconnects with Tennessee Gas Transmission near Portland, Tennessee and several interstate pipelines near Joliet, Illinois.
Stock Repurchase Plan - A total of ~~7.5~~15 million shares have been repurchased to date pursuant to a plan approved by our Board of Directors. The plan, originally approved by our Board of Directors in January 2005, was extended in November 2005, to allow us to purchase up to a total of 15 million shares of our common stock on or before November 2007. ~~Shares are~~On August 7, 2006, we repurchased 7.5 million shares of our outstanding common stock under an accelerated share repurchase agreement with UBS Securities LLC (UBS) at an initial price of $37.52 per share for a total of $281.4 million, which completed the plan approved by our Board of Directors. Under the terms of the accelerated repurchase agreement, we repurchased 7.5 million shares immediately from ~~time to time~~UBS. UBS then borrowed 7.5 million of our shares and will purchase shares in the open market ~~transactions or through privately negotiated transactions~~to settle its short position. Our repurchase is subject to a financial adjustment based on the volume-weighted average price, less a discount, of the shares subsequently repurchased by UBS over the course of the repurchase period. The price adjustment can be settled, at our ~~discretion, subject~~option, in cash or in shares of our common stock. In accordance with EITF Issue No. 99-7, “Accounting for an Accelerated Share Repurchase Program,” the repurchase was accounted for as two separate transactions: (1) as shares of common stock acquired in a treasury stock transaction recorded on the acquisition date and (2) as a forward contract indexed to ~~market conditions~~ONEOK common stock. Additionally, we classified the forward contract as equity under EITF Issue No. 00-19, “Accounting for Derivative Financial Instruments Indexed to, and ~~other factors. During the six months ended June~~Potentially Settled in, a Company’s Own Stock.” At September 30, 2006, we did not owe UBS for a price adjustment. We have no remaining shares available for repurchase ~~any shares of~~under our ~~common~~ stock ~~under this~~repurchase plan.
Credit Rating - Our credit ratings as of ~~June~~September 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~~September 30, 2006, the amount we could have been required to fund for the few counterparties with which we have a Credit Support Annex within our International Swaps and Derivatives Association Agreements is approximately ~~$126.5~~$89.9 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.
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 natural 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 $37.0 million in operating cash ~~flows~~inflows for the ~~six~~nine months ended ~~June~~September 30, 2005. Discontinued operations accounted for approximately ~~$(31.2)~~$31.2 million in investing cash ~~flows~~outflows for the ~~six~~nine months ended ~~June~~September 30, 2005, and did not account for any financing cash flows. The absence of cash flows from our discontinued operations is not expected to have a significant impact on our future cash flows.
Operating Cash Flows - Operating cash flows increased by ~~$365.2~~$602.3 million for the ~~six~~nine months ended ~~June~~September 30, 2006, compared with the same period in 2005. The increase in operating cash flows was primarily the result of a net decrease in working capital of ~~$392.0~~$306.1 million in 2006, compared with a net increase in working capital of $161.3 million in 2005. This decrease in working capital is primarily the result of ~~$176.6 million~~higher working capital at December 31, 2005 compared with December 31, 2004 and the subsequent collection of receivables in ~~2005. These decreases primarily related to decreases in accounts receivable, partially offset by decreases in accounts payable.~~2006, as well as falling gas prices. The increases in 2006 operating cash flows ~~was~~were 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.~~04-5. During the ~~six~~nine months ended ~~June~~September 30, 2006, we received ~~$69.8~~$93.2 million in distributions primarily from Northern Border Pipeline, compared with distributions primarily from ONEOK Partners of ~~$0.6~~$8.1 million in the prior year.
Investing Cash Flows - Our ONEOK Partners segment received $297.0 million for the sale of its 20 percent partnership interest in Northern Border Pipeline in April 2006.
Acquisitions in the ~~first half of~~nine months ending September 30, 2006, primarily relate to our ONEOK Partners segment acquiring the remaining 66²/ 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~~ownership of the entire two percent general partner interest in ONEOK Partners. Additionally, ONEOK Partners paid $11.4 million to Williams for initial capital expenditures ~~incurred~~ related to the Overland Pass Pipeline Company.
Acquisitions in 2005 primarily represent the cash purchase of the Koch assets. The sale of our Production segment resulted in proceeds from the sale of a discontinued component. The proceeds from the sale of assets in 2005 resulted from the sale of Cimarex Energy Company common stock, formerly Magnum Hunter Resources (MHR) common stock. The MHR common stock was acquired upon exercise of MHR stock purchase warrants in February 2005, resulting in us paying $22.7 million which is included in changes in other investments, net.
Financing Cash Flows - The ~~second quarter~~first nine months of 2006 ~~includes $78.6~~include $120.8 million in distributions to minority interests, which primarily resulted from our consolidation of ONEOK Partners in accordance with EITF 04-5 as of January 1, ~~2006.~~2006, and represents distributions to the unitholders of the 54.3 percent of ONEOK Partners that we do not own.
We also paid $281.4 million to repurchase 7.5 million shares of our common stock pursuant to the plan initially approved by our Board of Directors on January 20, 2005 and amended in November 2005. During the first nine months of 2005, we paid $188.7 million to repurchase approximately 6.0 million shares of our stock under the same plan.
In addition, we repaid the remaining $900 million outstanding on our $1.0 billion short-term bridge financing agreement. ONEOK Partners completed the underwritten public offering of senior notes totaling $1.39 billion in net proceeds, before offering expenses, which were used to repay all of the amounts outstanding under ONEOK Partners’ Bridge Facility and to repay $335 million of indebtedness outstanding under the 2006 Partnership Credit Agreement.
In June 2005, we issued $800 million of notes and used a portion of the proceeds to repay commercial paper. The commercial paper had been issued to finance ~~the~~our acquisition of 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. We incurred $1.35 billion of notes payable related to the Koch assets acquisition. This increase was partially offset by $643 million in payments on notes payable and commercial paper, which represents the cash received from the sale of our Production segment, and payments made in the normal course of operations.
During the first ~~half~~quarter 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.~~
We terminated $400 million of our interest rate swap agreements ~~in the first quarter~~and paid a net amount of ~~2005,~~$19.4 million, 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. InWe paid $2.4 million in the second quarter of 2005 ~~we terminated~~as a result of the termination of $500 million of our treasury rate-lock ~~agreements, which resulted in us paying $2.4 million.~~agreements. This amount, net of tax, has been recorded to accumulated other comprehensive loss and will be recognized in the income statement over the term of the related debt issuances.
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
The following table sets forth our contractual obligations related to debt, operating leases and other long-term obligations as of September 30, 2006, and reflects the consolidation of ONEOK Partners based on EITF 04-5. For further discussion of the debt and operating lease agreements, see Notes I and K, respectively, of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
   Payments Due by Period
Contractual Obligations
   Total
Remainder
of 2006    2007    2008    2009    2010    Thereafter
ONEOK
   (Thousands of dollars)
Long-term debt
   $ 1,989,984    $ 6,253    $ 6,242    $ 408,562    $ 106,279    $ 6,300    $ 1,456,348
Interest payments on debt
   1,340,800    30,400    120,400    100,100    90,300    89,600    910,000
Operating leases
   192,585    14,352    41,999    40,159    37,647    26,057    32,371
Storage contracts
   113,516    11,307    37,134    26,041    18,713    10,268    10,053
Firm transportation contracts
   450,406    27,915    94,196    65,715    55,955    46,877    159,748
Pension plan (a)
   10,025    425    2,900    2,100    2,200    2,400    -
Other postretirement benefit plan (a)
   73,996    4,178    17,052    17,289    17,534    17,943    -
   $ 4,171,312    $ 94,830    $ 319,923    $ 659,966    $ 328,628    $ 199,445    $ 2,568,520
ONEOK Partners

