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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 2003.

OR

For the transition period from              to             .

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.  ¨

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 June 30, 2003, was $1,470.7 million.

On March 1, 2004, the Company had 102,363,387 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

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ONEOK, Inc.

2003 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.

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, Inc. (Westar), 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, natural gas liquids and electricity marketing and trading business. We are the largest natural gas distributor in Kansas and Oklahoma and the third largest gas distributor in Texas, providing service as a regulated public utility to wholesale and retail customers. Our largest markets are Oklahoma City and Tulsa, Oklahoma; Wichita, Topeka and Johnson County (which includes Overland Park), Kansas; and Austin and El Paso, Texas. Our energy marketing and trading operations provide service to customers in many states.

Definitions

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

Strategy

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.

Acquisitions and Divestitures

Acquisition of Gulf Coast Fractionators - On February 25, 2004, we announced an agreement with ConocoPhillips to purchase a 22.5 percent general partnership interest in Gulf Coast Fractionators (GCF), which owns a natural gas liquids fractionation facility, located in Mont Belvieu, Texas for $23 million, subject to adjustments. The pending acquisition is subject to the customary closing conditions, the consent of the partners, and agreement by the partners that we will replace ConocoPhillips as operator of the facility. By existing agreement, the GFC partners have a preferential right to purchase the ConocoPhillips interest at the same terms as agreed to by us. This preferential right expires March 31, 2004. This facility has a fractionation capacity of 110 MBbls/d of mixed NGLs. As the operator, we will operate the facility and control approximately 24.8 MBbls/d of fractionation capacity. The acquisition is expected to close in April 2004 and is estimated to add $1.8 million to operating income in 2004.

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Sale of Transmission and Gathering Pipelines and Compression - On March 1, 2004, we completed a transaction to sell certain natural gas transmission and gathering pipelines and compression for approximately $13 million.

Acquisition of Properties of Wagner & Brown, Ltd. - On December 22, 2003, we purchased approximately $240 million of Texas gas and oil properties and related flow lines from a partnership owned by Wagner & Brown, Ltd. of Midland, Texas. The results of operations for these assets have been included in our consolidated financial statements since that date. The acquisition included approximately 318 wells, 271 of which we operate, and 177.2 Bcfe of estimated proved gas and oil reserves as of the September 1, 2003 effective date, with additional probable and possible gas reserve potential. Net production from these properties is approximately 26,000 Mcfe per day.

Acquisition of NGL Storage and Pipeline - In December 2003, we acquired NGL storage and pipeline facilities located in Conway, Kansas for approximately $13.7 million from ChevronTexaco. In the prior two years we had leased and operated these facilities.

Sale of Transmission Assets - In October 2003, we completed a transaction to sell certain Texas transmission assets for a sales price of approximately $3.1 million. A charge against accumulated depreciation of approximately $7.8 million was recorded in accordance with Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71) and the regulatory accounting requirements of the Federal Energy Regulatory Commission (FERC) and Texas Railroad Commission (TRC).

Acquisition of Fort Bliss Gas Distribution System - In August 2003, we acquired the gas distribution system at the United States Army’s Fort Bliss in El Paso, Texas for $2.4 million. The gas distribution system at Fort Bliss has approximately 2,500 customers.

Acquisition of Pipeline System - In August 2003, we acquired a pipeline system that extends through the Rio Grande Valley region in Texas for $3.6 million. The Texas Gas Service Company (TGS) pipeline system serves the city gate points for the TGS Rio Grande Valley service area, providing service to approximately 10 transport customers, two power plants and offers access to production wells that supply the area.

Sale of Production Assets - In January 2003, we closed the sale of approximately 70 percent of the natural gas and oil producing properties of our Production segment for a cash sales price of $294 million, including adjustments. The properties sold were in Oklahoma, Kansas and Texas. 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 $61.2 million in 2003 related to this sale. The statistical and financial information related to the properties sold is 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 Properties from Southern Union Company - On January 3, 2003, we purchased the Texas gas distribution business and other Texas assets from Southern Union Company (Southern Union). The results of operations for these assets have been included in our consolidated financial statements since that date. We paid approximately $436.6 million for these assets, including $16.6 million in working capital adjustments. The primary assets acquired were gas distribution operations that currently serve approximately 544,000 customers in cities located throughout Texas, including the major cities of El Paso and Austin, as well as the cities of Port Arthur, Galveston, Brownsville and others. Over 90 percent of the customers are residential. The other assets acquired include a 125-mile natural gas transmission system, as well as other energy related domestic assets involved in gas marketing, retail sales of propane and distribution of propane. The purchase also included natural gas distribution investments in Mexico. The gas distribution assets are operated under TGS.

Sale of Midstream Natural Gas Assets - On December 13, 2002, we closed the sale of a portion 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.

Sale of Sayre Storage Company Property Rights - In December 2002, we sold our property rights in Sayre Storage Company (Sayre), a natural gas storage field, and entered into a long-term agreement with the purchaser whereby we retain storage capacity consistent with our original ownership position.

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

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Sale of Investment in K. Stewart Petroleum Corporation - In June 2001, we sold our 40 percent interest in K. Stewart Petroleum Corporation (K. Stewart), a privately held exploration company, for a sales price of $7.7 million.

Environmental Matters

We are subject to multiple environmental laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid wastes and hazardous material and substance management. These laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. If an accidental leak or spill of hazardous materials occurs from our lines or facilities, in the process of transporting natural gas, or at any facilities that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including investigation and clean up costs, which could materially affect our results of operations and cash flows. In addition, emission controls required under the Federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure you that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial condition and results of operations.

We own or retain legal responsibility for the environmental conditions at 12 former manufactured gas sites in Kansas. These sites contain potentially harmful materials that 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 work at these sites. The terms of the consent agreement allow us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. We have commenced active remediation on three sites with regulatory closure achieved at two of these locations, and have begun assessment at the remaining sites. The site situations are not common and we have no previous experience with similar remediation efforts. We have not completed a comprehensive study of the remaining nine sites and therefore cannot accurately estimate individual or aggregate costs to satisfy our remedial obligations.

Our preliminary review of similar cleanup efforts at former manufactured gas sites reveals that costs can range from $100,000 to $10 million per site. These estimates do not give effect to potential insurance recoveries, recoveries through rates or from unaffiliated parties, to which we may be entitled. At this time, we have not recorded any amounts for potential insurance recoveries or recoveries from unaffiliated parties, and we are not recovering any environmental amounts in rates. Total costs to remediate the two sites, which have achieved regulatory closure, totaled approximately $800,000. Total remedial costs for each of the remaining sites are expected to exceed $400,000 per site, but there is no assurance that costs to investigate and remediate the remaining sites will not be significantly higher. As more information related to the site investigations and remediation activities becomes available, and to the extent such amounts are expected to exceed our current estimates, additional expenses could be recorded. Such amounts 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 and there have been no material effects upon earnings or our competitive position during 2003 related to compliance with environmental regulations.

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Employees

We employed 4,342 people at December 31, 2003. The acquisition of our Texas assets added approximately 735 employees to our workforce in 2003. Kansas Gas Service Company (KGS) employed 827 people who were subject to collective bargaining contracts at December 31, 2003. We had no other union employees at December 31, 2003. The following table sets forth our contracts with unions at December 31, 2003.

