ONEOK 10Q 2005 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 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 Act). Yes x No ¨.

On August 1, 2005, the Company had 100,932,209 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 Six Months Ended June 30, 2005 and 2004	3

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

	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2005 and 2004	7

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

	Notes to Consolidated Financial Statements	10-20

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21-40

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40-42

Item 4.	Controls and Procedures	42

Part II.	Other Information

Item 1.	Legal Proceedings	42-43

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43-44

Item 3.	Defaults Upon Senior Securities	44

Item 4.	Submission of Matters to a Vote of Security Holders	44-45

Item 5.	Other Information	45

Item 6.	Exhibits	45

Signature		46

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 June 30,					Six Months Ended June 30,
*(Unaudited)*	2005			2004		2005		2004
	*(Thousands of dollars, except per share amounts)*
Revenues
Operating revenues, excluding energy trading revenues	$	2,129,904		$	618,231	$	4,873,575	$	1,573,542
Energy trading revenues, net		(8,784	)		13,908		408		89,172

Total Revenues		2,121,120			632,139		4,873,983		1,662,714

Cost of sales and fuel		1,857,789			402,087		4,211,087		1,039,903

Net Margin		263,331			230,052		662,896		622,811

Operating Expenses
Operations and maintenance		124,887			113,646		253,965		244,022
Depreciation, depletion and amortization		52,165			46,226		103,661		92,966
General taxes		17,648			16,574		37,048		37,109

Total Operating Expenses		194,700			176,446		394,674		374,097

Operating Income		68,631			53,606		268,222		248,714

Other income		3,960			1,655		9,274		9,469
Other expense		3,957			883		4,761		8,473
Interest expense		27,901			24,949		57,703		48,637

Income before Income Taxes		40,733			29,429		215,032		201,073

Income taxes		15,881			11,640		82,516		78,131

Net Income	$	24,852		$	17,789	$	132,516	$	122,942

Earnings Per Share of Common Stock (Note M)
Earnings per share, basic	$	0.25		$	0.17	$	1.29	$	1.22
Earnings per share, diluted	$	0.23		$	0.17	$	1.20	$	1.20
Average Shares of Common Stock(Thousands)
Basic		101,143			102,545		102,404		100,830
Diluted		109,062			103,971		110,031		102,673

Dividends Declared Per Share of Common Stock	$	0.56		$	0.44	$	0.81	$	0.63

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS


*(Unaudited)*	June 30, 2005		December 31, 2004
	*(Thousands of dollars)*
Assets
Current Assets
Cash and cash equivalents	$	16,603	$	9,458
Trade accounts and notes receivable, net		930,074		1,432,425
Materials and supplies		22,665		22,475
Gas and natural gas liquids in storage		550,386		593,028
Energy marketing and risk management assets (Note C)		256,782		388,672
Deposits		76,807		32,394
Deferred income taxes		18,172		—
Other current assets		149,290		40,365

Total Current Assets		2,020,779		2,518,817

Property, Plant and Equipment
Production		487,594		455,964
Gathering and Processing		1,086,587		1,066,612
Pipelines and Storage		703,115		705,115
Distribution		2,963,002		2,916,440
Energy Services		128,279		128,120
Other		134,658		134,199

Total Property, Plant and Equipment		5,503,235		5,406,450
Accumulated depreciation, depletion and amortization		1,691,828		1,619,629

Net Property, Plant and Equipment		3,811,407		3,786,821

Deferred Charges and Other Assets
Regulatory assets, net (Note D)		191,808		203,547
Goodwill (Note E)		225,188		225,188
Energy marketing and risk management assets (Note C)		58,877		71,310
Prepaid pensions		122,500		127,649
Investments and other		266,311		259,317

Total Deferred Charges and Other Assets		864,684		887,011

Total Assets	$	6,696,870	$	7,192,649

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS


*(Unaudited)*	June 30, 2005			December 31, 2004
	*(Thousands of dollars)*
Liabilities and Shareholders’ Equity
Current Liabilities
Current maturities of long-term debt	$	6,539		$	341,532
Notes payable		111,500			644,000
Accounts payable		919,868			1,185,351
Dividends payable		28,235			—
Accrued taxes		48,410			36,346
Accrued interest		26,776			32,807
Customers’ deposits		39,665			39,478
Unrecovered purchased gas costs		65,648			64,322
Energy marketing and risk management liabilities (Note C)		413,813			409,633
Deferred income taxes		—			16,861
Other		112,698			144,465

Total Current Liabilities		1,773,152			2,914,795

Long-term Debt, excluding current maturities		2,338,250			1,543,202
Deferred Credits and Other Liabilities
Deferred income taxes		658,887			644,512
Energy marketing and risk management liabilities (Note C)		64,864			102,865
Lease obligation		80,080			86,817
Other deferred credits		283,267			294,754

Total Deferred Credits and Other Liabilities		1,087,098			1,128,948

Total Liabilities		5,198,500			5,586,945

Commitments and Contingencies (Note J)
Shareholders’ Equity
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 107,622,791 shares and outstanding 100,839,789 shares at June 30, 2005; issued 107,143,722 shares and outstanding 104,106,285 shares at December 31, 2004		1,076			1,071
Paid in capital		1,030,693			1,017,603
Unearned compensation		(833	)		(1,413	)
Accumulated other comprehensive loss (Note F)		(67,963	)		(9,591	)
Retained earnings		699,110			649,240
Treasury stock, at cost: 6,783,002 shares at June 30, 2005 and 3,037,437 shares at December 31, 2004		(163,713	)		(51,206	)

Total Shareholders’ Equity		1,498,370			1,605,704

Total Liabilities and Shareholders’ Equity	$	6,696,870		$	7,192,649

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,
*(Unaudited)*	2005			2004
	*(Thousands of Dollars)*
Operating Activities
Net income	$	132,516		$	122,942
Depreciation, depletion, and amortization		103,661			92,966
Loss (gain) on sale of assets		526			(8,606	)
Income from equity investments		(5,649	)		(542	)
Deferred income taxes		17,471			52,772
Stock based compensation expense		5,983			4,640
Allowance for doubtful accounts		8,188			10,005
Changes in assets and liabilities (net of acquisition effects):
Accounts and notes receivable		494,362			144,479
Inventories		42,347			53,256
Unrecovered purchased gas costs		1,326			13,793
Deposits		(44,413	)		21,939
Regulatory assets		(4,435	)		3,308
Accounts payable and accrued liabilities		(250,332	)		26,962
Energy marketing and risk management assets and liabilities		38,782			(11,468	)
Other assets and liabilities		(116,717	)		(48,695	)

Cash Provided by Operating Activities		423,616			477,751

Investing Activities
Changes in other investments, net		(31,349	)		888
Capital expenditures		(122,687	)		(114,402	)
Proceeds from sale of property		(334	)		15,073
Other investing activities		(2,215	)		(7,033	)

Cash Used in Investing Activities		(156,585	)		(105,474	)

Financing Activities
Borrowing (payments) of notes payable, net		(532,500	)		(560,000	)
Termination of interest rate swaps		(22,565	)		82,915
Issuance of debt, net of issuance costs		798,792			—
Payment of debt		(335,456	)		(465	)
Purchase of common stock		(112,507	)		(798	)
Issuance of common stock		7,857			168,545
Dividends paid		(54,576	)		(39,757	)
Other financing activities		(8,931	)		(15,929	)

Cash Used in Financing Activities		(259,886	)		(365,489	)

Change in Cash and Cash Equivalents		7,145			6,788
Cash and Cash Equivalents at Beginning of Period		9,458			12,172

Cash and Cash Equivalents at End of Period	$	16,603		$	18,960

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 income	—		—		—		—
Total comprehensive income
Repurchase of common stock	—		—		—		—
Common stock issuance pursuant to various plans	479,069		5		7,852		—
Stock-based employee compensation expense	—		—		5,238		745
Common stock dividends - $0.81 per share	—		—		—		(165	)

June 30, 2005	107,622,791	$	1,076	$	1,030,693	$	(833	)

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		—			132,516			—			132,516
Other comprehensive income		(58,372	)		—			—			(58,372	)

Total comprehensive income											74,144

Repurchase of common stock		—			—			(112,507	)		(112,507	)
Common stock issuance pursuant to various plans		—			—			—			7,857
Stock-based employee compensation expense		—			—			—			5,983
Common stock dividends - $0.81 per share		—			(82,646	)		—			(82,811	)

June 30, 2005	$	(67,963	)	$	699,110		$	(163,713	)	$	1,498,370

ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

A.	Summary of Accounting Policies

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

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 June 30,				Six Months Ended June 30,
	2005		2004		2005		2004
	*(Thousands of dollars, except per share amounts)*
Net income, as reported	$	24,852	$	17,789	$	132,516	$	122,942
Add: Stock option compensation included in net income, net of related tax effects		2,483		1,499		4,782		3,350
Deduct: Total stock option compensation expense determined under fair value based method for all awards, net of related tax effects		2,646		1,796		5,108		3,943

Pro forma net income	$	24,689	$	17,492	$	132,190	$	122,349

Earnings per share:
Basic - as reported	$	0.25	$	0.17	$	1.29	$	1.22
Basic - pro forma	$	0.24	$	0.17	$	1.29	$	1.21
Diluted - as reported	$	0.23	$	0.17	$	1.20	$	1.20
Diluted - pro forma	$	0.23	$	0.17	$	1.20	$	1.19

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 fiscal years ending after December 15, 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.

