Edgar Filing: ONEOK INC /NEW/

Form 10-Q/A (P.E. 3-31-2002)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q/A

(Amendment No. 1)

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

For the quarterly period ended March 31, 2002.

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

For the transition period from to

Commission file number 001-13643

ONEOK, Inc.

(Exact name of registrant as specified in its charter)

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

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

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

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 ¨

Common stock, with par value of $0.01 – 60,343,529 shares outstanding at May 8, 2002.

Explanatory Statement:

The purpose of this Amendment No. 1 is to restate the Consolidated Statements of Cash Flows on p. 6 of the ONEOK, Inc. Form 10-Q for the quarter ended March 31, 2002 to correct mathematical errors related to the treatment of bank overdrafts in 2002, to add Note M to the consolidated financial statements discussing the restatement, and to modify the discussion of operating cash flows on page 29 for the restatement. Except as amended as described above, the Consolidated Financial Statements of the Company being filed herewith (and included in the Company’s Form 10-Q for the quarter ended March 31, 2002 as previously filed with the Securities and Exchange Commission) remain unchanged.

Part I—FINANCIAL INFORMATION

Item 1. Financial Statements

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME

	Three Months Ended March 31,
(Unaudited)	2002			2001

	(Thousands of Dollars, except per share amounts)
Operating Revenues	$	1,465,658		$	2,956,924
Cost of gas		1,158,086			2,666,063

Net Revenues		307,572			290,861

Operating Expenses
Operations and maintenance		109,066			94,795
Depreciation, depletion, and amortization		40,236			36,955
General taxes		15,322			16,065

Total Operating Expenses		164,624			147,815

Operating Income		142,948			143,046

Other income (expense), net		(720	)		3,299
Interest expense		26,182			37,535
Income taxes		43,448			41,800

Income before cumulative effect of a change in accounting principle		72,598			67,010
Cumulative effect of a change in accounting principle, net of tax (Note I)		—			(2,151	)

Net Income		72,598			64,859
Preferred stock dividends		9,275			9,275

Income Available for Common Stock	$	63,323		$	55,584

Earnings Per Share of Common Stock (Note E)
Basic	$	0.61		$	0.54

Diluted	$	0.60		$	0.54

Average Shares of Common Stock (Thousands)
Basic		100,070			99,214
Diluted		100,276			99,596

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Unaudited)	March 31, 2002		December 31, 2001

	(Thousands of Dollars)
Assets
Current Assets
Cash and cash equivalents	$	150,705	$	28,229
Trade accounts and notes receivable, net		719,842		677,796
Materials and supplies		19,872		20,310
Gas in storage		39,110		82,694
Unrecovered purchased gas costs		—		45,098
Assets from price risk management activities		326,198		587,740
Deposits		9,708		41,781
Other current assets		87,790		78,321

Total Current Assets		1,353,225		1,561,969

Property, Plant and Equipment
Marketing and Trading		122,214		122,172
Gathering and Processing		1,052,426		1,040,195
Transportation and Storage		806,609		792,641
Distribution		2,006,641		1,985,177
Production		491,575		482,404
Other		87,549		85,168

Total Property, Plant and Equipment		4,567,014		4,507,757
Accumulated depreciation, depletion, and amortization		1,266,617		1,234,789

Net Property, Plant and Equipment		3,300,397		3,272,968

Deferred Charges and Other Assets
Regulatory assets, net (Note B)		232,318		232,520
Goodwill		113,868		113,868
Assets from price risk management activities		280,205		475,066
Investments and other		247,098		222,768

Total Deferred Charges and Other Assets		873,489		1,044,222

Total Assets	$	5,527,111	$	5,879,159

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Unaudited)	March 31, 2002			December 31, 2001

	(Thousands of Dollars)
Liabilities and Shareholders’ Equity
Current Liabilities
Current maturities of long-term debt	$	250,000		$	250,000
Notes payable		404,045			599,106
Accounts payable		355,506			390,479
Accrued taxes		11,572			11,528
Accrued interest		25,746			31,954
Unrecovered purchased gas costs		9,442			—
Customers’ deposits		22,547			21,697
Liabilities from price risk management activities		153,636			381,409
Other		165,231			132,244

Total Current Liabilities		1,397,725			1,818,417

Long-term Debt, excluding current maturities		1,493,899			1,498,012
Deferred Credits and Other Liabilities
Deferred income taxes		556,361			499,432
Liabilities from price risk management activities		397,540			491,374
Lease obligation		118,771			122,011
Other deferred credits		233,024			184,623

Total Deferred Credits and Other Liabilities		1,305,696			1,297,440

Total Liabilities		4,197,320			4,613,869

Commitments and Contingencies *(Note F)*
Shareholders’ Equity
Convertible preferred stock, $0.01 par value:
Series A authorized 20,000,000 shares; issued and outstanding 19,946,448 shares at March 31, 2002 and December 31, 2001		199			199
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 63,438,441 shares with 60,281,805 and 60,002,218 shares outstanding at March 31, 2002 and December 31, 2001, respectively		634			634
Paid in capital (Note H)		902,984			902,269
Unearned compensation		(4,227	)		(2,000	)
Accumulated other comprehensive income (loss) (Note J)		6,151			(1,780	)
Retained earnings		469,566			415,513
Treasury stock at cost: 3,156,636 shares at March 31, 2002; and 3,436,223 shares at December 31, 2001		(45,516	)		(49,545	)

Total Shareholders’ Equity		1,329,791			1,265,290

Total Liabilities and Shareholders’ Equity	$	5,527,111		$	5,879,159

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months Ended March 31,
(Unaudited)	2002 (Restated)			2001

	(Thousands of Dollars)
Operating Activities
Net income	$	72,598		$	64,859
Depreciation, depletion, and amortization		40,236			36,955
Gain on sale of assets		(813	)		(363	)
(Income) loss from equity investments		1,015			(5,407	)
Deferred income taxes		80,654			4,936
Amortization of restricted stock		487			332
Allowance for doubtful accounts		3,576			3,554
Mark-to-market (income) loss		13,690			(3,253	)
Changes in assets and liabilities:
Accounts and notes receivable		(45,622	)		266,888
Inventories		44,022			39,149
Unrecovered purchased gas costs		54,540			(85,061	)
Deposits		32,073			107,810
Accounts payable and accrued liabilities		(12,428	)		(152,170	)
Price risk management assets and liabilities		119,572			62,766
Other assets and liabilities		17,171			18,416