Long-term debt
   $ 2,023,555    $ 2,983    $ 11,931    $ 11,931    $ 11,931    $ 261,930    $ 1,722,849
Interest payments on debt
   1,831,603    35,035    138,987    137,728    136,965    124,231    1,258,657
Notes payable
   4,500    -        4,500    -        -        -        -
Operating leases
   10,516    1,156    3,305    2,715    854    538    1,948
Purchase commitments,
    rights-of-way and other
   128,071    2,391    117,035    1,975    1,787    1,746    3,137
Firm transportation contracts
   41,055    2,939    11,659    11,691    11,087    3,679    -
   $ 4,039,300    $ 44,504    $ 287,417    $ 166,040    $ 162,624    $ 392,124    $ 2,986,591
    Total
   $     8,210,612    $     139,334    $     607,340    $     826,006    $     491,252    $     591,569    $     5,555,111

(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.
Interest Payments on Debt - Interest expense is calculated by taking long-term debt and multiplying by the respective coupon rates, adjusted for active swaps.
Leases - We lease various buildings, facilities and equipment, which are accounted for as operating leases. We lease vehicles which are accounted for as operating leases for financial purposes and capital leases for tax purposes.
OTHER
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 our investors that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial condition and results of operations.
We own or retain legal responsibility for the environmental conditions at 12 former manufactured gas sites in Kansas that we acquired in November 1997. These sites contain potentially harmful materials that are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE presently governs all work at these sites. The
terms of the consent agreement allow us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater. We have commenced remediation on eleven sites, with regulatory closure achieved at two of these locations. Of the remaining nine sites, we have completed or are near completion of soil remediation at six sites, and we expect to commence soil remediation on the other three sites. We have begun site assessment at the remaining site where no active remediation has occurred.
To date, we have incurred remediation costs of $5.8 million and have accrued an additional $6.0 million related to the sites where we have commenced or will soon commence remediation. We have recorded estimates of future remediation costs for these sites based on our environmental assessments and remediation plans approved by the KDHE. These estimates are recorded on an undiscounted basis. For the site that is currently in the assessment phase, we have completed some analysis, but are unable at this point to accurately estimate aggregate costs that may be required to satisfy our remedial obligations at this site. Until the site assessment is complete and the KDHE approves the remediation plan, we will not have complete information available to us to accurately estimate remediation costs.
The ~~following table sets forth~~costs associated with these sites do not include other potential expenses that might be incurred, such as unasserted property damage claims, personal injury or natural resource claims, unbudgeted legal expenses or other costs for which we may be held liable but with respect to which we cannot reasonably estimate an amount. As of this date, we have no knowledge of any of these types of claims. The foregoing expense estimates do not consider potential insurance recoveries, recoveries through rates or from unaffiliated parties, to which we may be entitled. We have filed claims with our ~~contractual obligations~~insurance carriers relating to ~~make future payments under~~these sites and we have recovered a portion of our costs incurred to date. We have not recorded any amounts for potential insurance recoveries or recoveries from unaffiliated parties, and we are not recovering any environmental amounts in rates. As more information related to the site investigations and remediation activities becomes available, and to the extent such amounts are expected to exceed our current ~~debt agreements, operating lease agreements~~estimates, additional expenses could be recorded. Such amounts could be material to our results of operations and ~~fixed price contracts. For further discussion~~cash flows depending on the remediation and number of years over which the ~~debt and operating lease agreements, see Notes I and K, respectively, of Notes~~remediation is required to ~~the Consolidated Financial Statements in this Quarterly Report on Form 10-Q.~~be completed.

   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.~~
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 Quarterly Report on Form 10-Q identified by words such as “anticipate,” “plan,” “estimate,” “expect,” “forecast,” “intend,” “believe,” ~~“projection”~~“projection,” “goal” or ~~“goal.”~~similar phrases.
You should not place undue reliance on forward-looking statements. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:

actions by rating agencies concerning the credit ratings of ONEOK and ONEOK Partners;
the effects of weather and other natural phenomena on our operations, including energy sales and prices and demand for pipeline capacity;
competition from other U.S. and Canadian energy suppliers and transporters as well as alternative forms of energy;
the capital intensive nature of our businesses;
the profitability of assets or businesses acquired by us;
risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties;
economic climate and growth in the geographic areas in which we do business;
the risk of a significant slowdown in growth or decline in the U.S. economy or the risk of delay in growth recovery in the U.S. economy;
the uncertainty of estimates, including accruals and costs of environmental remediation;
the timing and extent of changes in commodity prices for natural gas, NGLs, electricity and crude oil;
the effects of changes in governmental policies and regulatory actions, including changes with respect to income 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~~and receipt of expected regulatory clearances involving the ~~Oklahoma Corporation Commission,~~OCC, KCC, Texas regulatory authorities or any other local, state or federal regulatory body, including the FERC;
our ability to access capital at competitive rates or on terms acceptable to us;
risks associated with adequate supply to our gas gathering and processing, fractionation and pipeline facilities, including production declines which outpace new drilling;
the risk that material weaknesses or significant deficiencies in our internal controls over financial reporting could emerge or that minor problems could become significant;
the impact of the outcome of pending and future litigation;
the possible loss of gas distribution franchises or other adverse effects caused by the actions of municipalities;
the impact of unsold pipeline capacity being greater or less than expected;
the ability to market pipeline capacity on favorable terms, including the affects of:
–      future demand for and prices of natural gas;
–      competitive conditions in the overall natural gas and electricity markets;
–      availability of supplies of Canadian and United States 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~~that are significantly different than ~~our assumptions~~the settlement related to ~~ONEOK Partner’s~~Northern Border Pipeline’s November 2005 rate case;
our ability to successfully transfer ONEOK Partners’ operations from Omaha and Denver to Tulsa;
performance of contractual obligations by our customers and shippers;
the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our state and FERC-regulated rates;
timely receipt of ~~required regulatory clearances~~approval by applicable governmental entities for construction and operation of ~~the Midwestern Gas Transmission Eastern Extension Project;~~our pipeline projects and required regulatory clearances;
our ability to acquire all necessary ~~pipeline~~ rights-of-way permits and ~~obtain agreements for interconnects~~consents in a timely ~~manner;~~manner, and our ability to promptly obtain all necessary materials and supplies required for construction, and our ability to construct pipelines without labor or contractor problems;
our ability to promptly obtain all necessary materials and supplies required for construction of gathering, processing and transportation facilities;
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 mechanical integrity of facilities operated;
demand for our services in the proximity of our facilities;
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,~~SEC, which are incorporated by reference.
~~Other~~
These factors ~~and assumptions~~are not ~~identified above were also involved in the making~~necessarily all of the ~~forward-looking statements. The failure of those assumptions to be realized, as well as other~~important factors ~~may also~~that could cause actual results to differ materially from those ~~projected. We~~expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future results. These and other risks are described in greater detail under Part II, Item 1A, “Risk Factors,” in this Quarterly Report and under Part I, Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2005. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under securities laws, we undertake no obligation ~~and make no undertaking~~ to update publicly ~~or revise~~ any forward-looking ~~information.~~statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.
~~ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our quantitative and qualitative disclosures about market risk are consistent with those discussed in Part II, Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” in our Annual Report on Form 10-K for the year ended December 31, 2005.
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 of Derivatives at September 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)
   $ (159,328 ) $ (19,071 ) $ —   $ (178,399 )
Prices provided by other external sources (c)
   136,834 27,398 —   164,232
Prices derived from quotes, other external
    sources and other assumptions (d)
   (5,072 ) 5,106 (105 ) (71 )
Total
   $ (27,566 ) $ 13,433 $ (105 ) $ (14,238 )

