UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2004

OR

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

For the transition period from              to             .

Commission file number 001-13643

ONEOK, Inc.

(Exact name of registrant as specified in its charter)

Oklahoma	73-1520922
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
100 West Fifth Street, Tulsa, OK	74103
(Address of principal executive offices)	(Zip Code)

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

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

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

On November 1, 2004, the Company had 103,412,019 shares of common stock outstanding.

ONEOK, Inc.

QUARTERLY REPORT ON FORM 10-Q

		Page No.
Part I.	Financial Information
Item 1.	Financial Statements (Unaudited)
	Consolidated Statements of Income - Three Months and Nine Months Ended September 30, 2004 and 2003	3
	Consolidated Balance Sheets - September 30, 2004 and December 31, 2003	4-5
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2004 and 2003	6
	Consolidated Statements of Shareholders’ Equity and Comprehensive Income - Nine Months Ended September 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	25-46
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46-48
Item 4.	Controls and Procedures	48-49
Part II.	Other Information
Item 1.	Legal Proceedings	49-50
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds Equity Securities	50
Item 3.	Defaults Upon Senior Securities	50
Item 4.	Submission of Matters to a Vote of Security Holders	51
Item 5.	Other Information	51
Item 6.	Exhibits	51
Signatures		52

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

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Part I - FINANCIAL INFORMATION

Item 1. Financial Statements

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME

	Three Months Ended September 30,				Nine Months Ended September 30,
(Unaudited)	2004		2003		2004		2003
	(Thousands of dollars, except per share amounts)
Revenues
Operating revenues, excluding energy trading revenues	$	1,709,351	$	557,093	$	3,282,893	$	1,966,030
Energy trading revenues, net		17,411		11,177		106,583		183,938
Total Revenues		1,726,762		568,270		3,389,476		2,149,968
Cost of sales and fuel		1,480,662		373,888		2,520,565		1,320,198
Net Margin		246,100		194,382		868,911		829,770
Operating Expenses
Operations and maintenance		124,000		106,433		368,022		332,996
Depreciation, depletion, and amortization		47,307		40,105		140,273		120,241
General taxes		15,290		16,024		52,399		50,267
Total Operating Expenses		186,597		162,562		560,694		503,504
Operating Income		59,503		31,820		308,217		326,266
Other income		1,632		1,252		11,101		4,157
Other expense		1,338		472		9,811		1,590
Interest expense		25,248		24,972		73,885		78,518
Income before Income Taxes		34,549		7,628		235,622		250,315
Income taxes		13,710		3,033		91,841		97,565
Income from Continuing Operations		20,839		4,595		143,781		152,750
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		20,839		4,595		143,781		49,576
Preferred stock dividends		—		4,000		—		24,211
Income Available for Common Stock	$	20,839	$	595	$	143,781	$	25,365
Earnings Per Share of Common Stock (Note M)
Basic:
Earnings per share from continuing operations	$	0.20	$	0.01	$	1.42	$	1.64
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	$	0.20	$	0.01	$	1.42	$	0.72
Diluted:
Earnings per share from continuing operations	$	0.19	$	0.01	$	1.38	$	1.49
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	$	0.19	$	0.01	$	1.38	$	0.57
Average Shares of Common Stock (Thousands)
Basic		102,914		77,865		101,530		78,650
Diluted		106,942		78,701		104,080		97,385
Dividends Declared per share of Common Stock	$	0.25	$	0.18	$	0.88	$	0.52

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Unaudited)	September 30, 2004		December 31, 2003
	(Thousands of dollars)
Assets
Current Assets
Cash and cash equivalents	$	17,759	$	12,172
Trade accounts and notes receivable, net		696,907		970,141
Materials and supplies		20,585		18,962
Gas in storage		636,229		500,439
Assets from price risk management activities (Note D)		469,312		233,013
Deposits		19,963		42,424
Deferred income taxes		22,408		—
Other current assets		59,418		46,184
Total Current Assets		1,942,581		1,823,335
Property, Plant and Equipment
Production		442,667		404,254
Gathering and Processing		1,055,075		1,036,080
Transportation and Storage		700,781		699,676
Distribution		2,888,524		2,813,800
Energy Services		127,687		126,315
Other		133,002		99,549
Total Property, Plant and Equipment		5,347,736		5,179,674
Accumulated depreciation, depletion, and amortization		1,586,456		1,487,848
Net Property, Plant and Equipment		3,761,280		3,691,826
Deferred Charges and Other Assets
Regulatory assets, net (Note E)		201,576		213,915
Goodwill (Note F)		225,363		225,615
Assets from price risk management activities (Note D)		83,103		67,294
Prepaid pensions		126,974		120,618
Investments and other		83,459		69,283
Total Deferred Charges and Other Assets		720,475		696,725
Total Assets	$	6,424,336	$	6,211,886

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Unaudited)	September 30, 2004			December 31, 2003
	(Thousands of dollars)
Liabilities and Shareholders’ Equity
Current Liabilities
Current maturities of long-term debt	$	341,334		$	6,334
Notes payable		298,000			600,000
Accounts payable		775,078			813,895
Dividends payable		25,840			—
Accrued taxes		24,155			102,637
Accrued interest		28,671			32,999
Customers’ deposits		36,970			34,692
Unrecovered purchased gas costs		68,535			51,378
Liabilities from price risk management activities (Note D)		610,122			246,474
Deferred income taxes		—			6,194
Other		112,341			130,174
Total Current Liabilities		2,321,046			2,024,777
Long-term Debt, excluding current maturities		1,549,232			1,878,264
Deferred Credits and Other Liabilities
Deferred income taxes		614,292			559,356
Liabilities from price risk management activities (Note D)		121,179			66,956
Lease obligation		90,186			100,292
Other deferred credits		329,013			340,849
Total Deferred Credits and Other Liabilities		1,154,670			1,067,453
Total Liabilities		5,024,948			4,970,494
Commitments and Contingencies (Note J)
Shareholders’ Equity
Common stock, $0.01 par value: authorized 300,000,000 shares; issued 106,396,240 shares and outstanding 103,359,074 shares at September 30, 2004; issued 98,194,674 shares and outstanding 95,194,666 shares at December 31, 2003		1,064			982
Paid in capital		996,855			815,870
Unearned compensation		(2,007	)		(3,422	)
Accumulated other comprehensive loss (Note G)		(96,183	)		(17,626	)
Retained earnings		550,858			495,971
Treasury stock, at cost: 3,037,166 shares at September 30, 2004 and 3,000,008 shares at December 31, 2003		(51,199	)		(50,383	)
Total Shareholders’ Equity		1,399,388			1,241,392
Total Liabilities and Shareholders’ Equity	$	6,424,336		$	6,211,886

See accompanying Notes to Consolidated Financial Statements.

5

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months Ended September 30,
(Unaudited)	2004			2003
	(Thousands of dollars)
Operating Activities
Income from continuing operations	$	143,781		$	152,750
Depreciation, depletion, and amortization		140,273			120,241
Gain on sales of assets		(9,345	)		(289	)
Income from equity investments		(802	)		(1,141	)
Deferred income taxes		77,906			93,451
Stock based compensation expense		6,695			3,588
Allowance for doubtful accounts		10,238			10,313
Changes in assets and liabilities (net of acquisition effects):
Accounts and notes receivable		262,659			215,271
Inventories		(137,771	)		(441,143	)
Unrecovered purchased gas costs		17,157			15,765
Deposits		22,461			(7,965	)
Regulatory assets		(6,921	)		(2,848	)
Accounts payable and accrued liabilities		(123,583	)		(51,445	)
Price risk management assets and liabilities		(33,780	)		5,468
Other assets and liabilities		(82,730	)		14,674
Cash Provided by Continuing Operations		286,238			126,690
Cash Provided by Discontinued Operations		—			8,285
Cash Provided by Operating Activities		286,238			134,975
Investing Activities
Changes in other investments, net		1,372			1,167
Acquisitions		—			(436,630	)
Capital expenditures		(192,335	)		(150,685	)
Proceeds from sale of property		17,249			—
Other investing activities		(2,990	)		(2,733	)
Cash Used in Continuing Operations		(176,704	)		(588,881	)
Cash Provided by Discontinued Operations		—			280,669
Cash Used in Investing Activities		(176,704	)		(308,212	)
Financing Activities
Payments of notes payable, net		(302,000	)		(98,500	)
Change in bank overdraft		4,262			253
Issuance of debt		—			404,964
Termination of interest rate swaps		82,915			—
Payment of debt issuance costs		—			(2,564	)
Payment of debt		(1,041	)		(15,792	)
Purchase of Series A Convertible Preferred Stock		—			(300,000	)
Purchase of common stock		—			(50,000	)
Issuance of common stock		176,107			218,521
Issuance (receipt) of treasury stock, net		(816	)		7,358
Dividends paid		(63,374	)		(52,410	)
Cash Provided by (Used in) Financing Activities		(103,947	)		111,830
Change in Cash and Cash Equivalents		5,587			(61,407	)
Cash and Cash Equivalents at Beginning of Period		12,172			73,522
Cash and Cash Equivalents at End of Period	$	17,759		$	12,115

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	1,301,566		13		25,072			—
Offering costs	—		—		(295	)		—
Stock-based employee compensation expense	—		—		4,960			1,735
Common stock dividends (Note H)	—		—		—			(320	)
September 30, 2004	106,396,240	$	1,064	$	996,855		$	(2,007	)

See accompanying Notes to the Consolidated Financial Statements.

