ONEOK INC /NEW/ - 10-Q Quarterly Report

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2002

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 of 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

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

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 ¨

At November 9, 2002, the registrant had 60,436,441 shares of common stock, with par value of $0.01 outstanding.

ONEOK, Inc.

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2002

		Page No.


Part I.	Financial Information

Item 1.	Financial Statements (Unaudited)

	Consolidated Statements of Income—Three and Nine Months Ended September 30, 2002 and 2001	3

	Consolidated Balance Sheets—September 30, 2002 and December 31, 2001	4-5

	Consolidated Statements of Cash Flows—Nine Months Ended September 30, 2002 and 2001	6

	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	44

Item 4.	Controls and Procedures	47

Part II.	Other Information

Item 1.	Legal Proceedings	47

Item 2.	Changes in Securities and Use of Proceeds	48

Item 3.	Defaults Upon Senior Securities	48

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

Item 5.	Other Information	48

Item 6.	Exhibits and Reports on Form 8-K	48

Signatures

Certifications

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

Part I—FINANCIAL INFORMATION

Item 1. Financial Statements

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME

	Three Months Ended September 30,						Nine Months Ended September 30,
*(Unaudited)*	2002			2001			2002			2001
	*(Thousands of Dollars, except per share amounts)*
Revenues
Operating revenues, excluding energy trading revenues	$	416,342		$	352,881		$	1,361,833		$	1,414,288
Energy trading revenues, net		49,051			27,085			186,836			93,541
Cost of sales		240,195			177,210			760,980			793,257

Net Revenues		225,198			202,756			787,689			714,572

Operating Expenses
Operations and maintenance		96,608			92,492			315,772			283,466
Depreciation, depletion, and amortization		44,732			39,322			129,944			114,133
General taxes		14,594			15,209			45,444			46,252

Total Operating Expenses		155,934			147,023			491,160			443,851

Operating Income		69,264			55,733			296,529			270,721

Other income, net		(7,012	)		(1,914	)		(2,601	)		1,951
Interest expense		28,991			34,731			83,026			108,515
Income taxes		12,542			301			82,202			54,752

Income before cumulative effect of a change in accounting principle		20,719			18,787			128,700			109,405
Cumulative effect of a change in accounting principle, net of tax (Note H)		—			—			—			(2,151	)

Net Income		20,719			18,787			128,700			107,254
Preferred stock dividends		9,275			9,275			27,825			27,825

Income Available for Common Stock	$	11,444		$	9,512		$	100,875		$	79,429

Earnings Per Share of Common Stock (Note D)
Basic	$	0.17		$	0.16		$	1.07		$	0.90

Diluted	$	0.17		$	0.16		$	1.06		$	0.90

Average Shares of Common Stock (Thousands)
Basic		99,957			99,521			99,852			99,382
Diluted		100,573			99,633			100,518			99,648

Dividends per share of Common Stock	$	0.16		$	0.16		$	0.47		$	0.47

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

*(Unaudited)*	September 30, 2002		December 31, 2001
Assets	*(Thousands of Dollars)*
Current Assets
Cash and cash equivalents	$	5,909	$	28,229
Trade accounts and notes receivable, net		487,998		677,796
Materials and supplies		17,651		20,310
Gas in storage		47,262		82,694
Unrecovered purchased gas costs		—		45,098
Assets from price risk management activities		833,693		587,740
Deposits		—		41,781
Other current assets		57,940		78,321

Total Current Assets		1,450,453		1,561,969

Property, Plant and Equipment
Marketing and Trading		124,489		122,172
Gathering and Processing		1,075,560		1,040,195
Transportation and Storage		706,512		691,976
Distribution		2,150,354		2,085,842
Production		512,748		482,404
Other		93,322		85,168

Total Property, Plant and Equipment		4,662,985		4,507,757
Accumulated depreciation, depletion, and amortization		1,335,946		1,234,789

Net Property, Plant and Equipment		3,327,039		3,272,968

Deferred Charges and Other Assets
Regulatory assets, net (Note B)		225,013		232,520
Goodwill		113,868		113,868
Assets from price risk management activities		386,546		475,066
Prepaid Pensions		136,991		116,847
Investments and other		53,926		105,921

Total Deferred Charges and Other Assets		916,344		1,044,222

Total Assets	$	5,693,836	$	5,879,159

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

*(Unaudited)*	September 30, 2002			December 31, 2001
Liabilities and Shareholders’ Equity	*(Thousands of Dollars)*
Current Liabilities
Current maturities of long-term debt	$	6,334		$	250,000
Notes payable		371,106			599,106
Accounts payable		362,869			390,479
Accrued taxes		33,130			11,528
Accrued interest		23,984			31,954
Unrecovered purchased gas costs		3,002			—
Customers’ deposits		20,615			21,697
Liabilities from price risk management activities		543,364			381,409
Deferred income taxes		82,369			3,327
Other		178,793			128,917

Total Current Liabilities		1,625,566			1,818,417

Long-term Debt, excluding current maturities		1,515,127			1,498,012
Deferred Credits and Other Liabilities
Deferred income taxes		559,330			499,432
Liabilities from price risk management activities		331,897			491,374
Lease obligation		112,291			122,011
Other deferred credits		204,102			184,623

Total Deferred Credits and Other Liabilities		1,207,620			1,297,440

Total Liabilities		4,348,313			4,613,869

Commitments and Contingencies *(Note E)*
Shareholders’ Equity
Convertible preferred stock, $0.01 par value:
Series A authorized 20,000,000 shares; issued and outstanding 19,946,448 shares at September 30, 2002 and December 31, 2001		199			199
Common stock, $0.01 par value: authorized 300,000,000 shares; issued 63,438,441 shares with 60,455,580 and 60,002,218 shares outstanding at September 30, 2002 and December 31, 2001, respectively		634			634
Paid in capital (Note G)		903,145			902,269
Unearned compensation		(3,150	)		(2,000	)
Accumulated other comprehensive loss (Note I)		(808	)		(1,780	)
Retained earnings		488,514			415,513
Treasury stock at cost: 2,982,861 shares at September 30, 2002; and 3,436,223 shares at December 31, 2001		(43,011	)		(49,545	)

Total Shareholders’ Equity		1,345,523			1,265,290

Total Liabilities and Shareholders’ Equity	$	5,693,836		$	5,879,159

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months Ended September 30,
*(Unaudited)*	2002			2001
	*(Thousands of Dollars)*
Operating Activities
Net income	$	128,700		$	107,254
Depreciation, depletion, and amortization		129,944			114,133
Gain on sale of assets		(1,844	)		(1,120	)
Gain on sale of equity investment		(7,622	)		(758	)
(Income) loss from equity investments		128			(8,100	)
Deferred income taxes		164,833			65,394
Amortization of restricted stock		1,647			844
Allowance for doubtful accounts		14,198			23,047
Mark-to-market income		(74,630	)		(55,502	)
Changes in assets and liabilities:
Accounts and notes receivable		175,600			1,065,211
Inventories		38,091			(23,133	)
Unrecovered purchased gas costs		48,100			(72,887	)
Deposits		41,781			51,995
Accounts payable and accrued liabilities		5,678			(781,922	)
Price risk management assets and liabilities		(79,283	)		(176,266	)
Other assets and liabilities		121,084			(85,957	)

Cash Provided by Operating Activities		706,405			222,233

Investing Activities
Changes in other investments, net		2,082			756
Acquisitions		(3,663	)		(15,345	)
Capital expenditures		(185,752	)		(243,244	)
Proceeds from sale of property		2,802			7,911
Proceeds from sale of equity investment		57,461			7,425

Cash Used in Investing Activities		(127,070	)		(242,497	)

Financing Activities
Payments of notes payable, net		(228,000	)		(278,775	)
Change in bank overdraft		(20,738	)		(48,414	)
Issuance of debt		3,500			401,367
Payment of debt		(305,500	)		(7,115	)
Issuance of common stock		—			5,171
Issuance of treasury stock, net		4,782			3,257
Dividends paid		(55,699	)		(55,370	)

Cash (Used In) Provided by Financing Activities		(601,655	)		20,121

Change in Cash and Cash Equivalents		(22,320	)		(143	)
Cash and Cash Equivalents at Beginning of Period		28,229			249

Cash and Cash Equivalents at End of Period	$	5,909		$	106

See accompanying Notes to 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 (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 and nine months ended September 30, 2002, 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, 2001.

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 has discontinued the amortization of goodwill effective January 1, 2002. In accordance with the provisions of Statement 142, the Company has completed its analysis of goodwill for impairment and there was no impairment indicated. See Note J.

Reclassifications—Certain amounts in the consolidated financial statements have been reclassified to conform to the 2002 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. The Company accounts 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 requires 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 are reflected in the consolidated balance sheets at fair value as assets and liabilities resulting from price risk management activities. The fair value of these assets and liabilities is 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 energy trading revenues, net in the consolidated statements of income. Market prices used to determine the fair value of these assets and liabilities reflect management’s best estimate considering various factors including closing exchange and over-the-counter quotations, time value and volatility underlying the commitments. Market prices are adjusted for the potential impact of liquidating the Company’s position in an orderly manner over a reasonable period of time under currently existing market conditions.

During the third quarter of 2002, the Company adopted the applicable provisions of Emerging Issues Task Force Issue No. 02-3, “Recognition and Reporting Gains and Losses on Energy Trading Contracts under EITF Issue No. 98-10, ‘Accounting for Contracts Involved in Energy Trading and Risk Management Activities,’ and No. 00-17, ‘Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10’” (EITF 02-3). EITF 02-3 provides that all mark-

ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

to-market gains and losses on energy trading contracts should 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. 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 natural gas price differential that exists between two trading locations relative to the Henry Hub price.

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), 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.

The rescission is effective for all existing energy trading contracts and inventory as of October 25, 2002 and will be applied in periods beginning after December 15, 2002. Additionally, the rescission applies 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 will be reported as a cumulative effect of a change in accounting principle on January 1, 2003. At this time, the Company has not determined the impact of the rescission. Any impact from this change will be non-cash and may be recovered in energy trading revenues in future periods. The impact of adopting the rescission of EITF 98-10 will be included in the March 31, 2003 financial statements and may have a material impact on our financial condition and results of operations.

The Marketing and Trading segment’s gas in storage inventory is recorded at fair value and is included in current price risk management assets.

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) and Texas Railroad Commission (TRC). Certain other transportation activities of the Company are subject to regulation by the Federal Energy Regulatory Commission (FERC). Oklahoma Natural Gas (ONG) and Kansas Gas Service (KGS), both included in the Distribution segment, follow the accounting and reporting guidance contained in Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71). 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 $225.0 million and $232.5 million at September 30, 2002 and December 31, 2001, respectively. Should unbundling of services occur, certain of these assets may no longer meet the criteria for accounting for these assets in

ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 B.

KGS was subject to a three-year rate moratorium, which was set to expire in November 2000. As a result of implementing a weather normalization mechanism in Kansas, KGS agreed to a two-year extension of the rate moratorium. The extended rate moratorium expires in late November 2002 and KGS expects to file a rate case soon after that time. ONG is not subject to a rate moratorium.

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. See Note K.