(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 )

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

For further discussion of trading activities and assumptions used in our trading activities, see Accounting Treatment 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~~$17.5 million and ~~$17.4~~$43.9 million at ~~June~~September 30, 2006, and 2005, respectively. The following table details the average, high and low daily VAR calculations.
   Three Months Ended
June 30,    Six Months Ended
June 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
Value-at-Risk
   2006    2005    2006    2005    2006    2005    2006    2005
   (Millions of dollars)    (Millions of dollars)
Average
   $ 19.9    $ 11.1    $ 24.4    $ 12.4    $ 10.8    $ 16.3    $ 19.0    $ 13.5
High
   $ 36.1    $ 18.1    $ 48.9    $ 27.1    $ 36.5    $ 44.0    $ 49.0    $ 44.0
Low
   $ 9.4    $ 6.1    $ 9.4    $ 6.1    $ 3.3    $ 7.1    $ 3.3    $ 6.2
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~~decrease in VAR for the three months ended ~~June~~September 30, 2006, compared with 2005, is primarily due to ~~higher~~lower volatility in 2006 attributable to changes in basis prices. In particular, there was significant price volatility in the latter part of the third quarter of 2005 due to weather related events. The increase in VAR for the ~~six~~nine months ended ~~June~~September 30, 2006, compared with 2005, iswas primarily due to higher average commodity prices ~~during~~beginning in the latter part of the third quarter 2005 and was prevalent into second quarter 2006.
INTEREST RATE ~~AND CURRENCY~~ RISK
~~Interest Rate Risk~~
General - At ~~June~~September 30, 2006, the interest rate on approximately ~~81.2~~87.8 percent of our long-term debt was fixed after considering the impact of interest rate swaps.
At ~~June~~September 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~~$4.9 million before ~~taxes.~~taxes and minority interest. 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~~nine months ended ~~June~~September 30, 2006, for all terminated swaps was ~~$5.1 million and the~~$7.6 million. The remaining net savings for all terminated swaps will be recognized over the periods set forth in the following ~~periods:~~table.