Cash Provided by Operating Activities		420,771			359,411

Investing Activities
Changes in other investments, net		1,478			399
Acquisitions		(30	)		(626	)
Capital expenditures		(60,850	)		(91,013	)
Proceeds from sale of property		1,400			486

Cash Used in Investing Activities		(58,002	)		(90,754	)

Financing Activities
Payments of notes payable, net		(195,061	)		(237,500	)
Change in bank overdraft		(27,859	)		(15,268	)
Payment of debt		(588	)		(1,568	)
Issuance of common stock		—			3,734
Issuance of treasury stock, net		1,760			377
Dividends paid		(18,545	)		(18,432	)

Cash Used In Financing Activities		(240,293	)		(268,657	)

Change in Cash and Cash Equivalents		122,476			—
Cash and Cash Equivalents at Beginning of Period		28,229			249

Cash and Cash Equivalents at End of Period	$	150,705		$	249

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

A. Summary of Accounting Policies

Interim Reporting—The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information. The interim consolidated financial statements reflect all adjustments, which, in the opinion of management, are necessary for a fair presentation of the results for the interim periods presented. All such adjustments are of a normal recurring nature. Due to the seasonal nature of the business, the results of operations for the three months ended March 31, 2002, are not necessarily indicative of the results that may be expected for a twelve-month period. For further information, refer to the consolidated financial statements and footnotes thereto included in the Company’s Form 10-K for the year ended December 31, 2001.

Goodwill—On January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (Statement 142). Accordingly, the Company has discontinued the amortization of goodwill effective January 1, 2002, with the adoption of Statement 142. In accordance with the provisions of Statement 142, the Company will complete its analysis of goodwill for impairment no later than June 30, 2002. See Note K of Notes to Consolidated Financial Statements.

Reclassifications—Certain amounts in the consolidated financial statements have been reclassified to conform to the 2002 presentation.

Critical Accounting Policies

Energy Trading and Risk Management Activities—The Company engages in price risk management activities for both trading and non-trading purposes. The Company accounts for price risk management activities in accordance with 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. 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.

Regulation—The Company’s intrastate transmission pipelines and distribution operations are subject to the rate regulation and accounting requirements of the Oklahoma Corporation Commission (OCC), Kansas Corporation Commission (KCC) and Texas Railroad Commission (TRC). Certain other transportation activities of the Company are subject to regulation by the Federal Energy Regulatory Commission (FERC). Oklahoma Natural Gas (ONG) and Kansas Gas Service (KGS) follow the accounting and reporting guidance contained in Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71). Allocation of costs and revenues to accounting periods for ratemaking and regulatory purposes may differ from 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.

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 $ 232.3 million and $232.5 million at March 31, 2002 and December 31, 2001, 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 B 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.

B. Regulatory Assets

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

	March 31, 2002		December 31, 2001

	(Thousands of Dollars)
Recoupable take-or-pay	$	73,966	$	75,336
Pension costs		10,079		11,124
Postretirement costs other than pension		60,198		60,170
Transition costs		21,452		21,598
Reacquired debt costs		22,137		22,351
Income taxes		27,559		28,365
Weather normalization		11,640		7,984
Other		5,287		5,592

Regulatory assets, net	$	232,318	$	232,520

C. Capital 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 $.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 presented 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.

D. Supplemental Cash Flow Information

The following table is supplemental information relative to the Company’s cash flows.

	Three Months Ended March 31,
	2002		2001

	(Thousands of Dollars)
Cash paid during the period
Interest (including amounts capitalized)	$	32,390	$	48,318
Income tax refund receivable	$	83,661	$	—
Noncash transactions
Dividends on restricted stock	$	56	$	32
Treasury stock transferred to compensation plans	$	25	$	131
Issuance of restricted stock, net	$	2,658	$	2,017
Notes payable reclassified to long-term debtbased upon subsequent refinancing	$	—	$	397,048

E. Earnings per Share Information

The Company computes its earnings per common share (EPS) in accordance with a pronouncement of the Financial Accounting Standards Board’s Staff at the Emerging Issues Task Force meeting in April 2001, codified as EITF Topic No. D-95 (Topic D-95). In accordance with Topic D-95, the dilutive effect of the Company’s Series A Convertible Preferred Stock is considered in the computation of basic EPS utilizing the “if-converted” method. Under the Company’s “if-converted” method, the dilutive effect of the 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 following is a reconciliation of the basic and diluted EPS computations.

	Three Months Ended March 31, 2002
	Income		Shares	Per Share Amount

	(Thousands, except per share amounts)
Basic EPS
Income available for common stock	$	63,323	60,178
Convertible preferred stock		9,275	39,892

Income available for common stock and assumed conversion of preferred stock		72,598	100,070	$	0.73

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

Basic earnings per share				$	0.61

Effect of Other Dilutive Securities Options		—	206

Diluted EPS
Income available for common stock and assumed exercise of stock options	$	72,598	100,276	$	0.72

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

Diluted earnings per share				$	0.60


	Three Months Ended March 31, 2001
	Income		Shares	Per Share Amount

	(Thousands, except per share amounts)
Basic EPS
Income available for common stock	$	55,584	59,322
Convertible preferred stock		9,275	39,892

Income available for common stock and assumed conversion of preferred stock		64,859	99,214	$	0.65

Further dilution from applying the “two-class” method					(0.11	)

Basic earnings per share				$	0.54

Effect of Other Dilutive Securities Options		—	382

Diluted EPS
Income available for common stock and assumed exercise of stock options	$	64,859	99,596	$	0.65

Further dilution from applying the “two-class” method					(0.11	)

Diluted earnings per share				$	0.54

There were 240,855 and 19,192 option shares excluded from the calculation of diluted EPS for the three months ended March 31, 2002 and 2001, 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.

	Three Months Ended March 31,
	Basic EPS					Diluted EPS
	2002		2001			2002		2001

	(Per share amounts)
Income available for common stockbefore cumulative effect of a change in accounting principle	$	0.61	$	0.56		$	0.60	$	0.56
Cumulative effect of a change inaccounting principle, net of tax		—		(0.02	)		—		(0.02	)

Income available for common stock	$	0.61	$	0.54		$	0.60	$	0.54

F. Commitments and Contingencies

Enron—Certain of the financial instruments discussed in the Company’s Form 10-K for the year-ended December 31, 2001, have Enron North America as the counterparty. Enron Corporation and various subsidiaries, including Enron North America (Enron), filed for protection from creditors under Chapter 11 of the United States Bankruptcy Code on December 3, 2001. In 2001, the Company took a charge of $37.4 million thereby providing an allowance for forward financial positions and establishing an allowance for uncollectible accounts related to previously settled financial and physical positions with Enron. In the first quarter of 2002, the Company recorded a recovery of approximately $14.0 million, as a result of an agreement to sell the related Enron claim. The additional income triggered increased employee costs of $5.5 million in the same period. The sale of the Enron claim is subject to normal representations as to the validity of the claims and the guarantees from Enron.