B. Regulatory Assets

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

	September 30, 2002		December 31, 2001
	September 30, 2002		December 31, 2001
	*(Thousands of Dollars)*
Recoupable take-or-pay	$	71,204	$	75,336
Pension costs		7,988		11,124
Postretirement costs other than pension		59,029		60,170
Transition costs		21,155		21,598
Reacquired debt costs		21,718		22,351
Income taxes		25,948		28,365
Weather normalization		9,321		7,984
Line replacements		4,150		94
Other		4,500		5,498

Regulatory assets, net	$	225,013	$	232,520

ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

C. Supplemental Cash Flow Information

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

	Nine Months Ended September 30,
	2002		2001
	*(Thousands of Dollars)*
Cash paid during the period
Interest (including amounts capitalized)	$	91,532	$	106,105
Income taxes	$	8,533	$	13,047
Income tax refund received	$	91,636	$	—
Noncash transactions
Dividends on restricted stock	$	169	$	128
Treasury stock transferred to compensation plans	$	120	$	131
Issuance of restricted stock, net	$	2,628	$	1,984

D. Earnings Per Share Information

The Company computes 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 is a participating instrument with the Company’s common stock with respect to the payment of dividends. For all periods presented, the “two-class” method resulted in additional dilution. Accordingly, EPS for such periods reflects this further dilution.

ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following is a reconciliation of the basic and diluted EPS computations for the periods indicated.

	Three Months Ended September 30, 2002
	Income		Shares	Per Share Amount
	*(Thousands, except per share amounts)*
Basic EPS
Income available for common stock	$	11,444	60,065
Convertible preferred stock		9,275	39,892

Income available for common stock and assumed conversion of preferred stock		20,719	99,957	$	0.21
Further dilution from applying the “two-class” method					(0.04	)

Basic earnings per share				$	0.17

Effect of Other Dilutive Securities Options and other dilutive securities		—	616

Diluted EPS
Income available for common stock and assumed exercise of stock options	$	20,719	100,573	$	0.21

Further dilution from applying the “two-class” method					(0.04	)

Diluted earnings per share				$	0.17

	Three Months Ended September 30, 2001
	Income		Shares	Per Share Amount
	*(Thousands, except per share amounts)*
Basic EPS
Income available for common stock	$	9,512	59,629
Convertible preferred stock		9,275	39,892

Income available for common stock and assumed conversion of preferred stock		18,787	99,521	$	0.19
Further dilution from applying the “two-class” method					(0.03	)

Basic earnings per share				$	0.16

Effect of Other Dilutive Securities Options and other dilutive securities		—	112

Diluted EPS
Income available for common stock and assumed exercise of stock options	$	18,787	99,633	$	0.19

Further dilution from applying the “two-class” method					(0.03	)

Diluted earnings per share				$	0.16

ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	Nine Months Ended September 30, 2002
	Income		Shares	Per Share Amount
	*(Thousands, except per share amounts)*
Basic EPS
Income available for common stock	$	100,875	59,960
Convertible preferred stock		27,825	39,892

Income available for common stock and assumed conversion of preferred stock		128,700	99,852	$	1.29
Further dilution from applying the “two-class” method					(0.22	)

Basic earnings per share				$	1.07

Effect of Other Dilutive Securities Options and other dilutive securities		—	666

Diluted EPS
Income available for common stock and assumed exercise of stock options	$	128,700	100,518	$	1.28

Further dilution from applying the “two-class” method					(0.22	)

Diluted earnings per share				$	1.06

	Nine Months Ended September 30, 2001
	Income		Shares	Per Share Amount
	*(Thousands, except per share amounts)*
Basic EPS
Income available for common stock	$	79,429	59,490
Convertible preferred stock		27,825	39,892

Income available for common stock and assumed conversion of preferred stock		107,254	99,382	$	1.08
Further dilution from applying the “two-class” method					(0.18	)

Basic earnings per share				$	0.90

Effect of Other Dilutive Securities Options and other dilutive securities		—	266

Diluted EPS
Income available for common stock and assumed exercise of stock options	$	107,254	99,648	$	1.08

Further dilution from applying the “two-class” method					(0.18	)

Diluted earnings per share				$	0.90

There were 206,504 and 332,915 option shares excluded from the calculation of diluted EPS for the three months ended September 30, 2002 and 2001, respectively, since their inclusion would be antidilutive for each period. For the nine months ended September 30, 2002 and 2001, there were 161,796 and 121,664 option shares, respectively, excluded from the calculation of diluted EPS since their inclusion would be antidilutive for each period.

ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following is a reconciliation of the basic and diluted EPS computations before the cumulative effect of a change in accounting principle to net income for the periods indicated.

	Nine Months Ended September 30,
	Basic EPS					Diluted EPS
	2002		2001			2002		2001
	*(Per share amounts)*
Income available for common stock before cumulative effect of a change in accounting principle	$	1.07	$	0.92		$	1.06	$	0.92
Cumulative effect of a change in accounting principle, net of tax		—		(0.02	)		—		(0.02	)

Income available for common stock	$	1.07	$	0.90		$	1.06	$	0.90

E. Commitments and Contingencies

Enron—Certain of the financial instruments discussed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2001, have Enron North America as the counterparty. Enron Corporation and various subsidiaries, including Enron North America, filed for protection from creditors under Chapter 11 of the United States Bankruptcy Code on December 3, 2001. In the fourth quarter of 2001, the Company recorded a charge of $37.4 million to provide an allowance for forward financial positions and to establish an allowance for uncollectible accounts related to previously settled financial and physical positions with Enron. In the first quarter of 2002, the Company recorded a cash recovery of approximately $22.1 million resulting in a gain of approximately $14.0 million as a result of an agreement to sell the related Enron claim to a third party. The sale of the Enron claim is subject to normal representations as to the validity of the claims and the guarantees from Enron.

Westar Energy—Westar Energy, Inc. (formerly known as Western Resources, Inc.) and its affiliates beneficially own approximately 44.3% of the Company’s outstanding common stock after giving effect to the conversion of the outstanding shares of the Company’s Series A convertible preferred stock held by an affiliate of Westar. On May 30, 2002, pursuant to the shareholder agreement with Westar, Westar notified the Company that it intends to dispose of all of the shares of the Company’s stock that it beneficially owns, which include 4,714,434 shares of common stock and 19,946,448 shares of Series A convertible preferred stock that are convertible into 39,892,896 shares of common stock at Westar’s option, subject to certain conditions. Under the shareholder agreement, the Company had the option to purchase the shares specified in the notice at a price of $21.77 per share, for a total purchase price of approximately $971.1 million. On August 22, 2002, the Company announced that it would not purchase the shares. Pursuant to Westar’s May 30, 2002 notice, Westar has until September 30, 2003 to dispose of the shares in accordance with the terms and conditions of the shareholder agreement.

Southwest Gas Corporation—In connection with the Company’s now terminated effort to acquire Southwest Gas Corporation (Southwest), the Company is a party to various lawsuits.

The Company and certain of its officers and former officers, as well as Southwest and certain of its officers, and others have been named as defendants in a lawsuit brought by Southern Union Company (Southern Union). The Southern Union allegations include, but are not limited to, violations of the Racketeer Influenced and Corrupt Organizations Act and improper interference

ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

in a contractual relationship between Southwest and Southern Union. The original claim asked for not less than $750 million compensatory damages, to be trebled for racketeering and unlawful violations, and rescission of a Confidentiality and Standstill Agreement between the Company and Southern Union.

On June 29, 2001, the Company filed Motions for Summary Judgment. On September 26, 2001, the Court entered an order that, among other things, denied the Motions for Summary Judgment by the Company on Southern Union’s claim for tortious interference with Southern Union’s prospective relationship with Southwest. However, the Court’s ruling limited any recovery by Southern Union to out-of-pocket damages and punitive damages. On June 10, 2002, the Company filed a motion for summary judgment against Southern Union as to Southern Union’s sole remaining claim for tortious interference with a prospective relationship, and also moved for summary judgment on Southern Union’s claim for punitive damages. Eugene Dubay, a former officer of the Company, and John A. Gaberino, Jr., an officer of the Company, joined in that motion. On August 6, 2002, Southwest and Southern Union settled their claims against each other. On September 16, 2002, in a sealed Order, the Court denied the Company’s pending motion for summary judgment on Southern Union’s claims for punitive damages against the Company and Messrs. Gaberino and Dubay. Trial on the remaining claims asserted by Southern Union against the Company and Messrs. Gaberino and Dubay was scheduled to begin October 15, 2002, but has been continued to a date to be set by the Court. The Court has scheduled a status conference for Southern Union and the Company for November 15, 2002. Trial of claims brought by Southern Union against Messrs. Irwin and Rose commenced October 29, 2002. The Company has accrued $5.0 million to cover contingent liabilities associated with this case.

Southwest filed a lawsuit against the Company and Southern Union alleging, among other things, fraud and breach of contract. On August 9, 2002, the Company settled with Southwest all claims asserted against each other in these cases in consideration for a payment of $3.0 million that was paid by the Company to Southwest in September 2002. This settlement was recorded in the second quarter of 2002.

Two substantially identical derivative actions were filed by shareholders against members of the Board of Directors of the Company alleging violation of their fiduciary duties to the Company by causing or allowing the Company to engage in certain fraudulent and improper schemes related to the planned acquisition of Southwest and waste of corporate assets. These two cases have been consolidated. They allege conduct by the Company caused the Company to be sued by both Southwest and Southern Union, which exposed the Company to millions of dollars in liabilities. The plaintiffs seek an award of compensatory and punitive damages and costs, disbursements and reasonable attorney fees. The Company and its independent directors and officers named as defendants filed Motions to Dismiss the action for failure of the plaintiffs to make a pre-suit demand on the Company’s Board of Directors. In addition, the independent directors and certain officers filed Motions to Dismiss the action for failure to state a claim. On February 26, 2001, the action was stayed until one of the parties notifies the Court that a dissolution of the stay is requested.

Except as set forth above, the Company is unable to estimate the possible loss associated with these matters. If substantial damages were ultimately awarded, this could have a material adverse effect on the Company’s results of operations, cash flows and financial position. The Company is defending itself vigorously against all claims asserted by Southern Union and all other matters relating to the terminated effort to acquire Southwest.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Environmental—The Company has 12 manufactured gas sites in Kansas, which were acquired in 1997, that may contain potentially harmful materials classified as hazardous. Hazardous materials are subject to control or remediation under various state and federal 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 and set remediation priorities for these sites based upon the results of the investigations and risk analysis. The prioritized sites will be investigated over a period of time as negotiated with the KDHE. Through September 30, 2002, the costs of the investigation and risk analysis related to these manufactured gas sites have been immaterial. Although remedial investigation and interim clean up has begun on four sites, limited information is available about the sites. Management’s best estimate of the cost of remediation ranges from $100,000 to $10 million per site based on a limited comparison of costs incurred to remediate comparable sites. These estimates do not give effect to potential insurance recoveries, recoveries through rates or recoveries from unaffiliated parties. 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 current estimates. 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 Company’s Yaggy gas storage facility, located approximately seven miles from Hutchison, Kansas, was idled following a series of natural gas explosions and eruptions of natural gas geysers which occurred within the city limits. In July 2002, the KDHE issued an administrative order that assessed a $180,000 civil penalty against the Company, based on alleged violations of several KDHE regulations. The Company requested a hearing on the administrative order and a status conference has been set for November 12, 2002. 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 in Hutchinson, Kansas in January 2001. 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. 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’s insurance carrier in these cases represents the Company and its subsidiaries. The Company is vigorously defending itself against all claims.