   ONEOK    ONEOK
Partners    Total    ONEOK
ONEOK
Partners    Total
   (Millions of dollars)    (Millions of dollars)
Remainder of 2006
   $ 3.3    $ 1.6    $ 4.9    $ 1.7    $ 0.8    $ 2.5
2007
   6.6    3.4    10.0    6.6    3.4    10.0
2008
   6.6    3.6    10.2    6.6    3.6    10.2
2009
   5.6    3.8    9.4    5.6    3.8    9.4
2010
   5.5    4.0    9.5    5.5    4.0    9.5
Thereafter
   15.3    0.8    16.1    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~~September 30, 2006, we ~~had~~recorded a net liability of ~~$30.2~~$13.9 million to recognize the interest rate swaps at fair value. Long-term debt was decreased by ~~$30.2~~$13.9 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~~$5.9 million for the ~~six~~nine months ended ~~June~~September 30, 2006. The swaps are expected to net the following savings for the remainder of the year:
interest expense savings of ~~$4.9~~$2.5 million related to the amortization of the swap value at termination, and
~~up to $1.8~~approximately $0.6 million in interest expense from the existing $490 million of swapped debt, based on LIBOR rates at ~~June~~September 30, 2006.
Total net swap savings for 2006 are expected to be ~~$7.3~~$7.8 million compared to $10.7 million for 2005.
~~Currency Rate Risk~~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~~September 30, 2006, our exposure to risk from currency translation was not material and there was no material currency translation gain or loss recorded.
~~ITEM 4. CONTROLS AND PROCEDURES~~
~~Status of Material Weakness~~ - As previously disclosed in our Annual Report on Form 10-K, the Company identified a software error in February 2006 which impacted our accounting for hedging instruments. The impact of this error was corrected prior to the issuance of the 2005 consolidated financial statements. As a result of the error, management concluded a material weakness existed as of December 31, 2005. During the first quarter of 2006, an alternate process was implemented to manually review and revalue the hedging ineffectiveness calculated by the software. The results are then validated through additional analytical reviews and reconciliations of reports generated by the affected software. Review and testing of the controls implemented in 2006 demonstrated that the controls are operating effectively. Accordingly, management has concluded that this material weakness has been effectively remediated.
ITEM 4. CONTROLS AND PROCEDURES
Quarterly Evaluation of Disclosure Controls and Procedures - As of the end of the period covered by this report, our Chairman and Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer) evaluated the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) and 15d-15(e) of the Exchange Act. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in this report is communicated to management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. Based on their evaluation, they concluded that as of ~~June~~September 30, 2006, our disclosure controls and procedures were effective in ensuring that the information required to be disclosed by us in the reports we file or submit under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
Changes in Internal Controls Over Financial Reporting - We have not made any changes in our internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended ~~June~~September 30, 2006, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, except for those controls described in the ~~above discussion of the Company’s remediation efforts pertaining to the material weakness and in the~~ following paragraphs.
In July 2006, the Oklahoma operations of our Distribution segment migrated to the customer service system that is used in Kansas and Texas. Due to the migration, controls related to the previous customer service system used in Oklahoma no longer apply and the controls related to the customer service system currently used in Kansas and Texas are already in effect in Oklahoma. The migration had no impact on the effectiveness of our overall internal control environment.
In connection with the sale of our former Gathering and Processing, Natural Gas Liquids and Pipelines and Storage assets to ONEOK Partners, the operations currently managed in ~~our~~ONEOK Partners’ Omaha, Nebraska, and Denver, Colorado, offices ~~will be~~are being moved to Tulsa, Oklahoma. The Denver office operations are anticipated to be completely transitioned to Tulsa by the end of ~~the year~~2006, and the Omaha office operations to be transitioned to Tulsa by April 2007. In July 2005, we completed our acquisition of the Natural Gas Liquids segment that subsequently was transferred to our ONEOK Partners segment. As part of our ongoing integration activities related to both of these transactions, we are in the process of developing and incorporating controls and procedures into our internal controls over financial reporting. Until such controls are more fully developed, we have implemented and are relying on compensating controls and have performed extensive reviews of our reported results. As with any change, there are inherent risks in the timing, development and implementation of internal controls that could negatively impact us; however, we do not believe they will materially affect our internal control over financial reporting.
Our ONEOK Partners segment is in the process of implementing a new contracting and billing system to support its gathering and processing operations by automating certain transactional processes, including scheduling, plant allocations and invoicing, that are currently handled manually. Implementation is scheduled to ~~take place~~be completed during the ~~third~~fourth quarter of 2006 and will result in changes to our internal control over financial reporting; however, we do not believe ~~they~~the changes will ~~have a material impact on our financial statements.~~be material.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
~~ITEM 1. LEGAL PROCEEDINGS~~
~~In the Matter of the Natural Gas Explosion at Hutchinson, Kansas during January, 2001, Case No. 02-E-0155, before the Secretary of the Kansas Department of Health and Environment.~~ ~~Remediation required~~Additional information about our legal proceedings is included under ~~the Consent Order we entered into with the Division of Environment of the Kansas Department of Health and Environment~~Part II, Item 1, “Legal Proceedings,” in our Quarterly Reports on ~~April 5, 2004, is complete. Monitoring of the wells and review of the data~~Form 10-Q for the ~~geoengineering study is ongoing.~~
~~Cornerstone Propane Partners, L.P., et al. v. E Prime, Inc., ONEOK Energy Marketing~~three months ended March 31, 2006, and ~~Trading Company, L.P., ONEOK, Inc.,~~the three months ended June 30, 2006, and ~~Calpine Energy Services, L.P., United States District Court~~under Part I, Item 3, “Legal Proceedings,” in our Annual Report on Form 10-K for the ~~Southern District of New York, Case No. 04-CV-00758.~~On May 24, 2006, the Court entered a Final Judgment and Order of Dismissal in this matter pursuant to the settlement reached between the plaintiffs and certain defendants in this matter, including the ONEOK entities.year ended December 31, 2005.
Enron Corp. v. Silver Oak Capital, ~~L.L.C.~~LLC and AG Capital Recovery Partners III, ~~L.P.~~LP, Adversary Proceeding No. 03-93568, relating to Case No. 01-16034, in the United States Bankruptcy Court for the Southern District of New York. ~~ONEOK Energy Services Company, L.P. (“OES”) and other claim owners have agreed with Enron Corp. and Enron North America Corp. to settle all~~The settlements reached in this matter became effective on or about August 7, 2006, upon the expiration of the ~~litigation regarding~~time to appeal the claims that OES originally sold to Bear Stearns. As a result, OES will have no further claims against Enron or Enron North America arising from the physical and financial contracts that were the subject of those claims. The settlement agreement was approved by the bankruptcy court on July 27, 2006. Additionally, OES has agreed to settle with the current ownersterms of the claims as to any repurchase obligations that OES might have under the original purchase agreement with Bear Stearns. Those settlement agreements will require payments by OES of approximately $1.8 million. All of these settlements ~~will become effective after the bankruptcy court approval becomes final~~ under applicable law. This matter is now concluded.
Samuel P. Leggett, et al. v. Duke Energy Corporation, et al., Case No. 13847 in the Chancery Court of Tennessee for the Twenty-Fifth Judicial District at Somerville.On ~~May 2,~~October 16, 2006, the ~~United States Court for~~defendants filed an updated Motion to Dismiss based upon the ~~District of Nevada granted plaintiffs’~~filed rate doctrine and federal preemption. The Court’s ruling on this motion ~~to remand this case, sending the case back to state court. The defendants’ motion to dismiss this case~~ is ~~still~~ pending.
Learjet, Inc., et al. v. ONEOK, Inc., et al.,originally filed in the District Court of Wyandotte County, Kansas (Case No. 05-CV-1500), removed to the United States District Court for the District of Kansas (Case No. 05-CV-2513-CM-JPO), ~~transferred to MDL-1566 in the United States District Court for the District of Nevada.~~ The Judicial Panel for Multidistrict Litigation issued an order on June 15, 2006, transferring this case to MDL Docket No. 1566 pending in the United States District Court for the District of Nevada. The plaintiffs’ motion to remand the case back to state court is still pending.
~~Sinclair Oil Corporation v. ONEOK Energy Services Corporation, L.P.~~,~~filed in the United States District Court for the District of Wyoming (Case No. 05-CV-254-D),~~ conditionally transferred to MDL-1566 in the United States District Court for the District of Nevada ~~(Case No. 05-CV-1396)~~. On ~~May 5,~~August 3, 2006, the ~~United States District~~ Court entered an order denying the Motion to Remand filed by the plaintiffs. On September 28, 2006, the plaintiffs filed a motion with the Judicial Panel for Multidistrict Litigation (the “MDL Panel”) requesting that the MDL Panel create a new multidistrict litigation (“MDL”) matter in the District of Kansas, arguing that the factual and legal bases for recovery in their case makes it markedly different from the other MDL cases pending before the Nevada ~~granted ONEOK Energy Services Company, L.P.’s (“OESC”) motion to dismiss this case and entered judgment in OESC’s favor.~~District Court. On ~~May 9, 2006, plaintiff Sinclair filed its notice of appeal of the order and judgment with the United States Court of Appeals for the Ninth Circuit. On July~~October 11, 2006, the ~~Ninth Circuit granted Sinclair’s~~MDL Panel struck plaintiffs’ motion based upon the motion lacking the predicate multidistrict character necessary for the MDL Panel to ~~stay~~exercise jurisdiction. On September 29, 2006, the ~~appeal until November 20, 2006, pending~~defendants filed a ~~decision in another case already~~Motion to Dismiss based upon the filed rate doctrine and federal preemption. The Court’s ruling on ~~appeal that had been dismissed on the same grounds as the Court’s dismissal of~~ this ~~case against OESC.~~motion is pending.
