UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2003.

OR

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

For the transition period from              to             .

Commission file number 001-13643

ONEOK, Inc.

(Exact name of registrant as specified in its charter)

Oklahoma	73-1520922
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
100 West Fifth Street, Tulsa, OK	74103
(Address of principal executive offices)	(Zip Code)

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

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

Common stock, par value of $0.01	New York Stock Exchange
8.5% Equity Units	New York Stock Exchange
(Title of Each Class)	(Name of Each Exchange on which Registered)

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

None

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

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

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:

Documents	Part of Form 10-K
Portions of the definitive proxy statement to be delivered to shareholders in connection with the Annual Meeting of Shareholders to be held May 20, 2004.	Part III

ONEOK, Inc.

2003 ANNUAL REPORT ON FORM 10-K

		Page No.
Part I.
Item 1.	Business	3-16
Item 2.	Properties	17-20
Item 3.	Legal Proceedings	21-22
Item 4.	Results of Votes of Security Holders	22
Part II.
Item 5.	Market Price and Dividends on the Registrant’s Common Stock and Related Shareholder Matters	23-24
Item 6.	Selected Financial Data	24-25
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25-51
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	52-53
Item 8.	Financial Statements and Supplementary Data	54-104
Item 9.	Changes in and Disagreements with Accountants On Accounting and Financial Disclosures	104
Item 9A.	Controls and Procedures	104-105
Part III.
Item 10.	Directors, Executive Officers, Promoters, and Control Persons of the Registrant	106
Item 11.	Executive Compensation	106
Item 12.	Security Ownership of Certain Beneficial Owners and Management	106
Item 13.	Certain Relationships and Related Transactions	106
Item 14.	Principal Accountant’s Fees and Services	106
Part IV.
Item 15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K	107-112
Signatures		113

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

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PART I.

ITEM 1. BUSINESS

General

ONEOK, Inc., an Oklahoma corporation, was organized on May 16, 1997. On November 26, 1997, we acquired the natural gas business of Westar Energy, 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:

Bbl	42 United States (U.S.) gallons, the basic unit for measuring crude oil and natural gas condensate
MBbls	One thousand barrels
MBbls/d	One thousand barrels per day
MMBbls	One million barrels
Btu	British thermal unit - a measure of the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit
MMBtu	One million British thermal units
MMMBtu/d	One billion British thermal units per day
Mcf	One thousand cubic feet of gas
MMcf	One million cubic feet of gas
MMcf/d	One million cubic feet of gas per day
Mcfe	Mcf equivalent, whereby barrels of oil are converted to Mcf using six Mcfs of natural gas to one barrel of oil
Bcf	One billion cubic feet of gas
Bcf/d	One billion cubic feet of gas per day
Bcfe	Bcf equivalent, whereby barrels of oil are converted to Bcf using six Bcfs of natural gas to one million barrels of oil
NGLs	Natural gas liquids
Mwh	Megawatt hour

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.

Union	Employees	Contract Expires
United Steelworkers of America	451	July 31, 2004
International Union of Operating Engineers	15	July 31, 2004
Gas Workers Metal Trades of the United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada	10	July 31, 2004
International Brotherhood of Electrical Workers	351	June 30, 2006

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

• Gathering and Processing

• Transportation and Storage

• Distribution

• Marketing and Trading

• Other

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:

• purchased gas and oil properties and related flow lines from a partnership owned by Wagner & Brown, Ltd. in December 2003

• sold natural gas and oil producing properties in January 2003

• sold our 40 percent interest in K. Stewart in June 2001

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:

• signed an agreement to acquire a 22.5 percent partnership interest in a Texas general partnership, which owns a natural gas liquids fractionation facility in Mont Belvieu, Texas, and is expected to close in April 2004

• acquired a retail propane business as part of the purchase of our Texas assets in January 2003

• acquired NGL storage and pipeline facilities located in Conway, Kansas in December 2003

• sold three natural gas processing plants and related gathering assets along with our interest in a fourth natural gas processing plant in December 2002

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:

• sold transmission and gathering pipelines and compression in March 2004

• sold Texas transmission assets in October 2003

• sold our property rights in Sayre in December 2002

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:

• acquired the gas distribution system at the United States Army’s Fort Bliss in El Paso, Texas in August 2003

• acquired a pipeline system that extends through the Rio Grande Valley region in Texas in August 2003

• acquired Texas gas distribution assets in January 2003

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:

• On November 12, 2003, TGS filed an appeal with the TRC based on the denial of proposed rate increases by the cities of Port Neches, Nederland and Groves, Texas. The proposed rate increases were implemented in May 2003, subject to refund, resulting in an annual revenue increase of approximately $0.8 million. The TRC is expected to rule by July 2004.

• On October 10, 2003, ONG filed an application with the OCC requesting that it be allowed to recover costs incurred since 2000 when ONG assumed responsibility for its customers’ service lines and enhanced its efforts to protect pipelines from corrosion. ONG also sought to recover costs related to its investment in gas in storage and rising levels of fuel-related bad debts. The application sought a total of $24 million in additional annual revenue. On January 30, 2004, the OCC approved a plan allowing ONG to increase its annual rates by $17.7 million. The plan authorizes the new rates to be in effect for a maximum of 18 months and categorizes $10.7 million of the annual additional revenues as interim and subject to refund until a final determination at the ONG’s next general rate case. Approximately $7.0 million annually is considered final and not subject to refund. The estimated annual impact on operating income is $13.6 million. ONG has committed to filing for a general rate review no later than January 31, 2005.

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.

• On September 17, 2003, the KCC issued an order approving a $45 million rate increase for our Kansas customers pursuant to the stipulated settlement agreement with KGS. The order settled the rate case filed by KGS in January 2003 and allowed KGS to begin operating under the new rate schedules effective September 22, 2003. After

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amortization of previously deferred costs, it is estimated that operating income will increase by approximately $29.6 million annually.

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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Name and Position	Age	Business Experience in Past Five Years
David L. Kyle Chairman of the Board, President and Chief Executive Officer	51	2000 to present 1997 to 2000 1995 to present	Chairman of the Board of Directors, President and Chief Executive Officer President and Chief Operating Officer Member of the Board of Directors
Jim Kneale Senior Vice President, Treasurer and Chief Financial Officer	52	2001 to present 1999 to 2000 1997 to 1999	Senior Vice President, Treasurer and Chief Financial Officer Vice President, Treasurer and Chief Financial Officer President, Oklahoma Natural Gas Company
John A. Gaberino, Jr. Senior Vice President, General Counsel, and Assistant Secretary	62	1998 to present 2001 to 2003 1994 to 1998	Senior Vice President and General Counsel Corporate Secretary Stockholder, Officer and Director, Gable & Gotwals
Edmund J. Farrell Senior Vice President - Administration	60	2001 to present 1999 to 2001 1997 to 1999	Senior Vice President - Administration President, Oklahoma Natural Gas Company Vice President, ONEOK Gas Marketing Company
D. Lamar Miller Senior Vice President - Financial Services	44	2003 to present 2000 to 2003 1998 to 2000 1997 to 1998	Senior Vice President - Financial Services Vice President - Risk Control Vice President, Chief Financial and Risk Officer, Entergy Power Marketing Corp. and Entergy Trading and Marketing, PLC Vice President and Controller, Duke Energy Trading and Marketing LLC.
John W. Gibson President - Energy	51	2000 to present 1995 to 2000	President - Energy (1) Executive Vice President, Koch Energy, Inc.; President, Koch Midstream Services; President, Koch Gateway Pipeline Company
Christopher R Skoog President, ONEOK Energy Marketing and Trading Company II	40	1999 to present 1995 to 1999	President, ONEOK Energy Marketing and Trading Company II Vice President, ONEOK Gas Marketing Company
J.D. Holbird President, ONEOK Energy Resources Company	54	2003 to present 1999 to 2003 1997 to 1999	President, ONEOK Energy Resources Company President, ONEOK Resources Company Vice President, ONEOK Resources Company
Phyllis Worley President, Kansas Gas Service Company	53	2002 to present 2002 to 2002 2001 to 2002 1999 to 2001 1997 to 1999	President, Kansas Gas Service Company Vice President - Administration, Oklahoma Natural Gas Company Vice President - Western Region, Kansas Gas Service Company Vice President - Southern Region, Kansas Gas Service Company Director - Southern Region, Kansas Gas Service Company
Samuel Combs, III President, Oklahoma Natural Gas Company	46	2001 to present 1999 to 2001 1996 to 1999	President, Oklahoma Natural Gas Company Vice President - Western Region, Oklahoma Natural Gas Company Vice President - Oklahoma City District, Oklahoma Natural Gas Company
Roger N. Mitchell President, Texas Gas Service Company	52	2002 to present 2001 to 2002 1997 to 2001	President, Texas Gas Service Company Vice President - Eastern Region, Oklahoma Natural Gas Company Manager, Communications and Advertising
Curtis L. Dinan Vice President and Chief Accounting Officer	36	2004 to present 2002 to 2004 1997 to 2002	Vice President and Chief Accounting Officer Assurance and Business Advisory Partner, Grant Thornton, LLP Assurance and Business Advisory Partner, Arthur Andersen, LLP; Assurance Business Advisory Senior Manager, Arthur Andersen, LLP; Assurance and Business Advisory Experienced Manager, Arthur Andersen, LLP
Beverly Monnet Vice President and Controller	45	2004 to present 2001 to 2004 1997 to 2001	Vice President and Controller Vice President, Controller and Chief Accounting Officer Manager of Accounting, ONEOK Resources Company

(1) The Energy group includes the Gathering and Processing and Transportation and Storage segments.

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

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ITEM 2. PROPERTIES

DESCRIPTION OF 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.

	Years Ended December 31,
Sales	2003	2002	2001
Continuing operations
Oil (MBbls)	265.0	273.0	261.0
Gas (MMcf)	7,486.0	7,370.0	8,000.0
Discontinued component
Oil (MBbls)	53.0	241.0	231.6
Gas (MMcf)	1,472.0	18,036.0	19,578.4

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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.

	Years Ended December 31,
	2003		2002		2001
Average Sales Price (a)
Continuing operations
Per Bbl of oil	$	27.25	$	24.37	$	23.88
Per Mcf of gas	$	4.78	$	3.49	$	3.95
Discontinued component
Per Bbl of oil	$	32.28	$	25.00	$	25.99
Per Mcf of gas	$	4.10	$	3.19	$	3.89
Average Production Costs (b)
Continuing operations
Per Mcfe	$	0.90	$	0.68	$	0.68
Discontinued component
Per Mcfe	$	0.66	$	0.67	$	0.68

(a) In determining the average sales price of oil and gas, sales to affiliates were recorded on the same basis as sales to unaffiliated customers. The average sales price, above, reflects the impact of hedging activities. The effect of natural gas hedges on the combined continuing operations and discontinued component average sales price is as follows: Year ended December 31, 2003, decrease by $0.30 per Mcf; Year ended December 31, 2002, increase by $0.25 per Mcf; Year ended December 31, 2001, decrease by $0.45 per Mcf. The effect of oil hedges on the combined continuing operations and discontinued component average sales price is as follows: Year ended December 31, 2003, decrease by $3.10 per Bbl. There were no oil hedges in place for 2002 or 2001.

(b) For the purpose of calculating the average production costs per Mcf equivalent, barrels of oil were converted to Mcf using six Mcfs of natural gas to one barrel of oil. Production costs, which include production taxes, are based on the combined wellhead market price of both continuing operations and the discontinued component, which averaged $30.88 per Bbl of oil and $5.18 per Mcf of gas in 2003, $24.65 per Bbl of oil and $3.02 per Mcf of gas in 2002, and $24.89 per Bbl of oil and $4.33 per Mcf of gas in 2001, instead of the weighted average price, net of hedges. Since oil is such a low percentage of our product mix, production costs are presented on an Mcfe basis rather than an Mcf and Bbl basis. The production tax component of the historical production cost, including both continuing operations and the discontinued component, per equivalent unit is as follows: Year ended December 31, 2003, $0.31 per Mcfe; Year ended December 31, 2002, $0.21 per Mcfe; Year ended December 31, 2001, $0.28 per Mcfe.

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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.

	Gas	Oil
Continuing operations
Gross wells	839	69
Net wells	348	33

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.

	Gross	Net
Oklahoma	18,517.0	10,007.4
Texas	876.6	436.1
Total	19,393.6	10,443.5

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.

	Years Ended December 31,
	2003	2002	2001
Development
Continuing operations
Productive	6.0	8.8	11.9
Dry	0.1	—	0.6
Discontinued component
Productive	—	12.0	17.7
Dry	—	—	—
Total	6.1	20.8	30.2

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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ITEM 3. LEGAL PROCEEDINGS

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.

ITEM 4. RESULTS OF VOTES OF SECURITY HOLDERS

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

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PART II.

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

Market Information and Holders

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

	Year Ended December 31, 2003				Year Ended December 31, 2002
	High		Low		High		Low
First Quarter	$	20.20	$	16.00	$	20.92	$	16.35
Second Quarter	$	20.99	$	18.14	$	23.13	$	19.71
Third Quarter	$	21.68	$	18.75	$	22.18	$	14.65
Fourth Quarter	$	22.44	$	19.20	$	19.71	$	17.43

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.

	Years Ended December 31,
	2003		2002
First Quarter	$	0.170	$	0.155
Second Quarter	$	0.170	$	0.155
Third Quarter	$	0.170	$	0.155
Fourth Quarter	$	0.180	$	0.155

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.

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a)	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)		Number of Securities Remaining Available For Future Issuance Under Equity Compensation Plans (Excluding Securities in Column (a)) (c)
Equity compensation plans approved by security holders (1)	3,607,349	$18.47		7,599,483	(4)
Equity compensation plans not approved by security holders (2)	293,231	$19.73	(3)	450,000	(4)
Total	3,900,580	$18.56		8,049,483

(1) Includes our stock options, restricted stock awards and performance share awards granted under our Long-Term Incentive Plan. For a brief description of the material features of this plan, see Note R of the Notes to Consolidated Financial Statements.

(2) Includes our Employee Non-Qualified Deferred Compensation Plan, the Deferred Compensation Plan for Non-Employee Directors and the Stock Compensation Plan for Non-Employee Directors. For a brief description of the material features of these plans, see Note R of the Notes to Consolidated Financial Statements.

(3) Compensation deferred into our common stock under our Employee Non-Qualified Deferred Compensation Plan and Deferred Compensation Plan for Non-Employee Directors is distributed to participants at fair market value on the date of distribution. The price used in the table is $22.08, which represents the price of our common stock at December 31, 2003.

(4) Securities reserved for future issuance under our Deferred Compensation Plan for Non-Employee Directors are included in shares reserved for issuance under our Long-Term Incentive Plan, which is reflected in the table as an equity compensation plan approved by security holders.

ITEM 6. SELECTED FINANCIAL DATA

In accordance with a pronouncement of the Financial Accounting Standards Board’s Staff at the Emerging Issues Task Force meeting in April 2001, codified as EITF Topic No. D-95 (Topic D-95), we revised our computation of earnings per common share (EPS). We restated the EPS amounts for all periods to be consistent with the revised methodology and to give effect 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.

	Years Ended December 31,												Year Ended August 31,
	2003			2002			2001			2000			1999
	(Millions of Dollars, except per share amounts)
Net revenues from continuing operations	$	1,136.5		$	975.7		$	826.4		$	745.7		$	571.0
Operating income from continuing operations	$	446.1		$	371.5		$	255.6		$	324.5		$	203.9
Income from continuing operations	$	214.3		$	156.0		$	78.8		$	137.7		$	99.1
Income from operations of discontinued component	$	2.3		$	10.6		$	24.9		$	5.8		$	7.3
Assets from discontinued component	$	—		$	225.3		$	227.9		$	215.5		$	223.1
Total assets	$	6,341.0		$	5,809.6		$	5,853.3		$	7,360.3		$	3,024.9
Long-term debt	$	1,830.9		$	1,442.0		$	1,744.2		$	1,350.7		$	837.0
Total basic earnings per share	$	1.48		$	1.40		$	0.85		$	1.23		$	0.86
Total diluted earnings per share	$	1.22		$	1.39		$	0.85		$	1.23		$	0.86
Dividends per common share	$	0.69		$	0.62		$	0.62		$	0.62		$	0.62
Percent of payout		56.6	%		44.6	%		72.9	%		50.4	%		72.1	%
Ratio of earnings to fixed charges		4.02x			3.24x			1.74x			2.80x			3.89x
Ratio of earnings to combined fixed charges and preferred stock dividend requirements		3.02x			2.12x			1.24x			1.88x			1.85x

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

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:

• significant and long-term declines in commodity prices

• a major accident affecting the use of an asset

• part or all of a regulated business no longer operating under Statement 71

• a significant decrease in the rate of return for a regulated business

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.

	Years Ended December 31,
	2003			2002		2001
	(Thousands of Dollars)
Financial Results
Operating revenues, excluding energy trading revenues	$	2,769,214		$	1,894,851	$	1,814,180
Energy trading revenues, net		229,782			209,429		101,761
Cost of gas		1,862,518			1,128,620		1,089,566
Net revenues		1,136,478			975,660		826,375
Operating costs		529,553			456,339		437,233
Depreciation, depletion, and amortization		160,861			147,843		133,533
Operating income	$	446,064		$	371,478	$	255,609
Other income	$	8,164		$	12,426	$	9,852
Other expense	$	5,224		$	19,038	$	8,976
Discontinued operations, net of taxes (Note C)
Income from discontinued component	$	2,342		$	10,648	$	24,879
Gain on sale of discontinued component	$	39,739		$	—	$	—
Cumulative effect of a change in accounting principle, net of tax	$	(143,885	)	$	—	$	(2,151	)

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:

• higher prices of natural gas, NGLs and crude oil

• contract restructuring in gathering and processing

• addition of our Texas gas distribution business

• implementation of KGS’ new rate schedule in September 2003

• effective utilization of storage and transport capacity to capture daily price volatility

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

• OCC actions including a $34.6 million charge to cost of gas in 2001 and a $14.2 million reduction in cost of gas in 2002

• sale of the Enron bankruptcy claim in 2002 which increased net revenues by $10.4 million compared to the $37.4 million charge for the bankruptcy claim that was recorded in 2001

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

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• additional costs of operating our Texas gas distribution business and the additional assets acquired with that business

• higher bad debt expenses due to higher prices

• increased employee and administrative costs

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

• additional costs associated with the operation of the NGL pipeline facilities which we leased at the end of 2001

• settlement of legal proceedings

• increased employee costs

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

	Years Ended December 31,
	2003			2002		2001
	(Thousands of Dollars)
Interest income	$	2,961		$	1,304	$	2,195
Coli		2,559			—		—
Partnership income		1,489			365		6,442
Gains on sale of property		292			10,485		1,159
Other		863			272		56
Other Income	$	8,164		$	12,426	$	9,852
	Years Ended December 31,
	2003			2002		2001
	(Thousands of Dollars)
Donations, civic, and governmental	$	6,829		$	6,180	$	1,234
Legal fees and penalties		3,046			104		1,897
Accrual of CFTC settlement		3,000			—		—
Terminated acquisition expense		175			621		266
Coli		—			1,304		998
Southwest litigation, net		(8,552	)		10,049		4,554
Other		726			780		27
Other Expense	$	5,224		$	19,038	$	8,976

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:

• earnings per share

• return on invested capital

• shareholder appreciation

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:

• purchased gas and oil properties and related flow lines from a partnership owned by Wagner & Brown, Ltd. in December 2003

• sold natural gas and oil producing properties in January 2003

• sold our 40 percent interest in K. Stewart in June 2001

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.

	Years Ended December 31,
	2003		2002			2001
	(Thousands of Dollars)
Financial Results of Continuing Operations
Natural gas sales	$	35,818	$	25,693		$	31,628
Oil sales		7,221		6,654			6,232
Other revenues		949		107			47
Net revenues		43,988		32,454			37,907
Operating costs		15,812		8,332			8,351
Depreciation, depletion, and amortization		12,070		13,842			11,240
Operating income	$	16,106	$	10,280		$	18,316
Other income (expense), net	$	10	$	(178	)	$	1,175
Discontinued operations, net of taxes (Note C)
Income from discontinued component	$	2,342	$	10,648		$	24,879
Gain on sale of discontinued component	$	39,739	$	—		$	—
Cumulative effect of a change in accounting principle, net of tax	$	117	$	—		$	(2,151	)

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	Years Ended December 31,
	2003		2002		2001
Operating Information and Financial Statistics
Proved reserves
Continuing operations
Gas (MMcf)		221,119		61,748		67,582
Oil (MBbls)		4,127		2,461		2,394
Discontinued component
Gas (MMcf)		—		177,828		165,385
Oil (MBbls)		—		2,787		2,117
Production
Continuing operations
Gas (MMcf)		7,486		7,370		8,000
Oil (MBbls)		265		273		261
Discontinued component
Gas (MMcf)		1,472		18,036		19,578
Oil (MBbls)		53		241		232
Average realized price (a)
Continuing operations
Gas ($/Mcf)	$	4.78	$	3.49	$	3.95
Oil ($/Bbls)	$	27.25	$	24.37	$	23.88
Discontinued component
Gas ($/Mcf)	$	4.10	$	3.19	$	3.89
Oil ($/Bbls)	$	32.28	$	25.00	$	25.99
Capital expenditures (thousands)
Continuing operations	$	18,655	$	17,810	$	20,429
Discontinued component	$	—	$	21,824	$	35,545

(a) The average realized price reflects the impact of hedging activities.

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:

• higher production taxes that were the result of higher prices

• higher well operating costs due to maintenance and workovers

• higher administrative costs

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:

• lower realized gas prices which include the impact of hedging gains and losses

• lower gas production volumes

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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:

• signed an agreement to acquire a 22.5 percent partnership interest in a Texas general partnership, which owns a natural gas liquids fractionation facility in Mont Belvieu, Texas, and is expected to close in April 2004

• acquired a retail propane business as part of the purchase of our Texas assets in January 2003

• acquired NGL storage and pipeline facilities located in Conway, Kansas in December 2003

• sold three natural gas processing plants and related gathering assets along with our interest in a fourth natural gas processing plant in December 2002

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

	Years Ended December 31,
	2003			2002			2001
	(Thousands of Dollars)
Financial Results
Natural gas liquids and condensate sales	$	1,041,764		$	654,930		$	587,842
Gas sales		640,499			380,095			635,569
Gathering, compression, dehydration and processing fees and other revenues		96,254			98,196			91,406
Cost of sales		1,564,380			938,843			1,125,196
Net revenues		214,137			194,378			189,621
Operating costs		122,103			127,747			116,853
Depreciation, depletion, and amortization		29,332			33,523			29,201
Operating income	$	62,702		$	33,108		$	43,567
Other income (expense), net	$	(194	)	$	(1,119	)	$	(178	)
Cumulative effect of a change in accounting principle, net of tax	$	(1,375	)	$	—		$	—

	Years Ended December 31,
	2003		2002		2001
Operating and Financial Statistics
Total gas gathered (MMMBtu/d)		1,171		1,205		1,331
Total gas processed (MMMBtu/d)		1,209		1,411		1,420
Natural gas liquids sales (MBbls/d)		114		95		76
Natural gas liquids produced (MBbls/d)		59		73		74
Gas sales (MMMBtu/d)		330		343		391
Capital expenditures (thousands)	$	20,598	$	43,101	$	51,442
Conway OPIS composite NGL Price ($/gal)
(based on our NGL product mix)	$	0.59	$	0.41	$	0.48
Average NYMEX crude oil price ($/Bbl)	$	30.98	$	25.41	$	26.60
Average natural gas price ($/MMBtu) (mid-continent region)	$	5.06	$	3.00	$	4.16

Operating Results - For 2003 compared to 2002, increased prices for NGLs, natural gas and crude oil contributed to increases in:

• natural gas liquids and condensate sales revenues

• gas sales

• cost of sales

• net revenues

The increased prices positively impacted net revenues by $32.6 million for 2003 compared to 2002. Our contractual restructuring efforts and our new Texas propane business also added about $16.7 million and $2.7 million, respectively, to 2003 net revenues. These net revenue increases were partially offset by the decrease of $19.4 million that resulted from the sale of the Oklahoma processing plant and gathering assets in the fourth quarter of 2002 and an approximate $9.5 million decrease that was the result of lower gas and NGL volumes processed in 2003. The volume decreases resulted primarily from natural well declines.

The decreases in operating costs for 2003 resulted primarily from the:

• $6 million reduction in expense due to the sale of the Oklahoma processing plant and gathering assets in December 2002

• $5.1 million reduction in bad debt expenses

These decreases were partially offset by increases in various other expenses including $2.9 million in additional costs for the operation of our Texas retail propane business.

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The decrease in depreciation, depletion and amortization for 2003 is primarily due to the $2.8 million depreciation expense reduction associated with owning fewer assets following the sale of a portion of our Oklahoma assets in 2002, partially offset by an increase of approximately $1 million that resulted from our normal 2003 capital expenditure program and the acquisition of our Texas retail propane assets. Additionally, 2002 depreciation expense included a $2.4 million loss taken in the third quarter associated with the sale of a portion of our Oklahoma assets.

An additional loss of $1.3 million was taken when the Oklahoma asset sale was closed in December 2002 and is included in other income, net, in 2002.

For 2002 compared to 2001, prices decreased resulting in decreased sales revenues and cost of sales which negatively impacted net revenues by $6.1 million. Despite price decreases, natural gas liquids and condensate sales revenues increased, resulting in a positive net revenue impact of $2.3 million due to the additional volumes from third party NGL purchases and sales from NGL pipeline facilities that were leased at the end of 2001.

Other increases in net revenues in 2002 compared to 2001 were due to our contractual restructuring efforts and customer elections regarding processing which resulted in an increase in net revenues of $5.9 million. These increases were partially offset by gas volume losses from natural well production declines and the effects of an ice storm in the first quarter of 2002 that caused plant outages across much of Oklahoma.

The increase in operating costs in 2002 compared to 2001 is due to the:

• $4.9 million in additional costs associated with the operation of the NGL pipeline facilities which were leased at the end of 2001

• $3.6 million increase primarily in bad debt expense

• $2.3 million higher employee costs

The increase in depreciation expense in 2002 compared to 2001 is primarily the result of the $2.4 million loss taken in the third quarter of 2002 relating to the sale of the Oklahoma processing plant and gathering assets described above, and due to our on-going capital expenditure program.

Risk Management - We used derivative instruments during 2003 and 2002 to minimize risk associated with price volatility. The realized financial impact of the derivative transactions is included in our operating income. At December 31, 2003, no hedges were in place. At December 31, 2002, our Gathering and Processing segment had an immaterial portion of its natural gas costs and NGL production hedged. 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.

Transportation and Storage

Overview - Our Transportation and Storage segment represents our intrastate natural gas transmission pipelines, natural gas storage and nonprocessable gas gathering facilities. We own or reserve capacity in five storage facilities in Oklahoma, three in Kansas and three in Texas, with a combined working capacity of approximately 59.6 Bcf, of which 8.0 Bcf is temporarily idle.

Our intrastate transmission pipelines operate in Oklahoma, Kansas and Texas and are regulated by the OCC, KCC, and TRC, respectively. In July 2002, we transferred certain transmission assets in Kansas to our affiliated Kansas distribution company. Historical financial and statistical information has been adjusted to reflect this transfer.