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.

B.	Acquisitions

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 $1.35 billion. This transaction includes Koch Hydrocarbon, LP’s entire mid-continent natural gas liquids 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, 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 which owns a 10.2 percent interest in Venice Energy Services Company, LLC (VESCO). These assets will be included in our consolidated financial statements beginning on July 1, 2005.

The acquisition was initially financed through our $1.0 billion short-term credit 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 issuance of long-term debt, proceeds from the settlement of our mandatory convertible equity units in February 2006, proceeds from the sale of less strategic assets, and available cash.

C.	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. We record these changes in fair value as energy trading revenues, net in our Consolidated Statements of Income. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposure to changes in fair values, cash flows or foreign currencies. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings in the period of change together with the offsetting 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 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.

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 six months of 2005 for all terminated swaps was $4.1 million, and the remaining net savings for all terminated swaps will be recognized over the following periods:


Remainder of 2005	$	3.5 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 June 30, 2005, we recorded a net asset of $3.2 million to recognize the interest rate swaps at fair value. Long-term debt was increased by $3.2 million to recognize the change in the fair value of the related hedged liability.

Our Energy Services segment uses basis swaps to hedge the fair value of certain firm transportation commitments. Net gains or losses from the fair value hedges are recorded as cost of sales and fuel. The ineffectiveness related to these hedges was immaterial for the three and six months ended June 30, 2005 and 2004.

Cash Flow Hedges

Our Energy Services segment uses futures and basis swaps to hedge the cash flows associated with its anticipated purchases and sales of natural gas and cost of fuel used in transportation of gas. Accumulated other comprehensive loss at June 30, 2005, includes net losses of approximately $54.4 million, net of tax, related to these hedges that will be realized within the next 43 months. We will recognize $28.3 million in net losses over the next 12 months, and we will recognize net losses of $26.1 million thereafter. Our Production segment and our Gathering and Processing segment periodically enter into derivative instruments to hedge the cash flows associated with their exposure to changes in the price of natural gas, natural gas liquids (NGLs) and crude oil. Accumulated other comprehensive loss at June 30, 2005, includes losses of approximately $6.4 million, net of tax, for the production hedges which will be realized in the income statement primarily within the next 12 months. Losses of approximately $4.6 million, net of tax, are included in accumulated other comprehensive loss at June 30, 2005, for the gathering and processing hedges, which will be realized in the income statement primarily within the next 12 months.

Our Distribution segment also uses derivative instruments from time to time. Gains or losses associated with these derivative instruments are included in, and recoverable through, the monthly purchased gas adjustment. At June 30, 2005, Kansas Gas Service had derivative instruments in place to hedge the cost of natural gas purchases for 4.2 Bcf, which represents part of its gas purchase requirements for the 2005/2006 winter heating months.

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 gain of approximately $0.6 million and a loss of $0.1 million for the three and six months ended June 30, 2005, respectively. Ineffectiveness related to these cash flow hedges for the three and six months ended June 30, 2004, resulted in a loss of approximately $2.0 million and $3.1 million, respectively. Additionally, losses of approximately $4.6 million were recognized from accumulated other comprehensive loss during the six months ended June 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.

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.

D.	Regulatory Assets

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


	June 30, 2005		December 31, 2004
	*(Thousands of dollars)*
Recoupable take-or-pay	$	55,488	$	58,412
Postretirement costs other than pension		48,740		52,477
Reacquired debt costs		19,348		19,777
Deferred taxes		16,848		18,471
Transition costs		15,963		16,209
Pension costs		12,454		13,125
Weather normalization		11,119		9,936
Ad valorem tax		5,778		5,659
Service lines		46		1,517
Other		6,024		7,964

Regulatory assets, net	$	191,808	$	203,547

In September 2003, the Kansas Corporation Commission (KCC) issued an order to Kansas Gas Service that included approval to recover $26.4 million of deferred postretirement and postemployment benefit costs over nine years and made the weather normalization adjustment rider, which had been renewed annually, a permanent component of customer rates. “Weather normalization” represents the revenue over- or under-recovered through this rider. This amount is deferred as a regulatory asset for a 12-month period. Kansas Gas Service then applies an adjustment to the customers’ bills for a subsequent 12 month period to refund the over-collected revenue or bill the under-collected revenue.

The Oklahoma Corporation Commission (OCC) has authorized Oklahoma Natural Gas’ recovery of the take-or-pay settlement, pension and postretirement benefit costs over periods ranging from 10-20 years.

We amortize reacquired debt costs in accordance with the accounting rules prescribed by the OCC and KCC. These costs were included as a component of interest in the most recent rate filing with the OCC and were included in the rate order issued by the KCC.

The $5.8 million “Ad valorem tax” represents an increase in Kansas Gas Service’s taxes above the amount approved in the September 2003, rate order. Kansas law permits a utility to file a tariff to recover additional ad valorem tax expense incurred above the amount currently recovered in the cost of service rate. This excess amount is recoverable through a surcharge, provided the utility reports the change in taxes to the KCC, on an annual basis. Kansas Gas Service filed the tariff and received approval for recovery from the KCC during the third quarter of 2004.

E.	Goodwill

We completed our annual analysis of goodwill for impairment as of January 1, 2005, and there was no impairment indicated.

F.	Comprehensive Income

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


	Three Months Ended June 30,
	2005						2004
	*(Thousands of dollars)*
Net income				$	24,852					$	17,789
Unrealized losses on derivative instruments	$	(3,421	)				$	(20,315	)
Unrealized holding losses arising during the period		—						30
Realized losses in net income		1,901						3,510

Other comprehensive loss before taxes		(1,520	)					(16,775	)
Income tax benefit on other comprehensive loss		588						6,490

Other comprehensive loss					(932	)					(10,285	)

Comprehensive income				$	23,920					$	7,504


	Six Months Ended June 30,
	2005						2004
	*(Thousands of dollars)*
Net income				$	132,516					$	122,942
Unrealized losses on derivative instruments	$	(84,548	)				$	(42,792	)
Unrealized holding losses arising during the period		(606	)					(76	)
Realized (gains) losses in net income		(10,018	)					15,187

Other comprehensive loss before taxes		(95,172	)					(27,681	)
Income tax benefit on other comprehensive loss		36,800						10,704

Other comprehensive loss					(58,372	)					(16,977	)

Comprehensive income				$	74,144					$	105,965

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

G.	Capital Stock

Stock Repurchase Plan - During the second quarter of 2005, we repurchased approximately 1.6 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 3.7 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.

Common Stock - Since September 17, 2004, the Thrift Plan for Employees of ONEOK, Inc. and subsidiaries (the Thrift Plan) has from time to time purchased shares of ONEOK common stock on the open market to meet the purchase requirements generated by participants in the Thrift Plan. Previously, the Thrift Plan used newly issued shares to meet the participants’ purchase requirements. All participant purchases of ONEOK common stock under the Thrift Plan are voluntary. We use newly issued shares to meet the purchase requirements generated by our Dividend Reinvestment Plan and our Long-Term Incentive Plan.

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

H.	Long-Term Debt

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 existing 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 this payment with working capital and the issuance of commercial paper in the short-term market.

In June 2005, we entered into a $1.0 billion short-term credit 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.

In September 2004, we entered into a $1.0 billion five-year credit agreement. The principal amount of the credit facility may be increased by $200 million if requested by us and the corresponding incremental commitments are received from new or existing lenders. The interest rate is a floating rate calculated in the same manner as the $1.0 billion short-term credit agreement.

Both the five-year and short-term credit agreements 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 June 30, 2005, we had no amounts outstanding under either of these credit agreements. On July 1, 2005, we borrowed $1.0 billion under the short-term credit agreement to assist in financing the Koch assets acquisition. See Note B, which describes this acquisition.

Other debt agreements to which we are a party contain covenants that relate to liens and sale/leaseback transactions. At June 30, 2005, we are in compliance with all covenants. With the addition of $1.0 billion borrowed under our short-term credit agreement as of July 1, 2005, we remain in compliance with all covenants.

