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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

OR

Commission file number 001-13643

ONEOK, Inc.

(Exact name of registrant as specified in its charter)

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

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

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

None

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

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

Indicate by checkmark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes  x  No  ¨.

Aggregate market value of registrant’s common stock held by non-affiliates based on the closing trade price on March 1, 2003, was $1,285.5 million

On March 1, 2003, the Company had 74,608,031 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

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ONEOK, Inc.

2002 ANNUAL REPORT ON FORM 10-K

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

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PART I.

ITEM 1. BUSINESS

General

ONEOK, Inc., an Oklahoma corporation, was organized on May 16, 1997. On November 26, 1997, we acquired the natural gas business of Westar Energy Corp. (formerly Western Resources, Inc.) and merged with ONEOK Inc., a Delaware corporation organized in 1933. We are the successor to a company founded in 1906 as Oklahoma Natural Gas Company.

ONEOK is a diversified energy company. We purchase, gather, process, transport, store, and distribute natural gas. We drill for and produce oil and natural gas, extract, sell and market natural gas liquids, and are engaged in the natural gas, crude oil and natural gas liquids marketing and trading business. We also own and operate an electric generating plant and engage in wholesale marketing of electricity. Our energy marketing and trading operations provide service to customers throughout most of the United States. We are the largest natural gas distributor in Kansas and Oklahoma and, following the acquisition of the Texas properties of Southern Union Company discussed below, the third largest gas distributor in Texas.

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

Also, on January 28, 2003, we issued 14 million equity units at a public offering price of $25 per unit, resulting in net proceeds to us, after underwriting discounts and commissions, of $24.25 per share, or $339.5 million in the aggregate. An over-allotment option allowing the purchase of an additional 2.1 million equity units was exercised on January 31, 2003, increasing the net proceeds to $390.4 million. Each equity unit consists of a stock purchase contract for the purchase of shares of our common stock and, initially, a senior note due February 16, 2008, issued pursuant to our existing Indenture with SunTrust Bank, as trustee. The equity units carry a total annual coupon rate of 8.5% (4.0% annual face amount of the senior notes plus 4.5% annual contract adjustment payments). Each stock purchase contract issued as a part of the equity units carries a maximum conversion premium of up to 20 percent over the $17.19 closing price of our common stock on January 22, 2003, and a floor of $17.19 per share.

The net proceeds from the sale of the equity units will be allocated between the stock purchase contracts and the senior notes in proportion to their respective fair market values at the time of issuance. The present value of the equity units contract adjustment payments will be initially charged to shareholders’ equity, with an offsetting credit to liabilities. This liability is accreted over three years by interest charges to the income statement based on a constant rate calculation. Subsequent contract adjustment payments reduce this liability. The purchase contracts are forward contracts in our common stock. Upon settlement of each purchase contract, we will receive $25 on the purchase contract and will issue the requisite number of shares of our common stock. The $25 that we receive will be credited to shareholders’ equity.

In February 2003, $300 million of the proceeds from these offerings was used to repurchase approximately 9 million shares (approximately 18.1 million shares of common stock equivalents) of our Series A Convertible Preferred Stock from Westar. The remaining 10.9 million shares of Series A Convertible Preferred Stock owned by Westar were exchanged for approximately 21.8 million shares of ONEOK’s $0.925 Series D Convertible Preferred Stock. The Series A Convertible Preferred Stock was convertible into two shares of common stock, reflecting the two-for-one stock split in 2001, and the Series D Convertible Preferred stock is convertible into one share of common stock.

Definitions

Following are definitions of abbreviations used in this Form 10-K:

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Acquisitions and Sales

Our business strategy is focused on the maximization of shareholder value by vertically integrating our natural gas business operations from the wellhead to the burner tip. We expect to continue evaluating and assessing acquisition opportunities to further complement our existing asset base. We also, from time to time, sell assets when deemed less strategic or as other conditions warrant.

Sale of Production Assets – On January 31, 2003, we closed the sale of approximately 70 percent of the natural gas and oil producing properties of our production segment to Chesapeake Energy Corporation for a cash sales price of approximately $300 million, subject to adjustment. The effective date of the sale was November 30, 2002. The sale included approximately 1,900 wells, 482 of which we operated. We recorded a pretax gain of approximately $74.4 million in the first quarter of 2003 related to this sale. The statistical and financial information related to the properties sold are reflected as a discontinued component in this Annual Report on Form 10-K. All periods presented have been restated to reflect the discontinued component.

Acquisition of Texas Properties of Southern Union Company – On January 3, 2003, we closed the purchase of all of the Texas assets of Southern Union Company (Southern Union) for a cash purchase price of approximately $420 million, subject to a working capital adjustment to be determined within 90 days of the closing of the transaction. The acquisition makes us the fifth largest gas distributor in the U.S. with almost two million customers in Oklahoma, Kansas and Texas. The assets acquired consist of the third largest gas distribution business in Texas, with operations that serve approximately 535,000 customers, over 90 percent of which are residential. Approximately 735 employees were added to our workforce as part of the acquisition.

Sale of Midstream Natural Gas Assets – On December 13, 2002, we closed the sale of some of our midstream natural gas assets for a cash sales price of approximately $92 million to an affiliate of Mustang Fuel Corporation, a private, independent oil and gas company. The assets that were sold are located in north central Oklahoma and include three natural gas processing plants and related gathering systems and our interest in a fourth natural gas processing plant. The sale of these assets is part of our strategy to dispose of assets that are not considered core assets for our future.

Sale of Investment in Magnum Hunter Resources – In the second quarter of 2002, we sold our remaining shares of common stock of Magnum Hunter Resources (MHR) for a pre-tax gain of approximately $7.6 million, which is included in other income for the year ended December 31, 2002. We retained approximately 1.5 million common stock purchase warrants.

Sale of Investment in K. Stewart Petroleum Corporation – In June 2001, we sold our forty percent interest in K. Stewart Petroleum Corporation (K. Stewart), a privately held exploration company, for a sales price of $7.7 million.

Acquisition of Kinder Morgan, Inc. Assets – In April 2000, we acquired certain natural gas gathering and processing assets located in Oklahoma, Kansas and western Texas from Kinder Morgan, Inc. (KMI) and certain of its affiliates. We also acquired KMI’s marketing and trading operations, as well as some storage and transmission pipelines in the mid-continent region. We paid approximately $123.5 million for these assets. We also assumed certain liabilities including an uneconomic lease obligation related to an operating lease for a processing plant and some firm capacity lease obligations to unaffiliated parties with out-of-market terms. This acquisition included more than 12,000 miles of gathering and transportation pipeline,

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natural gas processing plants with capacity of 1.26 Bcf/d and storage facilities with a combined capacity of approximately 10 Bcf. Approximately 350 employees were added to our workforce as part of the acquisition.

Acquisition of Dynegy, Inc. Assets – In March 2000, we acquired natural gas processing plants with an approximate capacity of 375 MMcf/d and approximately 7,000 miles of gas gathering and transmission pipeline systems in Oklahoma, Kansas and Texas from Dynegy, Inc. (Dynegy). We paid approximately $305 million for these assets. Approximately 75 employees were added to our workforce as part of the acquisition. The majority of these employees are in field operations in western Oklahoma, the Texas panhandle and southern Kansas.

Sale of Indian Basin Gas Processing Plant – In 2000, we sold our 42.4 percent partnership interest in the Indian Basin Gas Processing Plant and gathering system for a sales price of $55 million to El Paso Field Services Company, a business unit of El Paso Energy Corporation, resulting in a gain of approximately $26.7 million.

Business Segments

We report operations in the following reportable segments:

Marketing and Trading – Our Marketing and Trading segment conducts its business through ONEOK Energy Marketing and Trading Company (OEMT) and its subsidiaries. OEMT is actively engaged in value creation through marketing and trading of natural gas to both wholesale and retail customers throughout the United States using leased gas storage and firm transportation capacity from related parties and others. We have executed an integrated wholesale energy business strategy based on expanding our existing marketing, trading and arbitrage opportunities in the natural gas and power markets. The combination of owning or controlling strategic assets and having a trusted, reliable marketing franchise allows us to capture volatility in the energy markets.

We primarily conduct our operations in the mid-continent region of the U.S. However, acquisitions during 2000 allowed us to expand our marketing and trading presence from border to border and coast to coast.

OEMT was the successful bidder to supply gas to Oklahoma Natural Gas Company (ONG), an affiliated company, for its gas sales requirements for five years beginning in November 2000. In response, we entered into firm supply arrangements with major producers and large independents that average in length from two to five years.

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

Gathering and Processing – Our Gathering and Processing segment gathers and processes natural gas and fractionates, stores and markets NGLs primarily through its subsidiaries, ONEOK Field Services Company (OFS) and ONEOK NGL Marketing L.P. (NGL Marketing). These activities are conducted primarily in Oklahoma, Kansas and Texas.

Transportation and Storage – Our Transportation and Storage segment provides natural gas transportation, storage, and nonprocessable gas gathering services. These operations are primarily conducted through Mid Continent Market Center, Inc. (MCMC), ONEOK Gas Transportation, L.L.C. (OGT), ONEOK WesTex Transmission, L.P. (WesTex), ONEOK Gas Storage, L.L.C. (OGS), ONEOK Sayre Storage Company (Sayre), ONEOK Texas Gas Storage L.P. (OTGS) and ONEOK Gas Gathering, L.L.C. (OGG). Acquisitions in 2000 expanded our transmission and storage operations into Texas with the acquisition of OTGS and WesTex. The Texas Railroad Commission (TRC) regulates both OTGS and WesTex. OGS and Sayre operate under market-based rate authority granted by the Federal Energy Regulatory Commission (FERC). In a May 2000 Oklahoma Corporation Commission (OCC) Order, OGT became a separate regulated utility from the Distribution segment and its operations are regulated by the OCC. MCMC’s operations continue to be regulated by the Kansas Corporation Commission (KCC). In October 2001, OGG was created by merging the gathering assets of OGT with ONEOK Producer Services, L.L.C. In July 2002, we completed a transaction to transfer certain transmission assets in Kansas to our affiliated distribution company in Kansas. All historical financial and statistical information has been adjusted to reflect this

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transfer. In December 2002, we sold Sayre’s property rights and entered into a long-term agreement with the purchaser whereby we retain working storage capacity consistent with our historical usage.