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

• sold transmission and gathering pipelines and compression in March 2004

• sold Texas transmission assets in October 2003

• sold our property rights in Sayre in December 2002

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

	Years Ended December 31,
	2003			2002		2001
	(Thousands of Dollars)
Financial Results
Transportation and gathering revenues	$	102,812		$	89,349	$	102,092
Storage revenues		42,086			37,101		37,645
Gas sales and other revenues		16,401			37,784		23,326
Cost of fuel and gas		47,637			46,650		49,626
Net revenues		113,662			117,584		113,437
Operating costs		46,186			46,694		42,357
Depreciation, depletion, and amortization		16,694			17,563		17,990
Operating income	$	50,782		$	53,327	$	53,090
Other income, net	$	1,495		$	4,649	$	2,578
Cumulative effect of a change in accounting principle, net of tax	$	(645	)	$	—	$	—
	Years Ended December 31,
	2003			2002		2001
Operating and Financial Statistics
Volumes transported (MMcf)		449,261			507,972		486,866
Capital expenditures (thousands)	$	15,234		$	20,554	$	32,378
Average natural gas price ($/MMBtu) (mid-continent region)	$	5.06		$	3.00	$	4.16

Operating results - The increase in prices for natural gas for 2003 compared to 2002 contributed to increases in:

• transportation and gathering revenues

• storage revenues

• cost of fuel and gas

Prices decreased for 2002 compared to 2001 resulting in decreases in the same revenues and expenses.

Natural gas prices impact the cost of fuel and gas and the valuation of retained fuel. Accordingly, an increase in price will increase the value placed on the fuel retained as revenue for transportation, gathering and storage services. For the periods shown, we retained more fuel than we consumed in operations and, as a result, when prices increased as in 2003 compared to 2002 the effect was a positive impact on net revenues. Conversely, when prices fell as in 2002 compared to 2001, the effect was a negative impact on net revenues.

Periodically, reassessments are made related to the amount of operational inventory needed to operate our storage facilities. In 2002, we determined that some operational inventory at a number of our facilities could be reduced without affecting the operating capacity. As a result of this reassessment, we sold 7.2 Bcf of our operational inventory in 2002 which allowed us to increase our storage capacity available in 2003.

The sales of the operational inventory in 2002, with no comparable sales in either 2003 or 2001, offset the effect of prices on net revenues. The positive impact on net revenues for 2002 was $12.7 million. Adjustments related to the reconciliation of third party contractual storage and pipeline imbalance positions in 2002 which impacted net revenues by $8.9 million partially offset the impact of the inventory sales.

Additionally, storage revenues increased adding $1.4 million to net revenues for 2003 due to additional working capacity available as the result of improved operating conditions and additional capacity from the sales of gas inventory in 2002.

The increase in operating costs in 2002 compared to 2001 is due primarily to the:

• settlement of legal proceedings

• increased bad debt expense

• increased employee costs

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Other income, net for 2002 included a gain on the sale of storage assets in Oklahoma and transmission assets in Texas, partially offset by lower partnership income in 2002 compared to 2001.

Distribution

Overview - The Distribution segment provides natural gas distribution services in Kansas, Oklahoma and Texas. Operations in Kansas are conducted through KGS, which serves residential, commercial, industrial, transportation and wholesale customers. Operations in Oklahoma are conducted through ONG, which serves residential, commercial, industrial, wholesale and transportation customers, including customers that lease gas pipeline capacity. Operations in Texas are conducted through TGS, which serves residential, commercial, industrial, public authority and transportation customers. Our Distribution segment provides gas service to approximately 71 percent, 86 percent, and 14 percent of the distribution markets of Kansas, Oklahoma and Texas, respectively. KGS and ONG are subject to regulatory oversight by the KCC and OCC, respectively. TGS is subject to regulatory oversight by the various municipalities that it serves, which have primary jurisdiction in their respective areas. TGS’ rates in areas adjacent to the various municipalities and appellate matters are subject to regulatory oversight by the TRC.

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.

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

• acquired the gas distribution system at the United States Army’s Fort Bliss in El Paso, Texas in August 2003

• acquired a pipeline system that extends through the Rio Grande Valley region in Texas in August 2003

• acquired Texas gas distribution assets in January 2003

Selected Financial Information - The following table sets forth certain selected financial and operating information for the Distribution segment for the periods indicated.

	Years Ended December 31,
	2003			2002			2001
	(Thousands of Dollars)
Financial Results
Gas sales	$	1,640,323		$	1,140,257		$	1,434,184
Cost of gas		1,213,811			806,251			1,141,668
Gross margin		426,512			334,006			292,516
Transportation revenues		75,322			59,877			55,206
Other revenues		24,415			20,510			21,578
Net revenues		526,249			414,393			369,300
Operating costs		312,814			243,170			237,657
Depreciation, depletion, and amortization		95,654			76,063			70,359
Operating income	$	117,781		$	95,160		$	61,284
Other income (expense), net	$	(278	)	$	(3,183	)	$	(3,566	)

Operating Results - The Distribution segment’s operating results are primarily impacted by the number of customers, usage and the ability of the division to establish delivery rates that provide an authorized rate of return on the our investment and cost of service. Gas costs are passed through to distribution customers based on the actual cost of gas purchased by the respective distribution division.

Because most factors that affect gas sales also affect cost of gas by an equivalent amount, substantial swings can occur from year to year without impacting gross margin. Accordingly, it is more important to look at the factors affecting gross margin.

The increase in gross margin in 2003 compared to 2002 is primarily due to the:

• addition of TGS operations

• implementation of KGS’ new rate schedule in September 2003

These were partially offset by the $14.2 million reduction in gas costs in the second quarter of 2002 that resulted from the OCC Joint Stipulation.

37

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

• addition of TGS’ operations

• increased bad debt expense resulting from higher gas costs

• higher employee costs

The addition of TGS’ operations contributed approximately $91.0 million to gross margins, $106.7 million to net revenues and $25.1 million to operating income for 2003. Operating income also increased in 2003 compared to 2002 by approximately $9.8 million as a result of the implementation of KGS’ new rate schedule.

Gross margin for 2002 compared to 2001 increased primarily due to actions taken by the OCC related to the unusually high cost of natural gas incurred during late 2000 and early 2001. These actions, combined with our purchased gas cost recovery mechanism in Oklahoma, delayed the recovery and recognition of a portion of these high gas costs. OCC actions which impacted margins were the:

• $34.6 million charge to cost of gas in 2001 as the result of the OCC’s order limiting ONG’s recovery of gas purchase expense

• $14.2 million reduction in cost of gas in 2002 as the result of the OCC Joint Stipulation

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

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

	Years Ended December 31,
	2003		2002		2001
Operating and Financial Statistics
Average number of customers		1,990,757		1,439,657		1,436,444
Customers per employee		652		623		611
Capital expenditures (thousands)	$	153,405	$	115,569	$	133,470
	Years Ended December 31,
	2003		2002		2001
Volumes (MMcf)
Gas sales
Residential		126,794		104,267		102,976
Commercial		45,013		37,305		40,578
Industrial		3,539		3,387		4,101
Wholesale		29,823		32,082		31,060
Public Authority		2,523		—		—
Total volumes sold		207,692		177,041		178,715
PCL, ECT and Transportation		223,771		193,701		136,975
Total volumes delivered		431,463		370,742		315,690

Overall, gas volumes increased primarily as a result of the addition of our TGS customers.

Wholesale gas sales in Kansas, also known as “as available” gas sales, represent gas volumes available under contracts that exceed the needs of our residential and commercial customer base and are available for sale to other parties. Wholesale volumes decreased in 2003 as compared to 2002 due to increased volumes of gas injected into storage. Also impacting the reduction in wholesale volumes was a larger demand in the first quarter of 2003 for Kansas retail customers due to colder weather.

Public authority volumes reflect volumes used by state agencies and school districts serviced by TGS.

Transportation volumes, which include pipeline capacity leased to others and transportation for end-use customers, increased in 2003 primarily due to the addition of transportation customers acquired with TGS. Volumes also increased due to

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commercial and industrial customers moving to new transportation rates, a marketing effort to add small-usage customers, and a reduction in the minimum volume required for transport service in Oklahoma.

The residential volumes for 2002 compared to 2001 increased due to a slightly increased number of residential customers as the result of fewer customers being disconnected. Lower commercial and industrial volumes in 2002 compared to 2001 resulted from economic factors causing commercial and industrial customers to reduce their overall consumption.

Transportation volumes increased in 2002 after industrial customers returned to normal levels of transport following curtailed production in 2001 that was the result of high gas costs and the assumption of large volume customers in Kansas with the transfer of the MCMC transmission pipeline assets. Volume increases in 2002 were also due to customers moving from commercial and industrial rates to the new transport rates and a marketing effort to add small usage customers. Warmer and dryer weather also increased volumes to irrigation and gas-fired electric generation customers.

Capital expenditures - Our capital expenditure program includes expenditures for extending service to new areas, modifying customer service lines, increasing system capabilities, general replacements and improvements. It is our practice to maintain and periodically upgrade facilities to assure safe, reliable, and efficient operations. In 2003, $31.7 million of our capital expenditures were related to our Texas assets. Our capital expenditure program included $33.5 million, $18.3 million, and $22.4 million for new business development in 2003, 2002, and 2001, respectively.

Regulatory Initiatives

Oklahoma - On January 30, 2004, the OCC approved a plan allowing ONG to increase its annual rates $17.7 million in order to recover expenses related to its investment in service lines and cathodic protection, an increased level of uncollectible revenues, and a return on ONG’s investment in gas in storage. The Commission’s order also approves a modified distribution main extension policy and authorizes ONG to defer homeland security costs ONG expects to incur in the future. The plan authorizes the new rates to be in effect for a maximum of 18 months and categorizes $10.7 million of the annual additional revenues as interim and subject to refund until a final determination at ONG’s next general rate case. Approximately $7.0 million annually is considered final and not subject to refund. ONG has committed to filing for a general rate review no later than January 31, 2005.

A Joint Stipulation approved by the OCC on May 16, 2002, settled a number of outstanding ONG cases pending before the OCC. The major cases settled were the Commission’s inquiry into our gas cost procurement practices during the winter of 2000/2001, an application seeking relief from improper and excessive purchased gas costs, and enforcement action against ONG, our subsidiaries and affiliated companies. In addition, all of the open inquiries related to the annual audits of ONG’s fuel adjustment clause for 1996 to 2000 were closed as a result of this Stipulation.

The Stipulation has a $33.7 million value to ONG customers that will be realized over a three-year period. In July 2002, immediate cash savings were provided to all ONG customers in the form of billing credits totaling approximately $9.1 million. In December 2005, a final billing credit will be made to customers. The minimum amount of this credit is estimated to be approximately $2.8 million. ONG replaced certain gas contracts, which reduced gas costs by approximately $13.8 million, due to avoided reservation fees between April 2003 and October 2005. Additional savings of approximately $8.0 million from the use of storage gas are expected to occur between November 2003 and March 2005. Any expected savings from the use of storage that are not achieved will be added to the final billing credit scheduled to be provided to customers in December 2005. ONG’s operating income increased in the second quarter of 2002 by $14.2 million as a result of this settlement.

To protect against fuel procurement volatility, ONG exercised provisions contained in a number of its gas supply contracts that allow us to fix the price for a portion of its gas supply. ONG fixed the price of approximately 43 percent and 37 percent of its anticipated 2003/2004 and 2002/2003 winter gas supply deliveries, respectively.

Kansas - On September 17, 2003, the KCC issued an order approving a $45 million rate increase for our Kansas customers pursuant to the stipulated settlement agreement with KGS. The order settled the rate case filed by KGS in January 2003 and allowed KGS to begin operating under the new rate schedules effective September 22, 2003. After amortization of previously deferred costs, it is estimated that operating income will increase by approximately $29.6 million annually.

On June 16, 2003, KGS filed a motion with the KCC to extend the Kansas WeatherProof Bill program for an additional three years. However, as a result of notification that KGS’ contractor would not be able to provide sufficient support for the program, KGS was allowed by the KCC to withdraw its request on September 12, 2003. Accordingly, the Weatherproof Bill program ended effective December 1, 2003.

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In July 2002, we completed a transaction to transfer certain transmission assets in Kansas from our Transportation and Storage segment to our Distribution segment. Historical financial and statistical information have been adjusted to reflect these changes.

Texas - On November 12, 2003, TGS filed an appeal with the TRC based on the denial of proposed rate increases by the cities of Port Neches, Nederland and Groves, Texas. The proposed rate increases were implemented in May 2003, subject to refund, resulting in an annual revenue increase of approximately $0.8 million. The TRC is expected to rule by July 2004.

General - Certain costs to be recovered through the ratemaking process have been recorded as regulatory assets in accordance with Statement 71. Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria of Statement 71 and, accordingly, a write-off of regulatory assets and stranded costs may be required.

Marketing and Trading

Overview - 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, this volatility is 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.

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.

Power - 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 more volatile in the summer months. In October 2003, we signed a tolling arrangement with a third party for its power plant in Big Springs, Texas, which is connected to our gas transmission systems. The agreement, which expires in December 2005, allows us to sell the steam and power generated from the ERCOT. This agreement increases our owned or contracted power capacity from 300 to 512 megawatts.

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

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

	Years Ended December 31,
	2003			2002			2001
	(Thousands of Dollars)
Financial Results
Energy trading revenues, net	$	229,782		$	209,429		$	101,761
Power sales		91,004			71,749			28,101
Cost of power and fuel		85,378			67,646			21,234
Other revenues		961			948			1,659
Net revenues		236,369			214,480			110,287
Operating costs		33,699			27,674			32,846
Depreciation, depletion, and amortization		5,708			5,298			2,611
Operating income	$	196,962		$	181,508		$	74,830
Other income (expense), net	$	(9,272	)	$	(4,871	)	$	253
Cumulative effect of a change in accounting principle, net of tax	$	(141,982	)	$	—		$	—
	Years Ended December 31,
	2003			2002			2001
Operating and Financial Statistics
Natural gas volumes (MMcf)		1,011,530			998,537			977,602
Natural gas gross margin ($/Mcf)	$	0.17		$	0.13		$	0.10
Power volumes (MMwh)		2,086			2,228			467
Power gross margin ($/Mwh)	$	2.70		$	1.73		$	14.69
Physically settled volumes (MMcf) (a)		2,027,853			1,990,371			1,989,186
Capital expenditures (thousands)	$	555		$	2,340		$	43,486

(a) This represents the absolute value of gross transaction volumes for both buy and sell energy trading contracts that were physically settled.

Operating Results - Energy trading revenues include revenues related to marketing and trading of:

• natural gas - wholesale

• natural gas - retail

• crude oil

Included in the trading of natural gas are revenues from reservation fees and basis trades. Basis is the natural gas price differential that exists between a trading location’s price relative to the Henry Hub natural gas price. We began actively trading crude oil in this segment in the first quarter of 2002.

Net revenues increased 10 percent in 2003 over 2002, although sales volumes increased by only one percent. The increase in net revenues is attributed to the effective utilization of our storage and transport capacity to capture the increased intra-month price volatility in the first part of 2003 when daily price volatility was higher compared to the first part of 2002.

Included in our net revenues is the change in value of our derivative instruments subject to fair value accounting pursuant to Statement 133, which resulted in a gain of $38.7 million for 2003 (excluding those instruments qualifying for hedge accounting). Net revenues for 2002 and 2001 included mark-to-market earnings of approximately $42.6 million and $35.3 million respectively, which represented the change in net price risk management assets and liabilities for 2002 and 2001, resulting from the application of mark-to-market accounting on all energy contracts pursuant to EITF 98-10.

Included in 2002 and 2001 mark-to-market earnings are revenues associated with storage injections. Historically, net revenues were recognized under fair value accounting as physical natural gas inventories were injected into storage during the second and third quarters. With the rescission of EITF 98-10, natural gas inventories carried under storage agreements are no longer carried at fair value, but rather are accounted for on an accrual basis at lower of cost or market with revenues recorded when the gas is sold, typically in the first and fourth quarters.

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We also benefited by an increase in our natural gas retail operations, which expanded into Wyoming, Nebraska and Texas during 2003. Power-related margins increased due to expansion into ERCOT. The increase in our power capacity in ERCOT took place in the fourth quarter of 2003.

In the first quarter of 2002, we sold our Enron bankruptcy claim, which increased net revenues by $10.4 million. The sale was subject to normal representations as to the validity, but not collectibility, of the claims and guarantees from Enron. The claims were sold with recourse under certain conditions. Recently, Enron Corporation filed several avoidance actions against many claimants in its bankruptcy proceedings to avoid liability under various guarantees of indebtedness or obligations of Enron North America. If some or all of the Enron Corporation claims are reassigned, we would be required to refund some or all of the sales price of the Enron Corporation claims to the third party and would be responsible for enforcement of the claims in the Enron Corporation bankruptcy proceedings, which might result in an ultimate payment to us of less than our sales price of the Enron Corporation 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 Corporate bankruptcy, based on current information available to us we do not expect this matter to have a material adverse effect on us.

Operating costs were higher in 2003 compared to 2002 due to our expanded retail operations. The ad valorem tax on our storage inventory was also higher due to rate adjustments.

Other expense, net increased in 2003 compared to 2002 due to the accrual of the CFTC settlement.

Capital expenditures in 2001 consisted primarily of costs related to the construction of the electric generation plant, which was completed in mid-2001.

The significant increase in net revenues in 2002 compared to 2001 is attributable to the:

• use of storage and transport capacity to capture significant intra-month and regional price volatility

• diversification of our marketing and trading portfolio to include crude oil and natural gas liquids

• sale of the Enron bankruptcy claim in 2002 for $10.4 million, which increased net revenues compared to 2001 when the Enron bankruptcy increased gas cost by $22.9 million

Power-related margins decreased in 2002 compared to 2001, due to comparatively smaller spark spreads and reduced volatility in the Southwest Power Pool, thereby offsetting part of the increases described above.

The decrease in operating cost in 2002 compared to 2001 was due to the $14.5 million impact of the Enron-related bad debts in 2001 partially offset by increased employee costs in 2002 related to the expansion of trading, risk management, and support personnel required to operate the expanded base of marketing and trading activities.

Liquidity and Capital Resources

General - Part of our strategy is to grow through acquisitions that strengthen and complement our existing assets. We have relied primarily on operating cash flow, borrowings from commercial paper and bank lines of credit, and issuance of debt and equity in the capital markets for our liquidity and capital resource requirements. We expect to continue to use these sources for liquidity and capital resource needs on both a short and long-term basis. We also have no material guarantees of debt or other commitments to unaffiliated parties. During 2001 through 2003, our capital expenditures were financed through operating cash flows and short and long-term debt. Capital expenditures for 2003 for continuing operations were $215 million compared to $211 million in 2002.

Financing - Financing is provided through our commercial paper program, long-term debt and, as needed, through a revolving credit facility. Other options to obtain financing include, but are not limited to, issuance of equity, issuance of mandatory convertible debt securities, issuance of trust preferred securities by ONEOK Capital Trust I or ONEOK Capital Trust II, asset securitization and sale/leaseback of facilities.

In August 2002, we announced that we had completed our tender offer to purchase all of the outstanding 8.44% Senior Notes due 2004 and the 8.32% Senior Notes due 2007 for a total purchase price of approximately $65 million. The total purchase price included a premium of approximately $2.9 million and consent fees of approximately $1.8 million to purchase the notes, which are reflected in interest expense in the income statement.

In April 2002, we paid off $240 million of long-term floating rate notes that were issued in 2000.

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Credit Rating - Our credit ratings are currently an “A-” (stable outlook) by Standard and Poors and a “Baa1” (negative outlook) by Moody’s Investor Service. Our credit ratings may be affected by a material change in our financial ratios or a material adverse event affecting our business. The most common criteria for assessment of our credit rating are the debt to capital ratio, pretax and after-tax interest debt coverage and liquidity. If our credit ratings were downgraded, the interest rates on our commercial paper would increase, resulting in an increase in our cost to borrow funds. In the event that we are unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we have access to an $850 million revolving credit facility, which expires September 20, 2004. We expect the revolving credit facility to be renewed upon expiration.

Our energy marketing and trading business relies upon the investment grade rating of our senior unsecured long-term debt to satisfy credit support requirements with several counterparties. If our credit ratings declined below investment grade, our ability to participate in energy marketing and trading activity could be significantly limited. Without an investment grade rating, we would be required to fund margin requirements with the counterparties with which we have a Credit Support Annex within our International Swaps and Derivatives Association Agreements with cash, letters of credit or other negotiable instruments. At December 31, 2003, the total notional amount that could require such funding in the event of a credit rating decline to below investment grade is approximately $44.8 million.

We have reviewed our commercial paper agreement, trust indentures, building leases, equipment leases, and marketing, trading and risk contracts and no rating triggers were identified. Rating triggers are defined as provisions that would create an automatic default or acceleration of indebtedness based on a change in our credit rating. The revolving credit agreement contains a provision that would cause the cost to borrow funds to increase based on the amount borrowed under this agreement if our credit rating is negatively adjusted. The credit agreement also contains a default provision based on a material adverse change. An adverse rating change is not defined as a default or material adverse change. We currently do not have any funds borrowed under this credit agreement.

Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity price in either physical or financial energy contracts may impact our overall liquidity due to the impact the commodity price change has on items such as the cost of NGLs and gas held in storage, recoverability and timing of recovery, increased margin requirements, collectibility of certain energy-related receivables and working capital. We believe that our current commercial paper program and debt capacity are adequate to meet our liquidity requirements associated with commodity price volatility.

Pension Plan - Because the pension fund assets of $579 million in one of our pension plans exceeds the accumulated benefit obligation of $561 million for that plan, we have an asset reported on the balance sheet. Due to the poor performance of the equity market and lower interest rates, the market value of our pension fund assets has decreased and, accordingly, our pension benefit for our pension and supplemental retirement plans will decrease in 2004 from $4.4 million to $1.9 million. Should the value of our pension fund assets fall below our accumulated benefit obligation, we would eliminate the asset and record a minimum pension liability on the balance sheet with the difference flowing through other comprehensive income, net of tax. We believe we have adequate resources to fund our obligations under our pension plan.

Stock Buyback Plan - During 2001, we put in place a stock buyback plan for up to 10 percent of our capital stock. The program authorized us to make purchases of our common stock on the open market with the timing and terms of purchases and the number of shares purchased to be determined by management based on market conditions and other factors. The purchased shares were to be held in treasury and available for general corporate purposes, funding of stock-based compensation plans, and resale at a future date or retirement. This plan expired in 2002. At that time, we had not purchased any stock under the plan.

Westar - On January 9, 2003, we entered into an agreement with Westar Energy, Inc. and its wholly owned subsidiary, Westar Industries, Inc. (collectively, “Westar”), to repurchase a portion of the shares of our Series A Convertible Preferred Stock (Series A) held by Westar and to exchange Westar’s remaining shares of Series A for newly-created shares of our $0.925 Series D Non-Cumulative Convertible Preferred Stock (Series D). The Series A shares were convertible into two shares of our common stock for each share of Series A, reflecting our two-for-one stock split in 2001, and the Series D shares were convertible into one share of our common stock for each share of Series D. Some of the differences between the Series D and Series A were (a) the Series D had a fixed annual cash dividend of 92.5 cents per share, (b) the Series D was redeemable by us at any time after August 1, 2006, at a redemption price of $20, in the event that the closing price of our common stock exceeded, at any time prior to the date the notice of redemption was given, $25 for 30 consecutive trading days, (c) each share of Series D was convertible into one share of our common stock, and (d) with certain exceptions, Westar could not convert any shares of Series D held by it unless the annual per share dividend for our common stock for the previous year was greater than 92.5 cents per share and such conversion would not have subjected us to the Public Utility Holding Company Act of 1935.

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In connection with that transaction, a new rights agreement, a new shareholder agreement and a new registration rights agreement between us and Westar became effective. Our new shareholder agreement with Westar restricted Westar from selling five percent or more of our outstanding Series D and common stock (assuming conversion of all shares of Series D to be transferred), in a bona fide public underwritten offering, to any one person or to a group. The agreement allowed Westar to sell up to five percent of our outstanding Series D and common stock (assuming conversion of all shares of Series D to be transferred) to any one person or group that did not own more than five percent of our common stock (assuming conversion of all shares of Series D to be transferred).

The KCC approved our agreement with Westar on January 17, 2003. On February 5, 2003, we consummated the agreement by purchasing $300 million of our Series A from Westar. We exchanged Westar’s remaining 10.9 million Series A shares for approximately 21.8 million shares of our newly-created Series D. Upon the cash redemption of the Series A shares, the shares were converted to approximately 18.1 million shares of common stock in accordance with the terms of the Series A shares and the prior shareholder agreement with Westar. According, the redemption is reflected as an increase to common treasury stock. The Series D exchanged for the Series A was recorded at fair value and the premium over the previous carrying value of the Series A is reflected as a decrease in retained earnings. We registered all of the shares of our common stock held by Westar, as well as all the shares of our Series D issued to Westar and all of the shares of our common stock that were issuable upon conversion of the Series D.

On August 5, 2003, Westar conducted a secondary offering to the public of 9.5 million shares of our common stock at a public offering price of $19.00 per share, which resulted in gross offering proceeds to Westar of approximately $180.5 million. An over-allotment option for an additional 718,000 shares provided Westar with approximately $13.6 million. We did not receive any proceeds from the offering. Since Westar received in excess of $150 million of total proceeds from the offering, we were allowed, under a new transaction agreement related to the offering, to repurchase $50 million, or approximately 2.6 million shares, of our common stock from Westar at the public offering price of $19.00 per share. Our repurchase of those shares occurred immediately following the closing of the Westar offering. Of the shares sold in the Westar public offering, approximately 8.4 million shares represented our common stock issued by conversion of our Series D shares owned by Westar. The remaining shares consisted of approximately 1.1 million shares of our common stock owned by Westar.

On November 21, 2003, Westar sold all its remaining shares of our stock including approximately 13.4 million shares of Series D, which converted to shares of common stock when sold, and approximately 283,000 shares of common stock at a purchase price of $19.20 per share resulting in gross proceeds to Westar of approximately $262.7 million. We did not receive any proceeds from the offering.

Oklahoma Corporation Commission - The OCC staff filed an application on February 1, 2001 to review the gas procurement practices of ONG in acquiring its gas supply for the 2000/2001 heating season to determine if these procurement practices were consistent with least cost procurement practices and whether ONG’s decisions resulted in fair, just and reasonable costs to its customers. On November 20, 2001, the OCC entered an order stating that ONG was not allowed to recover the balance in ONG’s unrecovered purchased gas cost (UPGC) account related to the unrecovered gas costs from the 2000/2001 winter effective with the first billing cycle for the month following the issuance of a final order. This order halted ONG’s recovery process effective December 1, 2001. On December 12, 2001, the OCC approved a request to stay the order and allowed ONG to begin collecting unrecovered gas costs, subject to refund if ONG ultimately lost the case. In the fourth quarter of 2001, we recorded a charge of $34.6 million as a result of this OCC order. In April 2002, we, along with the staff of the Public Utility Division and the Consumer Services Division of the OCC, the Oklahoma Attorney General, and other stipulating parties filed a joint stipulation agreement proposing settlement of this and other issues. A hearing with the OCC was held in May 2002 and an order approving the settlement was issued at that time. As a result, we recorded a $14.2 million recovery in the second quarter of 2002 and have the potential of an additional $8.0 million recovery before December 2005 depending upon the potential value that could be generated by gas storage savings.

Cash Flow Analysis

Operating Cash Flows - Operating cash flows decreased by $808.2 million for the year ended December 31, 2003 compared to the same period in 2002, despite a significant increase in income from continuing operations. The primary impact on operating cash flows came from changes in working capital, much of which relates to increases in gas in storage. Weather can have a significant effect on gas inventories. November and December are typically withdrawal months providing a source of cash; however, warmer weather in November 2003 and much of December 2003 resulted in a higher level of gas remaining in storage than would normally be expected at that time of the year. The increased gas in storage, including amounts previously classified as price risk management assets, resulted in a reduction in operating cash flows of $218.1 million.