I.	Employee Benefit Plans

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


	Pension Benefits Three Months Ended June 30,						Pension Benefits Six Months Ended June 30,
	2005			2004			2005			2004
	*(Thousands of Dollars)*
Components of Net Periodic Benefit Cost (Income)
Service cost	$	4,941		$	3,982		$	9,882		$	7,963
Interest cost		10,758			10,372			21,516			20,743
Expected return on assets		(14,927	)		(15,486	)		(29,854	)		(30,971	)
Amortization of unrecognized net asset at adoption		—			(79	)		—			(157	)
Amortization of unrecognized prior service cost		361			166			722			332
Amortization of loss		2,126			577			4,252			1,155

Net periodic benefit cost (income)	$	3,259		$	(468	)	$	6,518		$	(935	)


	Postretirement Benefits Three Months Ended June 30,						Postretirement Benefits Six Months Ended June 30,
	2005			2004			2005			2004
	*(Thousands of Dollars)*
Components of Net Periodic Benefit Cost (Income)
Service cost	$	1,765		$	1,482		$	3,530		$	3,123
Interest cost		3,567			3,293			7,134			6,900
Expected return on assets		(1,086	)		(940	)		(2,172	)		(1,879	)
Amortization of unrecognized net asset at adoption		864			864			1,728			1,728
Amortization of unrecognized prior service cost		118			25			236			49
Amortization of loss		1,617			1,434			3,234			3,291

Net periodic benefit cost	$	6,845		$	6,158		$	13,690		$	13,212

Contributions- Contributions of $0.7 million and $7.4 million were made to our pension plan and other postretirement benefit plan, respectively, for the six months ended June 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.

J.	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 is 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.

Enron- We have repurchased a portion of the Enron Corp. guaranty claim that Enron Corp. and Enron North American Corp. (ENA) sought to avoid in the adversary proceeding. In addition to the adversary proceeding, Enron Corp. and ENA have filed an objection to portions of the guaranty claim and to portions of the underlying claim against ENA, creating a new contested matter in the Enron Corp. and ENA bankruptcy cases which involve different legal and factual issues than those raised in the adversary proceeding. 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 these proceedings since December 31, 2004.

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.

K.	Segments

Our business segments and the accounting policies of our business segments are the same as those described in the Note N and the Summary of Significant Accounting Policies in our Annual Report on Form 10-K for the year ended December 31, 2004. 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 ten percent or more of our consolidated gross revenues for the periods covered by this report.

As discussed in Note C, 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 June 30, 2005	Pipelines and Storage		Distribution			Energy Services			Gathering and Processing		Production		Other and Eliminations			Total
	*(Thousands of dollars)*
Sales to unaffiliated customers	$	17,868	$	339,794		$	1,391,753		$	363,728	$	30,987	$	(14,226	)	$	2,129,904
Energy trading revenues, net		—		—			(8,784	)		—		—		—			(8,784	)
Intersegment sales		25,132					171,257			156,355		1,063		(353,807	)		—

Total Revenues	$	43,000	$	339,794		$	1,554,226		$	520,083	$	32,050	$	(368,033	)	$	2,121,120

Net margin	$	31,236	$	106,492		$	12,552		$	83,061	$	32,050	$	(2,060	)	$	263,331
Operating costs		12,105		83,477			8,106			32,793		8,089		(2,035	)		142,535
Depreciation, depletion and amortization		4,438		30,014			1,575			8,540		7,486		112			52,165

Operating income (loss)	$	14,693	$	(6,999	)	$	2,871		$	41,728	$	16,475	$	(137	)	$	68,631

Income from equity investments	$	337	$	—		$	—		$	—	$	—	$	2,496		$	2,833
Capital expenditures	$	3,059	$	36,323		$	132		$	10,976	$	13,598	$	287		$	64,375

Three Months Ended June 30, 2004	Pipelines and Storage		Distribution			Energy Services			Gathering and Processing		Production		Other and Eliminations			Total
	*(Thousands of dollars)*
Sales to unaffiliated customers	$	11,316	$	307,820		$	47,265		$	342,242	$	23,009	$	(113,421	)	$	618,231
Energy trading revenues, net		—		—			13,908			—		—		—			13,908
Intersegment sales (a)		25,739		—			—			109,692		1,135		(136,566	)		—

Total Revenues	$	37,055	$	307,820		$	61,173		$	451,934	$	24,144	$	(249,987	)	$	632,139

Net margin	$	26,513	$	103,972		$	14,282		$	63,559	$	24,144	$	(2,418	)	$	230,052
Operating costs		11,091		80,734			7,919			28,057		6,017		(3,598	)		130,220
Depreciation, depletion and amortization		4,292		25,932			1,424			8,153		6,153		272			46,226

Operating income (loss)	$	11,130	$	(2,694	)	$	4,939		$	27,349	$	11,974	$	908		$	53,606

Income from equity investments	$	275	$	—		$	—		$	—	$	—	$	(58	)	$	217
Capital expenditures	$	1,967	$	36,728		$	704		$	5,880	$	11,946	$	8,275		$	65,500

(a)	- Intersegment sales for Energy Services were $114.3 million for the three months ended June 30, 2004. These are included in energy trading revenues, net above.


Six Months Ended June 30, 2005	Pipelines and Storage		Distribution		Energy Services		Gathering and Processing		Production		Other and Eliminations			Total
	*(Thousands of dollars)*
Sales to unaffiliated customers	$	28,718	$	1,117,924	$	2,945,664	$	736,328	$	58,269	$	(13,328	)	$	4,873,575
Energy trading revenues, net		—		—		408		—		—		—			408
Intersegment sales		54,667		—		377,165		306,125		2,049		(740,006	)		—

Total Revenues	$	83,385	$	1,117,924	$	3,323,237	$	1,042,453	$	60,318	$	(753,334	)	$	4,873,983

Net margin	$	61,336	$	307,712	$	74,647	$	161,449	$	60,318	$	(2,566	)	$	662,896
Operating costs		23,674		174,105		16,481		65,024		15,434		(3,705	)		291,013
Depreciation, depletion and amortization		8,814		60,003		2,982		16,878		14,760		224			103,661

Operating income	$	28,848	$	73,604	$	55,184	$	79,547	$	30,124	$	915		$	268,222

Income from equity investments	$	636	$	—	$	—	$	—	$	—	$	5,013		$	5,649
Total assets	$	576,723	$	2,660,904	$	1,300,637	$	1,322,671	$	415,766	$	420,169		$	6,696,870
Capital expenditures	$	4,786	$	64,009	$	159	$	20,369	$	31,159	$	2,205		$	122,687

Six Months Ended June 30, 2004	Pipelines and Storage		Distribution		Energy Services		Gathering and Processing		Production		Other and Eliminations			Total
	*(Thousands of dollars)*
Sales to unaffiliated customers	$	25,245	$	1,089,816	$	82,549	$	652,992	$	48,569	$	(325,629	)	$	1,573,542
Energy trading revenues, net		—		—		89,172		—		—		—			89,172
Intersegment sales (a)		50,237		—		—		250,351		1,962		(302,550	)		—

Total Revenues	$	75,482	$	1,089,816	$	171,721	$	903,343	$	50,531	$	(628,179	)	$	1,662,714

Net margin	$	56,978	$	306,986	$	89,616	$	122,985	$	50,531	$	(4,285	)	$	622,811
Operating costs		23,840		171,805		18,472		59,021		14,041		(6,048	)		281,131
Depreciation, depletion and amortization		8,556		52,151		2,815		16,166		12,654		624			92,966

Operating income	$	24,582	$	83,030	$	68,329	$	47,798	$	23,836	$	1,139		$	248,714

Income from equity investments	$	600	$	—	$	—	$	—	$	—	$	(58	)	$	542
Total assets	$	791,911	$	2,434,845	$	1,345,406	$	956,187	$	185,925	$	354,581		$	6,068,855
Capital expenditures	$	4,011	$	62,600	$	814	$	9,957	$	20,418	$	16,602		$	114,402

(a)	- Intersegment sales for Energy Services were $327.4 million for the six months ended June 30, 2004. These are included in energy trading revenues, net above.

The segment formerly named Transportation and Storage has been renamed Pipelines and Storage in order to better describe the activities of the segment.

With the completion of the Koch assets acquisition on July 1, 2005, we formed a new operating segment called Natural Gas Liquids. It consists of our existing natural gas liquids marketing business, which was part of our Gathering and Processing segment, and the assets acquired excluding those assets regulated by the Federal Energy Regulatory Commission, 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.