Distribution – Our Distribution segment provides natural gas distribution in Oklahoma and Kansas and interstate transportation across the Oklahoma/Texas border. Our distribution operations in Oklahoma and Kansas are conducted through ONG and Kansas Gas Service (KGS), respectively, both divisions of ONEOK, Inc., which serve residential, commercial, and industrial customers. ONG is regulated by the OCC and KGS is regulated by the KCC. The Distribution segment serves approximately 80 percent of Oklahoma’s population and 75 percent of Kansas’ population.

Production – Our Production segment produces natural gas and oil primarily in Oklahoma, Kansas and Texas through ONEOK Resources Company. The Production segment’s strategy is to acquire and develop properties and maximize value by producing the properties or divesting the properties at attractive prices. In November 2002, we entered into an agreement to sell approximately 70 percent of our proved properties for $300 million before adjustments. The properties sold are reflected as discontinued operations at December 31, 2002. The sale was completed on January 31, 2003. The financial and statistical information for all periods presented has been restated to reflect the discontinued operations presentation. During 2002, we participated in drilling 117 wells of which 92 were gas, 15 were oil and 10 were dry holes. We retained 38 of the wells we participated in drilling in 2002, of which 25 were gas, 7 were oil and 6 were dry holes. We sold 79 of the wells we participated in drilling, of which 67 were gas, 8 were oil and 4 were dry holes.

Other – The primary companies in our Other segment include ONEOK Leasing Company and ONEOK Parking Company. ONEOK Leasing Company leases, from an unaffiliated partnership, and operates our headquarters office building. ONEOK Parking Company owns and operates a parking garage adjacent to our corporate headquarters.

Segment Financial Information – For financial and statistical information regarding our business units by segment, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note O of Notes to Consolidated Financial Statements.

Environmental Matters

We have 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 us to investigate these sites and set remediation priorities based upon the results of the investigations and risk analysis. Remedial investigation has commenced on four sites. However, a comprehensive study is not complete and the results to date do not provide a sufficient basis for a reasonable estimation of the total liability. The liability accrued is reflective of an estimate of the total cost of remedial investigation and feasibility study. Through December 31, 2002, the costs of the investigations and risk analysis related to these manufactured gas sites have been immaterial. The site situations are not common and we have no previous experience with similar remediation efforts. The information currently available estimates the cost of remediation from $100,000 to $10 million per site based on a limited comparison of costs incurred by others to remediate comparable sites. As such, the information provides an insufficient basis to reasonably estimate a minimum range of our liability. These estimates do not give effect to potential insurance recoveries, recoveries through rates or from unaffiliated parties. At this time, we are not recovering any environmental amounts in rates. The KCC has permitted others to recover remediation costs through rates. It should be noted that additional information and testing could result in costs significantly below or in excess of the amounts estimated above. To the extent that such remediation costs are not recovered, the costs could be material to our results of operations and cash flows depending on the remediation done and number of years over which the remediation is completed.

Our expenditures for environmental evaluation and remediation have not been significant in relation to the results of operations. There have been no material effects upon earnings or our competitive position during 2002 related to compliance with environmental regulations.

Employees

We employed 3,593 persons at December 31, 2002. The acquisition of the Texas assets of Southern Union added approximately 735 employees to our workforce in 2003. We did not experience any strikes or work stoppages during 2002. KGS employed 844 people who were subject to collective bargaining contracts as of December 31, 2002. The following table sets forth our contracts with unions at December 31, 2002:

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SEC Filings

We file annual, quarterly and special reports, proxy statements and other information with the Securities and Exchange Commission (SEC). You can read and copy any materials we file with the SEC at its Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. You can obtain information about the operations of the SEC Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website that contains information we file electronically with the SEC, which you can access over the Internet at www.sec.gov. Our Common Stock is listed on the New York Stock Exchange (NYSE: OKE), and you can obtain information about us at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005.

Website Information

You can access financial and other information at our website. The address is www.oneok.com. We make available, free of charge, copies of our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and reports of holdings of our securities filed by our officers and directors under Section 16 of the Securities Exchange Act of 1934 as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the Securities and Exchange Commission.

DESCRIPTION OF BUSINESS SEGMENTS

Marketing and Trading

General – We are engaged in the marketing and trading of natural gas to retail and wholesale customers throughout most of the United States. Due to expanded supply, storage capabilities, and recent acquisitions, we market gas from border to border and coast to coast. We have also diversified our marketing and trading portfolio to include power, crude oil and natural gas liquids.

Operating income from the Marketing and Trading segment, including a $37.4 million charge related to Enron in 2001 as discussed in the Liquidity section, is 48.9 percent, 29.3 percent, and 15.8 percent of the consolidated operating income from continuing operations for fiscal years 2002, 2001, and 2000, respectively. The Marketing and Trading segment has no single external customer from which it receives ten percent or more of consolidated revenues.

We engage in price risk management activities for both energy trading and non-trading purposes. We account for price risk management activities for our energy trading contracts in accordance with Emerging Issues Task Force Issue No. 98-10, “Accounting for 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 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 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 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 our position in an orderly manner over a reasonable period of time under present market conditions.

During the third quarter of 2002, we adopted the applicable provisions of Emerging Issues Task Force Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3). EITF 02-3 provides that all mark-to-market gains and losses on energy trading

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contracts should be presented on a net basis (energy contract sales less energy contract costs) in the income statement without regard to the settlement provisions of the contract. Prior to the third quarter of 2002, energy trading revenues and costs were presented on a gross basis. The financial results of all energy trading contracts have been restated to reflect the adoption of this provision of EITF 02-3. Energy trading revenues include natural gas, reservation fees, crude oil, natural gas liquids, and basis. Basis is the natural gas price differential that exists between two trading locations relative to the Henry Hub price.

In October 2002, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) rescinded EITF 98-10. As a result, energy-related contracts that are not accounted for pursuant to Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133), will no longer be carried at fair value but rather will be accounted for on an accrual basis as executory contracts. 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 fiscal periods beginning after December 31, 2002 and for all existing energy trading contracts and inventory as of October 25, 2002. Additionally, the rescission applies immediately to contracts entered into on or after October 25, 2002. Changes to the accounting for existing contracts as a result of the rescission of EITF 98-10 will be reported as a cumulative effect of a change in accounting principle on January 1, 2003. At this time, we estimate this will result in a cumulative effect loss, net of tax, of approximately $141.0 million. Any impact from this change will be non-cash. All recoveries of the estimated value associated with this change in accounting will be recognized in operating income in future periods. The impact of adopting the rescission of EITF 98-10 will be included in our March 31, 2003 financial statements.

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

Market Conditions and Business Seasonality – In response to a very competitive marketing and trading environment resulting from continued deregulation of the retail natural gas markets and the restructuring of the U.S. retail and wholesale electricity markets, our strategy is to concentrate our efforts on capitalizing on short-term pricing volatility through marketing, trading and arbitrage opportunities provided by leasing or ownership of storage, generation and transportation assets. We focus on building and strengthening supplier and customer relationships to execute our strategy. Our strategy has also benefited from overall market conditions generated from large energy merchant and trading operations becoming under capitalized and having lower credit quality.

The Marketing and Trading segment’s net revenues are subject to fluctuations during the year primarily due to the impact certain seasonal factors have on sales volumes and the price of natural gas, electricity, crude oil and natural gas liquids. Natural gas sales volumes are typically higher in the winter heating months than in the summer months, reflecting increased demand due to greater heating requirements and, typically, higher natural gas prices that occur during the winter heating months.

Price Risk Management – In order to mitigate the risks associated with energy trading activities, we manage our portfolio of contracts and its assets in order to maximize value, minimize the associated risks and provide overall liquidity. In doing so, we use price risk management instruments, including swaps, options, futures and physical commodity-based contracts to manage exposures to market price movements. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Note D of Notes to Consolidated Financial Statements for further discussion.

Gathering and Processing

General – Our Gathering and Processing segment is engaged in the gathering and processing of natural gas and the fractionation, storage and marketing of NGLs. We have a processing capacity of approximately 1.993 Bcf/d, of which approximately 0.107 Bcf/d is currently idle. The remaining capacity associated with plants owned or leased is approximately 1.776 Bcf/d, while the amount of the plant capacity that we own an interest in but do not operate is approximately 0.110 Bcf/d. We own approximately 13,962 miles of gathering pipelines that supply our gas processing plants.

Operating income from the Gathering and Processing segment is 8.9 percent, 17.0 percent, and 34.2 percent of the consolidated operating income from continuing operations in 2002, 2001, and 2000, respectively. The Gathering and Processing segment has no single external customer from which it receives ten percent or more of consolidated revenues.

The gas processing operation includes the extraction of NGLs from natural gas and the fractionation (separation) of mixed NGLs into component products (ethane, propane, iso butane, normal butane and natural gasoline). We also extract helium,

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from time to time, at two of our plants located in Kansas. The NGL component products are used by and sold to a diverse customer base of end users for petrochemical feedstock, residential uses, and blending into motor fuels. The gathering operation, which connects unaffiliated and affiliated producing wells to the processing plants, consists of the gathering of natural gas through pipeline systems, including compression and dehydration services.

We generally process gas under three types of contracts. Under our “percent of proceeds” (POP) contracts, the producer is paid a percentage of the market value of the natural gas and NGLs that are processed. Our “keep whole” contracts allow us to replace the Btu’s extracted as NGLs with equivalent Btu’s of natural gas, which keeps the producer whole on Btu’s and allows us to retain and sell the NGLs. Under “fee” contracts, we are paid a cash fee for gas processing.

During 2002, we processed an average of 1,411 MMMBtu/d of natural gas and produced an average of 72.8 MBbls/d of NGLs. We market our NGL production through ONEOK NGL Marketing and also purchase NGLs from third parties for resale. During 2002, we sold approximately 95.4 MBbls/d of NGLs to a diverse base of customers.

Market Conditions and Business Seasonality – During the year, both crude oil and natural gas prices were volatile with NYMEX crude prices ranging from $18.34 to $30.11 per barrel and NYMEX natural gas prices ranging from $2.01 to $4.14 per MMBtu. The continued weak economy reduced the demand for many NGL products, particularly ethane and propane, which are major components of plastic products.

Despite significant consolidation in the recent past, the U.S. midstream industry remains relatively fragmented and faces competition from a variety of companies including major integrated oil companies, major pipeline companies and their affiliated marketing companies, and national and local gas gatherers, processors and marketers. Competition exists for obtaining gas supplies for gathering and processing operations, obtaining supplies of raw product for fractionation and the transportation of natural gas and NGLs. The factors that affect competition typically arise as a result of the efficiency and reliability of the operations, price and delivery capabilities.