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 Kinder Morgan, Inc. (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 damages 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 Kansas Department of Health and Environment (KDHE) presently governs all future work at these sites. The terms of the consent agreement allow the Company to investigate these sites and set remediation priorities based upon the results of the investigations and risk analysis. The prioritized sites will be investigated over a period of time as negotiated with the KDHE. Through March 31, 2002, 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 allowed ONG to commence collecting gas charges, subject to refund should the Company ultimately lose the case. In the fourth quarter of 2001, the Company took a charge of $34.6 million as a result of this order. The Company, along with the staff of the Public Utility Division and the Consumer Services Division of the OCC, the Oklahoma Attorney General, and other stipulating parties, has presented a joint settlement agreement to the OCC that resolves this gas cost issue and ongoing litigation related to a contract with Dynamic Energy Resources, Inc. A hearing with the OCC is scheduled for mid – May 2002. If approved in the current form, the financial impact of the settlement agreement on the Company will be recorded as a $14.2 million recovery, less any related costs, with the potential for an additional $8.0 recovery depending upon the potential value that could be generated by gas storage savings, less any related costs.

Two separate class action lawsuits have been filed against the Company in connection with the natural gas explosions and eruptions of natural gas geysers that occurred at the Yaggy storage facility 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. The Company and its subsidiaries are 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 filed rebuttal testimony on April 21, 2002. The hearing before the Commission is scheduled for June 3, 2002. This case is included in the proposed OCC settlement discussed above.

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.

G. Segments

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 six segments: (1) the Marketing and Trading segment markets natural gas to wholesale and retail customers and markets electricity to wholesale customers; (2) the Gathering and Processing segment gathers and processes natural gas and fractionates, stores and markets natural gas liquids; (3) the Transportation and Storage segment transports and stores natural gas for others and buys and sells natural gas; (4) the Distribution segment distributes natural gas to residential, commercial and industrial customers, leases pipeline capacity to others and provides transportation services for end-use customers; (5) the Production segment develops and produces natural gas and oil; and (6) the Other segment primarily operates and leases the Company’s headquarters building and a related parking facility.

During the first quarter of 2002, the Power segment was merged into the Marketing and Trading segment, eliminating the Power segment. This presentation reflects the Company’s strategy of trading around the recently completed electric generating power plant. The prior period has been restated to reflect this presentation.

The accounting policies of the segments are substantially the same as those described in the Summary of Significant Accounting Policies in the Company’s Form 10-K for the year ended December 31, 2001. 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 Company has no single external customer from which it receives ten percent or more of its consolidated revenues.

Three Months Ended March 31, 2002	Marketing and Trading		Gathering and Processing		Transportation and Storage		Distribution		Production			Other and Eliminations			Total

	(Thousands of Dollars)
Sales to unaffiliatedcustomers	$	773,564	$	157,042	$	19,129	$	497,985	$	16,838		$	1,100		$	1,465,658
Intersegment sales		138,920		58,553		30,074		1,144		2,819			(231,510	)	$	—

Total Revenues	$	912,484	$	215,595	$	49,203	$	499,129	$	19,657		$	(230,410	)	$	1,465,658

Net revenues	$	71,909	$	41,323	$	36,732	$	137,995	$	19,657		$	(44	)	$	307,572
Operating costs	$	8,165	$	32,070	$	14,665	$	62,885	$	7,295		$	(692	)	$	124,388
Depreciation, depletion and amortization	$	1,183	$	7,970	$	4,574	$	16,949	$	9,174		$	386		$	40,236
Operating income	$	62,561	$	1,283	$	17,493	$	58,161	$	3,188		$	262		$	142,948
Income (loss) from equity investments	$	—	$	—	$	438	$	—	$	—		$	(1,453	)	$	(1,015	)
Total assets	$	1,023,672	$	1,365,308	$	815,528	$	1,794,746	$	315,512		$	212,345		$	5,527,111
Capital expenditures	$	138	$	10,808	$	14,759	$	21,121	$	11,622		$	2,402		$	60,850


Three Months Ended March 31, 2001	Marketing and Trading		Gathering and Processing		Transportation and Storage		Distribution		Production			Other and Eliminations			Total

	(Thousands of Dollars)
Sales to unaffiliatedcustomers	$	1,868,120	$	273,687	$	34,840	$	761,175	$	16,839		$	2,263		$	2,956,924
Intersegment sales		420,038		202,905		18,363		733		12,447			(654,486	)	$	—

Total Revenues	$	2,288,158	$	476,592	$	53,203	$	761,908	$	29,286		$	(652,223	)	$	2,956,924

Net revenues	$	29,281	$	49,225	$	37,561	$	140,772	$	29,286		$	4,736		$	290,861
Operating costs	$	4,353	$	29,177	$	12,889	$	58,065	$	7,805		$	(1,429	)	$	110,860
Depreciation, depletion and amortization	$	137	$	6,811	$	4,750	$	16,977	$	7,585		$	695		$	36,955
Operating income	$	24,791	$	13,237	$	19,922	$	65,730	$	13,896		$	5,470		$	143,046
Cumulative effect of a change in accounting principle, net of tax	$	—	$	—	$	—	$	—	$	(2,151	)	$	—		$	(2,151	)
Income from equity investments	$	—	$	—	$	659	$	—	$	40		$	4,708		$	5,407
Total assets	$	1,841,792	$	1,499,077	$	636,633	$	2,004,305	$	313,998		$	(2,590	)	$	6,293,215
Capital expenditures	$	28,383	$	7,151	$	10,814	$	27,178	$	11,261		$	6,226		$	91,013

H. Paid in Capital

Paid in capital is $338.8 million and $338.1 million for common stock at March 31, 2002, and December 31, 2001, respectively. Paid in capital for convertible preferred stock was $564.2 million at March 31, 2002, and December 31, 2001.

I. Derivative Instruments and Hedging Activities

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 DIG is addressing Statement 133 implementation issues, the ultimate resolution of which may impact the application of Statement 133.