L.	Supplemental Cash Flow Information

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


	Six Months Ended June 30,
	2005		2004
	*(Thousands of dollars)*
Cash paid (received) during the period
Interest, including amounts capitalized	$	104,149	$	(24,849	)
Income taxes	$	55,260	$	88,424

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

M.	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 June 30, 2005
	Income		Shares	Per Share Amount
	*(Thousands, except per share amounts)*
Basic EPS
Income available for common stock	$	24,852	101,143	$	0.25
Diluted EPS
Effect of other dilutive securities:
Mandatory convertible units		—	6,840
Options and other dilutive securities		—	1,079

Income available for common stock and common stock equivalents	$	24,852	109,062	$	0.23


	Three Months Ended June 30, 2004
	Income		Shares	Per Share Amount
	*(Thousands, except per share amounts)*
Basic EPS
Income available for common stock	$	17,789	102,545	$	0.17
Diluted EPS
Effect of other dilutive securities:
Mandatory convertible units		—	767
Options and other dilutive securities		—	659

Income available for common stock and common stock equivalents	$	17,789	103,971	$	0.17


	Six Months Ended June 30, 2005
	Income		Shares	Per Share Amount
	*(Thousands, except per share amounts)*
Basic EPS
Income available for common stock	$	132,516	102,404	$	1.29
Diluted EPS
Effect of other dilutive securities:
Mandatory convertible units		—	6,569
Options and other dilutive securities		—	1,058

Income available for common stock and common stock equivalents	$	132,516	110,031	$	1.20


	Six Months Ended June 30, 2004
	Income		Shares	Per Share Amount
	*(Thousands, except per share amounts)*
Basic EPS
Income available for common stock	$	122,942	100,830	$	1.22
Diluted EPS
Effect of other dilutive securities:
Mandatory convertible units		—	1,222
Options and other dilutive securities		—	621

Income available for common stock and common stock equivalents	$	122,942	102,673	$	1.20

There were 21,964 and 37,902 option shares excluded from the calculation of diluted EPS for the three months ended June 30, 2005 and 2004, respectively, since their inclusion would be antidilutive for each period. For the six months ended June 30, 2005 and 2004, there were 24,977 and 20,713 option shares, respectively, excluded from the calculation of diluted EPS since their inclusion would be antidilutive for each period.

N.	Subsequent Event

On July 18, 2005, our Board of Directors approved the potential sale of our Production segment. If we proceed with the sale, it is anticipated to be completed in the third quarter of 2005. Beginning in the third quarter of 2005, we will reflect this segment’s results as discontinued operations. Our Production segment has total assets of $415.8 million at June 30, 2005, of which $385.3 million is net property, plant and equipment. An additional $17.3 million is accounts receivable. Total liabilities of $242.9 million include $161.4 million of intercompany long-term debt, $40.1 million of deferred income taxes and $21.7 million of accounts payable. This sale, if achieved, is in line with our business strategy to sell assets when deemed less strategic or as other conditions warrant. See Note K for our Production segment’s results of operations for the three and six months ended June 30, 2005 and 2004.

See Note B for a description of our acquisition of the natural gas liquids businesses from Koch.

Item 2.

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

Executive Summary - Operating income for our second quarter of 2005 was $68.6 million, an increase of $15.0 million, or 28 percent, compared with the same period in 2004. For the first six months of 2005, operating income was $268.2 million, an increase of $19.5 million, or eight percent, from the same period last year.

Diluted earnings per share of common stock (EPS) increased to 23 cents for the second quarter of 2005 from 17 cents for the same period in 2004. For the six-month period, EPS was $1.20 for both 2005 and 2004, with the positive impact of our increase in net income in 2005 offset by the dilutive effect of the mandatory convertible equity units.

Favorable energy prices had a significant impact on our results for the second quarter of 2005. Average prices for natural gas, natural gas liquids (NGLs) and crude oil exceeded prices for the same period in 2004. The gas processing spread was also higher in 2005 and continues to exceed the previous five-year average. The effect of these higher prices is primarily seen in the results of our Gathering and Processing segment, which saw an increase in operating income of 53 percent for the quarter and 66 percent for the six-month period compared with the same periods in 2004.

Our Production segment, through its developmental drilling program, increased production for both the three- and six-month periods in 2005. The increased production combined with higher oil and natural gas prices resulted in operating income increases for this segment of 38 percent and 26 percent for the three and six months, respectively.

On July 28, 2005, Oklahoma Natural Gas implemented new rates for approximately 820,000 customers, in accordance with Oklahoma law, which provides that a utility may implement new rates at the end of a 180-day period in the absence of a final order. The Oklahoma Corporation Commission (OCC) administrative law judge who heard the case has recommended an increase in annual revenues of approximately $58 million. The rates that Oklahoma Natural Gas put into effect are based on that amount and will be subject to refund with interest; however, the administrative law judge’s recommendation has been appealed to the full, three-member Commission by Oklahoma Natural Gas and the Oklahoma Attorney General. The appeals were heard by the Commission on August 1, 2005, and the Commissioners have taken the matter under advisement. We expect the Commissioners’ decision during the third quarter.

We have revised our 2005 earnings guidance. Our revised guidance for income from continuing operations is in the range of $1.93 to $1.97 per diluted share of common stock. Based on certain assumptions regarding the potential sale of our Production segment, net earnings per share are expected to be in the range of $2.56 to $2.62 per diluted share of common stock. Revised guidance reflects the production segment’s operating results as discontinued operations.

Acquisitions- 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 $1.35 billion. This transaction includes Koch Hydrocarbon, LP’s entire mid-continent natural gas liquids 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, 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 which owns a 10.2 percent interest in Venice Energy Services Company, LLC (VESCO). These assets will be included in our consolidated financial statements beginning on July 1, 2005.

Regulatory- Several regulatory initiatives positively impacted the earnings and future earnings potential for our Distribution segment. These initiatives are discussed beginning on page 33.

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 fiscal years ending after December 15, 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.

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 40 for amounts in our portfolio at June 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 futures transactions and swaps in order to hedge anticipated sales and purchases of natural gas and crude oil production, fuel requirements and NGL inventories. Interest rate swaps are also used to manage interest rate risk. Under certain conditions, we designate these derivative instruments as a hedge of exposure to changes in fair 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.

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 June 30, 2005, we had $225.2 million of goodwill recorded on our balance sheet.

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.” 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.

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

Pension and Postretirement Employee Benefits - We have a defined benefit pension plan covering substantially all full-time employees and a postretirement employee benefits plan covering most employees. Our actuarial consultant calculates the expense and liability related to these plans and uses statistical and other factors that attempt to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and employment periods. In determining the projected benefit obligations and the costs, assumptions can change from period to period and result in material changes in the costs and liabilities we recognize.

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 reflect our acquisition of Northern Plains, amendments in benefits payable under our gas union contracts and a change in our assumed discount rate. See Note I 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 June 30,					Six Months Ended June 30,
Financial Results	2005			2004		2005		2004
	*(Thousands of dollars)*
Operating revenues, excluding energy trading revenues	$	2,129,904		$	618,231	$	4,873,575	$	1,573,542
Energy trading revenues, net		(8,784	)		13,908		408		89,172
Cost of sales and fuel		1,857,789			402,087		4,211,087		1,039,903

Net margin		263,331			230,052		662,896		622,811
Operating costs		142,535			130,220		291,013		281,131
Depreciation, depletion and amortization		52,165			46,226		103,661		92,966

Operating income	$	68,631		$	53,606	$	268,222	$	248,714

Other income	$	3,960		$	1,655	$	9,274	$	9,469
Other expense	$	3,957		$	883	$	4,761	$	8,473

Operating Results- Changes in commodity prices can have an impact on our earnings, particularly in our Gathering and Processing segment and Production segment. Net margin increased for the three and six months ended June 30, 2005, compared with the same periods in 2004 primarily due to:

•

a favorable pricing environment for natural gas processing in our Gathering and Processing segment,

•

an increase in the gross processing spread on our keep whole contracts for our Gathering and Processing segment, and

•

the impact of higher volumes and prices for our Production segment.

These increases were partially offset by decreases in our Energy Services segment primarily due to the impact of increases in NYMEX natural gas prices on our trading operations for the three-month period and decreased storage activity for the six-month period. Our Distribution segment experienced reduced customer usage as a result of warmer weather during the first quarter of 2005.

For an explanation of energy trading revenues, net, see the discussion of our Energy Services segment beginning on page 33.

Consolidated operating costs increased for the three- and six-month periods primarily due to increased employee benefit costs. Also contributing to the increase was environmental and safety expenditures related to new storage regulations for our Gathering and Processing segment.

Depreciation, depletion and amortization increased for the three- and six-month periods primarily due to:

•

a charge related to the replacement of our customer service system in Texas,

•

regulatory asset amortization resulting from the Kansas rate case, and

•

depreciation related to additional plant and equipment in our Distribution segment.