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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		—			143,781			—			143,781
Other comprehensive income (loss)		(78,557	)		—			—			(78,557	)
Total comprehensive income											65,224
Receipts of restricted stock		—			—			(816	)		(816	)
Issuance of common stock
Common stock offering		—			—			—			151,317
Stock issuance pursuant to various plans		—			—			—			25,085
Offering costs		—			—			—			(295	)
Stock-based employee compensation expense		—			—			—			6,695
Common stock dividends (Note H)		—			(88,894	)		—			(89,214	)
September 30, 2004	$	(96,183	)	$	550,858		$	(51,199	)	$	1,399,388

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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 nine months ended September 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 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” to all options and awards granted prior to January 1, 2003.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2004		2003		2004		2003
	(Thousands of dollars, except per share amounts)
Net income, as reported	$	20,839	$	4,595	$	143,781	$	49,576
Add: Stock based compensation included in net income, net of related tax effects		1,576		1,015		4,926		2,712
Deduct: Total stock based compensation expense determined under fair value based method for all awards, net of related tax effects		1,873		1,318		5,816		3,622
Pro forma net income	$	20,542	$	4,292	$	142,891	$	48,666
Earnings per share:
Basic - as reported	$	0.20	$	0.01	$	1.42	$	0.72
Basic - pro forma	$	0.20	$	0.00	$	1.41	$	0.71
Diluted - as reported	$	0.19	$	0.01	$	1.38	$	0.57
Diluted - pro forma	$	0.19	$	0.00	$	1.37	$	0.56

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Related Party Transactions - From time to time and in the ordinary 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.

• Conducts natural gas sale transactions with Shawnee Milling Company (Shawnee). William L. Ford, President of Shawnee, is a member of the Company’s board of directors.

The table below shows the purchase and sale 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 September 30, 2004				Nine Months Ended September 30, 2004
	Sales		Purchases		Sales		Purchases
	(Thousands of dollars)
Frontier	$	38,120	$	1,872	$	116,546	$	14,223
Williford Companies	$	42	$	1,706	$	121	$	4,996
Shawnee Milling	$	36	$	—	$	133	$	—

Production Property - In September 2004, the FASB issued FASB Staff Position No. 142-2, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil- and Gas-Producing Entities” (FSP FAS 142-2) 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 Company classifies the cost of oil and gas mineral rights as property, plant and equipment on the balance sheet, which is consistent with FSP FAS 142-2.

Other

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

B. Acquisitions and Divestitures

In September 2004, the Company announced that it had entered into an agreement to purchase Northern Plains Natural Gas Company, which owns 82.5 percent of the general partnership interest and 500,000 limited partnership units, together representing a 2.73 percent ownership interest in Northern Border Partners, L.P., from CCE Holdings, LLC for $175 million. This transaction is subject to CCE Holdings, LLC closing its acquisition of CrossCountry Energy, LLC from Enron Corp. and certain of its affiliates, which is expected to occur in the fourth quarter of 2004.

In May and July 2004, the Company completed its sale of its propane bottle operations located in Texas and New Mexico in two separate transactions totaling approximately $1.4 million and recorded a pre-tax gain of $0.9 million, which is included in other income in the Gathering and Processing segment.

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.

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

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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.” 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 September 30,				Nine Months Ended September 30,
	2004		2003		2004		2003
	(Thousands of dollars)
Natural gas sales	$	—	$	—	$	—	$	6,036
Oil sales		—		—		—		1,705
Net margin		—		—		—		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 in earnings as they occur. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposure to changes in fair values, cash flows or foreign currencies. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings in the period of change together with the offsetting 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.

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.

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At the beginning of the third quarter, the Company completed a reorganization of its Energy Services segment with renewed 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 earned from these activities. Prior to the third quarter, the Company managed the Energy Services segment on an integrated basis and presented all energy trading activity on a net basis.

Concurrent with this reorganization, the Company evaluated the accounting treatment related to the presentation of revenues from the different types of activities to determine which amounts should be reported on a gross or net basis under the guidance in EITF 03-11. For derivative instruments considered held for trading purposes that result in physical delivery, the indicators in EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” were used to determine the proper treatment. These activities and all financially settled derivative contracts will continue to be reported on a net basis.

For derivative instruments that are not considered “held for trading purposes” and that result in physical delivery, the indicators in EITF 03-11 and EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19) were used to determine the proper treatment. The Company began accounting for the realized revenues and purchase costs of these contracts that result in physical delivery on a gross basis beginning with the third quarter of 2004. The Company applies the indicators in EITF No. 99-19 to determine the appropriate accounting treatment for non-derivative contracts that result in physical delivery. Derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are also reported on a gross basis. No prior periods have been adjusted for this change; therefore, comparisons to prior periods may not be meaningful. Reporting of these transactions on a gross basis did not impact operating income but resulted in an increase to revenues and cost of sales and fuel.

Fair Value Hedges

The Energy Services segment uses basis swaps to hedge the fair value of certain transportation commitments. At September 30, 2004, net price risk management assets include $11.6 million to recognize the fair value of the Energy Services 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 $1.8 million for the three and nine months ended September 30, 2004, respectively. These amounts are 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 were $81.9 million, after reduction for ineffectiveness and unpaid interest. Through September 30, 2004, $5.6 million in interest expense savings has been recognized and the remaining amount of $76.3 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:

Remainder of 2004	$	2.5 million
2005	$	10.0 million
2006	$	10.0 million
2007	$	10.0 million
2008	$	10.0 million
Thereafter	$	33.8 million

The Company 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 September 30, 2004, the Company recorded a $14.5 million net liability to recognize the interest rate swaps at fair value. Long-term debt was also decreased by $14.5 million to recognize the change in the fair value of the related hedged liability.

13

Cash Flow Hedges

The Energy Services segment uses futures and basis swaps to hedge the cash flows associated with its anticipated purchases and sales of natural gas. Accumulated other comprehensive loss at September 30, 2004, includes losses of approximately $82.4

million, net of tax, related to these hedges that will be realized within the next 39 months. Net gains and losses are reclassified out of accumulated other comprehensive loss to cost of sales and fuel when the anticipated purchase or sale occurs. Ineffectiveness related to these cash flow hedges resulted in a gain of approximately $0.1 million for the three months ended September 30, 2004 and a loss of approximately $4.0 million for the nine months ended September 30, 2004. Additionally, losses of approximately $4.6 million were recognized from accumulated other comprehensive loss during the nine months ended September 30, 2004, due to the discontinuance of cash flow hedge treatment on certain transactions since it was probable that the forecasted transactions would not occur.

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 loss at September 30, 2004, includes losses of approximately $11.3 million, net of tax, for the production hedges that will be realized in the income statement within the next 15 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 September 30, 2004, Kansas Gas Service Company (KGS) and Texas Gas Service Company (TGS) had derivative instruments in place to hedge the cost of natural gas purchases for 11.0 Bcf and 0.4 Bcf of natural gas, respectively, which represents part of their gas purchase requirements for the 2004/2005 winter heating months.

E. Regulatory Assets

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

	September 30, 2004		December 31, 2003
	(Thousands of dollars)
Recoupable take-or-pay	$	59,863	$	64,171
Postretirement costs other than pension		54,124		59,118
Reacquired debt costs		19,991		20,635
Income taxes		19,298		21,782
Transition costs		16,332		16,691
Pension costs		14,098		18,060
Weather normalization		5,023		1,075
Ad valorem tax		3,269		—
Service lines		2,036		3,250
Line replacements		582		495
Other		6,960		8,638
Regulatory assets, net	$	201,576	$	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. The order also allows ONG to recover costs related to its investment in gas in storage and rising levels of fuel-related bad debts. The OCC’s order also approved a modified distribution main extension policy and authorized ONG to defer expected homeland security costs. 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 18 month period. At September 30, 2004, the Company had approximately $3.8 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.

14

“Weather normalization” represents the revenue over- or under-recovered through the weather normalization adjustment program in Kansas. This amount is deferred as a regulatory asset during April 1 through March 31 of each year, at which time, KGS begins applying an adjustment to the customers’ bills to refund the over-collected revenue or bill the under-collected revenue over the next twelve-month period.

The $3.3 million “Ad valorem tax” represents an increase in KGS’ taxes above the amount approved in the September 2003 rate case. Kansas law permits a utility to file a tariff to recover additional ad valorem tax expense incurred above the amount currently recovered in the cost of service rate. This excess amount is recoverable through a surcharge and can be recovered, provided the utility reports the change in rates to the Kansas Corporation Commission (KCC), on an annual basis. KGS filed the tariff and received approval from the KCC during the third quarter of 2004.

F. Goodwill

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

	December 31, 2003		Adjustments			September 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
Energy Services		10,255		—			10,255
Total consolidated	$	225,615	$	(252	)	$	225,363

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 Company’s 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 following tables give an overview of comprehensive income for the periods indicated.

	Three Months Ended September 30,
	2004						2003
	(Thousands of dollars)
Net income				$	20,839					$	4,595
Unrealized gains (losses) on derivative instruments	$	(101,688	)				$	32,244
Unrealized holding losses arising during the period		(136	)					(165	)
Realized losses in net income		1,405						643
Other comprehensive income (loss) before taxes		(100,419	)					32,722
Income tax benefit (provision) on other comprehensive loss		38,839						(12,688	)
Other comprehensive income (loss)					(61,580	)					20,034
Comprehensive income (loss)				$	(40,741	)				$	24,629

15

	Nine Months Ended September 30,
	2004						2003
	(Thousands of dollars)
Net income				$	143,781					$	49,576
Unrealized gains (losses) on derivative instruments	$	(144,480	)				$	36,582
Unrealized holding losses arising during the period		(212	)					(59	)
Realized losses in net income		16,592						3,662
Other comprehensive income (loss) before taxes		(128,100	)					40,185
Income tax benefit (provision) on other comprehensive loss		49,543						(15,573	)
Other comprehensive income (loss)					(78,557	)					24,612
Comprehensive income				$	65,224					$	74,188

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

H. Capital Stock

Common Stock - Since September 17, 2004, the Thrift Plan for Employees of ONEOK, Inc. and subsidiaries (the Thrift Plan) has from time to time purchased shares of ONEOK common stock on the open market to meet the purchase requirements generated by participants in the Thrift Plan. Previously, the Thrift Plan used newly issued shares to meet the participants’ purchase requirements. All participant purchases of ONEOK common stock under the Thrift Plan are voluntary. The Company uses newly issued shares to meet the purchase requirements generated by the Company’s 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 nine months ended September 30, 2004, were $0.23 per share and $0.63 per share, respectively. In September 2004, the Company’s board of directors announced an increase in the quarterly dividend on the Company’s common stock to $0.25 per share payable in the fourth quarter of 2004.