Under Statement 133, entities are required to record all derivative instruments in the balance sheet at fair value. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, on the reason for holding it. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposures to changes in fair values, cash flows, or foreign currencies. If the hedged exposure is a fair value exposure, the gain or loss on the derivative instrument is recognized in earnings in the period of change together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. If the hedged exposure is a cash flow exposure, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income (outside earnings) and subsequently reclassified into earnings when the forecasted transaction affects earnings. Any amounts excluded from the assessment of hedge effectiveness, as well as the ineffective portion of the hedge, are reported in earnings immediately.

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

The Company realized a $0.7 million gain in earnings that was reclassified from accumulated other comprehensive income resulting from the settlement of contracts when the natural gas was sold. This gain is reported in Operating Revenues. Other comprehensive income at March 31, 2002 includes approximately $0.8 million related to a cash flow exposure and will be realized in earnings within the next 9 months.

The Company is subject to the risk of fluctuation in interest rates in the normal course of business. The Company manages interest rate risk through the use of fixed rate debt, floating rate debt and, at times, interest rate swaps. In July 2001, the Company entered into interest rate swaps on a total of $400 million in fixed rate long-term debt. The interest rate under these swaps resets periodically based on the three-month 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 $1.5 million net decrease in price risk management assets to recognize at fair value its derivatives that are designated as fair value hedging instruments in March 2002. Long-term debt was decreased by approximately $3.7 million to recognize the change in fair value of the related hedged liability. The Company also reduced interest expense by $2.2 million to recognize the ineffectiveness caused by locking the LIBOR rates into future periods.

J. Comprehensive Income

The table below gives an overview of Comprehensive Income for the three months ended March 31, 2002 and 2001. Other comprehensive income for the three months ended March 31, 2002, includes realized and unrealized gains and losses on derivative instruments and unrealized holding gains arising during the period relating to the investment in Magnum Hunter Resources (MHR). In March 2002, MHR merged with Prize Energy Corp. (Prize) reducing the Company’s direct ownership to approximately 11 percent and reducing the number of MHR board of director positions held by the Company from 2 to 1. As such, the Company began accounting for the investment in MHR as an available-for-sale security and, accordingly, marked the investment to fair value through other comprehensive income. Other comprehensive income for the three months ended March 31, 2001, includes the cumulative effect of a change in accounting principle due to the adoption of Statement 133 and realized and unrealized gains and losses on derivative instruments.

	Three Months Ended March 31,
	2002					2001

	(Thousands of Dollars)
Net Income				$	72,598				$	64,859
Other comprehensive income (loss):
Cumulative effect of a change in accounting principle	$	—				$	(45,556	)
Unrealized gains (losses) on derivative instruments		(800	)				12,426
Realized (gains) losses in net income		(734	)				20,836
Unrealized holding gains arising during the period		14,042					—

Other comprehensive income before taxes		12,508					(12,294	)
Income tax benefit (expense) on other comprehensive income (loss)		(4,577	)				4,756

Other comprehensive income (loss)				$	7,931				$	(7,538	)

Comprehensive income				$	80,529				$	57,321

K. Goodwill

The Company adopted Statement 142 on January 1, 2002. Under Statement 142, goodwill is no longer amortized but reviewed for impairment annually or more frequently if certain indicators arise. In accordance with the provisions of Statement 142, the Company will complete its analysis of goodwill for impairment no later than June 30, 2002. Had the Company been accounting for its goodwill under Statement 142 for all periods presented, the Company’s net income and income per share would have been as follows:

	Three Months Ended March 31,
	2002		2001

	(Thousands of Dollars)
Reported net income	$	72,598	$	64,859
Add back goodwill amortization, net of tax		—		639

Pro forma adjusted net income	$	72,598	$	65,498

Basic net income per share:
Reported net income	$	0.61	$	0.54
Goodwill amortization, net of tax		—		0.01

Pro forma adjusted basic net income per share	$	0.61	$	0.55

Diluted net income per share:
Reported net income	$	0.60	$	0.54
Goodwill amortization, net of tax		—		0.01

Pro forma adjusted diluted net income per share	$	0.60	$	0.55

L. Subsequent Events

In April 2002, the Company sold three million shares and 72,000 warrants of its investment in MHR for $21.7 million, net of commissions, reducing the Company’s direct ownership in MHR to approximately seven percent. The Company’s total direct and indirect ownership in MHR, including warrants convertible into common stock, after the sale is approximately nine percent. The Company also relinquished the remaining MHR board of director position held. As the Company accounts for the investment in MHR as an available-for-sale investment, the proportionate share of unrealized gains in other comprehensive income related to this investment were realized at the time of the sale. The Company will record a pre-tax gain of approximately $4.5 million in the statement of operations for the three months ended June 30, 2002.

M. Restatement of Consolidated Statements of Cash Flows

The consolidated statement of cash flows for the three-month period ended March 31, 2002 has been restated to correct a mathematical error related to the treatment of bank overdrafts. The balance of bank overdrafts at March 31, 2002, and December 31, 2001 was $21.1 million and $48.9 million, respectively, which are included in accounts payable in the accompanying consolidated balance sheets. A decrease in the bank overdraft was inadvertently treated as an increase of cash. The following is a summary of the impact of the changes:

		Three Months Ended March 31, 2002

		(Thousands of Dollars)
Accounts payable and accrued liabilities:
As previously reported		$ (68,146)
As restated		$ (12,428)

Cash Provided By Operating Activities:
As previously reported		$ 365,053
As restated		$ 420,771

Change in bank overdraft:
As previously reported		$ 27,859
As restated		$ (27,859)

Cash Used In Financing Activities:
As previously reported		$(184,575)
As restated		$(240,293)


Item 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Some of the statements contained and incorporated in this Form 10-Q are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The forward-looking statements relate to the anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in various circumstances. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

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

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

•

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

•

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

•

the capital intensive nature of the Company’s business;

•

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

•

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

•

the profitability of assets or businesses acquired by the Company;

•

risks of marketing, trading, and hedging activities as a result of changes in energy prices and creditworthiness of counterparties;

•

economic climate and growth in the geographic areas in which the Company does business;

•

the uncertainty of gas and oil reserve estimates;

•

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

•

the effects of changes in governmental policies and regulatory actions, including income taxes, environmental compliance, and authorized rates;

•

the results of litigation related to the Company’s now terminated proposed acquisition of Southwest Gas Corporation (Southwest) or to the termination of the Company’s merger agreement with Southwest;

•

the results of administrative proceedings and litigation involving the Oklahoma Corporation Commission and Kansas Corporation Commission; and

•

the other factors listed in the reports the Company has filed and may file with the Securities and Exchange Commission.

