ONEOK INC /NEW/ - 10-Q 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, 2004

¨	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 2, 2004, the Company had 103,047,219 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, 2004 and 2003	3

	Consolidated Balance Sheets - June 30, 2004 and December 31, 2003	4-5

	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2004 and 2003	6

	Consolidated Statements of Shareholders’ Equity and Comprehensive Income - Six Months Ended June 30, 2004	8-9

	Notes to Consolidated Financial Statements	10-24

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25-45

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45-46

Item 4.	Controls and Procedures	47

Part II.	Other Information

Item 1.	Legal Proceedings	47-48

Item 2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities	48

Item 3.	Defaults Upon Senior Securities	48

Item 4.	Submission of Matters to a Vote of Security Holders	48-49

Item 5.	Other Information	49

Item 6.	Exhibits and Reports on Form 8-K	49-50

Signatures		51

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)*	2004		2003		2004		2003
	*(Thousands of dollars, except per share amounts)*
Revenues
Operating revenues, excluding energy trading revenues	$	618,231	$	457,898	$	1,573,542	$	1,408,937
Energy trading revenues, net		13,908		37,090		89,172		172,761
Cost of gas		402,087		262,552		1,039,903		946,310

Net Revenues		230,052		232,436		622,811		635,388

Operating Expenses
Operations and maintenance		113,646		114,120		244,022		226,563
Depreciation, depletion, and amortization		46,226		39,709		92,966		80,136
General taxes		16,574		16,598		37,109		34,243

Total Operating Expenses		176,446		170,427		374,097		340,942

Operating Income		53,606		62,009		248,714		294,446

Other income		1,655		2,051		9,469		2,905
Other expense		883		1,005		8,473		1,118
Interest expense		24,949		24,969		48,637		53,546

Income before Income Taxes		29,429		38,086		201,073		242,687

Income taxes		11,640		15,538		78,131		94,532

Income from Continuing Operations		17,789		22,548		122,942		148,155
Discontinued operations, net of taxes (Note C):
Income from operations of discontinued component		—		—		—		2,342
Gain on sale of discontinued component		—		—		—		38,369
Cumulative effect of changes in accounting principle, net of tax		—		—		—		(143,885	)

Net Income		17,789		22,548		122,942		44,981
Preferred stock dividends		—		5,045		—		20,211

Income Available for Common Stock	$	17,789	$	17,503	$	122,942	$	24,770

Earnings Per Share of Common Stock (Note M)
Basic:
Earnings per share from continuing operations	$	0.17	$	0.24	$	1.22	$	1.66
Earnings per share from operations of discontinued component		—		—		—		0.02
Earnings per share from gain on sale of discontinued component		—		—		—		0.34
Earnings per share from cumulative effect of changes in accounting principle		—		—		—		(1.28	)

Net earnings per share, basic	$	0.17	$	0.24	$	1.22	$	0.74

Diluted:
Earnings per share from continuing operations	$	0.17	$	0.23	$	1.20	$	1.43
Earnings per share from operations of discontinued component		—		—		—		0.02
Earnings per share from gain on sale of discontinued component		—		—		—		0.34
Earnings per share from cumulative effect of changes in accounting principle		—		—		—		(1.28	)

Net earnings per share, diluted	$	0.17	$	0.23	$	1.20	$	0.51

Average Shares of Common Stock (Thousands)
Basic		102,545		74,412		100,830		79,048
Diluted		103,971		97,025		102,673		97,772

Dividends per share of Common Stock	$	0.44	$	0.17	$	0.63	$	0.34

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS


*(Unaudited)*	June 30, 2004		December 31, 2003
	*(Thousands of dollars)*
Assets
Current Assets
Cash and cash equivalents	$	18,960	$	12,172
Trade accounts and notes receivable, net		815,657		970,141
Materials and supplies		21,576		18,962
Gas in storage		444,569		500,439
Assets from price risk management activities (Note D)		227,033		289,417
Deposits		20,485		42,424
Other current assets		39,437		46,184

Total Current Assets		1,587,717		1,879,739

Property, Plant and Equipment
Production		424,993		404,254
Gathering and Processing		1,047,083		1,036,080
Transportation and Storage		697,280		699,676
Distribution		2,860,055		2,813,800
Marketing and Trading		127,128		126,315
Other		128,741		99,549

Total Property, Plant and Equipment		5,285,280		5,179,674
Accumulated depreciation, depletion, and amortization		1,561,931		1,487,848

Net Property, Plant and Equipment		3,723,349		3,691,826

Deferred Charges and Other Assets
Regulatory assets, net (Note E)		203,887		213,915
Goodwill (Note F)		225,363		225,615
Assets from price risk management activities (Note D)		117,906		113,052
Prepaid pensions		123,965		120,618
Investments and other		86,668		69,283

Total Deferred Charges and Other Assets		757,789		742,483

Total Assets	$	6,068,855	$	6,314,048

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS


	June 30,			December 31,
*(Unaudited)*	2004			2003
	(Thousands of dollars)
Liabilities and Shareholders’ Equity
Current Liabilities
Current maturities of long-term debt	$	341,334		$	6,334
Notes payable		40,000			600,000
Accounts payable		882,773			813,895
Dividends payable		23,685			—
Accrued taxes		43,140			102,637
Accrued interest		33,643			32,999
Customers’ deposits		35,700			34,692
Unrecovered purchased gas costs		65,171			51,378
Liabilities from price risk management activities (Note D)		283,511			302,878
Deferred income taxes		8,250			6,194
Other		118,458			130,174

Total Current Liabilities		1,875,665			2,081,181

Long-term Debt, excluding current maturities		1,525,988			1,878,264
Deferred Credits and Other Liabilities
Deferred income taxes		598,016			559,356
Liabilities from price risk management activities (Note D)		188,435			112,714
Lease obligation		93,555			100,292
Other deferred credits		330,810			340,849

Total Deferred Credits and Other Liabilities		1,210,816			1,113,211

Total Liabilities		4,612,469			5,072,656

Commitments and Contingencies (Note J)
Shareholders’ Equity
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 106,012,637 shares and outstanding 102,976,466 shares at June 30, 2004; issued 98,194,674 shares and outstanding 95,194,666 shares at December 31, 2003		1,060			982
Paid in capital		987,816			815,870
Unearned compensation		(2,489	)		(3,422	)
Accumulated other comprehensive loss (Note G)		(34,603	)		(17,626	)
Retained earnings		555,783			495,971
Treasury stock, at cost: 3,036,171 shares at June 30, 2004 and 3,000,008 shares at December 31, 2003		(51,181	)		(50,383	)

Total Shareholders’ Equity		1,456,386			1,241,392

Total Liabilities and Shareholders’ Equity	$	6,068,855		$	6,314,048

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,
*(Unaudited)*	2004			2003
	(Thousands of dollars)
Operating Activities
Income from continuing operations	$	122,942		$	148,155
Depreciation, depletion, and amortization		92,966			80,136
Gain on sale of assets		(8,606	)		(289	)
Income from equity investments		(541	)		(762	)
Deferred income taxes		52,772			67,999
Stock based compensation expense		4,640			2,095
Allowance for doubtful accounts		10,005			8,573
Changes in assets and liabilities (net of acquisition effects):
Accounts and notes receivable		144,479			152,724
Inventories		53,256			(259,848	)
Unrecovered purchased gas costs		13,793			(5,336	)
Deposits		21,939			—
Regulatory assets		(300	)		2,895
Accounts payable and accrued liabilities		26,962			47,978
Price risk management assets and liabilities		(11,468	)		8,272
Other assets and liabilities		(45,316	)		42,727

Cash Provided by Continuing Operations		477,523			295,319
Cash Provided by Discontinued Operations		—			8,285

Cash Provided by Operating Activities		477,523			303,604

Investing Activities
Changes in other investments, net		888			708
Acquisitions		—			(432,954	)
Capital expenditures		(114,402	)		(84,441	)
Proceeds from sale of property		15,073			—
Other investing activities		(7,033	)		—

Cash Used in Continuing Operations		(105,474	)		(516,687	)
Cash Provided by Discontinued Operations		—			280,669

Cash Used in Investing Activities		(105,474	)		(236,018	)

Financing Activities
Payments of notes payable, net		(560,000	)		(265,500	)
Change in bank overdraft		(15,929	)		11,830
Issuance of debt		—			402,500
Termination of interest rate swaps		82,915			—
Payment of debt issuance costs		—			(2,564	)
Payment of debt		(465	)		(15,667	)
Purchase of Series A Convertible Preferred Stock		—			(300,000	)
Issuance of common stock		168,545			218,521
Issuance (receipt) of treasury stock, net		(798	)		2,445
Dividends paid		(39,529	)		(34,680	)

Cash Provided by (Used in) Financing Activities		(365,261	)		16,885

Change in Cash and Cash Equivalents		6,788			84,471
Cash and Cash Equivalents at Beginning of Period		12,172			73,522

Cash and Cash Equivalents at End of Period	$	18,960		$	157,993

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME


(Unaudited)	Common Stock Issued	Common Stock		Paid-in Capital			Unearned Compensation
	*(Shares)*	*(Thousands of dollars)*
December 31, 2003	98,194,674	$	982	$	815,870		$	(3,422	)
Net income	—		—		—			—
Other comprehensive income (loss)	—		—		—			—

Total comprehensive income

Receipts of restricted stock	—		—		—			—
Issuance of common stock
Common stock offering	6,900,000		69		151,248			—
Stock issuance pursuant to various plans	917,963		9		17,285			—
Offering costs	—		—		(66	)		—
Stock-based employee compensation expense	—		—		3,479			1,161
Common stock dividends (Note H)	—		—		—			(228	)

June 30, 2004	106,012,637	$	1,060	$	987,816		$	(2,489	)

See accompanying Notes to the Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(Continued)


*(Unaudited)*	Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Treasury Stock			Total
	*(Thousands of dollars)*
December 31, 2003	$	(17,626	)	$	495,971		$	(50,383	)	$	1,241,392
Net income		—			122,942			—			122,942
Other comprehensive income (loss)		(16,977	)		—			—			(16,977	)

Total comprehensive income											105,965

Receipts of restricted stock		—			—			(798	)		(798	)
Issuance of common stock
Common stock offering		—			—			—			151,317
Stock issuance pursuant to various plans		—			—			—			17,294
Offering costs		—			—			—			(66	)
Stock-based employee compensation expense		—			—			—			4,640
Common stock dividends (Note H)		—			(63,130	)		—			(63,358	)

June 30, 2004	$	(34,603	)	$	555,783		$	(51,181	)	$	1,456,386

ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

A.	Summary of Accounting Policies

The accompanying unaudited consolidated financial statements of ONEOK, Inc. and its subsidiaries (ONEOK or the Company) have been prepared in accordance with accounting principles generally accepted in the United States of America. The accompanying unaudited consolidated financial statements reflect all adjustments which, in the opinion of management, 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 the Company’s business, the results of operations for the three months and six months ended June 30, 2004, 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 the audited consolidated financial statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003.

The Company’s accounting policies are consistent with those disclosed in Note A of the Notes to Consolidated Financial Statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, except as follows.

Critical Accounting Policies and Estimates

Pension and Postretirement Employee Benefits - In May 2004, the Financial Accounting Standards Board (FASB) issued FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2) as guidance on how employers should account for provisions of the recently enacted Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Reform Act). The Company adopted FSP FAS 106-2 in the second quarter of 2004. FSP FAS 106-2 superceded FASB Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-1), which was adopted by the Company in the first quarter of 2004. See Note I.

Significant Accounting Policies

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2004		2003		2004		2003
	*(Thousands of dollars, except per share amounts)*
Net income, as reported	$	17,789	$	22,548	$	122,942	$	44,981
Add: Stock based compensation included in net income, net of related tax effects		1,499		924		3,350		1,698
Deduct: Total stock based compensation expense determined under fair value based method for all awards, net of related tax effects		1,796		1,227		3,943		2,305

Pro forma net income	$	17,492	$	22,245	$	122,349	$	44,374

Earnings per share:
Basic - as reported	$	0.17	$	0.24	$	1.22	$	0.74
Basic - pro forma	$	0.17	$	0.23	$	1.21	$	0.73
Diluted - as reported	$	0.17	$	0.23	$	1.20	$	0.51
Diluted - pro forma	$	0.17	$	0.23	$	1.19	$	0.51

Related Party Transactions - From time to time and in the normal course of business, the Company:

•

Purchases natural gas and natural gas liquids from, sells natural gas and natural gas liquids to, and provides natural gas and natural gas liquids transportation services to Frontier Oil Corporation and its subsidiaries (Frontier). Julie H. Edwards, Executive Vice President - Finance and Administration and Chief Financial Officer for Frontier, is a member of the Company’s board of directors.

•

Conducts natural gas and natural gas liquids purchase and sale transactions with Williford Energy Company and TriCounty Gas Processors, Inc. Mollie Williford, Chairman of the Board of the Williford Companies, which consists of numerous companies including Williford Energy Company and TriCounty Gas Processors, Inc., is a member of the Company’s board of directors.

The table below shows the purchase and sales transactions with the related parties. The purchase and sale transactions are conducted under substantially the same terms as comparable third-party transactions.


	Three Months Ended June 30, 2004				Six Months Ended June 30, 2004
	Sales		Purchases		Sales		Purchases
	*(Thousands of dollars)*
Frontier	$	40,218	$	328	$	78,427	$	1,117
Williford Companies		—		1,229		—		2,492

Production Property - In July 2004, the FASB proposed FASB Staff Position No. 142-b, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil- and Gas-Producing Entities” (FSP FAS 142-b) to clarify that oil and gas-producing properties are excluded from the requirements in Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”. The comment deadline is August 17, 2004. The Company continues to classify the cost of oil and gas mineral rights as property, plant and equipment on the balance sheet, which is consistent with proposed FSP FAS 142-b.