Other—The OCC staff filed an application on February 1, 2001 to review the gas procurement practices of ONG in acquiring its gas supply for the 2000/2001 heating season and to determine if these practices were consistent with least cost procurement practices and whether the Company’s procurement decisions resulted in fair, just and reasonable costs being borne by ONG customers. In a hearing on October 31, 2001, the OCC issued an oral ruling that ONG not be allowed to recover the balance in the Company’s unrecovered purchased gas cost (UPGC) account related to the unrecovered gas costs from the 2000/2001 winter. This was effective with the first billing cycle for the month following the issuance of a final order. A final order, issued on November 20, 2001, halted the recovery process effective December 1, 2001. On December 12, 2001, the OCC approved a request to stay the order and allowed ONG to begin collecting unrecovered gas costs, subject to refund should the Company ultimately lose the case. In the fourth quarter of 2001, the Company took a charge of $34.6 million as a result of this order. In May 2002, the Company, along with the staff of the Public Utility Division and the Consumer Services Division

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

of the OCC, the Oklahoma Attorney General, and other stipulating parties, entered into a joint settlement agreement resolving this gas cost issue and ongoing litigation related to a contract with Dynamic Energy Resources, Inc.

The settlement agreement has a $33.7 million value to ONG customers that will be realized over a three-year period. In July 2002, immediate cash savings were provided to all ONG customers in the form of billing credits totaling approximately $9.1 million with an additional $1.0 million available for former customers returning to the ONG system. If the additional $1.0 million is not fully refunded to customers returning to the ONG system by December 2005, the remainder will be included in the final billing credit. ONG is replacing certain gas contracts, which is expected to reduce gas costs by approximately $13.8 million due to avoided reservation fees between April 2003 and October 2005. Additional savings of approximately $8.0 million from the use of storage service in lieu of those contracts are expected to occur between November 2003 and March 2005. Any expected savings from the use of storage that are not achieved, any remaining billing credits not issued to returning customers and an additional $1.8 million credit will be added to the final billing credit scheduled to be provided to customers in December 2005. As a result of this settlement agreement, the Company revised its estimate of the charge taken in the fourth quarter of 2001 downward by $14.2 million to $20.4 million and recorded the adjustment in the second quarter of 2002 as a decrease to cost of gas.

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 materially adverse effect on the Company’s consolidated results of operations, financial position, or liquidity.

F. 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 Marketing and Trading segment markets natural gas to wholesale and retail customers and markets electricity to wholesale customers; (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 Production segment develops and produces natural gas and oil; and (6) the Other segment primarily operates and leases the Company’s headquarters building and a related parking facility.

During the first quarter of 2002, the Power segment was combined with the Marketing and Trading segment, eliminating the Power segment. This presentation reflects the Company’s strategy of trading around the Company’s recently completed electric generating power plant. All segment data has been reclassified to reflect this change.

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, 2001, except for the change in energy trading and risk management

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

activities as 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 $22.7 million and $231.1 million for the three and nine months ended September 30, 2002, respectively, and $41.4 million and $567.3 million for the three and nine months ended September 30, 2001, respectively. Corporate overhead costs relating to a reportable segment 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.

Three Months Ended September 30, 2002	Marketing and Trading		Gathering and Processing		Transportation and Storage		Distribution			Production		Other and Eliminations			Total
	*(Thousands of Dollars)*
Sales to unaffiliated customers	$	24,351	$	224,027	$	25,956	$	150,722		$	20,650	$	(29,364	)	$	416,342
Energy trading contracts, net		49,051		—		—		—			—		—		$	49,051
Intersegment sales		—		79,489		15,690		—			4,172		(99,351	)	$	—

Total Revenues	$	73,402	$	303,516	$	41,646	$	150,722		$	24,822	$	(128,715	)	$	465,393

Net revenues	$	51,085	$	53,216	$	30,989	$	63,967		$	24,822	$	1,119		$	225,198
Operating costs	$	5,528	$	29,661	$	9,471	$	58,723		$	7,212	$	607		$	111,202
Depreciation, depletion and amortization	$	1,320	$	9,682	$	4,018	$	19,322		$	10,004	$	386		$	44,732
Operating income (loss)	$	44,237	$	13,873	$	17,500	$	(14,078	)	$	7,606	$	126		$	69,264
Income from equity investments	$	—	$	—	$	425	$	—		$	—	$	—		$	425
Capital expenditures	$	737	$	10,242	$	786	$	31,946		$	10,089	$	1,707		$	55,507

Three Months Ended September 30, 2001	Marketing and Trading		Gathering and Processing		Transportation and Storage		Distribution			Production		Other and Eliminations			Total
	*(Thousands of Dollars)*
Sales to unaffiliated customers	$	17,289	$	173,377	$	12,923	$	166,222		$	20,117	$	(37,047	)	$	352,881
Energy trading contracts, net		27,085		—		—		—			—		—		$	27,085
Intersegment sales		—		95,174		23,117		1,826			3,040		(123,157	)	$	—

Total Revenues	$	44,374	$	268,551	$	36,040	$	168,048		$	23,157	$	(160,204	)	$	379,966

Net revenues	$	32,438	$	52,821	$	25,342	$	66,416		$	23,157	$	2,582		$	202,756
Operating costs	$	6,314	$	28,319	$	10,064	$	56,219		$	5,612	$	1,173		$	107,701
Depreciation, depletion and amortization	$	1,127	$	7,406	$	4,543	$	17,690		$	8,134	$	422		$	39,322
Operating income (loss)	$	24,997	$	17,096	$	10,735	$	(7,493	)	$	9,411	$	987		$	55,733
Income (loss) from equity investments	$	—	$	—	$	992	$	—		$	260	$	639		$	1,891
Capital expenditures	$	1,035	$	10,369	$	3,438	$	32,773		$	16,587	$	5,052		$	69,254

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Nine Months Ended September 30, 2002	Marketing and Trading		Gathering and Processing		Transportation and Storage		Distribution		Production		Other and Eliminations			Total
	*(Thousands of Dollars)*
Sales to unaffiliated customers	$	44,713	$	570,120	$	56,239	$	860,370	$	58,075	$	(227,684	)	$	1,361,833
Energy trading contracts, net		186,836		—		—		—		—		—		$	186,836
Intersegment sales		—		217,096		69,364		2,244		10,795		(299,499	)	$	—

Total Revenues	$	231,549	$	787,216	$	125,603	$	862,614	$	68,870	$	(527,183	)	$	1,548,669

Net revenues	$	190,171	$	139,098	$	87,103	$	301,238	$	68,870	$	1,209		$	787,689
Operating costs	$	21,769	$	97,671	$	35,622	$	180,078	$	22,316	$	3,760		$	361,216
Depreciation, depletion and amortization	$	3,968	$	26,243	$	13,463	$	56,446	$	28,661	$	1,163		$	129,944
Operating income (loss)	$	164,434	$	15,184	$	38,018	$	64,714	$	17,893	$	(3,714	)	$	296,529
Income (loss) from equity investments	$	—	$	—	$	887	$	—	$	—	$	(1,015	)	$	(128	)
Total assets	$	1,505,146	$	1,263,234	$	808,381	$	1,688,383	$	335,678	$	93,014		$	5,693,836
Capital expenditures	$	2,317	$	35,057	$	19,286	$	87,843	$	33,060	$	8,189		$	185,752

Nine Months Ended September 30, 2001	Marketing and Trading		Gathering and Processing		Transportation and Storage		Distribution		Production			Other and Eliminations			Total
	*(Thousands of Dollars)*
Sales to unaffiliated customers	$	22,455	$	665,097	$	69,936	$	1,152,448	$	64,798		$	(560,446	)	$	1,414,288
Energy trading contracts, net		93,541		—		—		—		—			—		$	93,541
Intersegment sales		—		433,713		59,111		3,331		22,669			(518,824	)	$	—

Total Revenues	$	115,996	$	1,098,810	$	129,047	$	1,155,779	$	87,467		$	(1,079,270	)	$	1,507,829

Net revenues	$	101,052	$	145,126	$	87,526	$	287,553	$	87,467		$	5,848		$	714,572
Operating costs	$	13,119	$	86,715	$	30,231	$	179,875	$	20,566		$	(788	)	$	329,718
Depreciation, depletion and amortization	$	1,425	$	21,212	$	13,444	$	52,426	$	23,878		$	1,748		$	114,133
Operating income (loss)	$	86,508	$	37,199	$	43,851	$	55,252	$	43,023		$	4,888		$	270,721
Cumulative effect of a change in accounting principle, net of tax	$	—	$	—	$	—	$	—	$	(2,151	)	$	—		$	(2,151	)
Income from equity investments	$	—	$	—	$	2,500	$	—	$	119		$	5,481		$	8,100
Total assets	$	1,216,097	$	1,394,147	$	667,782	$	1,715,177	$	328,319		$	370,418		$	5,691,940
Capital expenditures	$	41,393	$	27,082	$	20,959	$	90,768	$	42,807		$	20,235		$	243,244

G. Paid in Capital

Paid in capital is $338.9 million and $338.1 million for common stock at September 30, 2002, and December 31, 2001, respectively. Paid in capital for convertible preferred stock was $564.2 million at September 30, 2002, and December 31, 2001.

H. Derivative Instruments and Hedging Activities

On January 1, 2001, the Company adopted the provisions of Statement 133, amended by Statement 137 and Statement 138. Statement 137 delayed the implementation of Statement 133 until fiscal years beginning after June 15, 2000. Statement 138 amended the accounting and reporting standards of Statement 133 for certain derivative instruments and hedging activities. Statement 138 also amends Statement 133 for decisions made by the FASB relating to the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Derivatives Implementation Group (DIG) process. The DIG is addressing Statement 133 implementation issues, the ultimate resolution of which may impact the application 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, on the reason for holding it. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposures 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 (outside earnings) 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.

In 2000, the Company entered into derivative instruments related to the production of natural gas, most of which expired by the end of 2001. These derivative instruments were designed to hedge the Production segment’s exposure to changes in the price of natural gas. Changes in the fair value of the derivative instruments were reflected initially in other comprehensive income (loss) and subsequently realized in earnings when the forecasted transaction affected earnings. At the adoption of Statement 133, the Company recorded a cumulative effect charge of $2.2 million, net of tax, in the income statement and $28 million, net of tax, in accumulated other comprehensive loss to recognize at fair value the ineffective and effective portions, respectively, of the losses on all derivative instruments that were designated as cash flow hedging instruments, which primarily consisted of no cost option collars and swaps on natural gas production.

The Company realized gains in earnings of approximately $1.9 million and $3.2 million for the three and nine months ended September 30, 2002, respectively, related to production hedges entered into in 2002. These realized gains were reclassified from accumulated other comprehensive income resulting from the settlement of contracts when the natural gas was sold. The gains are reported in operating revenues. Other comprehensive income for the three and nine months ended September 30, 2002 includes approximately $1.8 million and $3.6 million, respectively, related to a cash flow exposure for production hedges and will be realized in earnings within the next 27 months. Other comprehensive income for the three and nine months ended September 2002 also includes approximately $0.6 million related to a cash flow exposure for gathering and processing hedges entered into during the third quarter of 2002 that will be realized within the next four 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. In July 2001, the Company entered into interest rate swaps on a total of $400 million in fixed rate long-term debt. The interest rate under these swaps resets periodically based on the three-month London InterBank Offered Rate (LIBOR) or the six-month LIBOR rate at the reset date. In October 2001, the Company entered into an agreement to lock in the interest rates for each reset period under the swap agreements through the first quarter of 2003. In December 2001, the Company entered into interest rate swaps on a total of $200 million in fixed rate long-term debt. These swaps were designated as fair value hedges. Price risk management assets include $82.4 million to recognize the fair value of the Company’s derivatives

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

that are designated as fair value hedging instruments in September 2002. Long-term debt includes approximately $82.3 million to recognize the change in fair value of the related hedged liability. The Company also increased interest expense by $1.4 million for the three months ended September 30, 2002 to recognize the ineffectiveness caused by locking the LIBOR rates into future periods.