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The impact of higher commodity prices in 2003 on accounts receivables and accounts payables also negatively impacted operating cash flows. There is typically a lag between when payment is made for gas purchased for our distribution customers and when the customers are billed. This is due to the cycle billing where distribution customers are billed throughout the month. Under level prices, this lag would have no impact on cash flows from year to year, but with increased prices, as seen in 2003, this lag resulted in a negative impact on cash flows.

Deposits, or additional margin requirements, by our Marketing and Trading segment, changes in deferred income taxes, and changes in other assets and liabilities also contributed to the decrease in operating cash flows. Changes in other assets and liabilities reflect expenditures or recognition of liabilities for insurance costs, salaries, taxes other than income, and other similar items. Period-to-period fluctuations in these accounts reflect changes in the timing of payments or recognition of liabilities and are not directly impacted by seasonal factors.

We had a significant increase in earnings in 2002 compared to 2001. In addition, the changes in accounts receivable and accounts payable are primarily due to an increase in net energy trading revenues. Net energy trading revenues increased due to our use of storage and transport capacity to capture significant intra-month and regional price volatility. In 2002, we also diversified our marketing and trading portfolio to include crude oil and natural gas liquids. These increases were partially offset by decreases in accounts receivable and accounts payable due to lower natural gas prices in 2002. In addition, we had a full year of the electric generating plant operations in 2002 compared to 2001. The increase in deferred income taxes is primarily due to increased mark-to-market income in 2002 compared to 2001 and additional tax depreciation taken in 2002.

In 2001, the changes in cash flows provided by operating activities primarily reflect changes in working capital accounts, deferred income taxes, and price risk management assets and liabilities. The increase in deferred income taxes is primarily due to accelerated depreciation in 2001. The increase in price risk management assets and liabilities is primarily due to the Marketing and Trading segment’s gas in storage, which was included in price risk management assets on the consolidated balance sheet in 2001. Cash flow from operating activities was positively impacted in 2001 due to the reduction of accounts receivable, which was partially offset by increased cash used for payment of accounts payable and gas in storage as well as reduced recovery of unrecovered purchased gas costs.

Investing Cash Flows - Acquisitions in 2003 represent the cash purchase of our Texas assets and the purchase of gas and oil properties and related flow lines from a partnership owned by Wagner & Brown, Ltd. Cash provided by investing activities of the discontinued component represents the sale of natural gas and oil producing properties for a cash sales price of $294 million, including adjustments, of which $15 million was received in 2002.

Proceeds from the sale of property in 2002 include approximately $92 million related to the sale of a portion of our midstream natural gas assets to an affiliate of Mustang Fuel Corporation, a private, independent oil and gas company. Proceeds from the sale of equity investments represent the sale of our interest in MHR in 2002.

Capital expenditures in 2001 include approximately $42.3 million for the construction of the electric generating plant. In 2001, we were reimbursed by an unaffiliated company for approximately $14 million of the costs incurred to construct a pipeline in the Transportation and Storage segment. Due to regulatory treatment, this amount is recorded as a deferred credit in the balance sheet and amortized to income. We also received approximately $7.9 million related to the sale of assets by our Production segment in 2001. Acquisitions in 2001 include $14.5 million of purchase price adjustments, which resulted in an increase to goodwill, relating to acquisitions made in the previous year.

Financing Cash Flows - The following table sets forth our capitalization structure for the periods indicated.

	Years Ended December 31,
	2003		2002
Long-tem debt	60	%	53	%
Equity	40	%	47	%
Debt (including Notes payable)	67	%	57	%
Equity	33	%	43	%

In January 2003, we issued common stock and equity units, which were partially offset by the payment of notes payable and the repurchase of our Series A Convertible Preferred Stock from Westar in February 2003. In August 2003, we repurchased $50 million or approximately 2.6 million shares of our common stock from Westar. At December 31, 2003, $1.9 billion of

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long-term debt, including current maturities, was outstanding. As of that date, we could have issued $1.0 billion of additional long-term debt under the most restrictive provisions contained in our various borrowing agreements.

Both Standard and Poors (S&P) and Moody’s Investment Services consider the equity units we issued in January 2003 to be part equity and part debt. For purposes of computing capitalization ratios, these rating agencies adjust the capitalization structure. S&P considers the equity units to be equal amounts of debt and equity for the first three years, with the effect being to increase shareholders’ equity by the same amount as long-term debt, which would result in a capitalization structure of 47 percent equity and 53 percent long-term debt at December 31, 2003. Moody’s Investment Services considers 25 percent of the equity units to be long-term debt and 75 percent to be shareholders’ equity, which would result in a capitalization structure of 49 percent equity and 51 percent long-term debt at December 31, 2003.

Our $850 million revolving credit facility was renewed September 22, 2003. The new facility expires in September 2004 and includes a term-out option, which allows us to convert any outstanding borrowings under the credit agreement into a 364-day term note at the expiration of the credit agreement. This facility is primarily used to support our commercial paper program. At December 31, 2003, we had approximately $600 million of commercial paper outstanding and approximately $12 million in temporary investments. We did not have any funds outstanding under our revolving credit facility at December 31, 2003 and 2002, respectively.

In April 2001, we issued a $400 million, ten year, fixed rate note to refinance short-term debt.

On July 18, 2001, we filed a shelf registration statement on Form S-3 for the issuance and sale of shares of our common stock and debt securities in one or more offerings with an aggregate offering price of up to $500 million. On December 20, 2002, we amended the shelf registration statement on Form S-3 to increase the aggregate offering price of securities to be issued under the shelf registration statement to $1.0 billion and to add some additional securities, including preferred stock, stock purchase contracts and stock purchase units.

During the first quarter of 2003, we conducted public offerings of our common stock and equity units under that shelf registration statement. In connection with these offerings, we issued a total of 13.8 million shares of common stock at the public offering price of $17.19 per share, resulting in aggregate net proceeds to us, after underwriting discounts and commissions, of $16.524 per share, or $228 million.

In addition, we issued a total of 16.1 million equity units at the public offering price of $25 per unit, resulting in aggregate net proceeds to us, after underwriting discounts and commissions, of $24.25 per share, or $390.4 million. Each equity unit consists of a stock purchase contract for the purchase of shares of our common stock and, initially, a senior note due February 16, 2008, issued pursuant to our existing Indenture with SunTrust Bank, as trustee. The equity units carry a total annual coupon rate of 8.5 percent (4.0 percent annual face amount of the senior notes plus 4.5 percent annual contract adjustment payments). The interest expense associated with the 4.0 percent senior notes will be recognized in the income statement on an accrual basis over the term of the senior notes. The present value of the contract adjustment payments was accrued as a liability with a charge to equity at the time of the transactions. Accordingly, there will be no impact on earnings in future periods as this liability is paid, except for the interest recognized as a result of discounting the liability to its present value at the time of the transaction. This interest expense will be approximately $3.5 million over three years. The present value of the contract adjustment payments is accounted for as equity and reduces paid in capital. The number of shares that we will issue for each stock purchase contract issued as part of the equity units will be determined based on our average closing price over the 20-trading day period ending on the third trading day prior to February 16, 2006. If this average closing price:

• equals or exceeds $20.63, we will issue 1.2119 shares of our common stock for each purchase contract or unit;

• equals or is less than $17.19, we will issue 1.4543 shares of our common stock for each purchase contract or unit;

• is less than $20.63 but greater than $17.19, we will determine the number of shares of our common stock to be issued by multiplying the number of purchase contracts or units by the ratio of $25 divided by the average closing price.

On April 4, 2003, we filed an amendment to a shelf registration statement on Form S-3 for our issuance and sale of common stock, preferred stock, purchase contracts, purchase contract units and debt securities, and the issuance and sale by ONEOK Capital Trust I and ONEOK Capital Trust II of trust preferred securities, in one or more offerings with an aggregate offering price of up to $1.0 billion. Also, on April 4, 2003, we filed a shelf registration statement on Form S-3 to register for resale by Westar all of the shares of our common stock held by Westar, as well as all the shares of our Series D Convertible Preferred Stock issued to Westar and all of the shares of our common stock issuable upon conversion of the Series D Convertible Preferred Stock. Both of these registration statements have been declared effective by the SEC.

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During the first quarter of 2004, we conducted a public offering of our common stock. In connection with this offering, we sold a total of 6.9 million shares of our common stock to the underwriter at a price of $21.93 per share, resulting in proceeds to us, before expenses, of $151.3 million.

Contractual Obligations and Commercial Commitments

The following table sets forth our contractual obligations to make future payments under our current debt agreements, operating lease agreements and fixed price contracts. For further discussion of the debt and operating lease agreements, see Notes K and M, respectively, of Notes to the Consolidated Financial Statements in this Form 10-K.

	Payments Due by Period
Contractual Obligations	Total		2004		2005		2006		2007		2008		Thereafter
	(Thousands of Dollars)
Long-term debt	$	1,830,854	$	6,334	$	341,334	$	306,334	$	6,334	$	408,834	$	761,684
Notes payable		600,000		600,000		—		—		—		—		—
Operating leases		316,189		41,076		43,980		54,874		39,360		37,566		99,333
Storage contracts		48,182		22,590		11,739		7,231		5,379		1,243		—
Firm transportation contracts		247,057		69,131		50,184		46,150		34,077		12,472		35,043
Purchase commitments, rights-of-way and other		24,230		8,375		8,672		2,702		1,541		1,561		1,379
Total contractual obligations	$	3,066,512	$	747,506	$	455,909	$	417,291	$	86,691	$	461,676	$	897,439

Long-term debt as reported in the consolidated balance sheets includes unamortized debt discount and the mark-to-market effect of interest rate swaps. Purchase commitments exclude commodity purchase contracts. The Distribution segment is party to fixed price transportation contracts. However, the costs associated with these contracts are recovered through rates as allowed by the applicable regulatory agency and are excluded from the table above.

Trading Activities

The following table sets forth the fair value component of the price risk management assets and liabilities, which result from our Marketing and Trading segment’s energy trading portfolio.

Fair Value Component of Price Risk Management Assets and Liabilities
(Thousands of Dollars)
Net fair value of contracts outstanding at December 31, 2002	$	102,167
Rescission of EITF 98-10, resulting in the removal of energy - related contracts from fair value accounting		(230,997	)
Contracts realized or otherwise settled during the period		65,621
Fair value of new contracts when entered into during the period		36,932
Other changes in fair value		7,923
Net fair value of contracts outstanding at December 31, 2003	$	(18,354	)

The net fair value of contracts outstanding includes the effect of settled energy contracts and current period changes resulting primarily from newly originated transactions and the impact of market movements on the fair value of price risk management assets and liabilities attributable to our Marketing and Trading segment’s activities. Fair value estimates consider the market in which the transactions are executed. The market in which exchange traded and over-the-counter transactions are executed is a factor in determining fair value. We utilize third party references for pricing points from NYMEX and third party over-the-counter brokers to establish the commodity pricing and volatility curves. We believe the reported transactions from these sources are the most reflective of current market prices. Fair values are subject to change based on valuation factors. The estimate of fair value includes an adjustment for the liquidation of the position in an orderly manner over a reasonable period of time under current market conditions. The fair value estimate also considers the risk of nonperformance based on credit considerations of the counterparty.

The net fair value of contracts outstanding at December 31, 2003, includes energy commodity contracts considered derivatives under Statement 133, including forwards, futures, swaps and options.

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The net fair value of contracts outstanding at December 31, 2002, includes energy and energy-related trading contracts accounted for under the mark-to-market accounting requirements of EITF 98-10, including forwards, futures, swaps, options and energy transportation and storage contracts. The net fair value of contracts also includes the fair value component of gas in storage.

The following table sets forth our Marketing and Trading segment’s maturity of energy trading contracts based on the heating season from April through March. This maturity schedule is consistent with our Marketing and Trading segment’s business strategy.

	Fair Value of Contracts at December 31, 2003 Assets (Liabilities)
Source of Fair Value (1)	Matures through March 2004			Matures through March 2007			Matures through March 2009			Matures after March 2009			Total Fair Value
	(Thousands of Dollars)
Prices actively quoted (2)	$	15,979		$	(2,172	)	$	10		$	—		$	13,817
Prices provided by other external sources (3)		2,630			(29,803	)		(3,888	)		654			(30,407	)
Prices derived from quotes, other external sources and other assumptions (4)		(463	)		386			(1,667	)		(20	)		(1,764	)
Total	$	18,146		$	(31,589	)	$	(5,545	)	$	634		$	(18,354	)

(1) Fair value is the mark-to-market component of forwards, futures, swaps, and options utilized for trading activities, net of applicable reserves. These fair values are reflected as a component of assets and liabilities from price risk management activities in the consolidated balance sheets.

(2) Values are derived from energy market price quotes from national commodity trading exchanges that primarily trade future and option commodity contracts.

(3) Values are obtained through energy commodity brokers or electronic trading platforms, whose primary service is to match willing buyers and sellers of energy commodities. Because of the large energy broker network, energy price information by location is readily available.

(4) Values derived in this category utilize market price information from the other two categories, as well as other assumptions for liquidity and credit.

The following table sets forth our Marketing and Trading segment’s financial and commodity risk from fixed-price transactions at December 31, 2003.

	Investment Grade Credit Quality (1)			Below Investment Grade Credit Quality
	(Thousands of Dollars)
Gas and electric utilities	$	(4,921	)	$	(11,088	)
Financial institutions		(12,309	)		—
Oil and gas producers		(18,320	)		1,261
Industrial and commercial		(25,658	)		109
Other		844			(1,461	)
Net value of fixed-price transactions	$	(60,364	)	$	(11,179	)

(1) Investment grade is primarily determined using publicly available credit ratings along with consideration of cash prepayments, cash managing, standby letters of credit and parent company guarantees. Included in Investment Grade are counterparties with a minimum Standard and Poors’ or Moody’s rating of BBB- or Baa3, respectively.

Impact of Recently Issued Accounting Pronouncements

Statement 132R - In December 2003, the FASB issued a revised Statement of Financial Accounting Standards No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits – an amendment of FASB Statements No. 87, 88, and 106” (Statement 132R). Statement 132R requires additional disclosures about assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans. Statement 132R is effective for fiscal years ending after December 15, 2003, except for the disclosure of estimated future benefit payments which will be effective for fiscal years ending after June 15, 2004. In the fourth quarter of 2003, we adopted all additional

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disclosures required for fiscal years ending after December 15, 2003. We will adopt the disclosure of estimated future benefit payments in 2004.

Other

Related Party Transactions - KGS has a shared service agreement with Westar, who was the holder of our preferred stock. The shared services include call center backup, meter readings, customer billing operations and customer service. In 2003, KGS made a net payment of approximately $5.1 million to Westar related to this shared service agreement. During the year ended December 31, 2003, Westar sold, in a series of transactions, all of the shares of our common and preferred stock it held, and Westar no longer holds any shares of our common or preferred stock.

Southwest Gas Corporation - Two substantially identical derivative actions, which were consolidated, were filed by shareholders against members of the board of directors and certain officers of the Company alleging violation of their fiduciary duties to the Company by causing or allowing the Company to engage in certain fraudulent and improper schemes related to the planned acquisition of Southwest Gas Corporation and waste of corporate assets. The consolidated derivative action has been settled at no significant cost to the Company. The trial court entered a final judgment on June 24, 2003, approving the settlement by the parties after notice had been given to shareholders.

Information related to litigation arising out of the termination of our effort to acquire Southwest Gas Corporation is presented in Note M in the Notes to the Consolidated Financial Statements and in Part I, Item 3 Legal Proceedings of this Annual Report on Form 10-K.

Environmental - 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, operations and cash flow. 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 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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Yaggy Facility - In January 2001, the Yaggy gas 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 Hutchison, Kansas. In July 2002, the KDHE issued an administrative order that assessed an $180,000 civil penalty against us, based on alleged violations of several KDHE regulations. A status conference was held on June 27, 2003 regarding progress toward reaching an agreed upon consent order. The matter was continued pending further settlement negotiations. We believe there are no adverse long-term environmental effects.

Two class action lawsuits have been filed against us in connection with the natural gas explosions and eruptions of natural gas geysers that occurred at, and in the vicinity of, the Yaggy facility. These class action lawsuits claim that the explosions were caused by the releases of natural gas from our operations. In addition to the two pending class action matters, sixteen additional lawsuits have been filed against us or our subsidiaries seeking recovery for various claims related to the Yaggy incident, including property damage, personal injury, loss of business and, in some instances, punitive damage. In February 2003, a jury awarded the plaintiffs in one lawsuit $1.7 million in actual damages. The jury found that 50 percent of the liability related to the Company and 50 percent of the liability related to one of the Company’s subsidiaries. The jury also awarded punitive damages against a subsidiary of the Company. A hearing has been set for April 2004 to determine the amount of the punitive damages. Although no assurances can be given, we believe that the ultimate resolution of these matters will not have a material adverse effect on our financial position or results of operations. We are vigorously defending all claims in these cases and believe that our insurance coverage will provide coverage for any material liability associated with these cases.

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 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. We cooperated fully with the CFTC, producing documents and other material in response to specific requests relating to the reporting of natural gas trading information to energy industry publications, conducting an internal review with regard to our practice in voluntarily reporting information to trade publications, and providing reports on our internal review to the CFTC.

In January 2004, we announced a settlement with the CFTC relating to the investigation, whereby we agreed, among other things, to pay a civil monetary penalty of $3.0 million. This charge is recorded in earnings for the Marketing and Trading segment for the year ended December 31, 2003. We neither admitted nor denied the findings in the CFTC settlement order. We do not believe inaccurate trade reporting to the energy industry publications affected the financial accounting treatment of any transactions recorded in the financial statements.

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 a class action lawsuit filed in the United Sates District Court for the Southern District of New York brought on behalf of persons who bought and sold natural gas futures and options contacts on the New York Mercantile Exchange during the years 2000 through 2002. See Part 1, Item 3 Legal Proceedings in this Annual Report on Form 10-K. Although we agreed to the civil monetary penalty with the CFTC, it cannot guarantee other additional legal proceedings, civil or criminal fines or penalties, or other regulatory action related to this issue will not arise. Accordingly, the impact of any further action on the financial condition and results of operations cannot be predicted.

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

Forward-Looking Statements and Risk Factors

Some of the statements contained and incorporated in this Form 10-K are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The forward-looking statements relate to the anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. The Private Securities Litigation Reform Act of 1995 provides a safe

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harbor for forward-looking statements in various circumstances. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

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

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

• risks associated with any reduction in our credit ratings;

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

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

• the capital intensive nature of our business;

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

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

• the profitability of assets or businesses acquired by us;

• risks of marketing, trading and hedging activities as a result of changes in energy prices or the financial condition of our trading partners;

• economic climate and growth in the geographic areas in which we do business;

• the uncertainty of estimates, including estimates for oil and gas reserves;

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

• the effects of changes in governmental policies and regulatory actions, including, with respect to income taxes, environmental compliance, authorized rates or recovery of gas costs;

• the impact of recently issued and future accounting pronouncements and other changes in accounting policies;

• the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political dynamics in the Middle East and elsewhere;

• the impact of unforeseen changes in interest rates, equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension expense and funding resulting from changes in stock market returns;

• risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions;

• the results of administrative proceedings and litigation involving the Oklahoma Corporation Commission, Kansas Corporation Commission, Texas regulatory authorities or any other local, state or federal regulatory body including the Federal Energy Regulatory Commission;

• our ability to access capital at competitive rates on terms acceptable to us;

• the risk of a significant slowdown in growth or decline in the U.S. economy, the risk of delay in growth or recovery in the U.S. economy or the risk of increased costs for insurance premiums, security or other items as a consequence of the September 11, 2001 terrorist attacks; and

• the other factors listed in the reports we have filed and may file with the Securities and Exchange Commission, which are incorporated by reference.

Other factors and assumptions not identified above were also involved in the making of the forward-looking statements. The failure of those assumptions to be realized, as well as other factors, may also cause actual results to differ materially from those projected. We have no obligation and make no undertaking to update publicly or revise any forward-looking statements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Non-Regulated Businesses, Including Marketing and Trading - We are exposed to market risk and the impact of market price fluctuations of natural gas, NGLs, crude oil and power prices. Market risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in commodity energy prices. Our primary exposure arises from fixed price purchase or sale agreements that extend for periods of up to six years, gas in storage utilized by the marketing and trading operation, NGLs in storage utilized by the NGL marketing operation, the difference in price between natural gas and NGL prices with respect to our “keep whole” processing agreements, and anticipated sales of natural gas and oil production. To a lesser extent, we are exposed to the risk of changing prices or the cost of intervening transportation resulting from purchasing gas at one location and selling it at another (referred to as basis risk). To minimize the risk from market price fluctuations of natural gas, NGLs and crude oil, we use commodity derivative instruments such as futures contracts, swaps and options to manage market risk of existing or anticipated purchase and sale agreements, existing physical gas in storage, and basis risk. We adhere to policies and procedures that limit our exposure to market risk from open positions and that monitor our market risk exposure.

For a detail of the Marketing and Trading segment’s maturity of energy trading contracts based on heating injection and withdrawal periods from April through March and the related models and assumptions, refer to the Liquidity and Capital Resources section of Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Annual Report on Form 10-K.

For further discussion of trading activities, see the Critical Accounting Policies and Estimates section of Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations on this Annual Report on Form 10-K. Also, see Note D of the Notes to Consolidated Financial Statements in this Form 10-K.

Regulated Businesses - KGS uses derivative instruments to hedge the cost of anticipated gas purchases during the winter heating months to protect KGS customers from upward volatility in natural gas market prices. At December 31, 2003, KGS had derivative instruments in place to hedge the cost of purchases for 13.5 Bcf of gas, representing part of KGS’ gas purchase requirements for the 2003/2004 winter heating months based on normal weather conditions. Gains or losses associated with the KGS hedges are included in and recoverable through the monthly PGA.

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. At December 31, 2003, TGS had no derivative instruments in place to hedge the cost of purchases of gas. Gains or losses associated with the derivative instruments would be included in and recoverable through the monthly purchased gas adjustment.

Value-at-Risk - We measure market risk in the trading, price risk management, and non-trading portfolios of our non-regulated businesses using a value-at-risk (VAR) methodology, which estimates the expected maximum loss of the portfolio over a specified time horizon within a given confidence interval. Our VAR calculations are based on the Monte Carlo approach, which we began using in the second quarter of 2002. Prior to that time, we used the variance-covariance approach. The quantification of market risk using VAR provides a consistent measure of risk across diverse energy markets and products with different risk factors in order to set overall risk tolerance, to determine risk targets and set position limits. The use of this methodology requires a number of key assumptions, including the selection of a confidence level and the holding period to liquidation. Inputs to the calculation include prices, positions, instrument valuations and the variance-covariance matrix. Historical data is used to estimate our VAR with more weight given to recent data, which is considered a more relevant predictor of immediate future commodity market movements. We rely on VAR to determine the potential reduction in the trading and price risk management portfolio values arising from changes in market conditions over a defined period. While management believes that the referenced assumptions and approximations are reasonable, no uniform industry methodology exists for estimating VAR. Different assumptions and approximations could produce materially different VAR estimates.

Our VAR exposure represents an estimate of potential losses that would be recognized for our non-regulated businesses’ trading, price risk management, and non-trading portfolios of derivative financial instruments, physical contracts and gas in storage due to adverse market movements. A one-day time horizon and a 95 percent confidence level were used in our VAR data. Actual future gains and losses will differ from those estimated by the VAR calculation based on actual fluctuations in commodity prices, operating exposures and timing thereof, and the changes in our derivative financial instruments, physical contracts and gas in storage. VAR information should be evaluated in light of these assumptions and the methodology’s other limitations.

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The potential impact on our future earnings, as measured by the VAR, was $11.0 million and $3.2 million at December 31, 2003 and 2002, respectively. The following table details the average, high and low VAR calculations.

	Years Ended December 31,
Value-at-Risk	2003		2002
	(Millions of Dollars)
Average	$	3.9	$	5.0
High	$	17.1	$	17.8
Low	$	0.5	$	1.2

The variations in the VAR data are reflective of market volatility and changes in the portfolio during the year.

Risk Policy and Oversight - We control the scope of risk management, marketing and trading operations through a comprehensive set of policies and procedures involving senior levels of management. Our board of directors affirms the risk limit parameters, with our audit committee having oversight responsibilities for the policies. A risk oversight committee, comprised of corporate and business segment officers, oversees all activities related to commodity price, credit and interest rate risk management, and marketing and trading activities. The committee also proposes risk metrics including VAR and position loss limits. We have a corporate risk control organization led by our Senior Vice President of Financial Services and the Vice President of Audit Services and Risk Control, who are assigned responsibility for establishing and enforcing the policies, procedures and limits as well as evaluating the risks inherent in proposed transactions. Key risk control activities include credit review and approval, credit and performance risk measurement and monitoring, validation of transactions, portfolio valuation, VAR and other risk metrics.

To the extent open commodity positions exist, fluctuating commodity prices can impact our financial results and financial position either favorably or unfavorably. As a result, we cannot predict with precision the impact risk management decisions may have on the business, operating results or financial position.

Interest Rate Risk

We are subject to the risk of interest rate fluctuation in the normal course of business. We manage interest rate risk through the use of fixed rate debt, floating rate debt and, at times, interest rate swaps. Fixed rate swaps are used to reduce our risk of increased interest costs during periods of rising interest rates. Floating rate swaps are used to convert the fixed rates of long-term borrowings into short-term variable rates.

At December 31, 2003, the interest rate on 59.4 percent of our debt was fixed, after considering the effect of interest rate swaps. Currently, $740 million of fixed rate debt is swapped to floating. The floating rate debt is based on both three and six-month London InterBank Offered Rate (LIBOR). At December 31, 2003, $500.0 million of the $740 million had the interest rate locked through the first quarter of 2005. Based on the current LIBOR strip and the locks in place, the weighted average rate on the $740 million of debt will be reduced from 7.01 percent to 3.15 percent. This will result in an estimated savings of $28.6 million during 2004. The swaps resulted in approximately $20.6 million in savings in 2002 and $24.4 million in savings during 2003. At December 31, 2003, price risk management assets include $55.8 million to recognize the fair value of our derivatives that are designated as fair value hedging instruments. Long-term debt includes approximately $55.9 million to recognize the change in fair value of the related hedged liability. Interest expense increased approximately $0.9 million for the year ended December 31, 2003, to recognize the ineffectiveness of these hedges.

At December 31, 2003, a 100 basis point move in the annual interest rate on all of our outstanding long-term debt would change our annual interest expense by $2.4 million before taxes. This amount is limited based on the LIBOR locks that we have in place through the first quarter of 2005. If these locks were not in place, a 100 basis point change in the interest rates would affect our annual interest expense by $7.4 million before taxes. This 100 basis point change assumes a parallel shift in the yield curve. If interest rates changed significantly, we would take actions to manage our exposure to the change. Since a specific action and the possible effects are uncertain, no change has been assumed.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Shareholders

ONEOK, Inc.:

We have audited the accompanying consolidated balance sheets of ONEOK, Inc. and subsidiaries as of December 31, 2003 and 2002 and the related consolidated statements of income, shareholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2003. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of ONEOK, Inc. and subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes A and F to the consolidated financial statements, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, the recognition and measurement principles of Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation, and the rescission of the provisions of Emerging Issues Task Force 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, effective January 1, 2003, the provisions of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, effective January 1, 2002 and the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, effective January 1, 2001.