Breckenridge Brewery of Colorado, LLC, et al. v. ONEOK, Inc., ONEOK Energy Marketing and Trading Company, L.P., et al., originally filed in the District Court of Denver County, Colorado (Case No. 2006-CV-5825), removed to the United States District Court for the District of Colorado (Case No. 06-CV-01110), conditionally transferred to MDL-1566 in the United States District Court for the District of Nevada.~~This~~Plaintiffs’ Motion to Vacate the Conditional Transfer Order was considered by the Judicial Panel for Multidistrict litigation on September 28, 2006. No decision has been issued at this point. Plaintiff’s Motion to Remand is also awaiting decision by the Court.
J.P. Morgan Trust Company v. ONEOK, Inc., et al,originally filed in the District Court of Wyandotte County (Case No. 05-CV-1232), removed to the United States District Court for the District of Kansas (Case No. 05-CV-1331), transferred to MDL-1566 in the United States District Court for the District of Nevada (Case No. 05-CV-1331). On June 22, 2006, the defendants filed a ~~class action energy trading~~Motion to Dismiss based upon the filed rate doctrine and federal preemption. The Court’s ruling on this motion is pending. On September 28, 2006, the plaintiff filed a motion with the Judicial Panel for Multidistrict Litigation (the “MDL Panel”) requesting that the MDL Panel create a new multidistrict litigation (“MDL”) matter in the District of Kansas, arguing that the factual and legal bases for recovery in its case ~~that~~makes is markedly different from the other MDL cases pending before the Nevada District Court. On October 11, 2006, the MDL Panel struck plaintiff’s motion based upon the motion lacking the predicate multidistrict character necessary for the MDL Panel to exercise jurisdiction.
Richard Manson v. Northern Plains Natural Gas Company, LLC, et. al., Civil Action No. 1973-N, in the Court of Chancery of the State of Delaware in and for New Castle County. On May 22, 2006, a Motion to Dismiss was filed with the Delaware Chancery Court. The Court’s ruling on ~~May 19,~~this motion is pending.
Missouri Public Service Commission v. ONEOK, Inc., et al., Circuit Court of Jackson County, Missouri, at Kansas City, Missouri, Civil Action No. 0616-CV27565.On October 6, 2006, ~~in state district court in Denver, Colorado. We, two of our subsidiaries,~~a Petition for Damages and Other Relief was filed by the Missouri Public Service Commission against 23 named defendants, including ONEOK, Inc., ONEOK Energy Marketing and Trading Company, L.P. (now known as ONEOK Energy Services Company, L.P.), and Kansas Gas Marketing ~~Company, and 19 other companies are named as defendants.~~Company. The ~~putative class is all direct purchasers of natural gas in Colorado during~~plaintiff alleges that the ~~period from January 1, 2000, through October 31, 2002. Plaintiffs allege that~~ defendants falsely reported natural gas prices and manipulated the natural gas price indices. ~~Plaintiffs claim~~Plaintiff claims that the defendants violated the ~~Colorado Antitrust Act of 1992~~Missouri antitrust laws, engaged in fraud, and ~~fraudulently concealed~~were unjustly enriched by their ~~activities. Plaintiffs seek~~actions. The plaintiff seeks to recover damages for the ~~“full refund damage remedy” under~~difference between what local distribution companies paid and what they should have paid if the ~~Colorado Antitrust Act~~price indices had not been fraudulently manipulated, interest, and ~~their costs of bringing suit, including attorneys’~~attorney fees. ~~The case was removed to federal district court on June 12, 2006. On June 13, 2006, a~~
Notice of ~~Tag-Along Case was~~Rate Change of Northern Border Pipeline Company, Federal Energy Regulatory Commission, Docket No. RP06-72-000. On September 18, 2006, Northern Border Pipeline (“NBP”) filed a stipulation and agreement pursuant to the settlement reached in its rate case between Northern Border Pipeline and its participant customers. The settlement, supported by the FERC trial staff, establishes maximum long-term rates and charges for transportation on the Northern Border Pipeline system. Beginning in 2007, overall rates will be reduced, compared with rates prior to the ~~Judicial Panel~~filing, by approximately five percent. For the full transportation path from Port of Morgan, Montana to the Chicago area, the previous charge of approximately $0.46 per dekatherm will now be approximately $0.44 per dekatherm, which is comprised of a reservation rate, commodity rate and a compressor usage surcharge. The factors used in calculating depreciation expense for ~~Multidistrict Litigation. On June 27, 2006,~~transmission plant are being increased from the ~~Judicial Panel for Multidistrict Litigation issued a Conditional Transfer Order to~~current
2.25 percent to 2.40 percent. The settlement provides for seasonal rates for short-term transportation services. Seasonal maximum rates vary on a monthly basis from approximately $0.54 per dekatherm to approximately $0.29 per dekatherm for the ~~MDL-1566 matter currently pending in Nevada. On July 27, 2006,~~full transportation route from Port of Morgan, Montana to the ~~plaintiffs filed~~Chicago area. The settlement also includes a ~~Motion to Vacate the Conditional Transfer Order with the Judicial Panel for Multidistrict Litigation. A determination~~three-year moratorium on ~~the plaintiffs’ motion is pending.~~
~~In the Matter of the Application of Kansas Gas Service, a division of ONEOK, Inc. for Adjustment of its Natural Gas Rates in the State of Kansas, Docket No. 06-KGSG-1209-RTS, before the Kansas Corporation Commission.On May 15, 2006, Kansas Gas Service (KGS) filed~~filing rate cases and participants challenging these rates, and requires that Northern Border Pipeline file a rate case ~~with~~within six years. The non-contested settlement was certified on October 20, 2006 by the ~~Kansas Corporation Commission (KCC)~~administrative law judge presiding over the case and was provided to the FERC for ~~a $73.3 million annual revenue increase.~~approval. The ~~KCC has 240 days, or until January 10, 2007~~approval process is expected to ~~render its decision. KGS has requested a Return on Equity~~be completed by late 2006.
United States ex rel. Jack J. Grynberg v. ONEOK, Inc., et al., No. CIV-97-1006-R, United States District Court for the Western District of ~~11.25%~~Oklahoma, transferred,In re Natural Gas Royalties Qui Tam Litigation, MDL Docket No. 1293, United States District Court for the District of Wyoming. On October 20, 2006, the Court entered an order affirming in relevant part the Special Master’s recommendation that all claims against us, our subsidiaries, and ~~an overall Rate of Return of 8.87%.~~our Oklahoma Natural Gas division be dismissed. The ~~hearing on the merits is scheduled~~order remains subject to ~~commence on November 6, 2006.~~appeal by Mr. Grynberg.
~~ITEM 1A. RISK FACTORS~~
ITEM 1A. RISK FACTORS
Our investors should consider the risks set forth in Part I, Item 1A, ~~Risk Factors~~“Risk Factors” of our Annual Report on Form 10-K, for the year ending December 31, 2005, and the following risks that could affect us and our business. Although we have tried to discuss key factors, please be aware that other risks may prove to be important in the future. New risks may emerge at any time and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors should carefully consider the following discussion of risks and the other information included or incorporated by reference in this Quarterly Report on Form 10-Q, including Forward-Looking Information, which is included in Part I, Item 2, ~~Management’s~~“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Our ONEOK Partners segment may not be able to successfully integrate the operations of our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments with their current operations.
The integration of our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments with ONEOK Partners’ current operations will be a complex, time-consuming and costly process. Failure to timely and successfully integrate our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments may have a material adverse effect on our business, financial condition and results of operations. The difficulties of integrating our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments will present challenges to management including:
operating a significantly larger combined company with operations in geographic areas in which they have not previously operated;
managing relationships with new customers for whom they have not previously provided services;
integrating personnel with diverse backgrounds and organizational cultures;
experiencing operational interruptions or the loss of key employees, customers or suppliers;
working through inefficiencies and complexities that may arise due to our ONEOK Partners segment’s unfamiliarity with the new operations and the businesses associated with them, including with their markets;
assimilating the operations, technologies, services and products of our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments into ONEOK Partners;
assessing the internal controls and procedures for the combined entity that we are required to maintain under the Sarbanes-Oxley Act of 2002; ~~and~~
consolidating other corporate and administrative ~~functions.~~functions; and
the ability of ONEOK Partners to successfully accomplish construction of various pipeline projects and obtain customers.
We will also be exposed to risks that are commonly associated with transactions similar to this acquisition, such as unanticipated liabilities and costs, some of which may be material, and diversion of management’s attention. As a result, the anticipated benefits of the integration of our former Gathering and Processing, Natural Gas Liquids, and Pipelines and Storage segments into ONEOK Partners may not be fully realized, if at all.
A downgrade of ONEOK Partners’ credit rating may require an offer to repurchase certain of their senior notes or may impair ONEOK Partners’ ability to access capital.
ONEOK Partners could be required to offer to repurchase certain of its senior notes due 2010 and 2011 at par value, plus any accrued and unpaid interest, if Moody’s Investor Services or Standard & Poor’s Rating Services rates those senior notes below investment grade. Further, the indentures governing ONEOK Partners’ senior notes due 2010, 2011, 2012, 2016 and 2036
include an event of default upon the acceleration of other indebtedness of $100 million or more that would be triggered by such an offer to repurchase, and such an event of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2010, 2011, 2012, 2016 and 2036 to declare those notes immediately due and payable in full. ONEOK Partners may not have sufficient cash on hand to repurchase the senior notes, which may cause it to borrow money under its credit facilities or seek alternative financing sources to finance the repurchases. ONEOK Partners could also face difficulties accessing capital or its borrowing costs could increase, impacting its ability to obtain financing for acquisitions or capital expenditures, to refinance indebtedness and to fulfill its debt obligations.
~~ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS~~
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
ISSUER PURCHASES OF EQUITY SECURITIES
The following table sets forth information relating to our purchases of equity securities during the three months ended ~~June~~September 30, 2006.