I. Comprehensive Income

In March 2002, the Company began accounting for its investment in Magnum Hunter Resources (MHR) as an available-for-sale security and, accordingly, marked the investment to fair value through other comprehensive income. This is a result of MHR’s merger with Prize Energy Corp. (Prize), which reduced the Company’s direct ownership in MHR to approximately 11 percent and reduced the number of MHR board of director positions held by the Company from two to one. In April and June 2002, the Company sold its common stock ownership in MHR. The Company retained approximately 1.5 million MHR stock purchase warrants. Other comprehensive income for the three months ended September 30, 2002 includes unrealized holding losses arising during the period relating to the investment in Magnum Hunter Resources (MHR). Other comprehensive income for the nine months ended September 30, 2002 includes unrealized holding gains and losses arising during the period relating to the investment in MHR and the sale of the Company’s common stock ownership in MHR.

The tables below give an overview of comprehensive income for the three and nine months ended September 30, 2002 and 2001.

	Three Months Ended September 30, 2002						Nine Months Ended September 30, 2002
	*(Thousands of Dollars)*
Net Income				$	20,719					$	128,700
Other comprehensive income:
Unrealized gains on derivative instruments	$	2,425					$	4,211
Unrealized holding gains (losses) arising during the period		(667	)					13,193
Realized gains in net income		(1,860	)					(15,821	)

Other comprehensive income (loss) before taxes		(102	)					1,583
Income tax benefit (expense) on other comprehensive income		41						(611	)

Other comprehensive income (loss)				$	(61	)				$	972

Comprehensive income				$	20,658					$	129,672

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	Three Months Ended September 30, 2001					Nine Months Ended September 30, 2001
	*(Thousands of Dollars)*
Net Income				$	18,787				$	107,254
Other comprehensive income:
Cumulative effect of a change in accounting principle	$	—				$	(45,556	)
Unrealized gains on derivative instruments		6,604					29,330
Realized (gains) losses in net income		(620	)				25,395

Other comprehensive income before taxes		5,984					9,169
Income tax expense on other comprehensive income		(2,315	)				(3,546	)

Other comprehensive income				$	3,669				$	5,623

Comprehensive income				$	22,456				$	112,877

Accumulated other comprehensive loss of $0.8 million at September 30, 2002, includes unrealized and realized gains and losses on derivative instruments, unrealized and realized holding gains and losses related to the investment in MHR and minimum pension liability adjustments.

J. Goodwill

The Company adopted Statement of Financial Accounting Standards No. 142 on January 1, 2002. Under Statement 142, goodwill is no longer amortized but reviewed for impairment annually or more frequently if certain indicators arise. Statement 142 prescribes a two phase process for testing the impairment of goodwill. The first phase, required to be completed by June 30, 2002, identifies indicators for impairment. If an impairment is indicated, the second phase, required to be completed by December 31, 2002, measures the impairment. In accordance with the provisions of Statement 142, the Company has performed the first of the required impairment tests of goodwill and, based upon this transition impairment test, no impairment to goodwill was indicated and the Company will not record a charge in connection with the adoption of Statement 142. Had the Company been accounting for its goodwill under Statement 142 for all periods presented, the Company’s net income and earnings per share would have been as follows:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	Nine Months Ended September 30,
	2002		2001
	*(Thousands of Dollars)*
Reported net income	$	128,700	$	107,254
Add back goodwill amortization, net of tax		—		2,039

Pro forma adjusted net income	$	128,700	$	109,293

Basic earnings per share:
Reported net income	$	1.07	$	0.90
Goodwill amortization, net of tax		—		0.02

Pro forma adjusted basic earnings per share	$	1.07	$	0.92

Diluted earnings per share:
Reported net income	$	1.06	$	0.90
Goodwill amortization, net of tax		—		0.02

Pro forma adjusted diluted earnings per share	$	1.06	$	0.92

The changes in the carrying amount of goodwill for the nine months ended September 30, 2002 and 2001 are as follows:

	Balance December 31, 2001		Additions		Amortization			Balance September 30, 2002
	*(Thousands of Dollars)*
Marketing and Trading	$	5,616	$	—	$	—		$	5,616
Gathering and Processing		34,343		—		—			34,343
Transportation and Storage		37,842		—		—			37,842
Distribution		35,709		—		—			35,709
Production		358		—		—			358

Total consolidated	$	113,868	$	—	$	—		$	113,868


	Balance December 31, 2000		Additions		Amortization			Balance September 30, 2001
	*(Thousands of Dollars)*
Marketing and Trading	$	5,123	$	—	$	(141	)	$	4,982
Gathering and Processing		17,887		20,482		(454	)		37,915
Transportation and Storage		33,328		5,394		(658	)		38,064
Distribution		36,703		—		(746	)		35,957
Production		368		—		(7	)		361

Total consolidated	$	93,409	$	25,876	$	(2,006	)	$	117,279

K. Asset Impairment Charges

In accordance with Statement of Financial Accounting Standards No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144), in the third quarter of 2002, the Company evaluated the carrying value of the three gas processing plants and related gathering assets in the Gathering and Processing segment that are expected to be sold in the fourth quarter of 2002. As a result of the evaluation, a charge was recorded to depreciation expense in the third

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

quarter of 2002. The amount of the charge was determined from the $92 million fair market value (sales price) of the assets compared to the $94.4 million carrying value of the assets.

L. Subsequent Events

On October 11, 2002, the Company agreed to sell three gas processing plants, the related gas gathering systems and the Company’s interest in a fourth gas processing plant to an affiliate of Mustang Fuel Corporation for $92 million. Closing of the transaction requires antitrust clearance and is expected to occur on or before November 15, 2002. If completed, the sale of these assets, with any necessary adjustments to the charge taken in the third quarter of 2002 (see Note K), will be reflected in the Company’s December 31, 2002 financial statements.

On October 16, 2002, the Company agreed to purchase all of the Texas gas distribution assets of Southern Union for $420 million. The 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 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 Company is in the process of seeking regulatory consent and approval of the transaction from numerous municipalities. The Company will also give notice to the FERC and the TRC as well as seek antitrust clearance from the Federal Trade Commission. Assuming necessary governmental consents and approvals are received, the closing is expected on or before December 31, 2002. If completed, the acquisition will be reflected in the Company’s December 31, 2002 financial statements.

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

Forward Looking Statements

Some of the statements contained and incorporated in this Quarterly Report on Form 10-Q are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of pending litigation and 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 matters identified in the preceding paragraph as well as information concerning possible or assumed future results of operations and other statements contained or incorporated in this report identified by words such as “anticipate,” “estimate,” “expect,” “intend,” “believe,” “projection” or “goal.”

You should not place undue reliance on forward-looking statements. Forward looking statements are based on known and unknown risks, uncertainties and other factors that 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 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:

•

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, creditworthiness of counterparties and government regulation;

•

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 income taxes, environmental compliance, and authorized rates;

•

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;

•

the results of litigation related to our terminated effort to acquire Southwest Gas Corporation (Southwest);

•

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

•

our ability to access capital at competitive rates;

•

the risks associated with any change in our credit ratings;

•

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

•

the effect of a sale of our shares of common and preferred stock held by Westar Energy, Inc.; and

•

the other factors listed in the reports we have filed and may file from time to time with the Securities and Exchange Commission.

Other factors and assumptions not identified above also may be involved in the making of 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.

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:

•

Marketing and Trading

•

Gathering and Processing

•

Transportation and Storage

•

Distribution

•

Production

•

Other

During the third quarter of 2002, we adopted Emerging Issues Task Force Issue No. 02-3, “Recognition and Reporting Gains and Losses on Energy Trading Contracts under EITF Issue No. 98-10, ‘Accounting for Contracts Involved in Energy Trading and Risk Management Activities,’ and No. 00-17, ‘Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10 ’ ” (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.

During the first quarter of 2002, the Power segment was combined with the Marketing and Trading segment, eliminating the Power segment. 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 these changes.

We sold and received cash for 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 is 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.

During the second quarter of 2002, we settled a number of outstanding issues pending before the OCC. We had previously recorded a charge of $34.6 million in the fourth quarter of 2001 related to these matters. As a result of the settlement agreement, we revised the estimated amount of the charge and reversed $14.2 million of the charge in the second quarter of 2002.

On March 15, 2002, Magnum Hunter Resources (MHR) merged with Prize Energy Corp. (Prize) reducing our direct ownership to approximately 11 percent and reducing the number of positions held by us on the MHR board of directors from two to one. We began accounting for our investment in MHR as an available-for-sale security and, accordingly, marked the investment to fair value through other comprehensive income. During the second quarter of 2002, we sold the majority of our investment in MHR for a pre-tax gain of approximately $7.6 million, which is included in other income, net for the nine months ended September 30, 2002. We retained approximately 1.5 million stock purchase warrants. We also relinquished our remaining seat on MHR’s board of directors. The MHR investment and related equity income and loss are reported in the Other segment.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
Financial Results	2002			2001			2002			2001
	*(Thousands of Dollars)*
Operating revenues, excluding energy trading revenues	$	416,342		$	352,881		$	1,361,833		$	1,414,288
Energy trading revenues, net		49,051			27,085			186,836			93,541
Cost of gas		240,195			177,210			760,980			793,257

Net revenues		225,198			202,756			787,689			714,572
Operating costs		111,202			107,701			361,216			329,718
Depreciation, depletion, and amortization		44,732			39,322			129,944			114,133

Operating income	$	69,264		$	55,733		$	296,529		$	270,721

Other income, net	$	(7,012	)	$	(1,914	)	$	(2,601	)	$	1,951

Cumulative effect of a change in accounting principle	$	—		$	—		$	—		$	(3,508	)
Income tax		—			—			—			1,357

Cumulative effect of a change in accounting principle, net of tax	$	—		$	—		$	—		$	(2,151	)

For the three months ended September 30, 2002 compared to the same period in 2001, operating revenues and cost of gas increased due to increased volumes related to the addition of NGL pipeline facilities in our Gathering and Processing segment. This increase was partially offset by lower natural gas prices in 2002 compared to 2001. For the nine-month period, operating revenues and cost of gas decreased due to lower natural gas prices. We captured increased energy trading revenues, net for the three- and nine-month periods compared to 2001 by diversifying our portfolio to also include crude oil, and natural gas liquids. The increased use of storage and transport capacity also contributed to our ability to capture price volatility in energy

trading for the three- and nine- month periods. For the three months ended September 30, 2002 and 2001, net revenues include income recognized from mark-to-market accounting of approximately $22 million and $28 million, respectively. For the nine months ended September 30, 2002, net revenues were also increased by the $14.0 million recovery of a portion of the costs related to Enron sales contracts that were written off in the fourth quarter of 2001 and the $14.2 million adjustment due to the OCC settlement. Mark-to-market earnings for the nine months ended September 30, 2002 were $75 million compared to $56 million in the previous year.

Increased employee costs were part of the increase in operating costs for the three and nine months ended September 30, 2002 compared to the same periods in 2001. Operating costs also increased due to the additional costs associated with the NGL pipeline facilities leased at the end of 2001.

Other income, net for the three months ended September 30, 2002 includes additional reserves for legal costs. Other income, net for the nine months ended September 30, 2002, also includes the gain related to the sale of our investment in MHR and a charge for the settlement of litigation with Southwest related to our terminated effort to acquire Southwest. Other income, net in 2001 includes income from equity investments and ongoing litigation costs associated with our terminated effort to acquire Southwest.