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 at 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 to the SEC 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 SEC. Copies of our Code of Business Conduct, Corporate Governance Guidelines, Director Independence Guidelines and Board of Director committee charters including the charters of our audit, executive, executive compensation and corporate governance committees are also available on our website and we will make available, free of charge, copies of these documents upon request.

DESCRIPTION OF BUSINESS SEGMENTS

We report operations in the following reportable business segments:

Production

Segment Description - Our Production segment produces natural gas and oil in Oklahoma through ONEOK Energy Resources Company and in Texas through ONEOK Texas Energy Resources, LP.

General - We focus on development activities rather than exploratory drilling and seek to serve as operator on wells where we have significant ownership interest. In our role as operator, we control operating decisions that impact production volumes and lifting costs. We strive to reduce finding costs and to minimize production costs. We continue to review opportunities to acquire new properties, develop existing properties and divest of properties when the market offers premium value.

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Operating income from the Production segment is 3.6 percent, 2.8 percent, and 7.2 percent of our consolidated operating income from continuing operations for fiscal years 2003, 2002, and 2001, respectively. The Production segment has no single external customer from which it receives ten percent or more of consolidated revenues.

Acquisitions and Divestitures - The following acquisitions and divestitures are described beginning on page 3:

Producing Reserves - The Production segment primarily focuses on natural gas production activities. We own interests in 839 gas wells and 69 oil wells located in Oklahoma and Texas. A number of these wells produce from multiple zones. Production from our retained gas and oil wells decreased in 2003 compared to 2002 as a result of the natural decline in production on existing wells and limited new drilling. The lower gas production on retained wells was offset by the partial month of production on the properties acquired in December 2003. During 2003, we participated in drilling 20 wells, which included 19 producing gas wells and one dry hole.

Market Conditions and Business Seasonality - Natural gas prices during 2003 were stronger throughout the year than historical prices. This resulted in increased industry-wide drilling activity, which required us to participate in a number of developmental drilling projects during the year with other operators in order to maintain our reserve value. Until we identified and closed on the acquisition of the oil and gas properties in Texas, we limited our capital projects to only those required to maintain our leasehold position in Oklahoma. Once we fully incorporate the Texas properties into our operations, we will resume our pursuit of acquisition opportunities as a low-risk method of adding reserves.

Our goal is to continue to build on and maintain our existing reserve base through developmental drilling, and further supported by acquisition. We operate or have large interests in our retained wells. We are in a competitive position within our operating regions due to low finding costs and high quality production at locations near transportation points and markets. During 2003, the segment’s gas and oil production was sold at market prices to a number of affiliated and unaffiliated markets.

Similar to our other business segments, the Production segment can be subject to seasonal factors. The Production segment’s revenues are impacted by prices, which have been historically higher in the winter heating months, when demand is higher. Much of the seasonality has been offset through the utilization of hedging. As a result, prices received are not necessarily comparable to historical patterns. Oil prices in the United States are also impacted by international production and export policies.

Risk Management - We utilized derivative instruments in 2003 to hedge anticipated sales of natural gas and oil production. In 2003, hedges on gas production resulted in an average net wellhead price of $4.50 per MMBtu for 78 percent of our 2003 production. Hedges on oil production resulted in an average price of $27.25 per Bbl for 79 percent of our 2003 oil production.

At December 31, 2003, the Production segment had hedged 89 percent of its anticipated gas production and 89 percent of its anticipated oil production for 2004 at a weighted average wellhead price of $5.28 per MMBtu for gas and a net New York Mercantile Exchange (NYMEX) price of $30.35 per Bbl for oil. See Item 7A, Quantitative and Qualitative Disclosures About Market Risk and Note D of Notes to Consolidated Financial Statements in this Form 10-K.

Gathering and Processing

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

General - We have a processing capacity of approximately 2.0 Bcf/d, of which approximately 0.2 Bcf/d is currently idle. We own approximately 13,800 miles of gathering pipelines that supply our gas processing plants.

Operating income from the Gathering and Processing segment is 14.1 percent, 8.9 percent, and 17.0 percent of our consolidated operating income from continuing operations in 2003, 2002, and 2001, respectively. The Gathering and Processing segment has no single external customer from which it receives ten percent or more of consolidated revenues.

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The gas processing operation primarily includes the extraction of mixed NGLs from natural gas and the fractionation (separation) of mixed NGLs into component products (ethane, propane, iso butane, normal butane and natural gasoline). 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 connects unaffiliated and affiliated producing wells to the processing plants. It consists of the gathering of natural gas through pipeline systems, including compression, treatment 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 fee for gas processing.

During 2003, we processed an average of 1,209 MMMBtu/d of natural gas and produced an average of 59 MBbls/d of NGLs. NGL Marketing markets our NGL production and also purchases NGLs from third parties for resale. During 2003, we sold approximately 114 MBbls/d of NGLs to a diverse base of customers.

Acquisitions and Divestitures - The following acquisitions and divestitures are described beginning on page 3:

Market Conditions and Business Seasonality - During the year, both crude oil and natural gas prices were volatile with NYMEX crude oil prices ranging from $26.96 to $36.79 per Bbl and NYMEX natural gas prices ranging from $4.43 to $9.13 per MMBtu.

Despite significant consolidation in the recent past, the U.S. midstream industry remains relatively fragmented and we face 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 and storage of natural gas and NGLs. The factors that affect competition typically are the fees charged under the contract, the pressures maintained on the gathering systems, the location of our gathering systems relative to competition, the efficiency and reliability of the operations, and the delivery capabilities that exist at each plant location.

We have responded to these industry conditions by primarily acquiring assets that are strategically located near our existing assets, reducing costs, selling assets in non-core operating areas and renegotiating unprofitable contracts. The principal goal of the contract renegotiation effort is to mitigate earnings and cash flow variability.

Some of our products, such as natural gas and propane used for heating, are subject to seasonality resulting in more demand during the months of November through March. As a result, prices of these products are typically higher during that time period. Other products, such as ethane, are tied to the petrochemical industry, while iso butane and natural gasoline are used by the refining industry as blending stocks. As a result, the prices of these products are affected by the economic conditions and demand associated with these various industries.

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 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 can be used to minimize volatility in NGL and natural gas prices. Accordingly, we will occasionally use derivative instruments to hedge the purchase and sale of natural gas used for or produced by our operations. We also occasionally 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 in this Form 10-K.

Transportation and Storage

Segment Description - 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 Texas Gas Storage L.P. (OTGS) and ONEOK Gas Gathering, L.L.C. (OGG). The TRC regulates both OTGS and WesTex. OGS operates under market-based rate authority granted by the FERC. 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.

General - We own approximately 5,800 miles of intrastate pipeline and storage companies with a working storage capacity of approximately 59.6 Bcf, of which 8.0 Bcf is temporarily idle.

In Oklahoma, we operate OGT, OGG and OGS. These companies have approximately 2,900 miles of pipeline and five storage facilities with a combined working storage capacity of 44.6 Bcf. In December 2002, certain Oklahoma storage property rights were sold and a long-term agreement was entered into with the purchaser, whereby we retained 3 Bcf of working capacity for our own use consistent with our historical usage. Our Distribution segment is the Transportation and Storage segment’s major customer for intrastate natural gas pipeline transportation in Oklahoma and Kansas. Capacity in the storage facilities is leased to both ONEOK Energy Marketing and Trading Company (OEMT) and third parties under terms determined by contract or the market.

