Form 10-Q (9/30/2005)

10-Q 1 d10q.htm FORM 10-Q (9/30/2005) Form 10-Q (9/30/2005)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2005

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

For the transition period from to .

Commission file number 001-13643

ONEOK, Inc.

(Exact name of registrant as specified in its charter)


Oklahoma		73-1520922
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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

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

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

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

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

On November 2, 2005, the Company had 97,572,018 shares of common stock outstanding.

ONEOK, Inc.

QUARTERLY REPORT ON FORM 10-Q


		Page No.
Part I.	Financial Information

Item 1.	Financial Statements (Unaudited)

	Consolidated Statements of Income - Three Months and Nine Months Ended September 30, 2005 and 2004	3

	Consolidated Balance Sheets - September 30, 2005 and December 31, 2004	4-5

	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2005 and 2004	7

	Consolidated Statements of Shareholders’ Equity and Comprehensive Income - Nine Months Ended September 30, 2005	8-9

	Notes to Consolidated Financial Statements	10-24

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25-47

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	47-49

Item 4.	Controls and Procedures	49

Part II.	Other Information

Item 1.	Legal Proceedings	49-50

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50-51

Item 3.	Defaults Upon Senior Securities	51

Item 4.	Submission of Matters to a Vote of Security Holders	51

Item 5.	Other Information	51

Item 6.	Exhibits	51

Signature		52

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.

Part I - FINANCIAL INFORMATION

Item 1.

Financial Statements

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended September 30,					Nine Months Ended September 30,
(Unaudited)	2005			2004		2005			2004
	*(Thousands of dollars, except per share amounts)*
Revenues
Operating revenues, excluding energy trading revenues	$	3,181,591		$	1,647,000	$	7,969,014		$	3,135,115
Energy trading revenues, net		10,615			17,411		11,023			106,583

Total Revenues		3,192,206			1,664,411		7,980,037			3,241,698

Cost of sales and fuel		2,849,705			1,444,565		7,037,161			2,451,359

Net Margin		342,501			219,846		942,876			790,339

Operating Expenses
Operations and maintenance		153,031			118,508		395,059			351,641
Depreciation, depletion and amortization		48,142			39,718		135,052			118,005
General taxes		18,114			13,225		51,061			46,497

Total Operating Expenses		219,287			171,451		581,172			516,143

Operating Income		123,214			48,395		361,704			274,196

Other income		7,250			1,636		16,486			11,154
Other expense		3,365			1,322		8,087			9,754
Interest expense		41,601			21,148		91,682			62,052

Income before Income Taxes		85,498			27,561		278,421			213,544

Income taxes		32,800			11,010		106,914			83,401

Income from Continuing Operations		52,698			16,551		171,507			130,143
Discontinued operations, net of taxes:
Income (loss) from operations of discontinued components, net		(19,519	)		4,288		(5,812	)		13,638
Gain on sale of discontinued component, net		151,355			—		151,355			—

Net Income	$	184,534		$	20,839	$	317,050		$	143,781

Earnings Per Share of Common Stock (Note P)
Basic:
Earnings per share from continuing operations	$	0.53		$	0.16	$	1.69		$	1.28
Earnings (loss) per share from operations of discontinued components, net		(0.20	)		0.04		(0.06	)		0.14
Earnings per share from gain on sale of discontinued component, net		1.52			—		1.49			—

Net earnings per share, basic	$	1.85		$	0.20	$	3.12		$	1.42

Diluted:
Earnings per share from continuing operations	$	0.49		$	0.15	$	1.56		$	1.25
Earnings (loss) per share from operations of discontinued components, net		(0.18	)		0.04		(0.05	)		0.13
Earnings per share from gain on sale of discontinued component, net		1.39			—		1.38			—

Net earnings per share, diluted	$	1.70		$	0.19	$	2.89		$	1.38

Average Shares of Common Stock (Thousands)
Basic		99,894			102,914		101,568			101,530
Diluted		108,602			106,942		109,555			104,080

Dividends Declared Per Share of Common Stock	$	0.28		$	0.25	$	1.09		$	0.88

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS


(Unaudited)	September 30, 2005		December 31, 2004
	*(Thousands of dollars)*
Assets
Current Assets
Cash and cash equivalents	$	86,160	$	9,458
Trade accounts and notes receivable, net		1,471,986		1,412,861
Materials and supplies		22,497		19,888
Gas and natural gas liquids in storage		880,170		593,028
Commodity exchanges		160,704		1,758
Energy marketing and risk management assets (Note D)		1,300,283		386,781
Deposits		87,621		32,394
Deferred income taxes		136,668		—
Other current assets		336,870		38,284

Total Current Assets		4,482,959		2,494,452

Property, Plant and Equipment
Gathering and Processing		1,055,262		1,034,344
Natural Gas Liquids		483,536		32,268
Pipelines and Storage		1,125,629		705,115
Distribution		2,999,783		2,916,440
Energy Services		7,690		7,531
Other		135,311		137,178

Total Property, Plant and Equipment		5,807,211		4,832,876
Accumulated depreciation, depletion and amortization		1,608,153		1,519,719

Net Property, Plant and Equipment		4,199,058		3,313,157

Deferred Charges and Other Assets
Regulatory assets, net (Note E)		187,455		203,547
Goodwill (Note F)		397,161		225,188
Intangibles (Note G)		323,618		—
Energy marketing and risk management assets (Note D)		195,941		71,310
Prepaid pensions		119,929		127,649
Investments and other		391,939		258,609

Total Deferred Charges and Other Assets		1,616,043		886,303

Assets of Discontinued Component		64,395		505,240

Total Assets	$	10,362,455	$	7,199,152

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS


(Unaudited)	September 30, 2005			December 31, 2004
	*(Thousands of dollars)*
Liabilities and Shareholders’ Equity
Current Liabilities
Current maturities of long-term debt	$	306,543		$	341,532
Notes payable		1,202,500			644,000
Accounts payable		1,531,696			1,161,984
Dividends payable		27,647			—
Accrued taxes		203,234			42,849
Accrued interest		39,464			32,807
Customers’ deposits		41,025			39,478
Unrecovered purchased gas costs		109,869			64,322
Commodity exchanges		289,206			—
Energy marketing and risk management liabilities (Note D)		1,205,411			403,626
Deferred income taxes		—			16,841
Other		131,165			141,356

Total Current Liabilities		5,087,760			2,888,795

Long-term Debt, excluding current maturities		2,027,721			1,543,202
Deferred Credits and Other Liabilities
Deferred income taxes		633,405			601,281
Energy marketing and risk management liabilities (Note D)		873,997			102,865
Lease obligation		76,712			86,817
Other deferred credits		275,720			284,313

Total Deferred Credits and Other Liabilities		1,859,834			1,075,276

Liabilities of Discontinued Component		1,646			86,175

Total Liabilities		8,976,961			5,593,448

Commitments and Contingencies (Note M)
Shareholders’ Equity
Common stock, $0.01 par value: authorized 300,000,000 shares; issued 107,867,880 shares and outstanding 98,735,216 shares at September 30, 2005; issued 107,143,722 shares and outstanding 104,106,285 shares at December 31, 2004		1,079			1,071
Paid in capital		1,036,621			1,017,603
Unearned compensation		(549	)		(1,413	)
Accumulated other comprehensive loss (Note H)		(266,099	)		(9,591	)
Retained earnings		856,029			649,240
Treasury stock, at cost: 9,132,664 shares at September 30, 2005 and 3,037,437 shares at December 31, 2004		(241,587	)		(51,206	)

Total Shareholders’ Equity		1,385,494			1,605,704

Total Liabilities and Shareholders’ Equity	$	10,362,455		$	7,199,152

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)	2005			2004
	*(Thousands of Dollars)*
Operating Activities
Net income	$	317,050		$	143,781
Depreciation, depletion, and amortization		135,052			118,005
Impairment expense		52,226			—
Gain on sale of discontinued component		(151,355	)		—
Gain on sale of assets		(3,936	)		(9,345	)
Income from equity investments, net		1,134			(40	)
Deferred income taxes		40,128			77,906
Stock-based compensation expense		9,903			6,695
Allowance for doubtful accounts		9,723			10,238
Changes in assets and liabilities (net of acquisition and disposition effects):
Accounts and notes receivable		5,339			262,659
Inventories		(284,653	)		(137,771	)
Unrecovered purchased gas costs		45,547			17,157
Commodity exchanges		130,260			(359	)
Deposits		(55,227	)		22,461
Regulatory assets		(5,490	)		(6,921	)
Accounts payable and accrued liabilities		216,008			(123,583	)
Energy marketing and risk management assets and liabilities		113,634			(33,780	)
Other assets and liabilities		(336,304	)		(60,103	)

Cash Provided by Operating Activities		239,039			287,000

Investing Activities
Changes in other investments, net		(22,271	)		610
Acquisitions		(1,328,572	)		—
Capital expenditures		(189,930	)		(192,335	)
Proceeds from sale of discontinued component		630,214			—
Proceeds from sale of assets		27,520			17,249
Other investing activities		(3,866	)		(2,990	)

Cash Used in Investing Activities		(886,905	)		(177,466	)

Financing Activities
Borrowing (payments) of notes payable, net		558,500			(302,000	)
Termination of interest rate swaps		(22,565	)		82,915
Issuance of debt, net of issuance costs		798,792			—
Payment of debt		(335,808	)		(1,041	)
Purchase of common stock		(190,381	)		—
Issuance of common stock		10,207			176,107
Dividends paid		(82,834	)		(63,374	)
Other financing activities		(11,343	)		3,446

Cash Provided by (Used in) Financing Activities		724,568			(103,947	)

Change in Cash and Cash Equivalents		76,702			5,587
Cash and Cash Equivalents at Beginning of Period		9,458			12,172

Cash and Cash Equivalents at End of Period	$	86,160		$	17,759

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
	*(Shares)*	*(Thousands of Dollars)*
December 31, 2004	107,143,722	$	1,071	$	1,017,603	$	(1,413	)
Net income	—		—		—		—
Other comprehensive loss	—		—		—		—

Total comprehensive income

Repurchase of common stock	—		—		—		—
Common stock issuance pursuant to various plans	724,158		8		10,199		—
Stock-based employee compensation expense	—		—		8,819		1,084
Common stock dividends - $1.09 per share	—		—		—		(220	)

September 30, 2005	107,867,880	$	1,079	$	1,036,621	$	(549	)

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
	*(Thousands of Dollars)*
December 31, 2004	$	(9,591	)	$	649,240		$	(51,206	)	$	1,605,704
Net income		—			317,050			—			317,050
Other comprehensive loss		(256,508	)		—			—			(256,508	)

Total comprehensive income											60,542

Repurchase of common stock		—			—			(190,381	)		(190,381	)
Common stock issuance pursuant to various plans		—			—			—			10,207
Stock-based employee compensation expense		—			—			—			9,903
Common stock dividends - $1.09 per share		—			(110,261	)		—			(110,481	)

September 30, 2005	$	(266,099	)	$	856,029		$	(241,587	)	$	1,385,494

ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

A.	Summary of Accounting Policies

Our accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and reflect all adjustments that, in our opinion, are necessary for a fair presentation of the results for the interim periods presented. All such adjustments are of a normal recurring nature. Due to the seasonal nature of our business, the results of operations for the three and nine months ended September 30, 2005, 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, 2004.

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, 2004.

Critical Accounting Policies

Impairment of Long-Lived Assets - We assess our long-lived assets for impairment based on Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144). A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.

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 the third quarter of 2005, we made the decision to sell our Spring Creek power plant and exit the power generation business. In October 2005, we concluded that our Spring Creek power plant located in southwest Oklahoma had been impaired and recorded an impairment expense of $52.2 million. This conclusion was based on our Statement 144 impairment analysis of the results of operations for this plant through September 30, 2005, and also the net sales proceeds from the anticipated sale of the plant. These assets were held for sale at September 30, 2005, and, accordingly, this component of our business is accounted for as discontinued operations in accordance with Statement 144.

Significant Accounting Policies

Common Stock Options and Awards - In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 123R, “Share-Based Payment” (Statement 123R). Statement 123R requires companies to expense the fair value of share-based payments. In addition, there are also changes related to the expense calculation for share-based payments. Effective January 1, 2006, we will adopt Statement 123R, and we expect to use the prospective method. We are currently assessing the impact of adopting Statement 123R, but we do not believe it will have a material impact on our financial condition and results of operations, 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” on January 1, 2003.

The following table sets forth the effect on net income and earnings per share if we had applied the fair-value recognition provisions of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation,” to all options and awards granted prior to January 1, 2003.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	*(Thousands of dollars, except per share amounts)*
Net income, as reported	$	184,534	$	20,839	$	317,050	$	143,781
Add: Stock option compensation included in net income, net of related tax effects		2,582		1,576		7,364		4,926
Deduct: Total stock option compensation expense determined under fair value based method for all awards, net of related tax effects		2,745		1,873		7,852		5,816

Pro forma net income	$	184,371	$	20,542	$	316,562	$	142,891

Earnings per share:
Basic - as reported	$	1.85	$	0.20	$	3.12	$	1.42
Basic - pro forma	$	1.85	$	0.20	$	3.12	$	1.41
Diluted - as reported	$	1.70	$	0.19	$	2.89	$	1.38
Diluted - pro forma	$	1.70	$	0.19	$	2.89	$	1.37

Asset Retirement Obligations - In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), that requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. FIN 47 is effective for our year ending December 31, 2005. We are currently reviewing the applicability of FIN 47 to our operations and its potential impact on our consolidated financial statements.

Consolidation - In June 2005, the FASB ratified the consensus reached in EITF Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights” (EITF 04-5). EITF 04-5 presumes that a general partner controls a limited partnership and therefore should consolidate the partnership. Effective January 1, 2006, we will be required to consolidate Northern Border Partners’ operations in our consolidated financial statements. We are currently evaluating the impact of adopting EITF 04-5. However, had we consolidated Northern Border Partners at September 30, 2005, our debt to equity ratio would have changed from 72 percent debt and 28 percent equity to 78 percent debt and 22 percent equity. This increase results from the consolidation of Northern Border Partners’ debt of $1.3 billion at September 30, 2005, while the majority of their equity is reported as minority interest liability. The debt covenant calculations in our credit agreements exclude the debt of Northern Border Partners since it is a master limited partnership.

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 are currently reviewing the applicability of EITF 04-13 to our operations and its potential impact on our consolidated financial statements.