Other

Reclassifications - Certain amounts in the consolidated financial statements, primarily related to current and noncurrent deferred taxes, have been reclassified to conform to the 2004 presentation. These reclassifications did not impact previously reported net income or shareholders’ equity.

B.	Dispositions

In May 2004, the Company sold its investment in natural gas distribution operations located in Mexico for approximately $2 million and recorded a pre-tax gain of $1.6 million which is included in other income in the Other segment.

On March 1, 2004, the Company sold certain natural gas transmission and gathering pipelines and compression facilities for approximately $13 million. As a result of the sale, the Company recorded a pre-tax gain of $6.9 million, which is included in other income in the Transportation and Storage segment.

C.	Discontinued Operations

In January 2003, the Company sold a portion of its Production segment (the component). The component is accounted for as a discontinued operation in accordance with Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144). Accordingly, amounts in the Company’s financial statements and related notes for all periods shown reflect discontinued operations accounting.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2004		2003		2004		2003
	*(Thousands of dollars)*
Natural gas sales	$	—	$	—	$	—	$	6,036
Oil sales		—		—		—		1,705
Other revenues		—		—		—		—

Net revenues		—		—		—		7,741
Operating costs		—		—		—		1,985
Depreciation, depletion, and amortization		—		—		—		1,937

Operating income	$	—	$	—	$	—	$	3,819

Income taxes	$	—	$	—	$	—	$	1,477

Income from discontinued component	$	—	$	—	$	—	$	2,342

Gain on sale of discontinued component, net of tax of $20.7 million	$	—	$	—	$	—	$	38,369

D.	Price Risk Management Activities and Derivative Financial Instruments

Accounting Treatment - The Company accounts for derivative instruments and hedging activities in accordance with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133). Under Statement 133, entities are required to record all derivative instruments at fair value. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it. If the derivative instrument does not qualify or is not designated as part of a hedging relationship, the Company accounts for changes in fair value of the derivative instrument as they occur. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposure to changes in fair values, cash flows or foreign currencies. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings in the period of change together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. The difference between the change in fair value of the derivative instrument and the change in fair value of the hedged item represents hedge ineffectiveness. For hedges of exposure to changes in cash flow, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive 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 immediately.

As required by Statement 133, the Company formally documents 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. The Company specifically identifies the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item. The Company assesses the effectiveness of hedging relationships, both at the inception of the hedge and on an ongoing basis.

In July 2003, the Emerging Issues Task Force (EITF) of the FASB reached a consensus on EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3, ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities’” (EITF 03-11). EITF 03-11 provides that the determination of whether realized gains and losses on physically settled derivative contracts not “held for trading purposes” should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Consideration of the facts and circumstances should be made in the context of the various activities of the entity rather than based solely on the terms of the individual contracts. The Company has continued to present the financial results of all energy trading contracts on a net basis.

At the beginning of the third quarter, the Company completed a reorganization of its Marketing and Trading segment and renewed its focus on the physical marketing and storage business. The Company separated the management and operations of its physical marketing, retail marketing and trading activities and began accounting separately for the different types of revenue sources among these activities. As a result of this reorganization, the Company is evaluating the accounting treatment related to the presentation of revenues for the different types of activities to determine which amounts should be reported on a gross or net

basis under the guidance in EITF 03-11. The Company expects that a portion of these activities will be presented on a gross basis beginning with the third quarter of 2004. Reporting of these transactions on a gross basis will not impact operating income but will increase revenues and cost of gas.

Fair Value Hedges

The Marketing and Trading segment uses basis swaps to hedge the fair value of certain transportation commitments. At June 30, 2004, net price risk management assets include $8.7 million to recognize the fair value of the Marketing and Trading segment’s derivatives that are designated as fair value hedging instruments. The ineffectiveness related to these hedges was a loss of approximately $0.4 million and $1.4 million for the three and six months ended June 30, 2004, respectively. This amount is included as a reduction in operating revenues.

The Company is subject to the risk of fluctuations in interest rates in the normal course of business. The Company manages interest rate risk through the use of fixed rate debt, floating rate debt and at times, interest rate swaps.

During the first quarter of 2004, the Company terminated $670 million of its interest rate swap agreements to lock in savings and received $91.8 million, which includes $8.9 million of interest rate savings previously recorded. These interest rate swaps were previously initiated as a strategy to hedge the fair value of fixed-rate, long-term debt. The net proceeds received upon termination of the interest rate swaps was $81.9 million, after reduction for ineffectiveness and unpaid interest. During 2004, $3.2 million in interest expense savings was recognized and the remaining amount of $78.7 million will be recognized in the income statement over the remaining term of the debt instruments originally hedged. Consequently, the savings in interest expense will be recognized over the following periods:


2004	$	4.9 million
2005	$	10.0 million
2006	$	10.0 million
2007	$	10.0 million
2008	$	10.0 million
Thereafter	$	33.8 million

The Company has entered into new swap agreements to replace the terminated agreements. Currently, $740 million of 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, 2004, the Company recorded a $40.7 million net liability to recognize the interest rate swaps at fair value. Long-term debt was also decreased by $40.7 million to recognize the change in the fair value of the related hedged liability.

The change in the fair value of the related hedged liability and the terminated swaps resulted in $38.8 million which is included in long-term debt at June 30, 2004.

Cash Flow Hedges

The Marketing and Trading segment uses futures and swaps to hedge the cash flows associated with its natural gas. Accumulated other comprehensive income (loss) at June 30, 2004, includes losses of approximately $24.2 million, net of tax, related to these hedges that will be realized within the next seven months. The offsetting gains will be recorded when the physical delivery of the hedged item occurs. When gas inventory is sold, net gains and losses are reclassified out of accumulated other comprehensive income to energy trading revenues, net. Ineffectiveness related to these cash flow hedges was a loss of approximately $2.0 million and $3.1 million for the three and six months ended June 30, 2004, respectively. Additionally, losses of approximately $4.6 million were recognized from accumulated other comprehensive income 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.

The Production segment periodically enters into derivative instruments to hedge the cash flows associated with its exposure to changes in the price of natural gas and oil. Accumulated other comprehensive income (loss) at June 30, 2004, includes losses of approximately $8.2 million, net of tax, for the production hedges that will be realized in the income statement within the next 18 months.

The Gathering and Processing segment periodically enters into derivative instruments to minimize the risk associated with natural gas price volatility related to the Company’s natural gas and NGL sales. Accumulated other comprehensive income (loss) at June

30, 2004 includes income of approximately $0.1 million, net of tax, for gathering and processing hedges entered into during the second quarter of 2004 that will be realized in the income statement within the next six months.

The Company’s regulated businesses also use 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, 2004, Kansas Gas Service Company (KGS) had derivative instruments in place to hedge the cost of natural gas purchases for 3.1 Bcf of natural gas, representing part of KGS’ gas purchase requirements for the 2004/2005 winter heating months based on normal weather conditions. Gains or losses associated with the KGS hedges are included in and recoverable through the monthly purchased gas adjustment.

E.	Regulatory Assets

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


	June 30, 2004		December 31, 2003
	*(Thousands of dollars)*
Recoupable take-or-pay	$	61,307	$	64,171
Pension costs		15,418		18,060
Postretirement costs other than pension		55,769		59,118
Transition costs		16,455		16,691
Reacquired debt costs		20,206		20,635
Income taxes		20,126		21,782
Weather normalization		4,202		1,075
Line replacements		522		495
Service lines		2,180		3,250
Other		7,702		8,638

Regulatory assets, net	$	203,887	$	213,915

On January 30, 2004, the Oklahoma Corporation Commission (OCC) approved Oklahoma Natural Gas Company’s (ONG) request that it be allowed to recover costs that the Company has incurred since 2000 when it assumed responsibility for its customers’ service lines and enhanced efforts to protect pipelines from corrosion. ONG also sought to recover costs related to its investment in gas in storage and rising levels of fuel-related bad debts. The order allows rate relief of $17.7 million annually with $10.7 million as interim and subject to refund until a final determination at the Company’s next general rate case. ONG has committed to filing for a general rate review no later than January 31, 2005. Approximately $7.0 million annually is considered final and not subject to refund. With the approval of ONG’s request, the Company began amortizing the deferred costs associated with these OCC directives over an eighteen month period. At June 30, 2004, the Company had approximately $4.0 million remaining to be amortized compared to $6.0 million at December 31, 2003. These deferred costs are included in the captions “Service lines” and “Other” in the regulatory assets table above.

ONG’s current estimate of future rate relief is substantially in excess of the refund threshold of $10.7 million. The Company believes that any refund obligation is remote and, accordingly, it has not recorded a reserve. The Company will continue to monitor the regulatory environment to determine any changes in its estimated future rate relief. Should its analysis indicate a potential refund liability, the Company will record a reserve for this obligation.

F.	Goodwill

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


	December 31, 2003		Adjustments			June 30, 2004
	*(Thousands of dollars)*
Gathering and Processing	$	34,343	$	—		$	34,343
Transportation and Storage		22,288		(252	)		22,036
Distribution		158,729		—			158,729
Marketing and Trading		10,255		—			10,255

Total consolidated	$	225,615	$	(252	)	$	225,363


	December 31, 2002		Adjustments			June 30, 2003
	*(Thousands of dollars)*
Gathering and Processing	$	34,343	$	(734	)	$	33,609
Transportation and Storage		22,183		70			22,253
Distribution		51,368		113,456			164,824
Marketing and Trading		5,616		4,427			10,043

Total consolidated	$	113,510	$	117,219		$	230,729

The 2004 adjustment to goodwill resulted from the sale of certain natural gas transmission and gathering pipelines and compression facilities on March 1, 2004. The 2003 adjustments to goodwill resulted from the preliminary purchase price allocation of the Texas assets acquired in January 2003.

The Company completed its annual analysis of goodwill for impairment as of January 1, 2004 and there was no impairment indicated.

G.	Comprehensive Income

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


	Three Months Ended June 30,
	2004						2003
	*(Thousands of dollars)*
Net income				$	17,789					$	22,548
Other comprehensive income (loss):
Unrealized gains (losses) on derivative instruments	$	(20,315	)				$	15,784
Unrealized holding gains arising during the period		30						182
Realized losses in net income		3,510						805

Other comprehensive income (loss) before taxes		(16,775	)					16,771
Income tax benefit (provision) on other comprehensive loss		6,490						(6,484	)

Other comprehensive income (loss)					(10,285	)					10,287

Comprehensive income				$	7,504					$	32,835


	Six Months Ended June 30,
	2004						2003
	*(Thousands of dollars)*
Net income				$	122,942					$	44,981
Other comprehensive income (loss):
Unrealized gains (losses) on derivative instruments	$	(42,792	)				$	4,338
Unrealized holding gains (losses) arising during the period		(76	)					106
Realized losses in net income		15,187						3,019

Other comprehensive income (loss) before taxes		(27,681	)					7,463
Income tax benefit (provision) on other comprehensive loss		10,704						(2,885	)

Other comprehensive income (loss)					(16,977	)					4,578

Comprehensive income				$	105,965					$	49,559

Accumulated other comprehensive income (loss) reflected in the consolidated balance sheet at June 30, 2004, includes unrealized gains and losses on derivative instruments and minimum pension liability adjustments.

H.	Capital Stock

Common Stock - The Company uses newly issued shares to meet the purchase requirements generated by participants in its Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries. All participant purchases under this plan are voluntary. During the three months ended June 30, 2004, the Company issued 339,688 shares for a total of $7.2 million. During the six months ended June 30, 2004, the Company issued 664,888 shares for a total of $14.5 million. The Company also uses newly issued shares to meet the purchase requirements generated by the Dividend Reinvestment Plan and the Long-Term Incentive Plan.

2004 Common Stock Offering - During the first quarter of 2004, the Company sold 6.9 million shares of its common stock to an underwriter at $21.93 per share, resulting in proceeds to the Company, before expenses, of $151.3 million.

Dividends - Quarterly dividends paid on the Company’s common stock for shareholders of record during the three and six months ended June 30, 2004, were $0.21 per share and $0.40 per share, respectively. In May 2004, the Company’s board of directors announced an increase in the quarterly dividend on the Company’s common stock to $0.23 per share payable in the third quarter of 2004.

I.	Employee Benefit Plans

The table below provides the components of net periodic benefit cost (income).


	Pension Benefits Three Months Ended June 30,						Pension Benefits Six Months Ended June 30,
	2004			2003			2004			2003
	*(Thousands of dollars)*
Components of Net Periodic Benefit Cost (Income)
Service cost	$	3,982		$	3,403		$	7,963		$	6,806
Interest cost		10,372			10,227			20,743			20,454
Expected return on assets		(15,486	)		(15,681	)		(30,971	)		(31,362	)
Amortization of unrecognized net asset at adoption		(79	)		(117	)		(157	)		(234	)
Amortization of unrecognized prior service cost		166			149			332			298
Amortization of loss		577			407			1,155			814

Net periodic benefit income	$	(468	)	$	(1,612	)	$	(935	)	$	(3,224	)


	Postretirement Benefits Three Months Ended June 30,						Postretirement Benefits Six Months Ended June 30,
	2004			2003			2004			2003
	*(Thousands of dollars)*
Components of Net Periodic Benefit Cost (Income)
Service cost	$	1,482		$	1,303		$	3,123		$	2,606
Interest cost		3,293			3,003			6,900			6,006
Expected return on assets		(940	)		(763	)		(1,879	)		(1,526	)
Amortization of unrecognized net asset at adoption		864			836			1,728			1,672
Amortization of unrecognized prior service cost		25			(30	)		49			(60	)
Amortization of loss		1,434			966			3,291			1,932

Net periodic benefit cost	$	6,158		$	5,315		$	13,212		$	10,630

Contributions - For the six months ended June 30, 2004, $1.8 million and $6.8 million of contributions had been made for the pension plan and other postretirement benefit plan, respectively. The Company presently anticipates its total 2004 contributions to be $4.8 million for the pension plan and $13.4 million for the other postretirement benefit plan.