Marketing and Trading

Our Marketing and Trading segment purchases, stores, markets and trades natural gas to both wholesale and retail customers in 28 states. We have strong mid-continent region storage positions and transport capacity of approximately one Bcf/d (Bcf per day) that allows us to trade storage capacity and transportation from the California border, throughout the Rockies, to the Chicago city gate. With total storage capacity of 80 Bcf, withdrawal capability of 2.3 Bcf/d and injection capability of 1.3 Bcf/d, we have direct access to most regions of the country and flexibility to capture volatility in the energy markets. We constructed a peak electric power generating plant that began operations in mid-2001. This 300-megawatt plant is located in Oklahoma adjacent to one of our natural gas storage facilities and is configured to supply electric power during peak demand periods. This plant allows us to capture the “spark spread premium”, which is the value added by converting natural gas to electricity, during peak demand periods. 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.

During the first quarter of 2002, the Power segment was combined with the Marketing and Trading segment, eliminating the Power segment. This combination reflects our strategy of trading around the capacity of our electric generating plant. All segment data has been restated to reflect this combination.

During the third quarter of 2002, we adopted Emerging Issues Task Force Issue No. 02-3, “Recognition and Reporting Gains and Losses on Energy Trading Contracts under EITF Issue No. 98-10, ‘Accounting for Contracts Involved in Energy Trading and Risk Management Activities,’ and No. 00-17, ‘Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10’” (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. 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 the reporting of power sales, which will continue to be reported on a gross basis.

The rescission is effective for all existing energy trading contracts and inventory as of October 25, 2002 and will be applied in periods beginning after December 15, 2002. Additionally, the rescission applies 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 will be reported as a cumulative effect of a change in accounting principle on January 1, 2003. At this time, we have not determined the impact of the rescission. Any impact from this change will be non-cash and may be recovered in energy trading revenues in future periods. The impact of adopting the rescission of EITF 98-10 will be included in the March 31, 2003 financial statements and may have a material impact on our financial condition and results of operations.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
Financial Results	2002			2001		2002			2001
	*(Thousands of Dollars)*
Energy trading revenues, net	$	49,051		$	27,085	$	186,836		$	93,541
Power sales		24,201			17,127		44,157			21,035
Cost of power and fuel		22,317			11,936		41,378			14,944
Other revenues		150			162		556			1,420

Net revenues		51,085			32,438		190,171			101,052
Operating costs		5,528			6,314		21,769			13,119
Depreciation, depletion, and amortization		1,320			1,127		3,968			1,425

Operating income	$	44,237		$	24,997	$	164,434		$	86,508

Other income, net	$	(1,363	)	$	280	$	(3,574	)	$	280

	Three Months Ended September 30,				Nine Months Ended September 30,
Operating Information	2002		2001		2002		2001
Natural gas volumes (MMcf)		242,078		233,879		718,216		732,225
Natural gas gross margin ($/ Mcf)	$	0.099	$	0.088	$	0.145	$	0.128
Power volumes (MMwh)		566		311		1,218		384
Power gross margin ($/Mwh)	$	3.49	$	17.66	$	2.33	$	16.60
Physically settled volumes (MMcf)(a)		485,687		477,203		1,439,237		1,491,273
Capital expenditures (Thousands)	$	737	$	1,035	$	2,317	$	41,393

(a)

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

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

Net revenues increased for the three months ended September 30, 2002 compared to the same period in 2001, while sales volumes increased slightly between periods. We captured higher net revenues compared to 2001 by diversifying our portfolio to also include crude oil and natural gas liquids. The increased use of storage and transport capacity also contributed to our ability to capture price volatility for the three- and nine- month periods of 2002 compared to 2001. We also benefited from the renegotiation of certain long-term transportation contracts. Our net revenues for the three months ended September 30, 2002 and 2001 include income recognized from mark-to-market accounting of approximately $22 million and $28 million, respectively. Power related volumes increased while margins decreased for the three months ended September 30, 2002 compared to the same period in 2001 due to comparatively smaller spreads and reduced volatility in the Southwest Power Pool.

Energy trading revenues increased for the nine-month period ended September 30, 2002 compared to the same period in 2001, despite a decrease in sales volumes, due to our ability to capture higher margins by arbitraging the significant intra-month price volatility and to capture option value on stored gas and other energy assets. In addition, we benefited by $10.4 million from the sale of our Enron claim in the first quarter of 2002. Our net revenues for the nine months ended September 30, 2002 and 2001 include income recognized from mark-to-market accounting of approximately $75 million and $56 million, respectively.

Operating costs for the three months ended September 30, 2002 compared to the same period in 2001 decreased due to decreased employee costs for the quarter and decreased bad debt expense. Operating costs for nine months ended September 30, 2002 compared to the same periods in 2001 include increased employee costs and the addition of trading and support personnel.

Capital expenditures for the three and nine months ended September 30, 2001 include construction costs of $1.0 million and $41.0 million, respectively, related to the construction of the electric generating plant, which was completed in mid-2001.

Gathering and Processing

Our Gathering and Processing segment currently has a processing capacity of 2.16 Bcf/d, of which 0.14 Bcf/d is currently idle. The capacity associated with plants owned or leased is 1.9 Bcf/d, while the proportionate amount of the plant capacity that we own an interest in but do not operate is 0.12 Bcf/d. Our gathering and processing segment owns a total of about 16,700 miles of gathering pipelines that supply our gas processing plants.

In November 2002, we expect to complete the sale of three processing plants and related gathering assets, along with our interest in a fourth processing plant, all located in Oklahoma, to Mustang Fuel Corporation. The operating income for these assets was $2.2 million and $6.0 million for the three and nine months ended September 30, 2002, respectively. The sale will reduce our processing capacity to 2.05 Bcf/d. The capacity associated with plants owned or leased will be reduced to 1.8 Bcf/d while the proportionate amount of the plant capacity that we own an interest in but do not operate will be 0.11 Bcf/d. Also, subsequent to the sale, our Gathering and Processing segment will own a total of about 13,900 miles of gathering pipelines that supply our gas processing plants.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
Financial Results	2002			2001			2002			2001
	*(Thousands of Dollars)*
Natural gas liquids and condensate sales	$	181,178		$	134,926		$	461,683		$	477,613
Gas sales		98,217			110,942			254,838			550,533
Gathering, compression, dehydration and processing fees and other revenues		24,121			22,683			70,695			70,664
Cost of sales		250,300			215,730			648,118			953,684

Net revenues		53,216			52,821			139,098			145,126
Operating costs		29,661			28,319			97,671			86,715
Depreciation, depletion, and amortization		9,682			7,406			26,243			21,212

Operating income	$	13,873		$	17,096		$	15,184		$	37,199

Other income, net	$	(403	)	$	(119	)	$	(640	)	$	(119	)


	Three Months Ended September 30,						Nine Months Ended September 30,
Operating Information	2002			2001			2002			2001
Total gas gathered (MMMBtu/d)		1,213			1,128			1,222			1,320
Total gas processed (MMMBtu/d)		1,459			1,525			1,423			1,391
Natural gas liquids sales (MBbls/d)		103,708			78,576			93,656			72,601
Natural gas liquids produced (MBbls/d)		76,449			82,164			72,504			71,712
Gas sales (MMMBtu/d)		346			440			343			400
Capital expenditures (Thousands)	$	10,242		$	10,369		$	35,057		$	27,082

The increase in natural gas liquids (NGL) and condensate sales for the three months ended September 30, 2002, compared to the same period in 2001 is primarily due to the additional sales volumes generated from the NGL pipeline facilities leased at the end of 2001 that increased our access to different NGL markets. This increase was partially offset by an approximate 5%

reduction in the Conway OPIS composite NGL price in 2002 compared to the same period in 2001.

Gas sales decreased for the three months ended September 30, 2002, compared to the same period in 2001 primarily due to lower volumes processed and sold related to natural declines. This was partially offset by natural gas prices that were approximately 5% higher in 2002 compared to the same period in 2001.

Cost of sales increased for the three months ended September 30, 2002 compared to the same period in 2001, primarily due to higher NGL sales volumes associated with the NGL pipeline facilities leased at the end of 2001. This increase was partially offset by the reduction in the composite NGL price in 2002 compared to the same period in 2001. Additionally, lower gas sales volumes further reduced cost but this was partially offset by higher natural gas prices.

The increase in depreciation, depletion and amortization for the three months ended September 30, 2002 compared to the same period in 2001 is primarily due to the $2.4 million loss associated with the three Oklahoma gas processing plants and the related gathering assets that are expected to be sold in the fourth quarter of 2002. We also experienced higher operating costs primarily as a result of increased bad debt reserves and additional costs associated with the NGL pipeline facilities leased at the end of 2001.

The decrease in NGL and condensate sales revenues for the nine months ended September 30, 2002, compared to the same period in 2001 is primarily due to a decrease in composite NGL prices and crude oil prices. The Conway OPIS composite NGL price decreased from $0.53 per gallon for the nine months ended September 30, 2001 to $0.38 per gallon for the same period in 2002. The average NYMEX crude oil price decreased from $28.12 per barrel for the nine-month period in 2001 to $24.30 per barrel for the same period in 2002. These price decreases are mostly offset by the additional sales volumes generated from the NGL pipeline facilities leased at the end of 2001. In addition, NGL volumes produced and sold increased, and conversely gas volumes sold decreased, because of the change in plant operations to decrease the NGL recovery in the first quarter of 2001 due to the high value of natural gas relative to NGL prices.

Gas sales and cost of sales decreased for the nine months ended September 30, 2002 compared to the same period in 2001, primarily due to decreases in natural gas prices. Average natural gas price for the mid-continent region decreased from $4.77 MMBtu for the nine months ended September 30, 2001 to $2.75 MMBtu for the same period in 2002. This decrease was partially offset by the higher NGL sales volumes from the NGL pipeline facilities leased at the end of 2001.

The increase in operating costs for the nine months ended September 30, 2002 compared to the same period in 2001 is primarily due to increases in customer charge offs and bad debt reserves. Operating costs also increased as a result of higher employee costs and additional costs associated with the NGL pipeline facilities leased at the end of 2001.

The increase in depreciation, depletion and amortization for the nine months ended September 30, 2002 compared to the same period in 2001 is primarily due to the $2.4 million loss associated with the three Oklahoma gas processing plants and related gathering assets that are expected to be sold in the fourth quarter of 2002 as mentioned above. Depreciation expense also increased as a result of increased plant property and equipment related to our normal capital expenditure program.

Transportation and Storage

Our Transportation and Storage segment represents our intrastate natural gas transmission pipelines, natural gas storage and gas gathering facilities, which gather pipeline-quality gas. We have four storage facilities in Oklahoma, two in Kansas and three in Texas, with a combined working capacity of approximately 58 Bcf, of which 8 Bcf is currently idled. 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 Distribution segment. All historical financial and statistical information has been adjusted to reflect the transfer.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
Financial Results	2002		2001		2002		2001
	*(Thousands of Dollars)*
Transportation and gathering revenues	$	21,872	$	23,599	$	67,836	$	80,281
Storage revenues		9,359		8,812		26,417		30,150
Gas sales and other		10,415		3,629		31,350		18,616
Cost of fuel and gas		10,657		10,698		38,500		41,521

Net revenues		30,989		25,342		87,103		87,526
Operating costs		9,471		10,064		35,622		30,231
Depreciation, depletion, and amortization		4,018		4,543		13,463		13,444

Operating income	$	17,500	$	10,735	$	38,018	$	43,851

Other income, net	$	1,291	$	2,068	$	2,688	$	2,076

Three Months Ended September 30,

Nine Months Ended September 30,

Operating Information

2002

2001

2002

2001

Volumes transported (MMcf)

114,677

114,473

379,129

374,069

Capital expenditures (Thousands)

786

3,438

19,286

20,959

Gas sales and other revenues for the three-month period ended September 2002 compared to the same period 2001 increased primarily due to an increase in gas inventory sales, partially offset by lower gas sales associated with wellhead purchases on certain gathering facilities in Oklahoma.

