Edgar Filing: ONEOK INC /NEW/

Form 10-K - Amendment #1

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K/A

(Amendment No. 1)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 for the fiscal year ended December 31, 2001.

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 for the transition period

from to .

Commission file number 001-13643

ONEOK, Inc.

(Exact name of registrant as specified in its charter)

Oklahoma		73-1520922
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

100 West Fifth Street, Tulsa, OK		74103
(Address of principal executive offices)		(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:

Common stock, with par value of $0.01		New York Stock Exchange
(Title of Each Class)		(Name of Each Exchange on which Registered)

Securities registered pursuant to Section 12(g) of the Act:

None

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Registration S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Aggregate market value of registrant’s voting stock held by non-affiliates based on the closing trade price on March 8, 2002, was: Common stock of $ 1,167.6 million

On March 8, 2002, the Company had 60,248,668 shares of common stock outstanding.

Explanatory Statement:

The purpose of this Amendment No. 1 is to restate the Consolidated Statements of Cash Flows on p. 68 of the ONEOK, Inc. 2001 Annual Report on Form 10-K to correct mathematical errors related to the treatment of bank overdrafts, and to add Note U to the consolidated financial statements discussing the restatement. Except as amended as described above, the Consolidated Financial Statements of the Company being filed herewith (and included in the Company’s 10-K for the year ended December 31, 2001 as previously filed with the Securities and Exchange Commission) remain unchanged.

PART II.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Shareholders

ONEOK, Inc.:

We have audited the accompanying consolidated balance sheets of ONEOK, Inc. and subsidiaries as of December 31, 2001, 2000, and 1999, and the related consolidated statements of income, shareholders’ equity, and cash flows for the years ended December 31, 2001 and 2000, the year ended August 31, 1999 and the four months ended December 31, 1999. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of ONEOK, Inc. and subsidiaries as of December 31, 2001, 2000, and 1999, and the results of their operations and their cash flows for the years ended December 31, 2001 and 2000, the year ended August 31, 1999, and the four months ended December 31, 1999, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note U to the consolidated financial statements, the consolidated statements of cash flows for the years ended December 31, 2001 and 2000 and the four months ended December 31, 1999 have been restated.

As discussed in Notes A and C to the consolidated financial statements, the Company adopted the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, effective January 1, 2001 and the provisions of Emerging Issues Task Force 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, effective January 1, 2000.

KPMG LLP

Tulsa, Oklahoma

February 14, 2002, except as to Note U, which

is as of November 8, 2002

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31, 2001			Year Ended December 31, 2000		Four Months Ended December 31, 1999		Year Ended August 31, 1999

	(Thousands of Dollars, except per share amounts)
Operating Revenues *(Note A)*	$	6,803,146		$	6,642,858	$	806,478	$	1,838,949
Cost of gas		5,894,361			5,845,726		587,681		1,213,478

Net Revenues		908,785			797,132		218,797		625,471

Operating Expenses
Operations and maintenance		394,367			266,545		77,247		240,330
Depreciation, depletion, and amortization		157,310			143,351		43,227		129,704
General taxes		61,876			53,303		14,755		39,715

Total Operating Expenses		613,553			463,199		135,229		409,749

Operating Income		295,232			333,933		83,568		215,722

Other income, net		876			18,475		2,396		10,500
Interest expense		140,158			118,630		27,883		52,809
Income taxes		52,234			90,286		22,737		67,056

Income before cumulative effect of a change in accounting principle		103,716			143,492		35,344		106,357
Cumulative effect of a change in accounting principle, net of tax (Note A)		(2,151	)		2,115		—		—

Net Income		101,565			145,607		35,344		106,357
Preferred stock dividends		37,100			37,100		12,367		37,247

Income Available for Common Stock	$	64,465		$	108,507	$	22,977	$	69,110

Earnings Per Share of Common Stock (Note Q)
Basic	$	0.85		$	1.23	$	0.27	$	0.86

Diluted	$	0.85		$	1.23	$	0.27	$	0.86

Average Shares of Common Stock (Thousands)
Basic		99,449			98,340		100,742		103,102
Diluted		99,671			98,388		100,768		103,142

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

	December 31, 2001		December 31, 2000		December 31, 1999

	(Thousands of Dollars)
Assets
Current Assets
Cash and cash equivalents	$	28,229	$	249	$	72
Trade accounts and notes receivable, net		677,796		1,627,714		371,313
Materials and supplies		20,310		18,119		10,360
Gas in storage		82,694		57,800		124,511
Deferred income taxes		—		10,425		8,383
Purchased gas cost adjustment		45,098		1,578		8,105
Assets from price risk management activities (Note C)		587,740		1,416,368		—
Customer deposits		41,781		120,800		40,928
Other current assets		78,321		71,906		31,714

Total Current Assets		1,561,969		3,324,959		595,386

Property, Plant and Equipment
Marketing and Trading		3,979		2,795		2,047
Gathering and processing		1,040,195		1,001,994		385,260
Transportation and Storage		792,641		773,198		526,537
Distribution		1,985,177		1,860,181		1,766,057
Production		482,404		428,701		405,298
Power		118,193		75,891		17,193
Other		85,168		64,056		41,301

Total Property, Plant and Equipment		4,507,757		4,206,816		3,143,693
Accumulated depreciation, depletion, and amortization		1,234,789		1,110,803		1,021,915

Net Property		3,272,968		3,096,013		2,121,778

Deferred Charges and Other Assets
Regulatory assets, net (Note E)		232,520		238,605		247,486
Goodwill		113,868		92,909		80,743
Assets from price risk management activities (Note C)		475,066		405,666		—
Investments and other		222,768		202,193		195,847

Total Deferred Charges and Other Assets		1,044,222		939,373		524,076

Total Assets	$	5,879,159	$	7,360,345	$	3,241,240

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

	December 31, 2001			December 31, 2000			December 31, 1999

	(Thousdands of Dollars)
Liabilities and Shareholders’ Equity
Current Liabilities
Current maturities of long-term debt	$	250,000		$	10,767		$	21,767
Notes payable		599,106			824,106			462,242
Accounts payable		390,479			1,247,519			237,653
Accrued taxes		11,528			8,735			359
Accrued interest		31,954			24,161			16,628
Customers’ deposits		21,697			18,319			18,212
Liabilities from price risk management activities (Note C)		381,409			1,296,041			—
Other		132,244			96,913			29,852

Total Current Liabilities		1,818,417			3,526,561			786,713

Long-term Debt, excluding current maturities		1,498,012			1,336,082			775,074
Deferred Credits and Other Liabilities
Deferred income taxes		499,432			382,363			349,883
Liabilities from price risk management activities (Note C)		491,374			543,278			—
Lease obligation		122,011			137,131			—
Other deferred credits		184,623			209,973			178,046

Total Deferred Credits and Other Liabilities		1,297,440			1,272,745			527,929

Total Liabilities		4,613,869			6,135,388			2,089,716

Commitments and Contingencies *(Note K)*
Shareholders’ Equity
Convertible Preferred Stock, $0.01 par value:
Series A authorized 20,000,000 shares; issued and outstanding 19,946,448 shares at December 31, 2001, December 31, 2000, and December 31, 1999		199			199			199
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 63,438,441 shares and outstanding 60,002,218 shares at December 31, 2001; issued 63,198,610 shares and outstanding 59,176,550 shares at December 31, 2000; issued 63,198,610 shares and outstanding 59,109,246 shares at December 31, 1999		634			316			316
Paid in capital (Note G)		902,269			895,668			894,976
Unearned compensation		(2,000	)		(1,128	)		(1,846	)
Accumulated other comprehensive income (Note D)		(1,780	)		—			—
Retained earnings		415,513			387,789			317,985
Treasury stock at cost: 3,436,223 shares at December 31, 2001;
4,022,060 shares at December 31, 2000 and 4,089,364 shares at December 31, 1999		(49,545	)		(57,887	)		(60,106	)

Total Shareholders’ Equity		1,265,290			1,224,957			1,151,524

Total Liabilities and Shareholders’ Equity	$	5,879,159		$	7,360,345		$	3,241,240

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31, 2001 (Restated)			Year Ended December 31, 2000 (Restated)			Four Months Ended December 31, 1999 (Restated)			Year Ended August 31, 1999

	(Thousands of Dollars)
Operating Activities
Net income	$	101,565		$	145,607		$	35,344		$	106,357
Depreciation, depletion, and amortization		157,310			143,351			43,227			129,704
Unrecovered purchased gas cost adjustment		34,579			—			—			—
Gain on sale of assets		(1,120	)		(27,050	)		—			(6,639	)
Gain on sale of equity investments		(758	)		—			—			—
Income from equity investments		(8,109	)		(4,025	)		(1,063	)		(1,560	)
Deferred income taxes		134,933			26,143			28,317			14,925
Amortization of restricted stock		1,110			632			108			—
Allowance for doubtful accounts		43,495			6,048			436			4,029
Other		188			692			—			293
Changes in assets and liabilities:
Accounts and notes receivable		909,324			(1,262,449	)		(143,413	)		(54,716	)
Inventories		(11,906	)		(41,669	)		(15,920	)		19,429
Unrecovered purchased gas costs		(78,099	)		6,527			(3,553	)		(16,720	)
Regulatory assets		(8,387	)		(6,303	)		(3,841	)		(6,261	)
Other assets		37,201			(97,402	)		(5,457	)		(88,930	)
Accounts payable and accrued liabilities		(701,153	)		832,581			39,229			41,320
Price risk management assets and liabilities		(198,611	)		(64,574	)		—			—
Deferred credits and other liabilities		(6,211	)		78,559			(1,812	)		(7,034	)

Cash Provided by (Used In) Operating Activities		405,351			(263,332	)		(28,398	)		134,197

Investing Activities
Changes in other investments, net		1,194			68			994			(59,422	)
Acquisitions		(16,015	)		(494,904	)		(17,482	)		(344,494	)
Capital expenditures		(341,567	)		(311,403	)		(76,016	)		(164,170	)
Proceeds from sale of property		7,911			60,659			—			16,500
Proceeds from sale of equity investment		7,425			—			—			—

Cash Used in Investing Activities		(341,052	)		(745,580	)		(92,504	)		(551,586	)

Financing Activities
Borrowing of notes payable, net		(225,000	)		361,864			198,495			51,747
Change in bank overdraft		(141,923	)		168,145			22,699			—
Issuance of debt		401,367			590,000			—			695,888
Payment of debt		(7,583	)		(39,992	)		(36,952	)		(224,868	)
Issuance of common stock		5,447			—			—			1,087
Issuance (acquisition) of treasury stock, net		5,214			(453	)		(39,610	)		(22,570	)
Dividends paid		(73,841	)		(70,475	)		(28,060	)		(76,281	)
Acquisition and cancellation of preferred stock		—			—			—			(3,298	)

Cash Provided by (Used In) Financing Activities		(36,319	)		1,009,089			116,572			421,705

Change in Cash and Cash Equivalents		27,980			177			(4,330	)		4,316
Cash and Cash Equivalents at Beginning of Period		249			72			4,402			86

Cash and Cash Equivalents at End of Period	$	28,229		$	249		$	72		$	4,402

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

	Preferred Stock			Common Stock		Paid-in Capital			Unearned Compensation			Other Comprehensive Income		Retained Earnings			Treasury Stock			Total

	(Thousands of Dollars)
August 31, 1998	$	200		$	316	$	897,547		$	—		$	—	$	270,808		$	—		$	1,168,871
Net income		—			—		—			—			—		106,357			—			106,357
Issuance of common stock
Stock Purchase Plans		—			—		1,380			—			—		—			—			1,380
Convertible preferred stock dividends—$1.86 and $1.55per share for Series A andSeries B, respectively		—			—		—			—			—		(37,247	)		—			(37,247	)
Acquisition and Cancellation ofSeries B Convertible Preferred Stock		(1	)		—		(3,949	)		—			—		652			—			(3,298	)
Acquisition of Treasury Stock		—			—		—			—			—		—			(22,570	)		(22,570	)
Common stock dividends—$1.24 per share		—			—		—			—			—		(39,034	)		—			(39,034	)

August 31, 1999	$	199		$	316	$	894,978		$	—		$	—	$	301,536		$	(22,570	)	$	1,174,459
Net income		—			—		—			—			—		35,344			—			35,344
Re-issuance of treasury stock		—			—		(2	)		—			—		(131	)		141			8
Convertible preferred stock dividends—$.465 per sharefor Series A		—			—		—			—			—		(9,275	)		—			(9,275	)
Acquisition of treasury stock		—			—		—			—			—		—			(39,610	)		(39,610	)
Issuance of restricted stock		—			—		—			(1,933	)		—		—			1,933			—
Amortization of restricted stock		—			—		—			108			—		—			—			108
Common stock dividends—$0.31 per share		—			—		—			(21	)		—		(9,489	)		—			(9,510	)