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

The Oklahoma transmission system transported 236.7 Bcf in 2003, 257.2 Bcf in 2002, and 253.9 Bcf in 2001. 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 Kansas transmission assets from MCMC to our affiliated distribution company in Kansas. All historical financial and statistical information has been adjusted to reflect this transfer. After the transfer MCMC operates 200 miles of pipeline and three gas storage facilities with approximately 5.6 Bcf of working storage capacity. 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 2,680 miles of pipeline and three storage facilities. Total working storage capacity is approximately 9.3 Bcf. The Texas transmission system transported 192.2 Bcf in 2003, 227.3 Bcf in 2002 and 206.4 Bcf in 2001. 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, 11 natural gas processing plants and two producing fields. This system provides for gas to be moved to the Waha Hub for transportation 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 resulting in reduced in use storage capacity in Texas of approximately 5 Bcf.

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 11.4 percent, 14.4 percent, and 20.8 percent of our consolidated operating income from continuing operations in 2003, 2002, and 2001, respectively. The Transportation and Storage segment has no single external customer from which it receives ten percent or more of consolidated revenues.

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Divestitures - The following divestitures are described beginning on page 3:

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 Oklahoma, Kansas and Texas. 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. We believe that the working capacity of our transportation and storage assets enables us to compete effectively.

This industry is significantly affected by the economy, price volatility and weather. Transportation quantities fluctuate due to rainfall that impacts irrigation demand, hot temperatures that 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 withdrawn 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, Kansas and Texas are regulated by the Oklahoma Corporation Commission (OCC), KCC and TRC, respectively. We have flexibility in establishing transportation rates with customers. However, there is a maximum rate that we can charge our customers in Oklahoma and Kansas and if a rate cannot be agreed upon in Texas then 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 currently considering the steps necessary to return the field to service in accordance with regulations recently issued by the KDHE.

Customers - The Transportation and Storage segment serves affiliated companies in the Distribution and Marketing and Trading segments, as well as a number of commercial, industrial, power generation and fertilizer transporters. Each of our Transportation and Storage companies provides flexible service alternatives to meet the consumers’ needs.

Distribution

Segment Description - Our Distribution segment provides natural gas distribution in Kansas, Oklahoma and Texas. Operations in Kansas are conducted through our KGS division, which serves residential, commercial, industrial, transportation and wholesale customers. Operations in Oklahoma are conducted through our Oklahoma Natural Gas (ONG) division, which serves residential, commercial, industrial, wholesale and transportation customers, including customers that lease gas pipeline capacity. Operations in Texas are conducted through our TGS division, which serves residential, commercial, industrial, public authority and transportation customers. TGS is subject to regulatory oversight by the various municipalities that it serves, which have primary jurisdiction in their respective areas. Rates in areas adjacent to the various municipalities and appellate matters from municipalities are subject to regulatory oversight by the TRC. This segment also includes an interstate gas transportation company, OkTex Pipeline Company (OkTex), which is regulated by the FERC.

General - At December 31, 2003, ONG delivered natural gas to approximately 804,000 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 40 Oklahoma communities.

At December 31, 2003, KGS supplied natural gas to approximately 642,000 customers in 336 communities in Kansas. It also makes wholesale delivery to 27 customers. KGS’ largest markets served include Kansas City, Wichita, Topeka, and Johnson County, which includes Overland Park.

On July 28, 2003, KGS and the International Brotherhood of Electrical Workers labor union entered into a three-year bargaining agreement expiring June 30, 2006. Approximately 351 of our KGS employees are members of this labor union, comprising approximately 30 percent of our KGS workforce. The parties agreed to a two percent wage increase effective July 1, 2004 and an additional two percent wage increase effective July 1, 2005. On September 12, 2003, KGS completed negotiations with the remaining three Kansas labor unions to replace collective bargaining agreements that expired on July 31, 2003. Approximately 476 of our KGS employees are members of those three labor unions, comprising approximately 41 percent of our KGS workforce. The parties agreed to extend the existing agreements for one year with a two percent wage

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increase effective retroactively to August 1, 2003. Currently, we have no ongoing labor negotiations and there are no other unions representing our employees.

At December 31, 2003, TGS delivered natural gas to approximately 544,000 customers in 181 communities in Texas. TGS’ largest markets served include Austin and El Paso.

Operating income from the Distribution segment is 26.4 percent, 25.6 percent, and 24.0 percent of the consolidated operating income from continuing operations for fiscal years 2003, 2002, and 2001, respectively. The Distribution segment has no single external customer from which it receives ten percent or more of consolidated revenues.

Acquisitions - The following acquisitions are described beginning on page 3:

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 through the Transportation and Storage segment’s transmission system as well as transmission systems belonging to unaffiliated companies, ONG has direct access to all of the major gas producing areas in Oklahoma and the mid-continent region. Our gas storage, transportation and gathering assets were unbundled from the utility and operate as separate entities. A majority of ONG’s gas supply and transportation contracts were competitively bid and awarded for service beginning in the 2000/2001 heating season for a five-year term. 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 competitively bid reserved storage capacity of 0.9 Bcf with Southern Star Central Gas Pipeline, Inc. (Central) during 2003. Effective April 1, 2003, ONG added two additional storage contracts with affiliates. The first affiliate 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 affiliate 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 give ONG a reserved storage 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 2.4 Bcf of reserved storage capacity with MCMC throughout 2003. Effective April 22, 2003, KGS added an additional storage contract with Central for 2.5 Bcf of reserved storage capacity. The four contracts combined give KGS a reserved storage capacity of approximately 17.7 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’ demand served by the Central pipeline system. Amoco is one of various suppliers over the Central pipeline system. Management believes that if this contract were cancelled the 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.

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

KGS has transportation agreements for delivery of gas that have remaining terms with some extending to 2017 with the following nonaffiliated 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 five percent of KGS’ transportation service is provided by MCMC, which is an affiliated company.

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’ 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 proposed completion date of this pipeline is 2005. CIG must obtain several regulatory approvals before the pipeline can be completed.

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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 has firm transportation service. KGS uses these transmission pipeline assets to serve its customers and provide transportation service on and off-system. The order was effective July 1, 2002. All historical financial and statistical information has been adjusted to reflect this transfer.

The majority of TGS’ 2003 gas requirements for its operations were delivered under short and long-term transportation contracts through five major pipeline companies. TGS purchases significant volumes of gas under short and long-term arrangements with suppliers. The amounts of such short-term purchases are contingent upon price. TGS has firm supply commitments for all areas that are supplied with gas purchased under short-term arrangements. TGS also holds rights to 5.2 Bcf of storage capacity to assist in meeting peak demands in El Paso and Austin service areas.

TGS is committed under various agreements to purchase certain quantities of gas in the future. These commitments may extend over a period of several years depending upon when the required minimum quantity is purchased. TGS has purchased gas tariffs in effect for all its utility service areas that provide for purchased gas cost recovery under defined methodologies.