KPMG LLP

Tulsa, Oklahoma

February 13, 2004

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31,
	2003			2002		2001
	(Thousands of Dollars, except per share amounts)
Revenues
Operating revenues, excluding energy trading revenues	$	2,769,214		$	1,894,851	$	1,814,180
Energy trading revenues, net		229,782			209,429		101,761
Cost of gas		1,862,518			1,128,620		1,089,566
Net Revenues		1,136,478			975,660		826,375
Operating Expenses
Operations and maintenance		463,116			401,328		381,589
Depreciation, depletion, and amortization		160,861			147,843		133,533
General taxes		66,437			55,011		55,644
Total Operating Expenses		690,414			604,182		570,766
Operating Income		446,064			371,478		255,609
Other income		8,164			12,426		9,852
Other expense		5,224			19,038		8,976
Interest expense		104,185			106,405		140,158
Income before Income Taxes		344,819			258,461		116,327
Income taxes		130,527			102,485		37,490
Income from Continuing Operations		214,292			155,976		78,837
Discontinued operations, net of taxes (Note C):
Income from operations of discontinued component		2,342			10,648		24,879
Gain on sale of discontinued component		39,739			—		—
Cumulative effect of changes in accounting principles, net of tax (Note A and D)		(143,885	)		—		(2,151	)
Net Income		112,488			166,624		101,565
Preferred stock dividends		24,211			37,100		37,100
Income Available for Common Stock	$	88,277		$	129,524	$	64,465
Earnings Per Share of Common Stock (Note S)
Basic:
Earnings per share from continuing operations	$	2.38		$	1.31	$	0.66
Earnings per share from operations of discontinued component		0.02			0.09		0.21
Earnings per share from gain on sale of discontinued component		0.36			—		—
Earnings per share from cumulative effect of changes in accounting principle		(1.28	)		—		(0.02	)
Net earnings per share, basic	$	1.48		$	1.40	$	0.85
Diluted:
Earnings per share from continuing operations		2.13		$	1.30	$	0.66
Earnings per share from operations of discontinued component		0.02			0.09		0.21
Earnings per share from gain on sale of discontinued component		0.35			—		—
Earnings per share from cumulative effect of changes in accounting principle		(1.28	)		—		(0.02	)
Net earnings per share, diluted	$	1.22		$	1.39	$	0.85
Average Shares of Common Stock (Thousands)
Basic		80,569			99,914		99,449
Diluted		96,999			100,528		99,671
Dividends per share of Common Stock	$	0.69		$	0.62	$	0.62

See accompanying Notes to Consolidated Financial Statements.

55

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

	December 31, 2003		December 31, 2002
	(Thousands of Dollars)
Assets
Current Assets
Cash and cash equivalents	$	12,172	$	73,522
Trade accounts and notes receivable, net		970,141		773,017
Materials and supplies		18,962		16,949
Gas in storage		500,439		58,544
Unrecovered purchased gas costs		—		3,576
Assets from price risk management activities (Note D)		289,417		724,842
Deposits		42,424		—
Other current assets		46,184		44,790
Assets of discontinued component (Note C)		—		276
Total Current Assets		1,879,739		1,695,516
Property, Plant and Equipment
Production		404,254		144,174
Gathering and Processing		1,036,080		993,504
Transportation and Storage		699,676		689,150
Distribution		2,813,800		2,169,382
Marketing and Trading		126,315		124,512
Other		99,549		94,778
Total Property, Plant and Equipment		5,179,674		4,215,500
Accumulated depreciation, depletion, and amortization		1,487,848		1,199,568
Net Property, Plant and Equipment		3,691,826		3,015,932
Deferred Charges and Other Assets
Regulatory assets, net (Note E)		213,915		217,978
Goodwill (Note F)		225,615		113,510
Assets from price risk management activities (Note D)		113,052		360,645
Prepaid pensions		120,618		125,426
Investments and other		69,283		55,526
Total Deferred Charges and Other Assets		742,483		873,085
Non-current Assets of Discontinued Component (Note C)		—		225,061
Total Assets	$	6,314,048	$	5,809,594

See accompanying Notes to Consolidated Financial Statements.

56

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

	December 31, 2003			December 31, 2002
	(Thousands of Dollars)
Liabilities and Shareholders’ Equity
Current Liabilities
Current maturities of long-term debt	$	6,334		$	6,334
Notes payable		600,000			265,500
Accounts payable		813,895			672,153
Accrued taxes		102,637			41,922
Accrued interest		32,999			29,202
Customers’ deposits		34,692			21,096
Unrecovered purchased gas costs		51,378			—
Liabilities from price risk management activities (Note D)		302,878			496,467
Deferred income taxes		150,816			130,328
Other		130,174			125,129
Liabilities of discontinued component (Note C)		—			1,445
Total Current Liabilities		2,225,803			1,789,576
Long-term Debt, excluding current maturities		1,878,264			1,511,118
Deferred Credits and Other Liabilities
Deferred income taxes		414,734			475,163
Liabilities from price risk management activities (Note D)		112,714			309,070
Lease obligation		100,292			109,051
Other deferred credits		340,849			208,989
Total Deferred Credits and Other Liabilities		968,589			1,102,273
Non-current Liabilities of Discontinued Component (Note C)		—			41,015
Total Liabilities		5,072,656			4,443,982
Commitments and Contingencies (Note M)
Shareholders’ Equity
Convertible Preferred Stock, $0.01 par value:
Series A authorized 20,000,000 shares; issued and outstanding 19,946,448 shares at December 31, 2002		—			199
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 98,194,674 shares and outstanding 95,194,666 shares at December 31, 2003; issued 63,438,441 shares and outstanding 60,761,064 shares at December 31, 2002		982			634
Paid in capital (Note I)		815,870			903,918
Unearned compensation		(3,422	)		(2,716	)
Accumulated other comprehensive loss (Note G)		(17,626	)		(5,546	)
Retained earnings		495,971			507,836
Treasury stock, at cost: 3,000,008 shares at December 31, 2003 and 2,677,377 shares at December 31, 2002		(50,383	)		(38,713	)
Total Shareholders’ Equity		1,241,392			1,365,612
Total Liabilities and Shareholders’ Equity	$	6,314,048		$	5,809,594

See accompanying Notes to Consolidated Financial Statements.

57

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2003			2002			2001
	(Thousands of Dollars)
Operating Activities
Income from continuing operations	$	214,292		$	155,976		$	78,837
Depreciation, depletion, and amortization		160,861			147,843			133,533
Gain on sale of assets		292			(1,213	)		(1,120	)
Gain on sale of equity investments		—			(7,622	)		(758	)
Income from equity investments		(1,547	)		(366	)		(8,109	)
Deferred income taxes		111,788			165,723			120,189
Stock based compensation expense		6,289			2,121			1,110
Allowance for doubtful accounts		14,073			12,478			43,495
Changes in assets and liabilities (net of acquisition effects):
Accounts and notes receivable		(156,887	)		(122,733	)		909,284
Inventories		(428,408	)		27,334			(11,854	)
Unrecovered purchased gas costs		54,954			41,522			(43,520	)
Deposits		(42,424	)		41,781			79,019
Regulatory assets		(13,467	)		(543	)		(8,387	)
Accounts payable and accrued liabilities		100,961			239,167			(701,153	)
Price risk management assets and liabilities		27,651			(19,038	)		(198,611	)
Other assets and liabilities		(52,631	)		86,062			(49,992	)
Cash Provided by (Used in) Continuing Operations		(4,203	)		768,492			341,963
Cash Provided by Discontinued Operations		8,285			43,789			63,388
Cash Provided by Operating Activities		4,082			812,281			405,351
Investing Activities
Changes in other investments, net		(1,126	)		2,015			981
Acquisitions		(690,302	)		(4,036	)		(14,940	)
Capital expenditures		(215,148	)		(210,652	)		(306,022	)
Proceeds from sale of property		3,084			102,390			7,911
Proceeds from sale of equity investment		—			57,461			7,425
Cash Used in Continuing Operations		(903,492	)		(52,822	)		(304,645	)
Cash Provided by (Used in) Discontinued Operations		280,669			(22,393	)		(36,407	)
Cash Used in Investing Activities		(622,823	)		(75,215	)		(341,052	)
Financing Activities
Borrowing (payments) of notes payable, net		334,500			(333,606	)		(225,000	)
Change in bank overdraft		20,574			14,584			(141,923	)
Issuance of debt		404,964			3,500			401,367
Payment of debt issuance costs		(2,564	)		—			—
Payment of debt		(16,148	)		(305,623	)		(7,583	)
Purchase of Series A Convertible Preferred Stock		(300,000	)		—			—
Purchase of common stock		(50,000	)		—			—
Issuance of common stock		224,412			—			5,447
Issuance of treasury stock, net		12,616			3,673			5,214
Dividends paid		(70,963	)		(74,301	)		(73,841	)
Cash Provided by (Used in) Financing Activities		557,391			(691,773	)		(36,319	)
Change in Cash and Cash Equivalents		(61,350	)		45,293			27,980
Cash and Cash Equivalents at Beginning of Period		73,522			28,229			249
Cash and Cash Equivalents at End of Period	$	12,172		$	73,522		$	28,229

See accompanying Notes to Consolidated Financial Statements.

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59

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

	Common Stock Issued	Preferred Stock Issued	Series A Convertible Preferred Stock	Series D Convertible Preferred Stock	Common Stock	Paid-in Capital
	(Shares)		(Thousands of Dollars)
December 31, 2000	31,599,305	19,946,448	$199	$ —	$316	$895,668
Net income	—	—	—	—	—	—
Other comprehensive income	—	—	—	—	—	—
Total comprehensive income
Effect of two-for-one stock split	31,718,017	—	—	—	317	(317	)
Re-issuance of treasury stock	—	—	—	—	—	866
Issuance of common stock
Stock purchase plans	121,119	—	—	—	1	5,317
Convertible preferred stock dividends - $1.86 per share for Series A	—	—	—	—	—	—
Acquisition of treasury stock	—	—	—	—	—	—
Issuance of restricted stock	—	—	—	—	—	715
Amortization of restricted stock	—	—	—	—	—	—
Forfeitures of restricted stock	—	—	—	—	—	20
Common stock dividends - $0.62 per share	—	—	—	—	—	—
December 31, 2001	63,438,441	19,946,448	$199	$ —	$634	$902,269
Net income	—	—	—	—	—	—
Other comprehensive income	—	—	—	—	—	—
Total comprehensive income
Re-issuance of treasury stock	—	—	—	—	—	633
Issuance of common stock
Stock purchase plans	—	—	—	—	—	614
Convertible preferred stock dividends - $1.86 per share for Series A	—	—	—	—	—	—
Acquisition of treasury stock	—	—	—	—	—	—
Issuance of restricted stock	—	—	—	—	—	410
Amortization of restricted stock	—	—	—	—	—	—
Forfeitures of restricted stock	—	—	—	—	—	(8	)
Shares retained for taxes due on vested restricted stock	—	—	—	—	—	—
Common stock dividends - $0.62 per share	—	—	—	—	—	—
December 31, 2002	63,438,441	19,946,448	$199	$ —	$634	$903,918

See accompanying Notes to Consolidated Financial Statements.

60

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(Continued)

	Unearned Compensation		Accumulated Other Comprehensive Income (Loss)		Retained Earnings		Treasury Stock		Total
	(Thousands of Dollars)
December 31, 2000	$(1,128)		$ —		$387,789		$(57,887)		$1,224,957
Net income	—		—		101,565		—		101,565
Other comprehensive income	—		(1,780	)	—		—		(1,780	)
Total comprehensive income									99,785
Effect of two-for-one stock split	—		—		—		—		—
Re-issuance of treasury stock	—		—		—		7,278		8,144
Issuance of common stock
Stock purchase plans	—		—		—		—		5,318
Convertible preferred stock dividends - $1.86 per share for Series A	—		—		(37,100	)	—		(37,100	)
Acquisition of treasury stock	—		—		—		(29	)	(29	)
Issuance of restricted stock	(1,932	)	—		—		1,217		—
Amortization of restricted stock	1,110		—		—		—		1,110
Forfeitures of restricted stock	78		—		—		(124	)	(26	)
Common stock dividends - $0.62 per share	(128	)	—		(36,741	)	—		(36,869	)
December 31, 2001	$(2,000)		$(1,780)		$415,513		$(49,545)		$1,265,290
Net income	—		—		166,624		—		166,624
Other comprehensive income	—		(3,766	)	—		—		(3,766	)
Total comprehensive income									162,858
Re-issuance of treasury stock	—		—		—		4,926		5,559
Issuance of common stock
Stock purchase plans	—		—		—		4,201		4,815
Convertible preferred stock dividends - $1.86 per share for Series A	—		—		(37,100	)	—		(37,100	)
Acquisition of treasury stock	—		—		—		(5	)	(5	)
Issuance of restricted stock	(2,664	)	—		—		2,254		—
Amortization of restricted stock	2,121		—		—		—		2,121
Forfeitures of restricted stock	36		—		—		(28	)	—
Shares retained for taxes due on vested restricted stock	—		—		—		(516	)	(516	)
Common stock dividends - $0.62 per share	(209	)	—		(37,201	)	—		(37,410	)
December 31, 2002	$(2,716)		$(5,546)		$507,836		$(38,713)		$1,365,612

61

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

	Common Stock Issued	Preferred Stock Issued		Series A Convertible Preferred Stock		Series D Convertible Preferred Stock		Common Stock	Paid-in Capital
	(Shares)			(Thousands of Dollars)
December 31, 2002	63,438,441	19,946,448		$199		$ —		$634	$903,918
Net income	—	—		—		—		—	—
Other comprehensive income	—	—		—		—		—	—
Total comprehensive income
Re-issuance of treasury stock		—		—		—		—	1,608
Issuance of common stock
Common stock offering	13,800,000	—		—		—		138	227,893
Stock issuance pursuant       to various plans	—	—		—		—		—	6,029
Issuance costs of equity units	—	—		—		—		—	(9,728	)
Contract adjustment payment	—	—		—		—		—	(50,805	)
Repurchase of Series A
Convertible Preferred Stock	18,077,511	(9,038,755	)	(90	)	—		181	(91	)
Exchange of Series A
Convertible Preferred Stock	—	(10,907,693	)	(109	)	—		—	(308,466	)
Issuance of Series D
Convertible Preferred Stock	—	21,815,386		—		218		—	361,747
Repurchase of common stock	—	—		—		—		—	—
Exchange of Series D
Convertible Preferred Stock	—	(8,418,000	)	—		(84	)	—	(137,551	)
Conversion of Series D
Convertible Preferred Stock	2,551,835	(13,397,386	)	—		(134	)	26	(182,035	)
Issuance of restricted stock	—	—		—		—		—	107
Forfeiture of restricted stock	—	—		—		—		—	—
Registration Costs	—	—		—		—		—	(268	)
Stock-based employee compensation expense	326,887	—		—		—		3	3,512
Convertible preferred     stock dividends	—	—		—		—		—	—
Common stock dividends–     $0.69 per share	—	—		—		—		—	—
December 31, 2003	98,194,674	—		$ —		$ —		$982	$815,870

See accompanying Notes to Consolidated Financial Statements.

62

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(Continued)

	Unearned Compensation		Accumulated Other Comprehensive Income (Loss)		Retained Earnings		Treasury Stock		Total
	(Thousands of Dollars)
December 31, 2002	$(2,716	)	$  (5,546	)	$507,836		$(38,713	)	$1,365,612
Net income	—		—		112,488		—		112,488
Other comprehensive income	—		(12,080	)	—		—		(12,080	)
Total comprehensive income									100,408
Re-issuance of treasury stock	—		—		—		15,458		17,066
Issuance of common stock
Common stock offering	—		—		—		—		228,031
Stock issuance pursuant to various plans	—		—		—		—		6,029
Issuance costs of equity units	—		—		—		—		(9,728	)
Contract adjustment payment	—		—		—		—		(50,805	)
Repurchase of Series A
Convertible Preferred Stock	—		—		—		(300,000	)	(300,000	)
Exchange of Series A
Convertible Preferred Stock	—		—		—		—		(308,575	)
Issuance of Series D
Convertible Preferred Stock	—		—		(53,390	)	—		308,575
Repurchase of common stock	—		—		—		(50,000	)	(50,000	)
Exchange of Series D
Convertible Preferred Stock	—		—		—		137,635		—
Conversion of Series D
Convertible Preferred Stock	—		—		—		182,143		—
Issuance of restricted stock	(3,206	)	—		—		3,099		—
Forfeiture of restricted stock	5		—		—		(5	)	—
Registration Costs	—		—		—		—		(268	)
Stock-based employee compensation expense	2,774		—		—		—		6,289
Convertible preferred stock dividends	—		—		(18,753	)	—		(18,753	)
Common stock dividends - $0.69 per share	(279	)	—		(52,210	)	—		(52,489	)
December 31, 2003	$(3,422	)	$(17,626	)	$495,971		$(50,383	)	$1,241,392

63

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(A) SUMMARY OF ACCOUNTING POLICIES

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

The Production segment produces natural gas and oil and owns natural gas and oil reserves in Oklahoma and Texas. The Company owns and operates gas processing plants, as well as gathering pipelines in Oklahoma, Kansas and Texas through its Gathering and Processing segment. The Transportation and Storage segment owns and leases natural gas storage facilities and transports gas in Oklahoma, Kansas and Texas. The Company’s Distribution segment provides natural gas distribution services in Oklahoma, Kansas and Texas through Oklahoma Natural Gas Company (ONG), Kansas Gas Service Company (KGS) and Texas Gas Service Company (TGS), respectively. The Marketing and Trading segment markets natural gas to wholesale and retail customers and markets electricity to wholesale customers. The Company’s Other segment, whose results of operations are not material, operates and leases the Company’s headquarters building and parking facility.

Critical Accounting Policies

Energy Trading Derivatives and Risk Management Activities - The Company engages in wholesale marketing and trading, price risk management activities and asset optimization services. In providing asset optimization services, the Company partners with other utilities to provide risk management functions on their behalf. The Company accounts for derivative instruments utilized in connection with these activities under the fair value basis of accounting in accordance with the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (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 Certain Hedging Activities” (Statement 138) and No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (Statement 149). Statement 149 had no impact on the Company.

Under Statement 133, entities are required to record all derivative instruments in price risk management assets and liabilities at fair value. The fair value of derivative instruments is determined by commodity exchange prices, over-the-counter quotes, 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. The majority of the Company’s portfolio is based on actual market prices while only a small part is subject to estimate. The Company’s derivative instruments are highly concentrated in liquid markets, thereby providing a short life for these instruments. Market value changes result in a change in the fair value of the Company’s derivative instruments. The gain or loss from this change 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. The gains and losses resulting from changes in fair value are accounted for in accordance with Statement 133. See Note D.

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 - The Company’s intrastate transmission pipelines and distribution operations are subject to the rate regulation and accounting requirements of the Oklahoma Corporation Commission (OCC), Kansas Corporation Commission (KCC), Texas Railroad Commission (TRC) and various municipalities in Texas. Certain other transportation activities of the Company are subject to regulation by the Federal Energy Regulatory Commission (FERC). ONG, KGS, TGS and portions of the Transportation and Storage segment follow the accounting and reporting guidance contained in Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71). 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

64

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, the Company’s regulatory assets totaled $213.9 million.

Impairment of Goodwill and Long-Lived Assets - The Company assess its 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 the Company must perform a second test to measure the amount of the impairment. In the second test, the Company calculates 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.

The Company assesses its 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:

• significant and long-term declines in commodity prices

• a major accident affecting the use of an asset

• part or all of a regulated business no longer operating under Statement 71

• a significant decrease in the rate of return for a regulated business

Pension and Postretirement Employee Benefits - The Company has a defined pension plan covering substantially all full-time employees and a postretirement employee benefits plan covering most employees. The Company’s actuarial consultant, in calculating 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 recognized by the Company. See Note L.

Contingencies - The Company’s accounting for contingencies covers a variety of business activities including contingencies for potentially uncollectible receivables, legal exposures and environmental exposures. The Company accrues these contingencies when its 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”. The Company bases its estimates on currently available facts and its estimates of the ultimate outcome or resolution. Actual results may differ from the Company’s estimates resulting in an impact, either positive or negative, on earnings.

Significant Accounting Policies

Consolidation - The consolidated financial statements include the accounts of ONEOK, Inc. and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. Investments in 20 percent to 50 percent-owned affiliates are accounted for on the equity method. Investments in less than 20 percent owned affiliates are accounted for on the cost method.

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

Inventories - Materials and supplies are valued at average cost. Noncurrent gas in storage is classified as property and is valued at cost. The Marketing and Trading segment’s gas in storage of $223.8 million, which was recorded in current price risk management assets, was carried at fair value at December 31, 2002. At December 31, 2003, the Marketing and Trading segment’s gas in storage of $328.8 million was carried at the lower of cost or market and is recorded in gas in storage in the

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balance sheet. This change was the result of the rescission of EITF 98-10. Cost of current gas in storage for ONG is determined under the last-in, first-out (LIFO) methodology. The estimated replacement cost of current gas in storage was $28.3 million and $2.5 million at December 31, 2003 and 2002, respectively, compared to its value under the LIFO method of $32.6 million and $2.3 million at December 31, 2003 and 2002, respectively. Current gas and NGLs in storage for all other companies is determined using the weighted average cost of gas method.

Non-Trading Derivative Instruments and Hedging Activities - To minimize the risk of fluctuations in natural gas and crude oil prices, the Company’s nontrading segments periodically enter into futures transactions, swaps, and options in order to hedge anticipated sales of natural gas and crude oil production, fuel requirements and NGL inventories. Interest rate swaps are also used to manage interest rate risk.

On January 1, 2001, the Company adopted the provisions of Statement 133, amended by Statement 137, Statement 138 and Statement 149. Statement 149 had no impact on the Company. Many of the Company’s purchase and sale agreement that otherwise would be required to follow derivative accounting qualify as normal purchases and normal sales under Statement 133 and are therefore exempt from fair value accounting treatment.

Regulated Property - Regulated properties are stated at cost, which includes an allowance for funds used during construction. The allowance for funds used during construction represents the capitalization of the estimated average cost of borrowed funds (6.4 percent in 2003 and 2002, respectively) used during the construction of major projects and is recorded as a credit to interest expense.

Depreciation is calculated using the straight-line method based on rates prescribed for ratemaking purposes. The average depreciation rate for property that is regulated by the OCC approximated 2.8 percent, 3.0 percent and 2.9 percent in fiscal years 2003, 2002 and 2001, respectively. The average depreciation rate for property that is regulated by the KCC approximated 3.3 percent, 3.4 percent and 3.4 percent in fiscal years 2003, 2002 and 2001, respectively. The average depreciation rate for property that is regulated by the TRC and various municipalities in Texas approximated 3.2 percent in fiscal year 2003. The average depreciation rates for Mid Continent Market Center, Inc. (MCMC) properties were 3.5 percent, 3.6 percent and 3.4 percent in fiscal years 2003, 2002 and 2001, respectively.

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

The following table sets forth the remaining life and service years of the Company’s regulated properties.

	Remaining Life	Service Years
Distribution property	18-24	34-45
Transmission property	9-34	31-40
Other property	6-20	16-25

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

The FASB is expected to consider, based on a Securities and Exchange Commission (SEC) request, whether or not acquired oil and gas drilling rights should be classified as an intangible asset pursuant to Statement of Financial Accounting Standards No. 141, “Business Combinations” (Statement 141) and Statement 142. The Company classifies the cost of oil and gas mineral rights as property, plant, and equipment on the balance sheet and believes this classification is consistent with oil and gas accounting and industry practice. If the FASB determines that oil and gas drilling rights acquired are intangible assets pursuant to Statement 141 and Statement 142, approximately $271.8 million and $70.7 million would be reclassified from property, plant, and equipment to intangible assets on the December 31, 2003 and 2002 balance sheet, respectively. The

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reclassification would have no effect on the statements of income or cash flows. This reclassification to intangible assets would require additional disclosures under accounting standards.

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

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

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

The Company’s remaining segments recognize revenue when services are rendered or product is delivered. Major industrial and commercial gas distribution customers are invoiced as of the end of each month. Certain gas distribution customers, primarily residential and some commercial are invoiced on a cycle basis throughout the month, and the Company accrues unbilled revenues at the end of each month. ONG’s, KGS’ and TGS’ tariff rates for residential and commercial customers contain a temperature normalization clause that provides for billing adjustments from actual volumes to normalized volumes during the winter heating season. A flat monthly fee is included in TGS’ authorized rate design for El Paso and Port Arthur to protect customers from abnormal weather.

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

Asset Retirement Obligations - On January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (Statement 143). Statement 143 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset.

Statement 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of the fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for an amount other than the carrying amount of the liability, the Company will recognize a gain or loss on settlement.

All legal obligations for asset retirement obligations were identified and the fair value of these obligations was determined as of January 1, 2003. The obligations primarily relate to the 300-megawatt power plant and various processing plants, storage facilities and producing wells. As a result of the adoption of Statement 143, the Company recorded a long-term liability of approximately $16.3 million, an increase to property, plant and equipment, net of accumulated depreciation, of approximately $12.9 million, and a cumulative effect charge of approximately $2.1 million, net of tax, in the first quarter of 2003. The related depreciation and amortization expense is immaterial to the Company’s consolidated financial statements.

In accordance with long-standing regulatory treatment, the Company collects through rates the estimated costs of removal on certain of its regulated properties through depreciation expense, with a corresponding credit to accumulated depreciation, depletion, and amortization. These removal costs are non-legal obligations as defined by Statement 143. However, questions regarding the accounting treatment for these obligations have arisen since the issuance of Statement 143. In recent discussions between the industry and the SEC staff, the SEC staff has taken the position that these non-legal asset removal obligations are not covered under Statement 143, but rather should be accounted for as a regulatory liability under Statement 71. Historically, the regulatory authorities which have jurisdiction over the Company’s regulated operations have not

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required the Company to track this amount; rather these costs are addressed prospectively as depreciation rates are set in each general rate order. The Company has made a tentative estimation of its cost of removal liability using current rates since the last general rate order in each of its jurisdictions. However, significant uncertainty exists regarding the ultimate determination of this liability pending, among other issues, clarification of regulatory intent. Further study is ongoing, and the liability may be adjusted as more information is obtained. For the purposes of this Form 10-K, the estimated non-legal asset removal obligation has been reclassified from accumulated deprecation, depletion and amortization to non-current liabilities in other deferred credits on the balance sheet as of December 31, 2003 and 2002. To the extent this estimated liability is adjusted, such amounts will be reclassified between accumulated depreciation, depletion and amortization and other deferred credits and thus will not have an impact on earnings.

Common Stock Options and Awards - On January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure” (Statement 148). Statement 148 was an amendment to Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (Statement 123). The Company elected to begin expensing the fair value of all stock option compensation granted on or after January 1, 2003 under the prospective method allowed by Statement 148. Prior to January 1, 2003, the Company accounted for its stock option compensation under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25), and related interpretations. The following table sets forth the effect on net income and earnings per share as if the Company had applied the fair-value recognition provisions of Statement 123 to stock-based employee compensation in the periods presented.

	2003		2002		2001
	(Thousands of Dollars, except per share amounts)
Net income, as reported	$	112,488	$	166,624	$	101,565
Add: Stock option compensation included in net income, net of related tax effects		595		—		—
Deduct: Total stock option compensation expense determined under fair value based method for all awards, net of related tax effects		1,808		2,050		1,444
Pro forma net income	$	111,275	$	164,574	$	100,121
Earnings per share:
Basic - as reported	$	1.48	$	1.40	$	0.85
Basic - pro forma	$	1.46	$	1.38	$	0.84
Diluted - as reported	$	1.22	$	1.39	$	0.85
Diluted - pro forma	$	1.21	$	1.37	$	0.84

Earnings Per Common Share - In accordance with a pronouncement of the FASB’s Staff at the EITF meeting in April 2001, codified as EITF Topic No. D-95 (Topic D-95), the Company revised its computation of earnings per common share (EPS). In accordance with Topic D-95, the dilutive effect of the Company’s Series A Convertible Preferred Stock was considered in the computation of basic EPS, utilizing the “if-converted” method. Under the Company’s “if-converted” method, the dilutive effect of the Series A Convertible Preferred Stock on EPS cannot be less than the amount that would result from the application of the “two-class” method of computing EPS. The “two-class” method is an earnings allocation formula that determines EPS for the common stock and the participating Series A Convertible Preferred Stock according to dividends declared and participating rights in the undistributed earnings. The Series A Convertible Preferred Stock was a participating instrument with the Company’s common stock with respect to the payment of dividends. For all periods presented, the “two-class” method resulted in additional dilution. See Note S.