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005		2004
	*(Thousands of dollars)*
Equity income	$	2,833		$	217		$	5,649	$	542
Unrealized gain on investment		57			—			1,739		—
Interest income		268			223			698		454
Income (expense) from benefit plan investments		(17	)		(600	)		680		(721	)
Gain on sale of property		235			1,642			292		8,606
Other		584			173			216		588

Other Income	$	3,960		$	1,655		$	9,274	$	9,469



	Three Months Ended June 30,				Six Months Ended June 30,
	2005		2004		2005		2004
	*(Thousands of dollars)*
Litigation expense and claims, net	$	2,413	$	225	$	2,547	$	7,220
Donations, civic, and governmental		480		541		1,044		1,129
Loss on sale of property		815		—		818		—
Other		249		117		352		124

Other Expense	$	3,957	$	883	$	4,761	$	8,473

In the first quarter of 2004, we were required to repurchase a portion of the Enron claims we sold in 2002, resulting in an expense related to the decrease in value of the claims. Additionally, in the first half of 2004, we accrued amounts related to various other litigation. In the second quarter of 2005, we incurred an additional charge of $2.3 million related to the Enron claims. These amounts are included in litigation expense and claims, net.

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

Production

Overview - On July 18, 2005, our Board of Directors approved the potential sale of our Production segment. If we proceed with the sale, it is anticipated to be completed in the third quarter of 2005. This sale, if achieved, is in line with our business strategy to sell assets deemed less strategic or as other conditions warrant.

Our Production segment currently owns, develops and produces oil and natural gas reserves in Oklahoma and Texas. We focus on developmental drilling activities rather than exploratory drilling.

As a result of our developmental drilling program, the number of wells we operate increases as we grow our producing reserves. We typically serve as operator on wells where we have significant ownership interest. In our role as operator, we control operating decisions that impact production volumes and lifting costs (the costs incurred to extract oil and natural gas). We continually focus on reducing finding costs (the cost per Mcfe of adding proved reserves through drilling), and minimizing production costs.

The following table shows the results of our development activities for the periods indicated.


	Three Months Ended June 30,				Six Months Ended June 30,
	2005		2004		2005	2004
Wells drilled	17		22		74	67
Wells completed:
Gas	17		16		41	27
Oil	3		—		9	—
Wells still drilling	(a	)	(a	)	22	40
Dry holes	1		—		2	—

(a)	“Wells still drilling” are disclosed at a point in time, therefore data is shown as of June 30, 2005 and 2004.

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


	Three Months Ended June 30,						Six Months Ended June 30,
Financial Results	2005			2004			2005			2004
	*(Thousands of dollars)*
Natural gas sales	$	26,848		$	20,459		$	49,695		$	43,225
Oil sales		3,923			2,318			8,156			4,874
Other revenues		1,279			1,367			2,467			2,432

Net revenues		32,050			24,144			60,318			50,531
Operating costs		8,089			6,017			15,434			14,041
Depreciation, depletion and amortization		7,486			6,153			14,760			12,654

Operating income	$	16,475		$	11,974		$	30,124		$	23,836

Other income (expense), net	$	5		$	(64	)	$	(1	)	$	(90	)


	Three Months Ended June 30,						Six Months Ended June 30,
Operating Information	2005			2004			2005			2004
Proved reserves (a)
Gas(MMcf)		(c	)		(c	)		206,635			214,702
Oil(MBbls)		(c	)		(c	)		4,370			3,586
Production
Gas(MMcf)		4,355			4,060			8,399			8,303
Oil(MBbls)		86			83			181			169
Average realized price (b)
Gas($/Mcf)	$	6.16		$	5.04		$	5.92		$	5.21
Oil($/Bbl)	$	45.76		$	27.93		$	45.18		$	28.84
Capital expenditures(Thousands of dollars)	$	13,598		$	11,946		$	31,159		$	20,418

(a)	Proved reserves include proved undeveloped reserves which are attributed to locations directly offsetting (adjacent to) existing production.

(b)	Average realized price reflects the impact of hedging activities.

(c)	Reserves are disclosed at a point in time, therefore reserves are shown as of June 30, 2005 and 2004.

Operating Results - Net revenues increased for the three and six months ended June 30, 2005, compared with the same periods in 2004, due to:

•

increased revenues of $6.1 million and $8.7 million, respectively, resulting from higher realized net wellhead oil and natural gas prices, and

•

increased revenues of $1.9 million and $1.1 million, respectively, resulting from higher volumes produced.

Operating costs increased for the three- and six-month periods primarily due to a $1.0 million and $1.6 million increase, respectively, in field operating expenses for workovers and for new gathering and production facilities attributable to the Texas properties.

Capital Expenditures - Capital expenditures primarily relate to our developmental drilling program. Production from existing wells naturally declines over time and additional drilling on offsetting locations is necessary to maintain or enhance production from existing reserves.

Risk Management - The volatility of energy prices has a significant impact on the profitability of this segment. We utilize derivative instruments in order to hedge anticipated sales of oil and natural gas production. The realized financial impact of the derivative transactions is included in net margin.

The following tables set forth our remaining 2005 and 2006 hedging information for our Production segment. We have entered into NYMEX-based costless collars to secure a range of prices for a portion of our 2006 expected oil and natural gas production.


	Six Months Ending December 31, 2005
Product	Volumes Hedged	Basis-Adjusted Average Price
Natural gas
Texas	18,350 Mcf/d	$	5.89/Mcf
Oklahoma	9,500 Mcf/d	$	6.41/Mcf
Oil	15,000 Bbls/month	$	39.75/Bbl

	Year Ending December 31, 2006
Product	Volumes Hedged	Price
Natural gas
Texas	8,250 Mcf/d	$	6.46-10.66/Mcf
Oklahoma	5,710 Mcf/d	$	5.95-10.00/Mcf
Oil	9,000 Bbls/month	$	50.35-60.00/Bbl

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

Gathering and Processing

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

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. 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 third party and company-owned fractionation facilities. The component products can then be stored, transported and 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 28 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. 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.

We sell our NGL production and purchase NGLs from third parties for resale to a diverse base of customers. In the mid-continent, we have 89 MBbls/d of NGL fractionation capacity. We own and operate two NGL storage facilities in Kansas, with a combined storage capacity of 16 MMBbls, which provide both long- and short-term storage services. The storage facilities have truck and rail loading facilities and have direct pipeline interconnects with key NGL pipelines, NGL storage facilities and refiners in the mid-continent region.

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.

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 June 30,						Six Months Ended June 30,
Financial Results	2005			2004			2005			2004
	*(Thousands of dollars)*
Natural gas liquids and condensate sales	$	288,272		$	263,653		$	600,302		$	538,204
Gas sales		202,746			161,993			384,546			316,259
Gathering, compression, dehydration and processing fees and other revenues		29,065			26,288			57,605			48,880
Cost of sales and fuel		437,022			388,375			881,004			780,358

Net margin		83,061			63,559			161,449			122,985
Operating costs		32,793			28,057			65,024			59,021
Depreciation, depletion and amortization		8,540			8,153			16,878			16,166

Operating income	$	41,728		$	27,349		$	79,547		$	47,798

Other income (expense), net	$	(701	)	$	(284	)	$	(821	)	$	(289	)


	Three Months Ended June 30,						Six Months Ended June 30,
Operating Information	2005			2004			2005			2004
Total gas gathered(MMMBtu/d)		1,131			1,113			1,121			1,110
Total gas processed(MMMBtu/d)		1,167			1,147			1,135			1,155
Natural gas liquids sales(MBbls/d)		87			101			93			106
Natural gas liquids produced(MBbls/d)		64			59			63			60
Gas sales(MMMBtu/d)		353			332			346			322
Capital expenditures(Thousands of dollars)	$	10,976		$	5,880		$	20,369		$	9,957
Conway OPIS composite NGL price($/gal) (based on our NGL product mix)	$	0.79		$	0.66		$	0.77		$	0.64
Average NYMEX crude oil price($/Bbl)	$	51.95		$	38.54		$	49.93		$	36.47
Average condensate sales price($/Bbl)	$	45.91		$	35.45		$	46.29		$	33.80
Average natural gas price($/MMBtu) (mid-continent region)	$	6.26		$	5.51		$	5.99		$	5.36
Gross processing spread ($/MMBtu)	$	2.67		$	1.74		$	2.77		$	1.72

Operating Results - The increase in net margin for both the three and six months ended June 30, 2005, compared with the same periods for 2004, is primarily due to:

•

an increase of $4.8 million and $13.2 million, respectively, due to favorable commodity pricing for natural gas and NGL products on our POP contracts,

•

an increase of $5.5 million and $11.1 million, respectively, attributable to our keep whole contracts due primarily to an increase in our gross processing spread,

•

an increase of $6.0 million and $7.7 million, respectively, 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, which resulted in more residue gas sales, and higher NGL sales as a result of higher gas processing spreads, for ethane in particular,

•

an increase of $2.7 million and $4.5 million, respectively, due to improved third-party sales margins from increased NGL prices, and

•

an increase of $1.1 million and $3.7 million, respectively, due to the addition of certain NGL storage and transportation agreements associated with our NGL storage and pipeline assets located in Conway, Kansas.

