ONEOK INC /NEW/ - 10-Q Quarterly Report

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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 March 31, 2003

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 April 30, 2003, the Company had 95,315,952 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 Ended March 31, 2003 and 2002	3
	Consolidated Balance Sheets—March 31, 2003 and December 31, 2002	4-5
	Consolidated Statements of Cash Flows—Three Months Ended March 31, 2003 and 2002	6
	Consolidated Statement of Shareholders’ Equity and Comprehensive Income	7
	Notes to Consolidated Financial Statements	8-21
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22-38
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38-41
Item 4.	Controls and Procedures	41-42
Part II.	Other Information
Item 1.	Legal Proceedings	42
Item 2.	Changes in Securities and Use of Proceeds	42
Item 3.	Defaults Upon Senior Securities	42
Item 4.	Submission of Matters to a Vote of Security Holders	42
Item 5.	Other Information	42
Item 6.	Exhibits and Reports on Form 8-K	43-44
Signatures		45
Certifications		45-46

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

Part I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ONEOK, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

	Three Months Ended March 31,
	2003			2002
	(Unaudited)
	(Thousands of Dollars, except per share amounts)
Revenues
Operating revenues, excluding energy trading revenues	$	949,550		$	548,792
Energy trading revenues, net		135,671			71,715
Cost of sales		675,563			326,071

Net Revenues		409,658			294,436

Operating Expenses
Operations and maintenance		112,443			104,562
Depreciation, depletion, and amortization		40,427			34,100
General taxes		24,351			14,309

Total Operating Expenses		177,221			152,971

Operating Income		232,437			141,465

Other income		2,200			599
Other expense		(1,459	)		(1,319	)
Interest expense		28,577			26,182
Income taxes		78,994			42,870

Income from continuing operations		125,607			71,693
Discontinued operations, net of taxes (Note C)
Income from operations of discontinued component		2,342			905
Gain on sale of discontinued component		38,369			—
Cumulative effect of changes in accounting principle, net of tax (Note A)		(143,885	)		—

Net Income		22,433			72,598
Preferred stock dividends		15,166			9,275

Income Available for Common Stock	$	7,267		$	63,323

Earnings Per Share of Common Stock (Note M)
Basic:
Earnings per share from continuing operations	$	1.43		$	0.60
Earnings per share from operations of discontinued component	$	0.02		$	0.01
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	$	0.51		$	0.61

Diluted:
Earnings per share from continuing operations	$	1.20		$	0.59
Earnings per share from operations of discontinued component	$	0.02		$	0.01
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	$	0.28		$	0.60

Average Shares of Common Stock (Thousands)
Basic		83,733			100,070
Diluted		98,514			100,276

Dividends per share of Common Stock	$	0.17		$	0.16

See accompanying Notes to Consolidated Financial Statements.

ONEOK, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	March 31, 2003		December 31, 2002
	*(Unaudited)*
	*(Thousands of Dollars)*
Assets
Current Assets
Cash and cash equivalents	$	282,988	$	73,522
Trade accounts and notes receivable, net		1,256,552		773,017
Materials and supplies		32,324		16,949
Gas in storage		61,913		58,544
Unrecovered purchased gas costs		1,567		3,576
Assets from price risk management activities		253,853		655,974
Deposits		10,977		—
Other current assets		14,567		44,790
Assets of discontinued component		—		276

Total Current Assets		1,914,741		1,626,648

Property, Plant and Equipment
Production		148,474		144,174
Gathering and Processing		1,007,412		993,504
Transportation and Storage		692,229		689,150
Distribution		2,476,202		2,169,382
Marketing and Trading		125,843		124,512
Other		96,173		94,778

Total Property, Plant and Equipment		4,546,333		4,215,500
Accumulated depreciation, depletion, and amortization		1,229,124		1,200,451

Net Property, Plant and Equipment		3,317,209		3,015,049

Deferred Charges and Other Assets
Regulatory assets, net (Note E)		218,813		217,978
Goodwill		226,101		113,510
Assets from price risk management activities		103,766		351,660
Prepaid Pensions		127,380		125,426
Investments and other		82,116		55,526

Total Deferred Charges and Other Assets		758,176		864,100

Non-current Assets of Discontinued Component		—		225,061

Total Assets	$	5,990,126	$	5,730,858

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

	March 31, 2003			December 31, 2002
	(Unaudited)
	(Thousands of Dollars)
Liabilities and Shareholders’ Equity
Current Liabilities
Current maturities of long-term debt	$	6,334		$	6,334
Notes payable		—			265,500
Accounts payable		1,189,689			672,153
Accrued taxes		110,140			41,922
Accrued interest		30,101			29,202
Customers’ deposits		33,420			21,096
Liabilities from price risk management activities		259,658			427,599
Deferred income taxes		16,327			130,328
Other		148,452			125,129
Liabilities of discontinued component		—			1,445

Total Current Liabilities		1,794,121			1,720,708

Long-term Debt, excluding current maturities		1,897,025			1,511,118
Deferred Credits and Other Liabilities
Deferred income taxes		485,020			475,163
Liabilities from price risk management activities		105,254			300,085
Lease obligation		110,526			109,051
Other deferred credits		366,599			208,106

Total Deferred Credits and Other Liabilities		1,067,399			1,092,405

Non-current Liabilities of Discontinued Component		—			41,015

Total Liabilities		4,758,545			4,365,246

Commitments and Contingencies *(Note J)*
Shareholders’ Equity
Convertible preferred stock, $0.01 par value:
Series A authorized 20,000,000 shares; issued and outstanding 19,946,448 shares at December 31, 2002		—			199
Convertible preferred stock, $0.01 par value:
Series D authorized, issued and outstanding 21,815,386 shares at March 31, 2003		218			—
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 95,315,952 shares and outstanding 74,820,254 shares at March 31, 2003; issued 63,438,441 shares and outstanding 60,761,064 shares at December 31, 2002		953			634
Paid in capital (Note I)		1,124,954			903,918
Unearned compensation		(5,366	)		(2,716	)
Accumulated other comprehensive loss (Note G)		(11,255	)		(5,546	)
Retained earnings		456,581			507,836
Treasury stock at cost: 20,495,698 shares at March 31, 2003; and 2,677,377 shares at December 31, 2002		(334,504	)		(38,713	)

Total Shareholders’ Equity		1,231,581			1,365,612

Total Liabilities and Shareholders’ Equity	$	5,990,126		$	5,730,858

ONEOK, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months Ended March 31,
	2003			2002
	*(Unaudited)*
	*(Thousands of Dollars)*
Operating Activities
Income from continuing operations	$	125,607		$	71,693
Depreciation, depletion, and amortization		40,427			34,100
Gain on sale of assets		—			(813	)
(Income) loss from equity investments		(415	)		1,015
Deferred income taxes		44,592			78,101
Stock-based compensation expense		332			487
Allowance for doubtful accounts		4,530			3,576
Mark-to-market (income) loss		(11,841	)		13,690
Changes in assets and liabilities:
Accounts and notes receivable		(433,575	)		(45,622	)
Inventories		(3,313	)		44,022
Unrecovered purchased gas costs		2,009			54,540
Deposits		(10,977	)		32,073
Accounts payable and accrued liabilities		455,467			(12,428	)
Price risk management assets and liabilities		57,448			119,572
Other assets and liabilities		66,242			17,171

Cash Provided by Continuing Operations		336,533			411,177
Cash Provided by Discontinued Operations		4,705			9,594

Cash Provided by Operating Activities		341,238			420,771

Investing Activities
Changes in other investments, net		722			1,478
Acquisitions		(420,000	)		(30	)
Capital expenditures		(33,483	)		(54,597	)
Proceeds from sale of property		—			1,400

Cash Used in Investing Activities of Continued Operations		(452,761	)		(51,749	)
Cash Provided by (Used in) Investing Activities of Discontinued Operations		280,669			(6,253	)

Cash Used in Investing Activities		(172,092	)		(58,002	)

Financing Activities
Payments of notes payable, net		(265,500	)		(195,061	)
Change in bank overdraft		21,934			(27,859	)
Issuance of debt		402,500			—
Payment of debt issuance costs		(2,564	)		—
Payment of debt		(15,430	)		(588	)
Purchase of Series A Convertible Preferred Stock		(300,000	)		—
Issuance of common stock		218,521			—
Issuance of treasury stock, net		1,157			1,760
Dividends paid		(20,298	)		(18,545	)

Cash (Used In) Provided by Financing Activities		40,320			(240,293	)

Change in Cash and Cash Equivalents		209,466			122,476
Cash and Cash Equivalents at Beginning of Period		73,522			28,229

Cash and Cash Equivalents at End of Period	$	282,988		$	150,705

See accompanying Notes to Consolidated Financial Statements.

ONEOK, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME

	Common Stock Issued	Series A Convertible Preferred Stock			Series D Convertible Preferred Stock		Common Stock		Paid-in Capital
	(Unaudited)
	(Thousands of Dollars)
December 31, 2002	63,438,441	$	199		$	—	$	634	$	903,918
Net income	—		—			—		—		—
Other comprehensive income	—		—			—		—		—
Total comprehensive income
Re-issuance of treasury stock	—		—			—		—		47
Issuance of common stock
Common stock offering	13,800,000		—			—		138		227,893
Issuance costs of equity units	—		—			—		—		(9,728	)
Contract adjustment payment	—		—			—		—		(50,805	)
Repurchase of Series A Convertible Preferred Stock	18,077,511		(90	)		—		181		(91	)
Exchange of Series A Convertible Preferred Stock	—		(109	)		—		—		(308,466	)
Issuance of Series D Convertible Preferred Stock	—		—			218		—		361,747
Issuance of restricted stock	—		—			—		—		107
Amortization of restricted stock	—		—			—		—		—
Stock-based employee compensation expense	—		—			—		—		332
Convertible preferred stock dividends	—		—			—		—		—
Common stock dividends	—		—			—		—		—

March 31, 2003	95,315,952	$	—		$	218	$	953	$	1,124,954

	Unearned Compensation			Accumulated Other Comprehensive Loss			Retained Earnings			Treasury Stock			Total
	(Unaudited)
	(Thousands of Dollars)
December 31, 2002	$	(2,716	)	$	(5,546	)	$	507,836		$	(38,713	)	$	1,365,612
Net income		—			—			22,433			—			22,433
Other comprehensive income		—			(5,709	)		—			—			(5,709	)

Total comprehensive income														16,724

Re-issuance of treasury stock		—			—			—			1,110			1,157
Issuance of common stock
Common stock offering		—			—			—			—			228,031
Issuance costs of equity units		—			—			—			—			(9,728	)
Contract adjustment payment		—			—			—			—			(50,805	)
Repurchase of Series A Convertible Preferred Stock		—			—			—			(300,000	)		(300,000	)
Exchange of Series A Convertible Preferred Stock		—			—			—			—			(308,575	)
Issuance of Series D Convertible Preferred Stock		—			—			(53,390	)		—			308,575
Issuance of restricted stock		(3,206	)		—			—			3,099			—
Amortization of restricted stock		600			—			—			—			600
Stock-based employee compensation expense		—			—			—			—			332
Convertible preferred stock dividends		—			—			(7,971	)		—			(7,971	)
Common stock dividends		(44	)		—			(12,327	)		—			(12,371	)

March 31, 2003	$	(5,366	)	$	(11,255	)	$	456,581		$	(334,504	)	$	1,231,581

See accompanying Notes to the Consolidated Financial Statements.

ONEOK, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

A. Summary of Accounting Policies

Interim Reporting—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 for interim financial information. The interim 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 ended March 31, 2003, are not necessarily indicative of the results that may be expected for a twelve-month period. For further information, refer to the consolidated financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002.

Goodwill—On January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (Statement 142). Accordingly, the Company discontinued the amortization of goodwill effective January 1, 2002. In accordance with the provisions of Statement 142, the Company has completed its annual analysis of goodwill for impairment as of January 1, 2003 and 2002 and there was no impairment indicated. See Note F.

Asset Retirement Obligations—On January 1, 2003, the Company adopted Statement of Financial Accounting Standard No. 143, “Accounting for Asset Retirement Obligations” (Statement 143). Statement 143 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset.