Other

Reclassifications - Certain amounts in our consolidated financial statements have been reclassified to conform to the 2005 presentation. These reclassifications did not impact previously reported net income or shareholders’ equity. Prior periods have been adjusted to reflect the sale of our Production segment and the pending sale of our Spring Creek power plant as discontinued operations. See Note C for additional information.

B.	Acquisition and Divestiture

On July 1, 2005, we completed the acquisition of the natural gas liquids businesses owned by several affiliates and a subsidiary of Koch Industries, Inc. (Koch) for approximately $1.33 billion, net of working capital and cash received. This transaction includes Koch Hydrocarbon, LP’s entire mid-continent natural gas liquids fractionation business; Koch Pipeline Company, L.P.’s natural gas liquids pipeline distribution systems; Chisholm Pipeline Holdings, Inc., which has a 50 percent ownership interest in Chisholm Pipeline Company; MB1/LP, LLC (formerly MBFF, LP), which owns an 80 percent interest in the 160,000 barrel per day fractionator at Mont Belvieu, Texas; and Koch Vesco Holdings, LLC, an entity that owns a 10.2 percent interest in Venice Energy Services Company, LLC (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 the 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 the acquisition had actually occurred on the dates indicated or results that may be expected in the future.


	Pro Forma Three Months Ended September 30,		Pro Forma Nine Months Ended September 30,
	2004		2005		2004
	*(Thousand of Dollars, except per share amounts)*
Revenues	$	1,710,842	$	8,086,215	$	3,377,416
Net income	$	22,350	$	323,488	$	155,733
Net earnings per share, basic	$	0.22	$	3.19	$	1.53
Net earnings per share, diluted	$	0.21	$	2.94	$	1.50

We have recorded a preliminary purchase price allocation related to this acquisition. Our Natural Gas Liquids segment has recorded goodwill of approximately $172.0 million and intangibles of approximately $325.6 million. The purchase price allocation will be finalized as additional information regarding the assets acquired becomes available.

In October 2005, we entered into an agreement to sell certain natural gas gathering and processing assets located in Texas to a subsidiary of Eagle Rock Energy, Inc. for approximately $528 million. The transaction is expected to close December 1, 2005, and is subject to Hart-Scott-Rodino antitrust approval. The properties are located in the Texas panhandle and include six gas processing plants, operating at approximately 60 percent of 160 million cubic foot per day capacity with 3,700 miles of gas gathering lines, and estimated natural gas liquids (NGL) production of 13,500 barrels per day. The proceeds from this sale will be used to purchase other assets, repurchase ONEOK shares or retire debt.

C.	Discontinued Operations

In September 2005, we completed the sale of our Production segment to TXOK Acquisition, Inc. for $645 million, before adjustments. We recognized a pre-tax gain on the sale of our Production segment of approximately $243.2 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 had approved the potential sale in July 2005, which resulted in our Production segment being classified as held for sale during the third quarter. In accordance with Statement 144, we did not record any depreciation, depletion or amortization for our Production segment while it was classified as held for sale.

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 $53 million. The transaction requires Federal Energy Regulatory Commission (FERC) approval and is expected to be completed in 2006. The 300-megawatt gas-fired merchant power plant was built in 2001 to supply electrical power during peak periods using gas-powered turbine generators. The 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, “Accounting for the Impairment or Disposal of Long-Lived 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 September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	*(Thousands of dollars)*
Operating revenues, excluding energy trading revenues	$	45,917		$	62,351		$	131,629		$	147,778
Cost of sales and fuel		11,900			36,097			35,532			69,206

Net margin		34,017			26,254			96,097			78,572
Impairment expense		52,226			—			52,226			—
Operating costs		8,359			7,557			23,951			22,283
Depreciation, depletion and amortization		1,136			7,589			17,887			22,268

Operating income (loss)		(27,704	)		11,108			2,033			34,021

Other income (expense), net		170			(20	)		252			(110	)
Interest expense		3,947			4,100			11,657			11,833
Income taxes		(11,962	)		2,700			(3,560	)		8,440

Income (loss) from operations of discontinued components, net	$	(19,519	)	$	4,288		$	(5,812	)	$	13,638

Gain on sale of discontinued component, net of tax of $91.8 million	$	151,355		$	—		$	151,355		$	—

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


	September 30, 2005		December 31, 2004
	*(Thousands of dollars)*
Assets
Trade accounts and notes receivable, net	$	—	$	19,564
Materials and supplies		1,710		2,587
Energy marketing and risk management assets		—		1,891
Other		—		323
Property, plant and equipment, net		50,937		473,664
Deferred income taxes		10,925		—
Investments and other		823		7,211

Assets of Discontinued Component	$	64,395	$	505,240

Liabilities
Accounts payable	$	—	$	23,367
Energy marketing and risk management liabilities		—		6,007
Deferred income taxes		—		43,251
Other liabilities		1,646		13,550

Liabilities of Discontinued Component	$	1,646	$	86,175

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 FASB Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133), as amended. Under Statement 133, entities are required to record 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. 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 gain or loss 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 income and is subsequently reclassified into earnings when the forecasted transaction affects earnings. Any amounts excluded from the assessment of hedge effectiveness, as well as the ineffective portion of the hedge, are reported in 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 and assess the effectiveness of hedging relationships, both at the inception of the hedge and on an ongoing basis.

At the beginning of the third quarter of 2004, we completed a reorganization of our Energy Services segment and renewed our focus on our physical marketing and storage business. Concurrent with this reorganization, we evaluated the accounting treatment related to the presentation of revenues from the different types of activities to determine which amounts should be reported on a gross or net basis. We began accounting for the realized revenues and purchase costs of those contracts that result in physical delivery on a gross basis beginning in the third quarter of 2004. Derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are also reported on a gross basis. No prior periods have been adjusted for this change; therefore, comparisons with prior periods may not be meaningful. Reporting of these transactions on a gross basis did not impact operating income, but resulted in an increase to revenues and cost of sales and fuel.

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, 2004, for additional discussion.

Fair Value Hedges

During the first quarter of 2005, we terminated $400 million of our interest rate swap agreements and paid a net amount of $19.4 million, which included $20.2 million for the present value of future payments at the time of termination, less $0.8 million for interest rate savings through the termination of the swaps. During the first quarter of 2004, we terminated $670 million of our interest rate swap agreements and received $81.9 million. 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 first nine months of 2005 for all terminated swaps was $5.9 million, and the remaining net savings for all terminated swaps will be recognized over the following periods:


Remainder of 2005	$	1.7 million
2006	$	6.8 million
2007	$	6.6 million
2008	$	6.6 million
2009	$	5.6 million
Thereafter	$	20.8 million

Currently, $340 million of our fixed-rate debt is swapped to floating. The floating rate debt is based on both the three- and six-month London InterBank Offered Rate (LIBOR), depending upon the swap. At September 30, 2005, we recorded a net liability of $5.4 million to recognize the interest rate swaps at fair value. Long-term debt was decreased by $5.4 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 as cost of sales and fuel. The ineffectiveness related to these hedges was $1.7 million and $1.4 million for the three and nine months ended September 30, 2005, respectively. The ineffectiveness related to these hedges was immaterial for the three and nine months ended September 30, 2004.

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 gas. Accumulated other comprehensive loss at September 30, 2005, includes net losses of approximately $259.5 million, net of tax, related to these hedges that will be realized within the next 44 months. We will recognize $174.3 million in net losses over the next 12 months, and we will recognize net losses of $85.2 million thereafter. Our Gathering and Processing segment periodically enters into derivative instruments to hedge the cash flows

associated with our exposure to changes in the price of natural gas, NGLs and crude oil. Accumulated other comprehensive loss at September 30, 2005, which includes net losses of approximately $5.7 million, net of tax, related to these hedges, will be realized in the income statement primarily within the next 12 months. Our Natural Gas Liquids segment utilizes swaps to hedge our exposure to changes in the price of NGLs. Accumulated other comprehensive loss at September 30, 2005, which includes net losses of approximately $0.9 million, net of tax, related to these swaps, will be realized in the income statement in December 2005. These losses will be partially offset by the gains on the related physical sales that will be recognized in earnings at the time the derivative instruments are settled.

Net gains and losses are reclassified out of accumulated other comprehensive loss to operating revenues or cost of sales and fuel when the anticipated purchase or sale occurs. Ineffectiveness related to these cash flow hedges was a loss of approximately $7.0 million and a loss of approximately $7.1 million for the three and nine months ended September 30, 2005, respectively. Ineffectiveness related to these cash flow hedges for the three and nine months ended September 30, 2004, resulted in a gain of approximately $0.1 million and a loss of approximately $4.0 million, respectively. Additionally, losses of approximately $4.6 million were recognized from accumulated other comprehensive loss during the nine months ended September 30, 2004, due to the discontinuance of cash flow hedge treatment on certain transactions since it was probable that the forecasted transactions would not occur.

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 September 30, 2005, Kansas Gas Service had derivative instruments in place to hedge the cost of natural gas purchases for 8.9 Bcf, which represents part of its gas purchase requirements for the 2005/2006 winter heating months.

Prior to the issuance of the $800 million of notes in the second quarter of 2005, we entered into $500 million in treasury rate-lock agreements to hedge the changes in cash flows of our anticipated interest payments from changes in treasury rates prior to the issuance of the notes. Upon issuance of the notes in June 2005, the treasury rate-lock agreements terminated, which resulted in us paying $2.4 million. This amount, net of tax, has been recorded as accumulated other comprehensive loss and will be recognized in the income statement over the term of the related debt issuances.

E.	Regulatory Assets

The following table is a summary of regulatory assets, net of amortization, for the periods indicated.


	September 30, 2005		December 31, 2004
	*(Thousands of dollars)*
Recoupable take-or-pay	$	54,015	$	58,412
Postretirement costs other than pension		47,029		52,477
Reacquired debt costs		19,133		19,777
Deferred taxes		16,185		18,471
Transition costs		15,839		16,209
Pension costs		12,119		13,125
Weather normalization		10,961		9,936
Ad valorem tax		6,230		5,659
Service lines		—		1,517
Other		5,944		7,964

Regulatory assets, net	$	187,455	$	203,547

We amortize reacquired debt costs in accordance with the accounting rules prescribed by the Oklahoma Corporation Commission (OCC) and Kansas Corporation Commission (KCC). These costs were included as a component of interest in the rate order issued by the OCC on October 4, 2005, and were included in a previous rate order issued by the KCC.

The remaining amount of regulatory assets, net is being recovered through various rate cases with the exception of an immaterial amount, which we expect to eventually recover.

F.	Goodwill

In July 2005, we acquired the natural gas liquids businesses owned by Koch for approximately $1.33 billion, net of working capital and cash received. See Note B for additional information regarding this acquisition. The acquisition increased our mid-continent operating focus through a downstream extension of our natural gas gathering and processing operation. The assets acquired provide commercial, operational and administrative synergies as these assets enhance our existing mid-stream operating areas. This acquisition creates new and expanded commercial opportunities and we anticipate volumes and margins of our existing business to increase. Our gathering and processing assets were the second largest producer of NGLs on the system and all but one of our processing plants is connected to the system. Additionally, the acquisition improves our market access to the largest NGL hub, which is located in the gulf coast. As a result of our preliminary purchase price allocation, we assigned $1.2 billion to identifiable assets consisting of approximately $912.7 million to tangible assets based on the fair value of the net assets and approximately $325.6 million to identifiable intangible assets that will be amortized on a straight-line basis over the remaining useful lives of the assets, as determined by underlying contract terms or third-party appraisals. The excess of the purchase price over the fair value of identifiable assets acquired, net of liabilities assumed is $172.0 million which is recorded as goodwill.

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


	Balance December 31, 2004		Goodwill Acquired		Balance September 30, 2005
	*(Thousands of dollars)*
Gathering and Processing	$	34,343	$	—	$	34,343
Natural Gas Liquids		—		171,973		171,973
Pipelines and Storage		22,036				22,036
Energy Services		10,255		—		10,255
Distribution		158,554		—		158,554

Goodwill	$	225,188	$	171,973	$	397,161

G.	Intangibles

Intangible assets primarily relate to contracts acquired through the acquisition of the natural gas liquids businesses from Koch and based on the preliminary purchase price allocation are being amortized over our aggregate weighted-average period of 40 years. See Notes B and F for additional information regarding the acquisition that resulted in intangible assets. The aggregate amortization expense for each of the next five years is estimated to be approximately $8.1 million. The following tables reflect the gross carrying amount and accumulated amortization of intangibles at September 30, 2005.


	Intangibles, gross		Accumulated Amortization		Intangibles, net
	*(Thousands of dollars)*
Natural Gas Liquids	$	305,001	$	1,906	$	303,095
Pipelines and Storage		20,652		129		20,523

Intangibles	$	325,653	$	2,035	$	323,618


	Balance December 31, 2004		Amortization		Balance September 30, 2005
	*(Thousands of dollars)*
Natural Gas Liquids	$	—	$	1,906	$	1,906
Pipelines and Storage		—		129		129

Accumulated amortization	$	—	$	2,035	$	2,035

H.	Comprehensive Income

The tables below give an overview of comprehensive income for the periods indicated. The assumption of derivative instruments in the table below relates to the derivative instruments transferred to the buyer of our Production segment.


	Three Months Ended September 30,
	2005						2004
	*(Thousands of dollars)*
Net income				$	184,534					$	20,839
Unrealized losses on derivative instruments	$	(326,493	)				$	(101,688	)
Unrealized holding losses arising during the period		—						(136	)
Realized losses in net income		3,374						1,405
Assumption of derivative instruments related to sale of discontinued component		(18,915	)					—

Other comprehensive loss before taxes		(342,034	)					(100,419	)
Income tax benefit on other comprehensive loss		124,983						38,839

Other comprehensive loss					(217,051	)					(61,580	)

Comprehensive loss				$	(32,517	)				$	(40,741	)


	Nine Months Ended September 30,
	2005						2004
	*(Thousands of dollars)*
Net income				$	317,050					$	143,781
Unrealized losses on derivative instruments	$	(392,126	)				$	(144,480	)
Unrealized holding losses arising during the period		(606	)					(212	)
Realized (gains) losses in net income		(6,644	)					16,592
Assumption of derivative instruments related to sale of discontinued component		(18,915	)					—

Other comprehensive loss before taxes		(418,291	)					(128,100	)
Income tax benefit on other comprehensive loss		161,783						49,543

Other comprehensive loss					(256,508	)					(78,557	)

Comprehensive income				$	60,542					$	65,224

Accumulated other comprehensive loss at September 30, 2005 and 2004, primarily includes unrealized gains and losses on derivative instruments and minimum pension liability adjustments.