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. However, if supply shortages occur, ONG’s rate schedule “Order of Curtailment” and 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. In Texas, gas sales and/or transportation contracts with interruption provisions, whereby large volume users purchase gas with the understanding that they may be forced to shut down or switch to alternate sources of energy at times when the gas is needed for higher priority customers, have been utilized for load management by TGS and the gas industry as a whole. In addition, during times of special supply problems, curtailments of deliveries to customers with firm contracts may be made in accordance with guidelines established by appropriate federal and state regulatory agencies.

Residential and Commercial Customers - KGS, ONG and TGS distribute natural gas as public utilities to approximately 71 percent of Kansas’ distribution market, 86 percent of Oklahoma’s distribution market and 14 percent of Texas’ distribution market. Natural gas sold to residential and commercial customers, which is used primarily for heating and cooking, accounts for approximately 58 and 16 percent of gas sales, respectively, in Kansas, 66 and 27 percent of gas sales, respectively, in Oklahoma, and 62 and 23 percent of gas sales, respectively, in Texas.

A franchise, although nonexclusive, 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, KGS and TGS hold franchises in 40, 280 and 83 municipalities, respectively. 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 Customers - Under ONG’s transportation tariffs, certain customers, for a fee, 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. TGS transports gas for industrial customers that qualify under tariffs in each of the TGS service areas. Qualifying industrial and commercial customers are able to purchase gas on the spot market and have it transported by ONG, KGS and TGS.

Because of increased competition for the transportation of gas to commercial and industrial 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

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markets, the average cost of gas is less for ONG, KGS and TGS customers than the cost of an equivalent amount of electricity.

The Distribution segment is subject to competition from other pipelines for its existing industrial load. ONG, KGS and TGS compete for service to the large industrial and commercial customers and competition continues to lower rates. A portion of ONG’s transportation services and KGS’ ECT services are at negotiated rates that are generally below the approved transportation tariff rates, and increased competition potentially could lower these rates. In TGS’ service areas, transportation service is negotiated due to the ability of competitive pipelines within the proximity to by-pass TGS service, and file a separate, confidential tariff at the TRC. 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 and KGS’ tariff rates include a temperature normalization adjustment clause during the heating season, which mitigates the effect of fluctuations in weather. KGS’ WeatherProof Bill program was designed to mitigate the effect of weather fluctuations in Kansas for customers electing to use this program. Due to a notification that KGS’ contractor would not be able to provide sufficient support for the WeatherProof Bill program, this program ended effective December 1, 2003. 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. Approximately 78 percent of TGS’ revenues are protected from abnormal weather due to a flat fee rate and a weather normalization adjustment clause. TGS’ weather normalization adjustment clause is in 17 Texas towns and cities, including Austin, Galveston and Mineral Wells, to stabilize earnings and neutralize the impact of unusual weather on customers. A flat monthly fee is included in the authorized rate design for El Paso and Port Arthur to protect customers from abnormal weather. From time to time, TGS uses derivative instruments to mitigate the volatility of the cost of gas to protect its customers in the city of El Paso.

Government Regulation - Rates charged for gas services are established by the OCC for ONG and by the KCC for KGS. TGS is subject to regulatory oversight by the various municipalities that is serves, which have primary jurisdiction in their respective areas. Rates in areas adjacent to the various municipalities and appellate matters are subject to regulatory oversight by the TRC. Gas purchase costs are included in the Purchased Gas Adjustment (PGA) clause rate that is billed to customers. Our distribution companies 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, KCC, TRC and various municipalities in Texas.

There were several regulatory initiatives in 2003. The highlights of these initiatives are as follows:

We believe we will be able to recognize all revenues authorized by the OCC in this limited issue filing. We believe our next rate increase will exceed $10.7 million. We will continue to monitor the regulatory environment to determine any changes in our estimated future rate increase and if a refund liability is determined to exist we will record a reserve for the obligation.

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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, 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 NGPA with respect to rates, accounts and records, the addition of facilities, the extension of services in certain cases, the abandonment of services and facilities, the curtailment of gas deliveries and other matters. OkTex has the capacity to move up to 1,100 MMcf/d.

Marketing and Trading

Segment Description - Our Marketing and Trading segment conducts its business through 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 reliable marketing franchise allows us to capture volatility in the energy markets.

Through the strength of our wholesale marketing, trading and risk management capabilities, we provide commodity-diverse products and services designed to meet each of our customers’ needs. As a result of our core competencies, our retail operations have become a full-service provider in the states of our corporate-owned utilities and have successfully expanded throughout the United States.

OEMT was the successful bidder to supply gas to 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 our electric generating plant. All segment data has been restated to reflect this change.

General - Our Marketing and Trading segment purchases, stores, markets, and trades natural gas in the retail sector in its core distribution area and the wholesale sector throughout most of the United States. We have also diversified our marketing and trading portfolio to include power, crude oil and natural gas liquids. We have a strong mid-continent region storage and transport position, with transportation capacity of 1.3 Bcf/d. With total cyclical storage capacity of 75 Bcf, withdrawal capability of 2.3 Bcf/d and injection capability of 1.5 Bcf/d spread across 19 different facilities, we have direct access to most regions of the country and flexibility to capture volatility in the energy markets. Because of seasonal demands on natural gas for heating, volatility tends to be greater in the winter months. We recently extended our marketing and trading operations into leasing storage and pipeline capacity in Canada. 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.

Operating income from our Marketing and Trading segment is 44.2 percent, 48.9 percent, and 29.3 percent of our consolidated operating income from continuing operations for fiscal years 2003, 2002, and 2001, respectively. A $37.4 million charge related to Enron’s bankruptcy proceedings is included in 2001 and a $14.0 million gain related to the sale of Enron claims is included in 2002. The Marketing and Trading segment has no single external customer from which it receives ten percent or more of consolidated revenues.

We completed construction on 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. Because of seasonal demands for electricity for summer cooling, the demands on our power plant are greater in the summer months. In October 2003, we signed a tolling arrangement with a third party for

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their power plant in Big Springs, Texas, which is connected to our gas transmission system. The agreement, which expires in December 2005, allows us to sell the steam and power generated in the Electric Reliability Council of Texas (ERCOT). This agreement increased our owned or contracted power capacity from 300 to 512 megawatts.

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. We have 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, and crude oil. 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.

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 in this Form 10-K for further discussion.

Other

Segment Description - The primary companies in our Other segment include ONEOK Leasing Company and ONEOK Parking Company. Through these two subsidiaries, we own a parking garage and lease an office building (ONEOK Plaza) in downtown Tulsa, Oklahoma, where our headquarters are located. ONEOK Leasing Company leases excess office space to others and operates our headquarters office building. ONEOK Parking Company owns and operates a parking garage adjacent to our corporate headquarters.

The Other segment has no single external customer from which it receives ten percent or more of consolidated revenues.

On March 15, 2002, MHR merged with Prize Energy Corp., which reduced our direct ownership to approximately 11 percent and reduced the number of positions held by us on the MHR board of directors 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 comprehensive income. During the second quarter of 2002, we sold our remaining shares of MHR common stock for a pretax 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.

Segment Financial Information - For financial and statistical information regarding our business units by segment, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note O of Notes to the Consolidated Financial Statements in this Form 10-K.