December 31, 1999	$	199		$	316	$	894,976		$	(1,846	)	$	—	$	317,985		$	(60,106	)	$	1,151,524

See accompanying Notes to Consolidated Financial Statements

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

	Preferred Stock		Common Stock		Paid-in Capital			Unearned Compensation			Other Comprehensive Income			Retained Earnings			Treasury Stock			Total

	(Thousands of Dollars)
December 31, 1999	$	199	$	316	$	894,976		$	(1,846	)	$	—		$	317,985		$	(60,106	)	$	1,151,524
Net income		—		—		—			—			—			145,607			—			145,607
Re-issuance of treasury stock		—		—		—			—			—			(2,572	)		14,196			11,624
Issuance of common stock
Stock purchase plans		—		—		692			—			—			—			—			692
Convertible preferred stock dividends—$1.86 per share for Series A		—		—		—			—			—			(37,100	)		—			(37,100	)
Acquisition of treasury stock		—		—		—			—			—			—			(11,812	)		(11,812	)
Issuance of restricted stock		—		—		—			(137	)		—			—			137			—
Amortization of restricted stock		—		—		—			632			—			—			—			632
Forfeitures of restricted stock		—		—		—			302			—			—			(302	)		—
Common stock dividends— $1.24 per share		—		—		—			(79	)		—			(36,131	)		—			(36,210	)

December 31, 2000	$	199	$	316	$	895,668		$	(1,128	)	$	—		$	387,789		$	(57,887	)	$	1,224,957
Net income		—		—		—			—			—			101,565			—			101,565
Other comprehensive income		—		—		—			—			(1,780	)		—			—			(1,780	)

Total comprehensive income																					99,785
Effect of two-for-one stock split		—		317		(317	)		—			—						—			—
Re-issuance of treasury stock		—		—		866			—			—			—			7,278			8,144
Issuance of common stock
Stock purchase plans		—		1		5,317			—			—			—			—			5,318
Convertible preferred stock dividends—$1.86 per share for Series A		—		—		—			—			—			(37,100	)		—			(37,100	)
Acquisition of treasury stock		—		—		—			—			—			—			(29	)		(29	)
Issuance of restricted stock		—		—		715			(1,932	)		—			—			1,217			—
Amortization of restricted stock		—		—		—			1,110			—			—			—			1,110
Forfeitures of restricted stock		—		—		20			78			—			—			(124	)		(26	)
Common stock dividends— $0.62 per share		—		—		—			(128	)		—			(36,741	)		—			(36,869	)

December 31, 2001	$	199	$	634	$	902,269		$	(2,000	)	$	(1,780	)	$	415,513		$	(49,545	)	$	1,265,290

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(A) SUMMARY OF ACCOUNTING POLICIES

Nature of Operations—ONEOK, Inc. and subsidiaries (collectively, the “Company” or “ONEOK”) is a diversified energy company engaged in the production, processing, gathering, storage, transportation, distribution, and marketing of natural gas, electricity and natural gas liquids. The Company manages its business in seven segments: Marketing and Trading, Gathering and Processing, Transportation and Storage, Distribution, Production, Power and Other.

The Marketing and Trading segment purchases and markets natural gas, primarily in the mid-continent region of the United States. The Company owns and operates gas processing plants as well as gathering pipelines in Oklahoma, Kansas and Texas through its Gathering and Processing segment. The Transportation and Storage segment owns and leases natural gas storage facilities and transports gas in Oklahoma, Kansas and Texas. The Company’s Distribution segment provides natural gas distribution services in Oklahoma and Kansas through its divisions Oklahoma Natural Gas Company (ONG) and Kansas Gas Service Company (KGS). The Production segment produces natural gas and oil and owns natural gas and oil reserves. The Power segment produces and markets electricity to wholesale customers. The Company’s Other segment, whose results of operations are not material, operates and leases the Company’s headquarters building and parking facility and has an investment in Magnum Hunter Resources, Inc., an independent oil and gas company.

Critical Accounting Policies

Energy Trading and Risk Management Activities—The Company engages in price risk management activities for both trading and non-trading purposes. On January 1, 2000, the Company adopted Emerging Issues Task Force Issue No. 98-10, “Accounting for Energy Trading and Risk Management Activities” (EITF 98-10) for its energy trading contracts. EITF 98-10 requires entities involved in energy trading activities to account for energy trading contracts using mark-to-market accounting. Prior to the adoption of EITF 98-10, the Company accounted for its trading activities on the accrual method based on settlement of physical and financial positions. The adoption of EITF 98-10 was accounted for as a change in accounting principle and the cumulative effect at January 1, 2000 of $2.1 million, net of tax, was recognized. Forwards, swaps, options, and energy transportation and storage contracts utilized for trading activities are reflected at fair value as assets and liabilities from price risk management activities in the consolidated balance sheets. The fair value of these assets and liabilities are affected by the actual timing of settlements related to these contracts and current period changes resulting primarily from newly originated transactions and the impact of price movements. Changes in fair value are recognized in net revenues in the consolidated statements of income. Market prices used to fair value 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 present market conditions.

See Note C of Notes to Consolidated Financial Statements.

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). ONG and KGS 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 rate-making and regulatory purposes may differ from bases generally applied by non-regulated operations. Such allocations to meet regulatory accounting requirements are considered to be generally accepted accounting principles for regulated utilities provided that there is a demonstrable ability to recover any deferred costs in future rates.

During the rate-making 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 a regulatory asset and amortized to expense as they are recovered through rates. Total regulatory assets resulting from this deferral process are approximately $232.5 million, $238.6 million and $247.5 million at December 31, 2001, 2000 and 1999, respectively. Although no further unbundling of services is anticipated, should this occur, certain of these assets may no longer meet the criteria for following Statement 71 and, accordingly, a write-off of regulatory assets and stranded costs may be required. However, the Company does not anticipate that these costs, if any, will be significant. See Note E of Notes to the Consolidated Financial Statements.

KGS has a two-year rate moratorium, which expires in November 2002. ONG is not subject to a rate moratorium.

Impairments—The Company accounts for the impairment of long-lived assets to be recognized when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets carrying amount. 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. The Company evaluates impairment of assets on the lowest possible level.

Significant Accounting Policies

Consolidation—The consolidated financial statements include the accounts of ONEOK, Inc. and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. Investments in twenty percent to 50 percent-owned affiliates are accounted for on the equity method. Investments in less than twenty percent owned affiliates are accounted for on the cost method.

Cash and Cash Equivalents—Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less.

Inventories—Materials and supplies are valued at average cost. Noncurrent gas in storage is classified as property and is valued at cost. The Marketing and Trading segment’s gas in storage, which is recorded in current price risk management assets, is carried at fair value. Cost of current gas in storage for ONG is determined under the last-in, first-out, (LIFO) methodology. The estimated replacement cost of current gas in storage valued under the lifo method was $1.3 million, $12.3 million, and $7.3 million at December 31, 2001, 2000 and 1999, respectively, compared to its value under the LIFO method of $3.0 million, $4.6 million, and $5.7 million at December 31, 2001, 2000 and 1999, respectively. Current gas in storage for all other companies is determined using the weighted average cost of gas method.

Derivative Instruments and Hedging Activities—To minimize the risk from fluctuations in the price of natural gas and crude oil, the Company’s non-trading segments periodically enter into futures transactions, swaps, and options in order to hedge anticipated sales of natural gas and crude oil production, fuel requirements and inventories in its natural gas liquids business. Interest rate swaps are also used to manage interest rate risk.

Prior to 2001, in order to qualify as a hedge, the price movements in the underlying commodity derivatives had to be sufficiently correlated with the hedged transaction. Gains and losses from hedging transactions were recognized in income and reflected as cash flows from operating activities in the periods for which the underlying commodity or interest rate transactions were hedged. If the necessary correlation to the commodity or interest rate transaction being hedged was not maintained, the Company ceased to account for the contract as a hedge and recognized a gain or loss in current earnings to the extent the contract results had not been offset by the effects of the price or interest rate changes on the hedged item. If the underlying commodity or interest rate transaction being hedged by the derivative was disposed of or otherwise terminated, the gain or loss associated with such derivatives was no longer deferred and was recognized in the period the underlying was eliminated.

On January 1, 2001, the Company adopted the provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133), amended by Statement No. 137 and Statement No. 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 Financial Accounting Standards Board (FASB) relating to the Derivatives Implementation Group (DIG) process. The FASB 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.

See Note C of Notes to Consolidated Financial Statements.

Regulated Property—Regulated properties are stated at cost, which includes an allowance for funds used during construction. The allowance for funds used during construction represents the capitalization of the estimated average cost of borrowed funds (6.0 percent, 6.9 percent, 6.8 percent, and 7.8 percent, in fiscal years 2001 and 2000, the four months ended December 31, 1999, and the year ended August 31, 1999, respectively) used during the construction of major projects and is recorded as a credit to interest expense.

Depreciation is calculated using the straight-line method based upon rates prescribed for ratemaking purposes. The average depreciation rate for property that is regulated by the OCC approximated 2.9 percent in fiscal year 2001, 3.0 percent in fiscal year 2000, 4.1 percent in the four months ended December 31, 1999, and 3.8 percent in the year ended August 31,1999. The average depreciation rates for properties regulated by the KCC, excluding Mid-Continent Market Center (the Market Center), were approximately 3.4 percent in fiscal year 2001, 3.3 percent in fiscal year 2000, 3.4 percent in the four months ended December 31, 1999, and 3.2 percent in the year ended August 31, 1999. The average depreciation rates for the Market Center properties were 3.4 percent in fiscal year 2001, 3.3 percent in fiscal year 2000, 3.1 percent in the four months ended December 31, 1999, and 3.1 percent in the year ended August 31, 1999.

Maintenance and repairs are charged directly to expense. Generally, the cost of property retired or sold, plus removal costs, less salvage, is charged to accumulated depreciation. Gains and losses from sales or transfers of operating units or systems are recognized in income.

	Remaining Life	Service Years

Distribution property	22-25	40
Transmission property	18-33	47
Other property	6-24	40

Production Property—The Company uses the successful-efforts method to account for costs incurred in the acquisition and development of natural gas and oil reserves. Costs to acquire mineral interests in proved reserves and to drill and equip development wells are capitalized. Geological and geophysical costs and costs to drill exploratory wells which do not find proved reserves are expensed. Unproved oil and gas properties, which are individually significant, are periodically assessed for impairment. The remaining unproved oil and gas properties are aggregated and amortized based upon remaining lease terms and exploratory and developmental drilling experience. Depreciation and depletion are calculated using the unit-of-production method based upon periodic estimates of proved oil and gas reserves.

Other Property—Gas processing plants and all other properties are stated at cost. Gas processing plants are depreciated using various rates based on estimated lives of available gas reserves. All other property and equipment is depreciated using the straight-line method over its estimated useful life.

Goodwill—Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is amortized over a period of 30 to 40 years. The Company assesses the recoverability of this intangible asset by determining whether the amortization of the goodwill balance over its remaining life can be recovered through undiscounted future operating cash flows of the acquired operation. The amount of goodwill impairment, if any, is measured based on projected discounted future operating cash flows using a discount rate reflecting the Company’s average cost of funds. The assessment of the recoverability of goodwill will be impacted if estimated future operating cash flows are not achieved.

Environmental Expenditures—The Company accrues for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as further information develops or circumstances change. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.

Revenue Recognition—The Company’s Marketing and Trading, Gathering and Processing, Transportation and Storage, Distribution and Power segments recognize revenue when services are rendered or product is delivered. Major industrial and commercial gas distribution customers are invoiced as of the end of each month. Certain gas distribution customers, primarily residential and some commercial, are invoiced on a cycle basis throughout the month, and the Company accrues unbilled revenues at the end of each month. ONG’s and KGS’s tariff rates for residential and commercial customers contain a temperature normalization clause that provides for billing adjustments from actual volumes to normalized volumes during the winter heating season.

Revenues from the Production segment are recognized on the sales method when oil and gas production volumes are delivered to the purchaser.