I.	Capital Stock

Stock Repurchase Plan - During the third quarter of 2005, we repurchased approximately 2.3 million shares of our common stock pursuant to a plan approved by our Board of Directors on January 20, 2005, bringing the total repurchased under the plan to 6.0 million shares. This plan allows us to purchase up to a total of 7.5 million shares of our common stock on or before January 20, 2007.

Dividends - Quarterly dividends paid on our common stock for shareholders of record as of the close of business on January 31, 2005, May 2, 2005, and July 29, 2005, were $0.25 per share, $0.28 per share and $0.28 per share, respectively. Additionally, a quarterly dividend of $0.28 per share was declared in September, payable in the fourth quarter of 2005.

J.	Lines of Credit and Short-Term Notes Payable

In June 2005, we entered into a $1.0 billion short-term bridge financing agreement. The interest rate is based, at our election, on either (i) the higher of prime or one-half of one percent above the Federal Funds Rate or (ii) the Eurodollar rate plus a set number of basis points based on our current long-term unsecured debt ratings by Moody’s Investors Service and Standard and Poor’s.

On July 1, 2005, we borrowed $1.0 billion under the short-term bridge financing agreement to assist in financing the acquisition of assets from Koch. See Note B for additional information about this acquisition. We funded the remaining acquisition cost through our commercial paper program. We anticipate permanent financing of the acquisition to come from a combination of proceeds from the sale of assets, such as our Production segment, our natural gas gathering and processing assets located in Texas and our Spring Creek power plant, proceeds from the February 2006 settlement of the purchase contracts that are part of our mandatory convertible equity units, and free cash flow. At September 30, 2005, we had lowered the commitment of outstanding indebtedness under the bridge financing agreement to $900.0 million. The reduction in indebtedness under our short-term bridge financing agreement is a result of a required prepayment due to the sale of our Production segment.

In July 2005, we amended our 2004 $1.0 billion five-year credit agreement to increase the limit on our debt-to-equity ratio from 67.5 percent debt to 70 percent debt for the period from July 25, 2005, to February 28, 2006. Beginning on March 1, 2006, the limit on our debt will return to 67.5 percent of total capital.

In September 2005, we exercised the accordion feature of our 2004 $1.0 billion five-year credit agreement to increase the commitment amounts by $200 million to a total of $1.2 billion. The interest rate payable under this five-year credit agreement is a floating rate calculated in the same manner as the $1.0 billion short-term bridge financing agreement. Additionally, we amended the five-year credit and the short-term bridge financing agreements to change the definition of Consolidated Net Worth to eliminate the effect of gains and losses recorded in accumulated other comprehensive income (loss) as a result of certain commodity hedging agreements. The effect of these amendments was to increase the amount of indebtedness we can incur while maintaining compliance with the covenants in those agreements that limit our debt-to-equity ratio.

Both the five-year credit agreement and short-term bridge financing agreement contain customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in our business, changes in the nature of our business, transactions with affiliates, the use of proceeds, a limit on our debt-to-equity ratio, a limit on investments in master limited partnerships and a covenant that prevents us from restricting our subsidiaries’ ability to pay dividends to ONEOK, Inc. At September 30, 2005, we were in compliance with all covenants.

We had $168.7 million in letters of credit outstanding at September 30, 2005.

K.	Long-Term Debt

We had 16.1 million mandatory convertible equity units outstanding at September 30, 2005. Each unit consists of two components, an equity purchase contract and a note (see Notes H and J of Notes to Consolidated Financial Statements in our 2004 Form 10-K for additional information). In November 2005, we will seek to remarket the notes and any cash received will be put into a treasury portfolio pledged as collateral against the purchase contracts. This action will have no effect on our liquidity. In February 2006, the purchase contracts require the holders of the mandatory convertible equity units to purchase our common stock. If the notes are successfully remarketed, we will receive $402.5 million and issue common shares of stock, the number of which will depend upon the average closing price of our common stock for the 20 trading days prior to the date of issuance. For more information, refer to our Prospectus Supplement dated January 23, 2003.

In June 2005, we issued $800 million of notes, comprised of $400 million in 10-year maturities with a coupon of 5.2 percent and $400 million in 30-year maturities with a coupon of 6.0 percent. The notes were issued under our shelf registration statement dated April 15, 2003. Proceeds from this debt issuance were used to repay commercial paper borrowings and for general corporate purposes.

In March 2005, we had $335 million of long-term debt mature. We funded payment of this debt with working capital and the issuance of commercial paper in the short-term market.

L.	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 September 30,						Pension Benefits Nine Months Ended September 30,
	2005			2004			2005			2004
	*(Thousands of Dollars)*
Components of Net Periodic Benefit Cost
Service cost	$	4,941		$	3,925		$	14,823		$	11,888
Interest cost		10,758			10,555			32,273			31,299
Expected return on assets		(14,927	)		(13,817	)		(44,780	)		(44,787	)
Amortization of unrecognized net asset at adoption		—			(78	)		—			(236	)
Amortization of unrecognized prior service cost		361			166			1,082			496
Amortization of loss		2,126			1,145			6,377			2,301

Net periodic benefit cost	$	3,259		$	1,896		$	9,775		$	961


	Postretirement Benefits Three Months Ended September 30,						Postretirement Benefits Nine Months Ended September 30,
	2005			2004			2005			2004
	*(Thousands of Dollars)*
Components of Net Periodic Benefit Cost
Service cost	$	1,765		$	1,411		$	5,294		$	4,534
Interest cost		3,567			3,329			10,702			10,229
Expected return on assets		(1,086	)		(966	)		(3,258	)		(2,845	)
Amortization of unrecognized net asset at adoption		864			864			2,592			2,592
Amortization of unrecognized prior service cost		118			24			354			73
Amortization of loss		1,617			998			4,852			4,289

Net periodic benefit cost	$	6,845		$	5,660		$	20,536		$	18,872

Contributions - Contributions of $1.0 million and $12.3 million were made to our pension plan and other postretirement benefit plan, respectively, for the nine months ended September 30, 2005. We presently anticipate our total 2005 contributions to be $1.8 million for the pension plan and $16.1 million for the other postretirement benefit plan.

M.	Commitments and Contingencies

Environmental - We are subject to multiple environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid wastes and hazardous material and substance management. These laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to the results of operations. If an accidental leak or spill of hazardous materials occurs from our lines or facilities in the process of transporting natural gas or NGLs or at any facility that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including investigation and clean-up costs, which could materially affect our results of operations and cash flow. In addition, emission controls required under the Federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial condition and results of operations.

We own or retain legal responsibility for the environmental conditions at 12 former manufactured gas sites in Kansas. Our expenditures for environmental evaluation and remediation to date have not been significant in relation to the results of operations, and there have been no material effects upon earnings during 2005 related to compliance with environmental regulations. See Note L in our Annual Report on Form 10-K for the year ended December 31, 2004, for additional discussion. There has been no material change to the status of the manufactured gas sites since December 31, 2004.

Yaggy Facility - The two class action lawsuits filed against us in connection with the natural gas explosions and eruptions of natural gas geysers that occurred at, and in the vicinity of, our Yaggy facility in January 2001, resulted in jury verdicts in September 2004. The jury awarded the plaintiffs in the residential class $5.0 million in actual damages, and the judge ordered the payment of $2.0 million in attorney fees and $0.6 million in expenses, all of which are covered by insurance. In the other class action relating to business claims, the jury awarded no damages. The jury rejected claims for punitive damages in both cases. On April 11, 2005, the court denied the plaintiffs’ motion for a new trial and denied a post-trial motion filed by defendants. We filed our notice of appeal of the residential class verdict and the attorney fee award. The cases have now been transferred to the Kansas Supreme Court for appeal. With the exception of appeals, all litigation regarding our Yaggy facility has been resolved.

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.

N.	Segments

Our business segments and the accounting policies of our business segments are the same as those described in Note N and the Summary of Significant Accounting Policies in our Annual Report on Form 10-K for the year ended December 31, 2004, 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. Our equity method investments do not represent operating segments. 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 report.

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

With the acquisition of assets from Koch on July 1, 2005, we formed a new operating segment called Natural Gas Liquids. This segment consists of our existing natural gas liquids marketing business, which was previously part of our Gathering and Processing segment, and the assets acquired from Koch excluding those natural gas liquids gathering and pipeline distribution assets regulated by the FERC, which have been transferred to our Pipelines and Storage segment. VESCO, also acquired as part of the asset acquisition, was added to our Gathering and Processing segment.

Segment results for the Gathering and Processing segment for all prior periods have been restated to reflect the transfer of our existing natural gas liquids marketing business to the Natural Gas Liquids segment. The segment formerly named Transportation and Storage has been renamed Pipelines and Storage in order to better describe the activities of the segment.

As discussed in Note D, at the beginning of the third quarter of 2004, we completed a reorganization of our Energy Services segment. We began accounting separately for the different types of revenue earned from these activities, with certain revenues accounted for on a gross rather than a net basis.

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


Three Months Ended September 30, 2005	Gathering and Processing			Natural Gas Liquids		Pipelines and Storage		Energy Services			Distribution			Other and Eliminations			Total
	*(Thousands of dollars)*
Sales to unaffiliated customers	$	86,079		$	851,669	$	21,355	$	1,897,038		$	316,021		$	9,429		$	3,181,591
Energy trading revenues, net		—			—		—		10,615			—			—			10,615
Intersegment sales		360,418			—		42,233		110,083						(512,734	)		—

Total Revenues	$	446,497		$	851,669	$	63,588	$	2,017,736		$	316,021		$	(503,305	)	$	3,192,206

Net margin	$	80,003		$	37,874	$	50,857	$	68,222		$	105,104		$	441		$	342,501
Operating costs		32,558			14,801		19,426		12,474			91,596			290			171,145
Depreciation, depletion and amortization		8,165			5,584		7,426		544			26,298			125			48,142

Operating income (loss)	$	39,280		$	17,489	$	24,005	$	55,204		$	(12,790	)	$	26		$	123,214

Income (loss) from operations of discontinued components	$	—		$	—	$	—	$	(32,909	)	$	—		$	13,390		$	(19,519	)
Income (loss) from equity investments	$	(221	)	$	—	$	182	$	—		$	—		$	2,861		$	2,822
Capital expenditures	$	1,149		$	2,779	$	5,021	$	—		$	39,069		$	13,939		$	61,957


Three Months Ended September 30, 2004	Gathering and Processing			Natural Gas Liquids		Pipelines and Storage		Energy Services			Distribution			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	60,378		$	329,682	$	10,914	$	998,784		$	247,659		$	(417	)	$	1,647,000
Energy trading revenues, net		—			—		—		17,411			—			—			17,411
Intersegment sales		286,413			—		25,464		91,863			—			(403,740	)		—

Total Revenues	$	346,791		$	329,682	$	36,378	$	1,108,058		$	247,659		$	(404,157	)	$	1,664,411

Net margin	$	74,087		$	10,284	$	28,443	$	18,116		$	88,626		$	290		$	219,846
Operating costs		31,827			2,921		12,236		6,882			79,711			(1,844	)		131,733
Depreciation, depletion and amortization		8,272			32		4,382		402			26,518			112			39,718

Operating income (loss)	$	33,988		$	7,331	$	11,825	$	10,832		$	(17,603	)	$	2,022		$	48,395

Income (loss) from operations of discontinued components	$	—		$	—	$	—	$	(469	)	$	—		$	4,757		$	4,288
Income from equity investments	$	—		$	—	$	262	$	—		$	—		$	—		$	262
Capital expenditures	$	5,136		$	3,364	$	3,685	$	558		$	43,732		$	21,458		$	77,933


Nine Months Ended September 30, 2005	Gathering and Processing			Natural Gas Liquids		Pipelines and Storage		Energy Services			Distribution		Other and Eliminations			Total
	*(Thousands of dollars)*
Sales to unaffiliated customers	$	210,206		$	1,464,026	$	50,073	$	4,816,867		$	1,433,945	$	(6,103	)	$	7,969,014
Energy trading revenues, net		—			—		—		11,023			—		—			11,023
Intersegment sales		981,780			—		96,900		487,248			—		(1,565,928	)		—

Total Revenues	$	1,191,986		$	1,464,026	$	146,973	$	5,315,138		$	1,433,945	$	(1,572,031	)	$	7,980,037

Net margin	$	227,132		$	52,194	$	112,193	$	140,666		$	412,816	$	(2,125	)	$	942,876
Operating costs		92,203			20,180		43,100		28,351			265,701		(3,415	)		446,120
Depreciation, depletion and amortization		24,983			5,644		16,240		1,535			86,301		349			135,052

Operating income	$	109,946		$	26,370	$	52,853	$	110,780		$	60,814	$	941		$	361,704

Income (loss) from operations of discontinued components	$	—		$	—	$	—	$	(34,307	)	$	—	$	28,495		$	(5,812	)
Income (loss) from equity investments	$	(221	)	$	—	$	818	$	—		$	—	$	7,875		$	8,472
Total assets	$	1,398,006		$	1,589,905	$	1,048,879	$	3,105,229		$	2,661,119	$	559,317		$	10,362,455
Capital expenditures	$	21,518		$	8,065	$	9,807	$	159		$	103,078	$	47,303		$	189,930


Nine Months Ended September 30, 2004	Gathering and Processing			Natural Gas Liquids		Pipelines and Storage		Energy Services			Distribution		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	175,704		$	867,293	$	36,160	$	1,046,437		$	1,337,475	$	(327,954	)	$	3,135,115
Energy trading revenues, net		—			—		—		106,583			—		—			106,583
Intersegment sales (a)		788,667			—		75,700		91,863			—		(956,230	)		—

Total Revenues	$	964,371		$	867,293	$	111,860	$	1,244,883		$	1,337,475	$	(1,284,184	)	$	3,241,698

Net margin	$	188,946		$	18,410	$	85,421	$	105,945		$	395,612	$	(3,995	)	$	790,339
Operating costs		86,835			6,934		36,076		24,669			251,516		(7,892	)		398,138
Depreciation, depletion and amortization		24,382			88		12,938		1,192			78,669		736			118,005

Operating income	$	77,729		$	11,388	$	36,407	$	80,084		$	65,427	$	3,161		$	274,196

Income (loss) from operations of discontinued components	$	—		$	—	$	—	$	(2,200	)	$	—	$	15,838		$	13,638
Income (loss) from equity investments	$	—		$	—	$	861	$	—		$	—	$	(59	)	$	802
Total assets	$	1,067,434		$	195,289	$	801,266	$	1,735,853		$	2,543,513	$	80,981		$	6,424,336
Capital expenditures	$	14,120		$	4,337	$	7,696	$	1,372		$	106,332	$	58,478		$	192,335

(a) -

Intersegment sales for Energy Services were $327.3 million for the six months ended September 30, 2004. These are included in energy trading revenues, net above.