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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DESCRIPTION OF PROPERTIES

Production

We own varying economic interests, including working, royalty and overriding royalty interests in 839 gas wells and 69 oil wells that are related to both our Oklahoma and Texas operations, some of which are in multiple producing zones. We own 90,212 net onshore developed leasehold acres and 10,444 net onshore undeveloped acres located in Oklahoma and Texas. 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 2.0 Bcf/d, of which approximately 0.2 Bcf/d is currently idle. We own a total of approximately 13,800 miles of gathering pipelines that supply our gas processing plants.

Our natural gas processing operations utilize two types of gas processing plants, field plants 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 two NGL storage facilities in Kansas. The total capacity of the facilities is approximately 14 MMBbls. We own and operate two fractionation facilities, one in Oklahoma and one in Kansas. The total fractionation capacity of the two facilities is approximately 89 MBbls/d.

Transportation and Storage

We own approximately 2,900 miles of transmission pipeline in Oklahoma, approximately 200 miles in Kansas, and approximately 2,680 miles in Texas. Compression and dehydration facilities are located at various points throughout the pipeline system. In addition, we lease one and own four underground storage facilities located in Oklahoma, own three storage facilities in Kansas and own three storage facilities in Texas. The leased storage facility is leased through a long-term agreement. The storage facilities primarily consist of land and leasehold agreements with mineral and surface owners, wells and equipment, rights of way, and cushion gas. The total working storage capacity of these facilities is approximately 59.6 Bcf, of which 8.0 Bcf is currently idle. Four of the Oklahoma storage facilities are located in close proximity to large market areas. All 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 17,386 miles of pipeline and other distribution facilities in Oklahoma, approximately 12,211 miles of pipeline and other distribution facilities in Kansas and approximately 8,333 miles of pipeline and other distribution facilities in Texas. We own a number of warehouses, garages, meter and regulator houses, service buildings, and other buildings throughout Oklahoma, Kansas and Texas. We also own or lease a fleet of trucks and maintain an inventory of spare parts, equipment, and supplies.

Marketing and Trading

We own 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 224,000 square feet for our own use and lease the remaining space to others.

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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.

As of December 31, 2003, all of the oil and gas reserves for our Production segment are located in the Oklahoma and Texas.

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 included within this Annual Report on Form 10-K.

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.

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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, 2003.

Gross developed acres and net developed acres by well classification are not available. Gross developed acres for both oil and gas are 163,947 acres. Net developed acres for both oil and gas is 90,212 acres.

Undeveloped Acreage

The following table sets forth the gross and net undeveloped leasehold acreage for our Production segment at December 31, 2003.

Of the net undeveloped acres, approximately 96 percent are in the Anadarko Basin area of Oklahoma. The balance is located in Gregg and Upshur counties in east Texas.

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 2003, 2002, or 2001.

Present Drilling Activities

At December 31, 2003, the Production segment was participating in the drilling of 10 wells. Our net interest in these wells amounts to 2.7 wells.

Future Obligations to Provide Oil and Gas

Our Production segment does not have any future obligations to provide oil and gas.

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United States ex rel. Jack J. Grynberg v. ONEOK, Inc., et al., 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, along with two of our subsidiaries, were served on June 21, 1999 as defendants in an action brought under the False Claims Act by Mr. Grynberg, ostensibly on behalf of the United States. Approximately 70 other substantially identical lawsuits were filed against other companies in the natural gas industry. The main claim against the defendants alleges that they intentionally provided false information to the government concerning the volume and heating content of natural gas produced from lands in which the Federal Government or Native Americans owned the royalty rights. 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 have been transferred to the United States District Court for the District of Wyoming for coordination of pretrial proceedings. That Court overruled the defendants’ initial motion to dismiss, but granted the motion of the United States to dismiss certain portions of the complaints. The defendants are now conducting discovery regarding whether Mr. Grynberg has met the unique jurisdictional prerequisites for maintaining an action under the False Claims Act. We will continue to defend all claims made against us in this action.

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 (“Price I”). Plaintiffs brought suit on May 28, 1999 against us, five of our subsidiaries and one of our divisions as well as approximately 225 other defendants. Plaintiffs sought class certification for its claims that the defendants had underpaid gas producers and royalty owners throughout the United States by intentionally understating both the volume and the heating content of purchased gas. After extensive briefing and a hearing, the Court refused to certify the class sought by plaintiffs. Plaintiffs then filed an amended petition limiting the purported class to gas producers and royalty owners in Kansas, Colorado and Wyoming and limiting the claim to undermeasurement of volumes. A schedule has recently been established for resolving whether the case may properly be certified as a class action considering the amended petition. We intend to continue defending all claims made against us in this case.

Will Price and Stixon Petroleum, et al. v. Gas Pipelines, et al., 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 03C232 (“Price II”). This action was filed by the plaintiffs on May 12, 2003, after the Court had denied class status in Price I. Plaintiffs claim that 21 groups of defendants, including us and four of our subsidiaries, intentionally underpaid gas producers and royalty owners by understating the heating content of purchased gas in Kansas, Colorado and Wyoming. Price II has been consolidated with Price I for the determination of whether either or both cases may properly be certified as class actions. We intend to continue defending all claims made against us 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. Status conferences have been held periodically regarding progress toward reaching an agreed consent order. No date has been set for a follow up status conference.

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. Trial is set for June 2004.

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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 same gas explosions in Hutchinson, Kansas referenced in the above paragraph. The petition seeks recovery on behalf of the residents of Reno County, Kansas, who have suffered or will suffer damage and/or economic losses relating to personal property and displacement costs as a result of the explosion. We have never been served in this matter, and we are currently evaluating how we may proceed given the failure of service.

U.S. Commodity Futures Trading Commission. On January 9, 2003, we received a subpoena from the U.S. Commodity Futures Trading Commission (“CFTC”) requesting information regarding certain trading by energy and power marketing firms and information provided by us to energy industry publications in connection with the CFTC’s industry-wide investigation of trading and trade reporting practices of power and natural gas trading companies. We ceased providing such information to energy industry publications in 2002. Upon receipt of the subpoena, we conducted an internal review relating to our reporting of natural gas trading information to energy industry publications, and we produced documents and other information to the CFTC as requested. On January 28, 2004, we reached a settlement wit the CFTC, and we agreed to continue to cooperate fully and expeditiously with the CFTC in its ongoing industry-wide investigation and related proceedings. In the settlement, we neither admit nor deny the findings in the CFTC settlement order. The financial terms of the settlement required a payment by us of $3 million as a civil monetary penalty, which we have paid.

Conerstone Propane Partners, L.P., et al. v. E Prime, Inc., ONEOK Energy Marketing and Trading Company, L.P., ONEOK, Inc., and Calpine Energy Services, L.P., United States District Court for the Southern District of New York, Case No. 04-CV-00758. On February 4, 2004, we received notice that we and our wholly owned subsidiary, ONEOK Energy Marketing and Trading Company, L.P., have been named as two of the defendants in the above-captioned lawsuit filed in the United States District Court for the Southern District of New York brought on behalf of persons who bought and sold natural gas futures and options contracts on the New York Mercantile Exchange during the years 2000 through 2002. The Complaint seeks class certification, actual damages in unspecified amounts for alleged violations of the Commodities Exchange Act, recovery of costs of the suit, including attorney’s fees, and other appropriate relief. The Complaint states that it is filed as a related action to a consolidation class action complaint naming a number of other defendants in the energy industry. Although it is too early to accurately evaluate this matter, based on current information available to us, we do not expect this matter to have a material adverse effect on us. We intend to vigorously defend ourselves against these claims.