Cost of fuel and gas, while unchanged for the three-month period ended September 2002 compared to the same period 2001, included higher costs from the gas inventory sales, offset by reduced wellhead purchases and lower fuel prices. We also experienced higher gas costs associated with liabilities resulting from the reconciliation of third party contractual storage and pipeline imbalance positions.

Net revenues for the three-month period ended September 2002 compared to the same period 2001 were also positively impacted by favorable price and volume adjustments related to retained fuel and increased gas inventory sales.

Transportation and gathering revenues decreased for the nine months ended September 30, 2002 compared to the same period in 2001 primarily due to a decrease in the price of natural gas and its

impact on the valuation of retained fuel. The price of natural gas for the mid-continent region decreased 42% in 2002 compared to the same period in 2001. Storage revenues decreased for the nine-month period in 2002 compared to the same period in 2001 primarily due to a decrease in available storage capacity resulting from the idling of certain storage facilities in 2001. Gas sales and other revenues increased in the nine months ended September 30, 2002 compared to the same period in 2001 primarily due to increased gas inventory sales, partially offset by lower gas sales volumes associated with wellhead purchases on certain gathering facilities in Oklahoma.

Cost of fuel and gas decreased for the nine months ended September 30, 2002 compared to the same period in 2001 due to decreased natural gas prices for fuel and decreases in sales and fuel volumes primarily associated with our wellhead purchases. These decreases were partially offset by adjustments resulting from the reconciliation of third party contractual storage and pipeline imbalance positions and costs related to gas inventory sales.

The increase in operating costs for the nine-month period in 2002 compared to 2001 is due primarily to the settlement of certain legal proceedings, increased bad debt expense, and increased employee costs.

Distribution

Our Distribution segment provides natural gas distribution services in Oklahoma and Kansas to residential, commercial and industrial 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 Kansas are conducted through our Kansas Gas Service (KGS) division, which serves residential, commercial, and industrial customers. Our Distribution segment provides gas service to about 80 percent of the population of Oklahoma and about 71 percent of the population of Kansas. ONG and KGS are subject to regulatory oversight by the OCC and KCC, respectively.

A January 2002 order from the OCC authorized ONG to increase the level of line loss recoveries made through the Company’s line loss recovery rider. Recoveries related to throughput delivered through the ONG system were increased from 1.0% to 1.35% while recoveries related to throughput delivered through the ONEOK Gas Transportation (OGT) system, which is included in our Transportation and Storage segment, increased from 0.66% to 1.0%. All recoveries are calculated at our weighted average cost of gas for each month. The increased recovery percentages allow for a more timely recovery of costs incurred.

In May 2002, the KCC approved an order allowing the transfer of the Mid-Continent Market Center (MCMC) transmission pipeline assets from our Transportation and Storage segment to KGS. The operation of these assets is regulated by the KCC. The MCMC transportation system provides access to the major natural gas producing areas in Kansas intersecting with the nine intra/interstate pipelines at 18 interconnect points, four processing plants, and approximately three producing fields effectively allowing gas to be moved throughout the state. With the transfer of these assets, KGS is able to provide itself with firm transportation service. The order took affect July 1, 2002. All historical financial and statistical information has been adjusted to reflect the transfer.

A Joint Stipulation approved by the OCC on May 16, 2002, settled a number of outstanding cases pending before the OCC. The major cases settled were the Commission’s inquiry into our gas cost procurement practices during the winter of 2000/2001; an application seeking relief from improper and excessive purchased gas costs; and an enforcement action against us, our

subsidiaries and affiliated companies of ONG. In addition, all of the open inquiries related to the annual audits of ONG’s fuel adjustment clause for 1996 to 2000 were closed as a result of this Stipulation.

The Joint Stipulation has a $33.7 million value to ONG customers that will be realized over a three-year period. In July 2002, immediate cash savings were provided to all ONG customers in the form of billing credits totaling approximately $9.1 million with an additional $1.0 million available for former customers returning to our system. If the additional $1.0 million is not fully refunded to customers returning to the ONG system by December 2005, the remainder will be included in the final billing credit. ONG is replacing certain gas contracts, which is expected to reduce gas costs by approximately $13.8 million due to avoided reservation fees between April 2003 and October 2005. Additional savings of approximately $8.0 million from the use of storage service in lieu of those contracts are expected to occur between November 2003 and March 2005. Any expected savings from the use of storage that are not achieved, any remaining billing credits not issued to returning customers and an additional $1.8 million credit will be added to the final billing credit scheduled to be provided to customers in December 2005. ONG operating income increased by $14.2 million for the nine months ended September 30, 2002 compared to the same period in 2001 as a result of this settlement and the revision of the estimated loss recorded in the fourth quarter of 2001.

In Oklahoma, we initiated a Voluntary Fixed-Price Program where customers can lock in their gas price at a fixed rate from November 1, 2002 through October 31, 2003. Over 20,000 customers enrolled in the program for the 2002/2003 pilot year.

In October 2002, we agreed to purchase all of the Texas gas distribution assets of Southern Union for $420 million. The operations serve approximately 535,000 customers in cities located throughout the state of 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. We are in the process of seeking regulatory consent and approval of the transaction from numerous municipalities. The Company will also give notice to the FERC and the TRC as well as seek antitrust clearance from the Federal Trade Commission. Assuming necessary governmental consent and approvals are received, the closing is expected on or before December 31, 2002. If completed, the acquisition will be reflected in the Company’s December 31, 2002 financial statements. This acquisition could have a material effect on our financial results, particularly the financial results of the Distribution segment.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
Financial Results	2002			2001			2002			2001
	*(Thousands of Dollars)*
Gas sales	$	133,956		$	150,464		$	803,085		$	1,099,047
Cost of gas		86,755			101,632			561,376			868,226

Gross margin		47,201			48,832			241,709			230,821
PCL and ECT Revenues		13,111			12,012			43,361			40,794
Other revenues		3,655			5,572			16,168			15,938

Net revenues		63,967			66,416			301,238			287,553
Operating costs		58,723			56,219			180,078			179,875
Depreciation, depletion, and amortization		19,322			17,690			56,446			52,426

Operating income (loss)	$	(14,078	)	$	(7,493	)	$	64,714		$	55,252

Other income, net	$	(1,142	)	$	(1,548	)	$	(3,408	)	$	(2,656	)

The decrease in gas sales and cost of gas for the three and nine months ended September 30, 2002 compared to the same periods in 2001 is primarily attributable to decreased gas costs resulting from lower market prices. Additional gas cost reductions of approximately $14.2 million for the nine months ended September 30, 2002 resulted from the OCC Joint Stipulation. Warmer than normal weather during the first quarter of 2002 compared to the colder than normal weather in the first quarter of 2001 also contributed to the decreased gas costs for the nine months ended September 30, 2002. Increased customer participation in the KGS WeatherProof Bill program increased gross margin for the three months ended September 30, 2002 compared to the same period in 2001. The increased gross margin for the nine months ended September 30, 2002 is also due to the gas cost reduction related to the OCC Joint Stipulation.

Operating costs increased for the three and nine months ended September 30, 2002 compared to the same periods in 2001 due primarily to increased employee costs.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
Gross Margin per Mcf	2002		2001		2002		2001
Oklahoma
Residential	$	6.82	$	6.46	$	2.61	$	2.65
Commercial	$	3.51	$	3.21	$	2.22	$	1.95
Industrial	$	1.58	$	1.53	$	1.62	$	1.12
Pipeline capacity leases	$	0.30	$	0.32	$	0.29	$	0.31
Kansas
Residential	$	7.78	$	6.43	$	2.82	$	2.69
Commercial	$	3.06	$	2.62	$	2.08	$	1.97
Industrial	$	1.20	$	1.34	$	1.45	$	1.53
Wholesale	$	0.10	$	0.09	$	0.11	$	0.11
End-use customer transportation	$	0.36	$	0.48	$	0.51	$	0.59

	Three Months Ended September 30,		Nine Months Ended September 30,
Volumes *(MMcf)*	2002	2001	2002	2001
Gas sales
Residential	6,127	6,721	69,351	71,151
Commercial	3,168	3,447	24,874	28,704
Industrial	504	524	2,301	2,993
Wholesale	9,823	12,133	24,338	19,891

Total volumes sold	19,622	22,825	120,864	122,739
PCL and ECT	39,907	31,836	116,561	100,611

Total volumes delivered	59,529	54,661	237,425	223,350

Residential, commercial and industrial volumes decreased for the three and nine-month periods of 2002 compared to the same periods in 2001 due to warmer weather partially offset by an increase in the number of customers. The increase in customers for 2002 was partially due to fewer customers being disconnected for failure to pay their gas bills, as a result of the lower cost of gas.

Residential, commercial and industrial gross margins per Mcf for our Oklahoma customers increased for the three months ended September 30, 2002 compared to the same period in 2001 primarily due to lower volumes as a result of warmer weather.

In Oklahoma, the pipeline capacity lease (PCL) volume increased and gross margin decreased for the three and nine months ended September 30, 2002, compared to the same period in 2001 due to higher volumes sold to lower margin large industrial customers.

Kansas residential and commercial gross margin per Mcf increased for the three and nine months ended September 30, 2002 compared to the same periods in 2001 due to the Weatherproof Bill Plan (WBP). The WBP provides participating customers a level monthly payment determined from their estimated historical yearly consumption. Gas costs associated with these customers is recorded on actual usage resulting in margin per Mcf for these customers to be highest in the lowest consumption quarter, which is usually the third quarter. For 2002, approximately 15,000 more customers enrolled in this plan compared to 2001. For the third quarter 2002, the greater number of customers in this plan contributed to the overall margin per Mcf increase for the period.

Industrial customers are billed on rates that decrease with increased volumes, or step rates, during the months of April through October. During these months, industrial customers are billed at base rates for the first block of volumes and they are billed at approximately half the base rate for a second block of volumes. A greater number of volumes were sold at the lower rate second block for the three months ended September 30, 2002 compared to the same period in 2002 resulting in a lower unit margin for 2002. Industrial volumes sold during the heating season are billed at the base rate. For the nine months ended September 30, 2002 compared to the same period in 2001, lower sales in the first quarter of 2002 at the higher base rate reducing the overall margin per unit for the nine months ended.

Kansas 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 sales volumes decreased for the third quarter but have increased for the nine months ended September 30, 2002. The decrease for the third quarter is mainly due to the open market selling price for most of July being less than our contract purchase price. Therefore, we stored the gas rather than selling it. The increase for the nine

months is mainly due to sales made in the first quarter, where relatively mild weather allowed more volumes to be sold and market conditions were favorable. End-use customer transportation (ECT) margins per Mcf decreased for the three and nine months ended September 30, 2002 compared to the same periods in 2001 due to higher volumes sold to lower margin interruptible transport service customers.

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

Three Months Ended
September 30,

Nine Months Ended
September 30,

Operating Information

2002

2001

2002

2001

Average Number of Customers

1,423,951

1,409,034

1,443,486

1,429,311

Customers per employee

620

592

624

594

Capital expenditures (Thousands)

31,946

32,773

87,843

90,768

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.” Total regulatory assets resulting from this deferral process for our Distribution segment were approximately $225 million at September 30, 2002. 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.