O.	Supplemental Cash Flow Information

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


	Nine Months Ended September 30,
	2005		2004
	*(Thousands of dollars)*
Cash paid during the period
Interest, including amounts capitalized	$	141,868	$	13,115
Income taxes	$	55,797	$	106,775

Cash paid (received) for interest includes swap terminations, treasury rate-lock terminations and ineffectiveness of $22.6 million and $(82.9) million for the nine months ended September 30, 2005 and 2004, respectively.

P.	Earnings Per Share Information

We compute earnings per common share (EPS) as described in Note R of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2004.

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


	Three Months Ended September 30, 2005
	Income		Shares	Per Share Amount
	*(Thousands, except per share amounts)*
Basic EPS
Income from continuing operations available for common stock	$	52,698	99,894	$	0.53
Diluted EPS
Effect of other dilutive securities:
Mandatory convertible units		—	7,515
Options and other dilutive securities		—	1,193

Income from continuing operations available for common stock and common stock equivalents	$	52,698	108,602	$	0.49


	Three Months Ended September 30, 2004
	Income		Shares	Per Share Amount
	*(Thousands, except per share amounts)*
Basic EPS
Income from continuing operations available for common stock	$	16,551	102,914	$	0.16
Diluted EPS
Effect of other dilutive securities:
Mandatory convertible units		—	3,236
Options and other dilutive securities		—	792

Income from continuing operations available for common stock and common stock equivalents	$	16,551	106,942	$	0.15


	Nine Months Ended September 30, 2005
	Income		Shares	Per Share Amount
	*(Thousands, except per share amounts)*
Basic EPS
Income from continuing operations available for common stock	$	171,507	101,568	$	1.69
Diluted EPS
Effect of other dilutive securities:
Mandatory convertible units		—	6,884
Options and other dilutive securities		—	1,103

Income from continuing operations available for common stock and common stock equivalents	$	171,507	109,555	$	1.56


	Nine Months Ended September 30, 2004
	Income		Shares	Per Share Amount
	*(Thousands, except per share amounts)*
Basic EPS
Income from continuing operations available for common stock	$	130,143	101,530	$	1.28
Diluted EPS
Effect of other dilutive securities:
Mandatory convertible units		—	1,893
Options and other dilutive securities		—	657

Income from continuing operations available for common stock and common stock equivalents	$	130,143	104,080	$	1.25

There were 21,681 and 8,997 option shares excluded from the calculation of diluted EPS for the three months ended September 30, 2005, and 2004, respectively, since their inclusion would be antidilutive for each period. For the nine months ended September 30, 2005, and 2004, there were 48,062 and 14,711 option shares, respectively, excluded from the calculation of diluted EPS since their inclusion would be antidilutive for each period.

Item 2.

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

Executive Summary - Operating income for our third quarter of 2005 was $123.2 million, an increase of $74.8 million, or 155 percent, compared with the same period in 2004. For the first nine months of 2005, operating income was $361.7 million, an increase of $87.5 million, or 32 percent, from the same period last year.

Diluted earnings per share of common stock from continuing operations (EPS) increased to 49 cents for the third quarter of 2005 from 15 cents for the same period in 2004. For the nine-month period, EPS increased to $1.56 for 2005 from $1.25 in 2004.

Our Energy Services segment benefited from increases in natural gas prices and volatility during the third quarter of 2005. An increase of $54.6 million and $29.6 million for the three- and nine-month periods, respectively, was due to storage and transportation activities primarily attributable to opportunities to realize higher margins from selling natural gas from storage due to increases in natural gas prices and volatility, and gains associated with the increase in basis spreads on financial instruments used to hedge purchases and sales associated with storage activities.

Favorable energy prices also had a significant impact on our Gathering and Processing segment’s results during the nine-month period for 2005. Average prices for natural gas, natural gas liquids (NGLs) and crude oil exceeded prices for the same period in 2004. The gross processing spread was also higher in 2005 and continued to exceed the previous five-year average. The effect of these higher prices increased our Gathering and Processing segment’s operating income 16 percent for the quarter and 41 percent for the nine-month period, compared with the same periods in 2004.

On July 1, 2005, we completed the acquisition of the natural gas liquids businesses owned by several affiliates and a subsidiary of Koch Industries, Inc. (Koch). The results of operations for these acquired assets accounted for increases in both our Natural Gas Liquids segment and our Pipelines and Storage segment.

On October 4, 2005, the Oklahoma Corporation Commission (OCC) issued a final order on our application for a rate increase by Oklahoma Natural Gas. The OCC unanimously approved an annual rate increase of $57.5 million. In July, the Commission’s administrative law judge recommended an increase in annual revenues of approximately $58.0 million. Oklahoma Natural Gas implemented new rates, subject to refund, on July 28, 2005, based on the judge’s report.

Discontinued Operations - In September 2005, we completed the sale of our Production segment to TXOK Acquisition, Inc. for $645 million, before adjustments. We recognized a pre-tax gain on the sale of the discontinued component for our Production segment of approximately $243.2 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.

Additionally, in the third quarter of 2005 we made the decision to sell our Spring Creek power plant and exit the power generation business. In October 2005, we concluded that our Spring Creek power plant located in southwest Oklahoma had been impaired and recorded an impairment expense of $52.2 million. This conclusion was based on our impairment analysis of the results of operations for this plant through September 30, 2005, and also considered net sales proceeds from a sale of the plant. In October 2005, we entered into an agreement to sell our Spring Creek power plant to Westar Energy, Inc. for $53 million. The transaction requires Federal Energy Regulatory Commission (FERC) approval and is expected to be completed in 2006. The 300-megawatt gas-fired merchant power plant was built in 2001 to supply electrical power during peak periods using gas-powered turbine generators. The proceeds from this sale will be used to purchase other assets, repurchase ONEOK shares or retire debt.

These components of our business are accounted for as discontinued operations in accordance with Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144). Accordingly, amounts in our financial statements and related notes for all periods shown relating to our Production segment and our power generation business are reflected as discontinued operations. The 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.

Acquisition - On July 1, 2005, we completed the acquisition of the natural gas liquids businesses owned by Koch for approximately $1.33 billion, net of working capital and cash received. This transaction includes Koch Hydrocarbon, LP’s entire mid-continent natural gas liquids fractionation business; Koch Pipeline Company, L.P.’s natural gas liquids pipeline distribution systems; Chisholm Pipeline Holdings, Inc., which has a 50 percent ownership interest in Chisholm Pipeline Company; MB1/LP, LLC (formerly MBFF, LP), which owns an 80 percent interest in the 160,000 barrel per day fractionator at Mont Belvieu, Texas;

and Koch Vesco Holdings, LLC, an entity that owns a 10.2 percent interest in Venice Energy Services Company, LLC (VESCO). These assets are included in our consolidated financial statements beginning on July 1, 2005.

The acquisition was initially financed through our $1.0 billion short-term bridge financing agreement, which we entered into in June 2005, and our commercial paper program. We anticipate permanent financing of the acquisition to come from a combination of the proceeds from the settlement of our mandatory convertible equity units in February 2006, proceeds from the sale of less strategic assets and free cash flow.

Divestiture - In October 2005, we entered into an agreement to sell certain natural gas gathering and processing assets located in Texas to a subsidiary of Eagle Rock Energy, Inc. for approximately $528 million. The transaction is expected to close December 1, 2005, and is subject to Hart-Scott-Rodino antitrust clearance. The properties are located in the Texas panhandle and include six gas processing plants, operating at approximately 60 percent of 160 million cubic foot per day capacity with 3,700 miles of gas gathering lines, and estimated NGL production of 13,500 barrels per day. The proceeds from this sale will be used to purchase other assets, repurchase ONEOK shares or retire debt.

Regulatory - Several regulatory initiatives positively impacted the earnings and future earnings potential for our Distribution segment. These initiatives are discussed beginning on page 41.

Impact of New Accounting Standards - In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 123R, “Share-Based Payment” (Statement 123R). Statement 123R requires companies to expense the fair value of share-based payments. In addition, there are also changes related to the expense calculation for share-based payments. Effective January 1, 2006, we will adopt Statement 123R, and we expect to use the prospective method. We are currently assessing the impact of adopting Statement 123R, but we do not believe it will have a material impact on our financial condition and results of operations, 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” on January 1, 2003.

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), that requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. FIN 47 is effective for our year ending December 31, 2005. We are currently reviewing the applicability of FIN 47 to our operations and its potential impact on our consolidated financial statements.

In June 2005, the FASB ratified the consensus reached in EITF Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights” (EITF 04-5). EITF 04-5 presumes that a general partner controls a limited partnership and therefore should consolidate the partnership. Effective January 1, 2006, we will be required to consolidate Northern Border Partners’ operations in our consolidated financial statements. We are currently evaluating the impact of adopting EITF 04-5. However, had we consolidated Northern Border Partners at September 30, 2005, our debt to equity ratio would have changed from 72 percent debt and 28 percent equity to 78 percent debt and 22 percent equity. This increase results from the consolidation of Northern Border Partners’ debt of $1.3 billion at September 30, 2005, while their equity is reported as minority interest in partners’ equity. The debt covenant calculations in our credit agreements exclude the debt of Northern Border Partners, since it is a master limited partnership.

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 are currently reviewing the applicability of EITF 04-13 to our operations and its potential impact on our consolidated financial statements.

Critical Accounting Policies and Estimates

Derivatives and Risk Management Activities - We engage in wholesale energy marketing, retail marketing, trading and risk- management activities. We account for derivative instruments utilized in connection with these activities and services under the fair value basis of accounting in accordance with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133), as amended.

Under Statement 133, entities are required to record derivative instruments at fair value. The fair value of derivative instruments is determined by commodity exchange prices, over-the-counter quotes, volatility, time value, counterparty credit and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions. Refer to the table on page 47 for amounts in our portfolio at September 30, 2005, 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 value is 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 crude oil prices, we periodically enter into derivative transactions to hedge anticipated sales and purchases of natural gas, NGLs, crude oil, fuel requirements and transportation firm commitments. 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 value or cash flows. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings in the period of change together with the offsetting gain or loss 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 income and is subsequently reclassified into earnings when the forecasted transaction affects earnings. Any ineffectiveness of designated hedges is reported in earnings in the period incurred.

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. Energy-related contracts that are not derivatives pursuant to Statement 133 are accounted for on an accrual basis as executory contracts.

Impairment of Goodwill and Long-Lived Assets - We assess our goodwill for impairment at least annually based on Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (Statement 142). An initial assessment is made by comparing the fair value of each reporting unit with goodwill, as determined in accordance with Statement 142, to the book value of the 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. We completed our annual analysis of goodwill for impairment as of January 1, 2005, and there was no impairment indicated. At September 30, 2005, we had $397.2 million of goodwill recorded on our balance sheet.

We assess our long-lived assets for impairment based on Statement 144. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.

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,

•

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 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.

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

Pension and Postretirement Employee Benefits - We have a defined benefit pension plan covering substantially all full-time employees and a postretirement employee benefits plan covering some 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.

We use September 30 as the measurement date for our annual actuarial study related to our defined benefit pension plan and our postretirement benefit plan. We currently anticipate using a discount rate of 5.75 percent to estimate our 2006 expense and liability related to these plans. We have not completed our current actuarial study, however, the impact of using a discount rate of 5.75 percent, compared to 6.00 percent in our prior year study, will generally cause our expense for 2006 to increase compared to our expense recorded for 2005.

During 2004, we recorded net periodic benefit costs of $0.9 million related to our defined benefit pension plan and $25.0 million related to postretirement benefits. We estimate that in 2005 we will record net periodic benefit costs of $13.0 million related to our defined benefit pension plan and $27.4 million related to postretirement benefits. These increases primarily relate to Northern Plains’, our subsidiary which provides services to Northern Borders Partners, amendments in benefits payable under our gas union contracts and a change in our assumed discount rate. See Note L of Notes to Consolidated Financial Statements in this Form 10-Q.

Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal exposures and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies.” We base our estimates on currently available facts and our estimates of the ultimate outcome or resolution. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings.

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

Consolidated Operations

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


	Three Months Ended September 30,					Nine Months Ended September 30,
	2005			2004		2005			2004
	*(Thousands of dollars)*
Financial Results
Operating revenues, excluding energy trading revenues	$	3,181,591		$	1,647,000	$	7,969,014		$	3,135,115
Energy trading revenues, net		10,615			17,411		11,023			106,583
Cost of sales and fuel		2,849,705			1,444,565		7,037,161			2,451,359

Net margin		342,501			219,846		942,876			790,339
Operating costs		171,145			131,733		446,120			398,138
Depreciation, depletion and amortization		48,142			39,718		135,052			118,005

Operating income	$	123,214		$	48,395	$	361,704		$	274,196

Other income	$	7,250		$	1,636	$	16,486		$	11,154
Other expense	$	3,365		$	1,322	$	8,087		$	9,754

Discontinued operations, net of taxes:
Income (loss) from operations of discontinued components, net	$	(19,519	)	$	4,288	$	(5,812	)	$	13,638
Gain on sale of discontinued component, net	$	151,355		$	—	$	151,355		$	—

Operating Results - Net margin increased for the three and nine months ended September 30, 2005, compared with the same periods in 2004 primarily due to:

•

the effect of increased natural gas prices and higher volatility in our Energy Services segment,

•

the effect of the natural gas liquids assets acquired from Koch in our Natural Gas Liquids segment and our Pipelines and Storage segment,

•

the favorable commodity pricing for natural gas and NGL products on our Gathering and Processing segment, and

•

the implementation of new rate schedules in Oklahoma for our Distribution segment.

For an explanation of energy trading revenues, net, see the discussion of our Energy Services segment beginning on page 36.

Consolidated operating costs increased for the three- and nine-month periods primarily due to the costs related to the natural gas liquids assets acquired from Koch and increased employee benefit costs.

Depreciation, depletion and amortization increased for the three- and nine-month periods primarily due to the costs associated with the natural gas liquids assets acquired from Koch. Additionally, depreciation, depletion and amortization increased for the nine-month period due to a charge related to the replacement of our customer service system in Texas and regulatory asset amortization resulting from the Kansas rate case, both in our Distribution segment.