Other Postretirement Benefits Changes - In May 2004, the FASB issued FSP FAS 106-2 as guidance on how employers should account for provisions of the recently enacted Medicare Reform Act. The Company adopted FSP FAS 106-2 in the second quarter of 2004. FSP FAS 106-2 superceded FSP FAS 106-1, which was adopted by the Company in the first quarter of 2004. The Medicare Reform Act allows employers who sponsor a postretirement health care plan that provides a prescription drug benefit to receive a subsidy for the cost of providing that drug benefit. In order for employers to receive the subsidy payment under the Medicare Reform Act, the value of the offered prescription drug plan must be at least actuarially equivalent to the standard prescription drug coverage provided under Medicare Part D. Due to the Company’s lower deductibles and better coverage of drug costs, the Company believes that its plan is of greater value than Medicare Part D and will meet the actuarially equivalent definitions. The three months ended June 30, 2004, was the first time the Company could record a benefit related to the Medicare Reform Act, since a September 30 measurement date is used for this plan. The reduction in the accumulated postretirement benefit obligation related to benefits attributed to past service was $18.1 million. The amortization for the actuarial experience gain as a component of the net amortization was $0.4 million for both the three and six months ended June 30, 2004. The reduction in current period service cost due to the subsidy was $0.2 million for both the three and six months ended June 30, 2004. The resulting reduction in interest cost on the accumulated postretirement benefit obligation was $0.3 million for both the three and six months ended June 30, 2004. The Company believes that its plan will continue to provide drug benefits that are at least actuarially equivalent to Medicare Part D, that its plan will continue to be the primary plan for the Company’s retirees and that the Company will receive the subsidy. The Company does not expect that the Medicare Reform Act will have a significant effect on the Company’s retirees’ participation in its postretirement benefit plan.

J.	Commitments and Contingencies

Environmental - The Company is 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 the Company 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 the Company to fines, penalties and/or interruptions in operations that could be material to the results of the Company’s operations. If an accidental leak or spill of hazardous materials occurs from the Company’s lines or facilities, in the process of transporting natural gas, or at any facilities that the Company owns, operates or otherwise uses, the Company could be held jointly and severally liable for all resulting liabilities, including investigation and clean up costs, which could materially affect the Company’s 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 the Company’s facilities. The Company cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to the Company. 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 the Company’s business, financial condition and results of operations.

The Company owns or retains legal responsibility for the environmental conditions at 12 former manufactured gas sites in Kansas. These sites contain potentially harmful materials that are subject to control or remediation under various environmental laws and regulations. A consent agreement with the Kansas Department of Health and Environment (KDHE) presently governs all work at these sites. The terms of the consent agreement allow the Company to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. The Company has commenced active remediation on

three sites with regulatory closure achieved at two of these locations, and has begun assessment at the remaining sites. The site situations are not common and the Company has no previous experience with similar remediation efforts. The Company has completed some analysis of the remaining nine sites, but is unable to accurately estimate individual or aggregate costs that may be required to satisfy the remedial obligations.

The Company’s preliminary review of similar cleanup efforts at former manufactured gas sites reveals that costs can range from $100,000 to $10 million per site. These estimates do not give effect to potential insurance recoveries, recoveries through rates or from unaffiliated parties, to which the Company may be entitled. At this time, the Company has not recorded any amounts for potential insurance recoveries or recoveries from unaffiliated parties, and the Company is not recovering any environmental amounts in rates. The cost to remediate the two sites, which have achieved regulatory closure, totaled approximately $800,000. Total remedial costs for each of the remaining sites are expected to exceed $400,000 per site, but there is no assurance that costs to investigate and remediate the remaining sites will not be significantly higher. As more information related to the site investigations and remediation activities becomes available, and to the extent such amounts are expected to exceed the Company’s current estimates, additional expenses could be recorded. Such amounts could be material to the Company’s results of operations and cash flows depending on the remediation done and number of years over which the remediation is completed.

The Company’s 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 2004 related to compliance with environmental regulations.

Yaggy Facility - In January 2001, the Yaggy gas storage facility’s operating parameters were changed as mandated by the KDHE following natural gas explosions and eruptions of natural gas geysers in or near Hutchison, Kansas. In July 2002, the KDHE issued an administrative order that assessed a civil penalty against the Company, based on alleged violations of several KDHE regulations. On April 5, 2004, the Company and the KDHE entered into a Consent Order in which the Company paid a civil penalty in the amount of $180,000 and reimbursed the KDHE for its costs related to the investigation of the incident in the amount of approximately $79,000. In addition, the Consent Order requires the Company to conduct an environmental remediation and a geoengineering study. The Company believes there are no material adverse effects resulting from the Consent Order.

Two class action lawsuits have been filed against the Company in connection with the natural gas explosions and eruptions of natural gas geysers that occurred at, and in the vicinity of, the Yaggy facility in January 2001. These class action lawsuits claim that the explosions were caused by the release of natural gas from the Company’s operations. In addition to the two pending class action matters, there are four currently pending lawsuits that have been filed against the Company or subsidiaries seeking recovery for various claims related to the Yaggy incident, including property damage, personal injury, loss of business and, in some instances, punitive damage. In February 2004, a jury awarded the plaintiffs in one lawsuit $1.7 million in actual damages. In April 2004, the judge awarded punitive damages in the amount of $5.25 million. The Company has filed its notice of appeal of the jury verdict and the punitive damage award. The Company is vigorously defending these matters and, although no assurances can be given, believes its legal reserves and insurance coverage are adequate and that the ultimate resolution of these matters will not have a material adverse effect on the Company’s financial position or results of operations.

U.S. Commodity Futures Trading Commission - On April 14, 2004, the Company received a subpoena from the U.S. Commodity Futures Trading Commission (CFTC) requesting information in connection with the CFTC’s industry wide investigation relating to “Activities Affecting the Price of Natural Gas in the Fall of 2003”. The CFTC specifically requested information related to reporting of natural gas storage information to the Energy Information Agency during the time period of October 31, 2003—January 2, 2004. The Company cooperated fully with the CFTC’s request and has furnished the requested information. At the present time the Company cannot determine whether the CFTC’s industry wide investigation will have any adverse impact on the Company.

The Company and its wholly owned subsidiary, ONEOK Energy Marketing and Trading Company, L.P., have been named as two of the defendants in a class action lawsuit filed in the United States District Court for the Southern District of New York brought on behalf of persons who bought and sold natural gas futures and options contracts on the New York Mercantile Exchange during the years 2000 through 2002. Although the Company agreed to a civil monetary penalty with the CFTC in that matter, it cannot guarantee other additional legal proceedings, civil or criminal fines or penalties, or other regulatory action related to this issue will not arise. However, the Company plans to vigorously defend any claims related to this issue and does not expect this matter to have a material adverse effect on the Company’s consolidated results of operations, financial condition or liquidity.

United States and Canada Local 781 and the International Union of Operating Engineers Local 126 labor unions agreed upon a five-year contract expiring June 30, 2009. Approximately 475 KGS employees are members of these three labor unions, comprising approximately 41 percent of the KGS workforce. The parties agreed to a three percent wage increase retroactive to June 1, 2004 and an increase for each of the next four years as follows:

•

three percent beginning July 1, 2005

•

two and one-half percent beginning July 1, 2006

•

two and one-half percent beginning July 1, 2007

•

two and one-half percent beginning July 1, 2008

Currently, the Company has no ongoing labor negotiations.

Other - The Company is a party to other litigation matters and claims including environmental matters, which are normal in the ordinary course of its operations. While the results of litigation and claims cannot be predicted with certainty, management believes the final outcome of such matters will not have a material adverse effect on the Company’s consolidated results of operations, financial position, or liquidity.

K.	Segments

The accounting policies of the Company’s business segments are substantially the same as those described in the Summary of Significant Accounting Policies in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, except for those changes discussed in Note A. Intersegment sales are recorded on the same basis as sales to unaffiliated customers. Corporate overhead costs relating to the segments are allocated for the purpose of calculating operating income. The Company’s equity method investments do not represent operating segments of the Company. The Company has no single external customer from which it receives ten percent or more of its consolidated gross revenues.

The following tables set forth certain selected financial information for the Company’s six operating segments for the periods indicated.

Regulated

Non-Regulated

Three Months Ended June 30, 2004

Transportation
and
Storage

Distribution

Marketing and
Trading

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

25,739

—

^(a

⁾

109,692

1,135

(136,566

)

—

Total Revenues

37,055

307,820

61,173

451,934

24,144

(249,987

)

632,139

Net revenues

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

551

—

(59

)

492

Capital expenditures

1,967

36,728

704

5,880

11,946

8,275

65,500

^(a) - Intersegment sales for Marketing and Trading were $114.3 million for the three months ended June 30, 2004.


	Regulated				Non-Regulated
Three Months Ended June 30, 2003	Transportation and Storage		Distribution		Marketing and Trading			Gathering and Processing		Production		Other and Eliminations			Total
	*(Thousands of dollars)*
Sales to unaffiliated customers	$	20,097	$	298,703	$	21,607		$	218,701	$	8,784	$	(109,994	)	$	457,898
Energy trading revenues, net		—		—		37,090			—		—		—			37,090
Intersegment sales		18,392		—		^(a	⁾		168,460		963		(187,815	)		—

Total Revenues	$	38,489	$	298,703	$	58,697		$	387,161	$	9,747	$	(297,809	)	$	494,988

Net revenues	$	27,017	$	102,956	$	39,377		$	52,338	$	9,747	$	1,001		$	232,436
Operating costs	$	11,484	$	78,816	$	7,422		$	29,226	$	3,935	$	(165	)	$	130,718
Depreciation, depletion and amortization	$	4,184	$	23,722	$	1,469		$	7,337	$	2,637	$	360		$	39,709
Operating income	$	11,349	$	418	$	30,486		$	15,775	$	3,175	$	806		$	62,009
Income from equity investments	$	347	$	—	$	—		$	—	$	—	$	—		$	347
Capital expenditures	$	3,817	$	34,160	$	313		$	5,520	$	3,780	$	3,368		$	50,958

^(a) - Intersegment sales for Marketing and Trading were $111.0 million for the three months ended June 30, 2003.

Regulated

Non-Regulated

Six Months Ended June 30, 2004

Transportation
and
Storage

Distribution

Marketing and
Trading

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

50,237

—

^(a

⁾

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 revenues

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

—

(59

)

541

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 Marketing and Trading were $327.4 million for the six months ended June 30, 2004.


	Regulated					Non-Regulated
Six Months Ended June 30, 2003	Transportation and Storage			Distribution		Marketing and Trading			Gathering and Processing			Production		Other and Eliminations			Total
	*(Thousands of dollars)*
Sales to unaffiliated customers	$	40,272		$	991,035	$	34,141		$	628,962		$	21,296	$	(306,769	)	$	1,408,937
Energy trading revenues, net		—			—		172,761			—			—		—			172,761
Intersegment sales		36,767			—		^(a	⁾		298,983			1,096		(336,846	)		—

Total Revenues	$	77,039		$	991,035	$	206,902		$	927,945		$	22,392	$	(643,615	)	$	1,581,698

Net revenues	$	57,162		$	278,294	$	176,878		$	98,665		$	22,392	$	1,997		$	635,388
Operating costs	$	22,350		$	155,237	$	16,525		$	60,489		$	7,545	$	(1,340	)	$	260,806
Depreciation, depletion and amortization	$	8,338		$	47,610	$	2,931		$	14,538		$	5,995	$	724		$	80,136
Operating income	$	26,474		$	75,447	$	157,422		$	23,638		$	8,852	$	2,613		$	294,446
Income from operations of discontinued component	$	—		$	—	$	—		$	—		$	2,342	$	—		$	2,342
Cumulative effect of changes in accounting principles, net of tax	$	(645	)	$	—	$	(141,982	)	$	(1,375	)	$	117	$	—		$	(143,885	)
Income from equity investments	$	762		$	—	$	—		$	—		$	—	$	—		$	762
Total assets	$	846,200		$	2,320,080	$	1,341,542		$	1,281,774		$	147,624	$	(318,545	)	$	5,618,675
Capital expenditures	$	4,801		$	59,126	$	396		$	7,992		$	6,728	$	5,398		$	84,441

^(a) - Intersegment sales for Marketing and Trading were $308.5 million for the six months ended June 30, 2003.

L.	Supplemental Cash Flow Information

The following table sets forth supplemental information with respect to the Company’s cash flows for the periods indicated.


	Six Months Ended June 30,
	2004		2003
	*(Thousands of dollars)*
Cash paid (received) during the period
Interest (including amounts capitalized)	$	26,023	$	49,719
Income taxes paid (received)	$	88,424	$	(3,635	)
Noncash transactions
Cumulative effect of changes in accounting principle
Rescission of EITF 98-10 (price risk management assets and liabilities)	$	—	$	141,832
Adoption of Statement 143	$	—	$	2,053
Dividends payable	$	23,685	$	17,781
Dividends on restricted stock	$	228	$	121
Treasury stock transferred to compensation plans	$	—	$	1,324
Issuance of restricted stock, net	$	—	$	3,201


	Six Months Ended June 30,
	2004		2003
	*(Thousands of dollars)*
Acquisitions
Property, plant and equipment	$	—	$	290,054
Current assets		—		69,919
Current liabilities		—		(66,935	)
Regulatory assets and goodwill		—		126,708
Other assets		—		2,875
Lease obligation		—		(4,715	)
Deferred credits		—		(37,399	)
Deferred income taxes		—		52,447

Cash paid for acquisitions	$	—	$	432,954

M.	Earnings Per Share Information

The Company computes earnings per common share (EPS) as described in Note S of the Notes to Consolidated Financial Statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003.