Period

Total Number of Shares
(or Units) Purchased
Average Price
Paid per Share
(or Unit)    Total Number of
Shares (or Units)
Purchased as Part of
Publicly Announced
Plans or Programs
Maximum Number
(or Approximate Dollar Value)
of Shares (or Units) that
May Yet Be Purchased
Under the Plans or
Programs
April 1-30, 2006
   61,640 (1)(2) $ 33.33    —      7,500,000
May 1-31, 2006
   4,573 (1) $ 32.58    —      7,500,000
June 1-30, 2006
   2,190 (1) $ 33.07    —      7,500,000

Total
   68,403 $ 33.27    —      7,500,000

Period
   Total Number
of Shares
(or Units)
Purchased    Average Price
Paid per Share
(or Unit)    Total Number of
Shares (or Units)
Purchased as Part of
Publicly Announced
Plans or Programs    Maximum Number (or
Approximate Dollar Value)
of Shares (or Units) that
May Yet Be Purchased
Under the Plans or
Programs
July 1-31, 2006
   7,368 (1)  (2)    $                35.44    -      7,500,000
August 1-31, 2006
   7,550,709 (1)  (2)    $                37.52    7,500,000    -
September 1-30, 2006
   63,816 (1)  (2)    $                38.35    -      -

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

(1) Includes shares withheld pursuant to attestation of ownership and deemed tendered to us in connection with the exercise of stock options under the ONEOK, Inc. Long-Term Incentive Plan, as follows :
~~61,620~~7,350 shares for the period ~~April 1-30,~~July 1-31, 2006
~~4,573~~50,484 shares for the period ~~May~~August 1-31, 2006
~~2,190~~63,610 shares for the period ~~June~~September 1-30, 2006
(2) Includes shares repurchased directly from employees, pursuant to our Employee Stock Award Program, as follows:
2018 shares for the period ~~April~~July 1-31, 2006
225 shares for the period August 1-31, 2006
206 shares for the period September 1-30, 2006
EMPLOYEE STOCK AWARD PROGRAM
Under our Employee Stock Award Program, we issued, for no consideration, to all eligible employees (all full-time employees and employees on short-term disability) one share of our common stock when the per-share closing price of our common stock on the ~~New York Stock Exchange (NYSE)~~NYSE was for the first time at or above $26 per share, and we will issue, for no consideration, one additional share of our common stock to all eligible employees when the closing price on the NYSE is for the first time at or above each one dollar increment above $26 per share. The total number of shares of our common stock available for issuance under this program is 100,000.
Through ~~June~~September 30, 2006, a total of ~~45,415~~63,574 shares had been issued to employees under this program. The following table sets forth information on the number of shares issued during the three months ended September 30, 2006, under this program.
Date
   Closing Price
(at or above)    Shares
Issued
July 11, 2006
   $36.00    4,555
July 24, 2006
   $37.00    4,546
August 8, 2006
   $38.00    4,529
August 10, 2006
   $39.00    4,529
Total
      18,159

On ~~July 11,~~October 17, 2006, our common stock closed above ~~$36.00~~$40.00 per share, ~~and on July 24,~~which resulted in 4,499 shares being issued to eligible employees. On October 23, 2006, our common stock closed above ~~$37.00~~$41.00 per share, which resulted in ~~4,555~~4,503 shares ~~and 4,546 shares, respectively,~~ being issued to eligible employees. ~~This brought the total number of shares issued to employees under the program to 54,516.~~
The issuance of shares under this program has not been registered under the Securities Act of 1933, as amended (1933 Act) in reliance upon ~~Securities and Exchange Commission~~SEC releases, including Release No. 6188, dated February 1, 1980, stating that there is no sale of the shares in the 1933 Act sense to employees under this type of program.
~~ITEM 3. DEFAULTS UPON SENIOR SECURITIES~~
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
Not Applicable.
ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS
~~ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS~~
We held our 2006 annual meeting of shareholders on May 18, 2006. At this meeting, the individuals set forth below were elected by a plurality vote to our board of directors in Class C to serve for a term of three years:Not Applicable.

Director (Class)
   Votes For    Votes Withheld
William L. Ford (Class C)
   99,058,421    10,150,385
Douglas Ann Newsom (Class C)
   105,157,735    4,051,071
Gary D. Parker (Class C)
   105,404,341    3,804,465
Eduardo A. Rodriguez (Class C)
   105,296,574    3,912,232
~~The individuals set forth below are the members of our board of directors whose term of office as a director continued after the meeting:~~
~~Class A~~
~~Class B~~
~~(Term Ending 2007)~~ ~~(Term Ending 2008)~~
~~William M. Bell~~ ~~James C. Day~~
~~Pattye L. Moore~~ ~~David L. Kyle~~
~~Bert H. Mackie~~
~~Mollie B. Williford~~
~~In addition, at this meeting our shareholders ratified the appointment of KPMG, L.L.P. as our independent auditor for the 2006 fiscal year as follows:~~

   Votes For    Votes Against    Abstained
Appointment of KPMG, LLP as principal independent auditor
   105,265,876    3,759,358    183,572
~~Finally, at this meeting our shareholders did not approve a shareholder proposal relating to the separation of the positions of Chairman of the Board and Chief Executive Officer as follows:~~

      Votes For    Votes Against    Abstained
Proposal relating to separation of the positions of Chairman of the Board and Chief Executive Officer
   43,758,515    46,484,123    3,241,957
~~ITEM 5. OTHER INFORMATION~~
ITEM 5. OTHER INFORMATION
Not Applicable.
~~ITEM 6. EXHIBITS~~
ITEM 6. EXHIBITS
The following exhibits are filed as part of this Quarterly Report on Form 10-Q:

Exhibit No.
Exhibit Description
10.1 ~~$1,200,000,000 Amended and Restated Credit~~Purchase Agreement dated ~~as of July 14,~~August 7, 2006, ~~among~~by and between ONEOK, Inc. (the “Issuer”), and UBS AG, London Branch (“UBS”) acting through UBS Securities LLC (“Agent”) as ~~the Borrower, Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, Citibank, N.A., as L/C Issuer, and the Lenders party hereto.~~agent.
10.2 ~~364-day Credit~~Underwriting Agreement ~~dated April 6, 2006,~~ by and ~~among~~between ONEOK Partners, L.P., Citigroup Global Markets Inc. and SunTrust Capital Markets, Inc. as representatives of the several banks and other financial institutions and lenders from time to time party hereto, SunTrust Bank, as Administrative Agent, Citicorp North America, Inc., as Syndication Agent and Bank of Montreal (doing business as Harris Nesbitt), UBS Loan Finance LLC, and Wachovia Bank, National Association, as Co-Documentation Agentsunderwriters dated September 20, 2006 (incorporated by reference to Exhibit ~~10.1~~1.1 to ONEOK Partners, L.P.’s Form 8-K filed on ~~April 12,~~September 26, 2006 (File No. 1-12202)).
~~10.3~~    18 ~~Amended and Restated Revolving Credit Agreement dated March 30, 2006, among ONEOK Partners, L.P., the lenders from time~~Preferability Letter of Independent Registered Public Accounting Firm relating to time party thereto; SunTrust Bank, as administrative agent; Wachovia Bank, National Association, as Syndication Agent; Harris Nesbit Financing, Inc., Barclays Bank PLC and Citibank, N.A., as Co-Documentation Agents. (incorporated by reference to Exhibit 10.1 to ONEOK Partners, L.P. Form 8-K filed March 31, 2006 (File No. 1-2202)).change in accounting principle for annual goodwill impairment test date.
~~12.1~~ ~~Computation of Ratio of Earnings to Fixed Charges for the six months ended June 30, 2006 and 2005.~~
31.1 Certification of David L. Kyle pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 Certification of Jim Kneale pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 Certification of David L. Kyle pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).
32.2 Certification of Jim Kneale pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).
~~Signature~~SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

ONEOK, Inc.
Registrant
Date: ~~August 4,~~November 3, 2006
By:
/s/ Jim Kneale

Jim Kneale
Executive Vice President -
Finance and Administration
and Chief Financial Officer
(Principal Financial Officer)

6268


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

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

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

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

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

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


	Three Months Ended 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


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

Current Assets
Cash and cash equivalents	$ 247,475	$ 7,915
Trade accounts and notes receivable, net	944,732	2,202,895
Gas and natural gas liquids in storage	1,028,007	911,393
Commodity exchanges	191,184	133,159
Energy marketing and risk management assets (Note D)	408,093	399,439
Deposits	161,572	150,608
Other current assets	95,835	234,666
Total Current Assets	3,076,898	4,040,075