I. Employee Benefit Plans

The table below provides the components of net periodic benefit cost (income) for the Company’s pension and other postretirement benefit plans.

	Pension Benefits Three Months Ended September 30,						Pension Benefits Nine Months Ended September 30,
Components of Net Periodic Benefit Cost (Income)	2004			2003			2004			2003
	(Thousands of dollars)
Service cost	$	3,925		$	3,402		$	11,888		$	10,208
Interest cost		10,555			10,227			31,299			30,681
Expected return on assets		(13,817	)		(15,679	)		(44,787	)		(47,041	)
Amortization of unrecognized net asset at adoption		(78	)		(116	)		(236	)		(350	)
Amortization of unrecognized prior service cost		166			147			496			445
Amortization of loss		1,145			407			2,301			1,221
Net periodic benefit cost (income)	$	1,896		$	(1,612	)	$	961		$	(4,836	)

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	Postretirement Benefits Three Months Ended September 30,						Postretirement Benefits Nine Months Ended September 30,
Components of Net Periodic Benefit Cost (Income)	2004			2003			2004			2003
	(Thousands of dollars)
Service cost	$	1,411		$	1,304		$	4,534		$	3,910
Interest cost		3,329			3,002			10,229			9,008
Expected return on assets		(966	)		(762	)		(2,845	)		(2,288	)
Amortization of unrecognized net asset at adoption		864			835			2,592			2,507
Amortization of unrecognized prior service cost		24			(30	)		73			(90	)
Amortization of loss		998			967			4,289			2,899
Net periodic benefit cost	$	5,660		$	5,316		$	18,872		$	15,946

Contributions - For the nine months ended September 30, 2004, $6.4 million and $9.4 million of contributions were made to the Company’s pension plan and other postretirement benefit plan, respectively. The Company presently anticipates its total 2004 contributions will be $6.8 million for the pension plan and $12.6 million for the other postretirement benefit plan.

Actuarial Assumptions and Adjustments - Changes to the collective bargaining agreements that went into effect on July 1, 2004, required the re-measurement of the pension and other postretirement benefits with a discount rate that reflected the economic conditions as of that date. As a result, the discount rate was adjusted to 6.75 percent from 6.25 percent. In addition, there was a nonrecurring reduction in the value of the assets of $1.7 million in the third quarter of 2004.

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 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 and $0.9 million for three and nine months ended September 30, 2004, respectively. The reduction in current period service cost due to the subsidy was $0.1 million and $0.2 million for the three and nine months ended September 30, 2004, respectively. There was no change to the interest cost on the accumulated postretirement benefit obligation for the three months ended September 30, 2004, while there was a $0.3 million reduction for the nine months ended September 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 natural gas liquids 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 mandated 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.

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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 five sites with regulatory closure achieved at two of these locations, and has begun assessment at the remaining sites. The site situations are not similar and the Company has no previous experience with similar remediation efforts. The Company has completed some analysis of the remaining seven 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 $500,000 per site and 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. Based on information currently available to the Company, it does not believe there are any material adverse effects resulting from the Consent Order.

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. Based on information currently available to the Company, it believes its legal reserves and insurance coverage are adequate and that this matter will not have a material adverse effect on the Company.

The two class action lawsuits 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 resulted in jury verdicts in September 2004. The jury awarded the plaintiffs in the residential class $5 million in actual damages, which is covered by insurance. In the other class action relating to business claims, the jury awarded no actual damages. The jury rejected claims for punitive damages in both cases. The Company is reviewing its options for appealing the verdict rendered in the residential claimants’ class action.

With the exception of appeals, all litigation regarding the Yaggy facility has been resolved.

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. On August 30, 2004, the CFTC announced it had completed its investigation and did not uncover evidence that any entity or individual engaged in activity with an intent to cause an artificial price in natural gas in late 2003.

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Natural Gas Price Reporting Litigation - The Company and its wholly owned subsidiary, ONEOK Energy Services 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. Based on information currently available to the Company, it does not expect this matter to have a material adverse effect on the Company.

Although the Company agreed to a civil monetary penalty with the CFTC in its investigation into natural gas price reporting in January 2004, it cannot guarantee other additional legal proceedings, civil or criminal fines or penalties, or other regulatory action related to this issue will not arise. The Company plans to vigorously defend any claims related to this issue.

Enron - The Company has repurchased a portion of the Enron Corp. guaranty claim that Enron Corp. sought to avoid in the adversary proceeding. The Company is now providing the defense of the adversary proceeding for both the portion of the guaranty claim constituting the repurchased claim and also the portion of the guaranty claim previously sold. Based on information currently available to the Company, it does not expect the adversary proceeding to have a material adverse effect on the Company.

In addition to the adversary proceeding, Enron Corp. and Enron North American Corp. (“ENA”) have filed a new objection to portions of the guaranty claim and to portions of the underlying claim against ENA, creating a new contested matter in the Enron Corp. bankruptcy case which involves different legal and factual issues than those raised in the adversary proceeding. Enron Corp. and ENA allege in this matter that the guaranty claim and underlying claim against ENA are overstated. The filing of this matter may trigger additional obligations of the Company to repurchase some of the claims previously sold. Based on the information currently available to the Company, it does not expect this matter to have a material adverse effect on the Company.

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 463 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, based on information currently available to the Company it does not expect the final outcome of such matters to have a material adverse effect on the Company.

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 and Note D. As discussed in Note D, at the beginning of the third quarter the Company completed a reorganization of its Energy Services segment and separated the management and operations of its physical marketing, retail marketing and trading activities. The Company began accounting separately for the different types of revenue earned from these activities with certain revenues accounted for on a gross rather than a net basis.

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.

19

	Regulated					Non-Regulated
Three Months Ended September 30, 2004	Transportation and Storage		Distribution			Energy Services		Gathering and Processing		Production		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	10,914	$	247,659		$	1,036,367	$	390,001	$	23,552	$	858		$	1,709,351
Energy trading revenues, net		—		—			17,411		—		—		—		$	17,411
Intersegment sales		25,464		—			91,863		129,739		1,216		(248,282	)		—
Total Revenues	$	36,378	$	247,659		$	1,145,641	$	519,740	$	24,768	$	(247,424	)	$	1,726,762
Net margin	$	28,443	$	88,626		$	19,602	$	84,371	$	24,768	$	290		$	246,100
Operating costs	$	12,236	$	79,711		$	7,197	$	34,748	$	7,242	$	(1,844	)	$	139,290
Depreciation, depletion and amortization	$	4,382	$	26,518		$	1,398	$	8,304	$	6,593	$	112		$	47,307
Operating income (loss)	$	11,825	$	(17,603	)	$	11,007	$	41,319	$	10,933	$	2,022		$	59,503
Income from equity investments	$	261	$	—		$	—	$	—	$	—	$	—		$	261
Capital expenditures	$	3,685	$	43,732		$	558	$	8,500	$	17,190	$	4,268		$	77,933

	Regulated					Non-Regulated
Three Months Ended September 30, 2003	Transportation and Storage		Distribution			Energy Services			Gathering and Processing		Production		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	11,603	$	221,834		$	27,055		$	351,272	$	8,784	$	(63,455	)	$	557,093
Energy trading revenues, net		—		—			11,177			—		—		—		$	11,177
Intersegment sales		26,371		—			(a	)		83,422		1,025		(110,818	)		—
Total Revenues	$	37,974	$	221,834		$	38,232		$	434,694	$	9,809	$	(174,273	)	$	568,270
Net margin	$	26,848	$	89,501		$	14,496		$	53,456	$	9,809	$	272		$	194,382
Operating costs	$	11,840	$	71,460		$	6,750		$	28,597	$	3,547	$	263		$	122,457
Depreciation, depletion and amortization	$	4,180	$	24,023		$	1,397		$	7,383	$	2,795	$	327		$	40,105
Operating income (loss)	$	10,828	$	(5,982	)	$	6,349		$	17,476	$	3,467	$	(318	)	$	31,820
Income from equity investments	$	326	$	—		$	—		$	—	$	—	$	53		$	379
Capital expenditures	$	5,640	$	47,865		$	92		$	4,239	$	6,142	$	2,266		$	66,244

(a) - Intersegment sales for Energy Services were $64.5 million for the three months ended September 30, 2003.

	Regulated				Non-Regulated
Nine Months Ended September 30, 2004	Transportation and Storage		Distribution		Energy Services		Gathering and Processing		Production		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	36,160	$	1,337,475	$	1,118,916	$	1,042,992	$	72,121	$	(324,771	)	$	3,282,893
Energy trading revenues, net		—		—		106,583		—		—		—		$	106,583
Intersegment sales (a)		75,700		—		91,863		380,091		3,178		(550,832	)		—
Total Revenues	$	111,860	$	1,337,475	$	1,317,362	$	1,423,083	$	75,299	$	(875,603	)	$	3,389,476
Net margin	$	85,421	$	395,612	$	109,218	$	207,356	$	75,299	$	(3,995	)	$	868,911
Operating costs	$	36,076	$	251,516	$	25,669	$	93,769	$	21,283	$	(7,892	)	$	420,421
Depreciation, depletion and amortization	$	12,938	$	78,669	$	4,213	$	24,470	$	19,247	$	736		$	140,273
Operating income	$	36,407	$	65,427	$	79,336	$	89,117	$	34,769	$	3,161		$	308,217
Income from equity investments	$	861	$	—	$	—	$	—	$	—	$	(59	)	$	802
Total assets	$	801,266	$	2,390,165	$	1,484,257	$	971,977	$	205,840	$	570,831		$	6,424,336
Capital expenditures	$	7,696	$	106,332	$	1,372	$	18,457	$	37,608	$	20,870		$	192,335

(a) - Intersegment sales for Energy Services were $327.3 million for the six months ended June 30, 2004.