Other factors and assumptions not identified above were also involved in the making of the forward-looking statements. The failure of those assumptions to be realized, as well as other factors, may also cause actual results to differ materially from those projected.

A. Results of Operations

Consolidated Operations

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

•

Marketing and Trading

•

Gathering and Processing

•

Transportation and Storage

•

Distribution

•

Production

•

Other

During the quarter ended March 31, 2002, the Power segment was combined into the Marketing and Trading segment, eliminating the Power segment. All segment data has been restated to reflect this presentation.

In the first quarter of 2002, the Company sold its claim related to the Enron bankruptcy for $22.1 million. The sale is subject to normal representations as to the validity of the claim and guarantees from Enron. The Company recorded a charge of $37.4 million in the fourth quarter of 2001 related to the Enron bankruptcy.

	Three Months Ended March 31,
	2002			2001

	(Thousands of Dollars)
Financial Results
Operating revenues	$	1,465,658		$	2,956,924
Cost of gas		1,158,086			2,666,063

Net revenues		307,572			290,861
Operating costs		124,388			110,860
Depreciation, depletion, and amortization		40,236			36,955

Operating income	$	142,948		$	143,046

Other income, net	$	(720	)	$	3,299

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

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

The Company’s operating revenues and cost of gas decreased for the three months ended March 31, 2002 compared to the same period in 2001 primarily due to decreased market prices and warmer weather in the first quarter of 2002 compared to the first quarter of 2001. The decrease in operating revenues was partially offset by a $14.0 million increase due to the recovery of a portion of the costs related to Enron sales contracts that were written off in the fourth quarter of 2001. Although operating revenues and cost of gas decreased in 2002 compared to 2001, the Company’s net revenues increased primarily due to the $14.0 million Enron recovery and the Company’s ability to successfully execute its storage arbitrage strategy. Operating costs increased for the three months ended March 31, 2002 compared to the same period in 2001 primarily due to increased employee costs related to the increase in net income. Other income, net for the three months ended March 31, 2002 includes losses from equity investments, including Magnum Hunter Resources (MHR), of approximately $1.0 million and approximately $0.2 million of ongoing litigation costs associated with the terminated acquisition of Southwest Gas Corporation. Other income, net for the three months ended March 31, 2001 includes income from equity investments, including MHR, of approximately $5.4 million, which was partially offset by a charge of approximately $1.5 million of ongoing litigation costs associated with the terminated acquisition of Southwest Gas Corporation.

On March 15, 2002, MHR merged with Prize Energy Corp. (Prize) reducing the Company’s direct ownership to approximately 11 percent and reducing the number of MHR board of director positions held by the Company from two to one. The Company began accounting for the investment in MHR as an available-for-sale security and, accordingly, marked the investment to fair value through other comprehensive income at March 31, 2002. The MHR investment and related equity loss recorded through March 15, 2002, is reported in the Other segment. Subsequent to March 31, 2002, the Company sold approximately three million shares and 72,000 warrants of its investment reducing the Company’s total direct and indirect ownership to approximately nine percent. The Company also relinquished the remaining MHR board of director position held. See Note L of Notes to Consolidated Financial Statements for further discussion of the sale.

Marketing and Trading

The Marketing and Trading segment purchases, stores, markets and trades natural gas to both wholesale and retail sectors in 28 states. The Company has strong mid-continent region storage positions and transport capacity of 1 Bcf/d (Bcf per day) that allows for trade from the California border, throughout the Rockies, to the Chicago city gate. With total storage capacity of 77 Bcf, withdrawal capability of 2.5 Bcf/d and injection of 1.4 Bcf/d, the Company has direct access to all regions of the country with great flexibility in capturing volatility in the energy markets. The Company constructed a peak electric generating plant that began operations in mid-2001. The 300-megawatt electric power plant is located adjacent to one of the Company’s natural gas storage facilities and is configured to supply electric power during peak periods. This plant allows the Company to capture the spark spread premium, which is the value added by converting natural gas to electricity, during peak demand periods. The Company continues to enhance its strategy of focusing on higher margin business which includes providing reliable service during peak demand periods through the use of storage.

During the quarter ended March 31, 2002, the Power segment was combined into the Marketing and Trading segment, eliminating the Power segment. This presentation reflects the Company’s strategy of trading around the capacity of the electric generating plant. All segment data has been restated to reflect this presentation.

	Three Months Ended March 31,
	2002			2001

	(Thousands of Dollars)
Financial Results
Energy sales	$	912,272		$	2,287,413
Cost of sales		840,575			2,258,877

Gross margin on sales		71,697			28,536
Other revenues		212			745

Net revenues		71,909			29,281
Operating costs		8,165			4,353
Depreciation, depletion, and amortization		1,183			137

Operating income	$	62,561		$	24,791

Other income, net	$	141		$	—


	Three Months Ended March 31,
	2002			2001

Operating Information
Natural gas volumes (MMcf)		255,789			297,354
Natural gas gross margin ($/ Mcf)	$	0.150		$	0.093
Power volumes (MMwh)		316			—
Power gross margin (loss) ($/MMwh)	$	(0.05	)	$	—
Capital expenditures (Thousands)	$	138		$	28,383

Substantially lower natural gas prices for the three months ended March 31, 2002 compared to the same period in 2001, resulted in decreased energy sales and cost of sales. Natural gas sales volumes also decreased due to milder temperatures relative to the prior year. Energy sales include natural gas, power, reservation fees, crude, natural gas liquids, and basis. Basis is the price difference of natural gas due to the location of the sales and purchases. Energy sales for the period ended March 31, 2002 also include a recovery of $10.4 million related to Enron sales contracts written off in the fourth quarter of 2001. Additional employee costs of approximately $410 thousand were triggered by the income from the sale of the Enron claim and are included in operating costs. Gross margin on sales increased for the three months ended March 31, 2002 compared to the same period for 2001 due to the Company’s ability to successfully execute it’s strategy to capture higher margins in the current lower price environment by trading around its asset base and arbitraging intra-month price volatility and the $10.4 million Enron recovery. The Company also benefited from capturing wider winter/summer spreads on stored volumes and from comparatively lower prices that positively impacted fuel costs associated with its long-term transportation contracts. There were no power volumes sold during the three months ended March 31, 2001 as the electric generating plant was still under construction during that time.

Operating costs increased for the three months ended March 31, 2002 compared to the same period in 2001 due to increased employee costs including the addition of power trading personnel and the reassignment of risk management personnel to the marketing and trading segment.

Capital expenditures for the three months ended March 31, 2001 included construction costs of $28.4 million related to the electric generating plant, which was completed in mid-2001.