Income Taxes—Deferred income taxes are recognized for the tax consequences of “temporary differences” by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. The effect on deferred taxes of a change in tax rates is deferred and amortized for operations regulated by the OCC and KCC and for all other operations, is recognized in income in the period that includes the enactment date. The Company continues to amortize previously deferred investment tax credits over the period prescribed by the OCC and KCC for ratemaking purposes.

Common Stock Options and Awards—The Company follows Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (Statement 123) which permits, but does not require, a fair value based method of accounting for stock-based employee compensation. Alternatively, Statement 123 allows companies to continue applying the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25), however, such companies are required to disclose pro forma net income and earnings per share as if the fair value based method had been applied. The Company has elected to continue to apply the provisions of APB 25 for purposes of computing compensation expense and has provided the pro forma disclosure provisions of Statement 123 in Note P of Notes to Consolidated Financial Statements.

Earnings Per Common Share—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), the Company revised its computation of earnings per common share (EPS). In accordance with Topic D-95, the dilutive effect of the Company’s Series A Convertible Preferred Stock is now considered in the computation of basic EPS, utilizing the “if-converted” method. Under the Company’s “if-converted” method, the dilutive effect of the 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 common stock and the participating Series A Convertible Preferred Stock according to dividends declared and participating rights in the undistributed earnings. The 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. The Company restated the EPS amounts for all periods to be consistent with the revised methodology. See Note Q of Notes to Consolidated Financial Statements.

Use of Estimates—Certain amounts included in or affecting the Company’s financial statements and related disclosures must be estimated, requiring the Company to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. Items which may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, obligations under employees benefit plans, provisions for uncollectible accounts receivable, unbilled revenues for gas delivered but for which meters have not been read, gas purchased expense for gas received but for which no invoice has been received, the results of litigation and various other recorded or disclosed amounts. Accordingly, the reported amounts of the Company’s assets and liabilities, revenues and expenses and related disclosures are necessarily affected by these estimates.

The Company evaluates these estimates on an ongoing basis using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on the Company’s financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

Reclassification—Certain amounts in prior period consolidated financial statements have been reclassified to conform to the 2001 presentation.

(B) ACQUISITIONS AND DISPOSITIONS

On April 5, 2000, the Company acquired certain natural gas gathering and processing assets located in Oklahoma, Kansas and West Texas from Kinder Morgan, Inc. (KMI). The Company also acquired KMI’s marketing and trading operations, as well as some storage and transmission pipelines in the mid-continent region. The Company paid approximately $123.5 million for these assets plus working capital of approximately $53 million, which was subject to adjustment. The working capital adjustment was made in the first quarter 2001, resulting in the Company receiving approximately $4.0 million. The Company also assumed an operating lease for a processing plant for which the Company established a liability of approximately $157.7 million for an uneconomic lease obligation. The Company also assumed some firm capacity lease obligations to unaffiliated parties for which the Company established a reserve of approximately $220.1 million for out-of-market terms of those obligations. The acquisition was accounted for as a purchase. The results of operations of this acquisition are included in the consolidated statement of income subsequent to the purchase date.

The table of unaudited pro forma information set forth below, presents a summary of consolidated results of operations of the Company as if the acquisition of the businesses acquired from KMI had occurred at the beginning of the periods presented. The results do not necessarily reflect the results that would have been obtained if the acquisition had actually occurred on the dates indicated or the results that may be expected in the future.

	Pro Forma Years Ended
	December 31, 2000		August 31, 1999

(Thousands of Dollars, except per share amounts)
Operating revenues	$	7,596,667	$	5,623,102
Net income	$	153,087	$	107,271
Income available for common shareholders	$	115,987	$	70,024
Earnings Per Share of Common Stock—Diluted	$	1.29	$	0.87

In March 2000, the Company completed the sale of its 42.4 percent interest in Indian Basin Gas Processing Plant and gathering system for $55 million.

In March 2000, the Company completed the acquisition of assets located in Oklahoma, Kansas, and the Texas panhandle from Dynegy, Inc. for $305 million in cash, which included a $3 million adjustment for working capital. The assets include gathering systems, gas processing facilities, and transmission pipelines.

On January 20, 2000, the Board of Directors of the Company voted unanimously to terminate the merger agreement with Southwest Gas Corporation (Southwest) in accordance with the terms of the merger agreement. The Company charged $3.7 million of ongoing litigation costs to Other income, net for the year ended December 31, 2001. The Company charged $13.7 million of previously deferred transaction and litigation costs to Other income, net for the year ended December 31, 2000. See Note K of Notes to Consolidated Financial Statements.

In May 1999, the Company acquired the Oklahoma midstream natural gas gathering and processing assets of Koch Midstream Enterprises (Koch) for $285 million in cash. The assets acquired include eight natural gas processing plants and approximately 3,250 miles of gathering pipeline connected to 1,460 gas wells in Oklahoma.

(C) PRICE RISK MANAGEMENT ACTIVITIES AND FINANCIAL INSTRUMENTS

Market risks are monitored by a risk control group which operates independently from the operating segments that create or actively manage these risk exposures. The risk control group ensures compliance with the Company’s risk management policies.

Risk Policy and Oversight—The Company controls the scope of risk management, marketing and trading operations through a comprehensive set of policies and procedures involving senior levels of management. The Company’s Board of Directors affirms the risk limit parameters with its 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 value-at-risk (VAR) and position loss limits. The Company has a corporate risk control organization lead by the 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 the financial results and financial position of the Company either favorably or unfavorably. As a result, the Company cannot predict with precision the impact risk management decisions may have on the business, operating results or financial position.

Trading Activities

The Company’s operating results are impacted by commodity price fluctuations. The Company routinely enters into derivative financial instruments in order to minimize the risk of commodity price fluctuations related to its purchase and sale commitments, fuel requirements, transportation and storage contracts and inventories in its natural gas marketing and trading business.

The Marketing and Trading segment includes the Company’s wholesale and retail natural gas marketing and trading operations. The Marketing and Trading segment generally attempts to balance its fixed-price physical and financial purchase and sales commitments in terms of contract volumes and the timing of performance and delivery obligations. To the extent a net open position exists, fluctuating commodity market prices can impact the Company’s financial position and results of operations, either favorably or unfavorably. The net open positions are actively managed and the impact of the changing prices on the Company’s financial condition at a point in time is not necessarily indicative of the impact of price movements throughout the year.

Fair value—The fair value and the average fair value of derivative financial instruments, purchase and sale commitments, fuel requirements, transportation and storage contracts and inventories related to trading price risk management activities held during 2001 and 2000 are set forth as follows:

	Fair Value December 31, 2001				Average Fair Value (a) December 31, 2001
	Assets		Liabilities		Assets		Liabilities

	(Thousands of Dollars)
Energy commodities	$	1,039,611	$	854,219	$	1,094,946	$	975,359

(a)

Computed using the ending balance at the end of each quarter.

	Fair Value December 31, 2000				Average Fair Value (a) December 31, 2000
	Assets		Liabilities		Assets		Liabilities

	(Thousands of Dollars)
Energy commodities	$	1,822,034	$	1,839,319	$	1,254,446	$	1,394,605

(a)

Computed using the ending balance at the end of each quarter.

The Company did not hold any other commodity type contracts for trading price risk management purposes at December 31, 2001.

Notional value—The notional contractual quantities associated with trading price risk management activities are set forth as follows:

	Volumes Purchased	Volumes Sold

December 31, 2001:
Natural gas options (Bcf)	118.3	107.7
Crude oil options (MBbls)	5.6	5.4
Natural gas swaps (Bcf)	1,917.9	1,898.4
Crude oil swaps (MBbls)	—	6.0
Natural gas futures (Bcf)	159.9	220.7
Crude oil futures (MBbls)	19.9	69.8

December 31, 2000:
Natural gas options (Bcf)	75.3	65.7
Crude oil options (MBbls)	—	—
Natural gas swaps (Bcf)	683.6	733.8
Crude oil swaps (MBbls)	—	—
Natural gas futures (Bcf)	114.3	112.7
Crude oil futures (MBbls)	—	—

Notional amounts reflect the volume and indicated activity of transactions but do not represent the amounts exchanged by the parties or cash requirements associated with these financial instruments. Accordingly, notional amounts do not accurately measure the Company’s exposure to market or credit risk.

Credit Risk—In conjunction with the market valuation of its energy commodity contracts, the Company provides reserves for risks associated with its contract commitments, including credit risk. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company maintains credit policies with regard to its counterparties that management believes significantly minimize overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements which allow for netting of positive and negative exposures associated with a single counterparty.

Counterparties in its trading portfolio consist primarily of financial institutions, major energy companies, and local distribution companies. This concentration of counterparties may impact the Company’s overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Based on the Company’s policies, its exposures and its credit and other reserves, the Company does not anticipate a material adverse effect on financial position or results of operations as a result of counterparty nonperformance.

Non-Trading Activities

Financial instruments are also utilized for non-trading purposes to hedge natural gas and crude oil production anticipated sales, fuel requirements and inventories in its natural gas liquids business to hedge the impact of fair value fluctuations. 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.

Operating margins associated with the Gathering and Processing segment’s natural gas gathering, processing and fractionation activities are sensitive to changes in natural gas liquids prices, principally as a result of contractual terms under which natural gas is processed and products are sold and the availability of inlet volumes. Also, certain processing plant assets are impacted by changes in, and the relationship between, natural gas and natural gas liquids prices, which, in turn influences the volumes of gas processed.

In 2000, the Company entered into derivative instruments related to the production of natural gas, most of which expired in 2001. These derivative instruments were designed as cash flow hedges to hedge the Production segment’s exposure to changes in the price of natural gas. Changes in the fair value of the derivative instruments are reflected initially in other comprehensive income (loss) and subsequently realized in earnings when the forecasted transaction affects earnings. 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 are designated as cash flow hedging instruments, which primarily consisted of costless option collars and swaps on natural gas production.

The Company recognized $3.5 million in earnings, representing the ineffective portion of the cash flow hedges for the year ended December 31, 2001. The Company realized an $18.4 million loss in earnings that was reclassified from accumulated other comprehensive loss resulting from the settlement of contracts when the natural gas was sold. These gains and losses are reported in Operating Revenues. Other comprehensive income of $1.8 million at December 31, 2001 includes approximately $1.3 million related to a cash flow hedge for 2002 production, which will be realized within the next year when the financial transactions affect earnings.

In July 2001, the Company entered into interest rate swaps, which were designated fair value hedges, 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, 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, which were designated fair value hedges, on a total of $200 million in fixed rate long-term debt. The Company recorded a $7.4 million net increase in price risk management assets and liabilities to recognize the interest rate swaps at fair value. Long-term debt was also increased to recognize the change in fair value of the related hedged liability. See Note I of Notes to Consolidated Financial Statements

Fair value—The following table represents the estimated fair values of derivative instruments related to the Company’s non-trading price risk management activities. The fair value is the carrying value for these instruments at December 31,2001 and they have no carrying value at December 31, 2000 and August 31, 1999.

	Approximate Fair Value

(Thousands of Dollars)
December 31, 2001
Natural gas commodities—cash flow hedges	$	1,249
Interest rate swaps—fair value hedges	$	7,379
Natural gas commodities—other	$	(3,997	)

December 31, 2000
Natural gas commodities	$	(41,623	)

August 31, 1999
Natural gas commodities	$	(11,540	)

Notional value—The Company was a party to natural gas commodity derivative instruments including swaps and options covering 19.0 Bcf and 32.9 Bcf of natural gas for December 31, 2001 and 2000, respectively.

The Company utilized derivative contracts to mitigate its risk associated with weather for the month of November 2000 to reduce the impact of degree day deviations from normal weather. The Company did not have any weather hedges in place at December 31, 2001 and 2000.

Credit Risk—The Company maintains credit policies with regard to its counterparties that management believes significantly minimize overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements which allow for netting of positive and negative exposures associated with a single counterparty.

The counterparties to the non-trading instruments include large integrated energy companies. Accordingly, the Company does not anticipate a material adverse effect on financial position or results of operations as a result of counterparty nonperformance.

Financial Instruments

The following table represents the carrying amounts and estimated fair values of the Company’s financial instruments, excluding trading activities, which are marked to market, and non-trading commodity instruments, which are listed in the table above.