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	Regulated					Non-Regulated
Nine Months Ended September 30, 2003	Transportation and Storage			Distribution		Energy Services			Gathering and Processing			Production		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	51,875		$	1,212,869	$	61,196		$	980,234		$	30,080	$	(370,224	)	$	1,966,030
Energy trading revenues, net		—			—		183,938			—			—		—		$	183,938
Intersegment sales		63,138			—		(a	)		382,405			2,121		(447,664	)		—
Total Revenues	$	115,013		$	1,212,869	$	245,134		$	1,362,639		$	32,201	$	(817,888	)	$	2,149,968
Net margin	$	84,010		$	367,795	$	191,374		$	152,121		$	32,201	$	2,269		$	829,770
Operating costs	$	34,190		$	226,697	$	23,275		$	89,086		$	11,092	$	(1,077	)	$	383,263
Depreciation, depletion and amortization	$	12,518		$	71,633	$	4,328		$	21,921		$	8,790	$	1,051		$	120,241
Operating income	$	37,302		$	69,465	$	163,771		$	41,114		$	12,319	$	2,295		$	326,266
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	$	1,088		$	—	$	—		$	—		$	—	$	53		$	1,141
Total assets	$	862,511		$	2,288,523	$	1,178,553		$	1,305,563		$	141,757	$	(227,416	)	$	5,549,491
Capital expenditures	$	10,441		$	106,991	$	488		$	12,231		$	12,870	$	7,664		$	150,685

(a) - Intersegment sales for Energy Services were $373.0 million for the nine months ended September 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.

	Nine Months Ended September 30,
	2004		2003
	(Thousands of dollars)
Cash paid (received) during the period
Interest (including amounts capitalized)	$	64,078	$	68,532
Income taxes paid (received)	$	106,775	$	(10,848	)
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	$	25,840	$	18,614
Dividends on restricted stock	$	320	$	202
Treasury stock transferred to compensation plans	$	—	$	4,022
Issuance of restricted stock, net	$	—	$	3,201

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	Nine Months Ended September 30,
	2004		2003
	(Thousands of dollars)
Acquisitions
Property, plant and equipment	$	—	$	290,000
Current assets		—		69,919
Current liabilities		—		(63,205	)
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	$	—	$	436,630

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 September 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	$	20,839	102,914	$	0.20
Effect of other dilutive securities:
Mandatory convertible units		—	3,236
Options and other dilutive securities		—	792
Diluted EPS from continuing operations
Income from continuing operations available for common stock and common stock equivalents	$	20,839	106,942	$	0.19
	Three Months Ended September 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	$	595	77,865	$	0.01
Effect of other dilutive securities:
Options and other dilutive securities		—	836
Diluted EPS from continuing operations
Income from continuing operations available for common stock and common stock equivalents	$	595	78,701	$	0.01

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	Nine Months Ended September 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	$	143,781	101,530	$	1.42
Effect of other dilutive securities:
Mandatory convertible units		—	1,893
Options and other dilutive securities		—	657
Diluted EPS from continuing operations
Income from continuing operations available for common stock and common stock equivalents	$	143,781	104,080	$	1.38

	Nine Months Ended September 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		102,365	75,665	$	1.35
Basic EPS from continuing operations				$	1.64
Income from continuing operations available for Series D
Convertible Preferred Stock dividends		140,678	78,650
Effect of other dilutive securities:
Options and other dilutive securities		—	685
Series D Convertible Preferred Stock dividends		12,072	18,050
Income from continuing operations	$	152,750	97,385	$	1.57
Further dilution from applying the “two-class” method				$	(0.08	)
Diluted EPS from continuing operations				$	1.49

There were 8,997 and 171,249 option shares excluded from the calculation of diluted EPS for the three months ended September 30, 2004 and 2003, respectively, since their inclusion would be antidilutive for each period. For the nine months ended September 30, 2004 and 2003, there were 14,711 and 92,203 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 September 30, 2004, the applicable average stock price was $24.73 which resulted in 3.2 million dilutive units and reduced diluted EPS by approximately $0.01 per share. For the nine months ended September 30, 2004, the applicable average stock price was $22.92 which resulted in 1.9 million dilutive units and reduced diluted EPS by approximately $0.03 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 nine months ended September 30, 2003.

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N. Debt Covenant Compliance

On September 17, 2004, the Company entered into a $1.0 billion five-year credit agreement. The principal amount of the credit facility may be increased by $200 million if requested by the Company and the incremental commitment is received from new or existing lenders. The interest rate is a floating rate based on the Eurodollar rate plus a set number of basis points based on the Company’s current debt ratings by Moody’s Investors Service and Standard and Poors. The credit agreement contains customary affirmative and negative covenants relating to liens, investments, fundamental changes in the Company’s business, the restriction of certain payments, changes in the nature of the Company’s business, transactions with affiliates, burdensome agreements, the use of proceeds, and a limit on the Company’s debt to capital ratio.

The Company entered into an agreement with KBC Bank NV on April 20, 2004. The agreement gives the Company access to an uncommitted line of credit for loans and letters of credit up to a maximum principal amount of $10 million. The rate charged on any outstanding amount is the higher of prime or one-half of one percent above the Fed Funds overnight rate, which is the rate that banks charge each other for the overnight borrowing of funds. This agreement remains in effect until canceled by KBC Bank NV. This agreement does not contain any covenants more restrictive than those in the Company’s $1.0 billion five-year credit agreement.

The total amount of short term borrowings authorized by the board of directors is $1.2 billion.

Other debt agreements to which the Company is a party contain negative covenants that relate to liens and sale/leaseback transactions. At September 30, 2004, the Company was in compliance with all covenants.

O. Subsequent Event

In November 2004, the Company completed the sale of the propane distribution operations in and around Austin, Texas for approximately $2 million. The Company recorded a loss on the sale of approximately $0.3 million in the third quarter of 2004.

In October 2004, the Company entered into an agreement with Texas State Natural Gas, to sell the gas distribution system in Eagle Pass, Texas for approximately $2 million. The sale is expected to close in the fourth quarter of 2004.

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

Executive Summary - On November 1, 2004, we increased our earnings guidance for 2004 to a range of $2.25 to $2.31 per diluted share of common stock from a range of $2.18 to $2.24 per diluted share of common stock. This increase is the result of continued strength in natural gas prices, natural gas liquids prices and keep whole spreads in the Gathering and Processing segment. We also reaffirmed our earnings guidance for 2005 in the range of $2.22 to $2.28 per diluted share of common stock. Because 2005 guidance includes no benefits from financial trading operations, any margins from trading activities will increase this guidance.

Our acquisition of Northern Plains Natural Gas Company is expected to close in the fourth quarter and we will own 82.5 percent of the general partner interest in Northern Border Partners, L.P., one of the largest publicly-traded master limited partnerships. The assets owned by this master limited partnership complement our existing asset base, and the acquisition provides an infrastructure that will serve as a new growth vehicle for us.

During this quarter, our board of directors voted to increase our quarterly dividend to 25 cents per share of common stock. This was the sixth increase in two years and resulted in a dividend increase of 61 percent during that period of time. Our board of directors will continue to evaluate our dividend payout in relation to both our financial performance and our peer companies, making adjustments when appropriate, to provide a fair return to our investors.

Our Energy Services segment, formerly known as Marketing and Trading, has continued our efforts to grow our wholesale and retail marketing businesses while de-emphasizing both gas options trading and unhedged pipeline arbitrage. We expect trading activity to be a smaller part of our operating income with our focus on the physical purchase and sale of natural gas. As a result of this shift in focus, we have evaluated the accounting treatment related to the presentation of revenues and on July 1, 2004 began reporting revenues from certain activities on a gross rather than net basis. Reporting of these transactions on a gross basis affects revenues and cost of sales and fuel but does not impact net margin or operating income. We also adopted Energy Services as the new name for this segment, which more clearly differentiates our organization within the industry.

In September, the class action lawsuits related to the explosions or eruptions of natural gas geysers that occurred at or near the Yaggy storage field outside of Hutchinson, Kansas were concluded. The jury awarded the plaintiffs in the residential class $5 million in actual damages, which is covered by insurance. In the other class action relating to business claims, the jury awarded no actual damages. The jury rejected claims for punitive damages in both cases.

On October 4, 2004, Moody’s Investors Service changed our ratings outlook from negative to stable. Moody’s cited our sustained improved financial leverage, financial flexibility and demonstrated commitment to improving our credit profile.

Acquisitions and Divestitures - In November 2004, we completed the sale of the propane distribution operations in and around Austin, Texas for approximately $2 million. We recorded a loss on the sale of approximately $0.3 million in the third quarter of 2004.

In October 2004, we entered into an agreement with Texas State Natural Gas to sell the gas distribution system in Eagle Pass, Texas for approximately $2 million. The sale is expected to close in the fourth quarter of 2004.

In September 2004, we announced that we entered into an agreement to purchase Northern Plains Natural Gas Company, which owns 82.5 percent of the general partnership interest and 500,000 limited partnership units, together representing a 2.73 percent ownership interest in Northern Border Partners, L.P., from CCE Holdings, LLC for $175 million. This transaction is subject to CCE Holdings, LLC closing its acquisition of CrossCountry Energy, LLC from Enron Corp. and certain of its affiliates, which is expected to occur in the fourth quarter of 2004.

In May and July 2004, we completed the sale of our propane bottle operations located in Texas and New Mexico in two separate transactions totaling approximately $1.4 million and recorded a pre-tax gain of $0.9 million, which is included in other income in the Gathering and Processing segment.