Gathering and Processing

The Gathering and Processing segment currently owns and operates or leases and operates 25 gas processing plants and has an ownership interest in four additional gas processing plants that it does not operate. Six operated plants are temporarily idle. The total processing capacity of plants operated and the Company’s proportionate interest in plants not operated by the Company is 2.2 Bcf/d, of which 0.15 Bcf/d has been idled temporarily. A total of approximately 19,700 miles of gathering pipelines support the gas processing plants.

	Three Months Ended March 31,
	2002			2001

	(Thousands of Dollars)
Financial Results
Natural gas liquids and condensate sales	$	131,349		$	185,387
Gas sales		63,203			264,736
Gathering, compression, dehydration and processing fees and other revenues		21,043			26,469
Cost of sales		174,272			427,367

Net revenues		41,323			49,225
Operating costs		32,070			29,177
Depreciation, depletion, and amortization		7,970			6,811

Operating income	$	1,283		$	13,237

Other income, net	$	(39	)	$	—


	Three Months Ended March 31,
	2002			2001

Gas Processing Plants Operating Information
Total gas gathered (MMMBtu/d)		1,224			1,228
Total gas processed (MMMBtu/d)		1,358			1,212
Natural gas liquids sales (MBbls/d)		87			68
Natural gas liquids produced (MBbls/d)		66			62
Gas sales (MMMBtu/d)		344			396
Capital expenditures (Thousands)	$	10,808		$	7,151

The decrease in natural gas liquids and condensate sales revenues for the three months ended March 31, 2002, compared to the same period in 2001 is primarily due to a decrease in natural gas liquids (NGL) prices. This decrease was partially offset by an increase in NGL sales volumes due to a return to more normal processing operations in 2002 and through the addition of certain NGL pipeline facilities leased at the end of 2001, which increased the Company’s access to different markets. Gas sales and cost of sales decreased for the three months ended March 31, 2002 compared to the same period in 2001, primarily due to a reduction in gas prices and a reduction in volumes sold in 2002 as it was more economical to sell gas, rather than process gas, in 2001 due to the high value of natural gas relative to NGL prices. Additionally, gathering, compression, dehydration and processing fees and other revenues decreased due to lower compression and dehydration rates in 2002, which is directly related to the lower gas prices. The reduction in net revenues for the three months ended March 31, 2002 compared to the same period in 2001 is primarily associated with the decline in commodity prices, the relative value of NGLs compared to natural gas, the change in plant operations as a result of market conditions in 2002 compared to 2001, and the 2002 ice storm that caused plant outages across much of Oklahoma.

NGL sales and NGLs produced increased, and conversely gas sales decreased, for 2002 compared to 2001 because gas was not processed in 2001 due to the high value of natural gas relative to NGL prices. The Conway OPIS composite NGL price for 2002 decreased approximately 48 percent, from $0.634 per gallon for the quarter ended March 31, 2001 to $0.329 per gallon for the same period in 2002. Average natural gas price for the mid-continent region decreased from $7.02 per MMBtu for the three months ended March 31, 2001 to $2.21 per MMBtu for the same period in 2002.

Transportation and Storage

The Transportation and Storage segment represents the Company’s intrastate transmission pipelines and natural gas storage facilities. The Company has four storage facilities in Oklahoma, two in Kansas and three in Texas with a combined working capacity of approximately 58 Bcf, of which 8 Bcf is idled. The Company’s intrastate transmission pipelines operate in Oklahoma, Kansas and Texas and are regulated by the Oklahoma Corporation Commission (OCC), Kansas Corporation Commission (KCC), and Texas Railroad Commission (TRC), respectively.

	Three Months Ended March 31,
	2002		2001

	(Thousands of Dollars)

Financial Results
Transportation and gathering revenues	$	26,151	$	36,166
Storage revenues		7,547		9,954
Gas sales and other		15,505		7,083
Cost of fuel and gas		12,471		15,642

Net revenues		36,732		37,561
Operating costs		14,665		12,889
Depreciation, depletion, and amortization		4,574		4,750

Operating income	$	17,493	$	19,922

Other income, net	$	1,209	$	(841	)

Transportation and gathering revenues decreased for the three months ended March 31, 2002 compared to the same period in 2001 due to the decrease in price of natural gas and its impact on the sales value of retained fuel. Storage revenue decreased for the three months ended March 31, 2002 compared to the same period in 2001 due to a decrease in available capacity resulting from idling certain storage facilities in 2001. Gas sales and other increased in the quarter ended March 31, 2002 compared to the same period in 2001 due to the sale of operational inventory. This increase was partially offset by a discontinuation of certain gas contracts in 2001. For the three months ended March 31, 2002 compared to the same period in 2001, cost of fuel and gas decreased due primarily to the decrease in market prices partially offset by the increase in cost of sales relating to the sale of operational inventory. Net revenues for 2002 include $5.1 million for the sale of the operational inventory offset primarily by the decreases related to retained fuel and storage capacity, as discussed above.

	Three Months Ended March 31,
	2002		2001

Operating Information
Volumes transported (MMcf)		159,643		159,845
Capital expenditures (Thousands)	$	14,759	$	10,814

Distribution

The Distribution segment provides natural gas distribution services in Oklahoma and Kansas to residential, commercial and industrial customers. The Company’s operations in Oklahoma are primarily conducted through Oklahoma Natural Gas (ONG) that serves residential, commercial, and industrial customers and leases pipeline capacity. Operations in Kansas are conducted through Kansas Gas Service (KGS) that serves residential, commercial, and industrial customers. The Distribution segment serves about 80 percent of the population of Oklahoma and about 71 percent of the population of Kansas. ONG and KGS are subject to regulatory oversight by the OCC and KCC, respectively.

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

	Three Months Ended March 31,
	2002			2001

	(Thousands of Dollars)
Financial Results
Gas sales	$	474,637		$	737,716
Cost of gas		361,134			621,136

Gross margin		113,503			116,580
PCL and ECT Revenues		17,804			18,130
Other revenues		6,688			6,062

Net revenues		137,995			140,772
Operating costs		62,885			58,065
Depreciation, depletion, and amortization		16,949			16,977

Operating income (loss)	$	58,161		$	65,730

Other income, net	$	(336	)	$	—

The decrease in gas sales and cost of gas for the three months ended March 31, 2002 compared to the same period in 2001 is primarily attributable to decreased gas costs. Warmer than normal weather during the first quarter of 2002 also contributed to the decrease. The Company experienced high sales in the first quarter of 2001 due to colder than normal weather and high gas costs.