	Book Value		Approximate Fair Value

	*(Thousands of Dollars)*
December 31, 2001
Cash and cash equivalents	$	28,229	$	28,229
Accounts and notes receivable	$	677,796	$	677,796
Notes payable	$	599,106	$	599,106
Long-term debt	$	1,751,539	$	1,773,798

	Book Value		Approximate Fair Value

	(Thousands of Dollars)
December 31, 2000
Cash and cash equivalents	$	249	$	249
Accounts and notes receivable	$	1,627,714	$	1,627,714
Notes payable	$	824,106	$	824,106
Long-term debt	$	1,350,689	$	1,302,104

	Book Value		Approximate Fair Value

	(Thousands of Dollars)
December 31,1999
Cash and cash equivalents	$	72	$	72
Accounts and notes receivable	$	371,313	$	371,313
Notes payable	$	462,242	$	462,242
Long-term debt	$	800,731	$	753,298

The fair value of cash and cash equivalents, accounts and notes receivable and notes payable approximate book value due to their short term nature. The estimated fair value of long-term debt has been determined using quoted market prices of the same or similar issues, discounted cash flows, and/or rates currently available to the Company for debt with similar terms and remaining maturities.

(D) COMPREHENSIVE INCOME

The table below gives an overview of Other comprehensive income at December 31, 2001, which includes the cumulative effect of a change in accounting principle due to the adoption of Statement 133, realized and unrealized gains and losses on derivative instruments and an adjustment to the Company’s pension liability.

	Year Ended December 31, 2001

	(Thousands of Dollars)
Net income				$	101,565
Other comprehensive income (loss):
Cumulative effect of a change in accounting principle	$	(45,556	)
Unrealized gains on derivative instruments		28,491
Realized losses in net income		18,383
Minimum pension liability adjustment		(4,252	)

Other comprehensive loss before taxes		(2,934	)
Income tax benefit on other comprehensive loss		1,154

Other comprehensive loss				$	(1,780	)

Comprehensive income				$	99,785

(E) REGULATORY ASSETS

The table presents a summary of regulatory assets, net of amortization, at December 31, 2001, 2000 and 1999.

	December 31, 2001		December 31, 2000		December 31, 1999

	(Thousands of Dollars)
Recoupable take-or-pay	$	75,336	$	79,324	$	84,343
Pension costs		11,124		15,306		19,487
Postretirement costs other than pension		60,170		61,069		62,207
Transition costs		21,598		22,199		22,746
Reacquired debt costs		22,351		23,209		24,068
Income taxes		28,365		30,727		23,337
Other		13,576		6,771		11,298

Regulatory assets, net	$	232,520	$	238,605	$	247,486

The remaining recovery period for these assets that the Company is not earning a return on is set forth in the table below.

	December 31, 2001		Remaining Recovery Period

	(Thousands of Dollars)		(Months)
Postretirement costs other than pension – Oklahoma	$	7,876	141
Income taxes – Oklahoma	$	9,374	114-130
Transition costs	$	21,598	431

The OCC directed ONG to assume responsibility for, and ownership of, customer service lines and has authorized the Company to defer as regulatory assets the depreciation and operation and maintenance expenses incurred in connection with this plan. The recovery methodology, amount, and calculation of these deferrals will be addressed in ONG’s next rate case filing. Through December 2001, the Company has deferred approximately $801,000 associated with this Commission directive. These deferred costs are included in the caption “Other” in the above table of regulatory assets.

The OCC has authorized ONG to defer the incremental costs associated with a five-year cathodic protection program to be implemented to comply with the OCC’s Pipeline Safety Department inspection reports. The recovery methodology and amount of these deferred expenses will be addressed in ONG’s next rate case filing. Through December 2001, the Company has deferred approximately $1.9 million associated with this program. These deferred costs are included in the caption “Other” in the above table of regulatory assets.

The OCC has authorized recovery of the take-or-pay settlement, pension and postretirement benefit costs over a 10 to 20 year period. KGS has been deferring and recording postretirement benefits in excess of pay-as-you-go as a regulatory asset as authorized by the KCC. See Note J of Notes to Consolidated Financial Statements.

The KCC has allowed certain transition costs to be amortized and recovered in rates over a 40-year period with no rate of return on the unrecovered balance. Management believes that all transition costs recorded as a regulatory asset will be recovered through rates based on the accounting orders received and regulatory precedents established by the KCC.

The Company amortizes reacquired debt costs, which includes unamortized debt costs, in accordance with the accounting rules prescribed by the OCC and KCC. These costs have been included in recent rate filings with the OCC and will be included in future rate filings with the KCC as a component of interest.

In accordance with various rate orders received from the KCC and the OCC, KGS has not yet collected through rates the amounts necessary to pay a significant portion of the net deferred income tax liabilities. As management believes it is probable that the net future increases in income taxes payable will be recovered from customers, it has recorded a regulatory asset for these amounts.

Recovery through rates resulted in amortization of regulatory assets of approximately $11.3 million and $10.6 million for the years ended December 31, 2001 and 2000, respectively, $3.1 million for the four months ended December 31, 1999, and $13.7 million for the year ended August 31, 1999.

(F) CAPITAL STOCK

The Company has approximately 176 million shares of authorized and unreserved common stock available for issue. The Company issued Series A Convertible Preferred Stock, par value $0.01 per share, at the time of the November 1997 transaction with Western Resources, Inc. The holders of Series A Convertible Preferred Stock are entitled to receive a dividend payment, with respect to each dividend period of the common stock, equal to 3.0 times the dividend amount declared in respect of each share of common stock for the first five years of the agreement. In November 2002, the rate is reduced to 2.5 times the dividend amount declared in respect of each share of common stock, and at no time will the dividend be less than $1.80 per share on an aggregate annual basis. The dividend multiple has been adjusted to reflect the two-for-one common stock split described below.

The terms of Series B Convertible Preferred Stock were the same as Series A Convertible Preferred Stock, except that the dividend amount was equal to the greater of 2.5 times the common stock dividend, and at no time will the dividend be less than $1.50 per share on an aggregate annual basis during the first five years after the agreement and not less than $1.80 on an aggregate annual basis thereafter. In 1999, the Company acquired and canceled all of the Series B Convertible Preferred Stock it had issued in 1998 and 1999.

Series C Preferred Stock is designed to protect ONEOK, Inc. shareholders from coercive or unfair takeover tactics. Holders of Series C Preferred Stock are entitled to receive, in preference to the holders of ONEOK common stock, quarterly dividends in an amount per share equal to the greater of $0.50 or subject to adjustment, 100 times the aggregate per share amount of all cash dividends, and 100 times the aggregate per share amount (payable in kind) of all non-cash dividends. No Series C Preferred Stock has been issued.

The Series A Convertible Preferred Stock is convertible, subject to certain restrictions, at the option of the holder, into ONEOK, Inc., Common Stock at the rate of two shares for each share of Series A Convertible Preferred Stock.

On January 18, 2001, the Company’s Board of Directors approved, and on May 17, 2001, the shareholders of the Company voted in favor of, a two-for-one common stock split, which was effected through the issuance of one additional share of common stock for each share of common stock outstanding to holders of record on May 23, 2001, with distribution of the shares on June 11, 2001. The Company retained the current par value of $0.01 per share for all shares of common stock. Shareholders’ equity reflects the stock split by reclassifying from Paid in Capital to Common Stock an amount equal to the cumulative par value of the additional shares issued to effect the split. All share and per share amounts contained herein for all periods reflect this stock split. Outstanding convertible preferred stock is assumed to convert to common stock on a two-for-one basis in the calculations of earnings per share.

During 2001, the Company began a second stock buyback plan for up to 10 percent of its capital stock. The program authorizes the Company to make purchases of its common stock on the open market with the timing and terms of purchases and the number of shares purchased to be determined by management based on market conditions and other factors. Through December 31, 2001, no shares have been purchased under this plan. The purchased shares are held in treasury and available for general corporate purposes, funding of stock-based compensation plans, resale at a future date, or retirement. Purchases are financed with short-term debt or are made from available funds.

During 1999, the Company initiated a stock buyback plan for up to 15 percent of its capital stock. The program authorized the Company to make purchases of its common stock on the open market with the timing and terms of purchases and the number of shares purchased to be determined by management based on market conditions and other factors. This plan was terminated in April 2001. Through April 30, 2001, the shares purchased under this plan totaled 5.1 million, which has been adjusted for the two-for-one stock split. The purchased shares are held in treasury and available for general corporate purposes, funding of stock-based compensation plans, resale at a future date, or retirement. Purchases were financed with short-term debt or were made from available funds. This plan expired in 2001.

The Board of Directors has reserved 12.0 million shares of ONEOK, Inc.’s common stock for the Direct Stock Purchase and Dividend Reinvestment Plan, of which 424,000 shares were issued in fiscal year 2001, 190,000 shares were issued in fiscal year 2000, 56,000 shares were issued in the four months ended December 31, 1999, and 254,000 shares were issued in the year ended August 31, 1999. In January 2001, the Company amended and restated, in entirety, the existing Direct Stock Purchase and Dividend Reinvestment Plan. The Company has reserved approximately 13.2 million shares for the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries less the number of shares issued to date under this plan.

Under the most restrictive covenants of the Company’s loan agreements, $226.6 million (54.5 percent) of retained earnings were available to pay dividends at December 31, 2001.

(G) PAID IN CAPITAL

Paid in capital was $338.1 million, $331.5 million and $330.8 million for common stock at December 31, 2001, 2000 and 1999, respectively. Paid in capital for convertible preferred stock was $564.2 million at December 31, 2001, 2000 and 1999.

(H) LINES OF CREDIT AND SHORT-TERM NOTES PAYABLE

Commercial paper and short-term notes payable totaling $599.1 million, of which $275.0 million was used to purchase natural gas that was injected into storage, was outstanding at December 31, 2001. Commercial paper and short-term notes payable totaling $824.1 million and $462.2 million were outstanding at December 31, 2000 and 1999, respectively. The commercial paper and notes carried average interest rates of 4.25 percent, 6.53 percent, and 6.47 percent at December 31, 2001, 2000 and 1999, respectively. The Company has a $850 million short-term unsecured revolving credit facility, which provides a back-up line of credit for commercial paper in addition to providing short-term funds. Interest rates and facility fees are based on prevailing market rates and the Company’s credit ratings. No amounts were outstanding under the line of credit and no compensating balance requirements existed at December 31, 2001. Maximum short-term debt from all sources as approved by the Company’s Board of Directors is $1.2 billion.

(I) LONG-TERM DEBT

The aggregate maturities of long-term debt outstanding at December 31, 2001, are $250 million; $10 million; $50 million; $360 million; and $310 million for 2002 through 2006, respectively, including $6 million, which is callable at the option of the holder in each of those years. All long-term notes payable at December 31, 2001, are unsecured.

In 2001, the Company issued a $400 million note at a rate of 7.125%. The proceeds from the note were used to refinance short-term debt. The Company issued $240 million of two-year floating rate notes in April 2000. The interest rate for these notes resets quarterly at a 0.65 percent spread over the three month London InterBank Offered Rate (LIBOR). The proceeds from the notes were used to fund acquisitions. In March 2000, the Company issued $350 million of five year, 7.75 percent, fixed rate notes to refinance short-term debt and finance acquisitions.

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 LIBOR or the six-month LIBOR 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. The Company recorded a $7.4 million net increase in price risk management assets to recognize at fair value its derivatives that are designated as fair value hedging instruments. Long-term debt was increased by approximately $7.4 million to recognize the change in fair value of the related hedged liability. The swaps generated $5.3 million of interest rate savings during 2001. See further discussion of interest rate risk in Note C of Notes to the Consolidated Financial Statements.

	December 31, 2001		December 31, 2000		December 31, 1999

	(Thousands of Dollars)
Long-term Notes Payable
6.43% due 2000	$	—	$	—	$	5,000
7.25% due 2001		—		767		1,535
3.95% due 2002		240,000		240,000		—
8.44% due 2004		40,000		40,000		40,000
7.75% due 2005		350,000		350,000		—
7.75% due 2006		300,000		300,000		300,000
8.32% due 2007		24,000		28,000		32,000
6.00% due 2009		100,000		100,000		100,000
7.125% due 2011		400,000		—		—
6.40% due 2019		94,913		96,502		99,308
9.70% due 2019		—		—		8,826
9.75% due 2020		—		—		15,305
6.50% due 2028		93,880		95,420		98,757
6.875% due 2028		100,000		100,000		100,000

Total Long-term Notes Payable		1,742,793		1,350,689		800,731
Change in fair value of hedged debt		7,379		—		—
Other long-term debt		1,367		—		—
Unamortized debt discount		3,527		3,840		3,890
Current maturities		250,000		10,767		21,767

Long-term debt	$	1,498,012	$	1,336,082	$	775,074

(J) EMPLOYEE BENEFIT PLANS

Retirement Plans—The Company has defined benefit and defined contribution retirement plans covering substantially all employees. Company officers and certain key employees are also eligible to participate in supplemental retirement plans. The Company generally funds pension costs at a level equal to the minimum amount required under the Employee Retirement Income Security Act of 1974.