The following tables show the components of other income and other expense for the periods indicated.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005		2004
	*(Thousands of dollars)*
Equity income	$	2,822		$	262		$	8,472	$	802
Gain on sale of assets		4,463			1,158			4,754		9,765
Income (expense) from benefit plan investments		906			112			1,585		(609	)
Interest income		303			358			1,008		810
Other		213			(254	)		385		386
Realized gain on investment		282			—			282		—
Unrealized loss on investment		(1,739	)		—			—		—

Other Income	$	7,250		$	1,636		$	16,486	$	11,154


	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	*(Thousands of dollars)*
Litigation expense and claims, net	$	2,416	$	317	$	4,962	$	7,537
Donations, civic, and governmental		771		455		1,798		1,570
Loss on sale of assets		—		420		818		420
Other		178		130		509		227

Other Expense	$	3,365	$	1,322	$	8,087	$	9,754

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

Gathering and Processing

Overview - Our Gathering and Processing segment is engaged in the gathering and processing of natural gas and fractionation of NGLs primarily in Oklahoma, Kansas and Texas. We own approximately 13,900 miles of gathering pipelines that supply our gas processing plants. We have active processing capacity of approximately 1.8 Bcf/d and NGL fractionation capacity of 89 MBbls/d.

Our operations include the gathering of natural gas production from oil and natural gas wells. Through gathering systems, these volumes are aggregated into sufficient volumes to be 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. Some of this stream is then separated by a distillation process, referred to as fractionation, into component products (ethane, propane, isobutane, normal butane and natural gasoline) by company-owned fractionation facilities. The component products can then be stored, transported and/or marketed to a diverse customer base of end users.

We generally gather and process gas under three types of contracts:

•

Keep Whole - We extract NGLs and return to the producer volumes of merchantable natural gas containing the same amount of Btus as the raw natural gas that the producer delivered to us.

•

Percent of Proceeds (POP) - We retain a percentage of the NGLs and/or a percentage of the natural gas as payment for gathering, compressing and processing the producer’s raw natural gas.

•

Fee - We are paid a fee for the services provided such as Btus gathered, compressed, treated and/or processed.

Contracts covering approximately 29 percent of the volumes associated with our keep whole contracts allow us to charge conditioning fees for processing, in the event the keep whole spread is negative. This helps mitigate the impact of an unfavorable keep whole spread by effectively converting a keep whole contract to a fee contract during periods of negative keep whole spread. Our effort to add this conditioning language is a strategy that we continue to execute. We are also continuing our strategy of renegotiating any under-performing gas purchase and gathering contracts.

Additionally, we have the ability to adjust plant operations to take advantage of market conditions. By changing the temperatures and pressures at which the gas is processed, we can produce more of the specific commodities that have the most favorable prices or price spread.

We are impacted by producer drilling activity, which is sensitive to geological success as well as availability of capital and commodity prices. The mid-continent region is currently experiencing a significant upturn in oil and gas drilling activity. This resurgence in drilling activity has been driven by increased prices for natural gas, crude oil and by the long-term projections of continued demand for natural gas. We are exposed to volume risk from both a competitive and a production standpoint. We continue to see production declines in certain fields that supply our gathering and processing operations, and the possibility exists that declines may surpass development from new drilling.

For more discussion of our gathering and processing operations, including factors that affect our ability to compete, see our Form 10-K for the year ended December 31, 2004.

Acquisition - The following acquisition is discussed beginning on page 25.

•

On July 1, 2005, we acquired Koch Vesco Holdings, LLC, an entity which owns a 10.2 percent interest in Venice Energy Services Company, LLC (VESCO). VESCO owns a gas processing complex near Venice, Louisiana.

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


	Three Months Ended September 30,					Nine Months Ended September 30,
	2005			2004		2005			2004
	*(Thousands of dollars)*
Financial Results
Natural gas liquids and condensate sales	$	192,658		$	156,297	$	505,591		$	413,327
Gas sales		228,831			166,770		613,377			483,029
Gathering, compression, dehydration and processing fees and other revenues		25,008			23,724		73,018			68,015
Cost of sales and fuel		366,494			272,704		964,854			775,425

Net margin		80,003			74,087		227,132			188,946
Operating costs		32,558			31,827		92,203			86,835
Depreciation, depletion and amortization		8,165			8,272		24,983			24,382

Operating income	$	39,280		$	33,988	$	109,946		$	77,729

Other income (expense), net	$	(849	)	$	356	$	(1,571	)	$	124


	Three Months Ended September 30,					Nine Months Ended September 30,
	2005			2004		2005			2004
Operating Information
Total gas gathered (MMMBtu/d)		1,093			1,099		1,111			1,106
Total gas processed (MMMBtu/d)		1,141			1,175		1,139			1,162
Natural gas liquids sales (MBbls/d)		52			53		51			51
Natural gas liquids produced (MBbls/d)		62			64		62			61
Gas sales (MMMBtu/d)		338			330		344			325
Capital expenditures (Thousands of dollars)	$	1,149		$	5,136	$	21,518		$	14,120
Conway OPIS composite NGL price ($/gal) (based on our NGL product mix)	$	0.98		$	0.76	$	0.84		$	0.68
Average NYMEX crude oil price ($/Bbl)	$	60.36		$	42.28	$	53.40		$	38.41
Average realized condensate sales price ($/Bbl)	$	59.66		$	40.13	$	51.69		$	35.87
Average natural gas price ($/MMBtu) (mid-continent region)	$	7.35		$	5.43	$	6.44		$	5.38
Gross processing spread ($/MMBtu)	$	3.62		$	3.07	$	3.05		$	2.17

Operating Results - The financial and operating results above have been restated to reflect the transfer of the natural gas liquids marketing business that was previously included in our Gathering and Processing segment to our new Natural Gas Liquids segment.

The increase in net margin for the three month period is primarily due to an increase of $8.3 million attributable to higher natural gas and NGL prices on our POP contracts, net of hedging activities. This increase was offset by a decrease of $1.5 million due to less volume processed as a result of natural production declines and contract expirations.

The increase in net margin for the nine months ended September 30, 2005, compared with the same periods for 2004, is primarily due to:

•

an increase of $21.5 million due to higher natural gas and NGL prices on our POP contracts, net of hedges,

•

an increase of $12.0 million attributable to our keep whole contracts due primarily to an increase in our gross processing spread, net of hedging, and

•

an increase of $6.1 million due primarily to natural gas volume increases as certain natural gas producers elected to convert their contracts from keep whole to either fee or POP.

The gross processing spread for the three and nine months ended September 30, 2005, which is the relative difference in economic value between NGLs and natural gas on a Btu basis, was higher than the previous five-year average of $1.78. The gross processing spread in the third quarter of 2005 was $3.62 per MMBtu versus $3.07 per MMBtu in the third quarter of 2004; however, it had a minimal impact on margins because of hedging activities. Improved contractual terms for gas gathering and processing resulting from our continued efforts to renegotiate under-performing gas purchase, gas processing and gathering contracts, continue to positively impact net margin.

The increase in operating costs for both the three- and nine-month periods is primarily due to an increase of $0.6 million and $1.7 million, respectively, in materials, supplies and utilities related to compressor utilization and maintenance. The remaining increase is associated with higher employee-related costs.

The decrease in other income (expense) for both the three- and nine-month periods is partially due to the accrual of a $0.5 million insurance deductible associated with VESCO. The Venice, Louisiana plant suffered damage in August 2005 from Hurricane Katrina and is not currently operating. Management expects that insurance payments from our carriers will cover the remaining costs associated with repairing the damage to the facility. The facility is currently expected to be repaired and back in service during the first quarter of 2006.

The increase in capital expenditures for the nine-month period is primarily related to additional compression expenditures and growth activities.

In October 2005, we entered into an agreement to sell certain natural gas gathering and processing assets located in Texas. See page 26 for additional information. The impact of these assets on our Gathering and Processing segment’s operating income for the three and nine months ended September 30, 2005, was $14.0 million and $32.5 million, respectively.

Risk Management - We use derivative instruments to minimize the risks associated with price volatility. The realized financial impact of the derivative transactions is included in our operating income in the period that the physical transaction occurs.

The following tables set forth our remaining 2005 and 2006 hedging information for our Gathering and Processing segment.


	Three Months Ending December 31, 2005
Product	Volumes Hedged	Average Price
Percent of Proceeds:
Condensate (a)	135 MBbls	$	43.71/Bbl
NGL (b)	150 MBbls	$	0.74/gal
Natural gas (c)	1.6 Bcf	$	6.41/MMBtu
Keep Whole:
Gross processing spread (d)	2,215 MMBtu	$	3.23/MMBtu

(a)	- Hedged with NYMEX-based swaps.

(b)	- Hedged with forward sales and swaps.

(c)	- Hedged with NYMEX futures and basis swaps.

(d)	- Hedged with NYMEX futures, basis swaps and NGL forward sales.


	Year Ending December 31, 2006
Product	Volumes Hedged	Price
Percent of Proceeds:
Condensate (a)	300 MBbls	$	52.00-60.00/Bbl
Natural gas (a)	1.9 Bcf	$	6.15-11.00/MMBtu
Natural gas (b)	0.5 Bcf	$	9.76/MMBtu

(a)	- Hedged with NYMEX-based costless collars.

(b)	- Hedged with NYMEX futures and basis swaps.

We continue to evaluate market conditions to take advantage of favorable pricing opportunities associated with our POP contracts, as well as our keep whole quantities.

See Item 3, Quantitative and Qualitative Disclosures About Market Risk and Note D of the Notes to Consolidated Financial Statements in this Form 10-Q.

Natural Gas Liquids

Overview - Our Natural Gas Liquids segment primarily gathers, fractionates and treats raw NGLs produced from gas processing plants located in Oklahoma, Kansas and the Texas panhandle. We own and operate, or ship through affiliated companies, approximately 4,600 miles of gathering and distribution lines with gathering capacity of 277 MBbls/d and distribution capacity of 360 MBbls/d. Our gathering lines are connected to approximately 90 percent of the natural gas processing plants located in the mid-continent producing areas.

Most natural gas produced at the wellhead contains a mixture of NGL components such as ethane, propane, 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.

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 pure marketable products, such as ethane/propane mix, propane, iso-butane, normal butane and natural gasoline (collectively, NGL products). We have approximately 380 MBbls/d of fractionation capacity through our ownership or interest in four different facilities. These NGL products are then stored and/or distributed to petrochemical, heating and motor gasoline end users. Our fractionation and storage facilities are centrally located and provide flexible redelivery of NGL products to the two primary U.S. NGL market centers, Conway, Kansas and Mont Belvieu, Texas. We have the ability to satisfy our customer redelivery requests to these two market centers, and through our own account we can also market our NGL products to the highest value locations. We own or lease approximately 20.4 MMBbls of storage capacity in the mid-continent and gulf coast regions.

Our Natural Gas Liquids segment focuses on increasing market value of NGL products through use of our natural gas liquids assets. We are engaged in three primary business activities downstream of the natural gas gathering and processing segment.

•

Exchange Services – We provide gathering, fractionation, transportation, storage and treating of NGLs through term, fee-based exchange contracts. Under a typical fee-based exchange contract, we provide bundled services that include gathering and transporting raw NGLs to our fractionators, separating them into marketable products and redelivering the NGL products.

•

Optimization and Marketing – We use our asset base, portfolio of contracts and market knowledge to capture location price spreads through transactions that optimize the flow of our NGL products between the major U.S. market hubs in Conway, Kansas and Mont Belvieu, Texas. Optimization activities include redirecting NGL products to their highest value locations. In the mid-continent area, we purchase approximately two-thirds of our customers’ raw products on an index pricing basis, less an exchange fee. Additionally, we own and lease storage facilities in the mid-continent and gulf coast areas to capture seasonal price variances.

•

Isomerization – We own an isomerization unit in Conway, Kansas, with a capacity of 9 MBbls/d that converts normal butane to the more valuable iso-butane used by the refining industry to upgrade the octane of motor gasoline.

We are impacted by producer drilling activity, which is sensitive to geological success as well as availability of capital and commodity prices. The mid-continent region is currently experiencing a significant upturn in oil and gas drilling activity. This resurgence in drilling activity has been driven primarily by increased prices for natural gas and crude oil and by long-term projections of continued demand in the U.S. natural gas market. We continue to see production declines in certain fields that supply the gathering and processing facilities in our operating region and the possibility exists that declines may surpass development from new drilling. The factors that typically affect our ability to compete for NGL supplies are:

•

location of natural gas processing plants relative to our gathering pipelines,

•

location of our gathering pipelines relative to our competitors,

•

location of our fractionation facilities relative to our competitors,

•

efficiency, reliability and costs of operations including fuel and power consumption,

•

available fractionation and pipeline capacity, and

•

delivery capabilities to move NGL products to their highest value locations.

The main factors that affect our margins are:

•

transportation and fractionation volumes and associated fees,

•

commodity and regional pricing differences,

•

fees charged for storage, and

•

fees for marketing services.

Acquisition - The following acquisition is discussed beginning on page 25.

•

On July 1, 2005, we acquired the NGL businesses owned by Koch.

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


	Three Months Ended September 30,					Nine Months Ended September 30,
	2005		2004			2005			2004
	*(Thousands of dollars)*
Financial Results
Natural gas liquids and condensate sales	$	810,703	$	325,883		$	1,413,308		$	858,905
Storage and fractionation revenues		40,966		3,799			50,718			8,388
Cost of sales		813,795		319,398			1,411,832			848,883

Net margin		37,874		10,284			52,194			18,410
Operating costs		14,801		2,921			20,180			6,934
Depreciation, depletion and amortization		5,584		32			5,644			88

Operating income	$	17,489	$	7,331		$	26,370		$	11,388

Other income (expense), net	$	163	$	(44	)	$	64		$	(101	)


	Three Months Ended September 30,					Nine Months Ended September 30,
	2005		2004			2005			2004
Operating Information
Natural gas liquids gathered (MBbls/d)		193		—			(a	)		—
Natural gas liquids sales (MBbls/d)		201		108			129			107
Natural gas liquids fractionated (MBbls/d)		309		—			(a	)		—
Capital expenditures (Thousands of dollars)	$	2,779	$	3,364		$	8,065		$	4,337

(a) -

Data not meaningful as the acquisition of these assets was completed July 1, 2005.

Operating Results - The results of operations for 2004 shown above are related to the natural gas liquids marketing business that was previously included in our Gathering and Processing segment. The increases for both the three- and nine-month periods are primarily related to the natural gas liquids assets acquired from Koch in July 2005. The increases associated with the acquisition for both the three- and nine-month periods include:

•

an increase in net margin of $27.2 million,

•

an increase in operating costs of $11.2 million, and

•

an increase in depreciation, depletion and amortization of $5.0 million.