Property, Plant and Equipment
Property, plant and equipment	6,634,992	5,575,365
Accumulated depreciation, depletion and amortization	1,867,565	1,581,138
Net Property, Plant and Equipment (Note A)	4,767,427	3,994,227

Deferred Charges and Other Assets
Goodwill and intangibles (Note E)	1,025,420	683,211
Energy marketing and risk management assets (Note D)	111,122	55,713
Investments (Note O)	755,772	245,009
Other assets	388,982	471,289
Total Deferred Charges and Other Assets	2,281,296	1,455,222

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


*(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


*(Unaudited)*	Common Stock Issued	Common Stock		Paid in Capital		Unearned Compensation			Common Stock Issued	Common Stock	Paid in Capital	Unearned Compensation
	*(Shares)*	*(Thousands of Dollars)*							(Shares)	(Thousands of Dollars)
December 31, 2005	107,973,436	$	1,080	$	1,044,283	$	(105	)	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		—		11,208,998	112	177,572	-
Repurchase of common stock	—		—		—		—		-	-	-	-
Common stock issuance pursuant to various plans	495,350		5		6,503		—		642,694	6	9,232	-
Stock-based employee compensation expense	—		—		8,337		158		-	-	12,894	158
Common stock dividends - $0.58 per share	—		—		—		(53	)
Common stock dividends - $0.90 per share									-	-	-	(53)
September 30, 2006									119,825,128	$ 1,198	$1,243,981	$ -

June 30, 2006	119,677,784	$	1,197	$	1,236,695	$	—


*(Unaudited)*	Accumulated Other Comprehensive Loss			Retained Earnings			Treasury Stock			Total			Accumulated Other Comprehensive Income (Loss)	Retained Earnings	Treasury Stock	Total
	*(Thousands of Dollars)*												(Thousands of Dollars)
December 31, 2005	$	(56,991	)	$	1,085,845		$	(279,355	)	$	1,794,757		$ (56,991)	$ 1,085,845	$ (279,355)	$ 1,794,757
Net income		—			207,287			—			207,287		-	231,687	-	231,687
Other comprehensive income		13,290			—			—			13,290		90,242	-	-	90,242

Total comprehensive income											220,577					321,929

Equity unit conversion		—			—			224,764			402,448		-	-	224,764	402,448
Repurchase of common stock		—			—			(4,229	)		(4,229	)	-	-	(285,646)	(285,646)
Common stock issuance pursuant to various plans		—			—			—			6,508		-	-	-	9,238
Stock-based employee compensation expense		—			—			—			8,495		-	-	-	13,052
Common stock dividends - $0.58 per share		—			(62,511	)		—			(62,564	)
Common stock dividends - $0.90 per share													-	(100,128)	-	(100,181)
September 30, 2006													$ 33,251	$ 1,217,404	$ (340,237)	$ 2,155,597

June 30, 2006	$	(43,701	)	$	1,230,621		$	(58,820	)	$	2,365,992


	Pro Forma Three Months Ended June 30, 2005		Pro Forma Six Months Ended June 30, 2005				Pro Forma Nine Months Ended September 30, 2005
	*(Thousand of dollars, except per share amounts)*
(Thousands of dollars, except per share amounts)					(Thousands of dollars, except per share amounts)
Net margin	$	263,914	$	671,452		$	1,000,771
Net income	$	26,148	$	139,928		$	316,666
Net earnings per share, basic	$	0.26	$	1.37		$	3.12
Net earnings per share, diluted	$	0.24	$	1.27		$	2.89


	ONEOK		ONEOK Partners		Total			ONEOK		ONEOK Partners		Total
	*(Millions of dollars)*							(Millions of dollars)
Remainder of 2006	$	3.3	$	1.6	$	4.9	$	1.7	$	0.8	$	2.5
2007		6.6		3.4		10.0		6.6		3.4		10.0
2008		6.6		3.6		10.2		6.6		3.6		10.2
2009		5.6		3.8		9.4		5.6		3.8		9.4
2010		5.5		4.0		9.5		5.5		4.0		9.5
Thereafter		15.3		0.8		16.1		15.3		0.8		16.1


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

Goodwill	$	380,394	$	9,552	$	(2,001	)	$	184,843	$	572,788	$	380,394	$	9,552	$	(2,001	)	$	184,843	$	572,788


	Gross Intangibles		Accumulated Amortization			Net Intangibles
	*(Thousands of dollars)*							Gross Intangibles	Accumulated Amortization	Net Intangibles
June 30, 2006	$	462,214	$	(7,666	)	$	454,548
								(Thousands of dollars)
September 30, 2006								$ 462,214	$ (9,582)	$ 452,632
December 31, 2005	$	306,650	$	(3,833	)	$	302,817	$ 306,650	$ (3,833)	$ 302,817


	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


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


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


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


	ONEOK		ONEOK Partners		Guardian		Total			ONEOK		ONEOK Partners		Guardian		Total
	*(Millions of dollars)*									(Millions of dollars)
Remainder of 2006									$	6.3	$	-	$	3.0	$	9.3
2007	$	6.6	$	—	$	11.9	$	18.5		6.2		-		11.9		18.1
2008		408.9		—		11.9		420.8		408.6		-		11.9		420.5
2009		107.5		—		11.9		119.4		106.3		-		11.9		118.2
2010		6.3		250.0		11.9		268.2		6.3		250.0		11.9		268.2


	Pension Benefits Three Months Ended June 30,						Pension Benefits Six Months Ended June 30,
	2006			2005			2006			2005			Pension Benefits Three Months Ended September 30,						Pension Benefits Nine Months Ended September 30,
	*(Thousands of dollars)*													2006			2005			2006			2005
Components of Net Periodic Benefit Cost														(Thousands of dollars)
Service cost	$	5,267		$	4,941		$	10,532		$	9,882		$	5,204		$	4,941		$	15,736		$	14,823
Interest cost		10,871			10,758			21,742			21,516			10,826			10,758			32,569			32,273
Expected return on assets		(14,396	)		(14,927	)		(28,794	)		(29,854	)		(14,396	)		(14,927	)		(43,189	)		(44,780	)
Amortization of unrecognized prior service cost		378			361			756			722			378			361			1,133			1,082
Amortization of loss		3,353			2,126			6,708			4,252			3,278			2,126			9,985			6,377

Net periodic benefit cost	$	5,473		$	3,259		$	10,944		$	6,518		$	5,290		$	3,259		$	16,234		$	9,775


	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


	Postretirement Benefits Three Months Ended September 30,						Postretirement Benefits Nine Months Ended September 30,
		2006			2005			2006			2005
Components of Net Periodic Benefit Cost		(Thousands of dollars)
Service cost	$	1,583		$	1,765		$	4,749		$	5,294
Interest cost		3,539			3,567			10,617			10,702
Expected return on assets		(1,141	)		(1,086	)		(3,423	)		(3,258	)
Amortization of unrecognized net asset at adoption		797			864			2,392			2,592
Amortization of unrecognized prior service cost		(571	)		118			(1,715	)		354
Amortization of loss		2,271			1,617			6,814			4,852
Net periodic benefit cost	$	6,478		$	6,845		$	19,434		$	20,536