We have responded to these industry conditions by acquiring assets, most of which are strategically located near our existing assets, reducing costs, rationalizing assets in non-core operating areas and renegotiating unprofitable contracts. The principal goal of these efforts is to mitigate the variability of earnings and cash flow caused by fluctuations in commodity prices.

The Gathering and Processing segment is subject to seasonality. Products are used for heating and are normally more in demand during the months of November through March. Accordingly, the prices of these products are typically higher in the winter.

Acquisitions and Divestitures – In December 2002, we completed the sale of three processing plants and related gathering assets, along with our interest in a fourth processing plant, all located in Oklahoma, to an affiliate of Mustang Fuel Corporation. These plants had a processing capacity of 0.136 Bcf/d. The sale also included approximately 2,800 miles of gathering pipelines that supply our gas processing plants.

In April 2000, we acquired certain natural gas gathering and processing assets from KMI. This acquisition included natural gas processing plants with a capacity of approximately 1.26 Bcf/d and 6,400 miles of gathering lines. In March 2000, we acquired natural gas processing plants with a capacity of approximately 375 MMcf/d and approximately 7,000 miles of gas gathering and transmission pipeline systems from Dynegy.

Government Regulation – The FERC has traditionally maintained that a processing plant is not a facility for transportation or sale for resale of natural gas in interstate commerce and therefore is not subject to jurisdiction under the Natural Gas Act (NGA). Although the FERC has made no specific declaration as to the jurisdictional status of our gas processing operations or facilities, our gas processing plants are primarily involved in removing natural gas liquids and therefore, we believe, are exempt from FERC jurisdiction. The NGA also exempts natural gas gathering facilities from the jurisdiction of the FERC. Interstate transmission facilities, on the other hand, remain subject to FERC jurisdiction. The FERC has historically distinguished between these two types of facilities on a fact-specific basis. We believe our gathering facilities and operations meet the criteria used by the FERC to determine a non-jurisdictional gathering facility status. We can transport residue gas from our plants to interstate pipelines in accordance with Section 311(a) of the Natural Gas Policy Act (NGPA).

The states of Oklahoma, Kansas and Texas also have statutes regulating, in various degrees, the gathering of gas in those states. In each state, regulation is applied on a case-by-case basis if a complaint is filed against the gatherer with the appropriate state regulatory agency.

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Risk Management – Derivative instruments are used to minimize volatility in NGL and natural gas prices. Accordingly, we, at times, use derivative instruments to hedge the purchase and sale of natural gas used for or produced by our operations. We also, from time to time, use derivative instruments to secure a certain price for NGL products. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Note D of Notes to the Consolidated Financial Statements.

Transportation and Storage

General – Our Transportation and Storage segment provides intrastate natural gas pipeline transportation, Section 311(a) of the NGPA interstate transportation, nonprocessable gas gathering and storage services in Oklahoma, Kansas, and Texas. We conduct this business primarily through wholly-owned intrastate pipeline companies with approximately 7,700 miles of pipe and wholly-owned storage companies with a working storage capacity of approximately 59.6 Bcf.

In Oklahoma, we operate OGT and OGS. These companies have approximately 2,858 miles of pipeline and five storage facilities with a combined working storage capacity of 44.6 Bcf. One of these storage facilities is leased through a long-term agreement through which we retained 3 Bcf of working storage capacity for our own use. Our Distribution segment is this segment’s major customer for intrastate natural gas pipeline transportation in Oklahoma. Capacity in the storage facilities is leased to both OEMT and third parties under terms determined by contract or market. In December 2002, we sold properties and as part of the transaction retained 3 Bcf of working storage capacity. A $3.4 million expansion to increase deliverability from the OGS Depew storage field was completed in the spring of 2000.

The Oklahoma transmission system transported 257.2 Bcf in 2002, 253.9 Bcf in 2001, and 299.1 Bcf in 2000. OGT provides access to the major natural gas producing areas in Oklahoma. The system intersects 11 intrastate and interstate pipelines at 27 interconnect points and connects 21 processing plants and approximately 130 producing fields, allowing gas to be moved throughout the state.

In Kansas, we operate MCMC. In July 2002, we completed a transaction to transfer certain transmission assets in Kansas from MCMC to our affiliated distribution company in Kansas. All historical financial and statistical information has been adjusted to reflect this transfer. MCMC currently operates 204 miles of pipeline and three gas storage facilities with approximately 5.6 Bcf of working storage capacity. In January 2001, the Yaggy storage facility’s operating parameters were changed as mandated by the KDHE following natural gas explosions and eruptions of natural gas geysers in or near Hutchinson, Kansas. This removed injection capabilities related to 3 Bcf of our Kansas working storage capacity. We are considering the steps necessary to return the field to full service, but final steps will not be determined until the final KDHE regulations are issued, which is expected in 2003. MCMC has access to the major natural gas producing area in south central Kansas. The system intersects four different intrastate and interstate pipelines at six interconnect points and is connected to two processing plants and associated producing fields.

In Texas, we operate WesTex and OTGS. These companies have approximately 4,701 miles of pipeline and three storage facilities. Total working storage capacity is approximately 9.4 Bcf. Both WesTex and OTGS were acquired from KMI in April 2000. The Texas transmission system transported 227.3 Bcf in 2002, 206.4 Bcf in 2001 and 170.8 Bcf in 2000. WesTex is connected to the major natural gas producing areas in the Texas Panhandle and the Permian Basin. The system intersects with a total of 11 different interstate and intrastate pipelines at 32 interconnect points and 11 natural gas processing plants and two producing fields. This system provides for gas to be moved to the Waha Hub for transportation to the east to the Houston Ship Channel market and west to the California market. This pipeline allows us to provide service to the city of El Paso, Texas. The Loop storage facility remains operational with both injection and withdrawal capabilities. However, due to certain unresolved contractual issues, this facility is being used minimally. As a result of the reduced utilization, we have approximately 5 Bcf less of Texas’ working storage capacity in use.

OGG operates our gathering pipelines that are connected to our transmission pipelines, including gathering systems previously owned by OGT and ONEOK Producer Services, L.L.C.

The majority of the Transportation and Storage segment’s revenues are derived from services provided to affiliates. Operating income from the Transportation and Storage segment is 14.4 percent, 20.8 percent, and 17.6 percent of consolidated operating income from continuing operations in 2002, 2001, and 2000, respectively. The Transportation and Storage segment has no single external customer from which it receives ten percent or more of consolidated revenues.

Market Conditions and Seasonality – The Transportation and Storage segment primarily serves local distribution companies (LDCs), large industrial companies and marketing companies that serve both LDCs and large industrial customers. We compete directly with other intrastate and interstate pipelines and storage facilities within each of their

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respective states. Competition for transportation services continues to increase as the FERC and state regulatory bodies introduce more competition in the natural gas markets. Factors that affect competition are location, price and quality of services provided. This industry is significantly affected by the strength of the economy and price volatility. We believe that the working capacity of our transportation and storage assets enables us to compete effectively.

The Transportation and Storage segment is impacted by various weather conditions. Transportation quantities fluctuate due to rainfall, which impacts irrigation demand, hot temperatures, which affect power generation demand, and cold temperatures that affect heating demand. Historically, customers have purchased and stored gas in the summer months when prices were lower and withdrew gas during the heating season; however, increased price volatility in the natural gas market can mitigate the seasonality effect by influencing decisions relating to injection and withdrawal of natural gas in storage.

Government Regulations – Our transportation assets in Oklahoma are regulated by the OCC and in Kansas are regulated by the KCC. We have flexibility in establishing transportation rates with customers; however, there is a maximum rate that we can charge our customers in both states.

Our transportation and storage assets located in Texas are regulated by the TRC. We have flexibility in establishing transportation rates with customers; however, if a rate cannot be agreed upon, the rate is established by the TRC.

In January 2001, the Yaggy storage facility’s operating parameters were changed as mandated by the KDHE following natural gas explosions and eruptions of natural gas geysers in or near Hutchinson, Kansas. This removed injection capabilities related to 3 Bcf of our Kansas storage capacity. We are considering the steps necessary to return the field to full service, but final steps will not be determined until the final KDHE regulations are issued, which are expected in 2003.

Customers – The Transportation and Storage segment serves the affiliated companies of the Distribution segment and Marketing and Trading segment, as well as a number of transporters in the utilization of the transportation and storage facilities. Each of the companies provides flexible service alternatives to serve consumers. In June 2001, we announced the execution of long-term agreements between OGT and InterGen North America (InterGen) for firm transportation service to InterGen’s gas fueled Redbud Energy Facility near Luther, Oklahoma, in the amount of 200 MMcf/d. In June 2001, commercial operation for gas transportation began to the NRG McClain Generating Facility, which is connected to the OGT system, for transportation volumes up to 85 MMcf/d.

Acquisitions and Divestitures – We acquired transportation and storage assets located in Texas from KMI in April 2000. These assets are strategic assets to us, in part since they give us access to an expanded area in the Texas and California markets. In December 2002, we sold Sayre’s property rights and entered into a long-term agreement with the purchaser whereby we retain storage capacity consistent with our original ownership position.

Distribution

General – ONG distributes natural gas to wholesale and retail customers located in the state of Oklahoma. At December 31, 2002, ONG delivered natural gas to approximately 809,000 customers in 327 communities in Oklahoma. ONG’s largest markets are the Oklahoma City and Tulsa metropolitan areas. ONG also sells natural gas to other local gas distributors serving 39 Oklahoma communities. During 2000, the Oklahoma customers of KGS were removed from the KGS customer base and became ONG customers.

At December 31, 2002, KGS supplied natural gas to approximately 641,000 customers in 340 communities in Kansas. It also makes wholesale delivery to 10 customers. KGS’s largest markets served include Kansas City, Wichita, Topeka, and Johnson County, which includes Overland Park, Kansas.

Operating income from the Distribution segment is 25.6 percent, 24.0 percent, and 32.8 percent of the consolidated operating income from continuing operations for fiscal years 2002, 2001, and 2000, respectively. The Distribution segment has no single external customer from which it receives ten percent or more of consolidated revenues.

Gas Supply – Gas supplies available to ONG for purchase and resale include supplies of gas under both short and long-term contracts with gas marketers, independent producers and other suppliers. Oklahoma is the third largest gas producing state in the nation, and ONG has direct access through the Transportation and Storage segment’s transmission system and transmission systems belonging to unaffiliated companies to all of the major gas producing areas in Oklahoma. Our gas storage, transportation and gathering assets were unbundled from the utility and operate as separate entities. Gas supply and transportation contracts were awarded for service beginning in the 2000/2001 heating season for two- and five-year terms.