The increase in operating costs is primarily due to an increase in employee costs related to the increase in consolidated net income.

	Three Months Ended March 31,
	2002		2001

Gross Margin per Mcf
Oklahoma
Residential	$	1.92	$	1.99
Commercial	$	2.11	$	1.93
Industrial	$	1.43	$	1.05
Pipeline capacity leases	$	0.28	$	0.31
Kansas
Residential	$	1.60	$	1.53
Commercial	$	1.44	$	1.31
Industrial	$	1.42	$	1.41
Wholesale	$	0.13	$	0.51
End-use customer transportation	$	0.68	$	0.73

	Three Months Ended March 31,
	2002	2001

Volumes *(MMcf)*
Gas sales
Residential	50,913	53,772
Commercial	17,232	20,869
Industrial	1,476	1,951
Wholesale	5,469	1,318

Total volumes sold	75,090	77,910
PCL and ECT	42,607	39,431

Total volumes delivered	117,697	117,341

Residential gross margin per Mcf for the Oklahoma customers decreased for the three months ended March 31, 2002 compared to the same period in 2001 due to increased volumes in Oklahoma which resulted in customer-based fixed fees being spread over greater volumes. Increased volumes in Oklahoma relates to an increase in the number of customers partially offset by the warmer weather in Oklahoma compared to the same period in 2001. The increased volumes in Oklahoma were offset by decreased volumes in Kansas due to warmer weather, which resulted in a net decrease of volumes sold for the segment. Commercial and industrial gross margins per Mcf for Oklahoma customers increased due to reduced volumes, which resulted in customer-based fixed fees being spread over fewer volumes. Volumes decreased primarily due to the warmer weather. Pipeline capacity lease (PCL) gross margin decreased primarily due to an increase in volumes transported by high volume users that receive a discounted rate for the high volumes. Also, more customers qualify for the PCL and End-use customer transportation (ECT ) rates due to a reduction in the minimum capacity requirement pursuant to regulatory orders.

Gross margin per Mcf for the Kansas residential, commercial and industrial customers increased for the three-month period compared to the same period in 2001 due to normalized revenues spread across lower gas sales volumes. The Kansas weather normalization program minimizes the impact of weather extremes on the Company and its customers. Revenues billed to customers in excess of normal weather during colder years are returned to customers in the following year. Conversely, during a warm year the Company accrues revenues at a normal weather level and increases customer bills in the following year. Wholesale sales, also known as “As Available” gas sales, represent gas volumes available under contracts that exceed the needs of the Company’s residential and commercial customer base and are available for sale to other parties. The decrease in wholesale margins primarily relates to the lower gas prices. Wholesale volumes increased compared to the same period in 2001 as fewer volumes were required to meet the needs of the residential, commercial, and industrial customers due to the warmer weather, thus allowing more gas sales to wholesale customers. ECT margins decreased compared to 2001 due to an increase in volumes sold to customers that receive a discounted rate for large volume purchases.

	Three Months Ended March 31,
	2002		2001

Operating Information
Average Number of Customers		1,450,442		1,478,225
Capital expenditures (Thousands)	$	21,121	$	27,178
Customers per employee		624		583

The decrease in customers from March 31, 2001 to March 31, 2002 is due to more customers staying off the system for longer periods primarily due to the increased payments required to reconnect services and warmer weather.

Certain costs to be recovered through the rate making process have been recorded as regulatory assets in accordance with Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation”. Total regulatory assets resulting from this deferral process are approximately $232.3 million for the Distribution segment. Although no further unbundling of services is anticipated, should this occur, certain of these assets may no longer meet the criteria of a regulatory asset, and accordingly, a write-off of regulatory assets and stranded costs may be required. The Company does not anticipate that a write-off of costs, if any, will be material.

Production

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

	Three Months Ended March 31,
	2002		2001

	(Thousands of Dollars)
Financial Results
Natural gas sales	$	17,395	$	26,553
Oil sales		2,145		2,653
Other revenues		117		80

Net revenues		19,657		29,286
Operating costs		7,295		7,805
Depreciation, depletion, and amortization		9,174		7,585

Operating income	$	3,188	$	13,896

Other income, net	$	42	$	402

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

	Three Months Ended March 31,
	2002		2001

Operating Information
Proved reserves
Gas (MMcf)		234,555		252,582
Oil (MBbls)		4,647		4,173
Production
Gas (MMcf)		6,359		6,122
Oil (MBbls)		122		95
Average realized price (a)
Gas (Mcf)	$	2.74	$	4.34
Oil (Bbls)	$	17.65	$	27.78
Capital expenditures (Thousands)	$	11,622	$	11,261

(a) Average realized price reflects the impact of hedging activities

For the three months ended March 31, 2002 the average realized price of natural gas and the average realized price of oil were significantly lower than the same period in 2001. The decrease in the average realized prices were partially offset by increases in volumes sold. The three months ended March 31, 2002 also includes a recovery of $2.7 million related to the sale of the Enron claim. Additional employee costs of approximately $403 thousand were triggered by the income from the sale of the Enron claim and are included in operating costs. Depreciation, depletion, and amortization (DD&A) increased due to increased production of natural gas and oil and a higher DD&A rate per unit produced compared to the same period in 2001. At March 31, 2002, approximately 32 percent of remaining anticipated 2002 natural gas production is hedged at a wellhead price of $3.37 for the remainder of the year.

The Production segment added 6.3 Bcfe of net reserves in the first quarter of 2002 after adjustments, including 3.8 Bcfe proved developed, 0.5 Bcfe proved behind pipe, and 2.0 Bcfe proved undeveloped. Production of natural gas and oil in the first quarter of 2002 increased compared to the first quarter of 2001 due to the increased production capacity created from the higher level of drilling during 2001.

B. Financial Flexibility and Liquidity

Liquidity and Capital Resources

A part of the Company’s strategy has been and continues to be growth through acquisitions that strengthen and complement existing assets. The Company has relied primarily on a combination of operating cash flow and borrowings from a combination of commercial paper issuances, lines of credit, and capital markets for its liquidity and capital resource requirements. The Company expects to continue to use these sources for its liquidity and capital resource needs on both a short and long-term basis.

Financing is provided through the Company’s commercial paper program, long-term debt and, if needed, through a revolving credit facility. Other options to obtain financing include, but are not limited to, issuance of equity, asset securitization and sale/leaseback of facilities. The Company currently has a $500 million shelf registration in effect covering debt securities, including convertible debt and common stock. During 2001 and the first quarter of 2002, capital expenditures were financed through operating cash flows and short and long-term debt.