Statement 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of the fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expenses. If the obligation is settled for other than the carrying amount of the liability, the Company will recognize a gain or loss on settlement.

All legal obligations for asset retirement obligations were identified and the fair value of these obligations was determined as of January 1, 2003. The obligations primarily relate to the 300-megawatt power plant and various processing plants, storage facilities and producing wells. As a result of the adoption of Statement 143, the Company recorded a long-term liability of approximately $16.3 million, an increase to property, plant and equipment, net of accumulated depreciation, of approximately $12.9 million and a cumulative effect charge of approximately $2.1 million, net of tax. The related depreciation and amortization expense is immaterial to the consolidated financial statements.

Common Stock Options and Awards—On January 1, 2003, the Company adopted the recognition and measurement principles of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (Statement 123) as amended. The Company has elected to begin expensing the fair value of all stock based compensation granted on or after January 1, 2003 under the prospective method allowed by Statement 123. The Company recorded approximately $202,000, net of tax, of stock-based employee compensation costs in the first quarter of 2003. Prior to January 1, 2003, the Company accounted for its stock-based compensation plans under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees”, and related interpretations. 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 123 to all options granted prior to January 1, 2003.

	Three Months Ended March 31,
	2003		2002
	(Thousands of Dollars, except per share amounts)
Net income, as reported	$	22,433	$	72,598
Deduct: Total stock-based employee compensation expense
determined under fair value based method for awards granted
prior to January 1, 2003, net of related tax effects		303		513

Pro forma net income	$	22,130	$	72,085

Earnings per share:
Basic—as reported	$	0.51	$	0.61
Basic—pro forma	$	0.50	$	0.60
Diluted—as reported	$	0.28	$	0.60
Diluted—pro forma	$	0.27	$	0.60

Use of Estimates—Certain amounts included in or affecting the Company’s financial statements and related disclosures must be estimated. For further information, refer to the Notes to Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002.

Reclassifications—Certain amounts in the consolidated financial statements have been reclassified to conform to the 2003 presentation.

Critical Accounting Policies

Energy Trading and Risk Management Activities—The Company engages in price risk management activities for both energy trading and non-trading purposes. Through 2002, the Company accounted for price risk management activities for its energy trading contracts in accordance with Emerging Issues Task Force Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10). EITF 98-10 required entities involved in energy trading activities to account for energy trading contracts using mark-to-market accounting. Forwards, swaps, options and energy transportation and storage contracts utilized for trading activities were reflected at fair value as assets and liabilities from price risk management activities under EITF 98-10.

In October 2002, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) rescinded EITF 98-10. As a result, energy related contracts that are not accounted for pursuant to Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133), as amended, are no longer carried at fair value but rather are accounted for as executory contracts and accounted for on an accrual basis. As a result of the rescission of this statement, the Task Force also agreed that energy trading inventories carried under storage agreements should no longer be carried at fair value but should be carried at the lower of cost or market. The Marketing and Trading segment’s gas in storage inventory at March 31, 2003 is carried on the balance sheet as gas in storage at the lower of cost or market.

The rescission was effective for fiscal periods beginning after December 31, 2002 and for all existing energy trading contracts and inventory as of October 25, 2002. Additionally, the rescission applied immediately to contracts entered into on or after October 25, 2002. Changes to the accounting for existing contracts as a result of the rescission of EITF 98-10 were reported as a cumulative effect of a change in accounting principle on January 1, 2003. This resulted in a gross cumulative non-cash loss, of $231.0 million, $141.8 million, net of tax, in the first quarter of 2003. All recoveries of the estimated value

associated with this change in accounting will be recognized in operating income in future periods based on actual settlement prices.

The fair values of the assets and liabilities recorded pursuant to EITF 98-10 and Statement 133 are affected by the actual timing of settlements related to these contracts and current period changes resulting primarily from newly originated transactions and the impact of price movements. Changes in fair value are recognized in revenues, on a net basis, in the consolidated statements of income. Market prices used to determine fair value of these assets and liabilities reflects management’s best estimate considering various factors, including closing exchange and over-the-counter quotations, time value and volatility underlying the commitments. Market prices were adjusted for the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions.

During the third quarter of 2002, the Company adopted the applicable provisions of Emerging Issues Task Force Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3). EITF 02-3 provides that all mark-to-market gains and losses on energy trading contracts be presented on a net basis (energy contract sales less energy contract costs) in the income statement without regard to the settlement provisions of the contract. The FASB staff also indicated the dealer profits on unrealized gains or losses at contract inception were not appropriate unless evidenced by quoted prices or other market transactions. Prior to the third quarter of 2002, energy trading revenues and costs were presented on a gross basis. The financial results of all energy trading contracts have been restated to reflect the adoption of EITF 02-3. Energy trading revenues include natural gas, reservation fees, crude oil, natural gas liquids, and basis. Basis is the differential that exists between two geographic locations.

Regulation—The Company’s intrastate transmission pipelines and distribution operations are subject to the rate regulation and accounting requirements of the Oklahoma Corporation Commission (OCC), Kansas Corporation Commission (KCC), Texas Railroad Commission (TRC) and various municipalities in Texas. Certain other transportation activities of the Company are subject to regulation by the Federal Energy Regulatory Commission (FERC). Oklahoma Natural Gas (ONG), Kansas Gas Service (KGS) and Texas Gas Service (TGS), all included in the Distribution segment, and the Company’s intrastate transmission pipelines 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). Allocation of costs and revenues to accounting periods for ratemaking and regulatory purposes may differ from allocations generally applied by non-regulated operations. Allocations of costs and revenues made by the Company to meet regulatory accounting requirements are considered to be in accordance with generally accepted accounting principles for regulated utilities.

During the ratemaking process, regulatory commissions 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. This causes certain expenses to be deferred as regulatory assets and amortized to expense as they are recovered through rates. Total regulatory assets resulting from this deferral process were approximately $218.8 million and $218.0 million at March 31, 2003 and December 31, 2002, respectively. Should unbundling of services occur, certain of these assets may no longer meet the criteria for accounting for these assets in accordance with Statement 71 and, accordingly, a write-off of regulatory assets and stranded costs may be required. However, the Company does not anticipate that these costs, if any, will be significant. See Note E.

In January 2003, KGS filed a rate case with the KCC to increase annual rates approximately $76 million. The KCC has 240 days to issue a final order in the rate case. If approved, the new rates will be effective in the third quarter of 2003. Until a final order is received, KGS will continue to operate under the current rate schedules. The weather normalization rider was included in the rate case filing with the KCC in January 2003.

Impairment of Long-Lived Assets—The Company recognizes the impairment of a long-lived asset when indicators of impairment are present and the undiscounted cash flow is not sufficient to recover the carrying amount of these assets. The impairment loss is measured by comparing the fair value of the asset to its carrying amount. Fair values are based on discounted future cash flows or information provided by sales and purchases of similar assets.

B. Acquisitions

On January 3, 2003, the Company purchased the Texas distribution and other assets of Southern Union Company. The results of these assets have been included in the consolidated financial statements since that date. The Company paid approximately $420 million for these assets, which is subject to adjustment for working capital. The primary assets acquired were the gas distribution operations, which serve approximately 535,000 customers in cities located throughout Texas, including the major cities of El Paso and Austin, as well as the cities of Port Arthur, Galveston, Brownsville and others. Over 90 percent of the customers are residential. The acquisition includes a 125-mile natural gas transmission system, as well as other energy related domestic assets involved in gas marketing, retail sales of propane and distribution of propane. The purchase also includes natural gas distribution investments in Mexico. The distribution assets are operated under the name Texas Gas Service Company (TGS), a division of ONEOK, Inc. The assets and assumed liabilities have been recorded at preliminary fair values. As additional information is obtained, there could be adjustments to the purchase price allocation.

The addition of the Texas distribution system fits in well with the Company’s concentration in the mid-continent region of the United States, adding to its distribution systems in Oklahoma and Kansas. The acquisition also adds a stable revenue source as a majority of the margins are protected from the impact of weather swings due to weather normalization clauses and rate designs heavily weighted toward a fixed customer charge. The regulatory environment in which municipalities set rates diversifies regulatory risk. Other assets acquired with the acquisition complement and enhance the Company’s existing operations in its other business segments.

C. Discontinued Operations

In January 2003, the Company sold approximately 70 percent of the natural gas and oil producing properties of its Production segment (the component) for an adjusted cash price of $294 million. The component is accounted for as a discontinued operation in accordance with Statement of Financial Accounting Standards No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144). Accordingly, amounts in the financial statements and related notes for all periods shown reflect discontinued operations accounting. The Company’s decision to sell the component was based on strategic evaluations of the Production segment goals and favorable market conditions. The Company recognized a pretax gain on the sale of the discontinued component of approximately $59 million in the first quarter of 2003. The gain reflects the cash received, less adjustments, selling expenses and the net book value of assets sold.

The following table discloses the amount of revenues, costs and income taxes reported in discontinued operations for the periods indicated.

	Three Months Ended March 31,
	2003		2002
	(Thousands of Dollars)
Natural gas sales	$	6,036	$	12,024
Oil sales		1,705		1,019
Other revenues		—		93

Net revenues		7,741		13,136
Operating costs		1,985		5,517
Depreciation, depletion, and amortization		1,937		6,136

Operating income	$	3,819	$	1,483

Income taxes	$	1,477	$	578

Income from discontinued component	$	2,342	$	905

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

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

	December 31, 2002
	(Thousands of Dollars)
Assets:
Trade accounts and notes receivable, net	$	95
Materials and supplies		181

Total current assets of discontinued component		276

Property, plant, and equipment		371,534
Accumulated depreciation, depletion, and amortization		148,798

Net property, plant, and equipment		222,736

Other		2,325

Total non-current assets of discontinued component		225,061

Total assets of discontinued component	$	225,337

Liabilities:
Accounts payable	$	1,445

Total current liabilities of discontinued component		1,445

Deferred income taxes		40,285
Other		730

Total non-current liabilities of discontinued component		41,015

Total liabilities of discontinued component	$	42,460

D. Derivative Instruments and Hedging Activities

The Company adheres to the provisions of Statement 133. Under Statement 133, entities are required to record all derivative instruments in the balance sheet 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 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. If the hedged exposure is a fair value exposure, 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. If the hedged exposure is a cash flow exposure, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income and subsequently reclassified into earnings when the forecasted transaction affects earnings. Any

amounts excluded from the assessment of hedge effectiveness, as well as the ineffective portion of the hedge, are reported in earnings immediately. At March 31, 2003, the Company reported $3.5 million in cost of sales related to the ineffective portion of hedges.

The Company periodically enters into derivative instruments to hedge the Production segment’s exposure to changes in the price of natural gas. The Company realized losses in earnings of approximately $2.2 million for the three months ended March 31, 2003 related to production hedges. The realized losses were reclassified from accumulated other comprehensive income resulting from the settlement of contracts when the natural gas was sold. The losses are reported in operating revenues. Accumulated other comprehensive loss for the three months ended March 31, 2003 includes losses of approximately $0.7 million, net of tax, related to a cash flow exposure for production hedges and will be realized in earnings within the next 21 months. Accumulated other comprehensive loss for the three months ended March 31, 2003, also includes losses of approximately $4.4 million, net of tax, related to cash flow exposure for marketing and trading hedges entered into during the first quarter of 2003 that will be realized within the next 22 months.

The Company is subject to the risk of fluctuation 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 2003, the Company terminated $50 million in swaps that had a fair value of approximately zero. Currently, $550 million of fixed rate debt has been swapped to a floating rate based on the three-month or six-month London InterBank Offered Rate (LIBOR) at the respective reset date and the swaps have been designated as fair value hedges. In January 2003, interest rate locks were put in place locking the rates through the first quarter of 2004. At March 31, 2003, price risk management assets includes $76.6 million to recognize the fair value of the Company’s derivatives that are designated as fair value hedging instruments. Long-term debt includes approximately $76.9 million to recognize the change in fair value of the related hedged liability. The Company also increased interest expense by $1.1 million for the three months ended March 31, 2003 to recognize the ineffectiveness of these hedges.