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The two-year term contracts terminated in 2002 and were rebid to new terms of one year for gas supply and five years for transportation. As a result of the process, the majority of ONG’s gas supply and gas transportation needs will continue to be met by two affiliates, OEMT for supply, and OGT for upstream transportation service.

ONG reserved storage capacity of 0.9 Bcf with Southern Star Central Gas Pipeline, Inc. (Central) during 2002. Effective April 1, 2003, ONG will have two additional storage contracts with its affiliate, OGS. The first OGS contract is for 4.1 Bcf of reserved storage capacity and is the result of the settlement with the OCC in May 2002. The second OGS contract is for 1.4 Bcf of reserved storage capacity and is the result of OGS being the successful bidder in a competitive bid process. The three contracts combined will give ONG a reserved capacity of approximately 6.4 Bcf.

KGS had 12.4 Bcf of reserved storage capacity with Central, 0.4 Bcf of reserved storage capacity with Panhandle Eastern Pipeline Company (Panhandle) and 1.7 Bcf of reserved storage capacity with MCMC throughout 2002. Effective August 1, 2002, KGS added an additional storage contract with MCMC for 0.7 Bcf of reserved storage capacity. The four contracts combined give KGS a reserved storage capacity of approximately 15 Bcf.

KGS has a long-term gas purchase contract with Amoco Production Company (Amoco) for the purpose of meeting the requirements of the customers served over the Central system. We anticipate that this contract will supply between 45 percent and 55 percent of KGS’s demand served by the Central pipeline system. Amoco is one of various suppliers over the Central pipeline system and if this contract were cancelled, management believes gas supplied by Amoco could be replaced with gas from other suppliers. Gas available under the contract that exceeds the needs of our residential and commercial customer base is also available for sale to other parties, known as “as available” gas sales.

For the remainder of KGS’s supply, the gas is purchased from a combination of direct wellhead production, natural gas processing plants, and natural gas marketers and production companies.

KGS has transportation agreements for delivery of gas that have remaining terms varying up to 14 years with the following non-affiliated pipeline transmission companies: Central, Enbridge Pipelines – KPC, Inc. (KPC), Kinder Morgan Interstate Gas Transmission, L.L.C., Wyoming Interstate Gas Company, Panhandle, Northern Natural Gas Company and Natural Gas Pipeline Company of America. Additionally, approximately three percent of KGS’s transportation service is provided by MCMC and OFS, which are affiliated companies.

In 2002, KGS signed an agreement with Colorado Interstate Gas Company (CIG) for capacity on the proposed Cheyenne Plains pipeline. This pipeline will provide KGS access to the Rocky Mountain gas supply basin, which currently has excess supply. This will facilitate KGS’s ability to maintain a reliable gas source for our current customers through a proposed interconnection with Central and the KGS transmission system. The proposed Cheyenne Plains pipeline will originate at the Cheyenne Hub in northeast Colorado and terminate with deliveries to several pipelines in Kansas. The completion date of this pipeline is proposed for 2005. CIG must obtain several regulatory approvals before the pipeline can be completed.

In May 2002, the KCC approved an order allowing the transfer of certain MCMC transmission pipeline assets from our Transportation and Storage segment to KGS. The operation of these assets is regulated by the KCC. The transportation system provides access to the major natural gas producing areas in Kansas intersecting with eight intrastate and interstate pipelines at 13 interconnect points, three processing plants, and approximately three producing fields effectively allowing gas to be moved throughout the state. With the transfer of these assets, KGS is able to provide itself with firm transportation service. The order was effective July 1, 2002. All historical financial and statistical information has been adjusted to reflect this transfer.

KGS uses these transmission pipeline assets to serve its customers and provide transportation service on and off-system. KGS has agreements for 2.4 Bcf of storage with MCMC, and approximately 13 Bcf of storage with non-affiliated pipeline transmission companies.

There is an adequate supply of natural gas available to our utility systems and we do not anticipate problems with securing additional gas supply as needed for our customers. In order to ensure adequate deliveries of natural gas, KGS continues to develop new supply and transportation alternatives for meeting its existing and future needs. However, if supply shortages occur, ONG’s rate schedule “Order of Curtailment” and the KGS rate order “Priority of Service” provide for first reducing or totally discontinuing gas service to large industrial users and graduating down to requesting residential and commercial customers to reduce their gas requirements to an amount essential for public health and safety.

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Customers – Residential and Commercial – ONG and KGS distribute natural gas as public utilities to approximately 80 percent of Oklahoma’s population and 75 percent of Kansas’ population. Natural gas sold to residential and commercial customers, which is used primarily for heating and cooking, accounts for approximately 72 and 28 percent of gas sales, respectively, in Oklahoma and 76 and 24 percent of gas sales, respectively, in Kansas.

A franchise, although non-exclusive, is a right to use the municipal streets, alleys, and other public ways for utility facilities for a defined period of time for a fee. ONG has franchises in 41 municipalities including Tulsa and Oklahoma City, while KGS holds franchises in 279 municipalities. In management’s opinion, our franchises contain no unduly burdensome restrictions and are sufficient for the transaction of business in the manner in which it is now conducted.

Industrial – Under ONG’s pipeline capacity lease (PCL) program, certain customers, for a fee or a tariff, can have their gas, whether purchased from ONG or another supplier, transported to their facilities utilizing lines owned by ONG or its affiliates. KGS transports gas for large industrial customers through its End-Use Customer Transportation (ECT) program. The programs allow qualifying industrial and commercial customers to purchase gas on the spot market and have it transported by ONG and KGS, respectively.

Because of increased competition for the transportation of gas to PCL and ECT customers, some of these customers may be lost to affiliated or unaffiliated transporters. If the Transportation and Storage segment gained some of this business, it would result in a shift of some revenues from the Distribution segment to the Transportation and Storage segment.

Market Conditions and Business Seasonality – The natural gas industry is expected to remain highly competitive resulting from initiatives being pursued by the industry and regulatory agencies that allow industrial and commercial customers increased options for energy supplies. We believe that we must maintain a competitive advantage in order to retain our customers and, accordingly, continue to focus on reducing costs.

The Distribution segment is subject to competition from electric utilities offering electricity as a rival energy source and competing for the space heating, water heating, and industrial process markets. Alternative fuels such as propane and fuel oil also present competition. The principal means to compete against alternative fuels is lower prices, and natural gas continues to maintain its price advantage in the residential, commercial, and both small and large industrial markets. In residential markets, the average cost of gas is less for ONG and KGS customers than the cost of an equivalent amount of electricity. We provide education to customers on safety and the benefits of natural gas, which include product performance, price and environmental impact.

The Distribution segment is subject to competition from other pipelines for its existing industrial load. Both ONG and KGS compete for service to the large industrial and commercial customers; however, competition continues to lower rates. A portion of ONG’s PCL services and KGS’s ECT services are at negotiated rates that are generally below the approved PCL and transportation tariff rates, and increased competition potentially could lower these rates. Industrial and transportation sales volumes tend to remain relatively constant throughout the year.

Gas sales to residential and commercial customers are seasonal, as a substantial portion of gas is used principally for heating. Accordingly, the volume of gas sales is consistently higher during the heating season (November through March) than in other months of the year. ONG’s tariff rates include a temperature normalization adjustment clause during the heating season, which mitigates the effect of fluctuations in weather. KGS also implemented a weather normalization clause in December 2000, which mitigates the effect of fluctuations in weather on revenues. KGS’s WeatherProof Bill program, implemented in September 1999, is designed to mitigate the effect of weather fluctuations in Kansas for customers electing to use this program. Additionally, with prior KCC approval, KGS has a gas hedging program in place to reduce volatility in the gas price paid by consumers. The costs of this program are borne by the KGS customers.

Government Regulation – Rates charged for gas services are established by the OCC for ONG and by the KCC for KGS. Gas purchase costs are included in the Purchased Gas Adjustment (PGA) clause rate that is billed to customers. We do not make a profit on the cost of gas. Other changes in costs must be recovered through periodic rate adjustments approved by the OCC and KCC.

There were several regulatory initiatives in 2002. The highlights of these initiatives are as follows:

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We have settled all known claims arising out of long-term gas supply contracts containing “take-or-pay” provisions that purport to require us to pay for volumes of natural gas contracted for but not taken. The OCC has authorized recovery of the accumulated settlement costs over a 20-year period, expiring in 2014, or approximately $6.7 million annually through a combination of a surcharge from customers and revenue from transportation under Section 311(a) of the NGPA and other intrastate transportation revenues. There are no significant potential claims or cases pending against us under “take-or-pay” contracts.

OkTex transports gas in interstate commerce under Section 311(a) of the NGPA and is treated as a separate entity by the FERC. Accordingly, OkTex is subject to the regulatory jurisdiction of the FERC under the NGA with respect to rates, accounts and records, the addition of facilities, the extension of services in some cases, the abandonment of services and facilities, the curtailment of gas deliveries and other matters. OkTex has the capacity to move up to 800 MMcf/d.

In the first quarter of 2000, the FERC issued Order No. 637, which, among other things, imposed additional reporting requirements, required changes to make pipeline and secondary market services more comparable, removed the price caps on secondary market capacity for a period of two years, allowed rates to be based on seasonal or term differentiated factors and narrowed the applicability of the regulatory right of first refusal to apply only to the maximum rate contracts. Our interstate pipeline implemented the new regulations in May 2000. The FERC Order did not have a material effect on our operations.

Production

General – Our strategy has been to concentrate ownership of natural gas and oil reserves in the mid-continent region in order to add value not only to our existing production operations but also to integrate it into our gathering and processing, marketing and trading, and transportation and storage businesses. We continue to focus on growing through acquisitions, developing existing properties, and divesting properties when the market offers premium value.

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Operating income from the Production segment is 2.8 percent, 7.2 percent, and 1.8 percent of the consolidated operating income from continuing operations for fiscal years 2002, 2001, and 2000, respectively. The Production segment has no single external customer from which it receives ten percent or more of consolidated revenues.

Property Acquisitions and Divestitures –We acquired $3.7 million of properties located in the mid-continent region of the U.S. during 2002 of which $2.9 million are included in continuing operations and $0.8 million are included in the discontinued component. In November 2002, we agreed to sell approximately 70 percent of our proved properties for $300 million before adjustments. The sale was completed on January 31, 2003. The financial and statistical information related to the sale are presented as discontinued operations. All periods presented have been restated to reflect the discontinued component.