As a result of the Company’s repurchase and exchange of its Series A Convertible Preferred Stock with Westar Industries, Inc. in February 2003, the Company no longer applied the provisions of Topic D-95 to its EPS computation for periods beginning February 2003.

Labor Force - The Company employed 4,342 people at December 31, 2003. Approximately 19 percent of the workforce, all of whom are employed by KGS, is covered by collective bargaining agreements with 11 percent covered by agreements that expire in 2004 and 8 percent covered by agreements that expire in 2006.

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

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

Reclassifications - Certain amounts in prior period consolidated financial statements have been reclassified to conform to the 2003 presentation. Such reclassifications did not impact previously reported net income or shareholder’s equity.

Definitions

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

Bbl	42 United States (U.S.) gallons, the basic unit for measuring crude oil and natural gas condensate
MBbls	One thousand barrels
MBbls/d	One thousand barrels per day
MMBbls	One million barrels
Btu	British thermal unit - a measure of the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit
MMBtu	One million British thermal units
MMMBtu/d	One billion British thermal units per day
Mcf	One thousand cubic feet of gas
MMcf	One million cubic feet of gas
MMcf/d	One million cubic feet of gas per day
Mcfe	Mcf equivalent, whereby barrels of oil are converted to Mcf using six Mcfs of natural gas to one barrel of oil
Bcf	One billion cubic feet of gas
Bcf/d	One billion cubic feet of gas per day
Bcfe	Bcf equivalent, whereby barrels of oil are converted to Bcf using six Bcfs of natural gas to one million barrels of oil
NGLs	Natural gas liquids
Mwh	Megawatt hour

(B) ACQUISITIONS AND DISPOSITIONS

On December 22, 2003, the Company 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 the Company’s consolidated financial statements since that date. The acquisition included approximately 318 wells, 271 of which the Company operates, 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.

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

In October 2003, the Company 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 71 and the regulatory accounting requirements of the FERC and TRC.

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In August 2003, the Company 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.

In August 2003, the Company 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, the Company closed the sale of approximately 70 percent of the natural gas and oil producing properties of its Production segment for a cash sales price of $294 million, including adjustments. See Note C.

On January 3, 2003, the Company purchased the Texas gas distribution business and other assets from Southern Union Company (Southern Union). The results of operations for these assets have been included in the Company’s consolidated financial statements since that date. The Company 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 includes natural gas distribution investments in Mexico. The gas distribution assets are operated under TGS.

The unaudited pro forma information in the table below presents a summary of the Company’s consolidated results of operations as if the acquisition of the Texas assets from Southern Union had occurred at the beginning of the period presented. The results do not necessarily reflect the results that would have been obtained if the acquisition had actually occurred on the dates indicated or results that may be expected in the future. The December 22, 2003 acquisition from Wagner & Brown, Ltd. is not included in the pro forma information in the table below since this information is not available and the Company believes the amount is immaterial.

	Pro Forma Twelve Months Ended December 31, 2002
	(Thousands of Dollars, except per share amounts)
Operating Revenues	$	2,191,193
Net Revenues	$	1,084,262
Income from continuing operations	$	186,028
Net Income	$	196,676
Earnings per share from continuing operations - diluted	$	1.35
Earnings per share - diluted	$	1.44

The addition of the Texas gas distribution assets fits well with the Company’s concentration in the mid-continent region of the United States by adding to its distribution systems in Oklahoma and Kansas. The acquisition also adds a stable revenue source as a majority of the margins are protected from the impact of weather swings due to rate designs that include a fixed customer charge. The regulatory environment in which municipalities set rates diversifies regulatory risk.

On December 13, 2002, the Company closed the sale of a portion of its 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 interest in a fourth natural gas processing plant.

In December 2002, the Company sold its property rights in Sayre Storage Company, a natural gas storage field, and entered into a long-term agreement with the purchaser whereby the Company retains storage capacity consistent with the Company’s original ownership position.

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

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In June 2001, the Company sold its 40 percent interest in K. Stewart Petroleum Corporation, a privately held exploration company, for a sales price of $7.7 million.

(C) DISCONTINUED OPERATIONS

In January 2003, the Company sold approximately 70 percent of the natural gas and oil producing properties of its Production segment (the component) for an adjusted cash price of $294 million. The component is accounted for as a discontinued operation in accordance with Statement 144. Accordingly, amounts in the Company’s financial statements and related notes for all periods shown reflect discontinued operations accounting. The Company’s decision to sell the component was based on strategic evaluations of the Production segment’s goals and favorable market conditions. The properties sold were in Oklahoma, Kansas and Texas. The effective date of the sale was November 30, 2002. The Company recognized a pretax gain on the sale of the discontinued component of approximately $61.2 million in 2003. The gain reflects the cash received less adjustments, selling expenses and the net book value of the assets sold.

The amounts of revenue, costs and income taxes reported in discontinued operations are as follows.

	Years Ended December 31,
	2003		2002		2001
	(Thousands of Dollars)
Natural gas sales	$	6,036	$	57,520	$	76,218
Oil sales		1,705		6,024		6,030
Other revenues		—		407		162
Net revenues		7,741		63,951		82,410
Operating costs		1,985		21,660		19,010
Depreciation, depletion, and amortization		1,937		24,836		23,777
Operating income		3,819		17,455		39,623
Income taxes		1,477		6,807		14,744
Income from discontinued component	$	2,342	$	10,648	$	24,879
Gain on sale of discontinued component, net of tax of $21.5 million	$	39,739	$	—	$	—

The major classes of discontinued assets and liabilities included in the consolidated balance sheet are as follows.

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	December 31, 2002
	(Thousands of Dollars)
Assets
Trade accounts and notes receivable, net	$	95
Materials and supplies		181
Total current assets of discontinued component		276
Property, plant, and equipment		371,534
Accumulated depreciation, depletion, and amortization		148,798
Net property, plant, and equipment		222,736
Other		2,325
Total non-current assets of discontinued component		225,061
Total assets of discontinued component	$	225,337
Liabilities
Accounts payable	$	1,445
Deferred income taxes		—
Total current liabilities of discontinued component		1,445
Deferred income taxes		40,285
Other		730
Total non-current liabilities of discontinued component		41,015
Total liabilities of discontinued component	$	42,460

(D) PRICE RISK MANAGEMENT ACTIVITIES AND DERIVATIVE FINANCIAL INSTRUMENTS

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

Risk Policy and Oversight - The Company controls the scope of risk management, marketing and trading operations through a comprehensive set of policies and procedures involving senior levels of management. The Company’s Board of Directors affirms the risk limit parameters with its audit committee having oversight responsibilities for the policies. A risk oversight committee, comprised of corporate and business segment officers, oversees all activities related to commodity price, credit and interest rate risk management, marketing and trading activities. The committee also proposes risk metrics including value-at-risk (VAR) and position loss limits. The Company has a corporate risk control organization led by the Senior Vice President of Financial Services and the Vice President of Audit Services and Risk Control, who are assigned responsibility for establishing and enforcing the policies, procedures and limits and evaluating the risks inherent in proposed transactions. Key risk control activities include credit review and approval, credit and performance risk measurement and monitoring, validation of transactions, portfolio valuation, VAR and other risk metrics.

To the extent open commodity positions exist, fluctuating commodity prices can impact the financial results and financial position of the Company either favorably or unfavorably. As a result, the Company cannot predict with precision the impact risk management decisions may have on the business, operating results or financial position.

Accounting Treatment - The Company accounts for derivative instruments and hedging activities in accordance with Statement 133. Under Statement 133, entities are required to record all derivative instruments in price risk management assets and liabilities at fair value. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposure to changes in fair values, cash flows or foreign currencies. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings in the period of change together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. The difference between the change in fair value of the derivative instrument and the change in fair value of the hedged item represents hedge ineffectiveness. For hedges of exposure to changes in cash flow, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income and is

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subsequently reclassified into earnings when the forecasted transaction affects earnings. Any amounts excluded from the assessment of hedge effectiveness, as well as the ineffective portion of the hedge, are reported in earnings immediately.

As required by Statement 133, the Company formally documents all relationships between hedging instruments and hedged items, as well as risk management objectives, strategies for undertaking various hedge transactions and methods for assessing and testing correlation and hedge ineffectiveness. The Company specifically identifies the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item. The Company assesses the effectiveness of hedging relationships, both at the inception of the hedge and on an ongoing basis.

In July 2003, the EITF reached a consensus on EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3, ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities’” (EITF 03-11). EITF 03-11 provides that the determination of whether realized gains and losses on physically settled derivative contracts not “held for trading purposes” should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Consideration of the facts and circumstances should be made in the context of the various activities of the entity rather than based solely on the terms of the individual contracts. The Company has evaluated its activities and will continue to present the financial results of all energy trading contracts on a net basis.

In 2002 and 2001 the Company accounted for price risk management activities for its energy trading contracts in accordance with EITF 98-10. EITF 98-10 required entities involved in energy trading activities to account for energy trading contracts using mark-to-market accounting. Forwards, swaps, options, and energy transportation and storage contracts utilized for trading activities were reflected at fair value as assets and liabilities from price risk management activities in the consolidated balance sheets. Changes in the fair value were recognized as energy trading revenues, net, in the consolidated statements of income.

In October 2002, the Emerging Issues Task Force (EITF) of the FASB rescinded EITF 98-10. As a result, energy-related contracts that are not accounted for pursuant to Statement 133 are no longer carried at fair value, but rather will be accounted for on an accrual basis as executory contracts. As a result of the rescission of EITF 98-10, the Task Force also agreed that energy trading inventories carried under storage agreements should no longer be carried at fair value, but should be carried at the lower of cost or market. The rescission was effective for all fiscal periods beginning after December 31, 2002 and for all existing energy trading contracts and inventory as of October 25, 2002. Additionally, the rescission applied immediately to contracts entered into on or after October 25, 2002. Changes to the accounting for existing contracts as a result of the rescission of EITF 98-10 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. The impact from this change was non-cash.

Trading Activities

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

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

Fair Value Hedges - The Marketing and Trading segment uses basis swaps to hedge the fair value of certain transportation commitments. At December 31, 2003, net price risk management assets include $8.6 million to recognize the fair value of the Marketing and Trading segment’s derivatives that are designated as fair value hedging instruments. Price risk management liabilities include $8.6 million at December 31, 2003 to recognize the change in fair value of the related hedged firm commitment. The ineffectiveness of $0.7 million related to these hedges is included in energy trading revenues, net.

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Cash Flow Hedges - The Marketing and Trading segment uses futures and swaps to hedge the cash flows associated with its natural gas inventories. Accumulated other comprehensive income at December 31, 2003, includes losses of approximately $15.1 million, net of tax, related to these hedges that will be realized within the next 13 months. When gas inventory is sold, net gains and losses are reclassified out of accumulated other comprehensive income to energy trading revenues, net. Ineffectiveness related to these cash flow hedges was approximately $7.9 million in 2003.

Fair Value - At December 31, 2002, price risk management assets and liabilities include the fair value of derivative financial instruments, purchase and sales commitments, fuel requirements, transportation and storage contracts, and inventories related to trading price risk management activities. Due to the rescission of EITF 98-10, energy-related contacts that are not derivatives and energy trading inventories are no longer included in price risk management assets and liabilities at December 31, 2003.

The fair value and average fair value of the Marketing and Trading segment’s price risk management assets and liabilities during 2003 and 2002 are set forth as follows.

	Fair Value December 31, 2003				Average Fair Value (a) December 31, 2003
	Assets		Liabilities		Assets		Liabilities
	(Thousands of Dollars)
Energy commodities	$	290,914	$	339,310	$	237,721	$	296,340
(a)    Computed using the ending balance at the end of each quarter.

	Fair Value December 31, 2002				Average Fair Value (a) December 31, 2002
	Assets		Liabilities		Assets		Liabilities
	(Thousands of Dollars)
Energy commodities	$	920,265	$	720,257	$	939,561	$	750,603
(a)    Computed using the ending balance at the end of each quarter.

The Company did not hold any other commodity-type contracts for trading price risk management purposes at December 31, 2003.

Notional Value - The notional contractual quantities associated with trading price risk management activities are set forth as follows.

	Volumes Purchased	Volumes Sold
December 31, 2003:
Natural gas options (Bcf)	46.5	49.2
Crude oil options (MBbls)	176.9	482.6
Natural gas swaps (Bcf)	1,185.7	943.4
Crude oil swaps (MBbls)	4,416.0	4,416.0
Natural gas futures (Bcf)	297.7	318.8
Crude oil futures (MBbls)	1,720.0	1,480.0
December 31, 2002:
Natural gas options (Bcf)	134.3	118.8
Crude oil options (MBbls)	9.3	9.4
Natural gas swaps (Bcf)	1,485.7	1,357.1
Crude oil swaps (MBbls)	7.6	5.9
Ethane swaps (MBbls)	1.1	0.8
Propane swaps (MBbls)	0.7	0.6
Natural gas futures (Bcf)	250.2	278.4
Crude oil futures (MBbls)	5.5	5.6

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

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

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

Non-Trading Activities

Financial instruments are also utilized to hedge the impact of fair value fluctuations for anticipated sales of natural gas and crude oil production, anticipated fuel requirements, and inventories of the natural gas liquids business. The Company is subject to the risk of interest rate fluctuations in the normal course of business. The Company manages interest rate risk through the use of fixed rate debt, floating rate debt and, at times, interest rate swaps.

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

Fair Value Hedges - Currently, $740 million of fixed rate debt is swapped to floating. The floating rate debt is based on both three and six-month London InterBank Offered Rate (LIBOR). At December 31, 2003, $500 million of the $740 million had the interest rate locked through the first quarter of 2005. In 2003, the Company recorded a $55.8 million net increase in price risk management assets to recognize the interest rate swaps at fair value. Long-term debt was also increased to recognize the change in fair value of the related hedged liability. Ineffectiveness related to these hedges is included in interest expense. See Note K.

Cash Flow Hedges - The Production segment periodically enters into derivative instruments to hedge the cash flows associated with its exposure to changes in the price of natural gas. The realized gains and losses were reclassified from accumulated other comprehensive income resulting from the settlement of contracts when the natural gas was sold and are reported in operating revenues. Accumulated other comprehensive income at December 31, 2003 includes losses of approximately $0.2 million, net of tax, for the production hedges that will be realized in earnings within the next 12 months.

The Company’s regulated businesses also use derivative instruments from time to time. Gains or losses associated with the derivative instruments are included in and recoverable through the monthly purchased gas adjustment. At December 31, 2003, KGS had derivative instruments in place to hedge the cost of gas purchases for 13.5 Bcf of gas.

The following table represents the estimated fair values of derivative instruments related to the Company’s non-trading price risk management activities. The fair value is the carrying value for these instruments at December 31, 2003 and 2002.

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	Approximate Fair Value*
	(Thousands of Dollars)
December 31, 2003
Natural gas commodities - cash flow hedges	$	(29,117	)
Interest rate swaps - fair value hedges	$	55,750
Natural gas commodities - other	$	8,640
December 31, 2002
Natural gas commodities - cash flow hedges	$	921
Interest rate swaps - fair value hedges	$	79,021
Natural gas commodities - other	$	—
*  This excludes hedges related to the regulated entities as any income statement effect will be recovered through the cost of gas.

Notional Value - The Company was a party to natural gas commodity derivative instruments including swaps and options covering 17.6 Bcf and 6.6 Bcf of natural gas for December 31, 2003 and 2002, respectively.

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

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

Financial Instruments

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

	Book Value		Approximate Fair Value
	(Thousands of Dollars)
December 31, 2003
Cash and cash equivalents	$	12,172	$	12,172
Accounts and notes receivable	$	970,141	$	970,141
Notes payable	$	600,000	$	600,000
Long-term debt	$	1,886,777	$	2,010,596
	Book Value		Approximate Fair Value
	(Thousands of Dollars)
December 31, 2002
Cash and cash equivalents	$	73,522	$	73,522
Accounts and notes receivable	$	773,017	$	773,017
Notes payable	$	265,500	$	265,500
Long-term debt	$	1,520,305	$	1,547,234

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

(E) REGULATORY ASSETS

The following table presents a summary of regulatory assets, net of amortization, at December 31, 2003 and 2002.

	December 31, 2003		December 31, 2002
	(Thousands of Dollars)
Recoupable take-or-pay	$	64,171	$	69,812
Pension costs		18,060		6,942
Postretirement costs other than pension		59,118		55,901
Transition costs		16,691		21,005
Reacquired debt costs		20,635		21,512
Income taxes		21,782		25,142
Weather normalization		1,075		3,746
Line replacements		495		5,072
Service lines		3,250		1,882
Other		8,638		6,964
Regulatory assets, net	$	213,915	$	217,978

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

	December 31, 2003		Remaining Recovery Period
	(Thousands of Dollars)		(Months)
Postretirement costs other than
pension - Oklahoma	$	6,512	117
Income taxes - Oklahoma	$	5,460	90  - 106
Transition costs	$	16,691	407
Other - Texas	$	1,919	12 - 24

Regulatory assets increased by $21.2 million as a result of the TGS acquisition on January 3, 2003.

On September 17, 2003, the KCC issued an order approving a $45 million rate increase for the Company’s distribution customers in Kansas pursuant to a stipulated settlement agreement with KGS. The order primarily authorized the recovery of postretirement benefit costs over nine years. The order also made the weather normalization adjustment rider, which had been renewed annually, a permanent component of customer rates.

On January 30, 2004, the OCC approved ONG’s request that it be allowed to recover costs that the Company has incurred since 2000 when it assumed responsibility for its customers’ service lines and enhanced its efforts to protect pipelines from corrosion. ONG also sought to recover costs related to its investment in gas in storage and rising levels of fuel-related bad debts. The plan allows ONG to increase its annual rates $17.7 million with $10.7 million as interim and subject to refund until a final determination at the Company’s next general rate case. ONG has committed to filing for a general rate review no later than January 31, 2005. Approximately $7.0 million annually is considered final and not subject to refund. Through December 31, 2003, the Company has deferred approximately $6.0 million associated with these OCC directives. These deferred costs are included in the caption “Service Lines” and “Other” in the regulatory assets table above.

The OCC has authorized ONG’s recovery of the take-or-pay settlement, pension and postretirement benefit costs over a 10 to 20 year period. The KCC has authorized KGS’ recovery of postretirement benefit costs over a nine-year period for KGS in

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the September 17, 2003 order. TGS is authorized to recover pension and postretirement benefit costs over various periods based on the approval of the TRC and the various municipalities that it serves.

The Company amortizes reacquired debt costs in accordance with the accounting rules prescribed by the OCC and KCC. These costs were included as a component of interest in the most recent rate filing with the OCC and were included in the rate order issued by the KCC on September 17, 2003.

Recovery through rates resulted in amortization of regulatory assets of approximately $11.8 million, $11.9 million and $11.3 million for the years ended December 31, 2003, 2002 and 2001, respectively.

(F) GOODWILL

The Company adopted Statement 142 on January 1, 2002. Under Statement 142, goodwill is no longer amortized but reviewed for impairment annually or more frequently if certain indicators arise. Statement 142 prescribes a two-phase process for testing the impairment of goodwill. The first phase identifies indicators of impairment. If impairment is indicated, the second phase measures the impairment. In accordance with the provisions of Statement 142, the Company performed the first of the required impairment tests of goodwill and, based upon this transition impairment test, no impairment to goodwill was indicated and the Company did not record a charge in connection with the adoption of Statement 142. The Company performed its annual test of goodwill as of January 1, 2003, and will perform it annually thereafter. Had the Company been accounting for its goodwill under Statement 142 for all periods presented, the Company’s net income and earnings per share would have been as follows.

	Years Ended December 31,
	2003		2002		2001
	(Thousands of Dollars)
Reported net income	$	112,488	$	166,624	$	101,565
Add back goodwill amortization, net of tax		—		—		2,747
Pro forma adjusted net income	$	112,488	$	166,624	$	104,312
Basic earnings per share:
Reported earnings per share	$	1.48	$	1.40	$	0.85
Goodwill amortization, net of tax		—		—		0.02
Pro forma adjusted basic earnings per share	$	1.48	$	1.40	$	0.87
Diluted earnings per share:
Reported earnings per share	$	1.22	$	1.39	$	0.85
Goodwill amortization, net of tax		—		—		0.02
Pro forma adjusted diluted earnings per share	$	1.22	$	1.39	$	0.87

The changes in the carrying amount of goodwill for the years ended December 31, 2003 and 2002 are as follows.

	Balance December 31, 2002		Adjustments		Balance December 31, 2003
	(Thousands of Dollars)
Gathering and Processing	$	34,343	$	—	$	34,343
Transportation and Storage		22,183		105		22,288
Distribution		51,368		107,361		158,729
Marketing and Trading		5,616		4,639		10,255
Total consolidated	$	113,510	$	112,105	$	225,615

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	Balance December 31, 2001		Adjustments		Balance December 31, 2002
	(Thousands of Dollars)
Gathering and Processing	$	34,343	$	—	$	34,343
Transportation and Storage		22,183		—		22,183
Distribution		51,368		—		51,368
Marketing and Trading		5,616		—		5,616
Total consolidated	$	113,510	$	—	$	113,510

The 2003 goodwill additions are the result of the January 2003 acquisition of the Texas assets from Southern Union.

(G) COMPREHENSIVE INCOME

The table below gives an overview of comprehensive income for the periods indicated.

	Years Ended December 31,
	2003						2002
	(Thousands of Dollars)
Net income				$	112,488					$	166,624
Other comprehensive income (loss):
Unrealized gains (losses) on derivative instruments	$	(29,203	)				$	3,463
Unrealized holding gains arising during the period		396						13,087
Realized (gains) losses in net income		3,306						(16,512	)
Minimum pension liability adjustment		5,782						(6,166	)
Other comprehensive loss before taxes		(19,719	)					(6,128	)
Income tax benefit on other comprehensive loss		7,639						2,362
Other comprehensive loss				$	(12,080	)				$	(3,766	)
Comprehensive income				$	100,408					$	162,858

Accumulated other comprehensive loss at December 31, 2003, includes unrealized gains and losses on derivative instruments and minimum pension liability adjustments.

(H) CAPITAL STOCK

Series A Convertible Preferred Stock - The Company issued Series A Convertible Preferred Stock, par value $0.01 per share, at the time of the November 1997 transaction with Westar Energy, Inc. (formerly Western Resources, Inc.). On February 5, 2003, the Company repurchased from Westar Industries, a wholly owned subsidiary of Westar Energy (collectively “Westar”), approximately 9 million shares (approximately 18.1 million shares of common stock equivalents) of its Series A Convertible Preferred Stock. The Company exchanged the remaining shares for 21.8 million shares of its newly-created Series D Convertible Preferred Stock. See further discussion in the Westar section of this footnote. The Series A Convertible Preferred Stock was cancelled pursuant to the repurchase and exchange.

The terms of the Series A Convertible Preferred Stock provided that holders were entitled to receive a dividend payment, with respect to each dividend period of the common stock, equal to 3.0 times the dividend amount declared in respect to each share of common stock for the first five years of the agreement. In November 2002, the rate was reduced to 2.5 times the dividend amount declared in respect to each share of common stock, and at no time could the dividend have been less than $1.80 per share on an aggregate annual basis. The dividend multiple was adjusted to reflect the 2001 two-for-one common stock split. Preferential cash dividends were paid quarterly on each share of Series A Convertible Preferred Stock, but those dividends were not cumulative to the extent they are not paid on any dividend payment date.

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

The liquidation preference of the Series A Convertible Preferred Stock was equal to that payable per share of the Company’s Common Stock, as adjusted to reflect any stock split or similar events, assuming conversion of all outstanding shares of the Series A Convertible Preferred Stock immediately prior to the event triggering the liquidation preference, plus any dividends.

Holders of Series A Convertible Preferred Stock were entitled to vote together with holders of the Company’s Common Stock with respect to certain matters. Holders of Series A Convertible Preferred Stock could not vote in any election of directors to the Company’s Board of Directors or on any matter submitted to the Company’s shareholders other than those previously discussed and other matters as required by law.

Series B Convertible Preferred Stock - The terms of Series B Convertible Preferred Stock are the same as Series A Convertible Preferred Stock, except that the dividend amount is equal to the greater of 2.5 times the common stock dividend, and at no time could the dividend be less than $1.50 per share on an aggregate annual basis during the first five years after the agreement, which ended November 27, 2002, and not less than $1.80 on an aggregate annual basis thereafter. There are no shares of Series B Convertible Preferred Stock currently outstanding.

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

Series D Convertible Preferred Stock - In February 2003, the Company exchanged the remaining shares of Series A Convertible Preferred for 21.8 million shares of Series D Convertible Preferred Stock. During 2003, Westar sold all its equity in the Company, including all of the shares of the Company’s common stock and the Company’s Series D Convertible Preferred Stock, which converted to common stock when sold. See further discussion in the Westar section of this footnote. The Series D Convertible Preferred Stock was retired after Westar’s sale of the preferred shares.

The terms of Series D Convertible Preferred Stock provided that holders were entitled to receive, when and if declared by the Board of Directors, quarterly cash dividends in an amount per share equal to $0.23125. If the Company had not paid dividends on the Series D Convertible Preferred Stock on the dividend payment date for any dividend period, dividends would not have been subsequently paid for that dividend period.

The Company had the option to redeem the Series D Convertible Preferred Stock on or after August 1, 2006, subject to certain stock price requirements.

Series D Convertible Preferred Stock was convertible at any time, at the holder’s option, subject to certain provisions.

Holders of Series D Convertible Preferred Stock were entitled to vote together with holders of the Company’s common stock with respect to certain matters. Each share of Series D Convertible Preferred Stock carried a number of votes equal to those carried by the number of shares of common stock issuable upon conversion of one share of Series D Convertible Preferred Stock. Holders of Series D Convertible Preferred Stock could not vote in any election of directors to the Company’s Board of Directors or on any matter submitted to the Company’s shareholders other than those previously discussed and other matters as required by law.

Common Stock - At December 31, 2003, the Company had approximately 185 million shares of authorized and unreserved common stock available for issuance.

In July 2003, the Company began using shares of its common stock from treasury or newly issued shares to meet the purchase requirements generated by participants in its Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries. All participant purchases under this plan are voluntary. During the year ended December 31, 2003, the Company issued 514,292 shares for a total of $10.5 million.

On January 18, 2001, the Company’s Board of Directors approved, and on May 17, 2001, the shareholders of the Company voted in favor of, a two-for-one common stock split, which was effected through the issuance of one additional share of

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common stock for each share of common stock outstanding to holders of record on May 23, 2001, with distribution of the shares on June 11, 2001. The Company retained the current par value of $0.01 per share for all shares of common stock. Shareholders’ equity reflects the stock split by reclassifying from paid in capital to common stock an amount equal to the cumulative par value of the additional shares issued to effect the split. All share and per share amounts contained herein for all periods reflect this stock split. Outstanding convertible preferred stock is assumed to convert to common stock on a two-for-one basis in the calculations of earnings per share.