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


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

Diluted EPS from continuing operations
Income from continuing operations available for common stock and common stock equivalents	$	17,789	103,971	$	0.17


	Three Months Ended June 30, 2003
	Income		Shares	Per Share Amount
	*(Thousands, except per share amounts)*
Basic EPS from continuing operations
Income from continuing operations available for common stock	$	17,503	74,412	$	0.24
Effect of other dilutive securities:
Options and other dilutive securities		—	798
Series D Convertible Preferred Stock dividends		5,045	21,815

Diluted EPS from continuing operations
Income from continuing operations available for common stock and common stock equivalents	$	22,548	97,025	$	0.23


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

Diluted EPS from continuing operations
Income from continuing operations available for common stock and common stock equivalents	$	122,942	102,673	$	1.20


	Six Months Ended June 30, 2003
	Income		Shares	Per Share Amount
	*(Thousands, except per share amounts)*
Basic EPS from continuing operations
Income from continuing operations available for common stock under D-95	$	26,174	62,055
Series A Convertible Preferred Stock dividends		12,139	39,893

Income from continuing operations available for common stock and assumed conversion of Series A Convertible Preferred Stock		38,313	101,948	$	0.37

Further dilution from applying the “two-class” method				$	(0.08	)


Basic EPS from continuing operations under D-95				$	0.29
Income from continuing operations available for common stock not under D-95		101,770	74,315	$	1.37

Basic EPS from continuing operations				$	1.66

Income from continuing operations available for Series D Convertible Preferred Stock dividends		140,083	79,048
Effect of other dilutive securities:
Options and other dilutive securities		—	645
Series D Convertible Preferred Stock dividends		8,072	18,079

Income from continuing operations	$	148,155	97,772	$	1.51

Further dilution from applying the “two-class” method				$	(0.08	)

Diluted EPS from continuing operations				$	1.43

There were 37,902 and 145,474 option shares excluded from the calculation of diluted EPS for the three months ended June 30, 2004 and 2003, respectively, since their inclusion would be antidilutive for each period. For the six months ended June 30, 2004 and 2003, there were 20,713 and 216,709 option shares, respectively, excluded from the calculation of diluted EPS since their inclusion would be antidilutive for each period.

During 2003, the Company issued mandatory convertible equity units. These mandatory convertible units have a dilutive effect on EPS if the average stock price for the most recent 20 trading days exceeds $20.63 per share. For the three months ended June 30, 2004, the applicable average stock price was $21.47 which resulted in 0.8 million dilutive units and reduced diluted EPS by less than one cent. For the six months ended June 30, 2004, the applicable average stock price was $22.02 which resulted in 1.2 million dilutive units and reduced diluted EPS by approximately $0.01 per share.

The repurchase and exchange of the Company’s Series A Convertible Preferred Stock from Westar in February 2003 was recorded at fair value. In accordance with EITF Topic No. D-42, the premium, or the excess of the fair value of the consideration transferred to Westar over the carrying value of the Series A Convertible Preferred Stock, was considered a preferred dividend. The premium recorded on the repurchase and exchange of the Series A Convertible Preferred Stock was approximately $44.2 million and $53.4 million, respectively, for a total premium of $97.6 million. As a result of the Company’s adoption of Topic D-95, the Company has recognized additional dilution of approximately $94.5 million through the application of the “two-class” method of computing EPS. This additional dilution offsets the total premium recorded, resulting in a net premium of $3.1

million, which is reflected as a dividend on the Series A Convertible Preferred Stock in the above EPS calculation for the six months ended June 30, 2003.

N.	Debt Covenant Compliance

The Company’s revolving credit facility has customary covenants that relate to liens, investments, fundamental changes in the business, the restriction of certain payments, changes in the nature of the business, transactions with affiliates, burdensome agreements, the use of proceeds, and a limit on the Company’s debt to capital ratio. The facility includes a term-out option, which allows the Company to convert any outstanding borrowings under the credit agreement into a 364-day term note at the expiration of the credit agreement. Other debt agreements to which the Company is a party have negative covenants that relate to liens and sale/leaseback transactions. At June 30, 2004, the Company was in compliance with all covenants.

Item 2.

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

Executive Summary - In May, our board of directors announced another increase in our quarterly common stock dividend, the third increase this year. Since January 1, 2004, our quarterly dividend has increased from 18 to 23 cents per common share, an increase of 28 percent.

In August, we increased our earnings guidance for 2004 by six cents, to a range of $2.18 to $2.24 per share. The impact of higher prices for natural gas liquids compared to natural gas on keep whole contracts as well as higher prices in general for natural gas and natural gas liquids has had a positive effect on our Gathering and Processing segment. As a result, operating income for this segment in 2004 is expected to exceed 2003 by $36 million. For the six months ended June 30, 2004, operating income for this segment exceeded the same period in 2003 by $24 million. Our continuing effort to amend keep whole contracts and modify plant operations has had a positive effect in this part of our business.

Conversely, we expect our Marketing and Trading segment to be below last year, earning approximately $155 million compared to $197 million in 2003. Although we continue to generate strong earnings from our physical business, trading revenues are expected to decrease due primarily to reduced volatility in prices and weather as well as decreases in inter-regional price spreads.

In July 2004, our Marketing and Trading segment entered into a multi-year agreement to sell gas to the natural gas distributor for the city of Chicago. Based on current New York Mercantile Exchange (NYMEX) prices, gas revenues provided under this agreement are expected to range between $300 million and $575 million over the term of the agreement.

The acquisition of the natural gas and oil properties in Texas during 2003 has positively impacted the Production segment in the current year as we anticipated.

With our stable earnings base, we continue to perform well.

Acquisitions and Divestitures - In May 2004, we sold our investment in natural gas distribution operations located in Mexico for approximately $2 million and recorded a pre-tax gain of $1.6 million, which is included in other income in the Other segment.

On March 1, 2004, we sold certain natural gas transmission and gathering pipelines and compression facilities for approximately $13 million. As a result of the sale, we recorded a pre-tax gain of $6.9 million, which is included in other income in our Transportation and Storage segment.

Regulatory - On January 30, 2004, the Oklahoma Corporation Commission (OCC) issued an order allowing Oklahoma Natural Gas Company (ONG) 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 ONG’s service lines and gas in storage investment. The Commission’s order also approved a modified distribution main extension policy and authorized ONG to defer expected homeland security costs. The order authorized the new rates to be in effect for a maximum of 18 months and categorized $10.7 million of the annual additional revenues as interim and subject to refund until a final determination at ONG’s next general rate case. Approximately $7.0 million annually is considered final and not subject to refund. ONG has committed to filing for a general rate review no later than January 31, 2005.

Our current estimate of the future rate relief is substantially in excess of the refund threshold of $10.7 million. We believe any refund obligation is remote and, accordingly, have not recorded a reserve. We will continue to monitor the regulatory environment to determine any changes in our estimated future rate relief. Should our analysis indicate a potential refund liability, we will record a reserve for the obligation.

Impact of New Accounting Standards - In May 2004, the Financial Accounting Standards Board (FASB) issued FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2) as guidance on how employers should account for provisions of the recently enacted Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Reform Act). We adopted FSP FAS 106-2 in the second quarter of 2004. FSP FAS 106-2 superceded FASB Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS

106-1), which we adopted in the first quarter of 2004. The Medicare Reform Act allows employers who sponsor a postretirement health care plan that provides a prescription drug benefit to receive a subsidy for the cost of providing that drug benefit. In order for employers to receive the subsidy payment under the Medicare Reform Act, the value of the offered prescription drug plan must be at least actuarially equivalent to the standard prescription drug coverage provided under Medicare Part D. Due to our lower deductibles and better coverage of drug costs, we believe that our plan is of greater value than Medicare Part D and will meet the actuarially equivalent definitions. The three months ended June 30, 2004, was the first time we could record a benefit from Medicare Reform Act, since a September 30 measurement date is used for this plan. The reduction in the accumulated postretirement benefit obligation related to benefits attributed to past service was $18.1 million. The amortization for the actuarial experience gain as a component of the net amortization was $0.4 million for both the three and six months ended June 30, 2004. The reduction in current period service cost due to the subsidy was $0.2 million for both the three and six months ended June 30, 2004. The resulting reduction in interest cost on the accumulated postretirement benefit obligation was $0.3 million for both the three and six months ended June 30, 2004. We believe that our plan will continue to provide drug benefits that are actuarially equivalent to Medicare Part D, that our plan will continue to be the primary plan for our retirees and that we will receive the subsidy. We do not expect that the Medicare Reform Act will have a significant effect on our retirees’ participation in our postretirement benefit plan.

Critical Accounting Policies and Estimates

Energy Trading Derivatives and Risk Management Activities - We engage in wholesale marketing and trading, price risk management activities and asset optimization services. In providing asset optimization services, we partner with other utilities to provide risk management functions on their behalf. We account for derivative instruments utilized in connection with these activities 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 by Statement of Financial Accounting Standards No. 137, “Accounting for Derivative Instruments and Hedging Activities—Deferral of the Effective Date of FASB Statement No. 133” (Statement 137), No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” (Statement 138) and No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (Statement 149). We were not impacted by Statement 149.

Under Statement 133, entities are required to record all derivative instruments at fair value. A number of assumptions are considered in the determination of fair value. Our derivatives are primarily concentrated in markets where quoted prices exist. 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. Other factors impacting our estimates of fair value include 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 45 for amounts in our portfolio at June 30, 2004 that were determined by prices actively quoted, prices provided by other external sources, and prices derived from other sources. The gain or loss from changes in fair value is recorded in the period of the change. The volatility of commodity prices 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.

Energy-related contracts that are not accounted for pursuant to Statement 133 are no longer carried at fair value, but are accounted for on an accrual basis as executory contracts. Energy trading inventories carried under storage agreements are no longer carried at fair value, but are carried at the lower of cost or market. Changes to the accounting for existing contracts as a result of the rescission of Emerging Issues Task Force Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10) were reported as a cumulative effect of a change in accounting principle on January 1, 2003. This resulted in a cumulative effect loss, net of tax, of $141.8 million.

Regulation - Our intrastate transmission pipelines and distribution operations are subject to the rate regulation and accounting requirements of the OCC, Kansas Corporation Commission (KCC), Railroad Commission of Texas (RRC) and various municipalities in Texas. Certain of our other transportation activities are subject to regulation by the Federal Energy Regulatory Commission (FERC). ONG, Kansas Gas Service Company (KGS), Texas Gas Service Company (TGS) and portions of the Transportation and Storage segment follow the accounting and reporting guidance contained in Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71). During the rate-making process, regulatory authorities may require a utility to defer recognition of certain costs to be recovered through rates over time as opposed to expensing such costs as incurred. This allows the utility to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. Accordingly, actions of the regulatory authorities could have an effect on the amount recovered from rate payers. Any difference in the amount recoverable and the amount deferred would be recorded as income or expense at the time of the regulatory action. If all or a portion of the regulated operations becomes no longer subject to

the provision of Statement 71, a write-off of regulatory assets and stranded costs may be required. At June 30, 2004, our regulatory assets totaled $203.9 million.

Impairment of Goodwill and Long-Lived Assets - We assess our goodwill for impairment at least annually based on Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (Statement 142). An initial assessment is made by comparing the fair value of the operations with goodwill, as determined in accordance with Statement 142, to the book value. 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 associated with the 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, an impairment charge is recorded. See Note F of the Notes to Consolidated Financial Statements in this Form 10-Q.

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

Examples of long-lived asset impairment indicators include:

•

significant and long-term declines in commodity prices

•

a major accident affecting the use of an asset

•

part or all of a regulated business no longer operating under Statement 71

•

a significant decrease in the rate of return for a regulated business

Pension and Postretirement Employee Benefits - We have a defined pension plan covering substantially all full-time employees and a postretirement employee benefits plan covering most employees. Our actuarial consultant, in calculating the expense and liability related to these plans, 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. Assumptions used in determining the projected benefit obligations and the costs can change from period to period which could result in material changes in the costs and liabilities we recognize. See Note I of the Notes to Consolidated Financial Statements in this Form 10-Q.

Contingencies - Our accounting for contingencies covers a variety of business activities including contingencies for potentially uncollectible receivables, and legal 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 projections 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	2004		2003		2004		2003
	*(Thousands of dollars)*
Operating revenues, excluding energy trading revenues	$	618,231	$	457,898	$	1,573,542	$	1,408,937
Energy trading revenues, net		13,908		37,090		89,172		172,761
Cost of gas		402,087		262,552		1,039,903		946,310

Net revenues		230,052		232,436		622,811		635,388
Operating costs		130,220		130,718		281,131		260,806
Depreciation, depletion, and amortization		46,226		39,709		92,966		80,136

Operating income	$	53,606	$	62,009	$	248,714	$	294,446

Other income	$	1,655	$	2,051	$	9,469	$	2,905
Other expense	$	883	$	1,005	$	8,473	$	1,118

Discontinued operations, net of taxes (Note C)
Income from discontinued component	$	—	$	—	$	—	$	2,342
Gain on sale of discontinued component	$	—	$	—	$	—	$	38,369

Cumulative effect of a change in accounting principle, net of tax	$	—	$	—	$	—	$	(143,885	)

Operating Results - Changes in commodity prices can have a significant impact on our earnings, particularly in our Gathering and Processing segment. Volatility in prices, such as we experienced in the first half of 2003, provides the opportunity for increased margins in our Marketing and Trading segment. Net revenues decreased for the three and six months ended June 30, 2004 compared to the same periods in 2003 primarily due to reduced volatility in natural gas prices partially offset by increases in our Distribution, Production and Gathering and Processing segments due to rate relief, higher volumes sold and market conditions, respectively.