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.

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

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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 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.

During the third quarter of 2004, the Kansas Corporation Commission (KCC) approved Kansas Gas Service Company’s (KGS) request that it be allowed to recover additional ad valorem tax expense of $3.3 million incurred above the amount currently recovered in the cost of service rate. This excess is recoverable through a surcharge.

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 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”, 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 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 and $0.9 million for the three and nine months ended September 30, 2004, respectively. The reduction in current period service cost due to the subsidy was $0.1 million and $0.2 million for the three and nine months ended September 30, 2004, respectively. There was no change to the interest cost on the accumulated postretirement benefit obligation for the three months ended September 30, 2004, while there was a $0.3 million reduction for the nine months ended September 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

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”, No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” 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 47 for amounts in our portfolio at September 30, 2004 that were determined by prices actively quoted, prices provided by other external sources, and prices derived

26

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” 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, 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, KGS, Texas Gas Service Company (TGS) and portions of our 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 September 30, 2004, our regulatory assets totaled $201.6 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.” 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. As discussed in the Liquidity and Capital Resources section of this Form 10-Q, we adjusted the discount rate from 6.25 percent to 6.75 percent when we remeasured our pension and postretirement employee benefits plans’ assets and liabilities at July 1, 2004. Our annual remeasurement will occur as of September 30, 2004 and will affect the amount of pension and postretirement benefit expenses we will record beginning January 1, 2005. Based on market conditions at September 30, 2004, we anticipate using a discount rate of 6.00 percent during this remeasurement. Absent other changes in our assumptions, this impact will increase the level of expenses in 2005 compared to 2004. See Note I of the Notes to Consolidated Financial Statements in this Form 10-Q.

27

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 September 30,				Nine Months Ended September 30,
Financial Results	2004		2003		2004		2003
	(Thousands of dollars)
Operating revenues, excluding energy trading revenues	$	1,709,351	$	557,093	$	3,282,893	$	1,966,030
Energy trading revenues, net		17,411		11,177		106,583		183,938
Cost of gas		1,480,662		373,888		2,520,565		1,320,198
Net margin		246,100		194,382		868,911		829,770
Operating costs		139,290		122,457		420,421		383,263
Depreciation, depletion, and amortization		47,307		40,105		140,273		120,241
Operating income	$	59,503	$	31,820	$	308,217	$	326,266
Other income	$	1,632	$	1,252	$	11,101	$	4,157
Other expense	$	1,338	$	472	$	9,811	$	1,590
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. Net margin increased for the three and nine months ended September 30, 2004 compared to the same periods in 2003 primarily due to:

• a favorable pricing environment for natural gas processing

• improved margins resulting from the strategy of restructuring unprofitable gas purchase, gathering and processing contracts

• volumes produced from our Texas gas and oil properties acquired in December 2003

• the impact of higher prices on our Production segment

• rate relief in our Distribution segment

These increases were partially offset by the impact of reduced volatility in natural gas prices in our results from the Energy Services segment.

Consolidated operating costs increased for both the three and nine months ended September 30, 2004 compared to the same periods in 2003, primarily due to:

• increased labor and employee benefit costs

• increased production costs related to the acquisition of our Texas gas and oil properties

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

• additional depreciation resulting from the acquisition of the Texas gas and oil properties

• regulatory asset amortization resulting from the Kansas and Oklahoma rate cases

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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. The system was installed in Texas and Kansas in June 2004 and September 2004, respectively. Installation will follow in Oklahoma in the future. We have implemented control processes and performed extensive testing on this system. This resulted in us identifying certain implementation issues which we are addressing. As with any implementation, there are inherent risks and uncertainties that could negatively impact us; however, we do not believe they will have a material impact on our financial statements.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2004			2003		2004			2003
	(Thousands of dollars)
Gain on sales of property	$	1,158		$	—	$	9,765		$	289
Interest income		357			539		811			1,623
Partnership income		262			351		803			1,137
Income (expense) from benefit plan investments		112			170		(609	)		507
Other		(257	)		192		331			601
Other income	$	1,632		$	1,252	$	11,101		$	4,157

	Three Months Ended September 30,				Nine Months Ended September 30,
	2004		2003		2004		2003
	(Thousands of dollars)
Litigation expenses and claims, net	$	317	$	48	$	7,537	$	(809	)
Donations, civic, and governmental		463		420		1,592		1,386
Loss on sales of property		420		—		420		—
Other		138		4		262		1,013
Other expense	$	1,338	$	472	$	9,811	$	1,590

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. See Part II, Item 1 Legal Proceedings for additional discussion of the Enron case.

More information regarding our results of operations is provided in the discussion of operating results for each of our segments. The discontinued component is included in our Production segment’s financial results and the cumulative effect of a change in accounting principle is included in our Energy Services 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, which is the cost per Mcfe of adding proved reserves through drilling, and minimizing production costs.

Acquisition and 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 nine months ended September 30, 2004, we had the following results:

• participated in drilling 86 wells, including 19 wells during the third quarter

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• participated in completing 50 producing gas wells and three producing oil wells, including 25 gas wells and one oil well during the third quarter

• 33 wells were still being drilled or completed at September 30, 2004

• no dry holes

For the nine months ended September 30, 2003, we had the following results:

• participated in drilling 24 wells, including five wells during the third quarter

• participated in completing 14 producing gas wells and one producing oil well, including seven producing gas wells during the third quarter

• eight wells were still being drilled or completed at September 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 September 30,						Nine Months Ended September 30,
Financial Results	2004			2003			2004			2003
	(Thousands of dollars)
Natural gas sales	$	20,860		$	7,940		$	64,085		$	25,785
Oil sales		2,652			1,798			7,526			5,591
Other revenues		1,256			71			3,688			825
Net margin		24,768			9,809			75,299			32,201
Operating costs		7,242			3,547			21,283			11,092
Depreciation, depletion, and amortization		6,593			2,795			19,247			8,790
Operating income	$	10,933		$	3,467		$	34,769		$	12,319
Other income (expense), net	$	(20	)	$	(3	)	$	(110	)	$	2
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

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	Three Months Ended September 30,						Nine Months Ended September 30,
Operating Information	2004			2003			2004		2003
Proved reserves (a)
Continuing operations
Gas (MMcf)		(b	)		(b	)		204,793		62,759
Oil (MBbls)		(b	)		(b	)		3,620		2,140
Production
Continuing operations
Gas (MMcf)		4,036			1,709			12,339		5,282
Oil (MBbls)		89			67			258		202
Discontinued component
Gas (MMcf)		—			—			—		1,472
Oil (MBbls)		—			—			—		53
Average realized price (c)
Continuing operations
Gas ($/Mcf)	$	5.17		$	4.65		$	5.19	$	4.88
Oil ($/Bbls)	$	29.80		$	26.84		$	29.16	$	27.68
Discontinued component
Gas ($/Mcf)	$	—		$	—		$	—	$	4.10
Oil ($/Bbls)	$	—		$	—		$	—	$	32.28
Capital expenditures (Thousands of dollars)
Continuing operations	$	17,190		$	6,142		$	37,608	$	12,870

(a) Proved reserves include 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 once as of September 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 nine months ended September 30, 2004 compared to the same periods in 2003 due to:

• volumes produced from our Texas properties acquired in December 2003

• higher prices received on current year volumes

Our Texas properties produced 2.1 Bcf and 6.9 Bcf of natural gas during the three and nine months ended September 30, 2004, respectively. Oil production from these properties was 28,600 Bbls and 95,600 Bbls for the same periods.

Other revenues increased for the three and nine months ended September 30, 2004 as a result of the flow line fees and revenues from our Texas flow line system which was included in the December 2003 purchase.

For both the three and nine months ended September 30, 2004 compared to the same periods in 2003, the following increases in operating costs were primarily due to the Texas acquisition:

• $1.1 million and $3.4 million in lease operating expenses, respectively

• $0.5 million and $2.0 million in overhead costs, respectively

• $0.8 million and $1.8 million in production taxes, respectively

• $0.7 million and $1.7 million in ad valorem taxes, respectively

• $0.6 million and $1.3 million in gathering expenses, respectively

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

The Production segment added 8.2 Bcfe of net natural gas and oil reserves for the nine months ended September 30, 2004. This included 4.0 Bcfe of proved developed reserves, comprised of 1.4 Bcfe of proved developed producing reserves and 2.6 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.

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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 nine months ended September 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 margin. 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 100 percent of our anticipated oil production at a fixed New York Mercantile Exchange (NYMEX) price of $30.35 per Bbl.

Currently, we have hedges on 19 MMcf per day of our 2005 natural gas production at a net wellhead price of $5.69 per Mcf. We have also hedged an additional 9.8 MMcf per day of our first quarter 2005 natural gas production at a net wellhead price of $6.12 per Mcf and 9.8 MMcf per day of natural gas production for the remaining three quarters of 2005 at a net wellhead price of $6.22 per Mcf. Oil production is hedged in 2005 for 15,000 Bbls per month at a fixed NYMEX price of $39.75 per Bbl.

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.

Gathering and processing operations include 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 September 30,				Nine Months Ended September 30,
Contract Type	2004		2003		2004		2003
Fee	43	%	44	%	45	%	46	%
Percent of Proceeds	33	%	27	%	31	%	27	%
Keep Whole	24	%	29	%	24	%	27	%

Characteristics of the contract types are explained below.

• Under a fee contract, we are paid a fee for each Btu gathered, compressed and/or 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 quantities of merchantable natural gas containing the same number of Btus 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 quantities 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, or gross processing, spread which is the difference in value between NGLs and natural gas on a Btu basis.

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We have been successful in amending contracts covering about 22 percent of the quantities 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 margin 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 and Divestiture - The sale of the propane bottle operations located in Texas and New Mexico in May and July, 2004 is described on page 25.