Production

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

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

	Three Months Ended September 30,					Nine Months Ended September 30,
Financial Results	2002			2001		2002			2001
	*(Thousands of Dollars)*
Natural gas sales	$	20,810		$	19,869	$	58,545		$	78,610
Oil sales		3,803			3,276		9,059			8,716
Other revenues		209			12		1,266			141

Net revenues		24,822			23,157		68,870			87,467
Operating costs		7,212			5,612		22,316			20,566
Depreciation, depletion, and amortization		10,004			8,134		28,661			23,878

Operating income	$	7,606		$	9,411	$	17,893		$	43,023

Other income (expense), net	$	(104	)	$	8	$	(192	)	$	1,186

Cumulative effect of change in accounting principle, before tax	$	—		$	—	$	—		$	(3,508	)

	Three Months Ended September 30,				Nine Months Ended September 30,
Operating Information	2002		2001		2002		2001
Proved reserves
Gas (MMcf)		—		—		241,790		252,349
Oil (MBbls)		—		—		5,082		4,724
Production
Gas (MMcf)		6,530		6,419		19,095		19,069
Oil (MBbls)		144		127		380		328
Average realized price (a)
Gas (Mcf)	$	3.19	$	3.10	$	3.07	$	4.12
Oil (Bbls)	$	28.06	$	25.80	$	23.84	$	26.57
Capital expenditures (Thousands)	$	10,089	$	16,587	$	33,060	$	42,807

(a)

Average realized price reflects the impact of hedging activities.

Natural gas sales increased for the three months ended September 30, 2002, compared to the same period in 2001, due to higher natural gas prices received and higher volumes produced. The higher price was due to the positive impact of hedges on the average realized price, with 49 percent of third quarter volumes hedged at a price of $3.51 per Mcf. Natural gas volumes produced were also higher for the three months ended September 30, 2002 compared to the same period in 2001 due to new production on recently completed wells. Natural gas sales decreased for the nine months ended September 30, 2002, compared to the same period in 2001 due to the lower average gas prices received for the nine months ended 2002. The gas volumes produced for the nine months ended September 30, 2002 were relatively constant compared to the same period in 2001 as normal production declines were offset by new production from successful drilling efforts. Sales for the nine months ended September 30, 2002, include a recovery of $2.7 million related to the sale of our Enron claim on hedging contracts and additional gas revenue of $3.2 million from hedging gains on current year contracts through September 2002.

During the third quarter of 2002 we lifted our natural gas production hedges through December 2004 and fixed the margin for all product contracts previously in place related to our natural gas production. We recognize the benefit from the fixed margin as each contract month expires. For

September 30, 2002 we recognized $1.9 million in natural gas sales revenues related to these hedges. The fixed margins associated with these natural gas production hedges have been deferred in other comprehensive income and will be realized in the month that the natural gas production occurs.

The increase in oil sales for the three-month period ended September 30, 2002, compared to the same period in 2001, is due to both increased production volumes of oil and an increase in the average realized sales price resulting from higher market prices. We performed a number of workovers during the first six months of 2002 that resulted in higher oil production in the third quarter. Oil sales for the nine months ended September 30, 2002 increased over the same period in 2001 due to higher volumes produced, partially offset by lower oil prices.

Operating costs increased for the three and nine months ended September 30, 2002 compared to the same periods in 2001 due to treatment expenses for a new well that produces sour gas, maintenance costs on marginal wells, higher workover costs and lower overhead recovery from producing wells. The lower overhead recovery relates to a decrease in the allowable rate of recovery set by the Council of Petroleum Accounting Societies (COPAS). Production taxes were lower for the three and nine-month periods ended September 30, 2002 as they are calculated based on wellhead prices rather than realized prices. Wellhead prices were lower for the three and nine months ended September 30, 2002 compared to the same periods in 2001. The increase in depreciation, depletion, and amortization for the three and nine months ended September 30, 2002 compared to the same periods in 2001 is due to increased oil production and a higher rate per unit of production, caused by higher capital costs incurred in the last twelve months.

Our Production segment added 33.6 Bcfe of net reserves for the nine months ended September 30, 2002 after adjustments, including 22.4 Bcfe proved developed, 3.0 Bcfe proved behind pipe, and 8.2 Bcfe proved undeveloped.

Financial Flexibility and Liquidity

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, for liquidity and capital resource needs on both a short and long-term basis. During 2001 and the first nine months of 2002, 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, if needed, through a revolving credit facility. Other options to obtain financing include, but are not limited to, issuance of equity, asset securitization and sale/leaseback of facilities. We currently have a $500 million shelf registration in effect covering debt securities (including convertible debt) and common stock.

On August 21, 2002, the Company announced that it had completed its tender offer to purchase all of the outstanding 8.44% Senior Notes due 2004 and the 8.32% Senior Notes due 2007 for a total purchase price of approximately $65 million. The total purchase price included a premium of approximately $2.9 million and consent fees of approximately $1.8 million to purchase the notes, which are reflected in interest expense in the income statement.

On October 16, 2002, we agreed to purchase all of the Texas gas distribution assets of Southern Union for $420 million. The 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 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.

Assuming necessary governmental consents and approvals are received, the closing is expected on or before December 31, 2002. We are currently evaluating alternatives to finance the acquisition including borrowings, potential asset sales, and potential equity offerings. If completed, the acquisition will be reflected in our December 31, 2002 financial statements.

Our credit rating is currently an A 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 to be 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. For further discussion of debt rating triggers, see the Liquidity and Capital Resources section of our Annual Report on Form 10-K for the year ended December 31, 2001.

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 Credit Support Annex within our International Swaps and Derivatives Association Agreements with cash, letters of credit or other negotiable instruments. At September 30, 2002, the total notional amount that could require such funding in the event of a credit rating decline to below investment grade is approximately $21 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 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.

Our pension plan is currently overfunded resulting in an asset reported on the 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 expense will increase in 2003. Should the value of our pension fund assets fall below our Accumulated Benefit Obligation, we would eliminate the asset and record a liability on the Balance Sheet with the difference flowing through Other Comprehensive Income. The funding status will be evaluated quarterly and the

asset, liability and Other Comprehensive Income adjusted accordingly. We believe we have adequate resources to fund our obligations under our pension plan as deemed necessary.

Enron. Enron North America is the counterparty in certain of the financial instruments discussed in our Annual Report on Form 10-K for the year-ended December 31, 2001. Enron Corporation and various subsidiaries, including Enron North America, filed for protection from creditors under Chapter 11 of the United States Bankruptcy Code on December 3, 2001. In 2001, we recorded a charge of $37.4 million to provide an allowance for forward financial positions and to establish an allowance for uncollectible accounts related to previously settled financial and physical positions with Enron. In the first quarter of 2002, we recorded a recovery of approximately $14.0 million as a result of an agreement to sell our Enron claim to a third party, which is subject to normal representations as to the validity, but not the collectibility, of the claims and the guarantees from Enron.

Oklahoma Corporation Commission. The OCC staff filed an application on February 1, 2001 to review the gas procurement practices of our ONG division in acquiring its gas supply for the 2000/2001 heating season to determine if these procurement practices were consistent with least cost procurement practices and whether ONG’s decisions resulted in fair, just and reasonable costs to its customers. On November 20, 2001, the OCC entered an order stating that ONG not be allowed to recover the balance in ONG’s unrecovered purchased gas cost (UPGC) account related to the unrecovered gas costs from the 2000/2001 winter effective with the first billing cycle for the month following the issuance of a final order. This order halted ONG’s recovery process effective December 1, 2001. On December 12, 2001, the OCC approved a request to stay the order and allowed ONG to begin collecting unrecovered gas costs, subject to refund should ONG ultimately lose the case. In the fourth quarter of 2001, we recorded a charge of $34.6 million as a result of this OCC order. In April 2002, we, along with the staff of the Public Utility Division and the Consumer Services Division of the OCC, the Oklahoma Attorney General, and other stipulating parties filed a joint stipulation agreement proposing settlement of this and other issues. A hearing with the OCC was held in May 2002 and an order approving the settlement was issued at that time. As a result, we recorded a $14.2 million recovery in the second quarter of 2002 and have the potential of an additional $8.0 million recovery before December 2005 depending upon the potential value that could be generated by gas storage savings.

Cash Flow Analysis

Operating Cash Flows. Operating cash flows for the nine months ended September 30, 2002, were $706.4 million compared to $222.2 million for the same period one year ago. The changes in operating cash flows primarily reflect changes in working capital accounts, mark-to-market income, deferred income taxes and price risk management assets and liabilities. Receivables decreased for the nine-month period due to the decrease in energy prices. Additionally, receivables are typically higher during the heating season resulting in increased cash receipts in the first nine months of the year. A reduction in restricted deposits is due to decreased margin requirements based on positions at September 30, 2002 in the Marketing and Trading segment. The decrease in inventories during the nine months ended September 30, 2002 is partially due to the decrease in natural gas prices for the nine-month period. In addition, inventories are typically higher at December 31 and are used throughout the remainder of the winter. This is partially offset by the Distribution segment’s injections into storage in the third quarter to prepare for the 2002/2003 winter heating season. The change in inventories excludes the change in the Marketing and Trading segment’s gas in storage, which is included in price risk management assets. The change in unrecovered purchased gas costs is due to the recovery of outstanding

receivables from the 2000/2001 winter. The increase in deferred income taxes is due to additional tax depreciation and increased mark-to-market income in 2002.

For the nine months ended September 30, 2001, the changes in cash flow provided by operating activities are primarily due to the higher gas prices. Accounts receivable and accounts payable are typically higher during the heating season. However, they were higher than normal at December 31, 2000 due to the higher gas prices and integration of the businesses we acquired in 2000. The increase in inventories during the nine months ended September 30, 2001 is a result of increased volumes in storage as well as higher gas prices as we focused on opportunistically securing volumes that are then hedged at favorable winter/summer spreads.

Investing Cash Flows. Capital expenditures in 2001 included $41.0 million for the construction of our electric generating plant, located in Oklahoma, that was completed in the second quarter of 2001. Proceeds from the sale of equity investment represent the sale of our interest in MHR in 2002.

Financing Cash Flows. Our capitalization structure is 47 percent equity and 53 percent long-term debt at September 30, 2002, compared to 42 percent equity and 58 percent long-term debt at December 31, 2001. The change in our capital structure is primarily due to the retirement of approximately $300 million of long-term debt and earnings in excess of dividends for the nine months ended September 30, 2002. At September 30, 2002, we had $1.5 billion of long-term debt outstanding. As of that date, we could have issued $0.8 billion of additional long-term debt under the most restrictive provisions contained in our various borrowing agreements.

Our $850 million revolving credit facility is primarily used to support our commercial paper program. At September 30, 2002, $371.1 million of commercial paper was outstanding.

Impact of Recently Issued Accounting Pronouncements

In July 2001, the FASB issued Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (Statement 143). Statement 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Statement 143 is effective for fiscal years beginning after June 15, 2002. We are currently assessing the impact of Statement 143 on our financial condition and results of operations.

In April 2002, the FASB issued Statement of Financial Accounting Standards No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13 and Technical Corrections” (Statement 145). Statement 145 rescinds FASB Statement No. 4, “Reporting Gains and Losses from Extinguishment of Debt” (Statement 4), and an amendment to that Statement, FASB Statement No. 64 “Extinguishment of Debt Made to Satisfy Sinking-Fund Requirements” (Statement 64). Statement 145 also rescinds FASB Statement No. 13, “Accounting for Leases” (Statement 13) to eliminate the inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. Statement 145 also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings or describe their applicability under changed conditions. The provisions of Statement 145 related to the rescission of Statement 4 are effective for fiscal years beginning after May 15, 2002. The provisions of Statement 145 related to Statement 13 are effective prospectively for transactions occurring after May 15, 2002. All other provisions of

Statement 145 are effective prospectively for financial statements issued on or after May 15, 2002.