Consolidated operating costs remained relatively stable for the three months ended June 30, 2004 compared to the same period in 2003. Consolidated operating costs increased for the six months ended June 30, 2004 compared to the same period in 2003, primarily due to:

•

increased employee and contractor costs of $11.5 million in our Distribution segment

•

increased production costs of $6.5 million related primarily to our Production segment’s December 2003 acquisition

•

increased bad debt expense of $2.6 million in our Distribution segment

Depreciation, depletion and amortization increased for the three and six months ended June 30, 2004 compared to the same periods in 2003, primarily due to:

•

additional depreciation of $3.4 million and $6.6 million for the three and six months ended June 30, 2004, respectively, resulting from the Texas gas and oil properties acquired in December 2003

•

regulatory asset amortization resulting from the Kansas and Oklahoma rate cases

In order to consolidate the three customer service systems in our Distribution segment and provide better customer service, we are implementing a new customer service system. In June 2004, the system was installed in Texas. Installation will follow in Kansas and Oklahoma within the next year. We have implemented control processes and performed extensive testing on this system. However, as with any significant system conversion, there are inherent risks and uncertainties that could negatively impact us.

The following tables show the components of other income and other expense for the three and six months ended June 30, 2004 and 2003.


	Three Months Ended June 30,					Six Months Ended June 30,
	2004			2003		2004			2003
	*(Thousands of dollars)*
Gains on sale of property	$	1,642		$	—	$	8,606		$	289
Partnership income		217			372		542			786
Interest income		223			706		454			1,084
Benefit plan income (expense)		(600	)		716		(721	)		337
Other		173			257		588			409

Other income	$	1,655		$	2,051	$	9,469		$	2,905


	Three Months Ended June 30,					Six Months Ended June 30,
	2004			2003		2004			2003
	*(Thousands of dollars)*
Litigation expenses and claims, net	$	225		$	110	$	7,220		$	(857	)
Donations, civic, and governmental		541			537		1,129			966
Other		117			358		124			1,009

Other expense	$	883		$	1,005	$	8,473		$	1,118

In 2002, we sold our claims related to the Enron bankruptcy. In the first quarter of 2004, we were required to repurchase a portion of those claims resulting in an expense of approximately $1.8 million related to the decrease in value of the claims.

More information regarding our results of operations is provided in the discussion of each segment’s results. The discontinued component is included in our Production segment discussion and the cumulative effect of a change in accounting principle is included in our Marketing and Trading segment’s financial results.

Production

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

As a result of our strategy to grow through acquisitions and developmental drilling, the number of wells we operate increases as we grow our producing reserves. In our role as operator, we control operating decisions that impact production volumes and lifting costs, which are costs incurred to extract the natural gas and oil. We continually focus on reducing finding costs and minimizing production costs.

Acquisitionand Divestiture - The following acquisition and divestiture are described in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2003:

•

purchased gas and oil properties and related flow lines in December 2003

•

sold natural gas and oil producing properties in January 2003

Development Activities - For the six months ended June 30, 2004, we had the following results:

•

participated in drilling 67 wells, including 22 wells during the second quarter

•

participated in completing 27 producing gas wells, including 16 wells during the second quarter

•

40 wells were still drilling or being completed at June 30, 2004

•

no dry holes

For the six months ended June 30, 2003, we had the following results:

•

participated in drilling 19 wells, including 14 wells during the second quarter

•

participated in completing seven producing gas wells and one producing oil well, including three producing gas wells and one producing oil well during the second quarter

•

ten wells were still drilling or being completed at June 30, 2003

•

one dry hole of which our net interest was six percent

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	2004			2003			2004			2003
	*(Thousands of dollars)*
Natural gas sales	$	20,459		$	8,266		$	43,225		$	17,845
Oil sales		2,318			1,458			4,874			3,793
Other revenues		1,367			23			2,432			754

Net revenues		24,144			9,747			50,531			22,392
Operating costs		6,017			3,935			14,041			7,545
Depreciation, depletion, and amortization		6,153			2,637			12,654			5,995

Operating income	$	11,974		$	3,175		$	23,836		$	8,852

Other income (expense), net	$	(64	)	$	16		$	(90	)	$	5

Discontinued operations, net of taxes (Note C)
Income from discontinued component	$	—		$	—		$	—		$	2,342
Gain on sale of discontinued component	$	—		$	—		$	—		$	38,369

Cumulative effect of change in accounting principle, net of tax	$	—		$	—		$	—		$	117


	Three Months Ended June 30,						Six Months Ended June 30,
Operating Information	2004			2003			2004			2003
Proved reserves ^(a)
Continuing operations
Gas (MMcf)		^(b	⁾		^(b	⁾		214,702			60,323
Oil (MBbls)		^(b	⁾		^(b	⁾		3,586			2,188
Production
Continuing operations
Gas (MMcf)		4,060			1,741			8,303			3,573
Oil (MBbls)		83			58			169			135
Discontinued component
Gas (MMcf)		—			—			—			1,472
Oil (MBbls)		—			—			—			53
Average realized price ^(c)
Continuing operations
Gas ($/Mcf)	$	5.04		$	4.75		$	5.21		$	4.99
Oil ($/Bbls)	$	27.93		$	25.14		$	28.84		$	28.10
Discontinued component
Gas ($/Mcf)	$	—		$	—		$	—		$	4.10
Oil ($/Bbls)	$	—		$	—		$	—		$	32.28
Capital expenditures (Thousands of dollars)
Continuing operations	$	11,946		$	3,780			20,418		$	6,728

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

^(b)	Reserves are disclosed at a point in time, therefore reserves are only shown as of June 30, 2004 and 2003.

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

Operating Results - Natural gas and crude oil sales increased for the three and six months ended June 30, 2004 compared to the same periods in 2003 due to:

•

volumes produced from the Texas properties acquired in December 2003

•

higher prices received on current year volumes

Our Texas properties produced 2.2 Bcf and 4.8 Bcf of natural gas during the three and six months ended June 30, 2004, respectively. Oil production from these properties was 32,000 Bbls and 67,000 Bbls for the same periods.

Average natural gas prices before hedges were:

•

$5.61 per Mcf for the three months ended June 30, 2004 compared to $5.13 per Mcf for the same period in 2003

•

$5.60 per Mcf for the six months ended June 30, 2004 compared to $5.70 per Mcf for the same period in 2003

Other revenues increased for the three and six months ended June 30, 2004 as a result of the flow line fees and revenues from our Texas flow line system which we purchased in December 2003.

Operating costs increased for the three months ended June 30, 2004 compared to the same period in 2003 primarily due to a $1.8 million increase in lease operating expenses related to the acquisition of the Texas properties.

For the six months ended June 30, 2004 compared to the same period in 2003, the Texas acquisition led to the following increases in operating costs:

•

$1.5 million related to higher overhead costs

•

$3.0 million in lease operating expenses

•

$1.0 million in production taxes and $1.0 million for ad valorem taxes

The increases in depreciation, depletion and amortization for the three and six-month periods were also primarily due to the Texas acquisition.

The Production segment added 6.5 Bcfe of net natural gas and oil reserves for the six months ended June 30, 2004. This included 2.4 Bcfe of proved developed reserves, comprised of 0.4 Bcfe of proved developed producing reserves and 2.0 Bcfe of proved developed non-producing reserves.

Discontinued Component - Income from the discontinued component includes only one month of production in 2003 before the properties were sold.

Capital Expenditures - Capital expenditures primarily relate to our developmental drilling program. Production from existing wells naturally declines over time and additional drilling for existing wells 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 utilized derivative instruments for the three and six months ended June 30, 2004 and 2003, in order to hedge anticipated sales of natural gas and oil production. The realized financial impact of the derivative transactions is included in net revenues. For the remainder of 2004, we have hedged approximately 95 percent of our anticipated natural gas production at an average net price at the wellhead of $5.50 per Mcf, and approximately 100 percent of our anticipated oil production at a fixed NYMEX price of $30.35 per Bbl. Currently, we have hedges on 20 MMcf per day of our 2005 natural gas production at a net wellhead price of $5.68 per Mcf. We have also hedged an additional 10 MMcf per day for the first quarter of 2005 at a net wellhead price of $6.12 per Mcf.

Gathering and Processing

Overview - Our Gathering and Processing segment is engaged in the gathering, processing and marketing of natural gas and the fractionation (separation), storage and marketing of natural gas liquids (NGLs) primarily in Texas, Oklahoma and Kansas. We have processing capacity of approximately 1.9 Bcf/d, of which approximately 0.1 Bcf/d is currently idle. We own approximately 13,800 miles of gathering pipelines that supply gas to our processing plants.

The gathering and processing operation includes the gathering of natural gas production from oil and gas wells and the processing of this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities. When the liquids are separated from the raw natural gas at the processing plants, the liquids are generally in the form of a mixed stream. This stream is then separated by a distillation process 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. The following table sets forth our contract mix on a volumetric basis for the periods indicated.


	Three Months Ended June 30,				Six Months Ended June 30,
Contract Type	2004		2003		2004		2003
Fee	46	%	46	%	46	%	47	%
Percent of Proceeds	31	%	28	%	31	%	27	%
Keep Whole	23	%	26	%	23	%	26	%

Characteristics of the contract types are explained below.

•

Under a fee contract, we are paid a fee for each Btu gathered, compressed and processed. The producer may take its share of the NGLs and natural gas in kind or receive its share of proceeds from our sale of the commodities. This type of contract exposes us to little commodity risk.

•

Under a percent of proceeds (POP) contract, 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. The producer may take its share of the NGLs and natural gas in kind or receive its share of proceeds from our sale of the commodities. The POP contract exposes us to both natural gas and NGL commodity price risk, but puts the producer in economic alignment with us because we both benefit from higher commodity prices.

•

Under a keep whole contract, we extract NGLs and return to the producer volumes of merchantable natural gas containing the same Btu content as the raw natural gas that was delivered to us. We retain the NGLs as our fee for processing. Accordingly, we must purchase and return to the producer sufficient volumes of merchantable natural gas to replace the Btus that were removed as NGLs through processing. By using this method, the producer is kept whole on a Btu basis. This type of contract exposes us to the keep whole spread, which is the relative difference in value between NGLs and natural gas on a Btu basis.

We have been successful in amending contracts covering about 18 percent of the volume associated with our keep whole contracts to allow us to charge conditioning fees for processing when the keep whole spread is negative. This amendment helps mitigate the impact of unfavorable keep whole spreads between the two commodities by effectively converting a keep whole contract to a fee contract during periods of negative keep whole spreads. Our effort to add this conditioning language began in 2002 and remains a strategy that we continue to execute today. We are also continuing our strategy of restructuring any unprofitable gas purchase and gathering contracts.

Additionally, we are able to modify 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 price spread or prices. These strategies are intended to decrease the volatility of the net revenues generated by this segment.

We are exposed to volume risk from both a competitive and a production standpoint. We continue to see declines in the fields that feed our gathering and processing operations and the possibility exists that declines may outpace development from new drilling. The factors that typically affect our ability to compete are the fees charged under the contract, pressures maintained on the gathering systems, location of the gathering systems relative to our competitors, efficiency and reliability of operations and the delivery capabilities that exist at each plant location.

Acquisition - The following acquisition is described in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2003:

•

acquired NGL storage and pipeline facilities located in Conway, Kansas in December 2003

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	2004			2003			2004			2003
	*(Thousands of dollars)*
Natural gas liquids and condensate sales	$	263,653		$	209,047		$	538,204		$	514,783
Gas sales		161,993			156,168			316,259			366,622
Gathering, compression, dehydration and processing fees and other revenues		26,288			21,946			48,880			46,540
Cost of sales		388,375			334,823			780,358			829,280

Net revenues		63,559			52,338			122,985			98,665
Operating costs		28,057			29,226			59,021			60,489
Depreciation, depletion, and amortization		8,153			7,337			16,166			14,538

Operating income	$	27,349		$	15,775		$	47,798		$	23,638

Other income (expense), net	$	(284	)	$	(4	)	$	(289	)	$	(15	)

Cumulative effect of a change in accounting principle, net of tax	$	—		$	—		$	—		$	(1,375	)


	Three Months Ended June 30,						Six Months Ended June 30,
Operating Information	2004			2003			2004			2003
Total gas gathered (MMMBtu/d)		1,113			1,157			1,110			1,189
Total gas processed (MMMBtu/d)		1,147			1,224			1,155			1,223
Natural gas liquids sales (MBbls/d)		101			99			106			114
Natural gas liquids produced (MBbls/d)		59			58			60			56
Gas sales (MMMBtu/d)		332			322			322			338
Capital expenditures (Thousands of dollars)	$	5,880		$	5,520			9,957		$	7,992
Conway OPIS composite NGL price ($/gal) (based on our NGL product mix)	$	0.66		$	0.54		$	0.64		$	0.59
Average NYMEX crude oil price ($/Bbl)	$	38.54		$	29.27		$	36.47		$	31.63
Average natural gas price ($/MMBtu) (mid-continent region)	$	5.51		$	5.00		$	5.36		$	5.55

Operating Results - Net revenues for the three months ended June 30, 2004 increased compared to the same period in 2003 for the following reasons:

•

increased NGL and condensate sales primarily as a result of higher NGL and condensate prices, which are typically based on crude oil prices

•

increased gas sales primarily due to the increase in natural gas prices partially offset by increased cost of sales due to higher prices for both natural gas and NGLs

•

improved keep whole spreads due to the higher value of NGLs relative to natural gas

Net revenues for the six months ended June 30, 2004 increased compared to the same period in 2003 primarily due to higher NGL and condensate prices.

