Oneok - 10-Q quarterly report FY

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

Interim Reporting—The accompanying unaudited consolidated financial statements of ONEOK, Inc. and its subsidiaries (the “Company”) have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information. The interim consolidated financial statements reflect all adjustments, which, in the opinion of management, are necessary for a fair presentation of the results for the interim periods presented. All such adjustments are of a normal recurring nature. Due to the seasonal nature of the Company’s business, the results of operations for the three and nine months ended September 30, 2002, are not necessarily indicative of the results that may be expected for a twelve-month period. For further information, refer to the consolidated financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2001.

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

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

Energy Trading and Risk Management Activities—The Company engages in price risk management activities for both energy trading and non-trading purposes. The Company accounts for price risk management activities for its energy trading contracts in accordance with Emerging Issues Task Force Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10). EITF 98-10 requires entities involved in energy trading activities to account for energy trading contracts using mark-to-market accounting. Forwards, swaps, options, and energy transportation and storage contracts utilized for trading activities are reflected in the consolidated balance sheets at fair value as assets and liabilities resulting from price risk management activities. The fair value of these assets and liabilities is affected by the actual timing of settlements related to these contracts and current period changes resulting primarily from newly originated transactions and the impact of price movements. Changes in fair value are recognized in energy trading revenues, net in the consolidated statements of income. Market prices used to determine the fair value of these assets and liabilities reflect management’s best estimate considering various factors including closing exchange and over-the-counter quotations, time value and volatility underlying the commitments. Market prices are adjusted for the potential impact of liquidating the Company’s position in an orderly manner over a reasonable period of time under currently existing market conditions.

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

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

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

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

Regulation—The Company’s intrastate transmission pipelines and distribution operations are subject to the rate regulation and accounting requirements of the Oklahoma Corporation Commission (OCC), Kansas Corporation Commission (KCC) and Texas Railroad Commission (TRC). Certain other transportation activities of the Company are subject to regulation by the Federal Energy Regulatory Commission (FERC). Oklahoma Natural Gas (ONG) and Kansas Gas Service (KGS), both included in the Distribution segment, follow the accounting and reporting guidance contained in Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71). Allocation of costs and revenues to accounting periods for ratemaking and regulatory purposes may differ from allocations generally applied by non-regulated operations. Allocations of costs and revenues made by the Company to meet regulatory accounting requirements are considered to be in accordance with generally accepted accounting principles for regulated utilities.

During the ratemaking process, regulatory commissions may require a utility to defer recognition of certain costs to be recovered through rates over time as opposed to expensing such costs as incurred. This allows the utility to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. This causes certain expenses to be deferred as regulatory assets and amortized to expense as they are recovered through rates. Total regulatory assets resulting from this deferral process were approximately $225.0 million and $232.5 million at September 30, 2002 and December 31, 2001, respectively. Should unbundling of services occur, certain of these assets may no longer meet the criteria for accounting for these assets in

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

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

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

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

The Company computes its earnings per common share (EPS) in accordance with a pronouncement of the Financial Accounting Standards Board’s Staff at the Emerging Issues Task Force meeting in April 2001, codified as EITF Topic No. D-95 (Topic D-95). In accordance with Topic D-95, the dilutive effect of the Company’s Series A Convertible Preferred Stock is considered in the computation of basic EPS utilizing the “if-converted” method. Under the Company’s “if-converted” method, the dilutive effect of the Company’s Series A Convertible Preferred Stock on EPS cannot be less than the amount that would result from the application of the “two-class” method of computing EPS. The “two-class” method is an earnings allocation formula that determines EPS for the Company’s common stock and its participating Series A Convertible Preferred Stock according to dividends declared and participating rights in the undistributed earnings. The Company’s Series A Convertible Preferred Stock is a participating instrument with the Company’s common stock with respect to the payment of dividends. For all periods presented, the “two-class” method resulted in additional dilution. Accordingly, EPS for such periods reflects this further dilution.

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

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

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

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

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

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

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

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

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

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

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

Environmental—The Company has 12 manufactured gas sites in Kansas, which were acquired in 1997, that may contain potentially harmful materials classified as hazardous. Hazardous materials are subject to control or remediation under various state and federal environmental laws and regulations. A consent agreement with the Kansas Department of Health and Environment (KDHE) presently governs all future work at these sites. The terms of the consent agreement allow the Company to investigate and set remediation priorities for these sites based upon the results of the investigations and risk analysis. The prioritized sites will be investigated over a period of time as negotiated with the KDHE. Through September 30, 2002, the costs of the investigation and risk analysis related to these manufactured gas sites have been immaterial. Although remedial investigation and interim clean up has begun on four sites, limited information is available about the sites. Management’s best estimate of the cost of remediation ranges from $100,000 to $10 million per site based on a limited comparison of costs incurred to remediate comparable sites. These estimates do not give effect to potential insurance recoveries, recoveries through rates or recoveries from unaffiliated parties. The KCC has permitted others to recover remediation costs through rates. It should be noted that additional information and testing could result in costs significantly below or in excess of current estimates. To the extent that such remediation costs are not recovered, the costs could be material to the Company’s results of operations and cash flows depending on the remediation done and number of years over which the remediation is completed.

Yaggy Facility—In January 2001, the Company’s Yaggy gas storage facility, located approximately seven miles from Hutchison, Kansas, was idled following a series of natural gas explosions and eruptions of natural gas geysers which occurred within the city limits. In July 2002, the KDHE issued an administrative order that assessed a $180,000 civil penalty against the Company, based on alleged violations of several KDHE regulations. The Company requested a hearing on the administrative order and a status conference has been set for November 12, 2002. The Company believes there are no long-term environmental effects from the Yaggy storage facility.

Two separate class action lawsuits have been filed against the Company in connection with the natural gas explosions and eruptions of natural gas geysers that occurred in Hutchinson, Kansas in January 2001. These class action lawsuits were filed on the grounds that the eruptions and explosions related to natural gas that allegedly escaped from the Yaggy storage facility. Although no assurances can be given, the Company believes that the ultimate resolution of these matters will not have a material adverse effect on its financial position or results of operations. The Company’s insurance carrier in these cases represents the Company and its subsidiaries. The Company is vigorously defending itself against all claims.

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

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

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

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

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

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

The accounting policies of the segments are substantially the same as those described in the Summary of Significant Accounting Policies in the Company’s Annual Report on Form 10-K for the year ended December 31, 2001, except for the change in energy trading and risk management

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