The remaining net margin increase for both the three- and nine-month periods is primarily related to increased storage margins of $1.1 million and $4.8 million, respectively, from restructured storage contracts. Additionally, net margin also increased $1.9 million for the nine-month period as a result of higher NGL prices, driven primarily by higher marketing fees from increased NGL prices.

Increased storage regulatory compliance costs resulted in an additional $2.0 million in operating costs for the nine-month period in 2005 compared with 2004.

Pipelines and Storage

Overview - Our Pipelines and Storage segment, formerly known as Transportation and Storage, operates our intrastate natural gas transmission pipelines, natural gas storage, regulated natural gas liquids gathering and distribution pipelines and nonprocessable natural gas gathering facilities. We also provide interstate transportation service under Section 311(a) of the Natural Gas Policy

Act. We own or reserve capacity in five storage facilities in Oklahoma, three in Kansas and three in Texas, with a combined working capacity of approximately 59.6 Bcf, of which 8.0 Bcf is temporarily idle. The natural gas liquids gathering and distribution pipelines are interstate pipelines regulated by FERC and transport raw NGLs and NGL products pursuant to filed tariffs.

We operate approximately 5,600 miles of natural gas gathering and intrastate transmission pipelines in Oklahoma, Kansas and Texas, where we are regulated by the OCC, Kansas Corporation Commission (KCC) and Texas Railroad Commission (RRC), respectively. We have a peak transportation capacity of 2.9 Bcf/d. The majority of our revenues are derived from services provided to affiliates. We primarily serve local distribution companies (LDCs), large industrial companies, irrigation, power generation facilities and marketing companies. We compete directly with other interstate and intrastate pipelines and storage facilities. Competition for transportation services continues to increase as the FERC and state regulatory bodies continue to encourage more competition in the natural gas markets. Factors that affect competition are location, natural gas prices, fees for services and quality of service provided.

Following our acquisition of the Koch natural gas liquids assets in July 2005, we operate approximately 2,500 miles of regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas and Texas. Our natural gas liquids gathering system delivers raw NGLs gathered from gas processing plants located in these states to fractionation facilities in Medford, Oklahoma. Our NGL distribution pipelines move products from fractionators in Oklahoma and Kansas to market points in Conway, Kansas and Mont Belvieu, Texas. These pipelines are operated under the guidance and oversight of various governmental agencies including programs mandated by the OCC, the KCC, FERC, and other various state and governmental agencies. All of these NGL gathering and distribution pipelines are subject to tariff.

Our Pipeline and Storage segment is affected by the economy, natural gas price volatility and weather. The strength of the economy has a direct relationship on manufacturing and industrial companies and their resulting demand for natural gas and NGL components. Volatility in the natural gas market also impacts our customers’ decisions relating to injection and withdrawal of natural gas in storage. In addition, our NGL gathering pipelines are affected by operational or market driven changes in the output of the processing plants to which we are connected. Processing plant output may increase or decrease as a result of the relative value of natural gas to NGL prices. In addition, volume delivered through the system may increase or decrease as a result of the relative NGL price between the mid-continent and gulf coast regions. Natural gas transportation throughput fluctuates due to rainfall that impacts irrigation demand, hot temperatures that affect power generation demand and cold temperatures that affect heating demand.

Acquisition - The following acquisition is discussed beginning on page 25.

•

On July 1, 2005, the Pipelines and Storage segment acquired the FERC regulated assets that were part of our acquisition of the NGL businesses owned by Koch.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	*(Thousands of dollars)*
Financial Results
Transportation and gathering revenues	$	48,159	$	24,615	$	104,079	$	75,186
Storage revenues		12,181		10,575		36,948		32,828
Gas sales and other revenues		3,248		1,188		5,946		3,846
Cost of sales and fuel		12,731		7,935		34,780		26,439

Net margin		50,857		28,443		112,193		85,421
Operating costs		19,426		12,236		43,100		36,076
Depreciation, depletion and amortization		7,426		4,382		16,240		12,938

Operating income	$	24,005	$	11,825	$	52,853	$	36,407

Other income (expense), net	$	262	$	238	$	821	$	2,335


	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
Operating Information
Natural gas transported (MMcf)		118,478		92,409		358,706		314,156
Natural gas liquids transported (MBbls/d)		199		—		199		—
Natural gas liquids gathered (MBbls/d)		51		—		51		—
Capital expenditures (Thousands of dollars)	$	5,021	$	3,685	$	9,807	$	7,696
Average natural gas price ($/MMBtu) (mid-continent region)	$	7.35	$	5.43	$	6.44	$	5.38

Operating results - Net margin increased for both the three and nine months ended September 30, 2005, compared with the same periods in 2004, primarily due to:

•

an increase of $13.9 million for both the three- and nine-month periods related to revenues on NGL gathering and distribution pipelines acquired in July 2005,

•

an increase of $6.9 million and $9.0 million, respectively, in transport revenues resulting from increased throughput due to favorable weather conditions for transportation and our improved fuel position and higher commodity prices, and

•

an increase of $2.6 million and $4.4 million, respectively, related to increased revenues from renegotiated contracts and increased storage activity as a result of a better pricing environment for inter- and intra-month business, improved fuel position and higher commodity prices.

Operating costs increased $7.2 million and $7.0 million for the three- and nine-month periods ended, respectively, compared with 2004, primarily related to $5.4 million for operating the newly-acquired NGL pipelines with the balance being driven by higher regulatory compliance costs and employee costs.

The increase in depreciation, depletion and amortization of approximately $3.0 million for both the three- and nine-month periods is primarily related to the newly-acquired NGL pipelines.

The decrease in other income (expense), net, for the nine-month period is due to the $6.9 million gain on the 2004 sale of certain assets, which was partially offset by unrelated litigation costs.

Energy Services

Overview - Our Energy Services segment’s primary focus is to create value for our customers by delivering physical products and risk management services through our network of contracted gas supply, transportation and storage capacity. 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 2.3 Bcf per day and maximum injection capability of 1.6 Bcf per day. Our current transportation capacity is 1.6 Bcf per day. The contracted storage and transportation capacity connects the major supply and demand centers throughout the United States. 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 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. We provide risk management services to our customers.

Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for the Energy Services segment for the periods indicated. In the third quarter of 2005, we made the decision to sell our Spring Creek power plant and exit the power generation business. These assets were held for sale at September 30, 2005, and, accordingly, this component of our business is accounted for as discontinued operations, in accordance with Statement 144. In October 2005, we concluded that our Spring Creek power plant located in southwest Oklahoma had been impaired and recorded an impairment expense of $52.2 million. For additional information see discussion of discontinued operations on page 25.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	*(Thousands of dollars)*
Financial Results
Energy and power revenues	$	2,006,878		$	1,090,442		$	5,303,470		$	1,137,651
Energy trading revenues, net		10,615			17,411			11,023			106,583
Other revenues		243			205			645			649
Cost of sales and fuel		1,949,514			1,089,942			5,174,472			1,138,938

Net margin		68,222			18,116			140,666			105,945
Operating costs		12,474			6,882			28,351			24,669
Depreciation, depletion and amortization		544			402			1,535			1,192

Operating income	$	55,204		$	10,832		$	110,780		$	80,084

Other income (expense), net	$	(1,503	)	$	(1,874	)	$	(5,358	)	$	(5,398	)

Discontinued operations, net of taxes	$	(32,909	)	$	(469	)	$	(34,307	)	$	(2,200	)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Operating Information
Natural gas marketed (Bcf)		279			240			879			776
Natural gas gross margin ($/Mcf)	$	0.21		$	0.07		$	0.13		$	0.11
Physically settled volumes (Bcf)		560			508			1,759			1,559
Capital expenditures (Thousands of dollars)	$	—		$	558		$	159		$	1,372

Operating Results - Increases in natural gas price and volatility during the third quarter of 2005 had a direct impact on our Energy Services segment identified in the explanations below.

Energy and power revenues, as well as cost of sales and fuel, increased for the three-month period due to a 14.4 percent increase in sales volumes and a significant increase in commodity prices compared to the same period in 2004.

Net margin increased for the three months ended September 30, 2005, compared with the same period in 2004, primarily due to:

•

a net increase of $54.6 million related to higher margins from selling natural gas from storage and gains associated with an increase in basis spreads,

•

an increase of $5.3 million in power margins related to improved Electric Reliability Council of Texas (ERCOT) market heat-rates attributable to a 14.8 percent increase in cooling degree days compared to normal and an 18.7 percent increase in cooling days compared to the same period in 2004, and

•

a decrease of $10.3 million in financial trading margins.

Net margins increased for the nine month period primarily due to:

•

an increase of $29.6 million primarily related to storage sales in the third quarter that more than offset lower sales from storage during the first quarter,

•

an increase of $4.9 million in power margins related to improved ERCOT market heat-rates,

•

an increase of $6.6 million in margins related to optimizing transportation agreements associated with wider basis differentials,

•

a decrease of $9.0 million in margins from natural gas options trading, compared with the same period in 2004, and

•

a decrease of $2.3 million in retail activities related to reduced physical margins in the second quarter of 2005.

Net margin also increased $5.9 million for the nine-month period due to a timing difference in revenue recognition between physical transportation activities and the associated derivative contracts that hedge the physical transportation commitment. The derivative contracts hedging the transportation commitment were marked-to-market, as a portion of the derivatives did not highly correlate between the receipt and delivery points causing the derivative instrument to be marked-to-market without the physical underlying offset, or a portion of the hedged item was determined to be ineffective.

Operating costs increased $5.6 million and $3.7 million for the three- and nine-month periods, respectively, primarily due to increased employee-related costs and increased litigation expense.

Natural gas volumes marketed increased for the three- and nine-month periods due to our expanded Canadian operations, additional long-term contracts and opportunities to sell into supply-constrained markets.

Our natural gas in storage at September 30, 2005, was 63.9 Bcf compared to 79.1 Bcf at September 30, 2004. At September 30, 2005, our total natural gas storage capacity under lease was 86 Bcf compared to 85 Bcf at September 30, 2004.

At the beginning of the third quarter of 2004, we completed a reorganization of our Energy Services segment and renewed our focus on our physical marketing and storage business. Prior to the third quarter, we managed the Energy Services segment on an integrated basis and presented all energy trading activity on a net basis.

Concurrent with this reorganization, we evaluated the accounting treatment related to the presentation of revenues from the different types of activities to determine which amounts should be reported on a gross or net basis under the guidance in EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3” (EITF 03-11). 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” were used to determine the proper treatment. These activities and all financially settled derivative contracts will continue to be reported on a net basis.

For derivative instruments that are not considered “held for trading purposes” and result in physical delivery, the indicators in EITF 03-11 and EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19) were used to determine the proper treatment. We began accounting for the realized revenues and purchase costs of these contracts that result in physical delivery on a gross basis beginning with the third quarter of 2004. 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. Prior periods have not been adjusted for this change; therefore, comparisons to prior periods may not be meaningful. Reporting of these transactions on a gross basis did not impact operating income, but resulted in an increase to revenues and cost of sales and fuel.

Marketing and storage activities primarily include physical marketing (purchases and sales) using our firm storage and transportation capacity, including cash flow and fair value hedges and other derivative instruments 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. Power activities are also included in the marketing and storage business. Retail marketing includes revenues from providing physical marketing and supply services to residential and small commercial and industrial customers. Financial trading revenues include activities that are generally executed using financially settled derivatives. These activities are normally short-term in nature with a focus of capturing short-term price volatility. The following table shows margins from these activities.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005
	*(Thousands of dollars)*
Marketing and storage, gross	$	96,609		$	28,420		$	241,069
Less: Storage and transportation costs		(40,243	)		(31,944	)		(123,639	)

Marketing and storage, net		56,366			(3,524	)		117,430
Retail marketing		3,535			3,051			11,792
Financial trading		8,321			18,589			11,444

Net margin	$	68,222		$	18,116		$	140,666

Distribution

Overview - Our Distribution segment provides natural gas distribution services to over 2 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 Oklahoma and Kansas, we also serve wholesale customers and in Texas, we also serve public authority customers. We provide gas service to approximately 86 percent, 71 percent and 14 percent of the distribution markets of Oklahoma, Kansas and Texas, respectively. Oklahoma Natural Gas and Kansas Gas Service are subject to regulatory oversight by the OCC and KCC, respectively. Texas Gas Service is subject to regulatory oversight by the various municipalities that it serves, which have primary jurisdiction in their respective areas. Texas

Gas Service’s rates in areas adjacent to the various municipalities and appellate matters are subject to regulatory oversight by the RRC. This segment also includes an interstate gas transportation company, OkTex Pipeline, which is regulated by the FERC.

Our operating results are primarily impacted by the number of customers, usage and the ability to establish delivery rates that provide an authorized rate of return on our investment and cost of service. Gas costs are passed through to our customers based on the actual cost of gas purchased by the respective distribution division. Changes in the level of gas sales can occur from year to year without significantly impacting our gross margin, since most factors that affect gas sales also affect cost of gas by an equivalent amount. Gas sales to residential and commercial customers are seasonal, as a substantial portion of gas is used principally for heating. Accordingly, the volume of gas sales is consistently higher during the heating season (November through March) than in other months of the year.

In September 2005, Hurricane Rita caused significant damage to customers’ homes and businesses in the Texas Gas Service service area located in south Jefferson County and Port Arthur, Texas. Texas Gas Service suffered damage to its Port Arthur service center, meters in south Jefferson County and Port Arthur, Texas, and incurred system gas loss. The financial impact will be nominal due to insurance coverage that covers property damage, gas loss and business interruption loss.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	*(Thousands of dollars)*
Financial Results
Gas sales	$	289,766		$	224,727		$	1,345,760		$	1,257,299
Transportation revenues		20,059			17,510			67,587			59,993
Cost of sales and fuel		210,917			159,033			1,021,129			941,863

Gross margin		98,908			83,204			392,218			375,429
Other revenues		6,196			5,422			20,598			20,183

Net margin		105,104			88,626			412,816			395,612
Operating costs		91,596			79,711			265,701			251,516
Depreciation, depletion and amortization		26,298			26,518			86,301			78,669

Operating income (loss)	$	(12,790	)	$	(17,603	)	$	60,814		$	65,427

Other income (expense), net	$	(331	)	$	(124	)	$	(643	)	$	(942	)

Operating Results - Net margin increased by $16.5 million and $17.2 million for the three and nine months ended September 30, 2005, respectively, compared with the same periods in 2004, primarily due to a $14.9 million increase resulting from the implementation of new rate schedules in Oklahoma and a $0.7 million increase resulting from increased wholesale sales during the third quarter of 2005. The nine-month period also increased as a result of $2.6 million in additional margin during the time frame the limited issue filing was in effect in Oklahoma.