Improved contractual terms for gas gathering and processing resulting from our continued efforts to restructure unprofitable gas purchase and gathering contracts and favorable keep whole spreads contributed to the increase in net revenues for both the three and six-month periods in 2004 compared to the same periods in 2003.

Increases for both the three and six-month periods were partially offset by lower volumes gathered and processed as a result of natural field declines, bypassing of certain non-processable gas at our plants and the termination of low margin gas purchase and gathering agreements.

Decreased gas sales and cost of sales for the six-month period primarily resulted from the decrease in natural gas prices. Natural gas sales volumes also decreased while NGL volumes produced increased because market conditions favored NGL production in the first quarter of 2004 while contrasting market conditions favored gas sales in the first quarter of 2003.

Operating costs remain in line with management expectations and were slightly lower than in 2003 for both the three and six-month periods.

Depreciation, depletion and amortization increased for the three months ended June 30, 2004 compared to the same period in 2003 primarily due to the properties acquired and our normal capital expenditure program.

Risk Management - We used derivative instruments during the three and six months ended June 30, 2004 and 2003 to minimize risk associated with natural gas price volatility. For the six months ended June 30, 2004 we used derivative instruments to minimize the risk associated with our natural gas and NGL sales. The realized financial impact of the derivative transactions is included in our operating income. For the remainder of 2004, we have hedged approximately 50 percent of our equity condensate sales at an average NYMEX price of $38.38 per Bbl. We have also pre-sold for the remainder of 2004, approximately 50 percent of certain equity natural gas liquids at a weighted average price of $0.62 per gallon.

Transportation and Storage

Overview - Our Transportation and Storage segment 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 have significant supply and market connections to 68 pipelines, 34 processing plants and seven producing fields.

We operate approximately 5,500 miles of gathering and intrastate transmission pipelines in Oklahoma, Kansas and Texas where we are regulated by the OCC, KCC, and RRC, respectively. We have a peak transportation capacity of 2.9 Bcf per day. The majority of our revenues are derived from services provided to affiliates. We serve local distribution companies, large industrial companies, power generation facilities and marketing companies. We compete directly with other interstate and intrastate pipelines and storage facilities. Competition for transportation services continues to increase as the FERC and state regulatory bodies continue to encourage more competition in the natural gas markets. Factors that affect competition are location, natural gas prices, fees for services and quality of service provided.

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

Acquisition and Divestitures - The following acquisition is described on page 25:

•

sold transmission and gathering pipelines and compression facilities in March 2004

The following acquisition and divestiture are described in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2003:

•

sold Texas transmission assets in October 2003

•

acquired transmission assets as part of the purchase of our Texas assets in January 2003

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


	Three Months Ended June 30,				Six Months Ended June 30,
Financial Results	2004		2003		2004		2003
	*(Thousands of dollars)*
Transportation and gathering revenues	$	24,455	$	25,663	$	50,571	$	53,148
Storage revenues		11,405		11,236		22,253		20,303
Gas sales and other		1,195		1,590		2,658		3,588
Cost of fuel and gas		10,542		11,472		18,504		19,877

Net revenues		26,513		27,017		56,978		57,162
Operating costs		11,091		11,484		23,840		22,350
Depreciation, depletion, and amortization		4,292		4,184		8,556		8,338

Operating income	$	11,130	$	11,349	$	24,582	$	26,474

Other income (expense), net	$	185	$	376	$	2,097	$	889

Cumulative effect of a change in accounting principle, net of tax	$	—	$	—	$	—	$	(645	)


	Three Months Ended June 30,				Six Months Ended June 30,
Operating Information	2004		2003		2004		2003
Volumes transported (MMcf)		92,812		95,138		221,747		240,118
Capital expenditures (Thousands of dollars)	$	1,967	$	3,817		4,011	$	4,801
Average natural gas price ($/MMBtu) (mid-continent region)	$	5.51	$	5.00	$	5.36	$	5.55

Operating results - Net revenues showed little change for the three and six months ended June 30, 2004 compared to the same periods in 2003.

For the three and six months ended June 30, 2004, net revenues were impacted by the following:

•

decreased volumes transported as a result of milder and wetter weather reducing irrigation and power plant demand

•

increased storage revenues due to additional spot storage transactions associated with favorable market conditions resulting from the weather and favorable forward pricing in the first quarter of 2004

•

decreased cost of fuel and gas due to the reduction of fuel consumed resulting from lower transportation volumes partially offset by the impact of increased storage activity on fuel consumed

The increase in other income, net for the six months ended June 30, 2004 compared to the same period in 2003 includes the gain on the sale of the Texas assets of $6.9 million, offset by litigation costs.

Distribution

Overview - Our Distribution segment provides natural gas distribution services in Kansas, Oklahoma and Texas. Operations in Kansas are conducted through KGS, which serves residential, commercial, industrial, transportation and wholesale customers. Operations in Oklahoma are conducted through ONG, which serves residential, commercial, industrial and transportation customers. Operations in Texas are conducted through TGS, which serves residential, commercial, industrial, public authority and transportation customers. Our Distribution segment provides gas service to approximately 71 percent, 86 percent and 14 percent of the distribution markets of Kansas, Oklahoma and Texas, respectively. KGS and ONG are subject to regulatory oversight by the KCC and OCC, respectively. TGS is subject to regulatory oversight by the various municipalities that it serves, which have primary jurisdiction in their respective areas. TGS’ rates in areas adjacent to the various municipalities and appellate matters are subject to regulatory oversight by the RRC.

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 the other months of the year.

Acquisitions - The following acquisitions are described in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2003:

•

acquired the gas distribution system at the United States Army’s Fort Bliss in El Paso, Texas in August 2003

•

acquired a pipeline system that extends through the Rio Grande Valley region in Texas in August 2003

•

acquired Texas gas distribution assets in January 2003

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	2004			2003			2004			2003
	*(Thousands of dollars)*
Gas sales	$	283,846		$	277,972		$	1,032,572		$	940,027
Cost of gas		203,848			195,747			782,830			712,741

Gross margin		79,998			82,225			249,742			227,286
Transportation revenues		17,221			14,276			42,483			37,497
Other revenues		6,753			6,455			14,761			13,511

Net revenues		103,972			102,956			306,986			278,294
Operating costs		80,734			78,816			171,805			155,237
Depreciation, depletion, and amortization		25,932			23,722			52,151			47,610

Operating income (loss)	$	(2,694	)	$	418		$	83,030		$	75,447

Other income (expense), net	$	(736	)	$	(111	)	$	(818	)		(589	)

Operating Results - The Distribution segment’s 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 distribution 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 impacting our gross margin since most factors that affect gas sales also affect cost of gas by an equivalent amount. The decrease in gross margin for the three months ended June 30, 2004 compared to the same period in 2003 is primarily attributable to:

•

decreased ONG customer usage which lowered gross margin by $5.0 million partially offset by the implementation of ONG’s new rate schedule in January 2004 which added $2.4 million to gross margin

•

a reduction of $5.8 million due to the elimination of KGS’ WeatherProof Bill program in December 2003 which reversed part of the impact seen in the first quarter offset by the implementation of KGS’ new rate schedule in September 2003 which added $6.5 million to gross margin

The increase in gross margin for the six months ended June 30, 2004 compared to the same period in 2003 is primarily attributable to:

•

implementation of KGS’ new rate schedule in September 2003 which added $16.5 million to gross margin

•

the addition of $3.2 million to gross margin due to the elimination of KGS’ WeatherProof Bill program in December 2003 which is expected to reverse in the third quarter

•

implementation of ONG’s new rate schedule in January 2004 which added $8.3 million to gross margin, offset by decreased customer usage which lowered gross margin by $6.0 million

The $16.5 million increase in KGS’ gross margin is a result of an order issued by the KCC approving $45 million annually in rate relief. ONG’s new rate schedule, which added $8.3 million to gross margin in the six months ended June 30, 2004, is part of $17.7 million in rate relief approved by an order from the OCC.

The increase in transportation revenues for the three and six months ended June 30, 2004 is primarily due to the acquisitions of the distribution system at the United States Army’s Fort Bliss in El Paso, Texas and a pipeline system that extends through the

Rio Grande Valley region in Texas in August 2003. Additionally, lower thresholds to qualify for transportation rates in Oklahoma have contributed to the increase, as certain commercial and industrial customers have converted to transportation rates.

Operating costs increased for the three months ended June 30, 2004 compared to the same period in 2003 primarily due to:

•

increased employee costs of $2.4 million attributable to increased benefit costs

•

increased contractor costs of $1.7 million

These increases in operating costs were partially offset by decreased bad debt expense of $1.8 million.

Operating costs increased for the six months ended June 30, 2004 compared to the same periods in 2003 primarily due to:

•

increased employee costs of $8.3 million mainly resulting from increased benefit costs

•

increased contractor costs of $3.2 million

•

increased bad debt expense of $2.6 million

•

increased property taxes of $0.9 million

Depreciation, depletion and amortization increased for the three and six months ended June 30, 2004 compared to the same period in 2003 primarily due to:

•

regulatory asset amortization resulting from the Kansas and Oklahoma rate cases

•

the acquisitions of the distribution systems at United States Army’s Fort Bliss in El Paso, Texas and a pipeline system that extends through the Rio Grande Valley region in Texas in August 2003

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

Three Months Ended

June 30,

Six Months Ended

June 30,

Operating Information

2004

2003

2004

2003

Average Number of Customers

2,004,683

1,987,892

2,013,877

1,999,834

Customers per employee

664

655

664

658

Capital expenditures (Thousands of dollars)

36,728

34,160

62,600

59,126

Three Months Ended

June 30,

Six Months Ended

June 30,

Volumes (MMcf)

2004

2003

2004

2003

Gas sales

Residential

13,624

14,703

75,113

78,294

Commercial

5,036

6,142

25,303

27,678

Industrial

392

642

1,360

2,094

Wholesale

10,793

10,239

15,405

13,545

Public Authority

345

333

1,342

1,403

Total volumes sold

30,190

32,059

118,523

123,014

Transportation

54,182

48,411

121,574

112,647

Total volumes delivered

84,372

80,470

240,097

235,661


	Three Months Ended June 30,				Six Months Ended June 30,
Margin	2004		2003		2004		2003
	*(Thousands of dollars)*
Gas sales
Residential	$	62,594	$	64,730	$	189,023	$	169,785
Commercial		14,415		15,021		54,283		51,313
Industrial		646		349		2,067		1,913
Wholesale		1,762		1,729		2,636		2,748
Public Authority		581		394		1,733		1,525

Gross margin		79,998		82,223		249,742		227,284
Transportation		17,221		14,277		42,483		37,498

Total margin	$	97,219	$	96,500	$	292,225	$	264,782

Residential and commercial volumes decreased for the three and six months ended June 30, 2004 compared to the same periods in 2003 due to:

•

warmer weather

•

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

Industrial volumes decreased for the three and six months ended June 30, 2004 compared to the same periods in 2003 due to:

•

industrial customers migrating to transportation rates in Oklahoma

•

the current economic environment reducing overall consumption

Wholesale sales, also known as “as available” gas sales, represent gas volumes available under contracts that exceed the needs of our residential and commercial customer base and are available for sale to other parties. Wholesale volumes increased for the three and six months ended June 30, 2004 compared to the same periods in 2003 as fewer volumes were required to meet the needs of KGS’ residential, commercial, and industrial customers resulting in greater volumes available for wholesale customers.

Public authority volumes reflect volumes used by state agencies and school districts serviced by TGS.

Transportation volumes increased for the three and six months ended June 30, 2004 compared to the same periods in 2003 primarily due to:

•

ONG’s commercial and industrial customers migrating to transport rates

•

ONG’s marketing effort to add small usage transport customers

•

the acquisitions of the distribution systems at United States Army’s Fort Bliss in El Paso, Texas and a pipeline system that extends through the Rio Grande Valley region in Texas in August 2003

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 $8.2 million and $6.0 million for new business development for the three months ended June 30, 2004 and 2003, respectively, and $17.0 million and $11.9 million for new business development for the six months ended June 30, 2004 and 2003, respectively.

Regulatory Initiatives

Oklahoma - On January 30, 2004, the OCC issued an order allowing ONG an 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 ONG’s service lines and gas in storage investment. The Commission’s order also approved a modified distribution main extension policy and authorized ONG to defer expected homeland security costs. The order authorized the new rates to be in effect for a maximum of 18 months and categorized $10.7 million of the annual additional revenues as interim and subject to refund until a final determination at ONG’s next general rate case. Approximately $7.0 million annually is considered final and not subject to refund. ONG has committed to filing for a general rate review no later than January 31, 2005.

Our current estimate of the future rate relief is substantially in excess of the refund threshold of $10.7 million. We believe any refund obligation is remote and, accordingly, have not recorded a reserve. We will continue to monitor the regulatory environment to determine any changes in our estimated future rate relief and, should our analysis indicate a potential refund liability, we will record a reserve for the obligation.

Kansas - On September 17, 2003, the KCC issued an order approving $45 million in rate relief for our Kansas customers pursuant to the stipulated settlement agreement with KGS. The order settled the rate case filed by KGS in January 2003 and allowed KGS to begin operating under the new rate schedules effective September 22, 2003. After amortization of previously deferred costs, we estimate that operating income will increase by approximately $29.6 million annually.