Producing Reserves – The Production segment primarily focuses its production activities on natural gas. We are retaining interests in 511 gas wells and 63 oil wells, all located in Oklahoma. A number of these wells produce from multiple zones. Production from the retained oil wells increased in 2002 as compared to 2001, primarily as a result of production from new wells drilled and from recompletions of existing wells. Production from the retained gas wells decreased in 2002 compared to 2001 as a result of the natural decline in production on existing wells. Our discontinued component has interests in 1,741 gas wells and 172 oil wells located primarily in Oklahoma, Kansas, and Texas.

Market Conditions and Business Seasonality – Natural gas prices during the first quarter of 2002 were at their lowest levels of the previous two years, after which gas prices increased for the remainder of the year, with the last quarter of 2002 reaching the highest gas prices of the year. Despite the steadily increasing prices during 2002, industry-wide drilling activity was subdued and we were able to pursue our scheduled developmental drilling projects during the first part of the year due to an adequate supply of drilling rigs. Due to our agreement to sell approximately 70 percent of our production segment properties in the latter part of the year, we limited our capital projects to only those required to maintain our leasehold position. We continue to actively pursue acquisition opportunities as a low-risk method of adding reserves.

Our goal is to build on our existing reserve base through acquisition and development. We operate or have large interests in our retained wells. We are in a good competitive position within our operating region due to low finding costs and high quality production at locations near transportation points and markets. During 2002, the segment’s production was sold to a number of affiliated and unaffiliated markets, all at market prices.

Similar to our other business segments, the Production segment is subject to seasonal factors. The Production segment’s revenues are impacted by prices, which, historically, are higher in the winter heating months when demand is higher than in the summer and shoulder months of spring and fall. Oil prices in the U.S. are also impacted by international production and export policies.

Risk Management – We utilized derivative instruments in 2002 in order to hedge anticipated sales of natural gas and oil production. During the third quarter of 2002, we lifted our natural gas production hedges through December 2004 and fixed the gains for all derivative instruments used for hedges previously in place related to our natural gas production. We recognize the benefit from the fixed gain as each contract month expires. In 2002, we recognized $3.9 million in natural gas sales revenues related to these hedges. The gains associated with these natural gas production hedges have been deferred in other comprehensive income and will be realized in the month that the natural gas production occurs.

At December 31, 2002, the Production segment had hedged 72 percent of its anticipated gas production and 62 percent of its anticipated oil production for fiscal year 2003 at a weighted average wellhead price of $4.60 per Mcf for gas and $27.25 per Bbl for oil. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Note D of Notes to Consolidated Financial Statements.

Other

Through two subsidiaries, we own a parking garage and lease an office building (ONEOK Plaza) in downtown Tulsa, Oklahoma, where our headquarters is located. The parking garage is owned and operated by ONEOK Parking Company. ONEOK Leasing Company leases excess office space to others. The Other segment has no single external customer from which it receives ten percent or more of consolidated revenues.

On March 15, 2002, Magnum Hunter Resources (MHR) merged with Prize Energy Corp., reducing our direct ownership to approximately 11 percent and reducing the number of positions held by us on the MHR board of directors from two to one.

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We began accounting for our investment in MHR as an available-for-sale security and, accordingly, marked the investment to fair value through other comprehensive income. During the second quarter of 2002, we sold our remaining shares of MHR common stock for a pre-tax gain of approximately $7.6 million, which is included in other income in 2002. We retained approximately 1.5 million stock purchase warrants. We also relinquished our remaining seat on MHR’s board of directors. The MHR investment and related equity income and loss are reported in the Other segment.

Executive Officers

All executive officers are elected at the annual meeting of directors and serve for a period of one year or until successors are duly elected.

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No family relationships exist between any of the executive officers nor is there any arrangement or understanding between any executive officer and any other person pursuant to which the officer was selected.

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ITEM 2. PROPERTIES

DESCRIPTION OF PROPERTY

Production

We own varying economic interests, including working, royalty and overriding royalty interests in 511 gas wells and 63 oil wells that are related to ongoing operations and 1,741 gas wells and 172 oil wells related to the discontinued component, some of which are completed in multiple producing zones. The interests in wells retained after the sale, which closed in January 2003, are in wells located primarily in Oklahoma. We own 66,262 net onshore developed leasehold acres and 10,432 net onshore undeveloped acres, after the sale, all located in Oklahoma. The discontinued component includes 131,068 net onshore developed acres and 31,772 net onshore undeveloped leasehold acres. We do not own any offshore acreage.

Gathering and Processing

We own and operate, lease and operate, or own an interest in natural gas processing plants in Oklahoma, Kansas and Texas with a processing capacity of approximately 1.993 Bcf/d, of which approximately 0.107 Bcf/d is currently idle. The capacity associated with plants owned or leased is approximately 1.776 Bcf/d, while the amount of the plant capacity that we own an interest in but do not operate is approximately 0.110 Bcf/d. We own a total of approximately 13,962 miles of gathering pipelines that supply our gas processing plants.

Our natural gas processing operations utilize two types of gas processing plants, field and straddle plants. Field plants aggregate volumes from multiple producing wells into quantities that can be economically processed to extract natural gas liquids and to remove water vapor and other contaminants. Straddle plants are situated on mainline natural gas pipelines and allow operators to extract natural gas liquids under contract from a natural gas stream when the market value of natural gas liquids separated from the natural gas stream is higher than the market value of the same unprocessed natural gas stream.

We own and operate or lease and operate two NGL storage facilities in Kansas. The total capacity of the facilities is approximately 18 MMBbls. We own and operate or lease and operate two fractionation facilities in Oklahoma and Kansas. The total fractionation capacity of the two facilities is approximately 95 MBbls/d.

Transportation and Storage

We own a combined total of approximately 2,858 miles of transmission pipeline in Oklahoma, approximately 204 miles in Kansas, and approximately 4,701 miles in Texas. Compression and dehydration facilities are located at various points throughout the pipeline system. In addition, we own four and lease one underground storage facilities located throughout Oklahoma, own three storage facilities in Kansas and own three storage facilities in Texas. The storage facilities primarily consist of land and mineral leasehold agreements, wells and equipment, rights of way, and cushion gas. The total working storage capacity of these facilities is approximately 59.6 Bcf, of which 9.5 Bcf is currently idle. Four of the Oklahoma storage facilities are located in close proximity to large market areas; the other storage facility is located in western Oklahoma and is leased through a long-term agreement. We have 3 Bcf of working storage capacity in that facility for our use. The storage facilities in Oklahoma, Kansas and Texas are connected to our pipelines and are located near unaffiliated intrastate and interstate pipelines, providing our storage customers with access to multiple markets.

Distribution

We own approximately 17,123 miles of pipeline and other distribution facilities in Oklahoma and approximately 12,223 miles of pipeline and other distribution facilities in Kansas. We own a number of warehouses, garages, meter and regulator houses, service buildings, and other buildings throughout Oklahoma and Kansas. We also own a fleet of trucks and maintain an inventory of spare parts, equipment, and supplies.

Lease acreage in producing units is held by production. Leases not held by production are generally for a term of three years and may require payment of annual rentals.

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Marketing and Trading

We constructed a 300-megawatt gas-fired merchant power plant located in Logan County, Oklahoma adjacent to an affiliate’s gas storage facility. This plant is configured to supply electric power during peak periods with four gas-powered turbine generators.

Other

We own a parking garage and land, subject to a long-term ground lease. Located on this land is a seventeen-story office building with approximately 517,000 square feet of net rentable space. We also lease our office building under a lease term that expires in 2009 with six five-year renewal options. After the primary term or any renewal period, we can purchase the property at its fair market value. We occupy approximately 203,000 square feet for our own use and lease the remaining space to others.

OIL AND GAS RESERVES

As defined by the SEC, oil and gas production includes natural gas liquids in their natural state. Our gathering and processing operation produces natural gas liquids. The SEC excludes the production of natural gas liquids resulting from the operations of gas processing plants as an oil and gas activity. Accordingly, the following tables exclude information concerning the production of natural gas liquids by our processing operations.

All of the oil and gas reserves for our Production segment are located in the United States.

For quantities of our oil and gas reserves and the present value of estimated future net revenues from our oil and gas reserves see Notes U and V of the Notes to Consolidated Financial Statements.

We report our proved reserves on our operated oil and gas properties to the Energy Information Agency. These reported reserves are the same as the proved reserve amounts for these same properties used in our disclosures to the SEC, prior to applying the net ownership to the properties. We do not file our reserve estimates with any other governmental agency.

Quantities of Oil and Gas Produced

The following table sets forth the net quantities of oil and natural gas produced and sold, including intercompany transactions for the Production segment, for the periods indicated.

Average Sales Price and Production (Lifting) Costs

The following table sets forth the average sales prices and production costs for our Production segment for the periods indicated.

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Wells and Developed Acreage

The following table sets forth the gross and net wells in which the Production segment had an interest at December 31, 2002.

Gross developed acres and net developed acres by well classification are not available. Gross developed acres for both oil and gas are 115,475 acres for our continuing operations and 456,441 acres for the discontinued component. Net developed acres for both oil and gas is 66,262 acres for our continuing operations and 131,068 acres for the discontinued component.

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Undeveloped Acreage

The following table sets forth the gross and net undeveloped leasehold acreage for our Production segment at December 31, 2002.

Of the net undeveloped acres, all of the retained acreage related to ongoing operations is in the Anadarko Basin area in the state of Oklahoma.

Net Development Wells Drilled

The following table sets forth the net interest in total development wells drilled, by well classification, for our Production segment for the periods indicated.

We did not drill any exploratory wells in 2002, 2001, or 2000.

Present Drilling Activities

At December 31, 2002, the Production segment was participating in the drilling of nine wells. Our net interest in these wells amounts to 1.7 wells.

Future Obligations to Provide Oil and Gas

We do not have any future obligations to provide oil and gas related to our Production segment.