The Company’s credit rating may be affected by a material change in financial ratios or a material adverse event. The most common criteria for assessment of the Company’s credit rating are the debt to capital ratio, pre-tax and after-tax interest coverage and liquidity. If the Company’s credit rating was downgraded, the interest rates on the commercial paper would increase, therefore, increasing the Company’s cost to borrow funds. In the event, that the Company was unable to borrow funds under the commercial paper program, the Company has access to an $850 million revolving credit facility, which expires June 27, 2002 and the Company expects to renew. In addition, downgrades in the Company’s credit rating could impact the Marketing and Trading segment’s ability to do business by requiring the Company to post margins with the few counterparties with which the Company has a Credit Support Annex within its International Swaps and Derivatives Association Agreement. See further discussion of rating triggers in the Liquidity section of the Company’s Form 10-K for the year ended December 31, 2001.

The Company is subject to commodity price volatility. Significant fluctuations in commodity price in either physical or financial energy contracts may impact the Company’s overall liquidity due to the impact the commodity price change has on items such as the cost of gas held in storage, recoverability and timing of regulated natural gas costs, increased margin requirements, collectibility of certain energy related receivables and working capital. The Company believes that its current commercial paper program and debt capacity is adequate to meet liquidity requirements from commodity price volatility.

Enron—Certain of the financial instruments discussed in the Company’s Form 10-K for the year-ended December 31, 2001, have Enron North America as the counterparty. Enron Corporation and various subsidiaries, including Enron North America (Enron), filed for protection from creditors under Chapter 11 of the United States Bankruptcy Code on December 3, 2001. In 2001, the Company took a charge of $37.4 million thereby providing an allowance for forward financial positions and establishing an allowance for uncollectible accounts related to previously settled financial and physical positions with Enron. In the first quarter of 2002, the Company recorded a recovery of approximately $14.0 million, as a result of the agreement to sell the Enron claim, which is subject to normal representations as to the validity of the claims and the guarantees from Enron. The additional income from the sale of the Enron claim triggered increased employee costs of $5.5 million in the same period.

Oklahoma Corporation Commission—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 allowed ONG to commence collecting gas charges, subject to refund should the Company ultimately lose the case. In the fourth quarter of 2001, the Company took a charge of $34.6 million as a result of this order. The Company, along with the staff of the Public Utility Division and the Consumer Services Division of the OCC, the Oklahoma Attorney General, and other stipulating parties filed a joint agreement proposing settlement of this and other issues in April 2002. A hearing is expected in mid – May 2002.

Cash Flow Analysis

Operating Cash Flows

Operating cash flows for the three months ended March 31, 2002, as compared to the same period one year ago, were $420.8 million compared to $359.4 million. The changes in operating cash flows primarily reflect changes in working capital accounts, deferred income taxes and price risk management assets and liabilities. The change in price risk management assets and liabilities is primarily due to $13.7 million mark-to-market losses in the first quarter of 2002. In addition, the Marketing and Trading segment’s gas in storage, which is included in price risk management assets, decreased in the first quarter of due to lower gas volumes. Operating cash flows were negatively impacted in the current quarter by an increase in accounts receivable and a decrease in accounts payable. Accounts receivable would normally be expected to decrease from December 31, 2001 to March 31, 2002, as accounts receivable are typically higher during the heating season. However, accounts receivable increased during this period due to an increased UPGC rate in the first quarter of 2002 compared to the last quarter of 2001 and the receivable related to the sale of the Enron claim. Accounts payable decreased in the first quarter of 2002 as accounts payable is typically higher during the heating season. The decrease in inventories for the first quarter of 2002 and 2001 is due to the higher levels of gas in storage at December 31, 2001 and 2000, respectively, which are used throughout the remainder of the winter.

For the three months ended March 31, 2001, the changes in cash flow provided by operating activities primarily reflect changes in working capital accounts and an increase in price risk management assets and liabilities. The significant changes in the working capital accounts and price risk management assets and liabilities are primarily due to the historically higher gas prices. Accounts receivable and accounts payable are typically higher during the heating season, however, they were higher than normal at December 31, 2000 due to the higher gas prices and the integration of the businesses acquired in 2000.

Investing Cash Flows

Cash paid for capital expenditures for the three months ended March 31, 2002 was $60.9 million. For the same period in 2001, capital expenditures were $91.0 million, which included $28.4 million for the construction of the electric generating plant that was completed in the second quarter of 2001.

Financing Cash Flows

The Company’s capitalization structure is 43 percent equity and 57 percent long-term debt at March 31, 2002, compared to 42 percent equity and 58 percent long-term debt at December 31, 2001. At March 31, 2002, $1.7 billion of long-term debt was outstanding. As of that date, the Company could have issued $1. 1 billion of additional long-term debt under the most restrictive provisions contained in its various borrowing agreements.

The Company’s $850 million revolving credit facility is primarily used to support the commercial paper program. At March 31, 2002, $404.0 million of commercial paper was outstanding, which includes approximately $150.4 million in temporary investments and $152.2 million used to purchase natural gas that was injected in to storage. The seasonal needs of gas in storage result in increased notes payable at December 31, which are then paid throughout the first quarter of the following year.

C. Impact of Recently Issued Accounting Pronouncements

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

D. Other

Southwest Gas Corporation

Information related to the terminated proposed acquisition of Southwest Gas Corporation is presented in Note F in the Notes to the Consolidated Financial Statements and Part II, Item 1 of this Form 10-Q.

Item 4. Controls and Procedures

Within the 90 days prior to the filing date of this Amendment No. 1 to the Quarterly Report on Form 10-Q, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective in timely alerting them to material information required to be disclosed by us in our periodic reports to the Securities and Exchange Commission. There have been no significant changes in our internal controls or in other factors that could significantly affect our disclosure controls subsequent to the date of their evaluation.

Item 6. Exhibits and Reports on Form 8-K

(A) Documents Filed as Part of this Report


(99	)	Certification of David L. Kyle pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.

(99	)(a)	Certification of Jim Kneale pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.

Signatures

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

	ONEOK, Inc. Registrant

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 quarterly report on Form 10-Q of ONEOK, Inc.;

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

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

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

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

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

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

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

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

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

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

Date: November 12, 2002

/s/ David L. Kyle

Chief Executive Officer

Certification

I, Jim Kneale, certify that:

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

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

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

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

Date: November 12, 2002

/s/ Jim Kneale

Chief Financial Officer