Texas - On November 12, 2003, TGS filed an appeal with the RRC based on the denial of proposed rate filing by the cities of Port Neches, Nederland and Groves, Texas. On July 22, 2004, the RRC approved approximately $0.9 million in annual revenue relief. The rates were implemented in May 2003 and were subject to refund prior to the RRC approval.

General - Certain costs to be recovered through the ratemaking process have been recorded as regulatory assets in accordance with Statement 71. Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria of Statement 71 and, accordingly, a write-off of regulatory assets and stranded costs may be required.

Marketing and Trading

Overview - Our Marketing and Trading segment primarily purchases, stores, transports, markets, and trades natural gas in the retail sector in our core distribution area and the wholesale sector throughout most of the United States. We have a large storage and transport position, primarily in the mid-continent region of the United States, with total transportation capacity of 1.3 Bcf/d. With total cyclical storage capacity of 84 Bcf, withdrawal capability of 2.4 Bcf/d and injection capability of 1.6 Bcf/d spread across 19 different facilities, we have direct access to most regions of the country and flexibility to capture volatility in the energy markets. Due to seasonality of supply and demand balances, earnings will be significantly higher during the winter period than the summer period. We recently extended our marketing and trading operations into Canada by leasing storage and pipeline capacity. Our current Canadian operations bring gas supply from Western Canada into the upper Midwest with recent activity to supply customers in the Northeast.

We continue to enhance our strategy of customer-focus by providing reliable service during peak demand periods, through the use of our storage and transportation capacity. The physical and financial energy services we provide to our customers help them better execute their commodity-procurement and asset-management strategies.

In July 2004, we entered into a multi-year agreement to sell gas to the natural gas distributor for the city of Chicago. Based on current NYMEX prices, gas revenues provided under this agreement are expected to range between $300 million and $575 million over the term of the agreement.

Power - Our 300-megawatt peak electric power generating plant is located in Oklahoma adjacent to one of our natural gas storage facilities and is configured to supply electric power during peak demand periods. This plant allows us to capture the “spark spread premium,” which is the value added by converting natural gas to electricity, during peak demand periods. Because of seasonal demands for electricity for summer cooling, the demands on our power plant are more volatile in the summer months. In October 2003, we signed a tolling arrangement with a third party for its power plant in Big Springs, Texas, which is connected to our corporate-owned gas transmission system. The agreement, which expires in December 2005, allows us to sell the steam and power generated from the Electric Reliability Council of Texas (ERCOT). This agreement increases our owned or contracted power capacity from 300 to 512 megawatts.

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


	Three Months Ended June 30,						Six Months Ended June 30,
Financial Results	2004			2003			2004			2003
	*(Thousands of dollars)*
Energy trading revenues, net	$	13,908		$	37,090		$	89,172		$	172,761
Power sales		47,058			21,287			82,105			33,525
Cost of sales and fuel		46,891			19,320			82,105			30,024
Other revenues		207			320			444			616

Net revenues		14,282			39,377			89,616			176,878
Operating costs		7,919			7,422			18,472			16,525
Depreciation, depletion, and amortization		1,424			1,469			2,815			2,931

Operating income	$	4,939		$	30,486		$	68,329		$	157,422

Other income (expense), net	$	(1,830	)	$	(1,417	)	$	(3,524	)	$	(2,985	)

Cumulative effect of changes in accounting principle, net of tax	$	—		$	—		$	—		$	(141,982	)


	Three Months Ended June 30,						Six Months Ended June 30,
Operating Information	2004			2003			2004			2003
Natural gas marketed (MMcf)		248,670			218,210			535,156			534,147
Natural gas gross margin ($/Mcf)	$	0.05		$	0.12		$	0.13		$	0.25
Electricity marketed (MMwh)		966			453			1,751			743
Physically settled volumes (MMcf) ^(a)		510,509			472,301			1,050,613			1,049,736
Capital expenditures (Thousands of dollars)	$	704		$	313		$	814		$	396

^(a)	This represents the absolute value of gross transaction volumes for both buy and sell energy trading contracts that were physically settled.

Operating Results - Energy trading revenues decreased for the three months ended June 30, 2004 compared to the same period in 2003. The decrease resulted from:

•

reduced natural gas volatility and the impact that it has on our natural gas options portfolio

•

decreased inter-regional basis spreads especially between the Rocky Mountain and mid-continent regions

•

cooler and wetter early summer in 2004 in our primary service area

•

the change in value of our derivative contracts subject to fair value accounting

These decreases were partially offset by continued customer expansion and favorable contract extensions.

We have also increased our storage capacity resulting in increased storage expense which is included in energy trading revenues.

Power margins decreased due to comparatively weaker spark spreads in the Southwest Power Pool and ERCOT, while overall sales and purchases increased due to our Big Springs tolling agreement signed late in the fourth quarter of 2003.

Net revenues decreased for the six months ended June 30, 2004, compared to the same period in 2003 due to lower natural gas price volatility and inter-regional basis spreads. Lower natural gas price volatility reduced revenue associated with our storage capacity and lower inter-regional basis spreads reduced our 2004 transportation margins compared to 2003.

Weaker spark spreads in the Southwest Power Pool and ERCOT were responsible for reducing net revenues from power sales for the six months ended June 30, 2004 compared to the same period in 2003. The decrease in natural gas price volatility reduced the revenue generated from our natural gas option portfolio and the weaker spark spreads reduced revenue associated with our Spring Creek peaking electric power plant and Big Springs tolling agreement.

Natural gas sales volumes increased for the three months ended June 30, 2004 compared to the same period in 2003 due to expanded Canadian and retail operations.

The natural gas storage inventory level at June 30, 2004 was 58.9 Bcf compared to 48.5 Bcf at June 30, 2003.

Operating costs remained relatively stable for the three months ended June 30, 2004 compared to the same period in 2003.

Operating costs increased for the six months ended June 30, 2004 compared to same period in 2003 primarily due to:

•

$1.4 million increase in start-up costs associated with our Canadian operations

•

$0.6 million increase in ad valorem taxes

These increases in operating costs were offset by decreased employee costs of $0.5 million.

At the beginning of the third quarter, we completed a reorganization of our Marketing and Trading segment and renewed our focus on our physical marketing and storage business, adding three new LDC customers and two new large industrial customers. We separated the management and operations of our physical marketing, retail marketing and trading activities and began accounting separately for the different types of revenue sources among these activities. As a result of this reorganization, we are evaluating the accounting treatment related to the presentation of revenues for 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, Accounting for Derivative Instruments and Hedging Activities, and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3, ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities’” (EITF 03-11). We expect that a portion of these activities representing our non-trading revenues will be presented on a gross basis beginning with the third quarter of 2004. Reporting of these transactions on a gross basis will not impact operating income but will increase revenues and cost of gas.

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 bank lines of credit, 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 2003 and through the first half of 2004, our capital expenditures were financed through operating cash flows and short and long-term debt. Capital expenditures for 2004 are expected to be in the range of $270 million to $280 million compared to $215 million in 2003.

Financing - Financing is provided through our commercial paper program, long-term debt and, as needed, through a revolving credit facility. Other options to obtain financing include, but are not limited to, issuance of equity, issuance of mandatory convertible debt securities, issuance of trust preferred securities by ONEOK Capital Trust I or ONEOK Capital Trust II, asset securitization and the sale/leaseback of facilities.

Credit Rating - Our credit rating is currently an “A-” (stable outlook) by Standard and Poors and a “Baa1” (negative outlook) by Moody’s Investor Service. Our credit rating may be affected by a material change in our financial ratios or a material adverse event affecting our business. The most common criteria for assessing our credit rating are the debt to capital ratio, pre-tax 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. 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 an $850 million revolving credit facility, which expires September 20, 2004. We expect the revolving credit facility to be renewed upon expiration.

Our energy marketing and trading business relies heavily 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, 2004, the amount we could be required to fund the few counterparties with which we have a Credit Support Annex within our International Swaps and Derivatives Association Agreements is approximately $39.9 million. A decline in our credit rating below investment grade may also significantly impact other business segments.

We have reviewed our commercial paper agreement, trust indentures, building leases, equipment leases, marketing, 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. The revolving credit agreement contains a provision that would cause the cost to borrow funds to increase based on the amount borrowed under this agreement if our credit rating is negatively adjusted. The credit agreement also contains a default provision based on a material adverse change. An adverse rating change is not defined as a default or material adverse change. We currently do not have any funds borrowed under this credit agreement.

Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity prices in either physical or financial energy contracts may impact our overall liquidity due to the impact a commodity price change has on items such as the cost of NGLs and gas held in storage, increased margin requirements, collectibility of certain energy-related receivables and working capital. We believe that our current commercial paper program and debt capacity are adequate to meet our liquidity requirements associated with commodity price volatility.

Pension Plan - Our pension plan is currently overfunded resulting in an asset reported on our balance sheet. Due to the previous poor performance of the equity market and lower interest rates at our plan valuation date of September 30, 2003, the market value of our pension fund assets has decreased and, accordingly, our pension credit for our pension and supplemental retirement plans will decrease in 2004 from $4.4 million to $1.9 million. Should the value of our pension fund assets fall below our accumulated benefit obligation, we would eliminate the asset and record a minimum pension liability on the balance sheet with the difference flowing through other comprehensive income, net of tax. We believe we have adequate resources to fund our obligations under our pension plan.

Cash Flow Analysis

Operating Cash Flows - Operating cash flows increased by $173.9 million for the six months ended June 30, 2004 compared to the same period in 2003, despite a decrease in income from continuing operations. The primary impact on operating cash flows resulted from changes in working capital, much of which relates to decreases in gas in storage. Weather can have a significant impact on gas inventory levels. Warmer weather at the end of 2003 resulted in higher than normal inventory levels. During the first quarter of 2004, the withdrawal of inventory from storage reduced our gas inventory levels and positively impacted our operating cash flows for the six-month period in 2004. During the six months ended June 30, 2003, we injected higher levels of inventory into storage, which negatively impacted our operating cash flows.

Decreases in deposits, or margin requirements, by our Marketing and Trading segment had a positive impact on our 2004 operating cash flows. Changes in other assets and liabilities reflect expenditures or recognition of liabilities for insurance costs, salaries, taxes other than income, and other similar items. Period-to-period fluctuations in these accounts reflect changes in the timing of payments or recognition of liabilities and are not directly impacted by seasonal factors.

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

Acquisitions in the first quarter of 2003 represent the cash purchase of our Texas distribution assets. Cash provided by investing activities of discontinued operations represents the sale of natural gas and oil producing properties for a cash sales price of $294 million, including adjustments, of which $281 million was received in 2003 and the remaining amount was received in the prior year.

Financing Cash Flows - The following table sets forth our capitalization structure for the periods indicated.


	June 30, 2004		December 31, 2003
Long-term debt	56	%	60	%
Equity	44	%	40	%


Debt (including Notes payable)	57	%	67	%
Equity	43	%	33	%

At June 30, 2004, we had $1.9 billion of long-term debt outstanding, including current maturities. As of June 30, 2004, we could have issued $2.0 billion of additional long-term debt under the most restrictive provisions contained in our various borrowing agreements. During the first quarter, we paid off $600 million in notes payable using cash generated from operating activities and proceeds from our February 2004 equity offering. During the second quarter of 2004, we incurred $40 million of notes payable used in the ordinary course of business.

Both Standard and Poors and Moody’s Investment Services consider the equity units we issued in January 2003 to be part equity and part debt. For purposes of computing capitalization ratios, these rating agencies adjust the capitalization structure. Standard and Poors considers the 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 50 percent long-term debt and 50 percent equity at June 30, 2004. Moody’s Investment Services considers 25 percent of the equity units to be long-term debt and 75 percent to be shareholders’ equity, which would result in a capitalization structure of 47 percent long-term debt and 53 percent equity at June 30, 2004.

Our $850 million revolving credit facility was renewed September 22, 2003. The current facility expires in September 2004 and includes a term-out option, which allows us to convert any outstanding borrowings under the credit agreement into a 364-day term note at the expiration of the credit agreement. This facility is primarily used to support our commercial paper program. At June 30, 2004, we had $40 million in commercial paper outstanding and approximately $19.0 million in temporary investments.

We use newly issued shares to meet the purchase requirements generated by participants in our Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries. All participant purchases under this plan are voluntary. During the three months ended June 30, 2004, we issued 339,688 shares for a total of $7.2 million. During the six months ended June 30, 2004, we issued 664,888 shares for a total of $14.5 million. We also use newly issued shares to meet the purchase requirements generated by our Dividend Reinvestment Plan and our Long-Term Incentive Plan.

During the first quarter of 2004, we 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. These interest rate swaps were previously initiated as a strategy to hedge the fair value of fixed rate long-term debt. 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.

During the first quarter of 2003, we issued a total of 16.1 million equity units. Each equity unit consists of a stock purchase contract for the purchase of shares of our common stock and, initially, a senior note due February 16, 2008, issued pursuant to our existing Indenture with SunTrust Bank, as trustee. The number of shares that we will issue for each stock purchase contract issued as part of the equity units will be determined based on our average closing price over the 20-trading day period ending on the third trading day prior to February 16, 2006. If this average closing price:

•

equals or exceeds $20.63, we will issue 1.2119 shares of our common stock for each purchase contract or unit;

•

equals or is less than $17.19, we will issue 1.4543 shares of our common stock for each purchase contract or unit;

•

is less than $20.63 but greater than $17.19, we will determine the number of shares of our common stock to be issued by multiplying the number of purchase contracts or units by the ratio of $25 divided by the 20-trading day average closing price.