The acquisition of NGL storage and pipeline facilities located in Conway, Kansas in December 2003 is described in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 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 September 30,					Nine Months Ended September 30,
Financial Results	2004		2003			2004		2003
	(Thousands of dollars)
Natural gas liquids and condensate sales	$	325,504	$	259,572		$	863,708	$	774,355
Gas sales		166,770		151,146			483,029		517,768
Gathering, compression, dehydration and processing fees and other revenues		27,466		23,976			76,346		70,516
Cost of sales		435,369		381,238			1,215,727		1,210,518
Net margin		84,371		53,456			207,356		152,121
Operating costs		34,748		28,597			93,769		89,086
Depreciation, depletion, and amortization		8,304		7,383			24,470		21,921
Operating income	$	41,319	$	17,476		$	89,117	$	41,114
Other income (expense), net	$	312	$	(130	)	$	23	$	(145	)
Cumulative effect of a change in accounting principle, net of tax	$	—	$	—		$	—	$	(1,375	)

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	Three Months Ended September 30,				Nine Months Ended September 30,
Operating Information	2004		2003		2004		2003
Total gas gathered (MMMBtu/d)		1,099		1,162		1,106		1,178
Total gas processed (MMMBtu/d)		1,175		1,201		1,162		1,215
Natural gas liquids sales (MBbls/d)		108		112		107		113
Natural gas liquids produced (MBbls/d)		64		62		61		58
Gas sales (MMMBtu/d)		330		340		325		339
Capital expenditures (Thousands of dollars)	$	8,500	$	4,239	$	18,457	$	12,231
Conway OPIS composite NGL price ($/gal) (based on our NGL product mix)	$	0.76	$	0.57	$	0.68	$	0.58
Average NYMEX crude oil price ($/Bbl)	$	42.28	$	30.65	$	38.41	$	31.30
Average natural gas price ($/MMBtu) (mid-continent region)	$	5.43	$	4.80	$	5.38	$	5.30

Operating Results - Net margin for both the three and nine months ended September 30, 2004 increased compared to the same periods in 2003 primarily due to the pricing environment for natural gas processed during the third quarter of 2004 being more favorable than during any period in the last five years. Higher NGL and condensate prices, which are generally affected by crude oil prices, increased the profitability of our POP contracts as well as improved the keep whole pricing environment. Our composite gross processing spread increased as follows:

• $3.07 per MMBtu for the three month period in 2004 compared to $1.43 per MMBtu for the same period in 2003

• $2.17 per MMBtu for the nine month period in 2004 compared to $1.08 per MMBtu for the same period in 2003

The gross processing spread for both periods in 2004 was considerably higher than the five year average of $1.58. Based on current market conditions for 2005, we expect a return to the historical average as evidenced by natural gas prices recently strengthening against NGL prices despite the strong price of crude.

The renegotiation of certain NGL storage agreements at our Bushton facility and the addition of NGL storage and pipeline assets located at Conway, Kansas increased net margin for both the three and nine-month periods in 2004 compared to the same periods in 2003. Improved contractual terms for gas gathering and processing resulting from our continued efforts to restructure unprofitable gas purchase and gathering contracts continues to contribute to the increase in net margin.

Operating costs remain in line with management expectations but were higher for both the three and nine-month periods in 2004 than in the same periods in 2003 primarily as the result of higher labor and employee benefit costs. Additionally, approximately $3.3 million of the increase for both periods was related to charges associated with various contractual dispute settlements.

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

Capital expenditures increased in 2004 for both the three and nine-month periods relative to the same periods in 2003 primarily due to the construction of a new 33-mile NGL pipeline that will connect our Kansas NGL storage facilities at Bushton and Conway. This pipeline is expected to cost approximately $9.2 million and be in service by December 31, 2004.

Risk Management - We used derivative instruments during the three and nine months ended September 30, 2004 and 2003 to minimize risk associated with natural gas price volatility. For the nine months ended September 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.

Currently, for the remainder of 2004 we have:

• hedged approximately 66 percent of our anticipated company-owned condensate sales at an average NYMEX price of $39.40 per Bbl

• pre-sold approximately 57 percent of our anticipated company-owned NGLs at a weighted average price of $0.61 per gallon

• hedged approximately 67 percent of our anticipated keep whole quantities at an average gross processing spread of $3.44 per MMBtu

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Currently, for 2005 we have:

• hedged approximately 50 percent of our anticipated company-owned condensate sales at an average NYMEX price of $44.59 per Bbl

• pre-sold approximately 34 percent of our anticipated company- owned NGLs at a weighted average price of $0.74 per gallon

• hedged approximately 52 percent of our anticipated equity natural gas sales at a weighed average price of $6.66 per MMBtu

Management continues to evaluate market conditions for the remainder of 2004 as well as 2005 to take advantage of favorable pricing opportunities for our company-owned production associated with the POP contracts as well as our keep whole quantities. We use a variety of risk management tools including swaps, forward sales of NGLs, and the purchase and sale of NYMEX natural gas and crude futures, respectively.

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 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 sale of transmission and gathering pipelines and compression facilities in March 2004 is described on page 25.

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

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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 September 30,				Nine Months Ended September 30,
Financial Results	2004		2003		2004		2003
	(Thousands of dollars)
Transportation and gathering revenues	$	24,615	$	25,898	$	75,186	$	79,046
Storage revenues		10,575		10,428		32,828		30,731
Gas sales and other		1,188		1,648		3,846		5,236
Cost of fuel and gas		7,935		11,126		26,439		31,003
Net margin		28,443		26,848		85,421		84,010
Operating costs		12,236		11,840		36,076		34,190
Depreciation, depletion, and amortization		4,382		4,180		12,938		12,518
Operating income	$	11,825	$	10,828	$	36,407	$	37,302
Other income (expense), net	$	238	$	283	$	2,335	$	1,172
Cumulative effect of a change in accounting principle, net of tax	$	—	$	—	$	—	$	(645	)

	Three Months Ended September 30,				Nine Months Ended September 30,
Operating Information	2004		2003		2004		2003
Volumes transported (MMcf)		92,409		101,025		314,156		341,143
Capital expenditures (Thousands of dollars)	$	3,685	$	5,640	$	7,696	$	10,441
Average natural gas price ($/MMBtu) (mid-continent region)	$	5.43	$	4.80	$	5.38	$	5.30

Operating results - Net margin showed little change for the three and nine months ended September 30, 2004 compared to the same periods in 2003 and was 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 2004

• decreased cost of fuel and gas due to lower transportation volumes partially offset by the impact of increased storage activity on fuel consumed and higher fuel prices

Operating costs remain in line with management expectations but were slightly higher for both the three and nine-month periods in 2004 than in the same periods in 2003 primarily as the result of higher labor and employee benefit costs.

The increase in other income (expense), net for the nine months ended September 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 to approximately 2 million customers 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 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.

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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

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. The system was installed in Texas and Kansas in June 2004 and September 2004, respectively. Installation will follow in Oklahoma in the future. We have implemented control processes and performed extensive testing on this system. This resulted in us identifying certain implementation issues which we are addressing. As with any implementation, there are inherent risks and uncertainties that could negatively impact us; however, we do not believe they will have a material impact on our financial statements.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
Financial Results	2004			2003			2004			2003
	(Thousands of dollars)
Gas sales	$	224,727		$	200,524		$	1,257,299		$	1,140,551
Cost of gas		159,033			132,333			941,863			845,074
Gross margin		65,694			68,191			315,436			295,477
Transportation revenues		17,510			16,141			59,993			53,638
Other revenues		5,422			5,169			20,183			18,680
Net margin		88,626			89,501			395,612			367,795
Operating costs		79,711			71,460			251,516			226,697
Depreciation, depletion, and amortization		26,518			24,023			78,669			71,633
Operating income (loss)	$	(17,603	)	$	(5,982	)	$	65,427		$	69,465
Other income (expense), net	$	(124	)	$	162		$	(942	)		(427	)

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 significantly impacting our gross margin since most factors that affect gas sales also affect cost of gas by an equivalent amount.

Implementation of new rate schedules in Kansas and Oklahoma increased gross margin by $6.0 million and $1.1 million, respectively, for the three months ended September 30, 2004, compared to the same period in 2003. These increases were more than offset by the following reductions in gross margin:

• $1.2 million due to decreased customer usage in Oklahoma

• $1.3 million due to increased line loss expense, net of rider recoveries in Oklahoma

• elimination of the WeatherProof Bill program in Kansas which reduced gross margin by $7.1 million and offset the remainder of the benefit seen in the first quarter

The increase in gross margin for the nine months ended September 30, 2004, compared to the same period in 2003, is primarily attributable to new rate schedules in Kansas and Oklahoma, which added $22.5 million and $9.4 million, respectively.

These increases in gross margin were partially offset by:

• $7.8 million due to decreased customer usage in all three states

• $2.5 million due to increased line loss expense and decreased recoveries through rate riders

The increase in transportation revenues for the three and nine months ended September 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.

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Operating costs increased for the three months ended September 30, 2004 compared to the same period in 2003 primarily due to increased labor and employee benefit costs of $9.7 million.

These increases in operating costs were partially offset by:

• decreased property taxes of $2.0 million

• decreased bad debt expense of $1.2 million

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

• increased labor and employee benefit costs of $20.5 million

• increased bad debt expense of $1.3 million

• increased legal costs of $1.1 million

• increased operating costs of $0.8 million due to the acquisitions of the distribution systems 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

These increases in operating costs were partially offset by decreased property taxes of $0.9 million.