The Board of Directors has reserved 12.0 million shares of ONEOK, Inc.’s common stock for the Direct Stock Purchase and Dividend Reinvestment Plan, of which 172,000 shares, 188,000 shares and 424,000 shares were issued in fiscal years 2003, 2002 and 2001, respectively. In January 2001, the Company amended and restated, in its entirety, the existing Direct Stock Purchase and Dividend Reinvestment Plan. The Company has reserved approximately 10.3 million shares for the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries, less the number of shares issued to date under this plan.

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

During 2001, the Company approved a second stock buyback plan for up to 10 percent of its capital stock. The program authorized the Company to make purchases of its common stock on the open market with the timing and terms of purchases and the number of shares purchased to be determined by management based on market conditions and other factors. This plan expired in 2002. The Company did not purchase any stock under this plan.

2003 Public Stock Offering - During the first quarter of 2003, the Company conducted public offerings of its common stock and equity units. In connection with these offerings, the Company issued a total of 13.8 million shares of its common stock at the public offering price of $17.19 per share, resulting in aggregate net proceeds to the Company, after underwriting discounts and commissions, of $16.524 per share, or $228 million.

2003 Public Equity Units Offering - In addition to the stock offering described above, the Company issued a total of 16.1 million equity units at the public offering price of $25 per unit, resulting in aggregate net proceeds to the Company, after underwriting discounts and commissions, of $24.25 per equity unit, or $390.4 million. Each equity unit consists of a stock purchase contract for the purchase of the Company’s common stock shares and, initially, a senior note described in Note K. The number of shares that the Company will issue for each stock purchase contract issued as part of the equity units will be determined based on the its average closing price over the 20-trading day period ending on the third trading day prior to February 16, 2006. If this average closing price:

• equals or exceeds $20.63, the Company will issue 1.2119 shares of its common stock for each purchase contract or unit;

• equals or is less than $17.19, the Company will issue 1.4543 shares of its common stock for each purchase contract or unit;

• is less than $20.63 but greater than $17.19, the Company will determine the number of shares of its common stock to be issued by multiplying the number of purchase contracts or units by the ratio of $25 divided by the average closing price.

Westar - On January 9, 2003, the Company entered into an agreement with Westar to repurchase a portion of the shares of the Company’s Series A Convertible Preferred Stock (Series A) held by Westar and to exchange Westar’s remaining shares of Series A for newly-created shares of ONEOK’s $0.925 Series D Non-Cumulative Convertible Preferred Stock (Series D). The Series A shares were convertible into two shares of common stock for each share of Series A, reflecting the Company’s two-for-one stock split in 2001, and the Series D shares were convertible into one share of common stock for each share of Series D. Some of the differences between the Series D and the Series A were (a) the Series D had a fixed quarterly cash dividend of 23.125 cents per share, (b) the Series D was redeemable by ONEOK at any time after August 1, 2006, at a per share redemption price of $20, in the event that the per share closing price of ONEOK common stock exceeded, at any time prior to the date the notice of redemption was given, $25 for 30 consecutive trading days, (c) each share of Series D was convertible into one share of ONEOK common stock, and (d) with certain exceptions, Westar could not convert any shares of Series D held by it unless the annual per share dividend on ONEOK common stock for the previous year was greater than

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92.5 cents and such conversion would not have subjected ONEOK to the Public Utility Holding Company Act of 1935. Also, in connection with that transaction, a new rights agreement, a new shareholder agreement and a new registration rights agreement between ONEOK and Westar became effective. The shareholder agreement restricted Westar from selling five percent or more of ONEOK’s outstanding Series D and common stock (assuming conversion of all shares of Series D to be transferred), in a bona fide public underwritten offering, to any one person or group. The agreement allowed Westar to sell up to five percent of ONEOK’s outstanding Series D and common stock (assuming conversion of all shares of Series D to be transferred) to any one person or group who did not own more than five percent of ONEOK’s outstanding common stock (assuming conversion of all shares of Series D to be transferred). The KCC approved the Company’s agreement with Westar on January 17, 2003. On February 5, 2003, the Company consummated the agreement by purchasing $300 million of its Series A from Westar. The Company exchanged Westar’s remaining 10.9 million Series A shares for approximately 21.8 million shares of the Company’s newly-created Series D. Upon the cash redemption of the Series A shares, the shares were converted to approximately 18.1 million shares of common stock in accordance with the terms of the Series A shares and the prior shareholder agreement with Westar. Accordingly, the redemption is reflected as an increase to common treasury stock. The Series D exchanged for the Series A was recorded at fair value and the premium over the previous carrying value of the Series A is reflected as a decrease in retained earnings. The Company had registered for resale all of the shares of its common stock held by Westar, as well as all the shares of its Series D issued to Westar and all of the shares of its common stock that were issuable upon conversion of the Series D.

On August 5, 2003, Westar conducted a secondary offering to the public of 9.5 million shares of ONEOK common stock at a public offering price of $19.00 per share, which resulted in gross offering proceeds to Westar of approximately $180.5 million. An over-allotment option for an additional 718,000 shares provided Westar with approximately $13.6 million. The Company did not receive any proceeds from the offering. Since Westar received in excess of $150 million of total proceeds from the offering, the Company was allowed, under a new transaction agreement related to the offering, to repurchase $50 million, or approximately 2.6 million shares, of its common stock from Westar at the public offering price of $19.00 per share. The Company’s repurchase of those shares occurred immediately following the closing of the Westar offering. Of the shares sold in the Westar public offering, approximately 8.4 million shares represented ONEOK’s common stock issued by conversion of ONEOK’s Series D owned by Westar. The remaining shares consisted of approximately 1.1 million shares of ONEOK’s common stock owned by Westar.

On November 21, 2003, Westar sold its remaining equity in the Company, which included all the shares of common stock Westar owned and all the Company’s Series D Convertible Preferred Stock, which converted to shares of common stock when sold.

Dividends - Annual dividends on the Company’s common stock for shareholders of record totaled $0.69 per share during the year ended December 31, 2003. On September 18, 2003, the Company’s Board of Directors approved an increase in the quarterly dividend on the Company’s common stock to $0.18 per share that was applicable to the quarterly dividend declared in September 2003. Due to the timing of the Company’s Board of Directors meetings, four quarterly dividends on common stock were declared during the first three quarters of 2003. In January 2004, the Company’s Board of Directors increased the quarterly dividend on the Company’s common stock to $0.19 per share.

Under the most restrictive covenants of the Company’s loan agreements, $405.6 million (82 percent) of retained earnings was available to pay dividends at December 31, 2003. Under the Company’s existing credit agreement, it is restricted from declaring or making any dividend payment, directly or indirectly, or incurring any obligation to do so unless the aggregate amount declared, paid or expended after August 31, 1998, would not exceed an amount equal to 100 percent of the Company’s net income arising after August 31, 1998, plus $125 million and computed on a cumulative consolidated basis with other such transactions by the Company.

(I) PAID IN CAPITAL

Paid in capital was $815.9 million and $339.7 million for common stock at December 31, 2003 and 2002, respectively. Due to the conversion of the remaining preferred stock in 2003, the Company had no paid in capital for convertible preferred stock at December 31, 2003. Paid in capital for convertible preferred stock was $564.2 million at December 31, 2002.

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

Commercial paper and short-term notes payable totaling $600.0 million and $265.5 million were outstanding at December 31, 2003 and 2002, respectively. The commercial paper and short-term notes payable carried average interest rates of 1.24

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percent and 1.99 percent at December 31, 2003 and 2002, respectively. The Company has an $850 million short-term unsecured revolving credit facility, which provides a back-up line of credit for commercial paper in addition to providing short-term funds. Interest rates and facility fees are based on prevailing market rates and the Company’s credit ratings. No amounts were outstanding under the line of credit and no compensating balance requirements existed at December 31, 2003. Maximum short-term debt from all sources, as approved by the Company’s Board of Directors, is $1.2 billion.

The Company’s credit agreement contains no restrictions on the transfer of its subsidiaries’ assets to ONEOK (the parent company) in the form of loans, advances or cash dividends without the consent of a third party.

(K) LONG-TERM DEBT

The aggregate maturities of long-term debt outstanding at December 31, 2003, are $6.3 million; $341.3 million; $306.3 million; $6.3 million; and $408.8 million for 2004 through 2008, respectively, including $6.0 million, which is callable at the option of the holder in each of those years. Additionally, $186.5 million is callable at par at the option of ONEOK from now until maturity, which is 2019 for $93.7 million and 2028 for $92.8 million.

In the first quarter of 2003, the Company issued long-term debt concurrent with its public equity offering. The Company issued a total of 16.1 million equity units at the public offering price of $25 per unit for a total of $402.5 million. Each equity unit consists of a stock purchase contract for the purchase of shares of the Company’s common stock and, initially, a senior note due February 16, 2008, issued pursuant to the Company’s existing Indenture with SunTrust Bank, as trustee. The equity units carry a total annual coupon rate of 8.5 percent (4.0 percent annual face amount of the senior notes plus 4.5 percent annual contract adjustment payments). The interest expense associated with the 4.0 percent senior notes will be recognized in the income statement on an accrual basis over the term of the senior notes. The present value of the contract adjustment payments was accrued as a liability with a charge to equity at the time of the transactions. Accordingly, there will be no impact on earnings in future periods as this liability is paid, except for the interest recognized as a result of discounting the liability to its present value at the time of the transaction. This interest expense associated with the discounting will be approximately $3.5 million over three years.

In June 2002, the Company issued $3.5 million of long-term variable rate debt, which is secured by the corporate airplane, at an interest rate of 1.25 percent over LIBOR. All remaining long-term notes payable are unsecured. In August 2002, the Company completed a tender offer to purchase all of the outstanding 8.44% Senior Notes due 2004 and the 8.32% Senior Notes due 2007 for a total purchase price of approximately $65 million. The total purchase price included a premium of approximately $2.9 million and consent fees of approximately $1.8 million to purchase the notes, which are reflected in interest expense in the income statement. In April 2002, the Company retired $240 million of two-year floating rate notes that were issued in April 2000. The interest rate for these notes reset quarterly at a 0.65 percent spread over the three-month LIBOR. The proceeds from the notes were used to fund acquisitions. In 2001, the Company issued a $400 million note at a rate of 7.125%. The proceeds from the note were used to refinance short-term debt.

The Company is subject to the risk of fluctuation in interest rates in the normal course of business. The Company manages interest rate risk through the use of fixed rate debt, floating rate debt and, at times, interest rate swaps. Currently, $740 million of fixed rate debt is swapped to floating. The floating rate debt is based on both three and six-month LIBOR. At December 31, 2003, $500 million of the $740 million had the interest rate locked through the first quarter of 2005. Based on the current LIBOR strip and the locks in place, the weighted average rate on the $740 million will be reduced from 7.01 percent to 3.15 percent. This will result in an estimated savings of $28.6 million during 2004. In 2003, the Company recorded a $55.8 million net increase in price risk management assets to recognize at fair value its derivatives that are designated as fair value hedging instruments. Long-term debt was increased by approximately $55.9 million to recognize the change in fair value of the related hedged liability. The swaps generated $24.4 million of interest rate savings during 2003. See further discussion of interest rate risk in Note D.

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The following table sets forth the Company’s long-term debt for the periods indicated.

	December 31,
	2003			2002
	(Thousands of Dollars)
Long-term notes payable
7.75% due 2005	$	335,000		$	350,000
7.75% due 2006		300,000			300,000
4.0% due 2008		402,500			—
Libor + 1.25% due 2009		3,027			3,361
6.0% due 2009		100,000			100,000
7.125% due 2011		400,000			400,000
7.25% due 2013		2,421			—
6.4% due 2019		93,679			94,104
6.5% due 2028		92,865			93,208
6.875% due 2028		100,000			100,000
8.0% due 2051		1,362			1,364
Total long-term notes payable		1,830,854			1,442,037
Change in fair value of hedged debt		55,923			78,268
Unamortized debt discount		(2,179	)		(2,853	)
Current maturities		(6,334	)		(6,334	)
Long-term debt	$	1,878,264		$	1,511,118

The Company’s revolving credit facility has customary covenants that relate to liens, investments, fundamental changes in the business, restrictions of certain payments, changes in the nature of the business, transactions with affiliates, burdensome agreements, the use of proceeds, and a limit on the Company’s debt to capital ratio. Other debt agreements have negative covenants that relate to liens and sale/leaseback transactions.

(L) EMPLOYEE BENEFIT PLANS

Retirement and Other Postretirement Benefit Plans

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

The Company elected to delay recognition of the accumulated benefit obligation and amortize it over 20 years as a component of net periodic postretirement benefit cost. The accumulated benefit obligation for the defined benefit pension plan was $625.9 million and $536.9 million at December 31, 2003 and 2002, respectively.

Other Postretirement Benefit Plans - The Company sponsors welfare care plans that provide postretirement medical benefits and life insurance benefits to substantially all employees who retire under the retirement plans with at least five years of service. The postretirement medical plan is contributory, with retiree contributions adjusted periodically, and contains other cost-sharing features such as deductibles and coinsurance; provided further that nonbargaining unit employees retiring between the ages of 50 and 55 who elect postretirement medical coverage, and all nonbargaining unit employees hired on or after January 1, 1999 who elect postretirement medical coverage, pay 100 percent of the retiree premium for participation in the plan. Additionally, any employees that came to the Company through various acquisitions may be further limited in their eligibility to participate or receive any Company contributions.

The postretirement welfare plan provides prescription drug benefits to Medicare eligible retirees. The measurement date for the other postretirement benefit liabilities is prior to the enactment date of the Medicare Reform Act. While the Company believes the recently enacted Medicare reform legislation may have a favorable impact on its obligations, the Company has

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not reflected any impact as of its measurement date. The impact is currently being reviewed and could be recognized as early as the first quarter of 2004.

Measurement - The Company uses a September 30 measurement date for the majority of its plans.

Obligations and Funded Status - The following tables set forth the Company’s pension and other postretirement benefit plans benefit obligations, fair value of plan assets and funded status at December 31, 2003 and 2002.

	Pension Benefits December 31,						Postretirement Benefits December 31,
	2003			2002			2003			2002
	(Thousands of Dollars)
Change in Benefit Obligation
Benefit obligation, beginning of period	$	601,830		$	516,096		$	177,904		$	154,559
Service cost		14,872			10,662			5,391			3,587
Interest cost		42,602			36,782			12,418			10,990
Participant contributions		—			—			2,278			1,769
Plan amendments		—			667			3,818			(11,987	)
Actuarial (gain)/loss		18,751			72,310			45,069			30,817
Acquisitions (divestitures)		44,606			—			6,932			—
Benefits paid		(38,773	)		(34,687	)		(17,416	)		(11,831	)
Benefit obligation, end of period	$	683,888		$	601,830		$	236,394		$	177,904
Change in Plan Assets
Fair value of assets, beginning of period	$	526,516		$	587,289		$	30,269		$	27,747
Actual return on assets		91,783			(27,505	)		3,319			1,809
Employer contributions		5,842			1,419			3,674			713
Acquisitions (divestitures)		28,504			—			—			—
Benefits paid		(38,773	)		(34,687	)		—			—
Fair value of assets, end of period	$	613,872		$	526,516		$	37,262		$	30,269
Funded status - over (under)	$	(70,016	)	$	(75,314	)	$	(197,226	)	$	(147,636	)
Unrecognized net asset		(314	)		(781	)		31,854			—
Unrecognized transition obligation		—			—			—			9,061
Unrecognized prior service cost		5,494			5,989			2,537			—
Unrecognized net (gain) loss		199,713			195,532			103,171			57,767
Activity subsequent to measurement date		—			—			3,707			6,303
(Accrued) prepaid pension cost	$	134,877		$	125,426		$	(55,957	)	$	(74,505	)

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Components of Net Periodic Benefit Cost

	Pension Benefits Years Ended December 31,
	2003			2002			2001
	(Thousands of Dollars)
Components of Net Periodic Benefit Cost (Income)
Service cost	$	14,872		$	10,662		$	9,751
Interest cost		42,602			36,782			36,188
Expected return on assets		(64,264	)		(67,195	)		(61,161	)
Amortization of unrecognized net asset at adoption		(467	)		(467	)		(467	)
Amortization of unrecognized prior service cost		613			790			822
Amortization of (gain)/loss		2,235			(1,345	)		(4,377	)
Net periodic benefit cost (income)	$	(4,409	)	$	(20,773	)	$	(19,244	)
	Postretirement Benefits Years Ended December 31,
	2003			2002			2001
	(Thousands of Dollars)
Components of Net Periodic Benefit Cost
Service cost	$	5,391		$	3,587		$	3,074
Interest cost		12,418			10,990			10,195
Expected return on assets		(3,154	)		(2,791	)		(2,364	)
Amortization of unrecognized net transition obligation at adoption		3,456			1,954			1,954
Amortization of unrecognized prior service cost		(125	)		—			—
Amortization of loss		3,997			979			234
Net periodic benefit cost	$	21,983		$	14,719		$	13,093

Actuarial Assumptions - The following table sets forth the weighted-average assumptions used to determine benefit obligations at December 31, 2003 and 2002.

	Pension Benefits December 31,				Postretirement Benefits December 31,
	2003		2002		2003		2002
Discount rate	6.25	%	6.80	%	6.25	%	6.80	%
Compensation increase rate	4.00	%	4.00	%	4.50	%	4.50	%

The following table sets forth the weighted-average assumptions used to determine net periodic benefit costs at December 31, 2003 and 2002.

	Pension Benefits December 31,				Postretirement Benefits December 31,
	2003		2002		2003		2002
Discount rate	6.80	%	7.35	%	6.80	%	7.35	%
Expected long-term return on plan assets	9.00	%	9.85	%	9.00	%	9.85	%
Compensation increase rate	4.00	%	4.50	%	4.50	%	4.50	%

The overall expected long-term rate of return on assets assumption is an equally weighted blend of historical return, building block, and economic growth/yield to maturity projections determined by the Company based on its independent investment consultants’ advice.

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Health Care Cost Trend Rates - The following table sets forth the assumed health care cost trend rates at December 31, 2003 and 2002.

	2003	2002
Health care cost trend rate assumed for next year	9%	10%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5%	5%
Year that the rate reaches the ultimate trend rate	2007	2007

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects.

	One-Percentage Point Increase		One-Percentage Point Decrease
	(Thousands of Dollars)
Effect on total of service and interest cost	$	2,010	$	(1,621	)
Effect on postretirement benefit obligation	$	26,210	$	(21,459	)

Plan Assets - The following table sets forth the Company’s pension and postretirement benefit plan weighted-average asset allocations at December 31, 2003 and 2002.

	Pension Benefits				Postretirement Benefits
	Percentage of Plan Assets at December 31,				Percentage of Plan Assets at December 31,
Asset Category	2003		2002		2003		2002
U.S. equities	56	%	47	%	76	%	68	%
International equities	9	%	9	%	12	%	13	%
Investment grade bonds	8	%	12	%	11	%	18	%
High yield bonds	10	%	11	%	0	%	0	%
Insurance contracts	16	%	20	%	0	%	0	%
Other	1	%	1	%	1	%	1	%
Total	100	%	100	%	100	%	100	%

The Company’s investment strategy is to invest plan assets in accordance with sound investment practices that emphasize long-term investment fundamentals. The goal of this strategy is to maximize investment returns while managing risk in order to meet the plan’s current and projected financial obligations. The plan’s investments include a diverse blend of various U.S. and international equities, venture capital investments in various classes of debt securities, and insurance contracts. The target allocation for the investments is as follows.

Insurance contracts/corporate bonds	22	%
High yield corporate bonds	10	%
Large-cap value equities	15	%
Large-cap growth equities	18	%
Mid/small-cap value equities	10	%
Mid/small-cap growth equities	13	%
Large-cap/mid-cap international equities	11	%
Venture capital	1	%

As part of the Company’s risk management for the plans, minimums and maximums have been set for each of the asset classes listed above. All investment managers for the plan are subject to certain restrictions on the securities they purchase and, with the exception of indexing purposes, are prohibited from owning Company stock.

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Contributions - The Company expects to contribute $5.6 million to its pension plan and $28.1 million to its other postretirement benefits plan in 2004.

Regulatory Treatment - The OCC, KCC, TRC and applicable rate jurisdictions in Texas have approved the recovery of pension costs and other postretirement benefits costs through rates for ONG, KGS and TGS, respectively. The costs recovered through rates are based on current funding requirements and the net periodic postretirement benefits cost for pension and postretirement costs. Differences, if any, between the expense and the amount ordered through rates are charged to earnings. In the September 17, 2003 rate order the KCC authorized KGS to recover $26.4 million of deferred postretirement and postemployment costs over nine years. The OCC has authorized ONG’s recovery of pension and postretirement benefit costs over a 10 to 20 year period. TGS is authorized to recover pension and postretirement benefit costs over various periods based on the approval of the TRC and the various municipalities that it serves.

Other Employee Benefit Plans

Employee Thrift Plan - The Company has a Thrift Plan covering substantially all employees. Employee contributions are discretionary. Subject to certain limits, the Company matches employee contributions. The cost of the plan was $9.6 million, $8.5 million and $8.8 million in fiscal years 2003, 2002 and 2001, respectively.

Postemployment Benefits - The Company pays postemployment benefits to former or inactive employees after employment but before normal retirement in compliance with specific separation agreements. Nonbargaining employees hired after January 1, 1999 are not eligible for this benefit.

(M) COMMITMENTS AND CONTINGENCIES

Leases - The initial lease term of the Company’s headquarters building, ONEOK Plaza, is for 25 years, expiring in 2009, with six five-year renewal options. At the end of the initial term or any renewal period, the Company can purchase the property at its fair market value. Annual rent expense for the lease will be approximately $6.8 million until 2009. Rent payments were $9.3 million in fiscal years 2003, 2002 and 2001. Estimated future minimum rental payments for the lease are $9.3 million for each of the years ending December 31, 2004 through 2009.

The Company has the right to sublet excess office space in ONEOK Plaza. The Company received rental revenue of $2.8 million, $3.2 million and $3.5 million in fiscal years 2003, 2002 and 2001, respectively, for various subleases. Estimated minimum future rental payments to be received under existing contracts for subleases are $2.5 million in 2004, $1.8 million in 2005, $1.3 million in 2006, $0.5 million in 2007, $0.4 million in 2008 and a total of $0.3 million thereafter.

Other operating leases include a gas processing plant, office buildings, and equipment. Future minimum lease payments under non-cancelable operating leases (with initial or remaining lease terms in excess of one year) as of December 31, 2003, are $31.8 million in 2004, $34.7 million in 2005, $45.6 million in 2006, $30.1 million in 2007 and $28.3 million in 2008. The above amounts include lease payments for auto leases that are accounted for as operating leases but are treated as capital leases for income tax purposes. Also, the above amounts include the following minimum lease payments relating to the lease of a gas processing plant: $20.9 million in 2004, $24.2 million in 2005, $37.7 million in 2006, $24.2 million in 2007 and $24.2 million in 2008. The Company has a liability for uneconomic lease terms relating to a gas processing plant. Accordingly, the liability is amortized to rent expense in the amount of $13.0 million per year over the term of the lease. The amortization of the liability reduces rent expense; however, the cash outflow under the lease remains the same.

Southwest Gas Corporation - In May 1999, a series of lawsuits were filed in connection with the Company’s and Southern Union’s failed attempts to merge with Southwest Gas Corporation (Southwest). The Company, Southern Union and Southwest all sued each other and Southern Union made claims against a member of the Arizona Corporation Commission and other individuals, including officers and directors of the Company.

On August 9, 2002, the Company and Southwest settled their claims against each other for a payment of $3.0 million by ONEOK to Southwest. On January 3, 2003, the Company entered into a definitive settlement agreement with Southern Union resolving all remaining legal issues. It also resolved the claims against John A. Gaberino, Jr. and Eugene Dubay related to this matter. Under the terms of the settlement, the Company paid $5.0 million to Southern Union, which is included in the December 31, 2002 financial statements. The Company and its affiliated parties are released from any claims against them brought by Southern Union related to the terminated acquisition of Southwest.

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Two substantially identical derivative actions, which were consolidated, were filed by shareholders against members of the Board of Directors and certain officers of the Company alleging violation of their fiduciary duties to the Company by causing or allowing the Company to engage in certain fraudulent and improper schemes related to the planned acquisition of Southwest and waste of corporate assets. The consolidated derivative action has been settled at no significant cost to the Company. The trial Court entered a final judgment on June 24, 2003, approving the settlement by the parties after notice had been given to shareholders.

Environmental - The Company is subject to multiple environmental laws and regulations affecting many aspects of 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 the Company 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 the Company to fines, penalties and/or interruptions in operations that could be material to the results of operations. If an accidental leak or spill of hazardous materials occurs from the Company’s lines or facilities, in the process of transporting natural gas, or at any facilities that the Company owns, operates or otherwise uses, the Company could be held jointly and severally liable for all resulting liabilities, including investigation and clean up costs, which could materially affect the Company’s results, operations and cash flow. In addition, emission controls required under the Federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at the Company’s facilities. The Company cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to the Company. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on the Company’s business, financial condition and results of operations.

The Company owns or retains 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 the Company to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. The Company has commenced active remediation on three sites with regulatory closure achieved at two of these locations, and has begun assessment at the remaining sites. The site situations are not common and the Company has no previous experience with similar remediation efforts. The Company has not completed a comprehensive study of the remaining nine sites and therefore cannot accurately estimate individual or aggregate costs to satisfy the remedial obligations.

The Company’s 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 the Company may be entitled. At this time, the Company has not recorded any amounts for potential insurance recoveries or recoveries from unaffiliated parties, and the Company is 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 the Company’s results of operations and cash flows depending on the remediation done and number of years over which the remediation is completed.

The Company’s 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 the Company’s competitive position during 2003 related to compliance with environmental regulations.

Yaggy Facility - In January 2001, the Yaggy gas 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 Hutchison, Kansas. In July 2002, the KDHE issued an administrative order that assessed an $180,000 civil penalty against the Company, based on alleged violations of several KDHE regulations. A status conference was held on June 27, 2003 regarding progress toward reaching an agreed upon consent order. The matter was continued pending further settlement negotiations. The Company believes there are no adverse long-term environmental effects.

Two class action lawsuits have been filed against the Company in connection with the natural gas explosions and eruptions of natural gas geysers that occurred at, and in the vicinity of, the Yaggy facility. These class action lawsuits claim that the

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explosions were caused by the releases of natural gas from the Company’s operations. In addition to the two pending class action matters, sixteen additional lawsuits have been filed against the Company or subsidiaries seeking recovery for various claims related to the Yaggy incident, including property damage, personal injury, loss of business and, in some instances, punitive damage. In February 2003, a jury awarded the plaintiffs in one lawsuit $1.7 million in actual damages. The jury found that 50 percent of the liability related to the Company and 50 percent of the liability related to one of the Company’s subsidiaries. The jury also awarded punitive damages against a subsidiary of the Company. A hearing has been set for April 2004 to determine the amount of the punitive damages. Although no assurances can be given, the Company believes that the ultimate resolution of these matters will not have a material adverse effect on the Company’s financial position or results of operations. The Company is vigorously defending all claims in these cases and believes that the Company’s insurance coverage will provide coverage for any material liability associated with these cases.

U.S. Commodity Futures Trading Commission - On January 9, 2003, the Company 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 the Company to energy industry publications in connection with the CFTC’s investigation of trading and trade reporting practices of power and natural gas trading companies. The Company ceased providing such information to energy industry publications in 2002. The Company cooperated fully with the CFTC, producing documents and other material in response to specific requests relating to the reporting of natural gas trading information to energy industry publications, conducting an internal review with regard to its practices in voluntarily reporting information to trade publications, and providing reports on its internal review to the CFTC.