ITEM 3. LEGAL PROCEEDINGS

United States ex rel. Jack J. Grynberg v. ONEOK, Inc., ONEOK Resources Company, and Oklahoma Natural Gas Company, (CTN-8), No. CIV-97-1006-R, United States District Court for the Western District of Oklahoma, transferred, In re Natural Gas Royalties Qui Tam Litigation, MDL Docket No. 1293, United States District Court for the District of Wyoming. We are a defendant in an action initiated by Jack J. Grynberg, on behalf of the United States under the False Claims Act (31 U.S.C. § 729, et seq.). Similar complaints have been filed against approximately 75 other companies associated with the natural gas industry. The main allegation of the complaints is that, since at least 1985, the defendants have systematically undermeasured the volumes and/or the heating content of gas purchased from federal and

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Indian lands, resulting in underpayment of royalties due the federal government and the various Indian tribes. Grynberg seeks to recover $5,000 to $10,000 for each violation of the False Claims Act as well as treble damages for any underpayment. The actions brought by Grynberg, together with certain other actions alleging underpayment of gas royalties to federal and Indian lessors, have been assigned to a multidistrict litigation proceeding in the United States District Court for the District of Wyoming for coordination of pretrial proceedings. The Court overruled the defendants’ initial motion to dismiss, but granted the motion of the United States to dismiss certain portions of the complaint. The order granting the motion of the United States is now on appeal. Meanwhile, the defendants are conducting discovery regarding whether Grynberg has met the unique jurisdictional prerequisites for maintaining an action under the False Claims Act. We will continue to vigorously defend all aspects of claims made against us in this litigation.

Southern Union Company v. Southwest Gas Corporation, et al., No. CIV-99-1294-PHX-ROS, United States District Court for the District of Arizona; ONEOK, Inc. v. Southern Union Company, No. 99-CV-0345-H(M), United States District Court for the Northern District of Oklahoma, transferred, No. CV-00-1812-PHX-ROS, in the United States District Court for the District of Arizona, on appeal of preliminary injunction, United States Court of Appeals for the Tenth Circuit, Case Number 99-5103; ONEOK, Inc. v. Southwest Gas Corporation, No. 00-CV-063-H(E), United States District Court for the Northern District of Oklahoma, transferred, No. CIV-00-1775-PHX-ROS, United States District Court for the District of Arizona; and Southwest Gas Corporation v. ONEOK, Inc., No. CIV-00-0119-PHX-ROS, United States District Court for the District of Arizona. In May of 1999 a series of lawsuits were filed in connection with failed attempts by us and Southern Union Company (“SUG”) to merge with Southwest Gas Corporation (“SWX”). We, SWX and SUG all sued each other and SUG made claims against a member of the Arizona Corporation Commission and other individuals, including our officers and directors. On August 6, 2002, SWX and SUG settled their claims against each other for the payment of $17.5 million by SWX to SUG. Shortly thereafter, on August 9, 2002, we and SWX settled our claims against each other for a payment of $3 million by us to SWX. On October 11, 2002, we and SUG announced to the Court an agreement in principle to settle the remaining claims between us, our current/former officers and directors and SUG. On January 3, 2003, we completed that settlement. In exchange for a payment of $5 million by us to SUG, SUG dismissed with prejudice its claims against us and our current/former officers and directors and we likewise dismissed with prejudice our claims against SUG. There are no further outstanding claims involving us in these cases.

In re ONEOK, Inc. Derivative Litigation, No. CJ-2000-00593, District Court of Tulsa County, Oklahoma (formerly Gaetan Lavalla, derivatively on behalf of nominal defendant ONEOK, Inc. v. Larry W. Brummett, et al., No. CJ-2000-598 and Hayward Lane, derivatively on behalf of nominal defendant ONEOK, Inc. v. Larry W. Brummett, et al.). On February 3, 2000, two substantially identical derivative actions were filed in the District Court in Tulsa, Oklahoma, by shareholders against the members of our Board of Directors for violation of their fiduciary duties by allegedly causing or allowing us to engage in fraudulent and improper schemes designed to “sabotage” Southern Union Company’s (“SUG”) competitive bid to acquire Southwest Gas Corporation (“SWX”) and secure regulatory approval for our own planned merger with SWX. Such conduct allegedly caused us to be sued by both SWX and SUG, which exposed us to millions of dollars in liabilities. The allegations are used as a basis for causes of action for intentional breach of fiduciary duty, derivative claim for negligent breach of fiduciary duty, class and derivative claims for constructive fraud, and derivative claims for gross mismanagement. Each plaintiff seeks a declaration that the lawsuit is properly maintained as a derivative action, the defendants, and each of them, have breached their fiduciary duties to us, an injunction permanently enjoining defendants from further abuse of control and committing of gross mismanagement and constructive fraud, and asks for an award of compensatory and punitive damages and costs, disbursements and reasonable attorney fees. A joint motion for consolidation of both derivative actions was filed on June 6, 2000, and a pretrial order was entered on that date consolidating the actions and establishing a schedule for a response to a consolidated petition. On July 21, 2000, the plaintiffs filed their consolidated petition. Stephen J. Jatras and J. M. Graves have been eliminated as defendants in the consolidated petition, but Eugene Dubay was added as a new defendant. The plaintiffs also dropped their class and derivative claim for constructive fraud, but added a new derivative claim for waste of corporate assets. On September 19, 2000, we, our independent directors (Anderson, Bell, Cummings, Ford, Fricke, Lake, Mackie, Newsom, Parker, Scott and Young), David Kyle, and Gene Dubay filed motions to dismiss the action for failure of the plaintiffs to make a pre-suit demand on our Board of Directors. In addition, our independent directors, David Kyle, and Gene Dubay filed motions to dismiss the Plaintiffs’ Consolidated Petition for failure to state a claim. On January 3, 2001, the Court dismissed the action without prejudice as to its claims against Larry Brummett. On February 26, 2001, the action was stayed until one of the parties notifies the court that a dissolution of the stay is requested.

Will Price, et al. v. Gas Pipelines, et al. (f/k/a Quinque Operating Company, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 99C30. On June 8, 2001, a second amended petition was filed in this case as a purported class action against approximately 225 defendants, including us, one of our divisions and five of our subsidiaries. Plaintiffs later dismissed a number of defendants, including ONEOK

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Resources Company, one of our subsidiaries. On February 21, 2002, plaintiffs filed a third amended petition, in order to add certain plaintiffs, dismiss Quinque Operating Company as a plaintiff, and amended certain of their substantive allegations. The third amended petition was purportedly filed on behalf of all producers and royalty owners who have lost money as a result of alleged mismeasurement of gas since 1974 by any of the now approximately 135 defendants. The third amended petition alleges that each of the defendants engaged in one or more specific “mismeasurement techniques” and conspired with one another to undermeasure the gas sold by the alleged class members. The third amended petition alleges that the aggregate alleged underpayment to all purported class members since 1974 is estimated to be tens of billions of dollars. One of our named subsidiaries, ONEOK WesTex Transmission, Inc., formerly Westar Transmission Co., is a former subsidiary of Kinder Morgan, and Kinder Morgan has agreed to assume the defense of ONEOK WesTex while reserving its rights and denying that it has any obligation to indemnify us against any loss suffered by ONEOK WesTex as a result of this litigation. Discovery in the case, except as to class certification and personal jurisdiction issues, has been stayed. Plaintiffs and defendants have served and responded to various discovery requests on the personal jurisdiction and class certification issues. One of our subsidiaries, ONEOK Gas Transportation, LLC, is contesting personal jurisdiction. On August 19, 2002, the court entered an order denying the defendants’ motion to dismiss the case. Oral argument on the personal jurisdiction motion of defendants contesting personal jurisdiction was held on August 29, 2002, but no decision has been rendered on that motion yet. Oral argument also was held on plaintiffs’ class certification motion on January 13, 2003; however, no decision has been rendered on that motion either. ONEOK intends to vigorously defend all aspects of the claims asserted in this case.

In the Matter of the Natural Gas Explosion at Hutchinson, Kansas during January, 2001, Case No. 02-E-0155, before the Secretary of the Department of Health and Environment. On July 23, 2002 the Division of Environment of the Kansas Department of Health and Environment (KDHE) issued an administrative order, which assesses a $180,000 civil penalty against our Kansas Gas Service division. The penalty is based upon allegations of violations of various KDHE regulations relating to our operation of hydrocarbon storage wells, monitoring requirements applicable to stored hydrocarbon products, and spill reporting in connection with the gas explosion at our Yaggy gas storage facility in Hutchinson, Kansas in January 2001. In addition, the order requires us to monitor existing unplugged vent wells, drill additional observation, monitoring and vent wells as directed by the KDHE, perform cleanup activities relating to certain brine wells, and prepare a geoengineering plan with respect to the Yaggy gas field. We timely filed an appeal of the administrative order. A status conference was held on February 12, 2003, and another one has been scheduled for April 10, 2003, regarding progress toward reaching an agreed consent order.

Loyd Smith, et al v. Kansas Gas Service Company, Inc., ONEOK, Inc., Western Resources, Inc., Mid Continent Market Center, Inc., ONEOK Gas Storage, L.L.C., ONEOK Gas Storage Holdings, Inc., and ONEOK Gas Transportation, L.L.C., Case No. 01-C-0029, in the District Court of Reno County, Kansas, and Gilley et al. v. Kansas Gas Service Company, Western Resources, Inc., ONEOK, Inc., ONEOK Gas Storage, L.L.C., ONEOK Gas Storage Holdings, Inc., ONEOK Gas Transportation L.L.C. and Mid-Continent Market Center, Inc., Case No. 01-C-0057, in the District Court of Reno County, Kansas. Two separate class action lawsuits were filed against us and several of our subsidiaries in early 2001 relating to certain gas explosions in Hutchinson, Kansas. The court certified two separate classes of claimants, which include all owners of real estate in Reno County, Kansas whose property had allegedly declined in value, and owners of businesses in Reno County whose income had allegedly suffered. The petitions seek recovery on behalf of the class claimants for an amount, which will fully and fairly compensate all members of the class.

Loyd Smith, et al v. Kansas Gas Service Company, Inc., ONEOK, Inc., Western Resources, Inc., Mid Continent Market Center, Inc., ONEOK Gas Storage, L.L.C., ONEOK Gas Storage Holdings, Inc., and ONEOK Gas Transportation, L.L.C., Case No. 03-C-0029, in the District Court of Reno County, Kansas. This class action lawsuit was filed against us, several of our subsidiaries, and others on January 17, 2003 relating to the gas explosions occurring in Hutchinson, Kansas in January 2001. The petition seeks recovery on behalf of residents of Reno County, Kansas, who have suffered or will suffer damage and/or economic losses relating to personal property and displacement costs. We have not been served in this matter, and intend to vigorously defend all aspects of the claims against us in this litigation once properly served.

ITEM 4. RESULTS OF VOTES OF SECURITY HOLDERS

No matter was submitted to a vote of our security holders, through the solicitation of proxies or otherwise, during the fourth quarter of the fiscal year covered by this report.

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PART II.