The gross processing spread for the second quarter of 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. Based on current market conditions, the gross processing spread for the remainder of 2005 will also be above the previous five-year average. 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 six-month periods is primarily due to:

•

an increase of $2.4 million and $2.9 million, respectively, primarily related to increased environmental and safety expenditures in 2005 related to new storage regulations, and

•

an increase of $0.7 million and $1.1 million, respectively, in materials and chemicals related to compressor utilization and maintenance.

The increase in capital expenditures for both the three- and six-month periods are primarily related to the timing of expenditures for the natural gas liquids pipeline placed in service at the end of 2004 and regulatory compliance enhancements for our Kansas natural gas liquids storage facilities.

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.


	Six Months Ending December 31, 2005
Product	Volumes Hedged	Average Price
Percent of Proceeds:
Condensate (a)	270 MBbls	$	43.71/Bbl
NGL (b)	300 MBbls	$	0.74/gal
Natural gas (c)	3.4 Bcf	$	6.18/MMBtu
Keep Whole:
Gross processing spread (d)	5,452 MMMBtu	$	3.20/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

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

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

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

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 and nonprocessable 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.

We operate approximately 5,600 miles of 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 Federal Energy Regulatory Commission (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.

Our business 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. Volatility in the natural gas market also impacts our customers’ decisions relating to injection and withdrawal of natural gas in storage. Transportation throughput fluctuates due to rainfall that impacts irrigation demand, hot temperatures that affect power generation demand and cold temperatures that affect heating demand.

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 June 30,				Six Months Ended June 30,
Financial Results	2005		2004		2005		2004
	*(Thousands of dollars)*
Transportation and gathering revenues	$	27,551	$	24,455	$	55,920	$	50,571
Storage revenues		14,174		11,405		24,767		22,253
Gas sales and other revenues		1,275		1,195		2,698		2,658
Cost of sales and fuel		11,764		10,542		22,049		18,504

Net margin		31,236		26,513		61,336		56,978
Operating costs		12,105		11,091		23,674		23,840
Depreciation, depletion and amortization		4,438		4,292		8,814		8,556

Operating income	$	14,693	$	11,130	$	28,848	$	24,582

Other income (expense), net	$	273	$	185	$	559	$	2,097


	Three Months Ended June 30,				Six Months Ended June 30,
Operating Information	2005		2004		2005		2004
Volumes transported (MMcf)		108,898		92,812		240,228		221,747
Capital expenditures(Thousands of dollars)	$	3,059	$	1,967	$	4,786	$	4,011
Average natural gas price ($/MMBtu) (mid-continent region)	$	6.26	$	5.51	$	5.99	$	5.36

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

•

an increase of $1.8 million and $1.3 million, respectively, related to increased storage activity as a result of a better pricing environment for inter- and intra-month business,

•

an increase of $0.9 million and $1.3 million, respectively, in transport revenues resulting from increased throughput due to favorable weather conditions for transportation, and

•

an increase of $1.7 million and $1.5 million, respectively, due to our improved fuel position primarily related to increased transport and storage volumes and higher natural gas prices.

The decrease in other income (expense), net, for the six-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.

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. Substantial swings in 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.

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


	Three Months Ended June 30,						Six Months Ended June 30,
Financial Results	2005			2004			2005			2004
	*(Thousands of dollars)*
Gas sales	$	313,689		$	283,846		$	1,055,994		$	1,032,572
Transportation revenues		19,156			17,221			47,528			42,483
Cost of sales and fuel		233,302			203,848			810,212			782,830

Gross margin		99,543			97,219			293,310			292,225
Other revenues		6,949			6,753			14,402			14,761

Net margin		106,492			103,972			307,712			306,986
Operating costs		83,477			80,734			174,105			171,805
Depreciation, depletion and amortization		30,014			25,932			60,003			52,151

Operating income	$	(6,999	)	$	(2,694	)	$	73,604		$	83,030

Other income (expense), net	$	(119	)	$	(736	)	$	(312	)	$	(818	)

Operating Results - Net margin increased by $2.5 million and $0.7 million for the three and six months ended June 30, 2005, compared with the same periods in 2004. The increase in the quarter is primarily attributable to:

•

an increase of $1.3 million related to customer usage primarily in jurisdictions not subject to weather normalization and

•

an increase of $0.9 million due to the ad valorem tax recovery rider in Kansas.

The six-month period includes increases of $3.4 million due to the implementation of new rate schedules in Oklahoma and $3.2 million due to the ad valorem tax recovery rider in Kansas. These increases were offset by reduced customer usage as a result of warmer weather during the first quarter of 2005.

Operating costs increased $2.7 million for the three-month period primarily due to increased labor and employee benefit costs of $2.1 million and increased bad debts of $0.6 million. The $2.3 million increase in operating costs for the six-month period was primarily due to increased labor and employee benefit costs of $4.9 million offset by decreased bad debts of $2.1 million.

Depreciation, depletion and amortization increased for the three- and six-month periods primarily due to a $2.9 million charge related to the replacement of our customer service system in Texas. The ad valorem tax recovery rider in Kansas increased amortization for the three- and six-month periods by $0.9 million and $3.2 million, respectively. Additionally, depreciation increased $1.7 million for the six-month period 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

June 30,

Six Months Ended

June 30,

Operating Information

2005

2004

2005

2004

Average number of customers

2,019,953

2,004,683

2,031,720

2,013,877

Customers per employee

688

664

687

664

Capital expenditures(Thousands of dollars)

36,323

36,728

64,009

62,600

Three Months Ended
June 30,

Six Months Ended

June 30,

Volumes (MMcf)

2005

2004

2005

2004

Gas sales

Residential

14,502

13,624

73,047

75,113

Commercial

5,238

5,036

23,317

25,303

Industrial

419

392

1,201

1,360

Wholesale

9,584

10,793

16,456

15,405

Public Authority

323

345

1,288

1,342

Total volumes sold

30,066

30,190

115,309

118,523

Transportation

58,419

54,182

127,590

121,574

Total volumes delivered

88,485

84,372

242,899

240,097

Three Months Ended
June 30,

Six Months Ended

June 30,

Margin

2005

2004

2005

2004

(Thousands of dollars)

Gas sales

Residential

66,389

63,620

193,380

191,452

Commercial

14,340

14,767

52,195

55,121

Industrial

329

675

1,589

2,135

Wholesale

1,616

1,762

3,196

2,636

Public Authority

573

581

1,561

1,733

Gross margin on gas sales

83,247

81,405

251,921

253,077

Transportation

16,296

15,814

41,389

39,148

Gross margin

99,543

97,219

293,310

292,225

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 six-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 gas volumes available under contracts that exceed the needs of our residential, commercial and industrial customer base and are available for sale to other parties. Wholesale volumes decreased for the three months ended June 30, 2005, as greater volumes were required to meet the needs of residential, commercial and industrial customers. However, for the six-month period, fewer volumes were required to meet customers’ demands, resulting in additional volume being available for sale to other parties.

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

Transportation volumes increased for the three- and six-month periods primarily due to Oklahoma Natural Gas’ commercial and industrial customers 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 $10.4 million and $8.2 million for new business development for the three months ended June 30, 2005 and 2004, respectively, and $19.8 million and $17.0 million for new business development for the six months ended June 30, 2005 and 2004, respectively.

Regulatory Initiatives

Oklahoma - On January 28, 2005, Oklahoma Natural Gas filed a rate case with the OCC requesting annual rate relief of approximately $99.4 million, of which $38.5 million would be paid in additional income taxes. This amount includes $10.7 million of the interim rate relief granted in January 2004 and discussed below. Oklahoma law provides that a utility may implement new rates at the end of a 180-day period in the absence of a final order. On July 28, 2005, Oklahoma Natural Gas implemented new rates for approximately 820,000 customers, in accordance with state statutes.

The OCC administrative law judge who heard the case has recommended an increase in annual revenues of approximately $58 million. The rates that Oklahoma Natural Gas put into effect are based on that amount and will be subject to refund with interest; however, the administrative law judge’s recommendation has been appealed to the full, three-member Commission by Oklahoma Natural Gas and the Oklahoma Attorney General. The appeals were heard by the Commission on August 1, 2005, and the Commissioners have taken the matter under advisement. We expect the Commissioners’ decision during the third quarter.

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 gas in storage investment. 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 categorizes $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, which was filed on January 28, 2005. We believe any refund obligation is remote and, accordingly, have not recorded a reserve. Approximately $7.0 million annually is considered final and not subject to refund.

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.