In January 2004, the Company announced a settlement with the CFTC relating to the investigation, whereby the Company agreed, among other things, to pay a civil monetary penalty of $3.0 million. This charge is recorded in earnings for the Marketing and Trading segment for the year ended December 31, 2003. The Company neither admitted nor denied the findings in the CFTC settlement order. The Company does not believe inaccurate trade reporting to the energy industry publications affected the financial accounting treatment of any transactions recorded in the financial statements.

On February 4, 2004, the Company received notice that the Company and its wholly owned subsidiary, ONEOK Energy Marketing and Trading Company, L.P., have been named as two of the defendants in a class action lawsuit filed in the United Sates District Court for the Southern District of New York brought on behalf of persons who bought and sold natural gas futures and options contacts on the New York Mercantile Exchange during the years 2000 through 2002. Although the Company agreed to the civil monetary penalty with the CFTC, it cannot guarantee other additional legal proceedings, civil or criminal fines or penalties, or other regulatory action related to this issue will not arise. Accordingly, the impact of any further action on the financial condition and results of operations cannot be predicted.

Labor Negotiations - 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 the KGS employees are members of this labor union, comprising approximately 30 percent of the 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 KGS employees are members of those three labor unions, comprising approximately 41 percent of the KGS workforce. The parties agreed to extend the existing agreements for one year with a two percent increase effective retroactively to August 1, 2003. Currently, the Company has no ongoing labor negotiations and there are no other unions representing the Company’s employees.

Other - The OCC staff filed an application on February 1, 2001, to review the gas procurement practices of ONG in acquiring its gas supply for the 2000/2001 heating season and to determine if these practices were consistent with least cost procurement practices and whether the Company’s procurement decisions resulted in fair, just and reasonable costs being borne by ONG customers. In May 2002, the Company, along with the staff of the Public Utility Division and the Consumer Services Division of the OCC, the Oklahoma Attorney General, and other stipulating parties, entered into a joint settlement agreement resolving this gas cost issue and ongoing litigation related to a contract with Dynamic Energy Resources, Inc.

The settlement agreement will be realized over a three-year period. In July 2002, immediate cash savings were provided to all ONG customers in the form of billing credits with $1.0 million available for former customers returning to the ONG system. If the additional $1.0 million is not fully refunded to customers returning to the ONG system by December 2005, the remainder will be included in the final billing credit. ONG replaced certain gas contracts, which is expected to reduce gas costs by approximately $13.8 million, due to avoided reservation fees between April 2003 and October 2005. Additional savings of approximately $8.0 million from the use of storage service in lieu of those contracts are expected to occur between

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November 2003 and March 2005. Any expected savings from the use of storage that are not achieved, any remaining billing credits not issued to returning customers and an additional $1.8 million credit will be added to the final billing credit scheduled to be provided to customers in December 2005.

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

(N) INCOME TAXES

The following table sets forth the Company’s provisions for income taxes for the periods indicated.

	Years Ended December 31,
	2003			2002			2001
	(Thousands of Dollars)
Current income taxes
Federal	$	16,921		$	(53,306	)	$	(69,273	)
State		1,818			(9,932	)		(13,426	)
Total current income taxes from continuing operations		18,739			(63,238	)		(82,699	)
Deferred income taxes
Federal		112,242			139,243			113,882
State		(454	)		26,480			6,307
Total deferred income taxes from continuing operations		111,788			165,723			120,189
Total provision for income taxes before cumulative effect/discontinued operations		130,527			102,485			37,490
Total provision for income taxes for the cumulative effect of a change in accounting principle		(90,456	)		—			(1,356	)
Discontinued operations		22,895			6,807			14,744
Total provision for income taxes	$	62,966		$	109,292		$	50,878

The following table is a reconciliation of the Company’s provision for income taxes for the periods indicated.

	Years Ended December 31,
	2003			2002			2001
	(Thousands of Dollars)
Pretax income from continuing operations	$	344,819		$	258,460		$	116,327
Federal statutory income tax rate		35	%		35	%		35	%
Provision for federal income taxes		120,687			90,461			40,714
Amortization of distribution property investment tax credit		(522	)		(651	)		(764	)
State income taxes, net of federal tax benefit		13,283			10,756			(4,627	)
Other, net		(2,921	)		1,919			2,167
Income tax expense	$	130,527		$	102,485		$	37,490

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The following table sets forth the tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities for the periods indicated.

	Years Ended December 31,
	2003		2002		2001
	(Thousands of Dollars)
Deferred tax assets
Accrued liabilities not deductible until paid	$	117,784	$	111,020	$	180,331
Net operating loss carryforward		40,978		28,645		36,828
Regulatory assets		17,636		17,527		9,956
Other		130,998		37,002		2,057
Total deferred tax assets		307,396		194,194		229,172
Valuation allowance for net operating loss carryforward expected to expire prior to utilization		18,342		13,166		6,549
Net deferred tax assets		289,054		181,028		222,623
Deferred tax liabilities
Excess of tax over book depreciation and depletion		724,153		617,849		545,398
Investment in joint ventures		8,323		8,081		12,198
Regulatory assets		107,644		112,200		95,836
Other		14,484		48,390		38,472
Total deferred tax liabilities		854,604		786,520		691,904
Net deferred tax liabilities before discontinued operations	$	565,550	$	605,492	$	469,281
Discontinued operations		—		40,285		33,478
Net deferred tax liabilities	$	565,550	$	645,777	$	502,759

The Company has remaining net operating loss carryforwards for federal and state income tax purposes of approximately $49.3 million and $403.3 million, respectively, at December 31, 2003, which expire, unless utilized, at various dates through 2023. The valuation allowance for deferred tax assets was $312.0 million and $232.6 million at December 31, 2003 and 2002, respectively. The valuation allowance reflects management’s uncertainty as to the realization of a portion of the Company’s state net operating losses before they expire. At December 31, 2003, the Company had $6.1 million in deferred investment tax credits recorded in other deferred credits, which will be amortized over the next 12 years.

(O) SEGMENT INFORMATION

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

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

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

The accounting policies of the segments are substantially the same as those described in Note A. Intersegment gross sales are recorded on the same basis as sales to unaffiliated customers. Intersegment sales for the Marketing and Trading segment were $487.3 million, $299.2 million and $614.7 million for the years ended December 31, 2003, 2002 and 2001, respectively. Energy trading contracts included in the following table are reported net of related costs. Corporate overhead costs relating

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to a reportable segment have been allocated for the purpose of calculating operating income. The Company’s equity method investments do not represent operating segments of the Company. The Company has no single external customer from which it receives ten percent or more of its consolidated gross revenues.

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

	Regulated					Non-Regulated											Total
Year Ended December 31, 2003	Transportation and Storage			Distribution		Marketing and Trading			Gathering and Processing			Production		Other and Eliminations
	(Thousands of Dollars)
Sales to unaffiliated customers	$	68,724		$	1,740,060	$	91,965		$	1,311,069		$	40,858	$	(483,462	)	$	2,769,214
Energy trading contracts, net		—			—		229,782			—			—		—			229,782
Intersegment sales		92,575			—		—			467,448			3,130		(563,153	)		—
Total Revenues	$	161,299		$	1,740,060	$	321,747		$	1,778,517		$	43,988	$	(1,046,615	)	$	2,998,996
Net revenues	$	113,662		$	526,249	$	236,369		$	214,137		$	43,988	$	2,073		$	1,136,478
Operating costs	$	46,186		$	312,814	$	33,699		$	122,103		$	15,812	$	(1,061	)	$	529,553
Depreciation, depletion and amortization	$	16,694		$	95,654	$	5,708		$	29,332		$	12,070	$	1,403		$	160,861
Operating income	$	50,782		$	117,781	$	196,962		$	62,702		$	16,106	$	1,731		$	446,064
Income from operations of discontinued component	$	—		$	—	$	—		$	—		$	2,342	$	—		$	2,342
Cumulative effect of changes in accounting principles, net of tax	$	(645	)	$	—	$	(141,982	)	$	(1,375	)	$	117	$	—		$	(143,885	)
Income from equity investments	$	1,398		$	—	$	—		$	55		$	—	$	94		$	1,547
Total assets	$	867,743		$	2,462,299	$	1,332,022		$	1,307,445		$	151,575	$	192,964		$	6,314,048
Capital expenditures (continuing operations)	$	15,234		$	153,405	$	555		$	20,598		$	18,655	$	6,701		$	215,148

	Regulated				Non-Regulated									Total
Year Ended December 31, 2002	Transportation and Storage		Distribution		Marketing and Trading		Gathering and Processing		Production		Other and Eliminations
	(Thousands of Dollars)
Sales to unaffiliated customers	$	70,812	$	1,218,400	$	72,697	$	810,722	$	29,998	$	(307,778	)	$	1,894,851
Energy trading contracts, net		—		—		209,429		—		—		—			209,429
Intersegment sales		93,422		2,244		—		322,499		2,456		(420,621	)		—
Total Revenues	$	164,234	$	1,220,644	$	282,126	$	1,133,221	$	32,454	$	(728,399	)	$	2,104,280
Net revenues	$	117,584	$	414,393	$	214,480	$	194,378	$	32,454	$	2,371		$	975,660
Operating costs	$	46,694	$	243,170	$	27,674	$	127,747	$	8,332	$	2,722		$	456,339
Depreciation, depletion and amortization	$	17,563	$	76,063	$	5,298	$	33,523	$	13,842	$	1,554		$	147,843
Operating income	$	53,327	$	95,160	$	181,508	$	33,108	$	10,280	$	(1,905	)	$	371,478
Income from operations of discontinued component	$	—	$	—	$	—	$	—	$	10,648	$	—		$	10,648
Income from equity investments	$	1,381	$	—	$	—	$	—	$	—	$	(1,015	)	$	366
Total assets	$	815,301	$	1,773,000	$	1,666,271	$	1,246,866	$	348,222	$	(40,066	)	$	5,808,594
Capital expenditures (continuing operations)	$	20,554	$	115,569	$	2,340	$	43,101	$	17,810	$	11,278		$	210,652
Capital expenditures (discontinued component)	$	—	$	—	$	—	$	—	$	21,824	$	—		$	21,824

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	Regulated				Non-Regulated										Total
Year Ended December 31, 2001	Transportation and Storage		Distribution		Marketing and Trading		Gathering and Processing		Production			Other and Eliminations
	(Thousands of Dollars)
Sales to unaffiliated customers	$	76,837	$	1,506,420	$	29,760	$	814,963	$	33,799		$	(647,599	)	$	1,814,180
Energy trading contracts, net		—		—		101,761		—		—			—			101,761
Intersegment sales		86,226		4,548		—		499,854		4,108			(594,736	)		—
Total Revenues	$	163,063	$	1,510,968	$	131,521	$	1,314,817	$	37,907		$	(1,242,335	)	$	1,915,941
Net revenues	$	113,437	$	369,300	$	110,287	$	189,621	$	37,907		$	5,823		$	826,375
Operating costs	$	42,357	$	237,657	$	32,846	$	116,853	$	8,351		$	(831	)	$	437,233
Depreciation, depletion and amortization	$	17,990	$	70,359	$	2,611	$	29,201	$	11,240		$	2,132		$	133,533
Operating income	$	53,090	$	61,284	$	74,830	$	43,567	$	18,316		$	4,522		$	255,609
Income from operations of discontinued component	$	—	$	—	$	—	$	—	$	24,879		$	—		$	24,879
Cumulative effect of change in accounting principle, net of tax	$	—	$	—	$	—	$	—	$	(2,151	)	$	—		$	(2,151	)
Income from equity investments	$	2,946	$	—	$	—	$	—	$	111		$	5,052		$	8,109
Total assets	$	723,263	$	1,762,738	$	1,491,624	$	1,303,236	$	321,720		$	250,719		$	5,853,300
Capital expenditures (continuing operations)	$	32,378	$	133,470	$	43,486	$	51,442	$	20,429		$	24,817		$	306,022
Capital expenditures (discontinued component)	$	—	$	—	$	—	$	—	$	35,545		$	—		$	35,545

(P) QUARTERLY FINANCIAL DATA (UNAUDITED)

Total operating revenues are consistently greater during the heating season from November through March due to the large volume of natural gas sold to customers for heating. The following tables set forth the unaudited quarterly results of operations for the periods indicated.

Year Ended December 31, 2003	First Quarter			Second Quarter		Third Quarter		Fourth Quarter
	(Thousands of Dollars, except per share amounts)
Net revenues	$	402,952		$	232,436	$	194,382	$	306,708
Operating income	$	232,437		$	62,009	$	31,820	$	119,798
Income from continuing operations	$	125,607		$	22,548	$	4,595	$	61,542
Income from discontinued operations	$	2,342		$	—	$	—	$	—
Gain on sale of discontinued component	$	38,369		$	—	$	—	$	1,370
Cumulative effect of a change in accounting principle	$	(143,885	)	$	—	$	—	$	—
Net Income	$	22,433		$	22,548	$	4,595	$	62,912
Earnings per share from continuing operations
Basic	$	1.43		$	0.24	$	0.01	$	0.71
Diluted	$	1.20		$	0.23	$	0.01	$	0.65

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Year Ended December 31, 2002	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(Thousands of Dollars, except per share amounts)
Net revenues	$	294,436	$	238,637	$	208,842	$	233,745
Operating income	$	141,465	$	79,291	$	63,784	$	86,938
Income from continuing operations	$	71,693	$	32,318	$	17,376	$	34,589
Income from discontinued operations	$	905	$	3,065	$	3,343	$	3,335
Net Income	$	72,598	$	35,383	$	20,719	$	37,924
Earnings per share from continuing operations
Basic	$	0.60	$	0.27	$	0.15	$	0.30
Diluted	$	0.59	$	0.27	$	0.15	$	0.30

In the first quarter of 2002, the Company recovered $14.0 million of charges previously taken related to the Enron bankruptcy filing. In the second quarter of 2002, the Company increased operating income by $14.2 million as a result of a settlement with the OCC related to unrecovered gas costs associated with the 2000/2001 winter. For further discussion of these charges, see Note M.

(Q) SUPPLEMENTAL CASH FLOW INFORMATION

The following tables set forth supplemental information relative to the Company’s cash flows for the periods indicated.

	Years Ended December 31,
	2003			2002			2001
	(Thousands of Dollars)
Cash paid during the year
Interest (including amounts capitalized)	$	100,662		$	109,897		$	132,364
Income taxes paid (received)	$	(16,302	)	$	(90,306	)	$	13,050
Noncash transactions
Cumulative effect of changes in accounting principle
Rescission of EITF 98-10 (price risk management assets and liabilities)	$	141,832		$	—		$	—
Adoption of Statement 143	$	2,053		$	—		$	—
Dividends on restricted stock	$	279		$	209		$	128
Issuance of restricted stock, net	$	3,201		$	2,628		$	1,854
Treasury stock transferred to compensation plans	$	4,450		$	1,958		$	1,776
	Years Ended December 31,
	2003			2002			2001
	(Thousands of Dollars)
Acquisitions
Property, plant, and equipment	$	537,855		$	4,036		$	440
Current assets		70,027			—			—
Current liabilities		(60,106	)		—			—
Regulatory assets and goodwill		116,381			—			14,500
Lease obligation		(4,715	)		—			—
Deferred credits		(22,900	)		—			—
Deferred income taxes		55,858			—			—
Cash paid for acquisitions - continuing operations	$	692,400		$	4,036		$	14,940
Cash paid for acquisitions - discontinued operations	$	—		$	764		$	1,075

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(R) STOCK BASED COMPENSATION

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

Deferred Compensation Plans

Employee Non-Qualified Deferred Compensation Plan - The ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan provides select employees, as approved by the Board of Directors, with the option to defer portions of their compensation and provides non-qualified deferred compensation benefits which are not available due to limitations on employer and employee contributions to qualified defined contribution plans under the federal tax laws. Under the plan, participants have the option to defer their salary and/or bonus compensation to a short-term deferral account, which pays out a minimum of five years from commencement, or a long-term deferral account, which pays out at retirement or termination of the participant. Participants are immediately 100 percent vested. Short-term deferral accounts are allocated to the Five Year Treasury Bond Fund. Long-term deferral accounts are allocated among various investment options, including the Company’s common stock. At the distribution date, cash is distributed to the participants based on the fair market value of the investment at that date.

Deferred Compensation Plan for Non-Employee Directors - The ONEOK, Inc. Deferred Compensation Plan for Non-Employee Directors provides directors of the Company, who are not employees of the Company, the option to defer all or a portion of their compensation for their service on the Company’s Board of Directors. Under the plan, directors may elect either a cash deferral option or a phantom stock option. Under the cash deferral option, directors may defer the receipt of all or a portion of their annual retainer and/or meeting fees, plus accrued interest. Under the phantom stock option, directors may defer all or a portion of their annual retainer and/or meeting fees and receive such fees on a deferred basis in the form of shares of common stock under the Company’s Long-Term Incentive Plan. Shares are distributed to non-employee directors at the fair market value of the Company’s common stock at the date of distribution.

Long-Term Incentive Plan

General - The ONEOK, Inc. Long-Term Incentive Plan provides for the granting of incentive stock options, non-statutory stock options, stock bonus awards, restricted stock awards and performance unit awards to key employees and the granting of stock awards to non-employee directors. The Company has reserved approximately 7.8 million shares of common stock for the plan, less the number of shares previously issued under the plan. The maximum number of shares for which options or other awards may be granted to any employee or non-employee director during any year is 300,000 and 20,000, respectively.

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

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

Stock Option Plan for Non-Employee Directors - Under the plan, options may be granted by the Committee at any time on or before January 18, 2011. Options may be exercisable in full at the time of grant or may become exercisable in one or more installments. The plan also provides for restored options consistent with the plan for employees. Options issued to date become void upon termination of service as a Non-Employee Director. Such options must be exercised no later than ten

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years after the date of grant of the option. In the event of death, the option may be exercised by the personal representative of the optionee.

The following table sets forth the stock option activity for stock options under the Long-Term Incentive Plan for employees and non-employee directors for the periods indicated.

	Number of Shares		Weighted Average Exercise Price
Outstanding December 31, 2000	1,501,356		$	16.19
Granted	1,102,000		$	22.43
Exercised	(118,750	)	$	15.27
Expired	(179,672	)	$	19.57
Restored	3,538		$	22.49
Outstanding December 31, 2001	2,308,472		$	18.96
Granted	1,028,750		$	17.06
Exercised	(226,286	)	$	15.64
Expired	(120,211	)	$	19.41
Restored	72,951		$	21.01
Outstanding December 31, 2002	3,063,676		$	18.60
Granted	458,400		$	16.79
Exercised	(413,471	)	$	16.23
Expired	(25,062	)	$	20.45
Restored	134,146		$	21.33
Outstanding December 31, 2003	3,217,689		$	18.75
Options Exercisable
December 31, 2001	941,572		$	16.57
December 31, 2002	1,378,270		$	18.20
December 31, 2003	1,651,840		$	18.94

At December 31, 2003, the Company had 2,254,389 outstanding options with exercise prices ranging between $11.85 to $17.77 and a weighted average remaining life of 7.07 years. Of these options, 1,127,640 were exercisable at December 31, 2003, with a weighted average exercise price of $17.28.

The Company also had 963,300 options outstanding at December 31, 2003, with exercise prices ranging between $17.78 and $33.47 and a weighted average remaining life of 7.02 years. Of these options, 524,200 were exercisable at December 31, 2003, at a weighted average exercise price of $22.52.

Restricted Stock Awards - Under the Long-Term Incentive Plan, restricted stock awards may be granted to key officers and employees with ownership of the common stock vesting over a three-year period. Shares awarded may not be sold during the vesting period. The fair market value of the shares associated with the restricted stock awards is recorded as unearned compensation in shareholders’ equity and is amortized to compensation expense over the vesting period. The dividends on the restricted stock awards are reinvested in common stock. The average price of shares granted was $16.88, $17.05 and $22.31 for the years ended December 31, 2003, 2002 and 2001, respectively.

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Restricted stock information has been restated to give effect to the 2001 two-for-one stock split. The following table sets forth the restricted stock activity for the periods indicated.

	Number of Shares		Weighted Average Exercise Price
Outstanding December 31, 2000	114,814		$	14.55
Granted	90,400		$	22.31
Released to participants	(2,424	)	$	14.70
Forfeited	(6,676	)	$	14.70
Dividends	6,463		$	19.52
Outstanding December 31, 2001	202,577		$	18.17
Granted	156,300		$	17.05
Released to participants	(107,547	)	$	17.73
Forfeited	(1,912	)	$	18.77
Dividends	10,436		$	19.92
Outstanding December 31, 2002	259,854		$	17.74
Granted	189,900		$	16.88
Released to participants	(4,417	)	$	13.70
Forfeited	(2,686	)	$	19.15
Dividends	14,109		$	19.48
Outstanding December 31, 2003	456,760		$	17.47

Performance Share Awards - Under the Long-Term Incentive Plan, performance share awards may be granted to key officers and employees. The performance shares vest at the expiration of a three-year period after the grant date if certain performance criteria are met by the Company. Performance share units are not common stock, but may be converted into common stock if the performance criteria are met. The value of the units associated with the performance shares awards is recorded as unearned compensation in shareholders’ equity and is amortized to compensation expense over the vesting period. During 2003, the Company granted 172,900 performance share awards at a price of $16.88 per share. There were no performance share awards released to participants or forfeited during 2003.

Employee Stock Purchase Plan - The ESPP currently has 2.8 million shares reserved, less the number of shares issued to date under this plan. Subject to certain exclusions, all full-time employees are eligible to participate. Under the terms of the plan, employees can choose to have up to ten percent of their annual earnings withheld to purchase the Company’s common stock. The Committee may allow contributions to be made by other means provided that in no event will contributions from all means exceed ten percent of the employee’s annual earnings. The purchase price of the stock is 85 percent of the lower of its grant date or exercise date market price. Approximately 58 percent, 61 percent, and 56 percent of eligible employees participated in the plan in fiscal years 2003, 2002, and 2001, respectively. Under the plan, the Company sold 296,125 shares in 2003, 285,200 shares in 2002, and 192,593 shares in 2001.

Accounting Treatment - The Company applied APB 25 in accounting for the plans through 2002. Accordingly, no compensation cost was recognized in the consolidated financial statements for the Company’s stock options and the ESPP in 2002 or 2001. The Company adopted Statement 148 on January 1, 2003, and began expensing the fair value of all stock options granted on or after January 1, 2003. See Note A for disclosure of the Company’s pro forma net income and earnings per share information had the Company applied the provisions of Statement 123 to determine the compensation cost under these plans for stock options granted prior to January 1, 2003 for the periods presented.

The fair market value of each option granted was estimated on the date of grant based on the Black-Scholes model using the following assumptions: volatility of 30.3 percent for 2003, 22.1 percent for 2002, and 21.1 percent for 2001; dividend yield of 3.5 percent for 2003, 3.6 percent for 2002, and 5.5 percent for 2001; and risk-free interest rate of 4.0 percent for 2003, 5.1 percent for 2002, and 5.2 percent for 2001.

Expected life ranged from 1 to 10 years based upon experience to date and the make-up of the optionees. Fair value of options granted at fair market value under the Plan were $4.67, $3.88 and $3.17 for the years ended December 31, 2003,

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2002 and 2001, respectively. Fair value of options granted above fair market value under the Plan was $3.50 for the year ended December 31, 2001. The average exercise price of options granted above fair market value is $23.49 for the year ended December 31, 2001.

(S) EARNINGS PER SHARE INFORMATION

Through February 5, 2003, the Company computed its EPS in accordance with Topic D-95. In accordance with Topic D-95, the dilutive effect of the Company’s Series A Convertible Preferred Stock was considered in the computation of basic EPS utilizing the “if-converted” method. Under the Company’s “if-converted” method, the dilutive effect of the Company’s Series A Convertible Preferred Stock on EPS could not be less than the amount that would have resulted from the application of the “two-class” method of computing EPS. The “two-class” method is an earnings allocation formula that determined EPS for the Company’s common stock and its participating Series A Convertible Preferred Stock according to dividends declared and participating rights in the undistributed earnings. The Company’s Series A Convertible Preferred Stock was a participating instrument with the Company’s common stock with respect to the payment of dividends. For the years ended December 31, 2001 and 2002, and the period from January 1, 2003 to February 5, 2003, the “two-class” method resulted in additional dilution. Accordingly, EPS for this period reflects this further dilution. As a result of the Company’s repurchase and exchange of its Series A Convertible Preferred Stock in February 2003, the Company no longer applied the provisions of Topic D-95 to its EPS computations beginning in February 2003.

The following table sets forth the computation of basic and diluted earnings per share from continuing operations for the periods indicated.

	Year Ended December 31, 2003
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations available for common stock under D-95	$	26,174	62,055
Series A Convertible Preferred Stock dividends		12,139	39,893
Income from continuing operations available for common stock and assumed conversion of Series A Convertible Preferred Stock		38,313	101,948	$	0.37
Further dilution from applying the “two-class” method				$	(0.08	)
Basic EPS from continuing operations under D-95				$	0.29
Income from continuing operations available for common stock not under D-95		163,907	78,585	$	2.09
Basic EPS from continuing operations				$	2.38
Diluted EPS from continuing operations
Income from continuing operations available for Series D
Convertible Preferred Stock dividends		202,220	80,569
Effect of other dilutive securities:
Options and other dilutive securities		—	911
Series D Convertible Preferred Stock dividends		12,072	15,519
Income from continuing operations	$	214,292	96,999	$	2.21
Further dilution from applying the “two-class” method				$	(0.08	)
Diluted EPS from continuing operations				$	2.13

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	Year Ended December 31, 2002
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations available for common stock	$	118,876	60,022
Convertible preferred stock		37,100	39,892
Income from continuing operations available for common stock and assumed conversion of preferred stock		155,976	99,914	$	1.56
Further dilution from applying the “two-class” method					(0.25	)
Basic EPS from continuing operations				$	1.31
Effect of other dilutive securities
Options and other dilutive securities		—	614
Diluted EPS from continuing operations
Income from continuing operations available for common stock and assumed exercise of stock options	$	155,976	100,528	$	1.55
Further dilution from applying the “two-class” method					(0.25	)
Diluted EPS from continuing operations				$	1.30

	Year Ended December 31, 2001
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations available for common stock	$	41,737	59,557
Convertible preferred stock		37,100	39,892
Income from continuing operations available for common stock and assumed conversion of preferred stock		78,837	99,449	$	0.79
Further dilution from applying the “two-class” method					(0.13	)
Basic EPS from continuing operations				$	0.66
Effect of other dilutive securities
Options and other dilutive securities		—	222
Diluted EPS from continuing operations
Income from continuing operations available for common stock and assumed exercise of stock options	$	78,837	99,671	$	0.79
Further dilution from applying the “two-class” method					(0.13	)
Diluted EPS from continuing operations				$	0.66

There were 151,448, 167,116, and 158,989 option shares excluded from the calculation of diluted earnings per share for the years ended December 31, 2003, 2002 and 2001, respectively, since their inclusion would be antidilutive for each period.

The repurchase and exchange of the Company’s Series A Convertible Preferred Stock from Westar in February 2003 was recorded at fair value. In accordance with EITF Topic No. D-42, the premium, or the excess of the fair value of the consideration transferred to Westar over the carrying value of the Series A Convertible Preferred Stock, was considered a preferred dividend. The premium recorded on the repurchase and exchange of the Series A Convertible Preferred Stock was approximately $44.2 million and $53.4 million, respectively, for a total premium of $97.6 million. As a result of the Company’s adoption of Topic D-95, the Company recognized additional dilution of approximately $94.5 million through the application of the “two-class” method of computing EPS. This additional dilution offsets the total premium recorded,

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resulting in a net premium of $3.1 million, which is reflected as a dividend on the Series A Convertible Preferred Stock in the EPS calculation above for the year ended December 31, 2003.