E. Regulatory Assets

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

	March 31, 2003		December 31, 2002
	(Thousands of dollars)
Recoupable take-or-pay	$	68,413	$	69,812
Pension costs		12,116		6,942
Postretirement costs other than pension		55,906		55,901
Transition costs		20,855		21,005
Reacquired debt costs		21,306		21,512
Income taxes		24,302		25,142
Weather normalization		—		3,746
Line replacements		5,072		5,072
Other		10,843		8,846

Regulatory assets, net	$	218,813	$	217,978

F. Goodwill

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

	Balance December 31, 2002		Additions			Balance March 31, 2003
	(Thousands of Dollars)
Marketing and Trading	$	5,616	$	4,384		$	10,000
Gathering and Processing		34,343		(702	)		33,641
Transportation and Storage		22,183		2,100			24,283
Distribution		51,368		106,809			158,177

Total consolidated	$	113,510	$	112,591		$	226,101


	Balance December 31, 2001		Additions			Balance March 31, 2002
	(Thousands of Dollars)
Marketing and Trading	$	5,616	$	—		$	5,616
Gathering and Processing		34,343		—			34,343
Transportation and Storage		22,183		—			22,183
Distribution		51,368		—			51,368

Total consolidated	$	113,510	$	—		$	113,510

The additions to goodwill in the first quarter of 2003 are a result of the preliminary purchase price allocation of the Texas assets acquired in January 2003. See Note B.

G. Comprehensive Income

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

	Three Months Ended March 31,
	2003						2002
	(Thousands of Dollars)
Net Income				$	22,433					$	72,598
Other comprehensive income:
Unrealized losses on derivative instruments	$	(11,446	)				$	(800	)
Unrealized holding gains (losses) arising during the period		(76	)					14,042
Realized (gains) losses in net income		2,214						(734	)

Other comprehensive income (loss) before taxes		(9,308	)					12,508
Income tax benefit (expense) on other comprehensive income		3,599						(4,577	)

Other comprehensive income (loss)				$	(5,709	)				$	7,931

Comprehensive income				$	16,724					$	80,529

Accumulated other comprehensive loss reflected in the consolidated balance sheet of $11.3 million at March 31, 2003, includes unrealized gains and losses on derivative instruments and minimum pension liability adjustments.

H. Capital Stock

On January 9, 2003, the Company entered into an agreement with Westar Energy, Inc. and its wholly owned subsidiary, Westar Industries, Inc. (collectively, “Westar”), to repurchase a portion of the shares of the Company’s Series A Convertible Preferred Stock (Series A) held by Westar and to exchange Westar’s remaining shares of Series A for newly-created shares of ONEOK’s $0.925 Series D Non-Cumulative Convertible Preferred Stock (Series D). The Series A shares were convertible into two shares of common stock, reflecting the Company’s two-for-one stock split in 2001, and the Series D shares are convertible into one share of common stock. Some of the differences between the Series D and the Series A are (a) the Series D has a fixed quarterly cash dividend of 23.125 cents per share, (b) the Series D is redeemable by ONEOK at any time after August 1, 2006, at a redemption price of $20, in the event that the closing price of ONEOK common stock exceeds, at any time prior to the date the notice is given, $25 for 30 consecutive trading days, (c) each share of Series D is convertible into one share of ONEOK common stock, and (d) Westar may not convert any shares of Series D held by it unless the annual per share dividend on ONEOK common stock for the previous year is greater than 92.5 cents and such conversion would not subject ONEOK to the Public Utility Holding Company Act of 1935. Also, in connection with that transaction, a new rights agreement, a new shareholder agreement and a new registration rights agreement between ONEOK and Westar became effective. The shareholder agreement restricts Westar from selling five percent or more of ONEOK’s outstanding Series D and common stock (assuming conversion of all shares of Series D to be transferred) to any one person or group. The agreement also restricts Westar from selling up to five percent of ONEOK’s outstanding Series D and common stock (assuming conversion of all shares of Series D to be transferred) to any one person or group who already owns more than five percent of ONEOK’s outstanding common stock (assuming conversion of all shares of Series D to be transferred). The KCC approved the Company’s agreement with Westar on January 17, 2003. On February 5, 2003, the Company consummated the agreement by purchasing $300 million of its Series A from Westar. The Company exchanged Westar’s remaining 10.9 million Series A shares for approximately 21.8 million shares of the Company’s newly-created Series D. Upon the cash redemption of the Series A shares, the shares were converted to common stock in accordance with the terms of the Series A shares and the historical shareholder agreement with Westar. Accordingly, the redemption is reflected as an increase to common treasury stock. The Series D exchanged for the Series A was recorded at fair value and the premium over the previous carrying value of the Series A is reflected as a decrease in retained earnings. The Company has registered for resale all of the shares of its common stock held by Westar, as well as all the shares of its Series D issued to Westar and all of the shares of its common stock issuable upon conversion of the Series D. As a result of this transaction and the Company’s recently completed stock offering, discussed below, Westar’s equity interest in the Company has been reduced from approximately 44.4 percent to approximately 27.4 percent on a fully diluted basis.

On January 28, 2003, the Company issued 12 million shares of common stock at the public offering price of $17.19 per share, resulting in net proceeds to the Company, after underwriting discounts and commissions, of $16.524 per share, or $198.3 million in the aggregate. The Company granted the underwriters a 30-day over-allotment option to purchase up to an additional 1.8 million shares of the Company’s common stock at the same price, which was exercised on February 7, 2003, resulting in additional net proceeds to the Company of $29.7 million.

Also on January 28, 2003, the Company issued 14 million equity units at a public offering price of $25 per unit, resulting in net proceeds to the Company, after underwriting discounts and commissions, of $24.25 per equity unit, or $339.5 million in the aggregate. Each equity unit consists of a stock purchase contract for the purchase of shares of the Company’s common stock and, initially, a senior note due February 16, 2008, issued pursuant to the Company’s existing Indenture with SunTrust Bank, as trustee. The equity units carry a total annual coupon rate of 8.5 percent (4.0 percent annual face amount of the senior notes plus 4.5 percent annual contract adjustment payments). Each stock purchase contract issued as a part of the equity units carries a maximum conversion premium of up to 20 percent over the $17.19 closing price of the Company’s common stock on January 22, 2003. The Company granted the underwriters a 13-day over-allotment option to purchase up to an additional 2.1 million additional equity units at the same price, which was exercised on January 31, 2003, resulting in additional net proceeds to the Company of $50.9 million.

The present value of the equity units contract adjustment payments was initially charged to shareholders’ equity, with an offsetting credit to liabilities. This liability is accreted over three years by interest charges to the income statement.

Before the issuance of the Company’s common stock upon settlement of the purchase contracts, the purchase contracts will be reflected in the Company’s diluted earning per share calculations using the treasury stock method. The FASB has issued an exposure draft entitled “Accounting for Financial Instruments with Characteristics of Liabilities, Equity or Both.” Under the proposed Statement, some financial instruments indexed to an issuer’s own stock that is currently recorded in the stockholders’ equity section of the issuer’s balance sheet would be accounted for as a derivative instrument under the provisions of Statement 133. The proposed Statement would be effective for fiscal years beginning after June 15, 2002. However, due to unresolved issues raised during the Boards redeliberations, the FASB has communicated its plans to issue a limited-scope statement in early 2003 that will address certain, but not all, financial instruments that include forward purchase contracts. The FASB’s ultimate conclusions with respect to the accounting for financial instruments with characteristics of liabilities, equity, or both could result in the purchase contracts being accounted for as derivative instruments, with the contracts recorded at fair value and changes in fair value recorded in earnings. The FASB could also re-examine the method in which the equity units are included in an issuer’s diluted earnings per share calculation. The EITF of the FASB is also considering an issue related to the accounting for certain securities and financial instruments, including securities such as the equity units. At this time, the ultimate outcome of the deliberations referred to above, the timing of the issuance of a FASB Standard or an EITF Consensus, and their effect on the financial statements is uncertain.

I. Paid in Capital

Paid in capital is $763.2 million and $339.7 million for common stock at March 31, 2003, and December 31, 2002, respectively. Paid in capital for convertible preferred stock was $361.7 million and $564.2 million at March 31, 2003, and December 31, 2002, respectively.

J. Commitments and Contingencies

Environmental—The Company has 12 manufactured gas sites located in Kansas, which may contain potentially harmful materials that are classified as hazardous material. Hazardous materials 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 future work at these sites. The terms of the consent agreement allow the Company to investigate these sites and set remediation priorities based upon the results of the investigations and risk analysis. Remedial investigation has commenced on four sites. However, a comprehensive study is not complete and the results to date do not provide a sufficient basis for a reasonable estimation of the total liability. The liability accrued is reflective of an estimate of the total cost of remedial investigation and feasibility study. Through March 31, 2003, the costs of the investigations and risk analysis related to these manufactured gas sites have been immaterial. The site situations are not common and the Company has no previous experience with similar remediation efforts. The information currently available estimates the cost of remediation to range from $100,000 to $10 million per site based on a limited comparison of costs incurred by others to remediate comparable sites. As such, the information provides an insufficient basis to reasonably estimate a minimum range of the Company’s liability. These estimates do not give effect to potential insurance recoveries, recoveries through rates or from unaffiliated parties. At this time, the Company is not recovering any environmental amounts in rates. The KCC has permitted others to recover remediation costs through rates. It should be noted that additional information and testing could result in costs significantly below or in excess of the amounts estimated above. To the extent that such remediation costs are not recovered, the costs 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.

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 an $180,000 civil

penalty against the Company, based on alleged violations of several KDHE regulations. A status conference was held on April 10, 2003, and another one has been scheduled for June 4, 2003, regarding progress toward reaching an agreed to consent order. The Company believes there are no long-term environmental effects from the Yaggy storage facility.

Two separate class action lawsuits have been filed against the Company in connection with the natural gas explosions and eruptions of natural gas geysers that occurred at the Yaggy facility. These class action lawsuits were filed on the grounds that the eruptions and explosions related to natural gas that allegedly escaped from the Yaggy storage facility. On January 17, 2003, the two-year statute of limitations for known personal injury claims and all non-class members expired. In addition to the two class action matters, sixteen other cases have been filed against the Company or its subsidiaries seeking recovery for various claims, including property damage, personal injury, loss of business and, in some instances, punitive damages. Although no assurances can be given, the Company believes that the ultimate resolution of these matters will not have a material adverse effect on its financial position or results of operations. The Company is vigorously defending itself against all claims in these cases and its insurance coverages would provide coverage for any material liability associated with these cases.

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

K. Segments

Management has divided the Company’s operations into the following six reportable segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment: (1) the Production segment develops and produces natural gas and oil; (2) the Gathering and Processing segment gathers and processes natural gas and fractionates, stores and markets natural gas liquids; (3) the Transportation and Storage segment transports and stores natural gas for others and buys and sells natural gas; (4) the Distribution segment distributes natural gas to residential, commercial and industrial customers, leases pipeline capacity to others and provides transportation services for end-use customers; (5) the Marketing and Trading segment markets natural gas to wholesale and retail customers and markets electricity, NGLs and crude oil to wholesale customers; and (6) the Other segment primarily operates and leases the Company’s headquarters building and a related parking facility.

In July 2002, the Company completed a transaction to transfer certain transmission assets in Kansas from the Transportation and Storage segment to the Distribution segment. All historical financial and statistical information has been adjusted to reflect the transfer.

The accounting policies of the 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, 2002, except for those changes discussed in Note A. Intersegment gross sales are recorded on the same basis as sales to unaffiliated customers. Intersegment sales for the Marketing and Trading segment were $197.5 million and $138.9 million for the three months ended March 31, 2003 and 2002, respectively. Energy trading contracts included in the following table are reported net of related costs. Corporate overhead costs relating to the reportable segments are allocated for the purpose of calculating operating income. The Company’s equity method investments do not represent operating segments of the Company. The Company has no single external customer from which it receives ten percent or more of its consolidated gross revenues.