Operating costs increased $11.9 million for the three-month period, primarily due to the following:

•

labor and employee benefit costs of $8.4 million,

•

ad valorem taxes of $2.0 million,

•

equipment leasing costs of $0.6 million, and

•

the accrual of an insurance deductible of $0.5 million related to Hurricane Rita.

The $14.2 million increase in operating costs for the nine-month period was primarily due to increased labor and employee benefit costs of $13.2 million and the accrual of an insurance deductible of $0.5 million related to Hurricane Rita.

Depreciation, depletion and amortization increased for the nine-month period primarily due to a $2.9 million charge related to the replacement of our field customer service system in Texas. The ad valorem tax recovery rider in Kansas increased amortization for the nine-month period by $3.8 million, which is offset by increased revenues. The remaining increase for the nine-month period is primarily due to additional plant and equipment.

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

Three Months Ended
September 30,

Nine Months Ended
September 30,

2005

2004

2005

2004

Operating Information

Average number of customers

1,993,496

1,991,117

2,019,294

2,006,276

Customers per employee

683

659

686

662

Capital expenditures (Thousands of dollars)

39,069

43,732

103,078

106,332

Three Months Ended
September 30,

Nine Months Ended
September 30,

2005

2004

2005

2004

Volumes (MMcf)

Gas sales

Residential

8,266

8,049

81,313

83,162

Commercial

3,603

4,059

26,920

29,362

Industrial

706

602

1,906

1,962

Wholesale

12,204

11,360

28,660

26,765

Public Authority

279

263

1,567

1,605

Total volumes sold

25,058

24,333

140,366

142,856

Transportation

57,107

55,492

184,698

177,066

Total volumes delivered

82,165

79,825

325,064

319,922

Three Months Ended
September 30,

Nine Months Ended
September 30,

2005

2004

2005

2004

(Thousands of dollars)

Margin

Gas sales

Residential

65,275

53,158

258,655

244,610

Commercial

13,730

11,329

65,925

66,450

Industrial

496

408

2,085

2,543

Wholesale

2,284

1,616

5,480

4,252

Public Authority

269

418

1,830

2,151

Gross margin on gas sales

82,054

66,929

333,975

320,006

Transportation

16,854

16,275

58,243

55,423

Gross margin

98,908

83,204

392,218

375,429

Certain amounts have been reclassified to reflect transportation margin net of its related fuel cost. There was no impact on gross margin. All prior periods have been restated.

Residential and commercial volumes decreased for the nine-month period due to:

•

warmer weather during the first quarter of 2005, and

•

commercial customers migrating to new transportation rates as a result of lower minimum transport thresholds in Oklahoma.

Wholesale sales represent contracted gas volumes that exceed the needs of our residential, commercial and industrial customer base and are available for sale to other parties. Wholesale volumes increased for the three- and nine-months ended September 30, 2005, as fewer volumes were required to meet the needs of residential, commercial and industrial customers, resulting in additional volume being available for sale to other parties.

Public authority gas volumes reflect volumes used by state agencies and school districts serviced by Texas Gas Service.

Transportation volumes increased for the three- and nine-month periods primarily due to commercial and industrial customers of Oklahoma Natural Gas migrating to new transportation rates as a result of lower minimum transport thresholds.

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 $12.3 million and $8.0 million for new business development for the three months ended September 30, 2005, and 2004, respectively, and $32.2 million and $25.0 million for new business development for the nine months ended September 30, 2005, and 2004, respectively.

Regulatory Initiatives

Oklahoma - On October 4, 2005, the OCC issued a final order on our application for a rate increase by Oklahoma Natural Gas. The OCC unanimously approved an annual rate increase of $57.5 million. In July, the Commission’s administrative law judge recommended an increase in annual revenues of approximately $58.0 million. Oklahoma Natural Gas implemented new rates, subject to refund, on July 28, 2005, based on the judge’s report. The refund obligation associated with the difference between the rates we have been collecting since July 28, 2005, and the OCC approved rate increase is not material to our financial results for the three- and nine-month periods.

On January 30, 2004, the OCC issued an order allowing Oklahoma Natural Gas annual rate relief of $17.7 million in order to recover expenses related to its investment in service lines and cathodic protection, an increased level of uncollectible revenues, and a return on Oklahoma Natural Gas’ service lines and investment in gas in storage. The OCC’s order also approved a modified distribution main extension policy and authorized Oklahoma Natural Gas to defer homeland security costs. The order authorized the new rates to be in effect for a maximum of 18 months and categorized $10.7 million of the annual additional revenues as interim and subject to refund until a final determination at Oklahoma Natural Gas’ next general rate case. This interim relief expired on July 27, 2005, and was replaced by the rate increase of $57.5 million approved on October 4, 2005. As the final rate increase exceeded the interim revenues that were subject to refund, no refund obligation was incurred associated with this rate increase.

General - Certain costs to be recovered through the ratemaking process have been recorded as regulatory assets in accordance with Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71). Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria of Statement 71 and, accordingly, a write-off of regulatory assets and stranded costs may be required.

Discontinued Operations

Overview - In September 2005, we completed the sale of our Production segment to TXOK Acquisition, Inc. for $645 million, before adjustments. We recognized a pre-tax gain on the sale of the discontinued component for our Production segment of approximately $243.2 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 had approved the potential sale in July 2005, which resulted in our Production segment being classified as held for sale during the third quarter. In accordance with Statement 144, we did not record any depreciation, depletion or amortization for our Production segment while it was classified as held for sale.

Additionally, in the third quarter of 2005, we made the decision to sell our Spring Creek power plant and exit the power generation business. In October 2005, we concluded that our Spring Creek power plant located in southwest Oklahoma had been impaired and recorded an impairment expense of $52.2 million. This conclusion was based on our Statement 144 impairment analysis of the results of operations for this plant through September 30, 2005, and also considered net sales proceeds from a sale of the plant. Ultimately, the decision reached was to sell the plant and in October 2005, we entered into an agreement to sell our Spring Creek power plant to Westar Energy, Inc. for $53 million. The transaction requires FERC approval and is expected to be completed in 2006. The 300-megawatt gas-fired merchant power plant was built in 2001 to supply electrical power during peak periods using gas-powered turbine generators. The proceeds from this sale will be used to purchase other assets, repurchase ONEOK shares or retire debt.

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

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	*(Thousands of dollars)*
Operating revenues, excluding energy trading revenues	$	45,917		$	62,351		$	131,629		$	147,778
Cost of sales and fuel		11,900			36,097			35,532			69,206

Net margin		34,017			26,254			96,097			78,572
Impairment expense		52,226			—			52,226			—
Operating costs		8,359			7,557			23,951			22,283
Depreciation, depletion and amortization		1,136			7,589			17,887			22,268

Operating income (loss)		(27,704	)		11,108			2,033			34,021

Other income (expense), net		170			(20	)		252			(110	)
Interest expense		3,947			4,100			11,657			11,833
Income taxes		(11,962	)		2,700			(3,560	)		8,440

Income (loss) from operations of discontinued components, net	$	(19,519	)	$	4,288		$	(5,812	)	$	13,638

Gain on sale of discontinued component, net of tax of $91.8 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 commitments to unaffiliated parties. During 2004 and 2005, our capital expenditures were financed through operating cash flows and short- and long-term debt. Capital expenditures for the first nine months of 2005 were $189.9 million, compared with $192.3 million for the same period in 2004, exclusive of any acquisitions.

Financing - Financing is provided through our commercial paper program, long-term debt and, as needed, through credit agreements. 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, asset securitization and the sale/leaseback of facilities.

On July 1, 2005, we borrowed $1.0 billion under the short-term bridge financing agreement to assist in financing the acquisition of assets from Koch. See page 25-26 for additional information about this acquisition. We funded the remaining acquisition cost through our commercial paper program. We anticipate permanent financing of the acquisition to come from a combination of proceeds from the sale of assets, such as our Production segment, our natural gas gathering and processing assets located in Texas and our Spring Creek power plant, proceeds from the February 2006 settlement of the purchase contracts that are part of our mandatory convertible equity units, and free cash flow. At September 30, 2005, we had lowered the commitment of outstanding indebtedness under the short-term bridge financing agreement to $900.0 million. The reduction in indebtedness under our short-term bridge financing agreement is a result of a required prepayment due to the sale of our Production segment.

to eliminate the effect of gains and losses recorded in accumulated other comprehensive income (loss) as a result of certain commodity hedging agreements. The effect of these amendments was to increase the amount of indebtedness we can incur while maintaining compliance with the covenants in those agreements that limit our debt-to-equity ratio.

Both the five-year credit agreement and the bridge financing agreement contain customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in our business, changes in the nature of our business, transactions with affiliates, the use of proceeds, a limit on our debt-to-equity ratio, a limit on investments in master limited partnerships and a covenant that prevents us from restricting our subsidiaries’ ability to pay dividends to ONEOK, Inc.

The total amount of short-term borrowings authorized by our Board of Directors is $2.5 billion. At September 30, 2005, we had $302.5 million in commercial paper outstanding, $900.0 million drawn on our short-term bridge financing agreement, $168.7 million in letters of credit issued, and approximately $86.2 million in cash and temporary investments. We also had $2.3 billion of long-term debt outstanding, including current maturities. As of September 30, 2005, we could have issued $1.1 billion of additional debt under the most restrictive provisions contained in our various borrowing agreements.

In March 2005, $335 million of our long-term debt matured. We funded payment of this debt with working capital and the issuance of commercial paper in the short-term market.

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


	September 30, 2005		December 31, 2004
Long-term debt	63	%	54	%
Equity	37	%	46	%

Debt (including Notes payable)	72	%	61	%
Equity	28	%	39	%

Both S&P and Moody’s consider the mandatory convertible equity units we issued in January 2003 to be part equity and part debt. For purposes of computing capitalization ratios, these rating agencies adjust our capitalization structure. S&P considers our mandatory convertible equity units to be equal amounts of debt and equity for the first three years, with the effect being to increase shareholders’ equity by the same amount as long-term debt, which would result in a capitalization structure of 57 percent long-term debt and 43 percent equity at September 30, 2005. Moody’s considers 25 percent of our mandatory convertible equity units to be long-term debt and 75 percent to be shareholders’ equity, which would result in a capitalization structure of 55 percent long-term debt and 45 percent equity at September 30, 2005.

Currently, we have $48.2 million available under one of our shelf registration statements on Form S-3 for the issuance and sale of shares of our common stock, debt securities, preferred stock, trusted preferred securities, stock purchase contracts and stock purchase units. We also have $402.5 million remaining under another shelf registration statement on Form S-3 to cover the issuance of common stock required upon settlement of the forward purchase contracts that are part of the mandatory convertible equity units.

Credit Rating - Our credit ratings are currently a “BBB” (Stable) by S&P and a “Baa2” (Stable) by Moody’s. In October 2005, Moody’s downgraded us to “Baa2” from “Baa1”, S&P downgraded us to “BBB” from “BBB+” and both removed the negative

watch. Our credit ratings may be affected by a material change in our financial ratios or a material adverse event affecting our business. The most common criteria for assessment of our credit ratings are the debt-to-equity ratio, pretax and after-tax interest coverage, and liquidity. If our credit ratings were downgraded, the interest rates on our commercial paper would increase, resulting in an increase in our cost to borrow funds, and we could potentially lose access to commercial paper borrowings. In the event that we are unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we have access to our $1.2 billion five-year credit agreement, which expires September 16, 2009.

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 our credit ratings were to decline below investment grade, our ability to participate in energy marketing and trading activities could be significantly limited. Without an investment grade rating, we may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments. At September 30, 2005, 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 $125.6 million. A decline in our credit rating below investment grade may also significantly impact other business segments.

We have reviewed our commercial paper agreement, trust indentures, building leases, equipment leases, marketing and trading contracts, and other various contracts that may be subject to rating triggers, and we do not have a significant exposure. Rating triggers are defined as provisions that would create an automatic default or acceleration of indebtedness based on a change in our credit rating. Our five-year credit and short-term bridge financing agreements contain a provision that would cause the cost to borrow funds to increase based on the amount borrowed under these agreements if our credit rating is negatively adjusted. The agreements also contain a default provision based on a material adverse change. An adverse rating change is not defined as a default or material adverse change.

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 commodity price changes have on items such as the cost of NGLs and gas held in storage, increased margin requirements, collectibility of certain energy-related receivables and working capital. We believe that our current commercial paper program and debt capacity 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 2004 were $6.8 million and $17.2 million, respectively. We presently anticipate our total 2005 contributions to be $1.8 million for our pension plan and $16.1 million for the other postretirement benefit plan. We will be reimbursed approximately $2.5 million by Northern Border Partners for defined benefit pension plan expenses that we incur for them. We believe we have adequate resources to fund our obligations under our pension and postretirement benefit plans.

Oklahoma Corporation Commission - On October 4, 2005, the OCC issued a final order on the application for a rate increase by Oklahoma Natural Gas. The OCC unanimously approved an annual rate increase of $57.5 million. In July, the Commission’s administrative law judge recommended an increase in annual revenues of approximately $58.0 million. Oklahoma Natural Gas implemented new rates, subject to refund, on July 28, 2005, based on the judge’s report. The refund obligation associated with the difference between the rates we have been collecting since July 28, 2005, and the OCC approved rate increase is not material to our financial results for the three- and nine-month periods.

entitled to recover under this order. We have been authorized to collect this deficiency in December 2005, by offsetting the amount against the final billing credit associated with the Joint Stipulation discussed below.

A Joint Stipulation approved by the OCC on May 16, 2002, settled a number of outstanding Oklahoma Natural Gas cases pending before the OCC. The major cases settled were the OCC’s inquiry into our gas cost procurement practices during the winter of 2000/2001, an application seeking relief from improper and excessive purchased gas costs, and enforcement action against Oklahoma Natural Gas, our subsidiaries and affiliated companies. In addition, all of the open inquiries related to the annual audits of Oklahoma Natural Gas’ fuel adjustment clause for 1996 to 2000 were closed as a result of this Stipulation.

The Stipulation has a $33.7 million value to Oklahoma Natural Gas customers that will be realized over a three-year period. In July 2002, immediate cash savings were provided to all Oklahoma Natural Gas customers in the form of billing credits totaling approximately $9.1 million. In December 2005, a final billing credit will be made to customers. The minimum amount of this credit is estimated to be approximately $2.8 million. Oklahoma Natural Gas replaced certain gas contracts, which reduced gas costs by approximately $13.8 million, due to avoided reservation fees between April 2003 and October 2005. We anticipate additional savings of approximately $2.0 million from the use of storage gas. We estimate expected savings of approximately $6.0 million from the use of storage that was not achieved will be added to the final billing credit scheduled to be provided to customers in December 2005.