Other

Labor Negotiations - On July 1, 2004, KGS and the United Steelworkers of America Locals 12561, 13417, and 14228, the Gas Workers Metal Trades of the United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada Local 781 and the International Union of Operating Engineers Local 126 labor unions agreed upon a five-year contract expiring June 30, 2009. Approximately 475 of our KGS employees are members of these three labor unions, comprising approximately 41 percent of our KGS workforce. The parties agreed to a three percent wage increase retroactive to June 1, 2004 and an increase for each of the next four years as follows:

•

three percent beginning July 1, 2005

•

two and one-half percent beginning July 1, 2006

•

two and one-half percent beginning July 1, 2007

•

two and one-half percent beginning July 1, 2008

Currently, we have no ongoing labor negotiations.

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, management’s plans and objectives for future operations, business prospects, outcome of regulatory 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 operations and other statements contained or incorporated in this Form 10-Q identified by words such as “anticipate,” “estimate,” “expect,” “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 the 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 sales and prices;

•

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

•

the capital intensive nature of our business;

•

further deregulation, or “unbundling,” of the natural gas business;

•

competitive changes in the natural gas gathering, transportation and storage business resulting from deregulation, or “unbundling,” of the natural gas 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 trading partners;

•

economic climate and growth in the geographic areas in which we do business;

•

the uncertainty of estimates, including accruals and gas and oil reserves;

•

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

•

the effects of changes in governmental policies and regulatory actions, including, with respect to income taxes, environmental compliance, 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 dynamics in the Middle East and elsewhere;

•

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 market returns;

•

risks associated with pending or possible acquisitions and dispositions, including our ability to finance or to 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 on terms acceptable to us;

•

the risk of a significant slowdown in growth or a decline in the U.S. economy, the risk of delay in growth or recovery in the U.S. economy or the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;

•

risks associated with the adequate supply of natural gas to our gathering and processing facilities, including from 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 impact of the outcome of pending and future litigation; and

•

the other risks and other factors listed in the reports we have filed and may file from time to time 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, 2003, except as follows.

KGS uses derivative instruments to hedge the cost of anticipated gas purchases during the winter heating months to protect KGS customers from upward volatility in the market price of natural gas. At June 30, 2004, KGS had derivative instruments in place to hedge the cost of gas purchases for 3.1 Bcf of gas, representing part of KGS’ gas purchase requirements for the 2004/2005 winter heating months based on normal weather conditions. Gains or losses associated with the KGS hedges are included in and recoverable through the monthly purchased gas adjustment.

TGS may use derivative instruments to mitigate the volatility of gas costs to protect its customers in the city of El Paso. At June 30, 2004, TGS had no derivative instruments in place to hedge the cost of gas purchases. Gains or losses associated with the derivative instruments are included in and recoverable through the monthly purchased gas adjustment.

The following table provides a detail of our Marketing and Trading segment’s maturity of derivatives based on heating injection and withdrawal periods from April to March. Executory storage and transportation contacts and their related hedges are not included in the following table. This maturity schedule is consistent with our Marketing and Trading segment’s trading strategy.


Source of Fair Value ⁽¹⁾	Fair Value of Contracts at June 30, 2004
Source of Fair Value ⁽¹⁾	Matures through March 2005			Matures through March 2008			Matures through March 2010			Matures after March 2010		Total Fair Value
	*(Thousands of dollars)*
Prices actively quoted ⁽²⁾	$	25,130		$	2,356		$	—		$	—	$	27,486
Prices provided by other external sources⁽³⁾		(30,332	)		(20,204	)		(2,276	)		424		(52,388	)
Prices derived from quotes, other external sources and other assumptions⁽⁴⁾		(2,104	)		(1,336	)		1,029			34		(2,377	)

Total	$	(7,306	)	$	(19,184	)	$	(1,247	)	$	458	$	(27,279	)

⁽¹⁾	Fair value is the mark-to-market component of forwards, swaps, and options utilized for trading activities, net of applicable reserves. These fair values are reflected as a component of assets and liabilities from price 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 the Critical Accounting Policies in Note A and Accounting Treatment in Note D of the Notes to Consolidated Financial Statements included in this Form 10-Q.

Interest Rate and Currency Risk - At June 30, 2004, the interest rate on approximately 59 percent of our long-term debt was fixed after considering the impact of interest rate swaps.

During the first quarter of 2004, we terminated $670 million of our interest rate swap agreements to lock in savings and received $91.8 million, which includes $8.9 million of interest rate savings previously recorded. These interest rate swaps were previously

initiated as a strategy to hedge the fair value of fixed rate, long-term debt. The net proceeds received upon termination of the interest rate swaps were $81.9 million, after reduction for ineffectiveness and unpaid interest. During 2004, $3.2 million in interest expense savings was recognized and the remaining amount of $78.7 million will be recognized in the income statement over the remaining term of the debt instruments originally hedged. Consequently, the remaining savings in interest expense will be recognized over the following periods:


2004	$	4.9 million
2005	$	10.0 million
2006	$	10.0 million
2007	$	10.0 million
2008	$	10.0 million
Thereafter	$	33.8 million

We have entered into new swap agreements to replace the terminated agreements. Currently, $740 million of 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, 2004, we recorded a $40.7 million net liability to recognize the interest rate swaps at fair value. Long-term debt was also decreased by $40.7 million to recognize the change in the fair value of the related hedged liability.

The change in the fair value of the related hedged liability and the terminated swaps resulted in $38.8 million included in long-term debt at June 30, 2004.

Total savings from the interest rate swaps was $16.5 million for the first half of 2004. The swaps are expected to generate the following savings for the remainder of the year:

•

interest expense savings of $5 million for remainder of 2004 related to the amortization of the swap value at termination

•

up to $8.8 million in interest savings from the new swaps based on current LIBOR rates

Total swap savings for 2004 are expected to be $30 million which is an increase over the savings of $24.4 million and $20.6 million in 2003 and 2002, respectively.

A 100 basis point move in the LIBOR rate on all of our outstanding long-term debt would change annual interest expense by approximately $7.4 million before taxes. If interest rates changed significantly, we would 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 Marketing and Trading 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 revenues. At June 30, 2004, 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 $2.7 million and $1.7 million at June 30, 2004 and 2003, respectively.

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


	Three Months Ended June 30,				Six Months Ended June 30,
Value-at-Risk	2004		2003		2004		2003
	*(Millions of dollars)*
Average	$	3.2	$	3.3	$	4.3	$	4.4
High	$	7.1	$	7.1	$	17.7	$	17.1
Low	$	0.7	$	1.0	$	0.7	$	1.0

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 the Company’s Disclosure Controls - We evaluated the effectiveness of the design and operation of our disclosure controls and procedures (Disclosure Controls) as of the end of the period covered by this Quarterly Report on Form 10-Q. This evaluation (the Disclosure Controls Evaluation) was done under the supervision and with the participation of management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO). Rules adopted by the Securities and Exchange Commission (SEC) require that in this section of this Quarterly Report on Form 10-Q we present the conclusions of the CEO and the CFO about the effectiveness of our Disclosure Controls based on and as of the date of the Disclosure Controls Evaluation.

Disclosure Controls - Disclosure Controls are procedures that are designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934 (Exchange Act), such as this Quarterly Report on Form 10-Q, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure Controls are also designed with the objective of ensuring that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Limitations on the Effectiveness of Controls - Our management, including the CEO and CFO, does not expect that our Disclosure Controls will prevent all errors and all fraud. A control system, including our Disclosure Controls, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, some controls may become inadequate because of changes in conditions, or the degree of compliance with policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Scope of the Controls Evaluation - The CEO/CFO evaluation of our Disclosure Controls included a review of the controls’ objectives and design, the controls’ implementation by us and the effect of the controls on the information generated for use in this Quarterly Report on Form 10-Q. In the course of the Disclosure Controls Evaluation, we sought to identify data errors, control problems or acts of fraud and to confirm that appropriate corrective action, including process improvements, were being undertaken. This type of evaluation is done on a quarterly basis so that the conclusions concerning controls effectiveness can be reported in our Quarterly Reports on Form 10-Q and our Annual Report on Form 10-K. The overall goals of these evaluation activities are to monitor our Disclosure Controls and to make modifications as necessary. Our intent in this regard is that the Disclosure Controls will be maintained as dynamic systems that change (including with improvements and corrections) as conditions warrant.

Conclusions - Based upon the Disclosure Controls Evaluation, our CEO and CFO have concluded that, subject to the limitations noted above, our Disclosure Controls are effective in providing reasonable assurance of achieving their objective of timely alerting them to material information required to be disclosed by us in periodic reports we file with the SEC.

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. The parties have completed discovery regarding whether Mr. Gryberg has met the unique jurisdictional prerequisites for maintaining an action under the False Claims act. On June 4, 2004, we joined with the numerous other defendants in filing a motion to dismiss contending that Mr. Grynberg has not satisfied such unique jurisdictional prerequisites to maintain this action. A hearing on this motion has not been set by the court.

In the Matter of the Natural Gas Explosion at Hutchinson, Kansas during January, 2001, Case No. 02-E-0155, before the Secretary of the Department of Health and Environment. On April 11, 2004, we paid to the Kansas Department of Health and Environment (“KDHE”) the seventy-nine thousand dollars ($79,000) we were ordered to pay to reimburse the KDHE for its cost related to the investigation of the Yaggy gas storage facility incident. Additionally, remediation that we are required to perform pursuant to our consent order with the KDHE is ongoing. For additional discussion of this matter, see Note J of the Notes to Consolidated Financial Statements included in this Form 10-Q.

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, and Gilley 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. On June 14, 2004, the court transferred venue for trial of these cases from Reno County to Wyandotte County, Kansas. The court has set trial for August 24, 2004.

Item 2.

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

The following table sets forth information relating to our recent purchases of equity securities.

Issuer Purchases of Equity Securities


Period	Total Number of Shares (or Units) Purchased ⁽¹⁾		Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
April 1-30, 2004	10,811	⁽²⁾	$	22.76	—	—
May 1-31, 2004	4	⁽³⁾		20.25	—	—
June 1-30, 2004	9,536	⁽²⁾		21.24	—	—

Total	20,351		$	22.05	—	—

⁽¹⁾	Does not include the forfeiture of restricted stock for failure to satisfy vesting conditions. There were no restricted stock forfeitures for failure to satisfy vesting conditions for the periods.

⁽²⁾	Shares withheld pursuant to attestation of ownership and deemed tendered to the Company in connection with the exercise of stock options under the ONEOK, Inc. Long-Term Incentive Plan.

⁽³⁾	Shares repurchased directly from employee.

Item 3.

Defaults Upon Senior Securities

Not Applicable.

Item 4.

Submission of Matters to Vote of Security Holders

We held our 2004 annual meeting of shareholders on May 20, 2004. At this meeting, the individuals set forth below in Class A 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 B was elected by a plurality vote to our board of directors for a term of one year:


Director		Votes For	Votes Withheld
William M. Bell	(Class A)	89,348,116	4,659,788
Julie H. Edwards	(Class A)	88,789,000	5,218,904
Pattye L. Moore	(Class A)	92,418,976	1,588,928
J.D. Scott	(Class A)	62,422,360	31,585,544
James C. Day	(Class B)	92,459,634	1,548,270

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 B		Class C
(Term ending 2005)		(Term ending 2006)
David L. Kyle		William L. Ford
Bert H. Mackie		Douglas Ann Newsom
Mollie B. Williford		Gary D. Parker
		Eduardo A. Rodriguez

In addition, at the annual meeting the appointment of KPMG LLP as our independent auditor for the 2004 fiscal year was ratified by our shareholders as follows:


	Votes For	Votes Against	Abstained
Appointment of KPMG LLP as principal independent auditor	92,513,168	1,034,221	460,515

Item 5.

Other Information

Not Applicable.

Item 6.

Exhibits and Reports on Form 8-K

Exhibits

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


Exhibit No.		Exhibit Description

12		Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirement for the six months ended June 30, 2004 and 2003.

12.1		Computation of Ratio of Earnings to Fixed Charges for the six months ended June 30, 2004 and 2003.

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)).

Reports on Form 8-K

We filed the following Current Reports on Form 8-K during the quarter ended June 30, 2004, dated as follows:

April 15, 2004 - Announced that the Company’s board of directors declared a two-cent per share increase in the quarterly dividend to 21 cents per share of ONEOK, Inc. common stock.

April 15, 2004 - Announced that Eduardo A. Rodriquez, Executive Vice President for Legal and Administrative Affairs at Hunt Building Corporation, was elected to the Company’s board of directors.

April 15, 2004 - Announced that the Company had terminated its agreement to purchase the 22.5 percent interest in Gulf Coast Fractionators owned by ConocoPhillips.

April 26, 2004 - Announced that the Company will present at the AGA Financial Forum in Bonita Springs, Florida on Monday, May 3, 2004, beginning at approximately 2:25 p.m. E.D.T.

April 28, 2004 - Announced that the Company entered into an agreement to sell all the stock of ONEOK Energy International, Inc. and ONEOK International Investments, Inc. to Choahuila Energy, LLC for a sales price of approximately $2 million which was expected to close in early May 2004.

April 28, 2004 - Furnished the Company’s results of operations for the quarter ended March 31, 2004.

May 20, 2004 - Announced that the Company’s board of directors declared a two-cent per share increase in the quarterly dividend to 23 cents per share of ONEOK, Inc. common stock.

June 17, 2004 - Announced that the Company will present at the 2004 Wachovia Securities Nantucket Equity Conference in Nantucket, Massachusetts on Thursday, June 24, 2004, beginning at approximately 10:00 a.m. Central Time.

June 18, 2004 - Announced that the Company’s earnings guidance for 2004 remains in the range of $2.12 to $2.18 per diluted share of common stock, updated segment operating income estimates and provided quarterly earnings per share guidance.

Signatures

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


	ONEOK, Inc. Registrant

Date: August 4, 2004	By:	/s/ JIM KNEALE
		Jim Kneale Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)