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

	Regulated				Non-Regulated
Three Months Ended March 31, 2003	Transportation and Storage		Distribution		Marketing and Trading		Gathering and Processing		Production		Other and Eliminations			Total
Sales to unaffiliated customers	$	20,175	$	699,038	$	12,534	$	402,066	$	12,512	$	(196,775	)	$	949,550
Energy trading contracts, net		—		—		135,671		—		—		—		$	135,671
Intersegment sales		18,375		—		—		130,523		133		(149,031	)	$	—

Total Revenues	$	38,550	$	699,038	$	148,205	$	532,589	$	12,645	$	(345,806	)	$	1,085,221

Net revenues	$	30,145	$	182,044	$	137,501	$	46,327	$	12,645	$	996		$	409,658
Operating costs	$	10,866	$	83,127	$	9,103	$	31,263	$	3,610	$	(1,175	)	$	136,794
Depreciation, depletion and amortization	$	4,154	$	23,888	$	1,462	$	7,201	$	3,358	$	364		$	40,427
Operating income	$	15,125	$	75,029	$	126,936	$	7,863	$	5,677	$	1,807		$	232,437
Income from operations of discontinued component	$	—	$	—	$	—	$	—	$	2,342	$	—		$	2,342
Income from equity investments	$	415	$	—	$	—	$	—	$	—	$	—		$	415
Total assets	$	816,124	$	2,416,724	$	1,569,400	$	1,350,306	$	141,060	$	(303,488	)	$	5,990,126
Capital expenditures	$	984	$	24,966	$	83	$	2,472	$	2,948	$	2,030		$	33,483


	Regulated				Non-Regulated
Three Months Ended March 31, 2002	Transportation and Storage		Distribution		Marketing and Trading		Gathering and Processing		Production		Other and Eliminations			Total
Sales to unaffiliated customers	$	19,129	$	497,985	$	8,754	$	157,042	$	6,084	$	(140,202	)	$	548,792
Energy trading contracts, net		—		—		71,715		—		—		—		$	71,715
Intersegment sales		26,158		1,144		—		58,553		437		(86,292	)	$	—

Total Revenues	$	45,287	$	499,129	$	80,469	$	215,595	$	6,521	$	(226,494	)	$	620,507

Net revenues	$	32,816	$	141,911	$	71,909	$	41,323	$	6,521	$	(44	)	$	294,436
Operating costs	$	12,130	$	64,717	$	8,165	$	32,070	$	1,778	$	11		$	118,871
Depreciation, depletion and amortization	$	4,274	$	17,249	$	1,183	$	7,970	$	3,038	$	386		$	34,100
Operating income	$	16,412	$	59,945	$	62,561	$	1,283	$	1,705	$	(441	)	$	141,465
Income from operations of discontinued component	$	—	$	—	$	—	$	—	$	905	$	—		$	905
Income from equity investments	$	438	$	—	$	—	$	—	$	—	$	(1,453	)	$	(1,015	)
Total assets	$	741,460	$	1,868,814	$	1,023,672	$	1,365,308	$	315,512	$	212,345		$	5,527,111
Capital expenditures (continuing operations)	$	14,541	$	21,339	$	138	$	10,808	$	5,369	$	2,402		$	54,597
Capital expenditures (discontinued component)	$	—	$	—	$	—	$	—	$	6,253	$	—		$	6,253

L. Supplemental Cash Flow Information

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

	Three Months Ended March 31,
	2003			2002
	(Thousands of Dollars)
Cash paid (received) during the period
Interest (including amounts capitalized)	$	27,847		$	32,390
Income taxes received	$	(4,528	)	$	(14,369	)
Income tax refund receivable	$	—		$	83,661
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 on restricted stock	$	44		$	56
Treasury stock transferred to compensation plans	$	247		$	25
Issuance of restricted stock, net	$	3,206		$	2,658

	Three Months Ended March 31,
	2003			2002
	(Thousands of Dollars)
Acquisitions
Property, plant and equipment	$	290,000		$	30
Current assets		70,117			—
Current liabilities		(76,132	)		—
Regulatory assets and goodwill		120,009			—
Other assets		2,871			—
Lease obligation		(4,715	)		—
Deferred credits		(37,399	)		—
Deferred income taxes		55,249			—

Cash paid for acquisitions	$	420,000		$	30

M. Earnings Per Share Information

Through February 5, 2003, the Company computed its earnings per common share (EPS) in accordance with a pronouncement of the Financial Accounting Standards Board’s Staff at the Emerging Issues Task Force meeting in April 2001, codified as EITF Topic No. D-95 (Topic D-95). In accordance with Topic D-95, the dilutive effect of the Company’s Series A Convertible Preferred Stock is considered in the computation of basic EPS utilizing the “if-converted” method. Under the Company’s “if-converted” method, the dilutive effect of the Company’s Series A Convertible Preferred Stock on EPS cannot be less than the amount that would result from the application of the “two-class” method of computing EPS. The “two-class” method is an earnings allocation formula that determines EPS for the Company’s common stock and its participating Series A Convertible Preferred Stock according to dividends declared and participating rights in the undistributed earnings. The Company’s Series A Convertible Preferred Stock was a participating instrument with the Company’s common stock with respect to the payment of dividends. For the three months ended March 31, 2002, and the period from January 1, 2003 to February 5, 2003, the “two-class” method resulted in additional dilution. Accordingly, EPS for this period reflects this further dilution. As a result of the Company’s repurchase and exchange of its Series A Convertible Preferred Stock in February 2003, the Company no longer applied the provisions of Topic D-95 to its EPS computations beginning in February 2003.

	Three Months Ended March 31, 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		84,267	74,163	$	1.14

Basic EPS from continuing operations				$	1.43

Income from continuing operations available for Series D Convertible Preferred Stock dividends	$	122,580	83,733

Effect of other dilutive securities:
Options and other dilutive securities		—	480
Series D Convertible Preferred Stock dividends		3,027	14,301

Income from continuing operations	$	125,607	98,514	$	1.28

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

Diluted EPS from continuing operations				$	1.20


	Three Months Ended March 31, 2002
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations available for common stock	$	62,418	60,178
Convertible preferred stock		9,275	39,892

Income from continuing operations available for common stock and assumed conversion of preferred stock		71,693	100,070	$	0.72

Further dilution from applying the “two-class” method					(0.12	)

Basic EPS from continuing operations				$	0.60

Effect of other dilutive securities
Options and other dilutive securities		—	206

Diluted EPS from continuing operations
Income from continuing operations available for common stock and assumed exercise of stock options	$	71,693	100,276	$	0.71

Further dilution from applying the “two-class” method					(0.12	)

Diluted EPS from continuing operations				$	0.59

There were 284,799 and 240,855 option shares excluded from the calculation of diluted EPS for the three months ended March 31, 2003 and 2002, respectively, since their inclusion would be antidilutive for each period.

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, is considered a preferred dividend. The premium recorded on the repurchase and exchange of the Series A was approximately $44.2 million and $53.4 million, respectively, for a total premium of $97.6 million. Since the adoption of Topic D-95, the Company has recognized additional dilution of approximately $94.5 million through the application of the “two-class” method. This additional dilution offsets the total premium recorded, resulting in a net premium of $3.1 million, which is reflected as a dividend on Series A Convertible Preferred Stock in the above EPS calculation for the three months ended March 31, 2003.

N. Debt Covenant Compliance

The Company’s Revolving Credit Facility has customary covenants that relate to liens, investments, fundamental changes in the business, the restriction of certain payments, changes in the nature of the business, transactions with affiliates, burdensome agreements, the use of proceeds, and a limit on the Company’s debt to capital ratio. Other debt agreements have negative covenants that relate to liens and sale/leaseback transactions. At March 31, 2003, the Company was in compliance with all covenants.

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

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 the anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in various circumstances. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of operations and other statements contained or incorporated in this Form 10-Q identified by words such as “anticipate,” “estimate,” “expect,” “intend,” “believe,” “projection” or “goal.”

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

•

risks associated with any reduction in our credit ratings;

•

the effects of weather and other natural phenomena on sales and prices;

•

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

•

the capital intensive nature of our business;

•

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

•

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

•

the profitability of assets or businesses acquired by us;

•

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

•

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

•

the uncertainty of gas and oil reserve estimates;

•

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, or changes in, hostilities or changes in the political dynamics in the Middle East or elsewhere;

•

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

•

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

•

the results of administrative proceedings and litigation involving the Oklahoma Corporation Commission (OCC), Kansas Corporation Commission (KCC), Texas regulatory authorities or any other local, state or federal regulatory body;

•

our ability to access capital and competitive rates on terms acceptable to us;

•

actions taken by Westar or its affiliates with respect to its investment in ONEOK, including, without limitation, the effect of a sale of our shares of common stock and preferred stock beneficially owned by Westar;

•

the risk of a significant slowdown in growth or 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 the September 11, 2001, or possible future terrorists attacks or war; and

•

the other risks and other factors listed in the reports we have filed and may file from time to time with the SEC, 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.

Critical Accounting Policies and Estimates

Energy Trading and Risk Management Activities— We engage in price risk management activities for both energy trading and non-trading purposes. Through 2002, we accounted for price risk management activities for our energy trading contracts in accordance with Emerging Issues Task Force Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10). EITF 98-10 required entities involved in energy trading activities to account for energy trading contracts using mark-to-market accounting. Forwards, swaps, options and energy transportation and storage contracts utilized for trading activities were reflected at fair value as assets and liabilities from price risk management activities under EITF 98-10.

During the third quarter of 2002, we adopted the applicable provisions of Emerging Issues Task Force Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3). EITF 02-3 provides that all mark-to-market gains and losses on energy trading contracts be presented on a net basis (energy contract sales less energy contract costs) in the income statement without regard to the settlement provisions of the contract. The FASB staff also indicated the dealer profits on unrealized gains or losses at contract inception were not appropriate unless evidenced by quoted prices or other market transactions. Prior to the third quarter of 2002, energy trading revenues and costs were presented on a gross basis. The financial results of all energy trading contracts have been restated to reflect the adoption of EITF 02-3. Energy trading revenues include natural gas, reservation fees, crude oil, natural gas liquids, and basis. Basis is the differential that exists between two geographic locations.

Regulation—Our intrastate transmission pipelines and distribution operations are subject to the rate regulation and accounting requirements of the OCC, KCC, Texas Railroad Commission (TRC) and various municipalities in Texas. Certain other of our transportation activities are subject to regulation by the Federal Energy Regulatory Commission (FERC). Allocation of costs and revenues to accounting periods for ratemaking and regulatory purposes may differ from allocations generally applied by non-regulated operations. Such allocations of costs and revenues made to meet regulatory accounting requirements are considered to be in accordance with generally accepted accounting principles for regulated utilities.

Impairment of Long-Lived Assets—We recognize the impairment of a long-lived asset when indicators of impairment are present and the undiscounted cash flow is not sufficient to recover the carrying amount of these assets. The impairment loss is measured by comparing the fair value of the asset to its carrying amount. Fair values are based on discounted future cash flows or information provided by sales and purchases of similar assets.

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

Results of Operations

Consolidated Operations

We are a diversified energy company whose objective is to maximize value for shareholders by vertically integrating our business operations from the wellhead to the burner tip. This strategy has led us to focus on acquiring assets that provide synergistic trading and marketing opportunities along the natural gas energy chain. Products and services are provided to our customers through the following segments:

•

Production

•

Gathering and Processing

•

Transportation and Storage

•

Distribution

•

Marketing and Trading

•

Other

In January 2003, we closed the sale of some of the natural gas and oil producing properties of our production segment to Chesapeake Energy Corporation for a cash sales price of $294 million including

adjustments. Pursuant to the sale, we sold natural gas and oil reserves in Oklahoma, Kansas and Texas. The sale included approximately 1,900 wells, 482 of which were operated by us. The sale is accounted for as a discontinued operation. Accordingly, the statistical and financial information related to the properties sold has been restated as a discontinued component. We recorded a pre-tax gain on the sale of the discontinued component of approximately $59 million in the first quarter of 2003.

On January 28, 2003, we issued 12 million shares of common stock at the public offering price of $17.19 per share, resulting in net proceeds, after underwriting discounts and commissions, of $16.524 per share, or $198.3 million in the aggregate. We granted the underwriters a 30-day over-allotment option to purchase up to an additional 1.8 million shares of our common stock at the same price, which was exercised on February 7, 2003, resulting in additional net proceeds of $29.7 million.