Depreciation, depletion and amortization increased for the three and nine months ended September 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 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

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

	Three Months Ended September 30,				Nine Months Ended September 30,
Operating Information	2004		2003		2004		2003
Average Number of Customers		1,991,117		1,970,074		2,006,276		1,989,907
Customers per employee		659		660		662		666
Capital expenditures (Thousands of dollars)	$	43,732	$	47,865	$	106,332	$	106,991

	Three Months Ended September 30,		Nine Months Ended September 30,
Volumes (MMcf)	2004	2003	2004	2003
Gas sales
Residential	8,049	8,885	83,162	87,179
Commercial	4,059	4,099	29,362	31,777
Industrial	602	547	1,962	2,641
Wholesale	11,360	8,312	26,765	21,857
Public Authority	263	280	1,605	1,683
Total volumes sold	24,333	22,123	142,856	145,137
Transportation	55,492	54,125	177,066	166,772
Total volumes delivered	79,825	76,248	319,922	311,909

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	Three Months Ended September 30,				Nine Months Ended September 30,
Margin	2004		2003		2004		2003
	(Thousands of dollars)
Gas sales
Residential	$	52,286	$	55,166	$	241,309	$	224,953
Commercial		11,007		11,069		65,290		62,382
Industrial		367		327		2,434		2,240
Wholesale		1,616		1,209		4,252		3,957
Public Authority		418		420		2,151		1,945
Gross margin		65,694		68,191		315,436		295,477
Transportation		17,510		16,141		59,993		53,638
Total margin	$	83,204	$	84,332	$	375,429	$	349,115

Residential and commercial volumes decreased for the three and nine months ended September 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 nine months ended September 30, 2004 compared to the same period in 2003 due to industrial customers migrating to new transportation rates in Oklahoma.

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 nine months ended September 30, 2004 compared to the same periods in 2003 as fewer volumes were required to meet the needs of 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 nine months ended September 30, 2004 compared to the same periods in 2003 primarily due to:

• the acquisitions of the distribution systems 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

• ONG’s commercial and industrial customers migrating to new transportation rates

• ONG’s marketing effort to add small usage transport customers

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 upgrade facilities to assure safe, reliable, and efficient operations. Our capital expenditure program included $8.0 million and $10.6 million for new business development for the three months ended September 30, 2004 and 2003, respectively, and $25.0 million and $22.5 million for new business development for the nine months ended September 30, 2004 and 2003, respectively.

Regulatory Initiatives

Oklahoma - On January 30, 2004, the OCC issued an order allowing 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 and, should our analysis indicate a potential refund liability, we will record a reserve for the obligation.

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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 interim rates were implemented in May 2003.

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.

Energy Services

Overview - Our Energy Services segment, formerly known as Marketing and Trading, primarily purchases, stores, transports and markets 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 1.4 Bcf/d. With total cyclical storage capacity of 84.7 Bcf, maximum withdrawal capability of 2.3 Bcf/d and maximum injection capability of 1.6 Bcf/d spread across 18 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 energy services operations into Canada by leasing storage and pipeline capacity. Our Canadian operations bring gas supply from western Canada into the market areas of the upper midwestern and northeastern parts of the United States. We also trade natural gas and power on a smaller scale.

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

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 increased our owned or contracted power capacity from 300 to 512 megawatts.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
Financial Results	2004			2003			2004			2003
	(Thousands of dollars)
Energy and power revenues	$	1,128,025		$	26,896		$	1,210,130		$	60,421
Energy trading revenues, net		17,411			11,177			106,583			183,938
Other revenues		205			159			649			775
Cost of sales and fuel		1,126,039			23,736			1,208,144			53,760
Net margin		19,602			14,496			109,218			191,374
Operating costs		7,197			6,750			25,669			23,275
Depreciation, depletion, and amortization		1,398			1,397			4,213			4,328
Operating income	$	11,007		$	6,349		$	79,336		$	163,771
Other income (expense), net	$	(1,874	)	$	(1,632	)	$	(5,398	)	$	(4,617	)
Cumulative effect of changes in accounting principle, net of tax	$	—		$	—		$	—		$	(141,982	)

	Three Months Ended September 30,				Nine Months Ended September 30,
Operating Information	2004		2003		2004		2003
Natural gas marketed (MMcf)		240,462		220,622		775,618		754,769
Natural gas gross margin ($/Mcf)	$	0.07	$	0.03	$	0.11	$	0.19
Electricity marketed (MMwh)		1,661		561		3,412		1,304
Physically settled volumes (MMcf)		507,965		469,958		1,558,578		1,519,694
Capital expenditures (Thousands of dollars)	$	558	$	92	$	1,372	$	488

Operating Results - At the beginning of the third quarter, we completed a reorganization of our Energy Services segment and renewed our focus on our physical marketing and storage business. 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 earned from these activities. Prior to the third quarter, we managed the Energy Services segment on an integrated basis and presented all energy trading activity on a net basis. Power sales are accounted for as trading activities and, accordingly, are included in trading. The following table shows these types of margins by activity:

	Three Months Ended September 30, 2004
	(Thousands of dollars)
Marketing and storage	$	29,906
Trading		18,589
Retail marketing		3,051
Transportation and storage costs		(31,944	)
Net margin	$	19,602

Concurrent with this reorganization, we evaluated the accounting treatment related to the presentation of revenues from the different types of activities to determine which amounts should be reported on a gross or net basis under the guidance in EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, 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). For derivative instruments considered held for trading purposes that result in physical delivery, the indicators in EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” were used to determine the proper treatment. These activities and all financially settled derivative contracts will continue to be reported on a net basis.

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For derivative instruments that are not considered “held for trading purposes” and that result in physical delivery, the indicators in EITF 03-11 and EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19) were used to determine the proper treatment. We began accounting for the realized revenues and purchase costs of these contracts that result in physical delivery on a gross basis beginning with the third quarter of 2004. We apply the indicators in EITF No. 99-19, to determine the appropriate accounting treatment for non-derivative contracts that result in physical delivery. Derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are also reported on a gross basis. No prior periods have been adjusted for this change; therefore, comparisons to prior periods may not be meaningful. Reporting of these transactions on a gross basis did not impact operating income but resulted in an increase to revenues and cost of sales and fuel.

Net margin increased for the three months ended September 30, 2004 compared to the same period in 2003 primarily due to the increase in the mark to market value of our derivative contracts subject to fair value accounting, which increased $17.9 million, primarily due to increased natural gas volatility. A decrease of approximately 17 percent in cooling degree days led to reduced demand for electric generation offsetting much of this increase.

Other decreases in net margin were:

• increased expenses of $2.8 million included in cost of sales and fuel resulting from increased storage and transportation capacity

• weaker spark spreads of $2.0 million in the Southwest Power Pool and ERCOT resulting from unseasonably mild weather conditions in July and August 2004

• a decrease of $0.6 million in our retail natural gas operations primarily due to lack of irrigation demand because of above normal rainfall in Kansas and Nebraska

For the nine months ended September 30, 2004, compared to the same period in 2003, net margin decreased primarily by:

• $37.7 million due to lower natural gas price volatility and the impact it has on our trading portfolio

• $43.7 million due to lower inter-regional basis spreads early in 2004

• $5.5 million due to weaker spark spreads in the Southwest Power Pool and ERCOT

These decreases were partially offset by increased revenues of $8.0 million from reservation fees for natural gas peaking services.

Natural gas sales volumes increased for the three months ended September 30, 2004, compared to the same period in 2003 due to expanded Canadian operations and higher natural gas storage inventory levels at the beginning of the third quarter of 2004, which shifted purchased volumes from storage injections to regional sales.

Our natural gas storage inventory level at September 30, 2004 was 79.1 Bcf, or 86.8 percent of capacity, compared to 71.1 Bcf, or 88.4 percent of capacity, at September 30, 2003.

Operating costs increased $2.4 million for the nine months ended September 30, 2004 compared to the same period in 2003 primarily due to:

• $0.7 million increase in start-up costs associated with our Canadian operations

• $0.8 million increase in ad valorem taxes

• $0.9 million increase in employee-related costs

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, exclusive of any acquisitions.

Financing - Financing is provided through our commercial paper program, long-term debt and, as needed, through a credit agreement. 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. We expect to issue commercial paper to finance the acquisition of Northern Plains Natural Gas Company.

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Credit Rating - Our credit ratings are currently an “A-” (stable outlook) by Standard and Poors and a “Baa1” (stable outlook) by Moody’s Investors Service. Our credit ratings may be affected by a material change in our financial ratios or a material adverse event affecting our business. The most common criteria for assessing our credit ratings 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 a $1 billion credit agreement, which expires September 16, 2009.

Our Energy Services segment 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 September 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 $81.7 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. Additionally, a remeasurement of plan assets and liabilities at July 1, 2004 was triggered by changes in our contracts with the bargaining units. Because of market conditions at July 1, 2004, we selected a discount rate of 6.75 percent to remeasure our plan. The net impact of these changes increased our pension costs for 2004 by approximately $2.8 million. We also had a nonrecurring reduction in the value of the assets of $1.7 million in the third quarter of 2004. Accordingly, our pension credit for our pension and supplemental retirement plans will decrease from $4.4 million in 2003 to a charge of $0.9 million in 2004. If the value of our pension fund assets decreases below our accumulated benefit obligation, we will eliminate the asset and record a minimum pension liability on our 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 $151.3 million for the nine months ended September 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 nine months ended September 30, 2003, we injected higher levels of inventory into storage, which negatively impacted our 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 approximately $17.2 million.

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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.

	September 30, 2004		December 31, 2003
Long-term debt	57	%	60	%
Equity	43	%	40	%
Debt (including Notes payable)	61	%	67	%
Equity	39	%	33	%

At September 30, 2004, we had $1.9 billion of long-term debt outstanding, including current maturities. As of September 30, 2004, we could have issued $1.6 billion of additional long-term debt under the most restrictive provisions contained in our various borrowing agreements. During the first quarter of 2004, we paid off $600 million in notes payable using cash generated from operating activities and proceeds from our February 2004 equity offering. During the third quarter of 2004, we incurred $258 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 51 percent long-term debt and 49 percent equity at September 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 48 percent long-term debt and 52 percent equity at September 30, 2004.