In July 2002, the FASB issued Statement of Financial Accounting Standards No. 146, “Accounting for Restructuring Costs” (Statement 146). Under Statement 146, a company will record a liability for a cost associated with an exit or disposal activity when that liability is incurred and can be measured at fair value. Statement 146 also provides guidance on accounting for specified employee and contract terminations that are part of restructuring activities. Statement 146 is effective prospectively for exit or disposal activities initiated after December 31, 2002.

In July 2002, the Emerging Issues Task Force issued EITF Issues No. 02-3, “Recognition and Reporting Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, ‘Accounting for Contracts Involved in Energy Trading and Risk Management Activities,’ and No. 00-17, ‘Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10’” (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. An entity should disclose the gross transaction volumes for those energy trading contracts that are physically settled. We adopted these provisions of EITF 02-3 in the third quarter of 2002.

In October 2002, the EITF 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.

The rescission is effective for all existing energy trading contracts and inventory as of October 25, 2002 and will be applied in periods beginning after December 15, 2002. Additionally, the rescission applies 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 will be reported as a cumulative effect of a change in accounting principle on January 1, 2003. At this time, we have not determined the impact of the rescission. Any impact from this change will be non-cash and may be recovered in energy trading revenues in future periods. The impact of adopting the rescission of EITF 98-10 will be included in the March 31, 2003 financial statements and may have a material impact on our financial condition and results of operations.

Other

Westar Energy Sale Notice. Information related to the notice received by us from Westar Energy, Inc. with respect to the proposed sale by Westar of our shares of common and preferred stock is presented in Note E in the Notes to the Consolidated Financial Statements included in this Form 10-Q.

Southwest Gas Corporation. Information related to litigation arising out of the termination of our effort to acquire Southwest Gas Corporation is presented in Note E in the Notes to the Consolidated Financial Statements and in Item 1 of Part II in this Form 10-Q.

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 48 months, gas in storage utilized by the marketing and trading operation, and anticipated sales of natural gas and oil production. To a lesser extent, we are exposed to 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). 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 in storage, and basis risk. We adhere to policies and procedures that limit our exposure to market risk from open positions and that monitor market risk exposure.

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 September 30, 2002, KGS had derivative instruments in place to hedge the cost of purchases for 82.9 Bcf of gas. This represents all of KGS gas purchase requirements for the winter heating months based on normal weather conditions. Gains or losses associated with the KGS hedges are included in the 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. This maturity schedule is consistent with the Marketing and Trading segment’s trading strategy. The Marketing and Trading segment has contracted approximately 40 Bcf of storage with an affiliate, which is excluded from outstanding fair value at September 30, 2002 in accordance with generally accepted accounting principles.

	Fair Value of Contracts at September 30, 2002
Source of Fair Value (1)	Matures through March 2003			Matures through March 2006			Matures through March 2008			Matures after March 2008			Total fair value
	*(Thousands of Dollars)*
Prices actively quoted (2)	$	37,283		$	871		$	—		$	—		$	38,154
Prices provided by other external sources (3)	$	(58,643	)		(7,592	)		(1,701	)		(1,860	)	$	(69,796	)
Prices based on models and other valuation models (4)	$	100,872			57,387			11,442			(3,820	)	$	165,881

Total	$	79,512		$	50,666		$	9,741		$	(5,680	)	$	134,239

(1)

Fair value is the mark-to-market component of forwards, swaps, option, and energy transportation and storage contracts, 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.

(4)

Values primarily include natural gas storage and transportation capacity. Values derived in this category utilize market price information from the two other categories as well as other modeling assumptions that include, among others, assumptions for liquidity, credit, time value and other external attributes. Values attributable to storage models are determined on a heating injection/withdrawal model.

For further discussion of trading activities and models and assumptions used in our trading activities, see the Critical Accounting Policies in Notes A and H 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 September 30, 2002, the interest rate on 58.1 percent of our long-term debt was fixed after considering the impact of interest rate swaps. In July 2001, we entered into interest rate swaps on a total of $400 million in fixed rate long-term debt. The interest rate under these swaps resets periodically based on the three-month LIBOR or the six-month LIBOR at the reset date. In October 2001, we entered into an agreement to lock in the interest rates for each reset period under the swap agreements through the first quarter of 2003. In December 2001, we entered into additional interest rate swaps on a total of $200 million in fixed rate long-term debt. In September 2002, we recorded an $82.4 million net increase in price risk management assets to recognize at fair value our derivatives that are designated as fair value hedging instruments. Long-term debt was increased by approximately $82.3 million to recognize the change in fair value of the related hedged liability. We also increased interest expense by $1.4 million for the three months ended September 30, 2002 to recognize the ineffectiveness caused by locking the LIBOR rates into future periods.

A 100 basis point move in the annual interest rate would change our annual interest expense by $5.7 million before taxes. This amount is limited based on the LIBOR locks that we have in place through the first quarter of 2003. If these locks were not in place, a 100 basis point change in the interest rates would affect our annual interest expense by $9.7 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 the Company’s 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 $6.0 million and $4.4 million at September 30, 2002 and 2001, respectively. The following table details the average, high and low VAR calculations:

	Three Months Ended September 30,				Nine Months Ended September 30,
Value at Risk	2002		2001		2002		2001
			*(Millions of dollars)*
Average	$	4.2	$	3.6	$	5.2	$	3.3
High	$	11.3	$	7.0	$	17.8	$	8.7
Low	$	1.2	$	0.7	$	1.2	$	0.7

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 Vice-President of Risk Control, which 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 risk management decisions may have on our business, operating results or financial position.

Item 4. Controls and Procedures

Within the 90 days prior to the filing date of this Quarterly Report on Form 10-Q, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective in timely alerting them to material information required to be disclosed by us in our periodic reports to the Securities and Exchange Commission. There have been no significant changes in our internal controls or in other factors that could significantly affect our disclosure controls subsequent to the date of their evaluation.

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, Stevens County, Kansas, Civil Department, Case No. 99C30. The Court entered an order on August 19, 2002 denying the motion to dismiss on the pleadings filed by all of the defendants involved in this action. On August 29, 2002, the Court heard oral argument on our motion to dismiss for lack of personal jurisdiction filed by ONEOK Gas Transportation, L.L.C., and numerous other defendants, but no decision has been rendered by the Court on that motion. Discovery on class certification and personal jurisdiction issues is proceeding.

Southern Union Company v. Southwest Gas Corporation, et al., No. CIV-99-1294-PHX-ROS, United States District Court for the District of Arizona. On August 6, 2002, Southwest and Southern Union settled their claims against each other. On September 24, 2002, the Court denied the Company’s pending motion for summary judgment on Southern Union’s claims. Trial on the remaining claims asserted by Southern Union against the Company and Messrs. Gaberino and Dubay was scheduled to begin October 15, 2002, but has been continued to a date to be set by the Court. The Court has scheduled a status conference for Southern Union and the Company for November 15, 2002. Trial of the claims brought by Southern Union against Messrs. Erwin and Rose commenced October 29, 2002.

ONEOK, Inc. v. Southwest Gas Corporation, No. 00-CV-063-H(E), United States District Court for the Northern District of Oklahoma, transferred, No. 00-1775-PHX-ROS, United States District Court for the District of Arizona; and Southwest Gas Corporation v. ONEOK, Inc., No. CIV-00-0119-PHX-ROS, United States District Court for the District of Arizona. These cases have been settled and have been dismissed with prejudice pursuant to the Court’s order of August 8, 2002. The payment by the Company of $3.0 million for the settlement has been made to Southwest Gas Corporation.

In the Matter of the Natural Gas Explosion at Hutchinson, Kansas during January, 2001, Case No. 02-E-0155, before the Secretary of the Department of Health and Environment. On August 9, 2002, we filed a request for a hearing on the Administrative Order issued by the Division of Environment of the Kansas Department of Health and Environment (KDHE) which assessed a $180,000 civil penalty against our Kansas Gas Service division. A status conference has been set for November 12, 2002.

Loyd Smith, et al. v. Kansas Gas Service Company, Inc., ONEOK, Inc., Western Resources, Inc., Mid Continent Market Center, Inc., ONEOK Gas Storage, L.L.C., ONEOK Gas

Storage Holdings, Inc., and ONEOK Gas Transportation, L.L.C., Case No. 01-C-0029, in the District Court of Reno County, Kansas, and Gilley, et al. v. Kansas Gas Service Company, Western Resources, Inc., ONEOK, Inc., ONEOK Gas Storage, L.L.C., ONEOK Gas Storage Holdings, Inc., ONEOK Gas Transportation, L.L.C., and Mid Continent Market Center, Inc., Case No. 01-C-0157, in the District Court of Reno County, Kansas. The court certified both class action lawsuits on June 6, 2002, and notice of the class action has been mailed to all potential class members. The opt-out date for potential class members to be excluded from the class is December 12, 2002.

United States ex rel. Jack J. Grynberg v. ONEOK, Inc., ONEOK Resources Company, and Oklahoma Natural Gas Company, (CTN-8), No. CIV-97-1006-R, United States District Court for the Western District of Oklahoma, transferred, In re Natural Gas Royalties Qui Tam Litigation, MDL Docket No. 1293, United States District Court for the District of Wyoming. The Court granted the United States’ motion to dismiss certain portions of plaintiff Grynberg’s complaint on grounds that the United States is the real party in interest and was able to show a legitimate governmental interest in seeking the dismissal. The legitimate governmental purpose accepted by the Court was to allow the United States to pursue its chosen valuation claims against selected defendants (other than ONEOK) in another forum. Because of the Court’s decision, plaintiff Grynberg will be required to amend his complaint and remove certain claims, which will reduce the number of issues that would otherwise need to be addressed in discovery and later proceedings. We expect discovery on jurisdictional issues pertaining to the claims that will remain to commence soon.

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

Not Applicable.

Item 6. Exhibits and Reports on Form 8-K

Exhibits

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

Exhibit No.		Exhibit Description

12		Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirement for the three and nine months ended September 30, 2002 and 2001.



12.1		Computation of Ratio of Earnings to Fixed Charges for the three and nine months ended September 30, 2002 and 2001.



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 September 30, 2002.


August 5, 2002—		Announced a tender offer for our $40,000,000 aggregate principal amount of outstanding 8.44% Senior Notes due January 31, 2004 and our $24,000,000 aggregate principal amount of outstanding 8.32% Senior Notes due July 31, 2007. We also announced our solicitation of consents to proposed amendments to the agreements for both sets of Notes that would effectively eliminate most of their restrictive covenants.



August 9, 2002—		Furnished as exhibits the Statement Under Oath of our Principal Executive Officer and our Principal Financial Officer regarding facts and circumstances related to Securities Exchange Act filings.



August 21, 2002—		Announced completion of our previously announced tender offer and consent solicitation for $40,000,000 of outstanding 8.44% Senior Notes due January 31, 2004 and $20,000,000 of outstanding 8.32% Senior Notes due July 31, 2007.



August 22, 2002—		Announced that we would not purchase our shares of common and preferred stock held by Westar Industries, Inc.



August 28, 2002—		Announced that Moody’s Investor Services downgraded our debt ratings with a negative outlook.



September 19, 2002—		Announced that Phyllis Worley was named President of our Kansas Gas Service Company division.



September 23, 2002—		Announced that we renewed our $850 million, 364-day credit agreement.

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
	By:	/s/ Jim Kneale
Date: November 12, 2002		Jim Kneale Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)

Certification

I, David L. Kyle, certify that:

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

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;

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;

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;

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

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: November 12, 2002	/s/ David L. Kyle
		Chief Executive Officer

Certification

I, Jim Kneale, certify that:

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

controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 12, 2002	/s/ Jim Kneale
		Chief Financial Officer