Other Postretirement Benefit Plans—The Company sponsors welfare care plans that provide postretirement medical benefits and life insurance benefits to substantially all employees who retire under the Retirement Plans with at least five years of service. Non-bargaining unit employees retiring between the ages of 50 and 55 have access to the Company provided medical benefits. Non-bargaining unit employees retiring at age 55 or older are eligible for both the Company provided medical and life insurance benefits. The plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance.

The Company elected to delay recognition of the accumulated postretirement benefit obligation (APBO) and amortize it over 20 years as a component of net periodic postretirement benefit cost.

The following tables set forth the Company’s pension and other postretirement benefit plans benefit obligations, fair value of plan assets, and funded status at December 31, 2001, 2000 and 1999.

	Pension Benefits									Postretirement Benefits
	December 31,									December 31,
	2001			2000			1999			2001			2000			1999

	(Thousands of Dollars)
Change in Benefit Obligation
Benefit obligation, beginning of period	$	481,879		$	495,061		$	504,865		$	136,157		$	146,589		$	160,371
Service cost		9,751			9,365			2,829			3,074			3,566			1,297
Interest cost		36,188			34,806			11,431			10,195			10,312			3,636
Participant contributions		—			—			—			1,476			1,173			334
Plan amendments		—			—			—			—			(7,816	)		(10,893	)
Actuarial (gain)/loss		21,504			(25,965	)		(13,973	)		13,626			(5,228	)		(4,786	)
Benefits paid		(33,226	)		(31,388	)		(10,091	)		(9,969	)		(12,439	)		(3,370	)

Benefit obligation, end of period	$	516,096		$	481,879		$	495,061		$	154,559		$	136,157		$	146,589


Change in Plan Assets
Fair value of assets, beginning of period	$	747,635		$	640,330		$	660,386		$	24,110		$	17,837		$	17,500
Actual return on assets		(128,527	)		137,791			(10,198	)		374			1,941			(674	)
Employer contributions		1,407			902			233			3,263			4,332			1,011
Benefits paid		(33,226	)		(31,388	)		(10,091	)		—			—			—

Fair value of assets, end of period	$	587,289		$	747,635		$	640,330		$	27,747		$	24,110		$	17,837


Funded status - over(under)	$	71,193		$	265,756		$	145,269		$	(126,812	)	$	(112,048	)	$	(128,752	)
Unrecognized net asset		(1,248	)		(1,715	)		(2,182	)		—			—			—
Unrecognized transition obligation		—			—			—			22,903			24,758			34,332
Unrecognized prior service cost		6,112			6,934			7,756			—			—			877
Unrecognized net (gain)loss		27,177			(188,392	)		(79,969	)		25,976			9,689			16,356
Activity subsequent to measurement date		—			—			—			586			(793	)		(998	)

(Accrued)prepaid pension cost	$	103,234		$	82,583		$	70,874		$	(77,347	)	$	(78,394	)	$	(78,185	)


Actuarial Assumptions
Discount rate		7.35	%		7.75	%		7.25	%		7.35	%		7.75	%		7.25	%
Expected rate of return		9.85	%		9.25	%		9.25	%		9.85	%		9.25	%		9.25	%
Compensation increase rate		4.50	%		4.50	%		4.50	%		4.50	%		4.50	%		4.50	%

	Pension Benefits
	Year Ended December 31, 2001			Year Ended December 31, 2000			Four Months Ended December 31, 1999			Year Ended August 31, 1999

Components of Net Periodic Benefit Cost
Service cost	$	9,751		$	9,365		$	2,829		$	9,282
Interest cost		36,188			34,806			11,431			32,832
Expected return on assets		(61,161	)		(55,566	)		(17,581	)		(46,846	)
Amortization of unrecognized net asset at adoption		(467	)		(467	)		(156	)		(467	)
Amortization of unrecognized prior service cost		822			822			274			177
Amortization of (gain)/loss		(4,377	)		233			92			786

Net periodic benefit cost	$	(19,244	)	$	(10,807	)	$	(3,111	)	$	(4,236	)

	Postretirement Benefits
	Year Ended December 31, 2001			Year Ended December 31, 2000			Four Months Ended December 31, 1999			Year Ended August 31, 1999

Components of Net Periodic Benefit Cost
Service cost	$	3,074		$	3,566		$	1,297		$	4,036
Interest cost		10,195			10,312			3,636			10,055
Expected return on assets		(2,364	)		(1,792	)		(616	)		(1,325	)
Amortization of unrecognized net transition obligation at adoption		1,954			2,512			1,025			3,235
Amortization of unrecognized prior service cost		—			—			66			—
Amortization of loss		234			430			154			688

Net periodic benefit cost	$	13,093		$	15,028		$	5,562		$	16,689

For measurement purposes, a 6.10 percent annual rate of increase in the per capita cost of covered medical benefits (i.e., medical cost trend rate) was assumed for 2001. The rate was assumed to decrease gradually to 5 percent by the year 2003 and remain at that level thereafter. The medical cost trend rate assumption has a significant effect on the amounts reported. For example, increasing the assumed medical cost trend by one percentage point in each year would increase the accumulated postretirement benefit obligation as of December 31, 2001, by $12.3 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year ended December 31, 2001, by $1.3 million. Decreasing the assumed medical cost trend by one percentage point in each year would decrease the accumulated postretirement benefit obligation as of December 31, 2001, by $10.3 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year ended December 31, 2001, by $1 million.

Employee Thrift Plan—The Company has a Thrift Plan covering substantially all employees. Employee contributions are discretionary. Subject to certain limits, employee contributions are matched by the Company. The cost of the plan was $8.8 million and $6.7 million in fiscal years 2001 and 2000, respectively; $2.3 million for the four months ended December 31, 1999; and $6.3 million for the year ended August 31, 1999.

Postemployment Benefits—The Company pays postemployment benefits to former or inactive employees after employment but before normal retirement in compliance with specific separation agreements.

Regulatory Treatment—The OCC has approved the recovery of ONG pension costs and other postretirement benefit costs through rates. The costs recovered through rates are based on current funding requirements and the net periodic postretirement benefit cost for pension and postretirement costs, respectively. Differences, if any, between the expense and the amount ordered through rates are charged to earnings.

Prior to the acquisition of the assets regulated by the KCC in fiscal 1998, Western had established a corporate-owned life insurance (“COLI”) program which it believed in the long term would offset the expenses of its postretirement and postemployment benefit plans. Accordingly, the KCC issued an order permitting the deferral of postretirement and postemployment benefit expenses in excess of amounts recognized on a pay-as-you-go basis. The Company did not acquire the COLI program. In connection with the KCC’s approval of the acquisition, the KCC granted the Company the benefit of all previous accounting orders issued to Western and requested that the Company submit a plan of recovery either through a general rate increase or through specific cost savings or revenue increases. Based on regulatory precedents established by the KCC and the accounting order, which permits the Company to seek recovery through rates, management believes that it is probable that accrued postretirement and postemployment benefits can be recovered in rates. The Company plans to file for recovery of these costs when the rate moratorium expires and anticipates that recovery will be allowed over a period not to exceed approximately 10 years. If these costs cannot be recovered in rates charged to customers, the Company would be required to record a one-time charge to expense for the regulatory asset established for postretirement and postemployment benefit costs totaling approximately $52.3 million at December 31, 2001.

(K) COMMITMENTS AND CONTINGENCIES

Leases—The initial term of the Company’s headquarters building, ONEOK Plaza, is for 25 years, expiring in 2009, with six five-year renewal options. At the end of the initial term or any renewal period, the Company can purchase the property at its fair market value. Annual rent expense for the lease will be approximately $6.8 million until 2009. Rent payments were $9.3 million in fiscal years 2001 and 2000, $2.9 million for the four months ended December 31, 1999, and $5.8 million for the year ended August 31,1999. Estimated future minimum rental payments for the lease are $9.3 million for each of the years ending December 31, 2002 through 2009.

The Company has the right to sublet excess office space in ONEOK Plaza. The Company received rental revenue of $3.5 million in fiscal years 2001 and 2000, $1.0 million for the four months ended December 31, 1999, and $2.8 million for the year ended August 31,1999, for various subleases. Estimated minimum future rental payments to be received under existing contracts for subleases are $3.2 million in 2002, $2.7 million in 2003, $2.1 million in 2004, $1.3 million in 2005, $1.2 million in 2006 and a total of $0.7 million thereafter.

Other operating leases include a gas processing plant, office buildings, and equipment. Future minimum lease payments under non-cancelable operating leases (with initial or remaining lease terms in excess of one year) as of December 31, 2001 are $33.0 million in 2002, $25.1 million in 2003, $24.6 million in 2004, $27.4 million in 2005 and $40.7 million in 2006. The above amounts include the following minimum lease payments relating to the lease of a gas processing plant: $21.3 million in 2002, $16.2 million in 2003, $20.9 million in 2004, $24.2 million in 2005 and $37.7 million in 2006. The Company has a liability for uneconomic lease terms relating to the gas processing plant. Accordingly, the liability is amortized to rent expense in the amount of $13.0 million per year over the term of the lease.

Enron—Certain of the financial instruments discussed previously in Note C of the Notes to the Consolidated Financial Statements have Enron North America as the counterparty. Enron Corporation and various subsidiaries, including Enron North America (Enron), filed for protection from creditors under Chapter 11 of the United States Bankruptcy Code on December 3, 2001. The Company has provided an allowance for forward financial positions and also established an allowance for uncollectible accounts relating to previously settled financial and physical positions with Enron at December 31, 2001. The Company estimates its claim against Enron to be approximately $74 million. The ultimate resolution of any claims ONEOK may have against Enron cannot be determined at this time.

The filing of the voluntary bankruptcy proceeding by Enron created a possible technical default related to various financing leases tied to the Company’s Bushton gas processing plant in south central Kansas. The Company acquired the Bushton gas processing plant and related leases from KMI in April 2000. KMI had previously acquired the plant and leases from Enron. Enron is one of three guarantors of these Bushton plant leases; however, the Company is the primary guarantor. In January 2002, the company was granted a waiver on the possible technical default related to these leases. The Company will continue to make all payments due under these leases.

Southwest Gas Corporation—In connection with the now terminated proposed acquisition of Southwest Gas Corporation (Southwest), the Company is party to various lawsuits. The Company and certain of its 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, Racketeer Influenced and Corrupt Organizations Act violations and improper interference in a contractual relationship between Southwest and Southern Union. The original claim asked for $750 million damages to be trebled for racketeering and unlawful violations, compensatory damages of not less than $750 million and rescission of the Confidentiality and Standstill Agreement.

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 a prospective relationship with Southwest; however, the Court’s ruling limited any recovery by Southern Union to out-of-pocket damages and punitive damages. The Company expects to file a Motion for Summary Judgment seeking a dismissal of this single remaining claim and for punitive damages. Based on discovery at this point, the Company believes that Southern Union’s out-of-pocket damages potentially recoverable at trial, exclusive of legal fees and expenses, are less than $1.0 million.

Southwest filed a lawsuit against the Company and Southern Union alleging, among other things, fraud and breach of contract. Southwest is seeking damages in excess of $75,000. In an order dated January 4, 2002, the Court denied Southwest’s Motion for Partial Summary Judgment in its favor on its claims against the Company, granted in part the Company’s Motion for Summary Judgment against Southwest, and denied the Company’s Motion for Summary Judgment in part with respect to Southwest’s claims for fraud in the inducement and fraud. Based on discovery at this point, the Company believes that Southwest’s actual damages potentially recoverable at trial, exclusive of legal fees and expenses, are less than $5.5 million.

The lawsuits described above have been consolidated for purposes of trial. The Court has entered an order setting the cases for jury trial on October 15, 2002.

Two substantially identical derivative actions were filed by shareholders against members of the Board of Directors of the Company for alleged 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 merger with Southwest for alleged waste of corporate assets. These two cases were consolidated into one case. Such conduct allegedly 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 actions 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, if any, associated with these matters. If substantial damage were ultimately awarded, it 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 Southwest and all other matters relating to the now terminated proposed acquisition of Southwest.