Cash Flow Analysis

Operating Cash Flows - Operating cash flows decreased by $48.0 million for the nine months ended September 30, 2005, compared with the same period in 2004. The decrease in operating cash flows was primarily the result of a net increase in working capital of $170.9 million in 2005 compared with a net increase in working capital of $60.2 million in 2004. In 2005, higher prices and our current positions with counterparties increased our Energy Services segment’s deposit (margin) requirements, which resulted in a decrease in operating cash flows.

Investing Cash Flows - 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 discontinued component. The proceeds from 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.

Proceeds from the sale of certain natural gas transmission and gathering pipelines, compression assets and investments totaled $17.2 million for the nine months ended September 30, 2004.

Financing Cash Flows - 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 Northern Border Partners acquisition, 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 nine months of 2005, we paid $188.7 million to repurchase approximately 6.0 million shares of our stock pursuant to a plan approved by our Board of Directors on January 20, 2005. This plan allows us to repurchase up to a total of 7.5 million shares of our common stock on or before January 20, 2007.

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

During the first quarter of 2004, we paid off $600 million in notes payable using cash generated from operating activities and proceeds from our first quarter 2004 equity offering. During the second and third quarters of 2004, we incurred $298 million of notes payable used in the ordinary course of business. We also sold 6.9 million shares of our common stock to an underwriter at $21.93 per share, resulting in proceeds to us, before expenses, of $151.3 million.

We terminated $670 million of our interest rate swap agreements in the first quarter of 2004 to lock-in savings and generate a positive cash flow of $91.8 million, which included $8.9 million of interest savings previously recognized. The proceeds received upon termination of the interest rate swaps, net of amounts previously recognized, will be recognized in the income statement over the term of the debt instruments originally hedged.

Forward Looking Statements and Risk Factors

Some of the statements contained and incorporated in this 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, including anticipated operating income from the businesses we acquired on July 1, 2005, from Koch Industries, Inc. and affiliates; 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 Form 10-Q identified by words such as “anticipate,” “estimate,” “expect,” “forecast,” “intend,” “believe,” “projection” or “goal.”

You should not place undue reliance on forward-looking statements. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:

•

risks associated with any reduction in our credit ratings;

•

the effects of weather and other natural phenomena on energy sales and prices, production and processing volumes, availability of supplies and other aspects of our business;

•

competition from other energy suppliers as well as alternative forms of energy;

•

the capital intensive nature of our business;

•

the profitability of assets or businesses acquired by us;

•

risks of marketing, trading and hedging activities as a result 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 uncertainty of estimates, including accruals and costs of environmental remediation;

•

the timing and extent of changes in commodity prices for natural gas, natural gas liquids, power and crude oil, including basis differentials for natural gas and natural gas liquids;

•

the effects of changes in governmental policies and regulatory actions, including changes with respect to income taxes, environmental compliance, pipeline integrity, authorized rates or recovery of gas costs and ERISA;

•

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;

•

risks associated with casualty losses, including casualty losses at plant sites that could interrupt portions of our business;

•

the impact of 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 involving the Oklahoma Corporation Commission, Kansas Corporation Commission, 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;

•

the risk of a significant slowdown in growth or decline in the U.S. economy or the risk of delay in growth or recovery in the U.S. economy;

•

risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines which outpace new drilling;

•

risks inherent in the implementation of new software, such as our customer service system, and the impact on the timeliness of information for financial reporting;

•

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 franchises or other adverse effects caused by the actions of municipalities;

•

changes in law or increase in competition resulting from new federal energy legislation, including the repeal of the Public Utility Holding Company Act of 1935;

•

risks of holding a majority of the general partnership interest in Northern Border Partners, L.P., a publicly-traded limited partnership; and

•

the other factors listed in the reports we have filed and may file with the Securities and Exchange Commission, which are incorporated by reference.

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

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2004.

Kansas Gas Service uses derivative instruments to hedge the cost of anticipated gas purchases during the winter heating months and to protect Kansas Gas Service customers from upward volatility in the market price of natural gas. Gains or losses associated with these derivative instruments are included in, and recoverable through, the monthly purchased gas adjustment. At September 30, 2005, Kansas Gas Service had derivative instruments in place to hedge the cost of natural gas purchases for 8.9 Bcf, which represents part of their gas purchase requirements for the 2005/2006 winter heating months.

The following table provides a detail of our Energy Services segment’s maturity of derivatives based on heating injection and withdrawal periods from April to March. Executory storage and transportation contracts and their related hedges are not included in the following table.


	Fair Value of Contracts at September 30, 2005
	Matures through March 2006			Matures through March 2009			Matures through March 2011			Total Fair Value
	*(Thousands of dollars)*
Source of Fair Value (1)
Prices actively quoted (2)	$	374,106		$	2,448		$	—		$	376,554
Prices provided by other external sources (3)		(314,672	)		(351	)		(1,664	)		(316,687	)
Prices derived from quotes, other external sources and other assumptions (4)		(14,065	)		(12,236	)		2,638			(23,663	)

Total	$	45,369		$	(10,139	)	$	974		$	36,204

(1)	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.

(2)	Values are derived from energy market price quotes from national commodity trading exchanges that primarily trade futures and option commodity contracts.

(3)	Values are obtained through energy commodity brokers or electronic trading platforms, whose primary service is to match willing buyers and sellers of energy commodities. Because of the large energy broker network, energy price information by location is readily available.

(4)	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 contracts outstanding at December 31, 2004	$	17,951
Contracts realized or otherwise settled during the period		(35,432	)
Fair value changes in all contracts		53,685

Net fair value of contracts outstanding at September 30, 2005	$	36,204

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.

Interest Rate and Currency Risk - At September 30, 2005, the interest rate on approximately 85 percent of our long-term debt was fixed after considering the impact of interest rate swaps.

During the first quarter of 2005, we terminated $400 million of our interest rate swap agreements and paid a net amount of $19.4 million, which included $20.2 million for the present value of future payments at the time of termination, less $0.8 million for interest rate savings through the termination of the swaps. During the first quarter of 2004, we terminated $670 million of our interest rate swap agreements and received savings of $81.9 million. 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 first nine months of 2005 for all terminated swaps was $5.9 million, and the remaining net savings for all terminated swaps will be recognized over the following periods:


Remainder of 2005	$	1.7 million
2006	$	6.8 million
2007	$	6.6 million
2008	$	6.6 million
2009	$	5.6 million
Thereafter	$	20.8 million

Currently, $340 million of fixed rate debt is swapped to floating. The floating debt rate is based on both the three- and six-month London InterBank Offered Rate (LIBOR), depending upon the swap. At September 30, 2005, we had a net liability of $5.4 million to recognize the interest rate swaps at fair value. Long-term debt was decreased by $5.4 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 $7.8 million for the first nine months of 2005. The swaps are expected to generate the following savings for the remainder of the year:

•

interest expense savings of $1.7 million related to the amortization of the swap value at termination, and

•

up to $0.4 million in interest savings from the existing $340 million of swapped debt, based on LIBOR rates at September 30, 2005.

Total swap savings for 2005 are expected to be $9.9 million, compared with the savings of $27.6 million in 2004.

Prior to the issuance of the $800 million of notes in the second quarter of 2005, we entered into $500 million in treasury rate-lock agreements to hedge the changes in cash flows of our anticipated interest payments from changes in treasury rates prior to the issuance of the notes. Upon issuance of the notes in June 2005, the treasury rate-lock agreements terminated, which resulted in us paying $2.4 million. This amount, net of tax, has been recorded to accumulated other comprehensive loss and will be recognized in the income statement over the term of the related debt issuances.

A 100 basis point move in the LIBOR rate on all of our outstanding long-term debt would change annual interest expense by approximately $3.4 million before taxes. If interest rates change significantly, we may have the ability to take action to manage the exposure to the change. Since a specific action and the possible effects are uncertain, no change has been assumed.

With our Energy Services segment’s expansion into Canada, we are subject to currency exposure. Our objective with respect to currency risk is to reduce the exposure due to exchange-rate fluctuations. We use physical forward transactions, which result in an actual two-way flow of currency on the settlement date since we exchange U.S. dollars for Canadian dollars with another party. We have not designated these transactions for hedge accounting treatment; therefore, the gains and losses associated with

the change in fair value are recorded in net margin. At September 30, 2005, our exposure to risk from currency translation was not material.

Value-at-Risk (VAR) Disclosure of Market Risk - The potential impact on our future earnings, as measured by VAR, was $43.9 million and $4.2 million at September 30, 2005, and 2004, respectively.

The following table details the average, high and low daily VAR calculations.


	Three Months Ended September 30,				Nine Months Ended September 30,
VAR	2005		2004		2005		2004
	*(Millions of dollars)*
Average	$	16.3	$	1.8	$	13.5	$	3.5
High	$	44.0	$	4.2	$	44.0	$	17.7
Low	$	7.1	$	0.6	$	6.2	$	0.6

The variations in the VAR data are reflective of market volatility and changes in the portfolio during the quarter. In particular, there was significant volatility in the latter part of the third quarter of 2005.

Item 4.

Controls and Procedures

Quarterly Evaluation of Disclosure Controls and Procedures - We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Securities and Exchange Act of 1934, as amended (the Act), is recorded, processed, summarized and reported, within the time periods specified in the U.S. Securities and Exchange Commission’s (SEC) rules and forms. Under the supervision and with the participation of senior management, including our Chairman and Chief Executive Officer (Principal Executive Officer) and our Chief Financial Officer (Principal Financial Officer), we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Act. Based on this evaluation, our Principal Executive Officer and our Principal Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2005, in ensuring the timely disclosure of required information in our periodic SEC filings.

Changes in Internal Controls Over Financial Reporting - We have not made any changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Act) during the quarter ended September 30, 2005, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, except for those controls described in the next paragraph.

In July 2005, we completed the acquisition of the natural gas liquids assets from Koch as more fully described in Note B in the Notes to our Consolidated Financial Statements included in Part I of this report. As part of our ongoing integration activities, we are in the process of developing and incorporating controls and procedures related to these assets 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 acquisition, 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 have a material impact on our financial statements.

PART II - OTHER INFORMATION

Item 1.

Legal Proceedings

In the Matter of the Application of Oklahoma Natural Gas Company, a Division of ONEOK, Inc., for a Review and Change or Modification in its Rates, Charges, Tariffs and Terms and Conditions of Service, Oklahoma Corporation Commission, Cause No. PUD 200400610. The four primary parties in this matter executed a Stipulation and Settlement Agreement, which resolved the various issues raised on appeal in the case. The Commission unanimously approved the settlement on October 4, 2005. The annual revenue increase is $57.5 million.

Cornerstone Propane Partners, L.P., et al. v. E Prime, Inc., ONEOK Energy Marketing and Trading Company, L.P., ONEOK, Inc., and Calpine Energy Services, L.P., United States District Court for the Southern District of New York, Case No. 04-CV-00758. On October 3, 2005, the Court granted Plaintiffs’ Motion for Class Certification without a hearing.

Samuel P. Legget, 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 August 11, 2005, the Judicial Panel on Multidistrict Litigation issued a Transfer Order transferring this matter to the District of Nevada for inclusion in the multi-district litigation (MDL-1566) proceedings In Re Western States Wholesale Natural Gas Antitrust Litigation.

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 September 30, 2005.


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 (3)	Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs (3)
July 1-31, 2005	174,092	(1)(2)	$	34.51	—	3,815,500
August 1-31, 2005	1,878,664	(1)(2)	$	33.22	1,848,800	1,966,700
September 1-30, 2005	559,215	(1)(2)	$	33.23	498,300	1,468,400

Total	2,611,971		$	33.31	2,347,100	1,468,400

(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:

173,801 shares for the period July 1-31, 2005

29,621 shares for the period August 1-31, 2005

60,842 shares for the period September 1-30, 2005

(2)	Includes shares repurchased directly from employees, pursuant to our Employee Stock Award Program, as follows:

291 shares for the period July 1-31, 2005

243 shares for the period August 1-31, 2005

73 shares for the period September 1-30, 2005

(3)	On January 20, 2005, our Board of Directors approved the repurchase of up to 7.5 million shares of our common stock on or before January 20, 2007.

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) 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. In July 2005, our Board increased the total number of shares of our common stock available for issuance under this program from 50,000 to 100,000.

Through June 30, 2005, a total of 31,135 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, 2005, under this program.


Date	Closing Price (at or above)		Shares Issued
July 1, 2005	$	33.00	4,768
July 13, 2005	$	34.00	4,760
August 2, 2005	$	35.00	4,752

Total			14,280

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 releases, including Release No. 6188, dated February 1, 1980, stating that there is no sale of the shares in the 1933 Act sense to employees under this type of program.

Item 3.

Defaults Upon Senior Securities

Not Applicable.

Item 4.

Submission of Matters to Vote of Security Holders

Not Applicable.

Item 5.

Other Information

Not Applicable.

Item 6.

Exhibits

The following exhibits are filed as part of this Quarterly Report on Form 10-Q:


Exhibit No.		Exhibit Description
10.1		First Amendment to the Short-Term Bridge Financing Agreement between ONEOK, Inc. and Citibank, N.A., dated September 1, 2005.

10.2		Third Amendment to the five-year Credit Agreement between ONEOK, Inc. and Bank of America, N.A., dated September 13, 2005.

10.3		Fourth Amendment to the five-year Credit Agreement between ONEOK, Inc. and Bank of America, N.A., dated September 1, 2005.

10.4		Purchase Agreement between TXOK Acquisition, Inc. and ONEOK, Inc., dated September 19, 2005.

10.5		Stock Purchase Agreement between TXOK Acquisition, Inc. and ONEOK, Inc., dated September 19, 2005.

10.6		First Amendment to the Purchase Agreement between TXOK Acquisition, Inc., and ONEOK, Inc., dated September 27, 2005.

10.7		First Amendment to the Stock Purchase Agreement between TXOK Acquisition, Inc., and ONEOK, Inc., dated September 27, 2005.

12.1		Computation of Ratio of Earnings to Fixed Charges for the nine months ended September 30, 2005 and 2004.

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

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	ONEOK, Inc. Registrant

Date: November 4, 2005	By:	/s/ JIM KNEALE
		Jim Kneale
		Executive Vice President - Finance and Administration and Chief Financial Officer (Principal Financial Officer)