ITEM 5.    MARKET PRICE AND DIVIDENDS ON THE REGISTRANT’S COMMON STOCK AND RELATED SHAREHOLDER MATTERS

Market Information and Holders

Our common stock is listed on the New York Stock Exchange under the trading symbol OKE. The corporate name ONEOK is used in newspaper stock listings. The following table sets forth the high and low sales prices of our common stock for the periods indicated.

The high and low sales prices for the first and second quarters of the year ended December 31, 2001, have been restated to give the effect of the 2001 two-for-one stock split.

There were 13,125 holders of record of our common stock at March 1, 2003.

Dividends

The following table sets forth the quarterly dividends declared on our common stock during the periods indicated.

Quarterly dividends for the first and second quarters of the year ended December 31, 2001, have been restated to give the effect of the 2001 two-for-one stock split.

Our Revolving Credit Facility with Bank of American, N.A. and other financial institutions limits dividends and other distributions on our common stock. Under the most restrictive of these provisions, $143.8 million of retained earnings is so restricted. At December 31, 2002, $364.1 million was available for dividends on our common stock.

On November 21, 2002, our Board of Directors approved an increase in the quarterly dividend on our common stock to $0.17 per share that was applicable to the quarterly dividend declared in January 2003.

Equity Compensation Plan Information

The following table sets forth certain information concerning the Company’s equity compensation plans as of December 31, 2002.

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ITEM 6. SELECTED FINANCIAL DATA

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), we revised our computation of earnings per common share (EPS). We restated the EPS amounts for all periods to be consistent with the revised methodology and to give effect of the two-for-one stock split in 2001. See Note S of the Notes to the Consolidated Financial Statements.

In February 2003, we purchased approximately 9 million shares of our Series A Convertible Preferred Stock from Westar and converted the remaining 10.9 million shares of Series A Convertible Preferred Stock to 21.8 million shares of Series D Convertible Preferred Stock reflecting the two-for-one stock split in 2001. The Series D stock has a fixed annual cash dividend rate of 92.5 cents per share. As a result of this transaction, Topic D-95 will not apply to our computation of EPS beginning in February 2003.

The following table sets forth our selected financial data for each of the periods indicated.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements and Risk Factors

Some of the statements contained and incorporated in this Form 10-K 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-K identified by words such as “anticipate,” “estimate,” “expect,” “intend,” “believe,” “projection” or “goal.”

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

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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.

Operating Environment and Outlook

The energy industry has undergone tremendous changes throughout the past decade and energy trading in the past 12 to 18 months. Our strategy has been and continues to be one of growth through acquiring assets that complement and strengthen each other, maximizing the earnings potential of existing assets through asset rationalization and consolidation and introducing regulatory initiatives that benefit us and our customers. We believe that the energy markets will continue to see deregulation, although it may be different than how certain markets have been deregulated to date. We will continue to focus on enhancing the earnings potential of our existing assets through acquiring assets that grow our operations into new market areas and complement our existing asset base.

Operating Highlights

Acquisitions and Capital Expenditures – On January 31, 2003, we closed the sale of some of the natural gas and oil producing properties of our production segment to Chesapeake Energy Corporation for a cash sales price of approximately $300 million. Pursuant to the sale, we sold natural gas and oil reserves in Oklahoma and Texas. The sale included approximately 1,900 wells, 482 of which were operated by us. We recorded a gain of approximately $74.4 million in the first quarter of 2003 related to this sale.

On January 3, 2003, we closed the purchase of all of the Texas assets of Southern Union for a cash purchase price of approximately $420 million, subject to a working capital adjustment to be determined within 90 days of the closing of the transaction. The acquisition makes us the fifth largest gas distributor in the U.S., with almost two million customers in Oklahoma, Kansas and Texas. The assets acquired consist of the third largest gas distribution business in Texas, with operations that serve approximately 535,000 customers, over 90 percent of which are residential.

On December 13, 2002, we closed the sale of some of our midstream natural gas assets for a sales price of approximately $92 million to an affiliate of Mustang Fuel Corporation, a private, independent oil and gas company. The assets that were sold are located in north central Oklahoma and include three processing plants and related gathering systems and our interest in a fourth processing plant. The sale of these assets is part of our strategy to dispose of assets that are not considered core assets for our future.

In early 2001, we increased our common ownership interest in MHR from approximately nine percent to over 21 percent through conversion of shares and redemption of MHR preferred stock to shares of MHR common stock, as well as exercising warrants. As a result, we began accounting for the MHR investment using the equity method of accounting. In March 2002, MHR merged with Prize Energy Corp., which reduced our direct ownership to approximately 11 percent and reduced the number of MHR board of director positions held by us from two to one. At that time, we began accounting for our investment in MHR as an available-for-sale security and, accordingly, marked the investment to fair value through other

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comprehensive income. In the second quarter of 2002, we sold our shares of MHR common stock for a pre-tax gain of approximately $7.6 million, which is included in other income in 2002. We retained approximately 1.5 million stock purchase warrants. We also relinquished our remaining seat on MHR’s board of directors. The MHR investment and related equity income and loss are reported in the Other segment.

During 2001, we completed construction of the Spring Creek Power Plant, located in Logan County, Oklahoma, and began operations in mid-2001. Four gas-powered turbines provide electricity during peak demand periods. We spent approximately $42.3 million in 2001 and $58.7 million in 2000 constructing the 300-megawatt plant.

In 2000, we made two significant asset acquisitions that greatly enhanced our Gathering and Processing, Transportation and Storage, and Marketing and Trading segments. The combined acquisitions included natural gas processing plants with a combined capacity of 1.6 Bcf/d, approximately 14,000 miles of gathering and transmission lines, and natural gas storage facilities with a combined capacity of approximately 10 Bcf and contributed to a significant increase in trading. The acquisition of these assets demonstrates execution of our strategy of growing through acquisition of assets that complement and strengthen each other.

Regulatory – In 2000, KGS was successful in obtaining temporary approval of weather normalization. KGS also obtained permanent approval of the WeatherProof Bill Program that had been a temporary program. As this is a permanent program, it will remain in effect until KGS requests the program cease. We believe that the successful implementation of these initiatives and programs will reduce the impact of weather on earnings and customer bills. In January 2003, KGS filed a rate case with the KCC to increase rates approximately $76 million. The KCC has 240 days to issue a final order on the rate case. If approved, the new rates will be effective for the 2003/2004 heating season. Until a final order is received, KGS will operate under the current rate schedules. The weather normalization rider was included in the rate case filing with the KCC in January 2003.

In 2001, the OCC issued an order denying ONG the right to collect $34.6 million in unrecovered gas costs incurred while serving customers during the 2000/2001 winter season. We appealed this Order to the Oklahoma Supreme Court and asked the OCC to stay the provisions of this Order, pending the outcome of our appeal. The OCC subsequently approved our request to stay this Order, which allowed ONG to collect the $34.6 million, subject to a refund had we ultimately lost the case. A Joint Stipulation approved by the OCC on May 16, 2002, settled a number of outstanding cases pending before the OCC, including the Commission’s inquiry into our gas cost procurement practices during the winter of 2000/2001. It also settled cases relating to an application seeking relief from improper and excessive purchased gas costs and an enforcement action against us, our subsidiaries and affiliated companies of ONG. In addition, all of the open inquiries related to the annual audits of ONG’s fuel adjustment clause for 1996 to 2000 were closed as a result of this Stipulation.

The Joint Stipulation has a $33.7 million value to ONG customers that will be realized over a three-year period. In July 2002, immediate cash savings were provided to all ONG customers in the form of billing credits totaling approximately $9.1 million, with an additional $1.0 million available for former customers returning to our system. If the additional $1.0 million is not fully refunded to customers returning to the ONG system by December 2005, the remainder will be included in the final billing credit. ONG has replaced certain gas contracts, which is expected to reduce gas costs by approximately $13.8 million due to avoided reservation fees between April 2003 and October 2005. Additional savings of approximately $8.0 million from the use of storage service in lieu of those contracts are expected to occur between November 2003 and March 2005. Any expected savings from the use of storage that are not achieved, any remaining billing credits not issued to returning customers and an additional $1.8 million credit will be added to the final billing credit scheduled to be provided to customers in December 2005. ONG operating income increased by $14.2 million for the fiscal year ended December 31, 2002, compared to 2001 as a result of this settlement and the revision of the estimated loss recorded in the fourth quarter of 2001.

Other – On January 1, 2003, we adopted the provisions of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (Statement 123) and will expense the fair value of all stock options beginning with options granted on or after January 1, 2003. See Note A of the Notes to Consolidated Financial Statements for disclosure of our pro forma net income and earnings per share information had we applied the provisions of Statement 123 for the years ended December 31, 2002, 2001 and 2000.

Critical Accounting Policies and Estimates

Our discussion and analysis of financial condition and operations are based on our consolidated financial statements, prepared in accordance with accounting principles generally accepted in the United States of America and included in this

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report on Form 10-K. Certain amounts included in or affecting our financial statements and related disclosure must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. Therefore, the reported amounts of our assets and liabilities, revenues and expenses and associated disclosures with respect to contingent assets and obligations are necessarily affected by these estimates. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. We believe that certain accounting policies are of more significance in our financial statement preparation process than others, as discussed below.

Energy Trading and Risk Management Activities – We engage in price risk management activities for both energy trading and non-trading purposes. Through 2002, we accounted for price risk management activities for our energy trading contracts in accordance with 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 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 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 net revenues, on a net basis, in the consolidated statements of income. Market prices used to determine 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 our position in an orderly manner over a reasonable period of time under present market conditions.

During the third quarter of 2002, we adopted the applicable provisions of EITF 02-3. EITF 02-3 provides that all mark-to-market gains and losses on energy trading contracts should be presented on a net basis (energy contract sales less energy contract costs) in the income statement without regard to the settlement provisions of the contract. Prior to the third quarter of 2002, energy trading revenues and costs were presented on a gross basis. The historical financial results of all energy trading contracts have been restated to reflect the adoption of EITF 02-3. Energy trading revenues include natural gas, reservation fees, crude oil, natural gas liquids, and basis. Basis is the natural gas price differential that exists between two trading locations relative to the Henry Hub price.