(T) OIL AND GAS PRODUCING ACTIVITIES

The following table sets forth the Company’s historical cost information relating to its production operations for the periods indicated.

	Continuing Operations Years Ended December 31,						Discontinued Component Years Ended December 31,
	2003		2002		2001		2003		2002		2001
	(Thousands of Dollars)
Capitalized costs at end of year
Unproved properties	$	461	$	409	$	424	$	—	$	7,073	$	3,799
Gathering system		15,250		—		—		—		—		—
Proved properties (1)		385,566		143,492		122,345		—		364,461		355,643
Total capitalized costs		401,277		143,901		122,769		—		371,534		359,442
Accumulated depreciation, depletion and amortization		61,725		58,383		44,761		—		148,798		134,320
Net capitalized costs	$	339,552	$	85,518	$	78,008	$	—	$	222,736	$	225,122
Costs incurred during the year
Property acquisition costs (unproved)	$	212	$	326	$	792	$	—	$	4,118	$	1,542
Exploitation costs	$	—	$	—	$	8	$	—	$	—	$	—
Development costs	$	18,472	$	15,336	$	19,216	$	—	$	19,809	$	34,004
Purchase of minerals in place	$	240,512	$	2,899	$	1,244	$	—	$	764	$	328

(1) Proved properties includes $5.1 million for asset retirement obligations capitalized as additional costs per Statement 143.

The following table sets forth the results of the Company’s oil and gas producing operations for the periods indicated. The results exclude general office overhead and interest expense attributable to oil and gas production.

	Continuing Operations Years Ended December 31,						Discontinued Component Years Ended December 31,
	2003		2002		2001		2003		2002		2001
	(Thousands of Dollars)
Net revenues
Sales to unaffiliated customers	$	40,178	$	29,890	$	33,752	$	7,524	$	50,354	$	60,183
Gas sold to affiliates		2,860		2,456		4,108		217		13,190		22,065
Net revenues from production		43,038		32,346		37,860		7,741		63,544		82,248
Production costs		8,407		6,158		6,926		1,186		13,346		14,073
Depreciation, depletion and amortization		11,475		12,668		10,701		1,937		24,836		23,777
Taxes		8,298		5,230		7,826		1,477		9,810		17,173
Total expenses		28,180		24,056		25,453		4,600		47,992		55,023
Results of operations from producing activities	$	14,858	$	8,290	$	12,407	$	3,141	$	15,552	$	27,225

(U) OIL AND GAS RESERVES (UNAUDITED)

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

The following table sets forth estimates of the Company’s proved oil and gas reserves, net of royalty interests and changes herein, for the periods indicated.

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	Continuing Operations				Discontinued Component
	Oil     (MBbls)		Gas     (MMcf)		Oil     (MBbls)		Gas     (MMcf)
December 31, 2000	2,302		73,892		2,037		180,829
Revisions in prior estimates	(285	)	(8,190	)	(252	)	(20,043	)
Extensions, discoveries and other additions	636		9,688		562		23,709
Purchases of minerals in place	2		272		1		664
Sales of minerals in place	—		(80	)	—		(196	)
Production	(261	)	(8,000	)	(231	)	(19,578	)
December 31, 2001	2,394		67,582		2,117		165,385
Revisions in prior estimates	(399	)	(9,242	)	781		19,520
Extensions, discoveries and other additions	690		9,910		120		10,868
Purchases of minerals in place	49		869		10		197
Sales of minerals in place	—		(1	)	—		(106	)
Production	(273	)	(7,370	)	(241	)	(18,036	)
December 31, 2002	2,461		61,748		2,787		177,828
Revisions in prior estimates	(720	)	(3,832	)	—		—
Extensions, discoveries and other additions	337		12,926		—		—
Purchases of minerals in place	2,314		157,763		—		—
Sales of minerals in place	—		—		(2,734	)	(176,356	)
Production	(265	)	(7,486	)	(53	)	(1,472	)
December 31, 2003	4,127		221,119		—		—
Proved developed reserves
December 31, 2001	1,445		46,915		1,278		114,810
December 31, 2002	1,521		40,230		2,001		128,778
December 31, 2003	2,070		132,451		—		—

(V) DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

The following table sets forth estimates of the standard measure of discounted future cash flows from proved reserves of oil and natural gas for the periods indicated.

	Continuing Operations Years Ended December 31,						Discontinued Component Years Ended December 31,
	2003		2002		2001		2003		2002		2001
	(Thousands of Dollars)
Future cash inflows	$	1,453,999	$	365,637	$	195,871	$	—	$	883,816	$	473,457
Future production costs		269,779		70,574		52,024		—		173,299		112,145
Future development costs		94,579		20,934		11,787		—		23,067		24,785
Future income taxes		298,229		93,415		36,199		—		224,756		83,665
Future net cash flows		791,412		180,714		95,861		—		462,694		252,862
10 percent annual discount for estimated timing of cash flows		400,407		77,736		40,008		—		205,411		109,093
Standardized measure of discounted future net cash flows relating to oil and gas reserves	$	391,005	$	102,978	$	55,853	$	—	$	257,283	$	143,769

Future cash inflows are computed by applying year-end prices (averaging $29.78 per barrel of oil, adjusted for transportation and other charges, and $5.98 per Mcf of gas at December 31, 2003) to the year-end quantities of proved reserves. As of December 31, 2003, a portion of proved developed gas production for continuing operations in 2004 has been hedged. The effects of these hedges are not reflected in the computation of future cash flows above. If the effects of the hedges had been included, the future cash inflows would have decreased by approximately $9.6 million.

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

The following table sets forth the changes in standardized measure of discounted future net cash flow relating to proved oil and gas reserves for the periods indicated.

	Continuing Operations Years Ended December 31,									Discontinued Component Years Ended December 31,
	2003			2002			2001			2003			2002			2001
	(Thousands of Dollars)
Beginning of period	$	102,978		$	55,853		$	219,103		$	257,283		$	143,769		$	536,780
Changes resulting from:
Sales of oil and gas produced, net of production costs		(34,631	)		(26,199	)		(30,942	)		(3,818	)		(50,198	)		(68,175	)
Net changes in price, development, and production costs		7,086			62,196			(300,373	)		—			133,586			(578,330	)
Development costs incurred		18,472			15,336			23,223			—			19,809			29,997
Extensions, discoveries, additions, and improved recovery, less related costs		61,718			31,759			25,209			—			31,676			25,144
Purchases of minerals in place		363,367			2,899			468			—			764			1,104
Sales of minerals in place		—			(1	)		(7	)		(253,465	)		(322	)		(2,240	)
Revisions of previous quantity estimates		(14,796	)		(23,291	)		(42,858	)		—			49,513			(93,313	)
Accretion of discount		19,512			7,749			33,777			—			19,042			82,999
Net change in income taxes		(94,646	)		(31,583	)		99,617			—			(77,951	)		245,868
Other, net		(38,055	)		8,260			28,636			—			(12,405	)		(36,065	)
End of period	$	391,005		$	102,978		$	55,853		$	—		$	257,283		$	143,769

(W) SUBSEQUENT EVENTS (UNAUDITED)

2004 Common Stock Offering - During the first quarter of 2004, the Company sold 6.9 million shares of its common stock to an underwriter at $21.93 per share, resulting in proceeds to the Company, before expenses, of $151.3 million.

Related Party Transactions - In January 2004, the Company elected Julie H. Edwards, Executive Vice President – Finance and Administration and Chief Financial Officer for Frontier Oil Corporation and its subsidiaries (Frontier), to the board of directors. From time to time and in the normal course of business, the Company purchases natural gas liquids from and sells natural gas and natural gas liquids and provides natural gas transportation services to Frontier. The purchase and sales transactions are conducted under substantially the same terms as comparable third-party transactions.

In January 2004, the Company’s transactions with the Williford Companies increased substantially. Mollie Williford, Chairman of the Board of the Williford Companies, which consists of numerous companies including Williford Energy Company and TriCounty Gas Processors, Inc., is a member of the Company’s board of directors. In the normal course of business, the Company conducts natural gas and natural gas liquids purchase and sale transactions with Williford Energy Company and TriCounty Gas Processors, Inc. These transactions are conducted under substantially the same terms as comparable third-party transactions. All related party transactions with the Williford Companies prior to 2004 were immaterial.

Acquisition of Gulf Coast Fractionators - On February 25, 2004, the Company 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 the Company. This preferential right expires March 31, 2004. This facility has a fractionation capacity of 110 MBbls/d of mixed NGLs. As the operator, the Company 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.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not applicable.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of the Company’s Disclosure Controls - We evaluated the effectiveness of the design and operation of our disclosure controls and procedures (Disclosure Controls) as of the end of the period covered by this Annual Report on Form 10-K. This evaluation (the Disclosure Controls Evaluation) was done under the supervision and with the participation of management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO). Rules adopted by the Securities and Exchange Commission (SEC) require that in this section of this Annual Report on Form 10-K we present the conclusions of the CEO and the CFO about the effectiveness of our Disclosure Controls based on and as of the date of the Disclosure Controls Evaluation.

Disclosure Controls - Disclosure Controls are procedures that are designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934 (Exchange Act), such as this Annual Report on Form 10-K, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure Controls are also designed with the objective of ensuring that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Limitations on the Effectiveness of Controls - Our management, including the CEO and CFO, does not expect that our Disclosure Controls will prevent all errors and all fraud. A control system, including our Disclosure Controls, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based, in part, upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, some controls may become inadequate because of changes in conditions, or the degree of compliance with policies or procedures that may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Scope of the Controls Evaluation - The CEO/CFO evaluation of our Disclosure Controls included a review of the controls’ objectives and design, the controls’ implementation by us and the effect of the controls on the information generated for use in this Annual Report on Form 10-K. In the course of the Disclosure Controls Evaluation, we sought to identify data errors, control problems or acts of fraud and to confirm that appropriate corrective action, including process improvements, were being undertaken. This type of evaluation is done on a quarterly basis so that the conclusions concerning controls effectiveness can be reported in our Quarterly Reports on Form 10-Q and our Annual Report on Form 10-K. The overall goals of these evaluation activities are to monitor our Disclosure Controls and to make modifications as necessary. Our intent in this regard is that the Disclosure Controls will be maintained as dynamic systems that change (including with improvements and corrections) as conditions warrant.

Since the date of the Disclosure Controls Evaluation to the date of this Annual Report on Form 10-K, there have been no significant changes in our internal controls or in other factors that could significantly affect our internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses.

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Conclusions - Based upon the Disclosure Controls Evaluation, our CEO and CFO have concluded that, subject to the limitations noted above, our Disclosure Controls are effective in providing reasonable assurance of achieving their objective of timely alerting them to material information required to be disclosed by us in periodic reports we file with the SEC.

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PART III.

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS, AND CONTROL PERSONS OF THE REGISTRANT

Directors of the Registrant

Information concerning the directors of the Company is set forth in our 2004 definitive Proxy Statement and is incorporated herein by this reference.

Executive Officers of the Registrant

Information concerning the executive officers of the Company is included in Part I, Item 1. Business, of this Annual Report on Form 10-K.

Compliance with Section 16(a) of the Exchange Act

Information on compliance with Section 16(a) of the Exchange Act is set forth in our 2004 definitive Proxy Statement and is incorporated herein by this reference.

Code of Ethics

Information concerning the code of ethics, or code of business conduct, is set forth in our 2004 definitive Proxy Statement and is incorporated herein by this reference.

Nominating Committee Procedures

Information concerning the nominating committee procedures is set forth in our 2004 definitive Proxy Statement and is incorporated herein by this reference.

ITEM 11. EXECUTIVE COMPENSATION

Information on executive compensation is set forth in our 2004 definitive Proxy Statement and is incorporated herein by this reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Security Ownership of Certain Beneficial Owners

Information concerning the ownership of certain beneficial owners is set forth in our 2004 definitive Proxy Statement and is incorporated herein by this reference.

Security of Ownership of Management

Information on security ownership of directors and officers is set forth in our 2004 definitive Proxy Statement and is incorporated herein by this reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information on certain relationships and related transactions is set forth in our 2004 definitive Proxy Statement and is incorporated herein by this reference.

ITEM 14. PRINCIPAL ACCOUNTANT’S FEES AND SERVICES

Information concerning the principal accountant’s fees and services is set forth in our 2004 definitive Proxy Statement and is incorporated herein by this reference.

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PART IV.

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

Documents Filed as Part of this Report

(1)	Exhibits
	3	Certificate of Incorporation of WAI, Inc. (now ONEOK, Inc.) filed May 16, 1997 (incorporated by reference from Exhibit 3.1 to Amendment No. 3 to Registration Statement on Form S-4, filed August 6, 1997, Commission File No. 333-27467).
	3.1	Certificate of Merger of ONEOK, Inc. (formerly WAI, Inc.) filed November 26, 1997 (incorporated by reference from Exhibit (1)(b) to Form 10-Q dated May 31, 1998).
	3.2	Amended Certificate of Incorporation of ONEOK, Inc. filed January 16, 1998 (incorporated by reference from Exhibit (1)(b) to Form 10-Q dated May 31, 1998).
	3.3	Amendment to Certificate of Incorporation of ONEOK, Inc. filed May 23, 2001 (incorporated by reference from Exhibit 4.6 to Registration Statement on Form S-3, as amended, Commission File No. 333-65392).
	3.4	Certificate of Decrease of $0.925 Series D Non-Cumulative Convertible Preferred Stock (Par Value $0.01) of ONEOK, Inc., filed October 2, 2003.
	3.5	Certificate of Retirement of $0.925 Series D Non-Cumulative Convertible Preferred Stock (Par Value $0.01) of ONEOK, Inc., filed January 6, 2004.
	3.6	Bylaws of ONEOK, Inc.
	4	Certificate of Designation for Convertible Preferred Stock of WAI, Inc. (now ONEOK, Inc.), filed November 26, 1997 (incorporated by reference from Exhibit 3.3 to the Company’s Amendment No 3. to Registration Statement on Form S-4, filed August 31, 1997, Commission File No. 333-27467).
	4.1	Certificate of Designation for Series C Participating Preferred Stock of ONEOK, Inc., filed November 26, 1997 (incorporated by reference from Exhibit No. 1 to Form 8-A, filed November 26, 1997).
	4.2	Form of Common Stock Certificate (incorporated by reference from Exhibit 1 to the Company’s Registration Statement on Form 8-A filed November 21, 1997).
	4.3	Rights agreement, dated November 26, 1997, between ONEOK, Inc. and Liberty Bank and Trust Company of Oklahoma City, N.A., as Rights Agent (incorporated by reference from Exhibit 2.3 to Registration Statement on Form S-4, as amended, Commission File No. 333-27467).
	4.4	Indenture, dated September 24, 1998, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 4.1 to Registration Statement on Form S-3 filed August 26, 1998).

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4.5	Indenture dated December 28, 2001, between ONEOK, Inc. and SunTrust Bank (incorporated by reference from Exhibit 4.1 to Registration Statement on Form S-3 as amended, Commission File No. 333-65392).
4.6	First Supplemental Indenture dated September 24, 1998, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 5(a) to Form 8-K filed September 24, 1998).
4.7	Second Supplemental Indenture dated September 25, 1998, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 5(b) to Form 8-K filed September 24, 1998).
4.8	Third Supplemental Indenture dated February 8, 1999, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 4 to Form 8-K filed February 8, 1999).
4.9	Fourth Supplemental Indenture dated February 17, 1999, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 4.5 to Registration Statement on Form S-3 filed April 15, 1999, Commission File No. 333-76375).
4.10	Fifth Supplemental Indenture dated August 17, 1999, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 4 to Form 8-K filed August 17, 1999).
4.11	Sixth Supplemental Indenture dated March 1, 2000, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from the Registration Statement on Form S-4 filed March 13, 2000, Commission File No. 333-32254).
4.12	Seventh Supplemental Indenture dated April 24, 2000, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 4 to Form 8-K filed April 24, 2000).
4.13	Eighth Supplemental Indenture dated April 6, 2001, between ONEOK, Inc. and The Chase Manhattan Bank (incorporated by reference from Exhibit 4.9 to Registration Statement on Form S-3 filed July 18, 2001, Commission File No. 333-65392).
4.14	First Supplemental Indenture, dated as of January 28, 2003, between ONEOK, Inc. and SunTrust Bank (incorporated by reference from Exhibit 4.22 to Form 8-A/A filed January 30, 2003).
4.15	Form of Senior Note Due 2008 (included in Exhibit 4.14).
4.16	Certificate of Designation for $0.925 Series D Non-Cumulative Convertible Preferred Stock of ONEOK, Inc. (incorporated by reference from Exhibit 4.16 to Form 10-K, filed on March 10, 2003).
4.17	Purchase Contract Agreement, dated January 28, 2003, between ONEOK, Inc. and SunTrust Bank, as Purchase Contract Agent (incorporated by reference from Exhibit 4.3 to Form 8-A/A filed January 30, 2003).
4.18	Form of Corporate Unit (included in Exhibit 4.17).
4.19	Pledge Agreement, dated January 28, 2003, among ONEOK, Inc., SunTrust Bank, as Collateral Agent, Custodial Agent and Securities Intermediary, and SunTrust Bank, as Purchase Contract Agent (incorporated by reference from Exhibit 4.4 to Registration Statement on Form 8-A/A filed January 30, 2003).

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4.20	Remarketing Agreement, dated January 28, 2003, among ONEOK, Inc., UBS Warburg LLC, Banc of America LLC and J.P. Morgan Securities Inc. and SunTrust Bank, as Purchase Contract Agent (incorporated by reference from Exhibit 4.5 to Registration Statement on Form 8-A/A filed January 30, 2003).
4.21	Form of $0.925 Series D Non-Cumulative Convertible Preferred Stock Certificate (incorporated by reference from Exhibit 4.1 to Form 8-K dated February 6, 2003).
4.22	Amended and Restated Rights Agreement dated as of February 5, 2003, between ONEOK, Inc. and UMB Bank, N.A., as Rights Agent (incorporated by reference from Exhibit 1 to Registration Statement on Form 8-A/A (Amendment No. 1), dated February 5, 2003).
10	ONEOK, Inc. Long-Term Incentive Plan (incorporated by reference from Exhibit 10(a) to Form 10-K dated December 31, 2001).
10.1	ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors (incorporated by reference from Exhibit 99 to Form S-8 filed January 24, 2001).
10.2	ONEOK, Inc. Supplemental Executive Retirement Plan as amended and restated February 21, 2002 (incorporated by reference from Exhibit 10(c) to Form 10-K, dated December 31, 2001).
10.3	Termination Agreements between ONEOK, Inc. and ONEOK, Inc. executives, as amended, dated February 12, 2001 (incorporated by reference from Exhibit 10.3 to Form 10-K dated December 31, 2002).
10.4	Indemnification Agreement between ONEOK, Inc. and ONEOK, Inc. officers and directors, as amended, dated February 15, 2001 (incorporated by reference from Exhibit 10.4 to Form 10-K dated December 31, 2002).
10.5	ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference from Exhibit 10(f) to Form 10-K dated December 31, 2001).
10.6	ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan, as amended and restated February 15, 2001 (incorporated by reference from Exhibit 10(g) to Form 10-K dated December 31, 2001).
10.7	ONEOK, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated November 19, 1998 (incorporated by reference from Exhibit 10.7 to Form 10-K dated December 31, 2002).
10.8	Ground Lease between ONEOK Leasing Company and Southwestern Associates dated May 15, 1983 (incorporated by reference from Form 10-K dated August 31, 1983).
10.9	First Amendment to Ground Lease between ONEOK Leasing Company and Southwestern Associates dated October 1, 1984 (incorporated by reference from Form 10-K dated August 31, 1984).
10.10	Sublease between RMZ Corp. and ONEOK Leasing Company dated May 15, 1983 (incorporated by reference from Form 10-K dated August 31, 1984).

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10.11	First Amendment to Sublease between RMZ Corp. and ONEOK Leasing Company dated October 1, 1984 (incorporated by reference from Form 10-K dated August 31, 1984).
10.12	ONEOK Leasing Company Lease Agreement with Oklahoma Natural Gas Company dated August 31, 1984 (incorporated by reference from Form 10-K dated August 31, 1985).
10.13	$850,000,000 364-Day Credit Agreement dated September 23, 2002 among ONEOK, Inc. as Borrower and Bank of America, N.A. as Administrative Agent, Lender and Letter of Credit Issuing Lender; Bank One, N.A. and Wachovia Bank, N.A. as Co-Syndication Agents and ABN Amro Bank, N.V. and Citibank, N.A. as Co-Documentation Agents (incorporated by reference from Exhibit 10.1 to Form 8-K dated September 25, 2002).
10.14	Transaction Agreement dated January 9, 2003, among ONEOK, Inc., Westar Energy, Inc. and Westar Industries, Inc. (incorporated by reference from Exhibit 10.1 to Form 8-K filed January 10, 2003).
10.15	Shareholder Agreement dated January 9, 2003, among ONEOK, Inc., Westar Energy, Inc. and Westar Industries, Inc. (incorporated by reference from Exhibit 10.2 to Form 8-K filed January 10, 2003).
10.16	Amendment No. 1 to Shareholder Agreement, dated February 5, 2003, among ONEOK, Inc., Westar Energy, Inc. and Westar Industries, Inc. (incorporated by reference from Exhibit 10.2 to Form 8-K dated February 6, 2003).
10.17	Registration Rights Agreement dated January 9, 2003, among ONEOK, Inc., Westar Energy, Inc. and Westar Industries, Inc. (incorporated by reference from Exhibit 10.3 to Form 8-K filed January 10, 2003).
10.18	Stock Purchase Agreement, dated February 5, 2003, among ONEOK, Inc., Westar Energy, Inc. and Westar Industries, Inc. (incorporated by reference from Exhibit 10.2 to Form 8-K dated February 6, 2003).
10.19	Registration Rights Agreement dated March 1, 2000, among the Company and the Initial Purchaser described therein (incorporated by reference from the Registration Statement on Form S-4 filed March 13, 2000).
10.20	Shareholder Agreement, dated November 26, 1997, between Western Resources, Inc. and ONEOK, Inc. (incorporated by reference from Exhibit 2.2 to Registration Statement on Form S-4, as amended, Commission File No. 333-27467).
10.21	Form of Registration Rights Agreement, dated November 26, 1997, between Western Resources, Inc. and ONEOK, Inc. (incorporated by reference from Exhibit 3.4 to the Company's Registration Statement on Form S-4, as amended, Commission File No. 333-27467).
10.22	Transaction Agreement dated August 4, 2003, among ONEOK, Inc., Westar Energy, Inc. and Westar Industries, Inc (incorporated by reference from Exhibit 10.1 to Form 8-K filed on August 5, 2003).
10.23	First Amendment to Credit Agreement dated March 14, 2003 (incorporated by reference from Exhibit 10 to the Form 10-Q filed May 5, 2003).

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10.24	Purchase and Sale Agreement between Wagner & Brown, Ltd. and ONEOK Energy Resources Holdings, Inc. dated as of October 28, 2003 (incorporated by reference from Exhibit 10 to the Form 10-Q filed November 5, 2003).
10.25	364-Day Credit Agreement dated September 22, 2003, among ONEOK, Inc., Bank of America, N.A., as Administrative Agent and L/C Issuer, Bank One, NA, Wachovia Bank, National Association, ABN AMRO Bank N.V., Citibank, N.A., The Royal Bank of Scotland PLC, Suntrust Bank, UBS AG, Cayman Islands Branch, Bank of Oklahoma, N.A., JPMorgan Chase Bank, WESTLB AG, New York Branch, KBC Bank N.V., Sumitomo Mitsui Banking Corporation, Union Bank of California, N.A., UMB Bank, N.A., and ARVEST Bank (incorporated by reference from Exhibit 10.1 to the Form 8-K filed September 23, 2003).
12 (a)	Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements for the years ended December 31, 2003, 2002, and 2001.
12 (b)	Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements for the years ended December 31, 2000 and August 31, 1999 (incorporated by reference from Exhibit (12) to the Form 10-K filed March 26, 2001).
12 (c)	Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements for the four months ended December 31, 1999 (incorporated by reference from Exhibit (12.1) to the Form 10-K filed March 26, 2001).
12.1 (a)	Computation of Ratio of Earnings to Fixed Charges for the years ended December 31, 2003, 2002, and 2001.
12.1 (b)	Computation of Ratio of Earnings to Combined Fixed Charges for the years ended December 31, 2000 and August 31, 1999 (incorporated by reference from Exhibit (12) (a) to the Form 10-K filed March 26, 2001).
12.1 (c)	Computation of Ratio of Earnings to Combined Fixed Charges for the four months ended December 31, 1999 (incorporated by reference from Exhibit (12) (a.1) to the Form 10-K filed March 26, 2001).
21	Required information concerning the registrant’s subsidiaries.
23	Independent Auditors’ Consent.
31.1	Certification of David L. Kyle pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Jim Kneale pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of David L. Kyle pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).
32.2	Certification of Jim Kneale pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).

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(2)	Financial Statements		Page No.
	(a)	Independent Auditors’ Report	54
	(b)	Consolidated Statements of Income for the years ended December 31, 2003, 2002 and 2001.	55
	(c)	Consolidated Balance Sheets as of December 31, 2003 and 2002.	56-57
	(d)	Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001.	58
	(e)	Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2003, 2002, and 2001.	60-63
	(f)	Notes to Consolidated Financial Statements	64-104
(3)	Financial Statement Schedules
	All schedules have been omitted because of the absence of conditions under which they are required.

Reports on Form 8-K

We filed the following Current Reports on Form 8-K during the fourth quarter of fiscal year 2003:

October 3, 2003 – Announced that some information furnished to industry publications was inaccurate. This information was discovered as a result of an ongoing investigation being conducted by the Commodity Futures Trading Commission (CFTC).

October 10, 2003 – Announced request to the Oklahoma Corporation Commission to allow ONG to recover costs.

October 28, 2003 – Announced that the Company’s wholly owned subsidiary, ONEOK Energy Resources Company, has agreed to acquire approximately $240 million of East Texas gas and oil properties and related gathering systems from Wagner & Brown, Ltd. of Midland, TX.

October 30, 2003 – Furnished the Company’s results of operations for the quarter ended September 30, 2003.

November 21, 2003 – Announced Westar Energy sold all of its remaining equity in the Company.

December 19, 2003 – Announced earnings guidance for 2004.

December 22, 2003 – Announced that the Company’s wholly owned subsidiary, ONEOK Energy Resources Company, has completed the acquisition of approximately $240 million of East Texas gas and oil properties and related gathering systems from Wagner & Brown, Ltd. of Midland, TX.

December 30, 2003 – Announced that the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries is subject to a “blackout period,” as defined in Regulation BTR (Blackout Trading Restriction), in connection with the change in one of the investment funds available to participants in the plan.

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Signatures

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

	ONEOK, Inc.
	Registrant
Date: March 3, 2004	By:	/s/Jim Kneale
		Jim Kneale
		Senior Vice President, Treasurer and
		Chief Financial Officer
		(Principal Financial Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated and on this 3rd day of March 2004.

/s/ David L. Kyle	/s/ Beverly Monnet
David L. Kyle	Beverly Monnet
Chairman of the Board,	Vice President and Controller
Chief Executive Officer and Director
/s/ William M. Bell	/s/ Douglas A. Newsom
William M. Bell	Douglas A. Newsom
Director	Director
/s/ William L. Ford	/s/ Gary D. Parker
William L. Ford	Gary D. Parker
Director	Director
/s/ Bert H. Mackie	/s/ J. D. Scott
Bert H. Mackie	J.D. Scott
Director	Director
/s/ Pattye L. Moore
Pattye L. Moore	Mollie B. Williford
Director	Director
Julie H. Edwards	James C. Day
Director	Director

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