Also, on January 28, 2003, we issued 14 million equity units at a public offering price of $25 per unit, resulting in net proceeds, after underwriting discounts and commissions, of $24.25 per equity unit, or $339.5 million in the aggregate. 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 equity units carry a total annual coupon rate of 8.5 percent (4.0 percent annual face amount of the senior notes plus 4.5 percent annual contract adjustment payments). Each stock purchase contract issued as a part of the equity units carries a maximum conversion premium of up to 20 percent over the $17.19 closing price of our common stock on January 22, 2003. We granted the underwriters a 13-day over-allotment option to purchase up to an additional 2.1 million additional equity units at the same price, which was exercised on January 31, 2003, resulting in additional net proceeds of $50.9 million.

On January 9, 2003, we entered into an agreement with Westar Energy, Inc. and its wholly owned subsidiary, Westar Industries, Inc. (collectively, “Westar”), to repurchase a portion of the shares of our Series A Convertible Preferred Stock (Series A) held by Westar and to exchange Westar’s remaining shares of Series A for newly-created shares of our $0.925 Series D Non-Cumulative Convertible Preferred Stock (Series D). The Series A shares were convertible into two shares of common stock, reflecting our two-for-one stock split in 2001, and the Series D shares are convertible into one share of common stock. On February 5, 2003, we consummated the agreement by purchasing $300 million (approximately 18.1 million shares of common stock equivalents) of our Series A from Westar. We exchanged Westar’s remaining 10.9 million Series A shares for approximately 21.8 million shares of our newly-created Series D. Also, in connection with that transaction, a new rights agreement, a new shareholder agreement and a new registration rights agreement between ONEOK and Westar became effective. We have registered for resale all of the shares of our common stock held by Westar, as well as all the shares of our Series D issued to Westar and all of the shares of our common stock issuable upon conversion of the Series D. As a result of this transaction and our recently completed stock offering, Westar’s equity interest in ONEOK has been reduced from approximately 44.4 percent to approximately 27.4 percent on a fully diluted basis.

On January 3, 2003, we closed the purchase of the gas distribution and other assets of Southern Union for a cash purchase price of approximately $420 million, plus working capital adjustments. The assets acquired include the third largest gas distribution business in Texas, with operations that serve approximately 535,000 customers, over 90 percent of which are residential. The distribution assets are operated under the name of Texas Gas Service (TGS).

During the third quarter of 2002, we adopted EITF 02-3. EITF 02-3 provides that all mark-to-market gains and losses on energy trading contracts be presented on a net basis (energy contract sales less energy contract costs) in the income statement without regard to the settlement provisions of the contract. The financial results of all energy trading contracts have been restated to reflect the adoption of EITF 02-3 for all periods presented.

In October 2002, the EITF of the FASB rescinded EITF 98-10. As a result, energy related contracts that are not accounted for pursuant to Statement 133, will no longer be carried at fair value but rather will be accounted for as executory contracts and accounted for on an accrual basis. As a result of the rescission of this statement, the Task Force also agreed that energy trading inventories carried under storage agreements

should no longer be carried at fair value but should be carried at the lower of cost or market. Changes to the accounting for existing contracts as a result of the rescission of EITF 98-10 have been reported as a cumulative effect of a change in accounting principle on January 1, 2003. This resulted in a cumulative effect loss of $141.8 million, net of $89.2 million in taxes.

On January 1, 2003, we adopted Statement of Financial Accounting Standard No. 143, “Accounting for Asset Retirement Obligations” (Statement 143). Statement 143 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. As a result of the adoption of Statement 143, we recorded a cumulative effect of a change in accounting principle charge of approximately $2.1 million, net of $1.3 million in taxes.

On January 1, 2003, we adopted the recognition and measurement principles of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (Statement 123), as amended. We have elected to begin expensing the fair value of all stock-based compensation granted on or after January 1, 2003, under the prospective method allowed by Statement 123, as amended. We recorded approximately $202,000, net of approximately $129,000 in taxes, of stock-based employee compensation costs in the first quarter of 2003.

In July 2002, we completed a transaction to transfer certain transmission assets in Kansas from the Transportation and Storage segment to the Distribution segment. All historical financial and statistical information has been adjusted to reflect these changes.

We sold our claim related to the Enron bankruptcy for $22.1 million resulting in a gain of $14.0 million in the first quarter of 2002. The sale was subject to normal representations as to the validity, but not collectibility, of the claim and guarantees from Enron. We had previously recorded a charge of $37.4 million in the fourth quarter of 2001 related to the Enron bankruptcy.

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

	Three Months Ended March 31,
Financial Results	2003			2002
Operating revenues, excluding energy trading revenues	$	949,550		$	548,792
Energy trading revenues, net		135,671			71,715
Cost of gas		675,563			326,071

Net revenues		409,658			294,436
Operating costs		136,794			118,871
Depreciation, depletion, and amortization		40,427			34,100

Operating income	$	232,437		$	141,465

Other income	$	2,200		$	599
Other expense	$	(1,459	)	$	(1,319	)

Discontinued operations, net of taxes
Income from discontinued component	$	2,342		$	905
Gain on sale of discontinued component	$	38,369		$	—

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

Operating Results—Operating revenues and cost of gas increased in 2003, compared to the same period in 2002, primarily due to increases in commodity prices and the acquisition of the Texas assets. The increase in energy trading revenues, net is primarily attributable to our continued use of storage and transport capacity to capture the significant intra-month price volatility and inter-region inefficiencies that occurred during the period throughout most of the United States. Operating costs and depreciation, depletion and amortization also increased in 2003, compared to the same period in 2002, primarily due to

the acquisition of the Texas assets. The TGS addition contributed approximately $38.7 million to net revenues and $14 million to operating income.

Production

Our Production segment currently owns, develops and produces natural gas and oil reserves in Oklahoma. Our strategy is to add value not only to our existing oil and gas production operations, but also to our related marketing, gathering, processing, transportation and storage businesses. Accordingly, we focus on exploitation activities rather than exploratory drilling.

In January of 2003, we closed the sale of approximately 70% of the natural gas and oil producing properties of our Production segment to Chesapeake Energy Corporation for a cash sales price of $294 million including adjustments. The sale included approximately 1,900 wells, 482 of which we operated. We recorded an after-tax gain of $38.4 million ($59 million pre-tax) in the first quarter of 2003 related to this sale. The statistical and financial information related to the properties has been restated as a discontinued component for all periods presented.

The following tables set forth certain financial and operating information for our Production segment for the periods indicated.

Financial Results	Three Months Ended March 31,
Financial Results	2003			2002
	(Thousands of Dollars)
Natural gas sales	$	10,950		$	5,371
Oil sales		964			1,126
Other revenues		731			24

Net revenues		12,645			6,521
Operating costs		3,610			1,778
Depreciation, depletion, and amortization		3,358			3,038

Operating income	$	5,677		$	1,705

Other income (expense), net	$	(11	)	$	42

Discontinued operations, net of taxes
Income from discontinued component	$	2,342		$	905
Gain on sale of discontinued component	$	38,369		$	—

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

Operating Information	Three Months Ended March 31,
Operating Information	2003		2002
Proved reserves
Continuing operations
Gas (MMcf)		61,800		52,316
Oil (MBbls)		2,399		2,230
Discontinued component
Gas (MMcf)		—		182,239
Oil (MBbls)		—		2,417
Production
Continuing operations
Gas (MMcf)		1,832		1,673
Oil (MBbls)		36		65
Discontinued component
Gas (MMcf)		1,472		4,686
Oil (MBbls)		53		57
Average realized price (a)
Continuing operations
Gas ($/Mcf)	$	5.98	$	3.21
Oil ($/Bbls)	$	26.50	$	17.32
Discontinued component
Gas ($/Mcf)	$	4.10	$	2.57
Oil ($/Bbls)	$	32.28	$	17.88
Capital expenditures (Thousands)
Continuing operations	$	2,948	$	5,369
Discontinued component	$	—	$	6,253

(a)

Average realized price reflects the impact of hedging activities.

Operating Results—Natural gas sales increased for the three months ended March 31, 2003, compared to the same period in 2002, due to higher volumes produced and prices received in 2003. The increase in gas production is a result of significant drilling on retained properties during 2002. Average gas prices after hedges increased in 2003 to $5.98 per Mcf compared to $3.21 per Mcf average gas price in the first quarter of 2002. Prices for the same periods before hedges were $6.99 per Mcf in 2003 and $2.80 per Mcf in 2002. In December 2002, we hedged approximately 72 percent of our anticipated continuing gas production in 2003 at a weighted average wellhead price of $4.60 per Mcf.

The decrease in oil sales for the three-month period ended March 31, 2003, compared to the same period in 2002, is due to lower volumes produced in 2003. Higher oil volumes produced in the same period for 2002 reflect successful completions on two oil wells drilled during the last quarter of 2001. The two wells produced higher volumes in 2002 when the completions were new. Production generally tapers to a sustained level after the first few months following a completion. The lower volumes in 2003 were partially offset by higher oil prices received in the first quarter of 2003 compared to 2002. The average selling price for the three months ended March 31, 2003 was $26.50 per barrel after the effect of hedges

compared to $17.32 per barrel for the three months ended March 31, 2002. The average oil price at March 31, 2003 before hedges was $36.36 per barrel. There were no oil hedges in place for the first quarter of 2002. In December 2002, we placed additional hedges on oil production to hedge approximately 62 percent of our anticipated oil production in 2003 at a weighted average wellhead price of $27.25 per barrel.

Operating costs increased for the three months ended March 31, 2003 compared to the same period in 2002 due to higher production taxes caused by higher prices and due to higher overhead costs in 2003.

Our Production segment added 3.1 Bcfe of net reserves for the three months ended March 31, 2003, including 1.6 Bcfe of proved developed, which is comprised of 0.8 Bcfe of proved developed producing and 0.8 Bcfe of proved developed non-producing, and 1.5 Bcfe of proved undeveloped reserves.

Gathering and Processing

The Gathering and Processing segment is engaged in the gathering and processing of natural gas and the fractionation, storage and marketing of natural gas liquids (NGLs). Our Gathering and Processing segment currently has a processing capacity of approximately 2.0 Bcf/d (Bcf per day), of which approximately 0.2 Bcf/d is currently idle. The capacity, excluding idled capacity, associated with plants owned or leased is approximately 1.7 Bcf/d, while the amount of the plant capacity that we own an interest in but do not operate is approximately 0.1 Bcf/d. Our Gathering and Processing segment owns approximately 14,000 miles of gathering pipelines that supply our gas processing plants.

In January 2003, we acquired a retail propane business through our purchase of the Texas assets. This business consists of a small retail propane distribution business in Austin and a retail propane bottle and delivery service primarily located in El Paso.

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

Financial Results	Three Months Ended March 31,
Financial Results	2003			2002
	(Thousands of Dollars)
Natural gas liquids and condensate sales	$	297,541		$	131,349
Gas sales		210,454			63,203
Gathering, compression, dehydration and processing fees and other revenues		24,594			21,043
Cost of sales		486,262			174,272

Net revenues		46,327			41,323
Operating costs		31,263			32,070
Depreciation, depletion, and amortization		7,201			7,970

Operating income	$	7,863		$	1,283

Other income, net	$	(11	)	$	(39	)

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

Operating Information	Three Months Ended March 31,
Operating Information	2003		2002
Total gas gathered (MMMBtu/d)		1,208		1,224
Total gas processed (MMMBtu/d)		1,216		1,358
Natural gas liquids sales (MBbls/d)		129		87
Natural gas liquids produced (MBbls/d)		54		66
Gas sales (MMMBtu/d)		351		344
Capital expenditures (Thousands)	$	2,472	$	10,808

Operating Results—NGL and condensate sales increased for the three months ended March 31, 2003 compared to the same period in 2002 primarily due to additional third party sales volumes and increases in composite NGL prices and crude oil prices. The Conway OPIS composite NGL price based on our NGL product mix in the first quarter of 2003 increased from $0.33 per gallon in 2002 to $0.63 per gallon in 2003. The average NYMEX crude oil price increased from $19.33 per barrel in 2002 to $33.99 per barrel in 2003. Net revenues increased as the result of higher prices and the acquisition of the Texas assets. These increases were partially offset by decreases in net revenues as a result of the sale of certain Oklahoma gas gathering and processing assets in December 2002, which also decreased the volumes of NGLs produced. NGL volumes produced also declined as a result of market conditions in late February and early March that resulted in reduced NGL recovery due to the high value of natural gas relative to NGLs. NGL volumes sold increased as a result of increases in third party sales.