Environmental—The Company has 12 manufactured gas sites located in Kansas, which may contain potentially harmful materials that are classified as hazardous material. Hazardous materials are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE presently governs all future work at these sites. The terms of the consent agreement allow the Company to investigate these sites and set remediation priorities based upon the results of the investigations and risk analysis. The prioritized sites will be investigated over a period of time as negotiated with the KDHE. Through December 31, 2001, the costs of the investigations 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 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 the amounts estimated above. To the extent that such remediation costs are not recovered, the costs could be material to the Company’s results of operations and cash flows depending on the remediation done and number of years over which the remediation is completed.

In January 2001, the Yaggy storage facility, located in Hutchison, Kansas, was idled following natural gas explosions and eruptions of natural gas geysers. There are no known long-term environmental effects from the Yaggy storage facility, however, the Company continues to perform tests in cooperation with the KDHE.

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 to determine if they were consistent with least cost procurement practices and whether the Company’s decisions resulted in fair, just and reasonable costs being borne by its 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 effective with the first billing cycle for the month following the issuance of a final order. A final order, which was 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 will allow ONG to commence collecting gas charges, subject to refund should the Company ultimately lose the case. The stay will be in effect while the matter is before the Oklahoma Supreme Court. Although the Company believes that decisions made by the Company were prudent based upon the facts and circumstances existing at the time the decisions were made, which is the standard applicable to the Proceeding as stated by the OCC, the Company has taken a charge of $34.6 million in the fourth quarter of 2001 as a result of this order. This charge is recorded as an increase in gas purchase expense in the Distribution segment. The Company will continue to assert its legal rights and is hopeful that a resolution of this issue can be negotiated.

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. Although no assurances can be given, management believes that the ultimate resolution of these matters will not have a material adverse effect on its financial position or results of operations. ONEOK and its subsidiaries are being represented by their insurance carrier in these cases. The Company is vigorously defending itself against all claims.

In April 1998, an application filed with the OCC alleged that ONG has charged and continues to charge its ratepayers, through its PGA, excessive, imprudent and unwarranted gas purchase costs related to a contract with Dynamic Energy Resources, Inc. The Consumer Services Divisions (CSD) of the OCC conducted a review of the contract. The applicants and the CSD filed their direct testimony in February 2002. ONG is to file rebuttal testimony on April 21, 2002. The hearing before the Commission is scheduled for June 3, 2002.

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 consolidated results of operations, financial position, or liquidity.

(L) INCOME TAXES

The provisions for income taxes are as follows:

	Year Ended December 31, 2001			Year Ended December 31, 2000		Four Months Ended December 31, 1999			Year Ended August 31, 1999

	(Thousands of Dollars)
Current income taxes
Federal	$	(69,273	)	$	55,764	$	(6,345	)	$	48,760
State		(13,426	)		8,379		765			3,371

Total current income taxes		(82,699	)		64,143		(5,580	)		52,131

Deferred income taxes
Federal		127,750			23,947		25,938			13,671
State		7,183			2,196		2,379			1,254

Total deferred income taxes		134,933			26,143		28,317			14,925

Total provision for income taxes before cummulative effect of a change in accounting principle		52,234			90,286		22,737			67,056

Total provision for income taxes for the cummulative effect of a change in accounting principle		(1,356	)		1,334		—			—

Total provision for income taxes	$	50,878		$	91,620	$	22,737		$	67,056

Following is a reconciliation of the provision for income taxes.

	Year Ended December 31, 2001			Year Ended December 31, 2000			Four Months Ended December 31, 1999			Year Ended August 31, 1999

	(Thousands of Dollars)
Pretax income	$	152,442		$	233,778		$	58,081		$	173,413
Federal statutory income tax rate		35	%		35	%		35	%		35	%

Provision for federal income taxes		53,355			81,822			20,328			60,695
Amortization of distribution property investment tax credit		(764	)		(807	)		(302	)		(1,103	)
State income taxes, net of federal tax benefit		(4,058	)		6,874			2,044			5,737
Other, net		2,345			3,731			667			1,727

Actual income tax expense	$	50,878		$	91,620		$	22,737		$	67,056

The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities are shown in the accompanying table.

	December 31, 2001		December 31, 2000		December 31, 1999

	(Thousands of Dollars)
Deferred tax assets
Accrued liabilities not deductible until paid	$	180,331	$	173,493	$	8,383
Net operating loss carryforward		36,972		1,665		1,317
Regulatory assets		9,956		4,734		3,760
Other		2,057		4,277		1,982

Total deferred tax assets		229,316		184,169		15,442
Valuation allowance for net operating loss carryforward expected to expire prior to utilization		6,693		1,230		882

Net deferred tax assets		222,623		182,939		14,560
Deferred tax liabilities
Excess of tax over book depreciation and depletion		578,876		461,560		262,515
Investment in joint ventures		12,198		11,280		11,414
Regulatory assets		95,836		78,186		75,407
Other		38,472		3,851		6,724

Total deferred tax liabilities		725,382		554,877		356,060

Net deferred tax liabilities	$	502,759	$	371,938	$	341,500

The Company has remaining net operating loss carryforwards for federal and state income tax purposes of approximately $84 million and $115 million, respectively, at December 31, 2001, which expire, unless previously utilized, at various dates through the year 2020. At December 31, 2001, the Company had $6.7 million in deferred investment tax credits recorded in other deferred credits, which will be amortized over the next 14 years.

(M) SEGMENT INFORMATION

Management has divided its operations into the following reportable segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment.

The Company conducts its operations through seven segments: (1) the Marketing and Trading segment markets natural gas to wholesale and retail 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; (4) the Distribution segment distributes natural gas to residential, commercial and industrial customers and leases pipeline capacity to others; (5) the Production segment produces natural gas and oil; (6) the Power segment markets electricity to wholesale customers, and (7) the Other segment primarily operates and leases the Company’s headquarters building and a related parking facility and owns an investment in Magnum Hunter Resources, Inc.

The accounting policies of the segments are substantially the same as those described in the summary of significant accounting policies. Intersegment sales are recorded on the same basis as sales to unaffiliated customers. All corporate overhead costs relating to a reportable segment have been allocated for the purpose of calculating operating income. The Company’s equity method investments do not represent operating segments of the Company.

The Power segment has a signed definitive agreement with an unaffiliated company for a 15-year term providing the customer with the right to purchase approximately 25 percent of the plant’s generating capacity. There are no single external customers from which the Company receives ten percent or more of consolidated revenues.

Year Ended December 31, 2001	Marketing and Trading		Gathering and Processing		Transportation and Storage		Distribution		Production			Power		Other and Eliminations			Total

	*(Thousands of Dollars)*
Sales to unaffiliated customers	$	4,293,526	$	814,963	$	76,837	$	1,506,420	$	94,144		$	28,092	$	(10,836	)	$	6,803,146
Intersegment sales		614,698		499,854		102,133		4,548		26,173			—		(1,247,406	)	$	—

Total Revenues	$	4,908,224	$	1,314,817	$	178,970	$	1,510,968	$	120,317		$	28,092	$	(1,258,242	)	$	6,803,146

Net revenues	$	103,429	$	189,621	$	129,344	$	353,393	$	120,317		$	6,858	$	5,823		$	908,785
Operating costs	$	31,488	$	116,853	$	52,497	$	230,137	$	27,361		$	1,358	$	(3,451	)	$	456,243
Depreciation, depletion and amortization	$	597	$	29,201	$	19,190	$	69,159	$	35,017		$	2,014	$	2,132		$	157,310
Operating income	$	71,344	$	43,567	$	57,657	$	54,097	$	57,939		$	3,486	$	7,142		$	295,232
Cumulative effect of a change in accounting principle, net of tax	$	—	$	—	$	—	$	—	$	(2,151	)	$	—	$	—		$	(2,151	)
Income from equity investments	$	—	$	—	$	2,946	$	—	$	111		$	—	$	5,052		$	8,109
Total assets	$	1,369,220	$	1,322,438	$	797,331	$	1,688,670	$	321,720		$	122,404	$	257,376		$	5,879,159
Capital expenditures	$	1,184	$	51,442	$	35,911	$	129,937	$	55,974		$	42,302	$	24,817		$	341,567


Year Ended December 31, 2000	Marketing and Trading		Gathering and Processing		Transportation and Storage		Distribution		Production			Power		Other and Eliminations			Total

	(Thousands of Dollars)
Sales to unaffiliated customers	$	4,362,024	$	839,388	$	111,644	$	1,270,369	$	50,686		$	—	$	8,747		$	6,642,858
Intersegment sales		299,657		197,325		56,814		3,568		19,669			—		(577,033	)	$	—

Total Revenues	$	4,661,681	$	1,036,713	$	168,458	$	1,273,937	$	70,355		$	—	$	(568,286	)	$	6,642,858

Net revenues	$	66,482	$	224,012	$	125,582	$	377,277	$	70,355		$	—	$	(66,576	)	$	797,132
Operating costs	$	14,321	$	90,501	$	44,785	$	211,629	$	24,228		$	—	$	(65,616	)	$	319,848
Depreciation, depletion and amortization	$	887	$	22,692	$	18,639	$	67,717	$	30,884		$	—	$	2,532		$	143,351
Operating income	$	51,274	$	110,819	$	62,158	$	97,931	$	15,243		$	—	$	(3,492	)	$	333,933
Cumulative effect of a change in accounting principle, net of tax	$	2,115	$	—	$	—	$	—	$	—		$	—	$	—		$	2,115
Income from equity investments	$	—	$	—	$	3,240	$	—	$	125		$	—	$	660		$	4,025
Total assets	$	3,035,227	$	1,507,546	$	661,894	$	2,007,351	$	308,041		$	77,426	$	(237,140	)	$	7,360,345
Capital expenditures	$	815	$	32,383	$	37,701	$	124,983	$	34,035		$	58,697	$	22,789		$	311,403

Four Months Ended December 31, 1999	Marketing and Trading		Gathering and Processing		Transportation and Storage		Distribution		Production			Power		Other and Eliminations			Total

	(Thousands of Dollars)
Sales to unaffiliatedcustomers	$	365,224	$	63,869	$	13,283	$	337,890	$	18,692		$	—	$	7,520		$	806,478
Intersegment sales		17,825		15,032		25,868		1,334		4,779			—		(64,838	)	$	—

Total Revenues	$	383,049	$	78,901	$	39,151	$	339,224	$	23,471		$	—	$	(57,318	)	$	806,478

Net revenues	$	11,493	$	19,413	$	34,491	$	129,870	$	23,471		$	—	$	59		$	218,797
Operating costs	$	3,344	$	8,588	$	10,184	$	69,455	$	7,245		$	—	$	(6,814	)	$	92,002
Depreciation, depletion and amortization	$	242	$	2,513	$	5,124	$	24,815	$	9,715		$	—	$	818		$	43,227
Operating income	$	7,907	$	8,312	$	19,183	$	35,600	$	6,511		$	—	$	6,055		$	83,568
Income (loss) from equity investments	$	—	$	—	$	1,074	$	—	$	(11	)	$	—	$	—		$	1,063
Total assets	$	287,375	$	368,904	$	437,561	$	1,776,273	$	301,821		$	19,330	$	49,976		$	3,241,240
Capital expenditures	$	9	$	14,613	$	5,837	$	34,167	$	6,411		$	13,445	$	1,534		$	76,016

Year Ended August 31, 1999	Marketing and Trading		Gathering and Processing		Transportation and Storage		Distribution		Production		Power		Other and Eliminations			Total

	(Thousands of Dollars)
Sales to unaffiliatedcustomers	$	772,331	$	72,277	$	27,892	$	915,782	$	44,026	$	—	$	6,641		$	1,838,949
Intersegment sales		53,067		11,513		79,993		8,168		22,868		—		(175,609	)	$	—

Total Revenues	$	825,398	$	83,790	$	107,885	$	923,950	$	66,894	$	—	$	(168,968	)	$	1,838,949

Net revenues	$	35,443	$	31,311	$	102,910	$	393,461	$	66,894	$	—	$	(4,548	)	$	625,471
Operating costs	$	9,069	$	11,207	$	28,919	$	219,945	$	19,128	$	—	$	(8,223	)	$	280,045
Depreciation, depletion and amortization	$	503	$	3,562	$	13,852	$	75,443	$	34,073	$	—	$	2,271		$	129,704
Operating income	$	25,871	$	16,542	$	60,139	$	98,073	$	13,693	$	—	$	1,404		$	215,722
Income from equity investments	$	—	$	—	$	1,501	$	—	$	59	$	—	$	—		$	1,560
Total assets	$	269,444	$	343,133	$	373,742	$	1,722,381	$	310,715	$	4,047	$	1,483		$	3,024,945
Capital expenditures	$	448	$	8,557	$	32,618	$	98,685	$	16,046	$	3,748	$	4,068		$	164,170