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 1.5 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 help our customers execute their commodity procurement and asset management strategies. Our trading emphasis is to provide incremental value within a reasonable risk profile.

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.


	Three Months Ended June 30,						Six Months Ended June 30,
Financial Results	2005			2004			2005			2004
	*(Thousands of dollars)*
Energy and power revenues	$	1,562,814		$	47,058		$	3,322,427		$	82,105
Energy trading revenues, net	��	(8,784	)		13,908			408			89,172
Other revenues		196			207			402			444
Cost of sales and fuel		1,541,674			46,891			3,248,590			82,105

Net margin		12,552			14,282			74,647			89,616
Operating costs		8,106			7,919			16,481			18,472
Depreciation, depletion and amortization		1,575			1,424			2,982			2,815

Operating income	$	2,871		$	4,939		$	55,184		$	68,329

Other income (expense), net	$	(1,966	)	$	(1,830	)	$	(3,855	)	$	(3,524	)


	Three Months Ended June 30,				Six Months Ended June 30,
Operating Information	2005		2004		2005		2004
Natural gas marketed(Bcf)		275		249		600		535
Natural gas gross margin ($/Mcf)	$	0.02	$	0.05	$	0.09	$	0.13
Electricity marketed(MMwh)		563		966		1,148		1,751
Physically settled volumes(Bcf)		574		511		1,199		1,051
Capital expenditures(Thousands of dollars)	$	132	$	704	$	159	$	814

Operating Results - Net margin decreased for the three months ended June 30, 2005, compared with the same period in 2004, primarily due to the net impact of:

•

a decrease of $2.6 million in retail activities related to reduced physical margins,

•

a decrease of $5.1 million related to the impact of an increase in NYMEX natural gas prices over the quarter on our natural gas trading operation,

•

an increase of $2.7 million, which was the net of an increase in the value of the Rocky Mountain to mid-continent basis spread, partially offset by unrecovered transportation demand costs, and

•

an increase of $2.2 million in power margins primarily related to improved June 2005 Electric Reliability Council of Texas (ERCOT) heat-rates.

Net margin decreased for the six months ended June 30, 2005, primarily due to:

•

a net decrease of $20.4 million related to storage activity primarily attributable to a 4.5 percent decrease in heating degree days during the first quarter, partially offset by an increase in demand fees associated with long-term contracts, and

•

an increase of $6.5 million in transport margins primarily due to an increase in the natural gas basis spread between the Rocky Mountain and mid-continent trading locations.

Operating costs decreased $2.0 million for the six months ended June 30, 2005, compared with the same period in 2004, primarily due to lower employee-related costs.

Natural gas volumes marketed increased for the three- and six-month periods due to our expanded Canadian operations and additional long-term contracts.

Our natural gas in storage at June 30, 2005, was 59.0 Bcf compared to 58.9 Bcf at June 30, 2004. At June 30, 2005, our total natural gas storage capacity under lease was 86 Bcf compared to 84 Bcf at June 30, 2004.

Included in net margin is the change in value of all of our derivative instruments subject to fair value accounting pursuant to Statement 133, which resulted in a gain of $15.1 million and $0.2 million for the six months ended June 30, 2005 and 2004,

respectively, and a loss of $1.7 million and a gain of $2.9 million for the three months ended June 30, 2005 and 2004, respectively.

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 that 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 these types of margins by activity.


	Three Months Ended June 30, 2005			Six Months Ended June 30, 2005
	*(Thousands of dollars)*
Marketing and storage, gross	$	54,276		$	146,663
Less: Storage and transportation costs		(40,094	)		(83,396	)

Marketing and storage, net		14,182			63,267
Retail marketing		3,047			8,257
Financial trading		(4,677	)		3,123

Net margin	$	12,552		$	74,647

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 six months of 2005 were $123 million, compared with $114 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.

In June 2005, we entered into a $1.0 billion short-term credit agreement. The interest rate is based on 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 Investor Service (Moody’s) and Standard and Poor’s (S&P).

Both the five-year and the short-term credit agreements 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 June 30, 2005, we had no amounts outstanding under either of these credit agreements.

On July 1, 2005, we borrowed $1.0 billion under the short-term credit agreement to assist in financing the Koch assets acquisition. We used our commercial paper program to obtain the remaining funds needed. We anticipate permanent financing of the acquisition to come from a combination of issuance of long-term debt, proceeds from the settlement of our mandatory convertible equity units in February 2006, proceeds from the sale of less strategic assets, such as our Production segment, and available cash.

The total amount of short-term borrowings authorized by our Board of Directors is $2.5 billion. At June 30, 2005, we had $111.5 million in commercial paper outstanding and approximately $16.6 million in cash and temporary investments. We also had $2.3 billion of long-term debt outstanding, including current maturities. As of June 30, 2005, we could have issued $1.6 billion of additional debt under the most restrictive provisions contained in our various borrowing agreements.

On July 25, 2005, we amended the 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 returns to 67.5 percent of total capital. With this change and the additional debt of $1.0 billion borrowed on July 1, 2005, we could have issued $1.0 billion in additional debt under the most restrictive provisions contained in our various borrowing agreements.

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


	June 30, 2005		December 31, 2004
Long-term debt	61	%	54	%
Equity	39	%	46	%

Debt (including Notes payable)	62	%	61	%
Equity	38	%	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 55 percent long-term debt and 45 percent equity at June 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 53 percent long-term debt and 47 percent equity at June 30, 2005.

We have 16.1 million mandatory convertible equity units outstanding at June 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 are required to be exercised. This will result in our receipt of $402.5 million and the issuance of 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.

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+” (CreditWatch negative) by S&P and a “Baa1” (review for downgrade) by Moody’s. 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 $1.0 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 June 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 $113.8 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, and marketing, trading and risk contracts and other various contracts which may be subject to rating triggers and no such triggers were identified. 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 and short-term credit 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 credit 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 price 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 the pension plan and 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 the 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 January 28, 2005, Oklahoma Natural Gas filed a rate case with the OCC requesting annual rate relief of approximately $99.4 million, of which $38.5 million would be paid in additional income taxes. This amount includes $10.7 million of the interim rate relief granted in January 2004 and discussed below. Oklahoma law provides that a utility may implement new rates at the end of a 180-day period in the absence of a final order. On July 28, 2005, Oklahoma Natural Gas implemented new rates for approximately 820,000 customers, in accordance with state statutes.

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 $54.1 million for the six months ended June 30, 2005, compared with the same period in 2004. The decrease in operating cash flows was primarily the result of a net decrease in working capital of $160.9 million in 2005 compared with a net decrease in working capital of $203.6 million in 2004. In 2005, higher prices and our current positions with two counterparties increased our Energy Services segment’s deposit (margin) requirements, which resulted in a decrease in operating cash flows.

Investing Cash Flows - Proceeds from the sale of certain natural gas transmission and gathering pipelines, and compression assets totaled $15 million for the first half of 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.

During the first half of 2005, we paid $110.8 million to repurchase approximately 3.7 million shares of our stock pursuant to a plan 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.

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

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 quarter of 2004, we incurred $40 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 various 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 generally identified by words such as “anticipate,” “estimate,” “expect,” “forecast,” “intend,” “believe,” “projection” or “goal.”

You should not place undue reliance on the 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,

•

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, cost of environmental remediation and oil and natural gas reserves,

•

the timing and extent of changes in commodity prices for natural gas, NGLs, electricity and crude oil,

•

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

•

the impact of recently issued and future accounting pronouncements and other changes in accounting policies,

•

the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions in the Middle East and elsewhere,

•

the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks,

•

the impact of unforeseen changes in interest rates, equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension expense and funding resulting from changes in stock and bond market returns,

•

risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions,

•

the results of administrative proceedings and litigation involving the Oklahoma Corporation Commission, Kansas Corporation Commission, Texas regulatory authorities or any other local, state or federal regulatory body, including the Federal Energy Regulatory Commission,

•

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 and 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, 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 statements.

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 June 30, 2005, Kansas Gas Service had derivative instruments in place to hedge the cost of natural gas purchases for 4.2 Bcf, which represents part of their gas purchase requirements for the 2005/2006 winter heating months based on normal weather conditions.

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 June 30, 2005
Source of Fair Value (1)	Matures through March 2006			Matures through March 2009			Matures through March 2011			Total Fair Value
	*(Thousands of dollars)*
Prices actively quoted (2)	$	38,860		$	5,452		$	—		$	44,312
Prices provided by other external sources (3)		(30,678	)		(14,757	)		(1,120	)		(46,555	)
Prices derived from quotes, other external sources and other assumptions (4)		(1,039	)		56			1,999			1,016

Total	$	7,143		$	(9,249	)	$	879		$	(1,227	)

(1)	Fair value is the mark-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.