Gas sales and cost of sales increased for the three months ended March 31, 2003 compared to the same period in 2002 primarily due to an increase in natural gas prices. Average natural gas price for the mid-continent region increased from $2.21 per MMBtu in the first quarter of 2002 to $6.09 per MMBtu in the first quarter of 2003. Natural gas sales volumes increased in the first quarter of 2003 compared to the same period in 2002 primarily as a result of market conditions in late February and early March that resulted in reduced NGL recovery due to the high value of natural gas relative to NGLs. These increases were partially offset by reduced volumes of gas gathered and processed as the result of the sale of certain Oklahoma gas gathering and processing assets in December 2002.

Gathering, compression, dehydration, processing fees and other revenues increased primarily due to higher natural gas prices and new gathering contracts.

Operating costs and depreciation, depletion and amortization decreased for the three months ended March 31, 2003 compared to same period in 2002 primarily due to the sale of certain Oklahoma gas gathering and processing assets in December 2002 and lower employee costs and bad debt expense. These decreases to operating costs were partially offset by higher leased compression costs, liquid storage rental fees, insurance costs and additional operating costs from the acquisition of the Texas assets.

Transportation and Storage

Our Transportation and Storage segment includes our intrastate natural gas transmission pipelines, natural gas storage and nonprocessable gas gathering facilities. 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. Our intrastate transmission pipelines operate in Oklahoma, Kansas and Texas and are regulated by the OCC, KCC, and Texas Railroad Commission (TRC), respectively. In July 2002, we completed a transaction to transfer certain transmission assets in Kansas to our affiliated distribution company in Kansas. All historical financial and statistical information has been adjusted to reflect this transfer. In December 2002, certain Oklahoma storage property rights were sold and a long-term agreement was entered into with the purchaser, whereby we reserve storage capacity consistent with our historical usage.

The following tables set forth certain selected financial and operating information for our Transportation and Storage segment for the periods indicated.

Financial Results	Three Months Ended March 31,
Financial Results	2003			2002
	(Thousands of Dollars)
Transportation and gathering revenues	$	27,485		$	22,235
Storage revenues		9,067			7,547
Gas sales and other		1,998			15,505
Cost of fuel and gas		8,405			12,471

Net revenues		30,145			32,816
Operating costs		10,866			12,130
Depreciation, depletion, and amortization		4,154			4,274

Operating income	$	15,125		$	16,412

Other income, net	$	513		$	1,209

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

Operating Information	Three Months Ended March 31,
Operating Information	2003		2002
Volumes transported (MMcf)		144,980		133,687
Capital expenditures (Thousands)	$	984	$	14,541

Operating results—Transportation and gathering revenues increased for the three months ended March 31, 2003 compared to the same period in 2002 primarily due to the increase in the price of natural gas and its impact on the valuation of retained fuel and from increased volumes transported due to colder weather. The average natural gas price for the mid-continent region increased from $2.21 per MMBtu in the first quarter of 2002 to $6.09 per MMBtu in the first quarter of 2003. Storage revenues increased primarily due to additional working capacity being available as a result of improved operational conditions and gas inventory sales in 2002. Gas sales and other revenues decreased in the first quarter of 2003 compared to the same period in 2002 primarily due to reduced gas inventory sales and a reduction in sales volumes associated with our wellhead purchases on certain gathering facilities in Oklahoma.

Cost of fuel and gas decreased for the three months ended March 31, 2003 compared to same period in 2002 due to a decrease in costs related to gas inventory sales and our wellhead purchases. This decrease was partially offset by higher natural gas prices for fuel. Net revenues decreased primarily as the result of decreased gas inventory sales in the first quarter of 2003 compared to the same period in 2002.

The decrease in operating costs for the three months ended March 31, 2003 compared to the same period in 2002 is due to lower employee costs and regulatory fees. These decreases were partially offset by higher leased compression costs, maintenance costs, insurance costs and bad debt reserve expense.

Capital expenditures decreased primarily due to the completion of a large power generation project in the first quarter of 2002.

Distribution

Our Distribution segment provides natural gas distribution services in Kansas, Oklahoma and Texas. Operations in Kansas are conducted through our Kansas Gas Service (KGS) division, which serves residential, commercial, industrial, end-use transportation and wholesale customers. Operations in

Oklahoma are conducted through our Oklahoma Natural Gas (ONG) division, which serves residential, commercial, and industrial customers and leases gas pipeline capacity. Operations in Texas are conducted through our Texas Gas Service (TGS) division, which serves residential, commercial, industrial, public authority and transportation customers. Our Distribution segment provides gas service to approximately 71 percent of the population of Kansas, approximately 80 percent of the population of Oklahoma and approximately 17 percent of the population of Texas. KGS and ONG are subject to regulatory oversight by the KCC and OCC, respectively. TGS is subject to regulatory oversight by various municipalities, which have primary jurisdiction in their respective areas. Rates in areas adjacent to the various municipalities and appellate matters are subject to regulatory oversight by the TRC.

On January 3, 2003, we closed the purchase of the Texas gas distribution assets. The gas distribution operations serve approximately 535,000 customers in cities located throughout Texas, including the major cities of El Paso and Austin, as well as the cities of Port Arthur, Galveston, Brownsville, and others. Over 90 percent of the customers are residential. The acquisition also adds a stable revenue source as a majority of the margins are protected from the impact of weather swings due to weather normalization adjustment clauses and rate designs that are heavily weighted toward a fixed customer charge.

KGS filed a rate case with the KCC on January 31, 2003, to increase annual rates by $76 million. The KCC has up to 240 days to review the application and issue a final order. If approved, the new rates would become effective in the third quarter of 2003. Until regulatory approval is received, KGS will continue to operate under the current rate schedule.

The following table sets forth certain selected financial information for our Distribution segment for the periods indicated.

Financial Results	Three Months Ended March 31,
Financial Results	2003			2002
	(Thousands of Dollars)
Gas sales	$	668,761		$	474,637
Cost of gas		516,994			357,218

Gross margin		151,767			117,419
PCL and ECT Revenues		23,221			17,804
Other revenues		7,056			6,688

Net revenues		182,044			141,911
Operating costs		83,127			64,717
Depreciation, depletion, and amortization		23,888			17,249

Operating income	$	75,029		$	59,945

Other income, net	$	(706	)	$	(1,039	)

Operating results—The increase in gas sales and cost of gas for the three months ended March 31, 2003 compared to the same periods in 2002 is primarily attributable to the addition of TGS, as well as additional sales volumes in Kansas and Oklahoma due to colder weather in the 2003 period compared to the 2002 period. The increased gross margin for the three months ended March 31, 2003 is also due to the addition of TGS. The TGS addition contributed approximately $38.7 million to net revenues and $14 million to operating income.

Operating costs and depreciation, depletion and amortization increased for the three months ended March 31, 2003 compared to the same period in 2002 due primarily to the addition of TGS.

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

Volumes *(MMcf)*	Three Months Ended March 31,
Volumes *(MMcf)*	2003	2002
Gas sales
Residential	67,960	53,582
Commercial	23,222	19,037
Industrial	1,543	1,589
Wholesale	3,306	5,469
Public Authority	1,254	—

Total volumes sold	97,285	79,677
PCL, ECT and Transportation	64,690	49,659

Total volumes delivered	161,975	129,336

Residential and commercial volumes increased in the three months ended March 31, 2003 compared to the same period in 2002 as a result of the addition of TGS, as well as colder weather in Kansas and Oklahoma. Industrial volumes for the quarter decreased due to customers moving to new PCL rates and to current economic factors reducing overall consumption. Wholesale sales, also known as “as available” gas sales, represent gas volumes available under contracts that exceed the needs of our residential and commercial customer base and are available for sale to other parties. Wholesale volumes decreased for the current period compared to the same period in 2002 as greater volumes were required to meet the needs of the Kansas residential, commercial, and industrial customers due to colder weather, leaving fewer volumes available for wholesale customers. Public authority volumes reflect volumes used by state agencies and school districts serviced by TGS.

In Oklahoma, the PCL volume increased due to the addition of transportation customers through the addition of pipeline assets acquired with the Texas assets. Volumes also increased due to commercial and industrial customers moving to new PCL rates and as a result of a marketing effort to add small usage PCL customers. Transportation volumes increased in general due to the addition of TGS.

The following table sets forth certain selected operating information for our Distribution segment for the periods indicated.

	Three Months Ended March 31,
Operating Information	2003		2002
Average Number of Customers		2,011,764		1,450,442
Customers per employee		676		624
Capital expenditures *(Thousands)*	$	24,966	$	21,339

The average number of customers and customers per employee increased in 2003 compared to the same period in 2002 due to the addition of TGS and their favorable ratio of customers per employee.

Certain costs to be recovered through the ratemaking process have been recorded as regulatory assets in accordance with Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation.” See Note E of the Notes to Consolidated Financial Statements for a detail of regulatory assets at March 31, 2003. Should unbundling of our gas services occur, certain of these assets may no longer meet the criteria of a regulatory asset and, accordingly, a write-off of regulatory assets and stranded costs may be required. We do not anticipate that such a write-off of costs, if any, will be material.

Marketing and Trading

Our marketing and trading operation purchases, stores, markets, and trades natural gas to both the wholesale and retail sectors. We have mid-continent region storage positions and transport capacity that allow us to trade natural gas throughout most of the United States. We have direct access to most regions of the country and flexibility to capture volatility in the energy markets. We continue to enhance our strategy of focusing on higher margin business which includes providing reliable service during peak demand periods through the use of storage and transportation capacity.

We have a 300-megawatt electric power generating plant located in Oklahoma adjacent to one of our natural gas storage facilities that 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.

During the third quarter of 2002, we adopted certain provisions of EITF 02-3, which provides that all mark-to-market gains and losses on energy trading contracts be presented on a net basis (energy contract sales less energy contract costs) in the income statement without regard to the settlement provisions of the contract. The FASB staff also indicated the dealer profits on unrealized gains or losses at contract inception were not appropriate unless evidenced by quoted prices or other market transactions. Prior to the third quarter of 2002, our energy trading revenues and costs were presented on a gross basis. The financial results of all energy trading contracts have been restated to reflect the adoption of EITF 02-3 for all periods presented. EITF 02-3 does not affect power-related revenues, which will continue to be reported on a gross basis.

In October 2002, the EITF of the FASB rescinded EITF 98-10. As a result, energy related contracts that are not accounted for pursuant to Statement 133, are no longer carried at fair value but rather are accounted for as executory contracts and accounted for on an accrual basis. As a result of the rescission of this statement, the Task Force also agreed that energy trading inventories carried under storage agreements should no longer be carried at fair value but should be carried at the lower of cost or market.

The rescission was effective for fiscal periods beginning after December 31, 2002, and for all existing energy trading contracts and inventory as of October 25, 2002. Additionally, the rescission applied immediately to contracts entered into on or after October 25, 2002. Changes to the accounting for existing contracts as a result of the rescission of EITF 98-10 have been reported as a cumulative effect of a change in accounting principle on January 1, 2003. This resulted in a cumulative effect of a change in accounting principle, non-cash loss, net of tax, of $141.8 million. All recoveries of the estimated value associated with this change in accounting will be recognized in operating income in future periods based on actual settlement prices.

The following tables set forth certain selected financial and operating information for our Marketing and Trading segment for the periods indicated.

Financial Results	Three Months Ended March 31,
Financial Results	2003			2002
	(Thousands of Dollars)
Energy trading revenues, net	$	135,671		$	71,715
Power sales		12,238			8,542
Cost of power and fuel		10,704			8,560
Other revenues		296			212

Net revenues		137,501			71,909
Operating costs		9,103			8,165
Depreciation, depletion, and amortization		1,462			1,183

Operating income	$	126,936		$	62,561

Other income, net	$	(1,568	)	$	141

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

Operating Information	Three Months Ended March 31,
Operating Information	2003		2002
Natural gas sales volumes (MMcf)		315,937		255,789
Natural gas gross margin ($/Mcf)	$	0.35	$	0.15
Power sales volumes (MMwh)		290		316
Power gross margin ($/Mwh)	$	4.90	$	(0.05	)
Physically settled volumes (MMcf)(a)		577,435		490,173
Capital expenditures (Thousands)	$	83	$	138
(a) This represents the absolute value of gross transaction volumes for both buy and sell energy trading contracts that were physically settled.