(N) QUARTERLY FINANCIAL DATA (UNAUDITED)

Total operating revenues are consistently greater during the heating season from November through March due to the large volume of natural gas sold to customers for heating. A summary of the unaudited quarterly results of operations for the years ended December 31, 2001 and 2000, respectively, follows:

Year Ended December 31, 2001	First Quarter		Second Quarter			Third Quarter			Fourth Quarter

	(Thousands of dollars, except per share amounts)
Operating revenues	$	2,956,924	$	1,402,399		$	1,126,696		$	1,317,127
Operating income	$	143,046	$	71,942		$	55,733		$	24,511
Other income (expense)	$	3,299	$	566		$	(1,914	)	$	(1,075	)
Income taxes	$	41,800	$	12,651		$	301		$	(2,518	)
Net Income (Loss)	$	64,859	$	23,608		$	18,787		$	(5,689	)
Earnings per share of common stock
Basic	$	0.55	$	0.20		$	0.16		$	(0.05	)
Diluted	$	0.54	$	0.20		$	0.16		$	(0.05	)
Dividends per share of common stock	$	0.155	$	0.155		$	0.155		$	0.155
Average shares of common stock outstanding
Basic		99,214		99,407			99,521			99,648
Diluted		99,596		99,733			99,633			99,887


Year Ended December 31, 2000	First Quarter		Second Quarter			Third Quarter			Fourth Quarter

	(Thousands of dollars, except per share amounts)
Operating revenues	$	822,713	$	1,385,565		$	1,754,234		$	2,680,346
Operating income	$	105,821	$	76,067		$	48,525		$	103,520
Other income (expense)	$	15,517	$	(952	)	$	(1,073	)	$	4,983
Income taxes	$	38,446	$	19,610		$	5,029		$	27,201
Net Income	$	63,022	$	27,162		$	10,086		$	45,337
Earnings per share of common stock
Basic	$	0.53	$	0.23		$	0.01		$	0.38
Diluted	$	0.53	$	0.23		$	0.01		$	0.38
Dividends per share of common stock	$	0.155	$	0.155		$	0.155		$	0.155
Average shares of common stock outstanding
Basic		98,376		98,284			98,292			98,408
Diluted		98,378		98,292			98,300			98,752

During the fourth quarter of 2001, the Company took a charge of $34.6 million against operating income related to unrecovered gas costs associated with the 2000/2001 winter. The Company also took a charge of $37.4 million against operating income during the same period related to the Enron bankruptcy filing. For further discussion of these charges, see Note K of the Notes to Consolidated Financial Statements.

(O) SUPPLEMENTAL CASH FLOW INFORMATION

The table presents supplemental information relative to the Company’s cash flows for the years ended December 31, 2001 and 2000, the four months ended December 31, 1999, and the year ended August 31, 1999.

	Year Ended December 31, 2001		Year Ended December 31, 2000			Four Months Ended December 31, 1999		Year Ended August 31, 1999

	(Thousands of Dollars)
Cash paid during the year
Interest (including amounts capitalized)	$	132,364	$	111,097		$	16,605	$	50,498
Income taxes	$	13,050	$	57,579		$	—	$	59,466

Noncash transactions
Treasury stock transferred to compensation plans	$	—	$	61		$	2,071	$	—
Gas received as payment in kind	$	—	$	—		$	—	$	135

Acquisitions
Property, plant, and equipment	$	1,515	$	832,849		$	17,482	$	338,138
Current assets		—		74,012			—		—
Current liabilities		—		(20,996	)		—		—
Regulatory assets and goodwill		14,500		17,663			—		10,817
Lease obligation		—		(157,651	)		—		—
Price risk management activities		—		(239,660	)		—		—
Deferred credits		—		(11,313	)		—		—
Deferred income taxes		—		—			—		(4,461	)

Cash paid – acquisitions	$	16,015	$	494,904		$	17,482	$	344,494

(P) STOCK BASED COMPENSATION

Stock Splits—Due to the 2001 stock split, the number of shares and related exercise prices have been adjusted to maintain both the total market value of common stock underlying the options and Employee Stock Purchase Plan (ESPP) share elections, and the relationship between the fair market value of the common stock and the exercise price of the options and ESPP share elections.

Stock Option Plans

Long-Term Incentive Plan—The ONEOK, Inc. Long-Term Incentive Plan provides for the granting of incentive stock options, non-statutory stock options, stock bonus awards, and restricted stock awards to key employees and the granting of stock awards to non-employee directors. The Company has reserved approximately 7.8 million shares of common stock for the plan less the number of shares previously issued under the plan. The maximum numbers of shares for which options or other awards may be granted to any employee during any year is 300,000.

Under the plan, options may be granted by the Executive Compensation Committee (the Committee). Stock options and awards may be granted at any time until all shares authorized are transferred, except that no incentive stock option may be granted under the plan after August 17, 2005. Options may be granted which are not exercisable until a fixed future date or in installments. The plan also provides for restored options to be granted in the event an optionee surrenders shares of common stock which the optionee already owns in full or partial payment of the option price of an option being exercised and/or surrenders shares of common stock to satisfy withholding tax obligations incident to the exercise of an option. A restored option is for the number of shares surrendered by the optionee and has an option price equal to the fair market value of the common stock on the date on which the exercise of an option resulted in the grant of the restored option.

Options issued to date become void upon voluntary termination of employment other than retirement. In the event of retirement or involuntary termination, the optionee may exercise the option within three months. In the event of death, the option may be exercised by the personal representative of the optionee within a period to be determined by the Committee and stated in the option. A portion of the options issued to date can be exercised after one year from grant date and an option must be exercised no later than ten years after grant date.

Stock Compensation Plan for Non-Employee Directors—The ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors provides for the granting of incentive stock bonus awards, performance unit awards, restricted stock awards, and non-qualified stock options to Non-Employee Directors. The Company has reserved 700,000 shares less the number of shares previously issued under the plan. The maximum number of shares of common stock with respect to which options or other awards may be granted to any Non-Employee Director during any year is 20,000.

Under the plan, options may be granted by the Committee at any time on or before January 18, 2011. Options may be exercisable in full at the time of grant or may become exercisable in one or more installments. The plan also provides for restored options in the event that the optionee surrenders shares of common stock which the optionee already owns in full or partial payment of the option price of an option being exercised and/or surrenders shares of common stock to satisfy withholding tax obligations incident to the exercise of an option. A restored option is for the number of shares surrendered by the optionee, and has an option price equal to the fair market value of the common stock on the date the exercise of an option resulted in the grant of the restored option. Options issued to date become void upon termination of service as a Non-Employee Director. Such options must be exercised no later than ten years after the date of grant of the option. In the event of death, the option may be exercised by the personal representative of the optionee.

Stock option activity has been restated to give effect to the 2001 two-for-one stock split. Activity to date has been as follows:

	Number of Shares		Weighted Average Exercise Price

Outstanding August 31, 1998	701,952		$	15.65
Granted	531,448		$	17.61
Exercised	(55,900	)	$	13.44
Expired	(5,000	)	$	17.45
Restored	71,690		$	17.98

Outstanding August 31, 1999	1,244,190		$	16.55
Granted	617,400		$	14.58
Exercised	(2,000	)	$	11.85
Expired	(6,000	)	$	17.61
Restored	1,726		$	13.69

Outstanding December 31, 1999	1,855,316		$	15.89
Granted	8,000		$	13.16
Exercised	(342,822	)	$	15.38
Expired	(74,200	)	$	16.01
Restored	55,062		$	21.45

Outstanding December 31, 2000	1,501,356		$	16.19
Granted	1,102,000		$	22.43
Exercised	(118,750	)	$	15.27
Expired	(179,672	)	$	19.57
Restored	3,538		$	22.49

Outstanding December 31, 2001	2,308,472		$	18.96


Options Exercisable

August 31, 1999	709,990		$	15.75
December 31, 1999	841,540		$	16.05
December 31, 2000	813,894		$	16.27
December 31, 2001	941,572		$	16.57

At December 31, 2001, the Company had 1,157,952 outstanding options with exercise prices ranging between $11.85 to $17.78 and a weighted average remaining life of 7.02 years. Of these options, 803,252 were exercisable at December 31, 2001 with a weighted average exercise price of $16.04.

The Company also had 1,150,520 options outstanding at December 31, 2001 with exercise prices ranging between $17.78 and $26.67 and a weighted average remaining life of 8.62 years. Of these options, 138,320 were exercisable at December 31, 2001 at a weighted average exercise price of $19.64.

Restricted Stock Awards—Under the Long-Term Incentive Plan, restricted stock awards also may be granted to key officers and employees. Ownership of the common stock vests over a three year period. Shares awarded may not be sold during the vesting period. The fair market value of the shares associated with the restricted stock awards is recorded as unearned compensation in shareholders’ equity and is amortized to compensation expense over the vesting period. The dividends on the restricted stock awards are reinvested in common stock. These shares fully vest three years after the grant date of the restricted stock awards. The average price of shares granted was $22.31 and $13.16 for the years ended December 31, 2001 and 2000, respectively.

Restricted stock information has been restated to give effect to the 2001 two-for-one stock split. Restricted stock activity to date is as follows:

	Number of Shares

Outstanding August 31, 1999	—
Granted	132,600
Released to participants	—
Forfeited	—
Dividends	1,394

Outstanding December 31, 1999	133,994
Granted	4,000
Released to participants	(7,848	)
Forfeited	(20,780	)
Dividends	5,448

Outstanding December 31, 2000	114,814
Granted	90,400
Released to participants	(2,424	)
Forfeited	(6,676	)
Dividends	6,463

Outstanding December 31, 2001	202,577

Employee Stock Purchase Plan—In 1995, the Company authorized the Employee Stock Purchase Plan (ESPP) and the Company currently has 2.8 million shares reserved for the ESPP less the number of shares issued to date under this plan. Subject to certain exclusions, all full-time employees are eligible to participate. Under the terms of the plan, employees can choose to have up to ten percent of their annual earnings withheld to purchase the Company’s common stock. The Committee may allow contributions to be made by other means provided that in no event will contributions from all means exceed ten percent of the employee’s annual earnings. The purchase price of the stock is 85 percent of the lower of its grant date or exercise date market price. Approximately 56 percent, 56 percent, and 54 percent of eligible employees participated in the plan in fiscal years 2001, 2000, and 1999, respectively. Under the plan, the Company sold 192,593 shares in fiscal year 2001, 523,044 shares in fiscal year 2000, and 176,058 shares in fiscal year 1999.

Accounting Treatment—The Company continues to apply APB 25 in accounting for both plans. Accordingly, no compensation cost has been recognized in the consolidated financial statements for the Company’s options and the Employee Stock Purchase Plan. Had the Company applied the provisions of Statement 123 to determine the compensation cost under these plans, the Company’s pro forma net income and diluted earnings per share would have been as follows:

	Year Ended December 31, 2001		Year Ended December 31, 2000		Four Months Ended December 31, 1999		Year Ended August 31, 1999

	(Thousands of dollars, except per share amounts)
Net Income
As reported	$	101,565	$	145,607	$	35,344	$	106,357
Pro Forma	$	85,415	$	135,893	$	27,066	$	99,887
Earnings per share—Diluted
As reported	$	0.85	$	1.23	$	0.27	$	0.86
Pro Forma	$	0.71	$	1.15	$	0.20	$	0.81

The fair market value of each option granted is estimated based on the Black-Scholes model. Based on previous stock performance, volatility is estimated to be 0.2309 for fiscal year 2001, 0.2406 for fiscal year 2000, 0.2414 for the four months ended December 31, 1999, and 0.2151 for the year ended August 31, 1999. The average dividend amount is estimated to be $0.615 per share for fiscal year 2001, $0.61 per share for fiscal year 2000, the four months ended December 31, 1999, and the year ended August 31, 1999, with a risk-free interest rate of 5.497 percent of fiscal year 2001, 5.665 percent for fiscal year 2000, 5.664 percent for the four months ended December 31, 1999, and 5.983 percent for the year ended August 31, 1999.

Expected life ranged from 1 to 10 years based upon experience to date and the make-up of the optionees. Fair value of options granted at fair market value under the Plan were $8.14 and $13.29 for the years ended December 31, 2001 and 2000, respectively, $11.52 for the four months ended December 31, 1999, and $13.86 for the year ended August 31, 1999. Fair value of options granted above fair market value under the Plan was $7.92 for the year ended December 31, 2001. The average exercise price of options granted above fair market value is $23.49 for the year ended December 31, 2001.