Enron Corp. v. Silver Oak Capital, LLC and AG Capital Recovery Partners III, LP, Adversary Proceeding No. 03-93568, relating to Case No. 01-16034, in the United States Bankruptcy Court for the Southern District of New York. A Complaint was filed by Enron Corp. on November 28, 2003 against Silver Oak Capital, LLC and AG Capital Recovery Partners III, LP (“Angelo Gordon”) to avoid as a fraudulent transfer, under Section 548 of the Bankruptcy Code, certain guaranties issued by Enron Corp. in support of obligations owed by Enron North America Corp. to one of our subsidiaries, ONEOK Energy Marketing and Trading Company, L.P. (“OEMT”). Angelo Gordon is the assignee of the OEMT claims that were sold by OEMT on a recourse basis to Bear Stearns & Co. Inc. under a Transfer of Claims Agreement dated May 1, 2002. The filing of the Complaint by Enron may trigger obligations of OEMT under the Transfer of Claims Agreement to repurchase some claims it previously sold. If OEMT is obligated to repurchase any of the claims, then it would be responsible for enforcement of the claims in the Enron Corp. bankruptcy proceedings, which might result in an ultimate payment to it of less than its prior sales price of those claims. Although it is too early to accurately evaluate the possible effect of this reassignment and the ultimate value of the claims in the Enron Corp. bankruptcy, based on current information available to us we do not expect this matter to have a material adverse effect on the company.

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.

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.

There were 12,784 holders of record of our common stock at March 1, 2004.

Dividends

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

Our Revolving Credit Facility with Bank of America, N.A. and other financial institutions limits dividends and other distributions on our common stock. Under the most restrictive of these provisions, $90.4 million of retained earnings is restricted. At December 31, 2003, $405.6 million was available for dividends on our common stock.

On January 15, 2004 our board of directors approved an increase in the quarterly dividend on our common stock to $0.19 per share that was applicable to the quarterly dividend declared in January 2004.

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Equity Compensation Plan Information

The following table sets forth certain information concerning the Company’s equity compensation plans as of December 31, 2003.

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 to the two-for-one stock split in 2001. See Note S of the Notes to our Consolidated Financial Statements in this Form 10-K.

In February 2003, we purchased approximately 9 million shares of our Series A Convertible Preferred Stock (Series A) 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 (Series D) reflecting the two-for-one stock split in 2001. The Series D stock had a fixed annual cash dividend rate of 92.5 cents per share. As a result of this transaction, Topic D-95 no longer applied to our computation of EPS beginning in February 2003. In November 2003 the Series D Convertible Preferred Stock was converted to common stock. Prior to December 31, 2003, the Series A Convertible Preferred Stock was cancelled and Series D Convertible Preferred Stock was retired.

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

Executive Summary - We are a diversified energy company with nearly a century of experience in the natural gas business. Since 1906, we have grown from an Oklahoma intrastate natural gas pipeline business to a company providing natural gas services from the wellhead to the burner tip throughout the mid-continent area of the United States with a recent expansion into Canada. To achieve this diversity, we have built a combination of regulated and nonregulated businesses.

We are the largest natural gas distributor in Kansas and Oklahoma and the third largest in Texas. We serve almost 2 million customers through our Distribution segment’s operations. After serving Oklahoma customers for over 90 years, the substantial growth in this segment began with the acquisition of the Kansas distribution assets in 1997. In January 2003, we completed the acquisition of the Texas gas distribution system which currently serves 544,000 customers.

Our conservative practice of trading around assets we own has allowed for a successful marketing and trading business built around a strong mid-continent region storage and transport position which provides us direct access to most regions of the country and flexibility to capture volatility in the energy markets.

The production and midstream businesses complete the operation with each piece adding value to the other pieces resulting in a powerful asset mix.

We saw a positive change in 2003 with the repurchase and exchange of our Series A preferred stock, a stock that held participating rights in our undistributed earnings. This repurchase eliminated the dilutive effect resulting from computing earnings per share under Topic D-95. Additionally, all of the Series D issued in exchange for the Series A was converted by the end of 2003 to common stock and was then cancelled. These actions resulted in a capital structure consisting of only common stock that is more consistent with the capital structures of our peer companies.

The elimination of our Series A and Series D, and the dividend requirements associated with both, has allowed us to increase our common dividend per share. The quarterly dividend per common share has increased from 15.5 cents per share for the fourth quarter of 2002 to 19 cents per share currently, which is payable in the first quarter of 2004.

In 2003, we also saw a change in accounting for our energy trading contracts not under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133) and our energy trading

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inventories carried under storage agreements. These are no longer carried at fair value, but rather are accounted for on an accrual basis. The impact of this change shifted earnings from the second and third quarters to the first and fourth quarters.

Our strategy has not changed. It has been and continues to be one of maximizing shareholder value by acquiring assets that grow our operations into new market areas and complement our existing asset base, maximizing the earnings potential of existing assets and introducing regulatory initiatives that benefit us and our customers.

In addition to earnings per share, other key indicators that we use to evaluate our success are return on invested capital and shareholder appreciation as compared to our peer companies.

Acquisitions and Divestitures - On February 25, 2004, we announced an agreement with ConocoPhillips to purchase a 22.5 percent general partnership interest in Gulf Coast Fractionators (GFC), which owns a natural gas liquids fractionation facility located in Mont Belvieu, Texas for $23 million, subject to adjustments. The pending acquisition is subject to the customary closing conditions, the consent of the partners, and agreement by the partners that we will replace ConocoPhillips as operator of the facility. By existing agreement, the GFC partners have a preferential right to purchase the ConocoPhillips interest at the same terms as agreed to by us. This preferential right expires March 31, 2004. This facility has a fractionation capacity of 110 MBbls/d of mixed NGLs. As the operator, we will operate the facility and control approximately 24.8 MBbls/d of fractionation capacity. The acquisition is expected to close in April 2004 and is estimated to add $1.8 million to operating income in 2004.

On March 1, 2004, we completed a transaction to sell certain natural gas transmission and gathering pipelines and compression for approximately $13 million.

On December 22, 2003, we purchased approximately $240 million of Texas gas and oil properties and related flow lines from a partnership owned by Wagner & Brown, Ltd. of Midland, Texas. The results of operations for these assets have been included in our consolidated financial statements since that date. The acquisition included approximately 318 wells, 271 of which we operate, and 177.2 Bcfe of estimated proved gas and oil reserves as of the September 1, 2003 effective date, with additional probable and possible reserve potential. Net production from these properties is approximately 26,000 Mcfe per day.

In December 2003, we acquired NGL storage and pipeline facilities located in Conway, Kansas for approximately $13.7 million from ChevronTexaco. In the prior two years we had leased and operated these facilities.

In October 2003, we completed a transaction to sell certain Texas transmission assets for a sales price of approximately $3.1 million. A charge against accumulated depreciation for approximately $7.8 million was recorded in accordance with Statement 71 and the regulatory accounting requirements of the FERC and TRC.