In October 2002, the EITF of the FASB rescinded EITF 98-10. As a result, energy-related contracts that are not accounted for pursuant to Statement 133, will no longer be carried at fair value, but rather will be accounted for as executory contracts and accounted for on an accrual basis. As a result of the rescission of this statement, the EITF 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 fiscal periods beginning after December 31, 2002 and for all existing energy trading contracts and inventory as of October 25, 2002. Additionally, the rescission applies immediately to contracts entered into on or after October 25, 2002. Changes to the accounting for existing contracts as a result of the rescission of EITF 98-10 will be reported as a cumulative effect of a change in accounting principle on January 1, 2003. At this time, we estimate this will result in a cumulative effect loss, net of tax, of approximately $141.0 million. Any impact from this change will be non-cash. All recoveries of the estimated value associated with this change in accounting will be recognized in operating income in future periods. The impact of adopting the rescission of EITF 98-10 will be included in the March 31, 2003 financial statements.

Regulation – Our intrastate transmission pipelines and distribution operations are subject to the rate regulation and accounting requirements of the OCC, KCC and TRC. Certain of our other transportation activities are subject to regulation by the FERC. 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, provided that there is a demonstrable ability to recover any deferred costs in future rates.

During the rate-making process, regulatory commissions may require a utility to defer recognition of certain costs to be recovered through rates over time as opposed to expensing such costs as incurred. This allows the utility to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. This causes certain expenses to be deferred as a regulatory asset and amortized to expense as they are recovered through rates. Continued recovery of all regulatory assets is expected. Should recovery cease due to regulatory actions, a write-off of regulatory assets and stranded costs may be required.

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Impairments – We assess for impairment of long-lived assets when indicators of impairment are present. An impairment is recognized if the undiscounted cash flows are not sufficient to recover the asset’s carrying amount. Impairment loss is measured by comparing the fair value of the asset to its carrying amount. Fair values are based on discounted future cash flows or information provided by sales and purchases of similar assets.

See further discussion of our significant accounting policies in Note A of Notes to the Consolidated Financial Statements.

Consolidated Operations

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

Operating Results – Increased energy trading revenues, net in 2002 compared to 2001 were achieved by diversifying our portfolio to include crude oil and natural gas liquids. The increased use of storage and transport capacity also contributed to our ability to capture price volatility in energy trading. Mark-to-market earnings were $42.6 million in 2002 compared to $35.3 million in 2001 and contributed to the increase in energy trading revenues, net. Net revenues in 2002 include the $14.0 million recovery of a portion of the costs related to Enron sales contracts that were written off in the fourth quarter of 2001 and the $14.2 million adjustment due to the OCC settlement. Write-off of these costs totaled $72.0 million in 2001. We also benefited in the Marketing and Trading segment from the renegotiation of certain long-term transportation contracts in 2002.

Operating costs increased in 2002 compared to 2001 due primarily to higher employee costs.

Other income in 2002 includes a $7.6 million gain related to the sale of our investment in MHR, a $1.5 million gain related to the sale of certain Oklahoma property rights in the Transportation and Storage segment, and a $1.9 million gain related to the sale of certain Texas transmission assets in the Transportation and Storage segment. Other expense in 2002 includes $2.1 million of ongoing litigation costs associated with our terminated acquisition of Southwest and $8.0 million for the settlement of litigation with Southwest and Southern Union.

Interest expense decreased in 2002 compared to 2001 primarily due to the interest rate swaps we have in place that reduced interest expense by $20.6 million in 2002, compared to a $5.3 million reduction in 2001, from what the expense would have been with fixed rates. Interest expense also decreased due to the reduced balance in commercial paper and lower interest rates relating to commercial paper. See Note D of the Notes to Consolidated Financial Statements for further discussion of interest rate swaps.

A full year of operations of the assets acquired in March and April of 2000 contributed to increased net revenues in 2001 compared to 2000, despite lower energy prices in the latter part of 2001, and increased operating costs and depreciation, depletion and amortization. Our ability to successfully execute our transportation and storage arbitrage strategy also continued to favorably impact operating results. The impact of the OCC ruling related to the recovery of gas costs from the 2000/2001 winter reduced operating income by $34.6 million and the impact of the Enron bankruptcy reduced operating

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income by $37.4 million in 2001. Included in Other income for 2001 is $8.1 million in income from equity investments including MHR. Other expense in 2001 includes $3.7 million of ongoing litigation costs associated with the terminated acquisition of Southwest and a $1.5 million insurance deductible payment related to the Yaggy storage facility. The reduction in the effective tax rate for 2001 is the result of changes in estimates of prior year tax liabilities recorded in the third quarter.

Interest expense increased in 2001 compared to 2000 as a result of increased debt, primarily due to financing of acquisitions and increased working capital including unrecovered purchased gas costs. We had interest rate swaps in place that reduced interest expense by $5.3 million in 2001 from what the expense would have been with fixed interest rates. See Note K to the Notes to Consolidated Financial Statements for further discussion of interest rate swaps.

Marketing and Trading

Operational Highlights – Our Company’s marketing and trading operation purchases, stores, markets, and trades natural gas to both the wholesale and retail sectors throughout most of the United States. We have strong mid-continent region storage positions and transport capacity of 1 Bcf/d that allow us to trade natural gas from border to border and coast to coast. With total storage capacity of 80 Bcf, withdrawal capability of 2.4 Bcf/d and injection capability of 1.3 Bcf/d, we have direct access to most regions of the country and flexibility to capture volatility in the energy markets. We continue to enhance our strategy of focusing on higher margin business which includes providing reliable service during peak demand periods through the use of storage and transportation capacity.

We constructed a peak electric power generating plant in mid-2001. The 300-megawatt plant is located in Oklahoma adjacent to one of our natural gas storage facilities and is configured to supply electric power during peak demand periods. This plant allows us to capture the “spark spread premium,” which is the value added by converting natural gas to electricity, during peak demand periods.

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

During the third quarter of 2002, we adopted certain provisions of EITF 02-3, which provides that all mark-to-market gains and losses on energy trading contracts should be presented on a net basis (energy contract sales less energy contract costs) in the income statement without regard to the settlement provisions of the contract. Prior to the third quarter of 2002, our energy trading revenues and costs were presented on a gross basis. The financial results of all energy trading contracts have been restated to reflect the adoption of EITF 02-3 for all periods presented. EITF 02-3 does not affect power-related revenues, which will continue to be reported on a gross basis.

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

The rescission is effective for fiscal periods beginning after December 31, 2002 and for all existing energy trading contracts and inventory as of October 25, 2002. Additionally, the rescission applies immediately to contracts entered into on or after October 25, 2002. Changes to the accounting for existing contracts as a result of the rescission of EITF 98-10 will be reported as a cumulative effect of a change in accounting principle on January 1, 2003. At this time, we estimate this will result in a cumulative effect loss, net of tax, of approximately $141.0 million. Any impact from this change will be non-cash. All recoveries of the estimated value associated with this change in accounting will be recognized in operating income in future periods. The impact of adopting the rescission of EITF 98-10 will be included in our March 31, 2003 financial statements.

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

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

Net revenues significantly increased in 2002 over 2001 while sales volumes increased only slightly. The increase in net revenues is attributable to our use of storage and transport capacity to capture the significant intra-month and regional price volatility from border to border and coast to coast. Our storage and transport capacity also enabled us to secure positive option value and favorable winter/summer spreads on stored gas volumes. In 2002, we also diversified our marketing and trading portfolio to include crude oil and natural gas liquids, which positively impacted our net revenues. We also benefited from the renegotiation of certain long-term transportation contracts. Power-related margins decreased in 2002 compared to 2001, despite higher sales volume, due to comparatively smaller spark spreads and reduced volatility in the Southwest Power Pool. In the first quarter of 2002, we sold our Enron bankruptcy claim, which added $10.4 million to our net revenues. Our net revenues for the years ended 2002, 2001 and 2000 include income recognized from mark-to-market accounting of approximately $42.6 million, $35.3 million and $24.3 million, respectively. As a percentage of energy trading revenues, net, mark-to-market earnings have declined each year, indicative of our strategy of focusing on our physical leased transportation and storage assets and enabling us to capture the embedded optionality we possess with the price volatility due to the physical changes in supply and demand.

Operating costs were lower in 2002 compared to 2001 as the prior year included a reserve for Enron-related bad debts of $14.5 million. Excluding the Enron-related reserve, operating costs were higher in 2002 due to increased employee costs and the addition of trading, risk management, and support personnel.

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Other income, net decreased in 2002 compared to 2001 primarily due to an increase in fees paid to affiliated parties for use of corporate capital related to performance guarantees issued to OEMT.

Our natural gas sales volumes averaged 2.8 Bcf/d in 2002 and 2.7 Bcf/d in 2001 and 2000, while our margin per Mcf increased in 2002 over the prior year due to the price volatility in the market.

Capital expenditures in 2001 and 2000 consist primarily of costs related to the construction of the electric generating plant, which was completed in mid-2001.

The increase in our net revenues in 2001 compared to 2000 is attributable to our ability to capture higher margins by arbitraging regional price volatility through the use of our storage and transportation capacity. We were also able to capture wider winter/summer spreads on stored volumes and benefited from falling prices that positively impacted fuel costs associated with our long-term transportation contracts, while sales volumes decreased slightly. Increased operating costs were due primarily to increased personnel costs required to operate the expanded base of marketing and trading activities acquired in 2000. Also, the Enron bankruptcy resulted in a $22.9 million increase in cost of gas and a $14.5 million increase in operating costs, totaling a $37.4 million negative impact on operating results for 2001.

Gross margin per Mcf improved in 2001 compared to 2000, as we had fully integrated our mid-continent marketing and trading base following the acquisition in 2000 and were successfully executing our strategies for transportation and use of storage that focus on capturing higher margin sales.

Gathering and Processing

Operational Highlights – The Gathering and Processing segment is engaged in the gathering and processing of natural gas and the fractionation, storage and marketing of NGLs. Our Gathering and Processing segment currently has a processing capacity of approximately 1.993 Bcf/d, of which approximately 0.107 Bcf/d is currently idle. The capacity associated with plants owned or leased is approximately 1.776 Bcf/d, while the amount of the plant capacity that we own an interest in but do not operate is approximately 0.110 Bcf/d. Our Gathering and Processing segment owns approximately 13,962 miles of gathering pipelines that supply our gas processing plants.

In December 2002, we completed the sale of three processing plants and related gathering assets, along with interest in a fourth processing plant, all located in Oklahoma, to an affiliate of Mustang Fuel Corporation. The sale reduced our processing capacity by 0.136 Bcf/d. The capacity associated with plants owned or leased was reduced by 0.122 Bcf/d, while the amount of the plant capacity that we own an interest in but do not operate was reduced by 0.014 Bcf/d. The sale also reduced our gathering pipelines that supply our gas processing plant by approximately 2,800 miles.

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