(Q) EARNINGS PER SHARE INFORMATION

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

	Year Ended December 31, 2001
	Income		Shares	Per Share Amount

	(Thousands, except per share amounts)
Basic EPS
Income available for common stock	$	64,465	59,557
Convertible preferred stock		37,100	39,892

Income available for common stock and assumed conversion of preferred stock		101,565	99,449	$	1.02

Further dilution from applying the "two-class" method					(0.17	)

Basic earnings per share				$	0.85

Effect of Other Dilutive Securities Options		—	222

Diluted EPS
Income available for common stock and assumed exercise of stock options	$	101,565	99,671	$	1.02

Further dilution from applying the "two-class" method					(0.17	)

Diluted earnings per share				$	0.85

100

	Year Ended December 31, 2000
	Income		Shares	Per Share Amount

	(Thousands, except per share amounts)
Basic EPS
Income available for common stock	$	108,507	58,448
Convertible preferred stock		37,100	39,892

Income available for common stock and assumed conversion of preferred stock		145,607	98,340	$	1.48

Further dilution from applying the "two-class" method					(0.25	)

Basic earnings per share				$	1.23

Effect of Other Dilutive Securities Options		—	48

Diluted EPS
Income available for common stock and assumed exercise of stock options	$	145,607	98,388	$	1.48

Further dilution from applying the "two-class" method					(0.25	)

Diluted earnings per share				$	1.23

	Four Months Ended December 31, 1999
	Income		Shares	Per Share Amount

	(Thousands, except per share amounts)
Basic EPS
Income available for common stock	$	22,977	60,850
Convertible preferred stock		12,367	39,892

Income available for common stock and assumed conversion of preferred stock		35,344	100,742	$	0.35

Further dilution from applying the "two-class" method					(0.08	)

Basic earnings per share				$	0.27

Effect of Other Dilutive Securities Options		—	26

Diluted EPS
Income available for common stock and assumed exercise of stock options	$	35,344	100,768	$	0.35

Further dilution from applying the "two-class" method					(0.08	)

Diluted earnings per share				$	0.27

101

	Year Ended August 31, 1999
	Income		Shares	Per Share Amount

	(Thousands, except per share amounts)
Basic EPS
Income available for common stock	$	69,110	62,996
Convertible preferred stock		37,247	40,106

Income available for common stock and assumed conversion of preferred stock		106,357	103,102	$	1.03

Further dilution from applying the "two-class" method					(0.17	)

Basic earnings per share				$	0.86

Effect of Other Dilutive Securities Options		—	40

Diluted EPS
Income available for common stock and assumed exercise of stock options	$	106,357	103,142	$	1.03

Further dilution from applying the "two-class" method					(0.17	)

Diluted earnings per share				$	0.86

There were 158,989, 113,836, 180,010, and 82,070 option shares excluded from the calculation of Diluted Earnings per Share for the years ended December 31, 2001 and 2000, the four months ended December 31, 1999, and the year ended August 31, 1999, respectively, due to being antidilutive for the periods.

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

	Year Ended December 31, 2001			Year Ended December 31, 2000		Four Months Ended December 31, 1999		Year Ended August 31, 1999

	(Per share amounts)
Basic EPS
Income available for common stock before cumulative effect of a change in accounting principle	$	0.87		$	1.21	$	0.27	$	0.86
Cumulative effect of a change in accounting principle, net of tax		(0.02	)		0.02		—		—

Income available for common stock	$	0.85		$	1.23	$	0.27	$	0.86

Diluted EPS
Income available for common stock before cumulative effect of achange in accounting principle	$	0.87		$	1.21	$	0.27	$	0.86
Cumulative effect of a change in accounting principle, net of tax		(0.02	)		0.02		—		—

Income available for common stock	$	0.85		$	1.23	$	0.27	$	0.86

102

(R) OIL AND GAS PRODUCING ACTIVITIES

The following is historical cost information relating to the Company’s production operations:

	Year Ended December 31, 2001		Year Ended December 31, 2000		Four Months Ended December 31, 1999		Year Ended August 31, 1999

			(Thousands of Dollars)
Capitalized costs at end of year
Unproved properties	$	4,223	$	2,210	$	4,224	$	4,245
Proved properties		475,151		423,824		398,748		393,096

Total capitalized costs		479,374		426,034		402,972		397,341
Accumulated depreciation, depletion and amortization		177,622		146,749		128,220		120,109

Net capitalized costs	$	301,752	$	279,285	$	274,752	$	277,232

Costs incurred during the year
Property acquisition costs (unproved)	$	2,334	$	878	$	103	$	948
Exploitation costs	$	8	$	10	$	6	$	17
Development costs	$	53,220	$	32,817	$	6,254	$	13,659
Purchase of minerals in place	$	1,572	$	4,751	$	—	$	79,385

The accompanying schedule presents the results of operations of the Company’s oil and gas producing activities. The results exclude general office overhead and interest expense attributable to oil and gas production.

	Year Ended December 31, 2001		Year Ended December 31, 2000		Four Months Ended December 31, 1999		Year Ended August 31, 1999

			(Thousands of Dollars)
Net revenues
Sales to unaffiliated customers	$	93,935	$	49,868	$	18,623	$	42,077
Gas sold to affiliates		26,173		19,669		4,779		22,868

Net revenues from production		120,108		69,537		23,402		64,945

Production costs		20,991		17,575		5,465		14,516
Exploitation costs		8		10		6		17
Depreciation, depletion and amortization		35,017		30,465		9,588		33,771
Income taxes		24,999		8,311		3,226		6,359

Total expenses		81,015		56,361		18,285		54,663

Results of operations from producing activities	$	39,093	$	13,176	$	5,117	$	10,282

(S) OIL AND GAS RESERVES (UNAUDITED)

Following are estimates of the Company’s proved oil and gas reserves, net of royalty interests and changes herein, for the fiscal years 2001, 2000, the four months ended December 31, 1999, and the year ended August 31,1999 .

The Company emphasizes that the volumes of reserves shown are estimates, which, by their nature, are subject to later revision. The estimates are made by the Company utilizing all available geological and reservoir data as well as production performance data. These estimates are reviewed annually both internally and by an independent reserve engineer and revised, either upward or downward, as warranted by additional performance data.

103

	Oil		Gas
	(MBbls)		(MMcf)

August 31, 1998	3,272		178,047
Revisions in prior estimates	300		8,397
Extensions, discoveries and other additions	376		37,202
Purchases of minerals in place	884		61,286
Sales of minerals in place	(175	)	(3,057	)
Production	(460	)	(27,773	)

August 31, 1999	4,197		254,102
Revisions in prior estimates	18		(8,086	)
Extensions, discoveries and other additions	84		9,276
Purchases of minerals in place	—		—
Sales of minerals in place	(1	)	(7	)
Production	(138	)	(8,306	)

December 31, 1999	4,160		246,979
Revisions in prior estimates	221		9,134
Extensions, discoveries and other additions	661		29,193
Purchases of minerals in place	215		945
Sales of minerals in place	(518	)	(4,784	)
Production	(400	)	(26,746	)

December 31, 2000	4,339		254,721
Revisions in prior estimates	(536	)	(28,233	)
Extensions, discoveries and other additions	1,198		33,397
Purchases of minerals in place	3		936
Sales of minerals in place	—		(276	)
Production	(493	)	(27,578	)

December 31, 2001	4,511		232,967

Proved developed reserves
August 31, 1999	2,540		175,771
December 31, 1999	2,451		169,060
December 31, 2000	2,495		182,052
December 31, 2001	2,723		161,725

(T) DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

Estimates of the standard measure of discounted future cash flows from proved reserves of oil and natural gas are shown in the following table.

104

	Year Ended December 31, 2001		Year Ended December 31, 2000		Four Months Ended December 31, 1999		Year Ended August 31, 1999

	(Thousands of Dollars)
Future cash inflows	$	669,328	$	2,498,525	$	632,751	$	639,721
Future production and development costs		200,741		400,767		194,332		194,077
Future income taxes		119,864		742,505		62,533		53,442

Future net cash flows		348,723		1,355,253		375,886		392,202
10 percent annual discount for estimated timing of cash flows		149,101		599,370		149,527		161,156

Standardized measure of discounted future net cash flows relating to oil and gas reserves	$	199,622	$	755,883	$	226,359	$	231,046

Future cash inflows are computed by applying year-end prices (averaging $19.84 per barrel of oil, adjusted for transportation and other charges, and $2.49 per Mcf of gas at December 31, 2001) to the year-end quantities of proved reserves. As of December 31, 2001, a portion of proved developed gas production in 2002 has been hedged. The effects of these hedges are not reflected in the computation of future cash flows above.

These estimated future cash flows are reduced by estimated future development and production costs based on year-end cost levels, assuming continuation of existing economic conditions, and by estimated future income tax expense. The tax expense is calculated by applying the current year-end statutory tax rates to pretax net cash flows (net of tax depreciation, depletion, and lease amortization allowances) applicable to oil and gas production.

The changes in standardized measure of discounted future net cash flow relating to proved oil and gas reserves are as follows:

	Year Ended December 31, 2001			Year Ended December 31, 2000			Four Months Ended December 31, 1999			Year Ended August 31, 1999

				(Thousands of Dollars)
Beginning of period	$	755,883		$	226,359		$	231,046		$	162,629
Changes resulting from:
Sales of oil and gas produced, net of production costs		(99,117	)		(51,962	)		(17,938	)		(50,120	)
Net changes in price, development, and production costs		(825,483	)		783,763			3,523			13,269
Extensions, discoveries, additions, and improved
recovery, less related costs		50,353			102,607			9,981			37,379
Purchases of minerals in place		1,572			4,751			—			67,120
Sales of minerals in place		(2,247	)		(5,761	)		(24	)		(9,326	)
Revisions of previous quantity estimates		(136,171	)		43,318			(8,454	)		10,477
Accretion of discount		116,776			25,826			8,750			17,317
Net change in income taxes		345,485			(376,438	)		(6,174	)		(11,618	)
Other, net		(7,429	)		3,420			5,649			(6,081	)

End of period	$	199,622		$	755,883		$	226,359		$	231,046

105

(U) Restatement of Consolidated Statements of Cash Flows

The consolidated statements of cash flows for the years ended December 31, 2001 and 2000 and the four months ended December 31, 1999, have been restated to correct mathematical errors related to the treatment of bank overdrafts. The balance of bank overdrafts at December 31, 2001, 2000 and 1999 was $48.9 million, $190.8 million, and $22.7 million, respectively, which are included in accounts payable in the accompanying consolidated balance sheets. Increases in bank overdrafts were inadvertently treated as decreases of cash and decreases in bank overdrafts were inadvertently treated as increases of cash. The following is a summary of the impact of these changes:

	Year Ended December 31, 2001			Year Ended December 31, 2000			Four Months Ended December 31, 1999

	(In Thousands)
Accounts payable and accrued liabilities:
As previously reported	$	(984,999	)	$	1,168,871		$	84,627
As restated	$	(701,153	)	$	832,581		$	39,229

Cash Provided By (Used In) Operating Activities:
As previously reported	$	121,505		$	72,958		$	17,000
As restated	$	405,351		$	(263,332	)	$	(28,398	)

Change in bank overdraft:
As previously reported	$	141,923		$	(168,145	)	$	(22,699	)
As restated	$	(141,923	)	$	168,145		$	22,699

Cash Provided By (Used In) Financing Activities:
As previously reported	$	247,527		$	672,799		$	71,174
As restated	$	(36,319	)	$	1,009,089		$	116,572

106

PART III.

ITEM 14. CONTROLS AND PROCEDURES

Within the 90 days prior to the filing date of this Amendment No. 1 to the Annual Report on Form 10-K, 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 IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(A) DOCUMENTS FILED AS A PART OF THIS REPORT

(1) Exhibits


(23	)	Independent Auditors’ Consent

(99	)(b)	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	)(c)	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.

107

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	ONEOK, Inc. Registrant

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

Certification

I, David L. Kyle, certify that:

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

2. Based on my knowledge, this annual 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 annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual report;

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

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual 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 annual report (the “Evaluation Date”); and

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

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

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

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

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:

1. I have reviewed this annual report on Form 10-K 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 annual report (the “Evaluation Date”); and

presented in this annual 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

6. The registrant’s other certifying officers and I have indicated in this annual 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/ Jim Kneale
				Chief Financial Officer