We signed a $1 billion, five year credit agreement on September 17, 2004. The agreement expires on September 16, 2009, at which time all outstanding amounts under the credit agreement will be due and payable. This agreement is primarily used to support our commercial paper program. At September 30, 2004, we had $298 million in commercial paper outstanding and approximately $17.8 million in cash and temporary investments.

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

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;

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• 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 463 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 of the natural gas business;

• competitive changes in the natural gas gathering, transportation and storage business resulting from deregulation of the natural gas business;

• the profitability of assets or businesses acquired by us;

• risks of marketing, hedging, and trading activities as a result of changes in energy prices or the financial condition of our counterparties;

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

• the uncertainty of estimates, including accruals, cost of environmental remediation, and 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;

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

• risks associated with pending or possible acquisitions and dispositions, including our ability to finance or 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 risk that material weaknesses or significant deficiencies in internal control over financial reporting could emerge or that minor problems could become significant;

• 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 Ris k

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. TGS may use derivative instruments to mitigate the volatility of gas costs to protect its customers in the city of El Paso. At September 30, 2004, KGS and TGS had derivative instruments in place to hedge the cost of natural gas purchases for 11.0 Bcf and 0.4 Bcf, respectively, which represents part of their gas purchase requirements for the 2004/2005 winter heating months based on normal weather conditions. Gains or losses associated with the KGS and TGS hedges are included in and recoverable through the monthly purchased gas adjustment.

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

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	Fair Value of Contracts at September 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)	$	116,799		$	5,190		$	—		$	—	$	121,989
Prices provided by other external sources (3)		(116,308	)		(11,729	)		—					(128,037	)
Prices derived from quotes, other external sources and other assumptions (4)		(11	)		(218	)		(1,232	)		426		(1,035	)
Total	$	480		$	(6,757	)	$	(1,232	)	$	426	$	(7,083	)

(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 September 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. Through September 30, 2004, $5.6 million in interest expense savings has been recognized and the remaining amount of $76.3 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:

Remainder of 2004	$	2.5 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 September 30, 2004, we recorded a $14.5 million net liability to recognize the interest rate swaps at fair value. Long-term debt was also decreased by $14.5 million to recognize the change in the fair value of the related hedged liability.

Total savings from the interest rate swaps was $23.2 million for the first nine months of 2004. The swaps are expected to generate the following savings for the remainder of the year:

• interest expense savings of $2.6 million for remainder of 2004 related to the amortization of the swap value at termination

• up to $2.3 million in interest savings from the new swaps based on current LIBOR rates

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Total swap savings for 2004 are expected to be $28.1 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 may have the ability to take action to manage the exposure to the change. Since a specific action and the possible effects are uncertain, no change has been assumed.

With our Energy Services segment’s expansion into Canada, we are subject to currency exposure. Our objective with respect to currency risk is to reduce the exposure due to exchange-rate fluctuations. We use physical forward transactions, which result in an actual two-way flow of currency on the settlement date since we exchange U.S. dollars for Canadian dollars with another party. We have not designated these transactions for hedge accounting treatment; therefore, the gains and losses associated with the change in fair value are recorded in net margin. At September 30, 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 $4.2 million and $9.0 million at September 30, 2004 and 2003, respectively.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
Value-at-Risk	2004		2003		2004		2003
	(Millions of dollars)
Average	$	1.8	$	1.8	$	3.5	$	3.5
High	$	4.2	$	3.9	$	17.7	$	17.1
Low	$	0.6	$	0.8	$	0.6	$	0.8

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

Item 4. Controls and Procedur es

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 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.

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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 - In the course of our ongoing evaluation, management has identified certain implementation issues which we are addressing related to the implementation of the new customer service system for our Distribution segment. We are implementing this system in order to consolidate the three customer service systems in our Distribution segment and to provide better customer service. The system was installed in Texas and Kansas in June 2004 and September 2004, respectively. Installation will follow in Oklahoma in the future. We have implemented control processes and performed extensive testing. As with any implementation, there are inherent risks and uncertainties that could negatively impact us; however, we do not believe they will have a material impact on our financial statements.

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

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. These two separate class action lawsuits filed against us in early 2001 relating to the natural gas explosions in Hutchinson, Kansas, resulted in jury verdicts in September 2004 in both cases. In the class action relating to the residential claimants, the jury awarded the claimants $5 million in actual damages, which is covered by insurance. In the other class action relating to business claims, the jury awarded no actual damages. The jury rejected claims for punitive damages in both cases. We are reviewing our options for appeal of the residential claimants’ class action. With the exception of a related lawsuit that was filed in Sedgwick County, Kansas, which is now on appeal (see Note J of the Notes to Consolidated Financial Statements included in this Form 10-Q for additional discussion on this matter), all other litigation regarding the gas explosions has been resolved.

Cornerstone Propane Partners, L.P., et al. v. E-Prime, Inc., ONEOK Energy Marketing and Trading Company, L.P., ONEOK, Inc. and Calpine Energy Services, L.P., Case No. 04-CV-00758, in the United States District Court for the Southern District of New York. On August 17, 2004, this case was consolidated for all purposes with a related lawsuit which names a number of other defendants in the energy industry. Plaintiffs in the related case assert allegations similar to those alleged against us in this case. On September 24, 2004, our motion to dismiss was denied. Discovery is underway. Although it is too early to accurately evaluate this matter, based on current information available to us, we do not expect this matter to have a material adverse effect on us. We intend to vigorously defend ourselves against these claims.

Enron Corp. v. Silver Oak Capital, LLC and AG Capital Recovery Partners III, LP, Adversary Proceeding No. 03-93568, relating to Case No. 01-16034, in the United States Bankruptcy Court for the Southern District of New York; Related Contested Matter in Case No. 01-16034. As reported previously, our subsidiary, ONEOK Energy Services, L.P. (formerly ONEOK Energy Marketing and Trading Company, L.P.) (“OES”), has repurchased from Angelo Gordon a portion (the “Repurchased Claim”) of the Enron Corp. guaranty claim (the “Guaranty Claim”) that Enron Corp. sought to avoid in the adversary proceeding (the “Adversary Proceeding”), as contemplated by the Transfer of Claims Agreement whereby OES originally sold the Guaranty Claim. OES is now providing the defense of the Adversary Proceeding for both the portion of the Guaranty Claim constituting the Repurchased Claim and also the portion of the Guaranty Claim still owned by Angelo Gordon’s successors in interest. Based on information currently available to us, we do not expect the Adversary Proceeding to have a

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material adverse effect on us. In addition to the Adversary Proceeding, Enron Corp. and Enron North America Corp. (“ENA”) have filed a new objection to portions of the Guaranty Claim and to portions of the underlying claim against ENA (the “Underlying ENA Claim”), instituting a new contested matter in the Enron Corp. bankruptcy case (the “Contested Matter”). The Contested Matter involves different legal and factual issues than those raised in the Adversary Proceeding. Enron Corp. and ENA allege in the Contested Matter that the Guaranty Claim and the Underlying ENA Claim are overstated. The filing of the Contested Matter may trigger additional obligations of OES under the Transfer of Claims Agreement to repurchase some of the claims previously sold. However, based on information currently available to us, we do not expect the Contested Matter to have a material adverse effect on us.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

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

Period	Total Number of Shares (or Units) Purchased		Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
July 1-31, 2004	32,860	(1)(2)(3)	$	21.84	—	—
August 1-31, 2004	24,989	(2)(3)	$	22.72	—	—
September 1-30, 2004	34,453	(2)	$	24.20	—	—
Total	92,302		$	22.96	—	—

(1) Includes restricted stock forfeitures for failure to satisfy vesting conditions as follows:

985 shares for the period July 1-31, 2004

(2) Includes 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, as follows :

31,869 shares for the period July 1-31, 2004

24,985 shares for the period August 1-31, 2004

34,453 shares for the period September 1-30, 2004

(3) Includes shares repurchased directly from employees as follows:

six shares for the period July 1-31, 2004

four shares for the period August 1-31, 2004

Employee Stock Award Program

Under our Employee Stock Award Program, we will issue, for no consideration, to all eligible employees (all full-time employees and employees on short-term disability) one share of our common stock when the per-share closing price of our common stock on the New York Stock Exchange (“NYSE”) is for the first time at or above $26 per share, and we will issue, for no consideration, one additional share of our common stock to all eligible employees when the closing price on the NYSE is for the first time at or above each one dollar increment above $26 per share. A total of 50,000 shares of our common stock are available for issuance under this program.

On September 30, 2004, the per-share price of our common stock closed for the first time at or above $26 on the NYSE. Accordingly, we issued one share of our common stock to each of our eligible employees on September 30, 2004, for a total of 4,223 shares. The issuance of shares under this program has not been registered under the Securities Act of 1933, as amended (“1933 Act”) in reliance upon Securities and Exchange Commission releases, including Release No. 6188, dated February 1, 1980, stating that there is no sale of the shares in the 1933 Act sense to employees under this type of program.

Item 3. Defaults Upon Senior Securitie s

Not Applicable.

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Item 4. Submission of Matters to Vote of Security Holders

Not Applicable.

Item 5. Other Information

Not Applicable.

Item 6. Exhibits

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

Exhibit No.	Exhibit Description
10.1	Form of 2003 Non-Statutory Stock Option.
10.2	Form of 2003 Restricted Stock Award.
10.3	Form of 2003 Performance Shares Award.
10.4	Form of 2004 Restricted Stock Incentive Award.
10.5	Form of 2004 Performance Shares Award.
12	Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirement for the nine months ended September 30, 2004 and 2003.
12.1	Computation of Ratio of Earnings to Fixed Charges for the nine months ended September 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)).

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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: November 3, 2004	By:	/s/ Jim Kneale
		Jim Kneale Executive Vice President - Finance and Administration and Chief Financial Officer (Principal Financial Officer)

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