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

Interest Rate and Currency Risk - At June 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 six months of 2005 for all terminated swaps was $4.1 million, and the remaining net savings for all terminated swaps will be recognized over the following periods:


Remainder of 2005	$	3.5 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 June 30, 2005, we had a net asset of $3.2 million to recognize the interest rate swaps at fair value. Long-term debt was increased by $3.2 million to recognize the change in fair value of the related hedged liability.

Total savings from the interest rate swaps and amortization of terminated swaps was $6.5 million for the first six months of 2005. The swaps are expected to generate the following savings for the remainder of the year:

•

interest expense savings of $3.5 million for remainder of 2005 related to the amortization of the swap value at termination and

•

up to $1.7 million in interest savings from the existing $340 million of swapped debt, based on LIBOR rates at June 30, 2005.

Total swap savings for 2005 are expected to be $11.7 million, compared to 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 June 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 $17.4 million and $2.7 million at June 30, 2005 and 2004, respectively.

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


	Three Months Ended June 30,				Six Months Ended June 30,
VAR	2005		2004		2005		2004
	*(Millions of dollars)*
Average	$	11.1	$	3.2	$	12.4	$	4.3
High	$	18.1	$	7.1	$	27.1	$	17.7
Low	$	6.1	$	0.7	$	6.1	$	0.7

The variations in the VAR data are reflective of market volatility and changes in the portfolio during the quarter.

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 June 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 June 30, 2005, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1.

Legal Proceedings

United States ex rel. Jack J. Grynberg v. ONEOK, Inc., et al., No. CIV-97-1006-R, United States District Court for the Western District of Oklahoma, transferred,In re Natural Gas Royalties Qui Tam Litigation, MDL Docket No. 1293, United States District Court for the District of Wyoming. On May 13, 2005, the Special Master issued his Report and Recommendation (the “Report”), recommending that several cases, including the case against us, be dismissed for lack of subject matter jurisdiction. Mr. Grynberg has objected to the Special Master’s Report insofar as it recommends dismissal for us and other defendants. Briefing in response to the Report is expected to be completed by August 2005.

Will Price, et al. v. Gas Pipelines, et al. (f/k/a Quinque Operating Company, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 99C30 (“Price I”). As previously discussed in our Annual Report on Form 10-K for the year ended December 31, 2004, we, along with five of our subsidiaries and one of our divisions are among the approximately 225 named defendants in this case. Additionally, in connection with the completion of our acquisition of the natural gas liquids (NGL) businesses owned by several Koch companies, on July 1, 2005, we acquired Koch Hydrocarbon, LP (renamed ONEOK Hydrocarbon, L.P.) which is also one of the named defendants in this case.

Will Price and Stixon Petroleum, et al. v. Gas Pipelines, et al., 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 03C232 (“Price II”). As previously discussed in our Annual Report on Form 10-K for the year ended December 31, 2004, we, along with four of our subsidiaries are among the 21 groups of defendants named in this case. Additionally, in connection with the completion of our acquisition of the natural gas liquids (NGL) businesses owned by several Koch companies, announced on July 1, 2005, we acquired Koch Hydrocarbon, LP (renamed ONEOK Hydrocarbon, L.P.) which is also one of the named defendants in this case.

Loyd Smith, et al. v. Kansas Gas Service Company, Inc., ONEOK, Inc., Western Resources, Inc., Mid Continent Market Center, Inc., ONEOK Gas Storage, L.L.C., ONEOK Gas Storage Holdings, Inc., and ONEOK Gas Transportation, L.L.C., Case No. 01-C-0029, in the District Court of Reno County, Kansas, andGilley et al. v. Kansas Gas Service Company, Western Resources, Inc., ONEOK, Inc., ONEOK Gas Storage, L.L.C., ONEOK Gas Storage Holdings, Inc.,

ONEOK Gas Transportation L.L.C. and Mid Continent Market Center, Inc., Case No. 01-C-0057, in the District Court of Reno County, Kansas. The business class plaintiffs and residential class plaintiffs have filed notices of appeal. We have filed a notice of appeal of the residential class verdict and the attorney fee award. The cases have been transferred to the Kansas Supreme Court for appeal.

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 Administrative Law Judge (ALJ) issued a report on July 20, 2005 recommending an annual revenue increase of $57,990,122. The ALJ also recommended approval of the pipeline Integrity Management Plan Rider and the Gas In Storage Rider. On July 25, 2005, we and the Attorney General both appealed the ALJ Report. The appeals were heard by the Commission en banc on August 1, 2005, after which the Commission took the matter under advisement. The end of the statutory 180-day period was July 27, 2005, and we implemented the rate increase on July 28, 2005, on an interim basis and subject to refund, pursuant to the statute.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

The following table sets forth information relating to our purchases of equity securities during the three months ended June 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)
April 1-30, 2005	318,294	(1)(2)	$	30.63	305,500	5,094,100
May 1-31, 2005	1,278,684	(2)	$	29.61	1,278,600	3,815,500
June 1-30, 2005	80,364	(1)(2)	$	31.80	—	3,815,500

Total	1,677,342		$	29.91	1,584,100	3,815,500

(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 :

12,647 shares for the period April 1-30, 2005

80,291 shares for the period June 1-30, 2005

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

147 shares for the period April 1-30, 2005

84 shares for the period May 1-31, 2005

73 shares for the period June 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 March 31, 2005, a total of 21,940 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 June 30, 2005, under this program.


Date	Closing Price (at or above)		Shares Issued
April 1, 2005	$	31.00	4,607
June 23, 2005	$	32.00	4,588

Total			9,195

On July 1, 2005, our common stock closed above $33.00 per share, which resulted in 4,768 shares being issued to eligible employees. On July 13, 2005, our common stock closed above $34.00 per share, which resulted in 4,760 shares being issued to eligible employees. On August 2, 2005, our common stock closed above $35.00 per share, which resulted in 4,752 shares being issued to eligible employees.

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

We held our 2005 annual meeting of shareholders on May 19, 2005. At this meeting, the individuals set forth below in Class B were elected by a plurality vote to our board of directors for a term of three years, and the individual set forth below in Class C was elected by a plurality vote to our board of directors for a term of one year:


Director (Class)	Votes For	Votes Withheld
James C. Day (Class B)	95,550,312	998,621
David L. Kyle (Class B)	92,019,600	4,529,333
Bert H. Mackie (Class B)	89,310,207	7,238,725
Mollie B. Williford (Class B)	92,030,165	4,518,768
Eduardo A. Rodriguez (Class C)	95,585,319	963,613

The individuals set forth below are the members of our board of directors whose term of office as a director continued after the meeting:


Class C		Class A
(Term ending 2006)		(Term Ending 2007)
William L. Ford		William M. Bell
Douglas Ann Newsom		Julie H. Edwards
Gary D. Parker		Pattye L. Moore

As previously reported, effective July 1, 2005, Julie H. Edwards resigned from our board of directors.

In addition, at this meeting the shareholders took the following actions. The new ONEOK, Inc. Equity Compensation Plan was approved by our shareholders as follows:


	Votes For	Votes Against	Abstained
ONEOK, Inc. Equity Compensation Plan	74,679,954	8,936,714	737,775

The amendment to the ONEOK, Inc. Employee Stock Purchase Plan to increase the number of shares authorized under this plan from 2,800,000 to 3,800,000 was approved by our shareholders as follows:


	Votes For	Votes Against	Abstained
Amendment to the ONEOK, Inc. Employee Stock Purchase Plan	81,439,723	2,291,810	622,908

The appointment of KPMG LLP as our independent auditor for the 2005 fiscal year was ratified by our shareholders as follows:


	Votes For	Votes Against	Abstained
Appointment of KPMG LLP as principal independent auditor	91,909,059	3,894,316	745,557

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		Purchase Agreement between Koch Hydrocarbon Management Company, LLC and ONEOK, Inc. dated May 9, 2005.

10.2		Asset Purchase Agreement between Koch Pipeline Company, L.P. and ONEOK, Inc. dated May 9, 2005.

10.3		Purchase Agreement between Koch Holdings Enterprises, LLC and ONEOK, Inc. dated May 9, 2005.

10.4		Purchase Agreement between Koch Hydrocarbon Management Company, LLC and ONEOK, Inc. dated May 9, 2005.

10.5		Second Amendment To Credit Agreement among ONEOK, Inc., the Borrower, Bank of America, N.A., as Administrative Agent for the Lenders and as a Lender and L/C Issuer, and the Lenders, effective as of July 25, 2005.

12.1		Computation of Ratio of Earnings to Fixed Charges for the six months ended June 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: August 3, 2005	By:	/s/ Jim Kneale
		Jim Kneale
		Executive Vice President - Finance and Administration and Chief Financial Officer (Principal Financial Officer)

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ONEOK (OKE) 10-Q2005 Q2 Quarterly report

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