In August 2003, we acquired the gas distribution system at the United States Army’s Fort Bliss in El Paso, Texas for $2.4 million. The gas distribution system at Fort Bliss serves approximately 2,500 customers.

In August 2003, we acquired a pipeline system that extends through the Rio Grande Valley region in Texas for $3.6 million. The TGS pipeline system serves the city gate points for the TGS Rio Grande Valley service area, providing service to approximately 10 transport customers, two power plants and offers access to production wells that supply the area.

In January 2003, we closed the sale of approximately 70 percent of the natural gas and oil producing properties of our Production segment for a cash sales price of $294 million, including adjustments. The properties sold were in Oklahoma, Kansas and Texas. 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 $61.2 million in 2003 related to this sale. The statistical and financial information related to the properties sold is reflected as a discontinued component in this Annual Report on Form 10-K. All periods presented have been restated to reflect the discontinued component.

On January 3, 2003, we purchased the Texas gas distribution business and other Texas assets from Southern Union. The results of operations for these assets have been included in our consolidated financial statements since that date. We paid approximately $436.6 million for these assets, including $16.6 million in working capital adjustments. The primary assets acquired were gas distribution operations that currently serve approximately 544,000 customers in cities located throughout Texas, including the major cities of El Paso and Austin, as well as the cities of Port Arthur, Galveston, Brownsville and others. Over 90 percent of the customers are residential. The other assets acquired include a 125-mile natural gas

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transmission system, as well as other energy related domestic assets involved in gas marketing, retail sales of propane and distribution of propane. The purchase also included natural gas distribution investments in Mexico. The gas distribution assets are operated under TGS.

On December 13, 2002, we closed the sale of a portion 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.

In December 2002, we sold our property rights in Sayre, a natural gas storage field, and entered into a long-term agreement with the purchaser whereby we retain storage capacity consistent with our original ownership position.

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. On March 15, 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 comprehensive income. In the second quarter of 2002, we sold our remaining shares of MHR common stock for a pretax gain of approximately $7.6 million, which is included in the Other segment’s other income for the year ended December 31, 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.

In June 2001, we sold our 40 percent interest in K. Stewart, a privately held exploration company, for a sales price of $7.7 million.

Regulatory - Several regulatory initiatives positively impacted the earnings and future earnings potential for the Distribution segment. These are discussed beginning on page 39.

Off-Balance Sheet Arrangements - We lease various buildings, facilities and equipment, which are accounted for as operating leases. We lease vehicles, which are accounted for as operating leases for financial purposes and capital leases for tax purposes. For a summary of scheduled future payments, see Contractual Obligations and Commercial Commitments on page 47.

Other - On January 1, 2003, we adopted Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure” (Statement 148) and began expensing the fair value of all stock options beginning with options granted on or after January 1, 2003 under the prospective method allowed by Statement 148. See Note A of the Notes to Consolidated Financial Statements in this Form 10-K for disclosure of our pro forma net income and earnings per share information had we applied the fair value provisions for options granted for the years ended December 31, 2002 and 2001.

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 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 Derivatives and Risk Management Activities - We engage in wholesale marketing and trading, price risk management activities and asset optimization services. In providing asset optimization services, we partner with other utilities to provide risk management functions on their behalf. We account for derivative instruments utilized in connection with these activities under the fair value basis of accounting in accordance with Statement 133 as amended by Statement of Financial Accounting Standards No. 137, “Accounting for Derivative Instruments and Hedging Activities—Deferral of the Effective Date of FASB Statement No. 133” (Statement 137), No. 138, “Accounting for Certain Derivative Instruments and

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Certain Hedging Activities” (Statement 138) and No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (Statement 149). We were not impacted by Statement 149.

Under Statement 133, entities are required to record all derivative instruments in price risk management assets and liabilities at fair value. A number of assumptions are considered in the determination of fair value. Our derivatives are primarily concentrated in exchange-traded and over-the-counter markets where quoted prices in liquid markets exist. Transactions are also executed in exchange-traded or over-the-counter markets for which market prices may exist but the market may be relatively inactive thereby resulting in limited price transparency that requires management’s subjectivity in estimating fair values. Other factors impacting our estimates of fair value include volatility, time value, counterparty credit and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions. Refer to the table on page 48 for amounts in our portfolio at December 31, 2003 which were determined by prices actively quoted (exchange-traded), prices provided by other external sources (over-the-counter), and prices derived from other sources. The gain or loss from changes in fair value is recorded in the period of the change. The volatility of commodity prices may have a significant impact on the gain or loss in any given period. For more information on fair value sensitivity and a discussion of the market risk of pricing changes, see Item 7A, Quantitative and Qualitative Disclosures about Market Risk.

Energy-related contracts that are not accounted for pursuant to Statement 133 are no longer carried at fair value, but are accounted for on an accrual basis as executory contracts. Energy trading inventories carried under storage agreements are no longer carried at fair value, but are carried at the lower of cost or market. Changes to the accounting for existing contracts as a result of the rescission of Emerging Issues Task Force Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10) were reported as a cumulative effect of a change in accounting principle on January 1, 2003. This resulted in a cumulative effect loss, net of tax, of $141.8 million.

Regulation - Our intrastate transmission pipelines and distribution operations are subject to the rate regulation and accounting requirements of the OCC, KCC, TRC and various municipalities in Texas. Certain of our other transportation activities are subject to regulation by the FERC. ONG, KGS, TGS and portions of the Transportation and Storage segment follow the accounting and reporting guidance contained in Statement 71. During the rate-making process, regulatory authorities 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. Accordingly, actions of the regulatory authorities could have an affect on the amount recovered from rate payers. Any difference in the amount recoverable and the amount deferred would be recorded as income or expense at the time of the regulatory action. If all or a portion of the regulated operations becomes no longer subject to the provision of Statement 71, a write-off of regulatory assets and stranded costs may be required. At December 31, 2003, our regulatory assets totaled $213.9 million.

Impairment of Goodwill and Long-Lived Assets - We assess our goodwill for impairment at least annually based on Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (Statement 142). An initial assessment is made by comparing the fair value of the operations with goodwill, as determined in accordance with Statement 142, to the book value. If the fair value is less than the book value, an impairment is indicated and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the operations with goodwill from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill, an impairment charge is recorded. See Note F of the Notes to Consolidated Financial Statements in this Form 10-K.

We assess our long-lived assets for impairment based on Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144). A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair values are based on sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.

Examples of long-lived asset impairment indicators include:

Pension and Postretirement Employee Benefits - We have a defined pension plan covering substantially all full-time employees and a postretirement employee benefits plan covering most employees. Our actuarial consultant, in calculating

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the expense and liability related to these plans, uses statistical and other factors that attempt to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and employment periods. In determining the projected benefit obligations and the costs, assumptions can change from period to period and result in material changes in the costs and liabilities we recognize. See Note L of the Notes to Consolidated Financial Statements in this Form 10-K.

Contingencies - Our accounting for contingencies covers a variety of business activities including contingencies for potentially uncollectible receivables, legal exposures and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies”. We base our estimates on currently available facts and our estimates of the ultimate outcome or resolution. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings.