Three Months Ended June 30, 2006	Distribution		Energy Services			ONEOK Partners		Other and Eliminations			Total
Three Months Ended September 30, 2006															Distribution			Energy Services			ONEOK Partners			Other and Eliminations			Total
															(Thousands of dollars)
	*(Thousands of dollars)*
Sales to unaffiliated customers	$	317,109	$	1,103,904		$	998,070	$	8,712		$	2,427,795		$	252,261		$	1,350,802		$	1,045,634		$	615		$	2,649,312
Energy trading revenues, net		—		4,112			—		—			4,112			-			(8,435	)		-			-			(8,435	)
Intersegment sales		—		86,763			161,280		(248,043	)		—			-			51,892			168,949			(220,841	)		-

Total Revenues	$	317,109	$	1,194,779		$	1,159,350	$	(239,331	)	$	2,431,907		$	252,261		$	1,394,259		$	1,214,583		$	(220,226	)	$	2,640,877

Net margin	$	119,631	$	64,327		$	215,200	$	2,491		$	401,649		$	106,942		$	30,725		$	210,682		$	637		$	348,986
Operating costs		91,524		10,304			77,199		1,047			180,074			88,821			8,637			75,529			996			173,983
Depreciation, depletion and amortization		27,161		529			39,282		122			67,094			27,307			524			27,516			121			55,468
Gain on sale of assets		—		—			113,877		1,027			114,904			-			-			-			-			-

Operating income	$	946	$	53,494		$	212,596	$	2,349		$	269,385		$	(9,186	)	$	21,564		$	107,637		$	(480	)	$	119,535

Loss from operations of discontinued components	$	—	$	(150	)	$	—	$	—		$	(150	)	$	-		$	(13	)	$	-		$	-		$	(13	)
Income from equity investments	$	—	$	—		$	18,075	$	—		$	18,075
Equity earnings from investments														$	-		$	-		$	22,788		$	-		$	22,788
Capital expenditures	$	41,017	$	—		$	35,799	$	1,106		$	77,922		$	37,154		$	-		$	61,213		$	13,008		$	111,375

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

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

Income (loss) from operations of discontinued components														$	-		$	(32,972	)	$	-		$	13,390		$	(19,582	)
Equity earnings from investments														$	-		$	-		$	(39	)	$	2,861		$	2,822
Capital expenditures														$	39,069		$	-		$	8,949		$	13,939		$	61,957


Three Months Ended June 30, 2005	Distribution			Energy Services			ONEOK Partners		Other and Eliminations			Total
Nine Months Ended September 30, 2006																Distribution		Energy Services			ONEOK Partners		Other and Eliminations			Total
	*(Thousands of dollars)*															(Thousands of dollars)
Sales to unaffiliated customers	$	339,794		$	1,383,473		$	263,140	$	103,167		$	2,089,574		$	1,356,613	$	4,485,343		$	2,983,875	$	(454	)	$	8,825,377
Energy trading revenues, net		—			(8,784	)		—		—			(8,784	)		-		3,047			-		-			3,047
Intersegment sales		—			171,257			181,409		(352,666	)		—			-		323,800			559,888		(883,688	)		-

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		$	1,356,613	$	4,812,190		$	3,543,763	$	(884,142	)	$	8,828,424

Net margin	$	315,072		$	167,481		$	420,141	$	3,485		$	906,179		$	422,014	$	198,206		$	624,143	$	4,122		$	1,248,485
Operating costs		182,037			19,564			155,802		1,803			359,206			270,858		28,201			224,650		2,799			526,508
Depreciation, depletion and amortization		55,314			1,104			66,752		250			123,420			82,621		1,628			94,269		371			178,889
Gain on sale of assets		—			—			114,865		1,027			115,892			-		-			114,865		1,027			115,892

Operating income	$	77,721		$	146,813		$	312,452	$	2,459		$	539,445		$	68,535	$	168,377		$	420,089	$	1,979		$	658,980

Income (loss) from operations of discontinued components	$	—		$	(397	)	$	—	$	—		$	(397	)	$	-	$	(410	)	$	-	$	-		$	(410	)
Income from equity investments	$	—		$	—		$	49,954	$	—		$	49,954
Equity earnings from investments															$	-	$	-		$	72,750	$	-		$	72,750
Total assets	$	2,628,453		$	1,689,530		$	5,040,491	$	817,630		$	10,176,104		$	2,606,379	$	1,987,476		$	5,030,429	$	564,234		$	10,188,518
Capital expenditures	$	77,692		$	—		$	53,575	$	1,326		$	132,593		$	114,846	$	-		$	114,788	$	14,334		$	243,968

Nine Months Ended September 30, 2005																Distribution		Energy Services			ONEOK Partners		Other and Eliminations			Total
																(Thousands of dollars)
Sales to unaffiliated customers															$	1,433,945	$	4,816,867		$	1,444,788	$	273,414		$	7,969,014
Energy trading revenues, net																-		11,023			-		-			11,023
Intersegment sales																-		487,248			860,909		(1,348,157	)		-
Total Revenues															$	1,433,945	$	5,315,138		$	2,305,697	$	(1,074,743	)	$	7,980,037

Net margin															$	412,816	$	127,483		$	391,519	$	(2,125	)	$	929,693
Operating costs																265,701		28,277			155,483		(3,415	)		446,046
Depreciation, depletion and amortization																86,301		1,503			46,867		349			135,020
Gain on sale of assets																-		-			-		-			-
Operating income															$	60,814	$	97,703		$	189,169	$	941		$	348,627
Income (loss) from operations of discontinued components															$	-	$	(34,413	)	$	-	$	28,495		$	(5,918	)
Equity earnings from investments															$	-	$	-		$	597	$	7,875		$	8,472
Total assets															$	2,661,119	$	3,105,229		$	4,036,790	$	559,317		$	10,362,455
Capital expenditures															$	103,078	$	159		$	39,390	$	47,303		$	189,930


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


	Number of Shares		Weighted Average Exercise Price		Number of Shares			Weighted Average Price
Outstanding December 31, 2005	1,952,415		$	22.51	1,952,415		$	22.51
Exercised	(359,256	)	$	21.39	(590,921	)	$	23.04
Expired	(2,166	)	$	19.39	(2,166	)	$	19.39
Restored	115,667		$	31.83	237,111		$	35.03
Outstanding September 30, 2006					1,596,439		$	24.17

Outstanding June 30, 2006	1,706,660		$	23.38
Exercisable September 30, 2006					1,405,070		$	22.55

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	$	—



Volatility (a)	~~13.88%~~13.88	% to ~~31.06~~	%31.06%
Dividend Yield	~~2.78%~~2.78	% to ~~8.93~~	%8.5%
Risk-free Interest Rate	~~2.52%~~2.52	% to ~~6.53~~	%6.11%


	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


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


	Number of Shares		Weighted Average Exercise Price		Number of Shares			Weighted Average Price
Nonvested December 31, 2005	119,514		$	22.44	119,514		$	22.44
Released to participants	(4,086	)	$	21.55	(4,086	)	$	21.55
Forfeited	(2,912	)	$	23.19	(2,912	)	$	23.19
Nonvested September 30, 2006					112,516		$	22.45

Nonvested June 30, 2006	112,516		$	22.45


	Number of Units		Weighted Average Exercise Price		Number of Units			Weighted Average Price
Nonvested December 31, 2005	581,847		$	21.13	581,847		$	21.13
Granted	479,000		$	25.98	479,000		$	25.98
Released to participants	(158,365	)	$	15.31	(158,365	)	$	15.31
Forfeited	(16,324	)	$	23.96	(20,654	)	$	24.29
Nonvested September 30, 2006					881,828		$	24.74

Nonvested June 30, 2006	886,158		$	24.74


	~~February~~January 19, 2006
Volatility (a)	~~18.80~~	%18.80%
Dividend Yield	~~3.70~~	%3.70%
Risk-free Interest Rate	~~4.32~~	%4.32%


	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	%


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