Operating results—Energy trading revenues include revenues related to trading natural gas, reservation fees, crude oil, natural gas liquids, and basis. Basis is the natural gas price differential that exists between certain geographic locations relative to the Henry Hub. We began actively trading crude oil and natural gas liquids in this segment in the first quarter of 2002.

Net revenues and gas volumes increased in 2003 over 2002. The increase in sales volumes is attributable to colder temperatures in 2003 compared to the same period in 2002 and additional marketing and trading opportunities that have developed with the recent downsizing of certain trading companies in our industry. The increase in net revenues is attributable to our continued use of storage and transport capacity to capture the intra-month price volatility and inter-region inefficiencies that occurred during the period throughout most of the United States. Our storage and transport capacity also enabled us to secure positive option value and realize favorable pricing spreads on stored gas volumes. Our retail business continues to provide positive results as retail margins increased $4.5 million in 2003 compared to the same period in 2002. Power-related margins also improved in 2003 compared to 2002, due to comparatively better spark spreads in the Southwest Power Pool. Included in our net revenues is the change in value of our derivative contracts subject to fair value accounting, which totaled a positive $11.8 million for the three months ended March 31, 2003, compared to a negative $13.7 million for the same period in 2002. In the first quarter of 2002, we sold our Enron bankruptcy claim, which added $10.4 million to our net revenues.

Operating costs increased for the three months ended March 31, 2003 compared to same period in 2002 primarily due to increased employee and overhead costs.

Liquidity and Capital Resources

General—A part of our strategy is to grow through acquisitions that strengthen and complement our existing assets. We have relied primarily on operating cash flow and borrowings from a combination of commercial paper, bank lines of credit, and capital markets for our liquidity and capital resource requirements. We expect to continue to use these sources, together with possible equity financings, such as our recent public common stock and equity unit offerings, for liquidity and capital resource needs on both a short and long-term basis. During 2002 and the first quarter of 2003, our capital expenditures were financed through operating cash flows and short and long-term debt.

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

Our credit rating is currently an “A” (stable outlook) by Standard and Poors and a “Baa1” with a watch for possible downgrade by Moody’s Investor Service. Our credit rating may be affected by a material change in our financial ratios or a material adverse event affecting our business. The most common criteria for assessment of our credit rating are the debt to capital ratio, pre-tax and after-tax interest debt coverage and liquidity. If our credit ratings were downgraded, the interest rates on our commercial paper would increase, resulting in an increase in our cost to borrow funds. In the event that we are unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we have access to an $850 million revolving credit facility, which expires September 22, 2003.

Our energy marketing and trading business relies upon the investment grade rating of our senior unsecured long-term debt to satisfy credit support requirements with several counterparties. If our credit ratings were to decline below investment grade, our ability to participate in energy marketing and trading activity could be significantly limited. Without an investment grade rating, we would be required to fund margin requirements with the few counterparties with which we have a Credit Support Annex within our International Swaps and Derivatives Association Agreements with cash, letters of credit or other negotiable instruments. At March 31, 2003, the total notional amount that could require such funding in the event of a credit rating decline to below investment grade is approximately $55.2 million.

We are subject to commodity price volatility. Significant fluctuations in commodity price in either physical or financial energy contracts may impact our overall liquidity due to the impact the commodity price change has on items such as the cost of NGLs and gas held in storage, recoverability and timing of recovery of regulated natural gas costs, 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. We also have no material guarantees of debt or other commitments to unaffiliated parties.

Our pension plan is currently overfunded resulting in an asset reported on our balance sheet. Due to the poor performance of the equity market and lower interest rates, the market value of our pension fund assets has decreased and, accordingly, our pension benefit for our pension and supplemental retirement plans will decrease in 2003 from $20.8 million to $7.0 million. Should the value of our pension fund assets fall below our Accumulated Benefit Obligation, we would eliminate the asset and record a minimum pension liability on the balance sheet with the difference flowing through other comprehensive income, net of tax. We believe we have adequate resources to fund our obligations under our pension plan as deemed necessary.

Westar— On January 9, 2003, we entered into an agreement with Westar Energy, Inc. and its wholly owned subsidiary, Westar Industries, Inc. (collectively, “Westar”), to repurchase a portion of the shares of our Series A Convertible Preferred Stock (Series A) held by Westar and to exchange Westar’s remaining shares of Series A for newly-created shares of ONEOK’s $0.925 Series D Non-Cumulative Convertible Preferred Stock (Series D). The Series A shares were convertible into two shares of common stock, reflecting our

two-for-one stock split in 2001, and the Series D shares are currently convertible into one share of common stock. Some of the differences between the Series D and Series A are (a) the Series D has a fixed annual cash dividend of 92.5 cents per share, (b) the Series D is redeemable by us at any time after August 1, 2006, at a redemption price of $20, in the event that the closing price of our common stock exceeds, at any time prior to the date the notice is given, $25 for 30 consecutive trading days, (c) each share of Series D is currently convertible into one share of our common stock, and (d) Westar may not convert any shares of Series D held by it unless the annual per share dividend on our common stock for the previous year is greater than 92.5 cents and such conversion would not subject us to the Public Utility Holding Company Act of 1935. Also, in connection with that transaction, a new rights agreement, a new shareholder agreement and a new registration rights agreement between ONEOK and Westar became effective. Our new shareholder agreement with Westar restricts Westar from selling five percent or more of ONEOK’s outstanding Series D and common stock (assuming conversion of all shares of Series D to be transferred) to any one person or to a group. The agreement also restricts Westar from selling up to five percent of ONEOK’s outstanding Series D and common stock (assuming conversion of all shares of Series D to be transferred) to any one person or group that already owns more than five percent of our common stock (assuming conversion of all shares of Series D to be transferred). The KCC approved our agreement with Westar on January 17, 2003. On February 5, 2003, we consummated the agreement by purchasing $300 million of our Series A from Westar. We exchanged Westar’s remaining 10.9 million Series A shares for approximately 21.8 million shares of our newly-created Series D. In addition, we have registered all of the shares of our common stock held by Westar, as well as all the shares of our Series D issued to Westar and all of the shares of our common stock issuable upon conversion of the Series D. As a result of this transaction and our recently completed common stock offering, Westar’s ownership interest in our company has been reduced from approximately 44.4 percent to approximately 27.4 percent on a fully diluted basis.

Cash Flow Analysis

Operating Cash Flows—Operating cash flows decreased in the first quarter of 2003 compared to the same period in 2002, despite a significant increase in income from continuing operations. The decreases in operating cash flows in 2003 compared to 2002 primarily relate to changes in working capital, deferred income taxes, and mark-to-market income. Accounts receivable and accounts payable increased from December 31^st to March 31^st due to increased commodity prices throughout the first quarter of 2003 and the addition of the Texas assets. The change in unrecovered purchased gas costs (UPGC) is primarily due to the unusually high recovery of UPGC in the first quarter of 2002 related to previously deferred UPGC due to an OCC order. The changes in price risk management assets and liabilities primarily relate to derivative contracts that expired and were settled in the first quarter of 2003.

In 2002, the changes in operating cash flows primarily reflect changes in working capital. The Marketing and Trading segment’s gas in storage, which is included in price risk management assets in 2002, decreased primarily due to withdrawals during the heating season to supply trading opportunities and contractual agreements. Operating cash flows were negatively impacted in 2002 by an increase in accounts receivable and a decrease in accounts payable. Although accounts receivable typically decreases in the first quarter, there was an increase in 2002 due to an increased unrecovered purchased gas cost rate in 2002 and the receivable related to the sale of the Enron claim.

Investing Cash Flows—Acquisitions in 2003 represent the $420 million cash purchase of all of the Texas assets. Proceeds from the sale of property include approximately $281 million related to the sale of some of our natural gas and oil producing properties to Chesapeake Energy Corporation for a cash sales price of $294 million, including adjustments, of which $15 million was received in 2002.

Financing Cash Flows—Our capitalization structure is 39 percent equity and 61 percent long-term debt at March 31, 2003, compared to 47 percent equity and 53 percent long-term debt at December 31, 2002. There were no notes payable at March 31, 2003. Our capitalization structure including notes payable was 43 percent equity and 57 percent total debt at December 31, 2002. The change in our capital structure is primarily due to the issuance of common stock and equity units in January 2003, which was partially offset by the payment of notes payable and the repurchase of our Series A Convertible Preferred Stock from

Westar in February 2003. At March 31, 2003, we had $1.9 billion of long-term debt outstanding. As of that date, we could have issued $1.0 billion of additional long-term debt under the most restrictive provisions contained in our various borrowing agreements.

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 debt, which would result in a capitalization structure of 46 percent equity and 54 percent long-term debt at March 31, 2003. Moody’s Investment Services considers 25 percent of the equity units to be debt and 75 percent to be shareholders’ equity, which would result in a capitalization structure of 49 percent equity and 51 percent long-term debt at March 31, 2003.

Our $850 million revolving credit facility is primarily used to support our commercial paper program. At March 31, 2003, we had no commercial paper outstanding and had approximately $283 million in temporary investments.

On January 28, 2003, we issued 12 million shares of common stock at the public offering price of $17.19 per share, resulting in net proceeds to us, after underwriting discounts and commissions, of $16.524 per share, or $198.3 million in the aggregate. We granted the underwriters a 30-day over-allotment option to purchase up to an additional 1.8 million shares of our common stock at the same price, which was exercised on February 7, 2003, at the same price per share, resulting in additional net proceeds to us of $29.7 million.

Also, on January 28, 2003, we issued 14 million equity units at a public offering price of $25 per unit, resulting in net proceeds to us, after underwriting discounts and commissions, of $24.25 per share, or $339.5 million in the aggregate. An over-allotment option allowing the purchase of an additional 2.1 million equity units was exercised on January 31, 2003, increasing the net proceeds to $390.4 million. 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 equity units carry a total annual coupon rate of 8.5% (4.0% annual face amount of the senior notes plus 4.5% annual contract adjustment payments). Each stock purchase contract issued as a part of the equity units carries a maximum conversion premium of up to 20 percent over the $17.19 closing price of our common stock on January 22, 2003, and a floor of $17.19 per share.

On April 4, 2003, we filed an amendment to a shelf registration statement on Form S-3 for the issuance and sale by ONEOK of common stock, preferred stock, purchase contracts, purchase units and debt securities, and the issuance and sale by ONEOK Capital Trust I and ONEOK Capital Trust II of trust preferred securities, in one or more offerings with an aggregate offering price of up to $1.0 billion. Also, on April 4, 2003, we filed a shelf registration statement on Form S-3 to register for resale by Westar all of the shares of our common stock held by Westar, as well as all the shares of our Series D Convertible Preferred Stock issued to Westar and all of the shares of our common stock issuable upon conversion of the Series D Convertible Preferred Stock. Both of these registration statements have been declared effective by the Securities and Exchange Commission.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Risk Management—We are, substantially through our nonutility business segments, exposed to market risk in the normal course of our business operations and to the impact of market fluctuations in the price of natural gas, NGLs, crude oil and power prices. Market risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in commodity energy prices. Our primary exposure arises from fixed price purchase or sale agreements that extend for periods of up to 36 months, NGLs and gas in storage utilized by our marketing and trading operations, respectively, and anticipated sales of natural gas and oil production. To a lesser extent, we are exposed to the risk of changing prices or the cost of intervening transportation resulting from purchasing gas at one location and selling it at another (referred to

as basis risk) and the relative value of natural gas to NGLs. To minimize the risk from market fluctuations in the price of natural gas, NGLs and crude oil, we use commodity derivative instruments such as futures contracts, swaps and options to manage market risk of existing or anticipated purchase and sale agreements, existing physical gas and NGLs in storage, and basis risk. We adhere to policies and procedures that limit our exposure to market risk from open positions and that regularly monitor market risk exposure.

Our Gathering and Processing segment uses derivative instruments, from time to time, to minimize the risk associated with price volatility of natural gas and NGLs.

KGS uses derivative instruments to hedge the cost of anticipated gas purchases during the winter heating months to protect KGS customers from upward volatility in the market price of natural gas. At March 31, 2003, KGS had no derivative instruments in place to hedge the cost of purchases for gas. Gains or losses associated with the KGS hedges are included in and recoverable through the monthly purchased gas adjustment.

TGS uses derivative instruments to mitigate the volatility of the cost of gas to protect its customers in the city of El Paso. At March 31, 2003, TGS had derivative instruments in place for the equivalent of 0.06 Bcf of gas ranging from $3.12 per MMBtu to $3.97 per MMBtu. Gains or losses associated with the derivative instruments are included in and recoverable through the monthly purchased gas adjustment.

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

Source of Fair Value (1)	Fair Value of Contracts at March 31, 2003
Source of Fair Value (1)	Matures through March 2004			Matures through March 2007			Matures through March 2009			Matures after March 2009			Total fair value
	(Thousands of Dollars)
Prices actively quoted (2)	$	12,252		$	727		$	—		$	—		$	12,979
Prices provided by other external sources (3)	$	(29,160	)	$	(36,947	)	$	(8,321	)	$	(973	)	$	(75,401	)

Total	$	(16,908	)	$	(36,220	)	$	(8,321	)	$	(973	)	$	(62,422	)

(1)

Fair value is the mark-to-market component of forwards, swaps, and options, net of applicable reserves utilized for trading activities. 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 future 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.

For further discussion of trading activities and models and assumptions used in our trading activities, see the Critical Accounting Policies in Notes A and D of Notes to Consolidated Financial Statements included in this Form 10-Q.

Interest Rate Risk—We are subject to the risk of fluctuation in interest rates in the normal course of business. We manage interest rate risk through the use of fixed rate debt, floating rate debt and, at times, interest rate swaps. Fixed rate swaps are used to reduce our risk of increased interest costs during periods of rising interest rates. Floating rate swaps are used to convert the fixed rates of long-term borrowings into short-term variable rates.

At March 31, 2003, the interest rate on 69.8% of our long-term debt was fixed after considering the impact of interest rate swaps. During the first quarter of 2003, we terminated $50 million in swaps that had a fair

value of approximately zero. Currently, $550 million of fixed rate debt has been swapped to a floating rate based on the three-month or six-month London InterBank Offered Rate (LIBOR) at the respective reset date and the swaps have been designated as fair value hedges. In January 2003, interest rate locks were put in place locking the rates through the first quarter of 2004. The swaps will result in an estimated $23.0 million in savings during 2003. At March 31, 2003, price risk management assets include $76.6 million to recognize the fair value of our derivatives that are designated as fair value hedging instruments. Long-term debt includes approximately $76.9 million to recognize the change in fair value of the related hedged liability. We also increased interest expense by $1.1 million for the three months ended March 31, 2003 to recognize the ineffectiveness of these hedges.

A 100 basis point move in the annual interest rate on all of our outstanding long-term debt would change our annual interest expense by approximately $33,000 before taxes. This amount is limited based on the LIBOR locks that we have in place through the first quarter of 2004. If these locks were not in place, a 100 basis point change in the interest rates would affect our annual interest expense by $5.5 million before taxes. This 100 basis point change assumes a parallel shift in the yield curve. If interest rates changed significantly, we would take actions to manage our exposure to the change. Since a specific action and the possible effects are uncertain, no change has been assumed.

Value-at-Risk Disclosure of Market Risk—We measure entity-wide market risk in our trading, price risk management, and our non-trading portfolios using value-at-risk (VAR). Our VAR calculations are based on the Risk Works Monte Carlo approach, assuming a one-day holding period. We began using the Monte Carlo approach in the second quarter of 2002. Prior to that time, we used the variance-co-variance approach. The quantification of market risk using VAR provides a consistent measure of risk across diverse energy markets and products with different risk factors in order to set overall risk tolerance, to determine risk targets and set position limits. The use of this methodology requires a number of key assumptions, including the selection of a confidence level and the holding period to liquidation. Inputs to the calculation include prices, positions, instrument valuations and the variance-co-variance matrix. Historical data is used to estimate our VAR with more weight given to recent data, which is considered a more relevant predictor of immediate future commodity market movements. We rely on VAR to determine the potential reduction in the trading and price risk management portfolio values arising from changes in market conditions over a defined period. While management believes that the referenced assumptions and approximations are reasonable, no uniform industry methodology exists for estimating VAR and different assumptions and approximations could produce materially different VAR estimates.

Our VAR exposure represents an estimate of potential losses that would be recognized for our trading and price risk management portfolio of derivative financial instruments, physical contracts and gas in storage due to adverse market movements over a defined time horizon within a specified confidence level. A one-day time horizon and a 95 percent confidence level were used in our VAR data. Actual future gains and losses will differ from those estimated by the VAR calculation based on actual fluctuations in commodity prices, operating exposures and timing thereof, and the changes in our trading and price risk management portfolio of derivative financial instruments and physical contracts. VAR information should be evaluated in light of this information and the methodology’s other limitations.

The potential impact on our future earnings, as measured by the VAR, was $4.1 million and $11.8 million at March 31, 2003 and 2002, respectively. The following table details the average, high and low VAR calculations:

Value at Risk	Three Months Ended March 31,
Value at Risk	2003		2002
	(Millions of Dollars)
Average	$	5.4	$	6.5
High	$	17.1	$	17.8
Low	$	2.6	$	2.0

The variations in the VAR data are reflective of our marketing and trading growth and market volatility during the quarter.

Risk Policy and Oversight—We control the scope of risk management, marketing and trading operations through a comprehensive set of policies and procedures involving senior levels of management. Our Board of Directors affirms the risk limit parameters with our audit committee having oversight responsibilities for the policies. A risk oversight committee, comprised of corporate and business segment officers, oversees all activities related to commodity price, credit and interest rate risk management, marketing and trading activities. The committee also proposes risk metrics, including VAR and position loss limits. We have a corporate risk control organization, led by our Senior Vice-President of Financial Services and our Vice-President of Audit and Risk Control, that is assigned responsibility for establishing and enforcing the policies, procedures and limits and evaluating the risks inherent in proposed transactions. Key risk control activities include credit review and approval, credit and performance risk measurement and monitoring, validation of transactions, portfolio valuation, VAR and other risk metrics.

To the extent open commodity positions exist, fluctuating commodity prices can impact our financial results and financial position either favorably or unfavorably. As a result, we cannot predict with precision the impact that risk management decisions may have on our business, operating results or financial position.

Item 4. Controls and Procedures

Quarterly Evaluation of the Company’s Disclosure Controls—Within the 90 days prior to the date of this Quarterly Report on Form 10-Q, we evaluated the effectiveness of the design and operation of our “disclosure controls and procedures” (Disclosure Controls). This evaluation (the 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’s (SEC) require that in this section of the Quarterly Report 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 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, 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, do not expect that our Disclosure Controls will prevent all error and all fraud. A control system, 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 that may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Scope of the Controls Evaluation—The CEO/CFO evaluation of our Disclosure Controls included a review of the controls’ objectives and design, the controls’ implementation by us and the effect of the controls on the information generated for use in the Quarterly Report. In the course of the 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 will be 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.

Since the date of the Controls Evaluation to the date of this Quarterly Report, there have been no significant changes in our internal controls or in other factors that could significantly affect our internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses.

Conclusions—Based upon the Controls Evaluation, our CEO and CFO have concluded that, subject to the limitations noted above, our Disclosure Controls are effective in 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

Will Price, et al. v. Gas Pipelines, et al. (f/k/a Quinque Operating Company, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 99C30. On April 10, 2003, the Court entered an order denying plaintiffs’ motion for class certification. Plaintiffs have indicated they intend to file a motion to further amend their petition. We plan to continue vigorously defending all aspects of the claims asserted in this case.

In the Matter of the Natural Gas Explosion at Hutchinson, Kansas during January, 2001, Case No. 02-E-0155, before the Secretary of the Department of Health and Environment. The parties held a status conference on April 10, 2003 and efforts towards a consent order continue to progress. The next status conference has been scheduled for June 4, 2003.

Item 2. Changes in Securities and Use of Proceeds

Not Applicable.

Item 3. Defaults Upon Senior Securities

Not Applicable.

Item 4. Submission of Matters to Vote of Security Holders

Not Applicable.

Item 5. Other Information

Our Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries was subject to a “blackout period,” as defined in Regulation BTR (Blackout Trading Restriction), in connection with our quarterly payment of dividends. The blackout period commenced on April 24, 2003, and ended on April 30, 2003. During that blackout period, the ability of all participants in the plan to purchase, sell or otherwise acquire or transfer an interest in plan assets, to make changes in investment options, to initiate distributions or loans and to change payroll deferral percentages was suspended. All of our common stock was subject to the blackout period. The person designated by us to respond to inquiries about the blackout period was Angela Wells, ONEOK, Inc., 100 West Fifth Street, Tulsa, OK 74103, 918-588-7309. We received notice of the blackout

period from the plan administrator on March 28, 2003, as required by Section 101(i)(2)(E) of the Employment Retirement Income Security Act of 1974. This disclosure is provided pursuant to Item 11 of Form 8-K.

Item 6. Exhibits and Reports on Form 8-K

Exhibits

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

Exhibit No.		Exhibit Description

10		First Amendment to Credit Agreement dated March 14, 2003.

12		Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirement for the three months ended March 31, 2003 and 2002.

12.1		Computation of Ratio of Earnings to Fixed Charges for the three months ended March 31, 2003 and 2002.

99.1		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.

99.2		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.

Reports on Form 8-K

We filed the following Current Reports on Form 8-K during the quarter ended March 31, 2003.


January 6, 2003	–	Announced that we closed the purchase of the Texas gas distribution assets of Southern Union Company.

January 6, 2003	–	Announced that we entered into a definitive agreement with Southern Union Company resolving all remaining legal issues stemming from the terminated offer by ONEOK to acquire Southwest Gas Corporation in 1999.

January 9, 2003	–	Announced that we entered into a transaction agreement with Westar Energy and Westar Industries, a wholly owned subsidiary of Westar Energy, to repurchase a portion of the shares of our Series A Convertible Preferred Stock held by Westar Industries.

January 14, 2003	–	Announced that we initiated concurrent offerings of common stock and equity units under our current shelf registration.

January 14, 2003	–	Described various material risk factors that may affect our business, financial condition and operations.

January 17, 2003	–	Announced that the Kansas Corporation Commission approved our agreement with Westar Energy, Inc. and its wholly owned subsidiary, Westar Industries, Inc., to repurchase up to $250 million worth of our Series A Convertible Preferred Stock held by Westar Industries.

January 23, 2003	–	Announced that we priced our concurrent public offerings of common stock and equity units.


January 31, 2003	–	Announced that we had consummated concurrent underwritten offerings of 12 million shares of our common stock at a public offering price of $17.19 per share and 14 million of our 8.50% equity units, with a stated value of $25 per unit.

February 3, 2003	–	Announced that we closed the sale of certain natural gas and oil producing properties to Chesapeake Energy for $300 million in cash.

February 5, 2003	–	Announced that Kansas Gas Service, a division of ONEOK, Inc., filed for a $76 million rate increase with the Kansas Corporation Commission.

February 6, 2003	–	Announced that we purchased $300 million, or 18.1 million common stock equivalents, of our Series A Convertible Preferred Stock from Westar Energy. The remaining Series A shares held by Westar were exchanged for 21.8 million shares of our newly-created Series D Convertible Preferred Stock.

February 25, 2003	–	Announced that we will adopt the fair market value method of accounting for stock options contained in Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation, effective for options granted on or after January 1, 2003.

February 28, 2003	–	Announced earnings guidance for 2003.

March 3, 2003	–	Filed the transcript of the conference call with analysts to discuss the results of operations for the year ended December 31, 2002.

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: May 5, 2003	By:	/s/ Jim Kneale
		Jim Kneale Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)

Certification

I, David L. Kyle, certify that:

1. I have reviewed this quarterly report on Form 10-Q of ONEOK, Inc.;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.


Date: May 5, 2003								/s/ David L. Kyle
								Chief Executive Officer

Certification

I, Jim Kneale, certify that:

1. I have reviewed this quarterly report on Form 10-Q of ONEOK, Inc.;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and


Date: May 5, 2003								/s/ Jim Kneale
								Chief Financial Officer