For further discussion of our accounting policies, see Note A of the Notes to Consolidated Financial Statements in this Form 10-K.

Consolidated Operations

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

Operating Results - Changes in commodity prices can have a significant impact on our earnings, particularly in the Gathering and Processing segment. Volatility in prices, such as we experienced during the early part of 2003 due to the extremely cold weather, provides the opportunity for increased margins in our Marketing and Trading segment. Net revenues from continuing operations increased in 2003 compared to 2002 primarily due to:

Net revenues from continuing operations increased in 2002 compared to 2001 primarily due to the:

Operating costs and depreciation, depletion and amortization increased in 2003 compared to 2002 primarily due to:

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Operating costs and depreciation, depletion and amortization increased in 2002 compared to 2001 primarily due to:

The following tables show the components of other income and other expense for each of the years ended December 31, 2003, 2002 and 2001.

More information regarding our results of operations is provided in the discussion of each segment’s results. The discontinued component is discussed in the Production segment section and the cumulative effect of a change in accounting principle is discussed in the Marketing and Trading segment section.

Key Performance Indicators - Key performance indicators reviewed by management include:

For the year ended December 31, 2003, our basic and diluted earnings per share from continuing operations is $2.38 and $2.13, respectively, representing an 81.7 percent and 63.8 percent increase in basic and diluted earnings per share from continuing operations compared to 2002. Return on invested capital is 16.7 percent in 2003 compared to 13.0 percent in 2002.

To evaluate shareholder appreciation, we compare ourselves to a group of 20 peer companies. For the year ended December 31, 2003, we ranked in the top 35^th percentile in shareholder appreciation compared to our peers.

Production

Overview - Our Production segment currently owns, develops and produces natural gas and oil reserves in Oklahoma and Texas. We focus on development activities rather than exploratory drilling.

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As a result of our growth strategy through acquisitions and developmental drilling, the number of wells we operate increases as we grow our reserves. In our role as operator, we control operating decisions that impact production volumes and lifting costs. We continually focus on reducing finding costs and minimizing production costs.

Acquisitions and Divestitures - The following acquisitions and divestitures are discussed beginning on page 26:

Development Activities - Through our developmental drilling program we participated in drilling 20 wells in 2003, which included 19 producing gas wells and one dry hole.

Selected Financial and Operating Information - The following tables set forth certain selected financial and operating information for the Production segment for the periods indicated.

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All proved undeveloped reserves are attributed to locations directly offsetting (adjacent to) productive units.

Operating Results - Net revenues from continuing operations increased in 2003 compared to 2002 due to higher realized oil and gas prices which include the impact of hedging gains and losses.

We experienced higher gas production from continuing operations in 2003 compared to 2002, reflecting a partial month of production on the acquired properties. Normal production declines on our gas wells were offset by the production from new wells drilled. Lower oil production in 2003 compared to 2002 resulted from normal production declines on existing wells as well as no new drilling and minimal acquisition of new wells.

Operating costs from continuing operations are higher in 2003 compared to 2002, reflecting:

Depreciation, depletion and amortization for continuing operations declined in 2003 compared to 2002 due primarily to a lower depletion rate.

With respect to retained properties, the Production segment added 15 Bcfe of net natural gas and oil reserves in 2003 from drilling activities. This included 9.9 Bcfe of proved developed reserves, comprised of 6.6 Bcfe of proved developed producing and 3.3 Bcfe of proved non-producing. Production for 2003, including acquired properties for the period owned, was 9.1 Bcfe. Ten days of production for the acquired properties in Texas are included in 2003.

Net revenues from continuing operations decreased in 2002 compared to 2001 due to:

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Depreciation, depletion and amortization for continuing operations increased in 2002 compared to 2001 due primarily to a higher depletion rate.

In 2001, other income, net, primarily represents the gain from the sale of our 40 percent interest in K. Stewart.

Discontinued Component - Income from the discontinued component is significantly lower in 2003 compared to 2002 since the properties produced only one month in 2003 before they were sold. Lower gas prices received resulted in income from the discontinued component being lower in 2002 compared to 2001.

Natural gas and oil reserve additions for the discontinued component totaled 11.8 Bcfe of net reserves in 2002. This included 9.9 Bcfe of proved developed reserves, comprised of 8.3 Bcfe of proved developed producing and 1.6 Bcfe of proved non-producing. Other adjustments, primarily revisions of prior estimates, reduced the year-end reserves for the discontinued component by an additional 24.1 Bcfe. Production for the year ended December 31, 2002 for the discontinued component was 19.5 Bcfe.

Capital Expenditures - Capital expenditures primarily relate to our developmental drilling program. Production from existing wells naturally declines over time and additional drilling for existing wells is necessary to maintain or enhance production from existing reserves. Capital expenditures related to our drilling program for continuing operations were approximately $18.3 million, $15.3 million, and $19.2 million in 2003, 2002, and 2001, respectively. Capital expenditures related to our drilling program for the discontinued component were $19.8 million and $34.0 million in 2002 and 2001, respectively.

Risk Management - The volatility of energy prices has a significant impact on the profitability of this segment. We utilized derivative instruments in 2003 in order to hedge anticipated sales of natural gas and oil production. The realized financial impact of the derivative transactions is included in net revenues. For 2003, we hedged approximately 78 percent of our natural gas production at an average net price at the wellhead of $4.50 per MMBtu, and 79 percent of our oil production at a fixed NYMEX price of $27.25 per Bbl. At December 31, 2003, we have hedged approximately 89 percent of our anticipated 2004 natural gas production and 89 percent of our anticipated 2004 oil production. The weighted average wellhead price for gas hedges is $5.28 per MMBtu, and the net oil hedge NYMEX price is $30.35 per Bbl. See Item 7A, Quantitative and Qualitative Disclosures About Market Risk and Note D of the Notes to Consolidated Financial Statements in this Form 10-K.

Gathering and Processing

Overview - The Gathering and Processing segment is engaged in the gathering, processing and marketing of natural gas and the fractionation, storage and marketing of NGLs. Our Gathering and Processing segment has a processing capacity of approximately 2.0 Bcf/d, of which approximately 0.2 Bcf/d is currently idle. Our Gathering and Processing segment owns approximately 13,800 miles of gathering pipelines that supply our gas processing plants.

Strategy - The price of natural gas relative to the price of NGLs can be an important factor in determining the profitability of processing gas and extracting its various liquid components. We have been successful in amending contracts covering about 10 to 15 percent of the volume associated with our “keep whole” contracts to allow us to charge conditioning fees for processing when the price of natural gas relative to NGLs becomes too high. This change helps mitigate the impact of unfavorable spreads between the two commodities. Our effort to add this conditioning language began in 2002 and remains a strategy that we continue to pursue today. Our goal is to have this conditioning language in contracts covering 75 percent of our “keep whole” volumes within five years. We are also continuing the strategy of restructuring unprofitable gas purchase and gathering contracts.

Additionally, we are able to modify plant operations to take advantage of market conditions. By changing operations such as rerouting gas around or through the plant or changing the temperatures and pressures at which the gas is processed, we can produce more of the specific commodities that have the most favorable pricing condition. These strategies are intended to increase the stability of our net revenues.

Acquisitions and Divestitures - The following acquisitions and divestitures are described beginning on page 26: