For the fiscal year ended December 31, 2004

10-K 1 d10k.htm FOR THE FISCAL YEAR ENDED DECEMBER 31, 2004 For the fiscal year ended December 31, 2004

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, 2004.

¨	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, 2004, was $2,264.5 million.

On March 2, 2005, the Company had 104,204,049 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 19, 2005.

Part III

ONEOK, Inc.

2004 ANNUAL REPORT ON FORM 10-K


		Page No.
Part I.

Item 1.	Business	3-15

Item 2.	Properties	15-19

Item 3.	Legal Proceedings	19-21

Item 4.	Submission of Matters to a Vote of Security Holders	21

Part II.

Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters	22-24

Item 6.	Selected Financial Data	25

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	25-55

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	55-57

Item 8.	Financial Statements and Supplementary Data	58-109

Item 9.	Changes in and Disagreements with Accountants On Accounting and Financial Disclosures	109

Item 9A.	Controls and Procedures	109-110

Item 9B.	Other Information	110

Part III.

Item 10.	Directors and Executive Officers of the Registrant	111

Item 11.	Executive Compensation	111

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	111

Item 13.	Certain Relationships and Related Transactions	111

Item 14.	Principal Accountant Fees and Services	112

Part IV.

Item 15.	Exhibits and Financial Statement Schedules	113-118

Signatures		119

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.

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, Inc. is a diversified energy company. We purchase, gather, process, transport, store, and distribute natural gas. We drill for and produce natural gas and oil; extract, fractionate, store, transport, sell and market natural gas liquids (NGLs); and are engaged in natural gas, crude oil, NGLs and power physical marketing, retail marketing and trading activities. We are the largest natural gas distributor in Oklahoma and Kansas 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; Kansas City, Wichita, and Topeka, Kansas; and Austin and El Paso, Texas. Our energy services operations provide services 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
Mwh		Megawatt hour

Strategy

Our business strategy is focused on the maximization of shareholder value by integrating our natural gas business operations. 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.

Significant Acquisitions and Divestitures

Acquisition of Northern Plains Natural Gas Company - In November 2004, we acquired Northern Plains Natural Gas Company and its wholly owned subsidiary Pan Border Gas Company (collectively, Northern Plains), which own 82.5 percent of the general partnership interest and 500,000 limited partnership units, together representing a 2.73 percent ownership interest, in Northern Border Partners, from CCE Holdings, LLC for $175 million.

Sale of Transmission and Gathering Pipelines and Compression Facilities - In March 2004, we sold certain natural gas transmission and gathering pipelines and compression facilities for approximately $13 million.

Acquisition of Properties of Wagner & Brown, Ltd. - In December 2003, we acquired 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 Facilities - 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 Production Assets - In January 2003, we sold 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. 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 - In January 2003, we acquired 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 557,000 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 included 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 assets relating to the propane distribution operations were sold in May and July 2004 and the natural gas distribution investments in Mexico were sold in May 2004. Texas Gas Service operated these assets.

Sale of Midstream Natural Gas Assets - In December 2002, we sold 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 gas and oil 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.

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 NGLs, or at any facility 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 six sites with regulatory closure achieved at two of these locations, and have begun assessments at the remaining sites. The site situations are not similar and we have no previous experience with similar remediation efforts. We have completed some analysis of the remaining six sites, but are unable to accurately estimate individual or aggregate costs to satisfy our remedial obligations.

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, was approximately $700,000. Total remedial costs for each of the remaining sites are expected to exceed $500,000 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 to date have not been significant in relation to the results of operations and there were no material effects upon earnings during 2004 related to compliance with environmental regulations.

Employees

We employed 4,627 people at February 28, 2005. The acquisition of Northern Plains, a general partner of Northern Border Partners, added approximately 430 employees to our workforce in 2004 and the acquisition of our Texas assets added approximately 735 employees to our workforce in 2003. At February 28, 2005, Kansas Gas Service employed 818 people who were subject to collective bargaining contracts and we had no other union employees. The following table sets forth our contracts with unions at February 28, 2005.


Union	Employees	Contract Expires
United Steelworkers of America	443	June 30, 2009
International Union of Operating Engineers	14	June 30, 2009
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	June 30, 2009
International Brotherhood of Electrical Workers	351	June 30, 2006

SEC Filings

We file annual, quarterly and current 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 and equity units are 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 Directors 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

•

Energy Services

•

Other

See Note N of Notes to Consolidated Financial Statements in this Form 10-K for sales to unaffiliated customers, operating income and total assets by business segment.

Production

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

General - Operating income from the Production segment is 9.7 percent, 3.6 percent, and 2.8 percent of our consolidated operating income from continuing operations in 2004, 2003, and 2002, respectively. The Production segment has no single external customer from which it receives ten percent or more of consolidated revenues.

We focus on developmental drilling activities rather than exploratory drilling. As a result of our strategy to grow through acquisitions and developmental drilling, the number of wells we operate increases as we grow our producing reserves. We also 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, which are costs incurred to extract natural gas and oil. We strive to reduce finding costs, which is the cost per Mcfe of adding proved reserves through drilling, and 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.

Producing Reserves - Our Production segment primarily focuses on natural gas production activities. We own interests in 885 gas wells and 90 oil wells located in Oklahoma and Texas. A number of these wells produce from multiple zones. Production for 2004 compared to 2003 increased as a result of a full year of production from the Texas gas and oil producing properties acquired in December 2003. New production from the acquired properties was partially offset by the natural decline in production from wells owned prior to the acquisition. During 2004, we participated in drilling 70 wells, which included 66 producing gas wells, three producing oil wells and one dry hole.

Market Conditions and Business Seasonality - Our goal is to continue to build on and maintain our existing reserve base through developmental drilling. Natural gas prices were generally stronger during 2004 than in prior years. This resulted in increased drilling activity.

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 2004, our gas and oil production was sold at market prices to affiliated and unaffiliated companies.

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. Oil prices in the United States are also impacted by international production and export policies.

Risk Management - We utilized derivative instruments in 2004 to hedge anticipated sales of natural gas and oil production. 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 is engaged in the gathering, processing and marketing of natural gas and fractionation, storage, transportation and marketing of NGLs primarily through its two main subsidiaries, ONEOK Field Services and ONEOK NGL Marketing. These activities are conducted primarily in Oklahoma, Kansas and Texas.

General - Operating income from the Gathering and Processing segment is 26.7 percent, 14.1 percent, and 8.9 percent of our consolidated operating income from continuing operations in 2004, 2003, and 2002, respectively. The Gathering and Processing segment has no single external customer from which it receives ten percent or more of consolidated revenues.

We have active processing capacity of approximately 1.8 Bcf/d. We own approximately 13,800 miles of gathering pipelines that supply gas to our processing plants.

The gathering and processing operations include the gathering of natural gas produced from gas and oil wells. Through gathering systems, these volumes are aggregated into sufficient volumes which can be processed to remove water vapor,

solids and other contaminants and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. When the liquids are separated from the raw natural gas at the processing plants, the liquids are generally in the form of a mixed NGL stream. This mixed stream is then separated by a distillation process, referred to as fractionation, into component products (ethane, propane, isobutane, normal butane and natural gasoline) by third party and company-owned fractionation facilities. The component products can then be stored, transported and marketed to a diverse customer base of end-users.

We generally gather and process gas under three types of contracts. Factors influencing the contract mix at a particular plant include, among other things:

•

the Btu content of the gas, which determines if NGLs must be extracted from the natural gas to meet commercial pipeline specifications,

•

the term of the gas supply contracts behind a processing plant, and

•

the prevailing competitive factors when the contracts are negotiated.

Characteristics of the contract types are explained below.

•

Keep Whole - Under a keep whole contract, we extract NGLs and return to the producer volumes of merchantable natural gas containing the same amount of Btus as the raw natural gas that was delivered to us. We retain the NGLs as our fee for processing. Accordingly, we must purchase and return to the producer sufficient volumes of merchantable natural gas to replace the Btus that were removed as NGLs through the gathering and processing operation, commonly referred to as “shrink”. By using this contract type, the producer is kept whole on a Btu basis. This type of contract exposes us to the keep whole spread, or gross processing spread, which is the relative difference in the economic value between NGLs and natural gas on a Btu basis.

•

Percent of Proceeds (POP) - Under a POP contract, we retain a percentage of the NGLs and/or a percentage of the natural gas as payment for gathering, compressing and processing the producer’s raw natural gas. The producer may take its share of the NGLs and natural gas in kind or receive its share of proceeds from our sale of the commodities. We also have POP contracts that have an associated fee contract for providing services such as gathering, dehydration, compression and treating. The POP contract exposes us to both natural gas and NGL commodity price risk, but economically aligns us with the producer because we both benefit from higher commodity prices.

•

Fee - Under a fee contract, we are paid a fee for the services provided such as Btus gathered, compressed and/or processed. The wellhead volume and fees received for the services provided are the main components of the margin for this type of contract. The producer may take its NGLs and natural gas in kind or receive its proceeds from our sale of the commodities. This type of contract exposes us to minimal commodity price risk.

We have been successful in amending some of our keep whole contracts to allow us to charge conditioning fees for processing when the keep whole spread is negative. This amendment helps mitigate the impact of an unfavorable keep whole spread by effectively converting a keep whole contract to a fee contract during periods of negative keep whole spread. Additionally, we modify plant operations to take advantage of market conditions. By changing the temperatures and pressures at which the gas is processed, we can produce more of the specific commodities that have the most favorable prices or price spread. These strategies are used to improve the net margin generated by this segment.

We are exposed to volume risk from both a competitive and a production standpoint. We are impacted by producer drilling activity, which is sensitive to geological success as well as capital and commodity prices. We continue to see declines in the fields that supply our gathering and processing operations and the possibility exists that declines may surpass development from new drilling.

ONEOK NGL Marketing sells our NGL production and also purchases NGLs from third parties for resale to a diverse base of customers. We have 89 MBbls/d of mid-continent NGL fractionation capacity. We own and operate two NGL storage facilities in Kansas, with a combined storage capacity of 16 MMBbls, which provide both long- and short-term storage services. The storage facilities have truck and rail loading facilities and have direct pipeline interconnects with the key NGL pipelines, NGL storage facilities and refiners in the mid-continent region. The results of our storage operations are impacted by:

•

NGL supply and demand requirements of regional refineries,

•

NGL production in the mid-continent, Rockies and Canada,

•

Midwest demand for propane,

•

the petrochemical industry’s level of capacity utilization and specific feedstock requirements,

•

efficiency and reliability of operations, and

•

the delivery capabilities that exist at each location.

The main factors that affect our ONEOK NGL Marketing margins are:

•

the fees charged for storage,

•

transportation and fractionation costs,

•

fees for marketing services, and

•

margins on NGL sales.

Market Conditions and Business Seasonality - During the year, both crude oil and natural gas prices were volatile, with New York Mercantile Exchange (NYMEX) crude oil prices ranging from $33.02 to $54.92 per Bbl and NYMEX natural gas prices ranging from $5.08 to $7.98 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:

•

producer drilling activity, which is sensitive to commodity prices and availability of capital,

•

petrochemical industry’s level of capacity utilization and their specific feedstock requirements,

•

fees charged under the contract,

•

pressures maintained on the gathering systems,

•

location of our gathering systems relative to competition,

•

efficiency and reliability of the operations, and

•

delivery capabilities that exist at each plant location for residue gas and NGLs.

We have responded to these industry conditions by primarily acquiring assets that are strategically located near our existing assets, making capital investments to improve plant processing flexibility, constructing NGL pipelines, reducing costs, selling assets in non-core operating areas and renegotiating unprofitable contracts. The principal goal of the contract renegotiation effort is to eliminate unprofitable contracts and improve margins, primarily when the keep whole spread is negative.

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 isobutane 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 Federal Energy Regulatory Commission (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 NGLs 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.

Risk Management - Derivative instruments can be used to minimize volatility in NGL, condensate and natural gas prices. Accordingly, we use derivative instruments to hedge the cash flows generated by the purchase and sale of natural gas, condensate and NGLs used for, or produced by, our operations. We use physical forward sales and derivative instruments to secure a certain price for natural gas, condensate and NGL products. The processing spread on our keep whole contracts may be hedged with a combination of derivative instruments and physical forward sales. 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 some gas gathering services. These operations are primarily conducted through ONEOK Gas Transportation, ONEOK WesTex Transmission, ONEOK Gas Storage, ONEOK Texas Gas Storage, ONEOK Gas Gathering, ONEOK Transmission, and Mid Continent Market Center. The Texas Railroad Commission (RRC) regulates both ONEOK Texas Gas Storage and ONEOK WesTex Transmission. ONEOK Gas Storage operates under market-based rate authority granted by the FERC. Mid Continent Market Center’s and ONEOK Gas Transportation’s operations are regulated by the Kansas Corporation Commission (KCC) and the Oklahoma Corporation Commission (OCC), respectively.

General - Operating income from the Transportation and Storage segment is 12.2 percent, 11.4 percent, and 14.4 percent of our consolidated operating income from continuing operations in 2004, 2003, and 2002, respectively. The Transportation and Storage segment has no single external customer from which it receives ten percent or more of consolidated revenues.

We own storage facilities with a working storage capacity of approximately 59.6 Bcf, of which 8.0 Bcf is temporarily idle, and approximately 5,600 miles of intrastate pipeline.

In Oklahoma, we operate both transmission and gathering pipelines and storage facilities connected to our transmission pipelines. We have access to the major natural gas producing areas in Oklahoma allowing for gas to be moved throughout the state. In Kansas, we have access to the major natural gas producing area in south central Kansas. In Texas, we are connected to the major natural gas producing areas in the Texas Panhandle and the Permian Basin, providing for gas to be moved to the Waha Hub where other pipelines may be accessed for transportation east to the Houston Ship Channel market and west to the California market.

The majority of the Transportation and Storage segment’s revenues are derived from services provided to affiliates.

Market Conditions and Seasonality - The Transportation and Storage segment primarily serves local distribution companies (LDCs), large industrial companies, irrigation customers, power generation facilities and marketing companies. We compete directly with other intrastate and interstate pipelines and storage facilities. Competition for transportation services continues to increase as the FERC and state regulatory bodies continue to encourage more competition in the natural gas markets. Factors that affect competition are location, natural gas prices, fee for services and quality of services provided. We believe that our transportation and storage assets enable us to compete effectively.

Our business is affected by the economy, price volatility and weather. The strength of the economy has a direct relationship on manufacturing and the resulting demand for natural gas used in the manufacturing process. Transportation throughput fluctuates due to rainfall that impacts irrigation demand, hot temperatures that affect power generation demand and cold temperatures that affect heating demand. Volatility in the natural gas market also impacts our customers’ decisions relating to injection and withdrawal of natural gas in storage.

Government Regulation - Our transportation assets in Oklahoma, Kansas and Texas are regulated by the OCC, KCC and RRC, 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 RRC.

In January 2001, our 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, which idled 3 Bcf of our storage capacity. In April 2004, we entered into a Consent Order with the KDHE. As a part of the Consent Order, we are to conduct an environmental remediation and a geoengineering study.

Customers - The Transportation and Storage segment serves affiliated companies in the Distribution and Energy Services segments, as well as a number of commercial, industrial, power generation and fertilizer transporters.

Oklahoma Natural Gas and Kansas Gas Service are the Transportation and Storage segment’s major customers for intrastate natural gas pipeline transportation in Oklahoma and Kansas. Capacity in the storage facilities is leased to ONEOK Energy Services, Oklahoma Natural Gas, Kansas Gas Service and third parties under terms determined by contract or the market.

Distribution

Segment Description - Our Distribution segment provides natural gas distribution services to approximately 2 million customers in Oklahoma, Kansas, and Texas. Operations are conducted through Oklahoma Natural Gas, Kansas Gas Service, and Texas Gas Service, which serve residential, commercial, industrial and transportation customers in all three states. In Oklahoma and Kansas, we also serve wholesale customers and in Texas, we also serve public authority customers. This segment also includes an interstate gas transportation company, OkTex Pipeline.

General - Operating income from the Distribution segment is 22.5 percent, 26.4 percent, and 25.6 percent of the consolidated operating income from continuing operations in 2004, 2003, and 2002, respectively. The Distribution segment has no single external customer from which it receives ten percent or more of consolidated revenues.

In 2004, Oklahoma Natural Gas delivered natural gas to approximately 808,000 customers in 328 communities in Oklahoma. Oklahoma Natural Gas’ largest markets are the Oklahoma City and Tulsa metropolitan areas. Oklahoma Natural Gas also sells natural gas to other local gas distributors serving 40 Oklahoma communities.

In 2004, Kansas Gas Service supplied natural gas to approximately 644,000 customers in 333 communities in Kansas. It also makes wholesale delivery to 16 customers. Kansas Gas Service’s largest markets served include Kansas City, Wichita, and Topeka.

In 2004, Texas Gas Service delivered natural gas to approximately 557,000 customers in 181 communities in Texas. Texas Gas Service’s largest markets served include Austin and El Paso.

On July 1, 2004, Kansas Gas Service and the United Steelworkers of America Locals 12561, 13417, and 14228, the Gas Workers Metal Trades of the United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada Local 781 and the International Union of Operating Engineers Local 126 labor unions agreed to a five-year contract expiring June 30, 2009. Approximately 467 Kansas Gas Service employees are members of these three labor unions, comprising approximately 41 percent of the Kansas Gas Service workforce. The parties agreed to a three percent wage increase effective June 1, 2004 and an increase for each of the next four years as follows:

•

three percent beginning July 1, 2005

•

two and one-half percent beginning July 1, 2006

•

two and one-half percent beginning July 1, 2007

•

two and one-half percent beginning July 1, 2008

In 2003, Kansas Gas Service and the International Brotherhood of Electrical Workers labor union entered into a three-year bargaining agreement expiring June 30, 2006. Approximately 351 of our Kansas Gas Service employees are members of this labor union, comprising approximately 31 percent of our Kansas Gas Service 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.

Currently, we have no ongoing labor negotiations and there are no other unions representing our employees.

Gas Supply - Gas supplies available to Oklahoma Natural Gas 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. Oklahoma Natural Gas has access to all of the major gas producing areas in Oklahoma through transmission systems belonging to affiliated and nonaffiliated entities. A majority of Oklahoma Natural Gas’ 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 Oklahoma Natural Gas’ gas supply and gas transportation needs has been met by two affiliates, ONEOK Energy Services for supply and ONEOK Gas Transportation for upstream transportation service. A portion of the supply contracts expire in 2005. We anticipate renewing or replacing these contracts through a competitive bid process.

Oklahoma Natural Gas has reserved storage capacity of 0.9 Bcf with Southern Star Central Gas Pipeline, Inc. (Southern Star), 5.4 Bcf with an affiliate, and another 4.0 Bcf of additional storage with OGE Energy Resources, Inc., Tenaska Gas Storage LLC, and Enogex, Inc. All of these contracts combined give Oklahoma Natural Gas a reserved storage capacity of approximately 10.3 Bcf. As these contracts expire, we expect to renew or replace the contracts using a competitive bid process.

In 2004, Kansas Gas Service had reserved capacity of 14.9 Bcf with Southern Star, 0.4 Bcf with Panhandle Eastern Pipeline Company (Panhandle) and 2.4 Bcf with an affiliate. These contracts combined give Kansas Gas Service a reserved storage capacity of approximately 17.7 Bcf.

Kansas Gas Service has long-term gas purchase contracts with BP PLC (BP) for the purpose of meeting the requirements of the customers served over the Southern Star system. We anticipate that these contracts will supply between 70 and 80 percent of Kansas Gas Service’s demand served by the Southern Star system. BP is one of various suppliers over the Southern Star system. Management believes that if these contracts were cancelled the gas supplied by BP could be replaced with gas from other suppliers. Gas available under these contracts that exceeds the needs of our residential and commercial customer requirements is also available for sale to other parties, known as “as available” gas sales.

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

Kansas Gas Service has transportation agreements for delivery of gas with remaining terms of one to 14 years with the following nonaffiliated pipeline transmission companies: Southern Star, Enbridge Pipelines - KPC, Inc., Kinder Morgan Interstate Gas Transmission, L.L.C., Wyoming Interstate Gas Company, Panhandle, Northern Natural Gas Company, Natural Gas Pipeline Company of America and Cheyenne Plains Gas Pipeline Company LLC. Additionally, approximately eight percent of Kansas Gas Service’s transportation service is provided by Mid Continent Market Center, which is an affiliated company.

Kansas Gas Service also has a service agreement with Cheyenne Plains Gas Pipeline Company, LLC for capacity on the Cheyenne Plains pipeline. This pipeline will provide Kansas Gas Service access to the Rocky Mountain gas supply basin, which currently has excess supply. This will facilitate Kansas Gas Service’s ability to maintain a reliable gas source for our current customers through an interconnection with Southern Star and the Kansas Gas Service transmission system. The Cheyenne Plains pipeline originates at the Cheyenne Hub in northeast Colorado and terminates with deliveries to several pipelines in Kansas. This pipeline went into service in December 2004.

The majority of Texas Gas Service’s 2004 gas requirements for its operations were delivered under short and long-term transportation contracts through four major pipeline companies: Enterprise Texas Pipeline L.P., Kinder Morgan Texas Pipeline L.P., El Paso Natural Gas Company, and Houston Pipe Line Company L.P. Texas Gas Service purchases significant volumes of gas under short and long-term arrangements with suppliers. The amounts of such short-term purchases are contingent upon price and demand needs. Texas Gas Service has firm supply commitments that are supplied with gas purchased under short-term and long-term arrangements. Texas Gas Service also holds rights to 5.2 Bcf of a combination of storage capacity and pipeline operational balancing capacity that acts as storage to assist in meeting peak demands in El Paso, Austin and Breckenridge service areas.

Texas Gas Service 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 the terms in each gas supply contract.

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, Oklahoma Natural Gas’ rate schedule “Order of Curtailment” and Kansas Gas Service’s 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. Texas Gas Service gas transportation contracts with interruption provisions require large volume users to purchase their 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. 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, state and local regulatory agencies.

Residential and Commercial Customers - Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service distribute natural gas as public utilities to approximately 86 percent, 71 percent and 14 percent of Oklahoma’s, Kansas’ and Texas’ distribution markets, respectively. Natural gas sold to residential and commercial customers, which is used primarily for heating and cooking, accounts for approximately 68 and 22 percent of gas sales, respectively, in Oklahoma, 58 and 16 percent of gas sales, respectively, in Kansas, and 64 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. Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service 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 our transportation tariffs, qualifying industrial and commercial customers are able to purchase gas from the supplier of their choice and have it transported for a fee by Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service.

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 and service. We believe that we must maintain a competitive advantage in order to retain our customers and, accordingly, we focus on providing reliable, efficient service and reducing costs.

The Distribution segment is subject to competition from other pipelines for our existing industrial load. Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service compete for service to the large industrial and commercial customers and competition continues to lower rates. A portion of Oklahoma Natural Gas’ and Kansas Gas Service’s transportation services are at negotiated rates that are generally below the approved transportation tariff rates, and increased competition potentially could lower these rates. In Texas Service’s service area, transportation service is negotiated only when a competitive pipeline is in proximity to bypass Texas Gas Service or another energy option is available. Any negotiated transportation service contract is filed under a separate, confidential tariff at the RRC. 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. Oklahoma Natural Gas’ and Kansas Gas Service’s tariff rates include a temperature normalization adjustment clause during the heating season, which mitigates the effect of fluctuations in weather. Additionally, with prior KCC approval, Kansas Gas Service 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 Kansas Gas Service customers. Approximately 83 percent of Texas Gas Service’s revenues are protected from abnormal weather due to a flat fee rate or a weather normalization adjustment clause. Texas Gas Service’s weather normalization adjustment clause is in 19 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, Texas Gas Service 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 Oklahoma Natural Gas and by the KCC for Kansas Gas Service. Texas Gas Service 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 are subject to regulatory oversight by the RRC. 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, RRC and various municipalities in Texas. See pages 43-44 for a detailed description of our various regulatory initiatives.

Oklahoma Natural Gas has 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 $7.0 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 Pipeline transports gas in interstate commerce under blanket authority of the FERC and is treated as a separate entity by the FERC. Accordingly, OkTex Pipeline 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 Pipeline has the capacity to move up to 1,100 MMcf/d.

Energy Services

Segment Description - Our Energy Services segment conducts its business through ONEOK Energy Services and its subsidiaries. ONEOK Energy Services is actively engaged in the marketing and trading of natural gas to both wholesale and retail customers throughout the United States using gas storage and pipeline capacity, including firm transportation capacity, leased from related parties and others. The combination of owning supply and controlling strategic assets allows us to provide customers with enhanced services in return for premium value. This combination also allows us to capture incremental value from the volatility in the energy markets.

We have a large leased storage and pipeline capacity position, primarily in the mid-continent region of the United States, with total transportation capacity of 1.7 Bcf/d. With total cyclical storage capacity of 83.5 Bcf, maximum withdrawal capability of 2.3 Bcf/d and maximum injection capability of 1.5 Bcf/d spread across 18 different facilities, we have direct access to most regions of the country and flexibility to capture volatility in the energy markets. We recently extended our energy services operations into Canada by leasing storage and pipeline capacity in Canada, allowing us to bring gas supply from western Canada into the market areas of the upper Midwestern and Northeastern parts of the United States. We also trade power on a smaller scale.

General - Operating income from our Energy Services segment is 28.1 percent, 44.2 percent, and 48.9 percent of our consolidated operating income from continuing operations in 2004, 2003, and 2002, respectively. A $14.0 million gain related to the sale of Enron claims is included in 2002. In 2004, we were required to repurchase a portion of the Enron claims and we are now providing the defense in two Enron related matters. See Item 3, Legal Proceedings in this Form 10-K for additional discussion. In 2004, the Energy Services segment had one customer, BP, from which it received $664.4 million, or approximately 11 percent, of consolidated revenues. We maintain a reasonable, balanced position with BP in order to minimize our credit exposure. Our exposure is also mitigated by existing netting arrangements. A significant supply agreement with BP expires in May 2005. The net margin impact would be minimal if the agreement is not extended and we no longer conduct business with BP. In 2003 and 2002, the Energy Services segment had no single external customer from which it received ten percent or more of consolidated revenues.

At the beginning of the third quarter of 2004, we completed a reorganization of our Energy Services segment and renewed our focus on our physical marketing and storage business. We separated the management and operations of our wholesale marketing, retail marketing and financial trading activities and began accounting separately for the different types of revenue earned from these activities. Prior to the third quarter, we managed the Energy Services segment on an integrated basis and presented all energy trading activity on a net basis, in the Consolidated Statements of Income.

We continue to enhance our customer-focused strategy by providing reliable service during peak demand periods through the use of our storage and transportation capacities. The physical and financial energy services we provide help our customers execute their commodity procurement and asset management strategies.

Through our wholesale and retail marketing, trading and risk management capabilities, we provide commodity-diverse products and services designed to meet each of our customers’ needs. Our retail operations successfully expanded throughout much of the United States.

In October 2003, we signed a tolling arrangement with a third party for 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.

ONEOK Energy Services was the successful bidder to supply gas to Oklahoma Natural Gas, 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.

Market Conditions and Business Seasonality - In response to a very competitive marketing environment resulting from 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 providing reliable service during peak demand periods and capture opportunities created by short-term pricing volatility through our leased storage, generation and transportation assets. We focus on building and strengthening supplier and customer relationships to execute our strategy.

Due to seasonality of supply and demand balances, earnings will be significantly higher during the winter months than the summer months. The Energy Services segment’s margins 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 our energy marketing and 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 Northern Plains, which owns a 2.73 percent interest in Northern Border Partners, ONEOK Leasing Company and ONEOK Parking Company. Northern Plains was acquired in November 2004 and was not material to us in 2004. Through ONEOK Leasing Company and ONEOK Parking Company, 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.

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

On March 15, 2002, Magnum Hunter Resources (MHR) merged with Prize Energy Corp., which reduced our direct ownership to approximately 11 percent. 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 with an exercise price of $15 per share, which we exchanged for 1.5 million shares of MHR common stock in February 2005.

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 N 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.


Name and Position	Age		Business Experience in Past Five Years

David L. Kyle Chairman of the Board, President and Chief Executive Officer	52	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 Executive Vice President- Finance and Administration and Chief Financial Officer	53	2004 to present 2001 to 2004 1999 to 2000 1997 to 1999	Executive Vice President - Finance and Administration and Chief Financial Officer Senior Vice President, Treasurer and Chief Financial Officer Vice President, Treasurer and Chief Financial Officer President, Oklahoma Natural Gas Company

John R. Barker Senior Vice President and General Counsel	57	2004 to present 1994 to 2004	Senior Vice President and General Counsel Stockholder, President and Director, Gable & Gotwals

Curtis L. Dinan Senior Vice President and Chief Accounting Officer	37	2004 to present 2004 to 2004 2002 to 2004 2000 to 2002	Senior Vice President and Chief Accounting Officer Vice President and Chief Accounting Officer Assurance and Business Advisory Partner, Grant Thornton, LLP Assurance and Business Advisory Partner, Arthur Andersen, LLP; Assurance and Business Advisory Senior Manager, Arthur Andersen, LLP

John A. Gaberino, Jr. Senior Vice President and Special Counsel to the Chairman of the Board	63	2004 to present 1998 to 2004 2001 to 2003	Senior Vice President and Special Counsel to the Chairman of the Board Senior Vice President and General Counsel Corporate Secretary

William R. Cordes CEO-Northern Border Partners, LP and President - Northern Plains Natural Gas Company	56	2000 to present 1993 to 2000	CEO, Northern Border Partners, LP/ President, Northern Plains Natural Gas Company President, Northern Natural Gas Company

Samuel Combs, III President - ONEOK Distribution Companies	47	2005 to present 2001 to 2005 1999 to 2001 1996 to 1999	President, ONEOK Distribution Companies President, Oklahoma Natural Gas Company Vice President - Western Region, Oklahoma Natural Gas Company Vice President - Oklahoma City District, Oklahoma Natural Gas Company

John W. Gibson President - ONEOK Energy Companies	52	2005 to present 2000 to 2005 1995 to 2000	President, ONEOK Energy Companies (1) President, Energy Executive Vice President, Koch Energy, Inc.; President, Koch Midstream Services; President, Koch Gateway Pipeline Company

J.D. Holbird President - ONEOK Energy Resources Companies	55	2003 to present 1999 to 2003 1997 to 1999	President, ONEOK Energy Resources Company President, ONEOK Resources Company Vice President, ONEOK Resources Company

(1)	The ONEOK Energy Companies includes the Gathering and Processing, Transportation and Storage, and Energy Services 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.

ITEM 2. PROPERTIES

DESCRIPTION OF PROPERTIES

Production

We own varying economic interests, including working, royalty and overriding royalty interests in 885 gas wells and 90 oil wells that are related to both our Oklahoma and Texas operations, some of which are in multiple producing zones. We own 91,908 net onshore developed leasehold acres and 9,721 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 active processing capacity of approximately 1.8 Bcf/d. 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. Processing plants extract NGLs and remove water vapor and other contaminants from the raw natural gas stream. Field plants, representing 42 percent of our processing capacity, are located in Texas, Oklahoma and Kansas and aggregate gathered volumes of unprocessed gas from multiple producing wells into quantities that can be processed. Straddle plants, representing about 58 percent of our processing capacity, are situated on mainline natural gas pipelines in Kansas and allow us to extract NGLs under contract from a natural gas stream.

We own and operate two NGL storage facilities in Kansas. We have recently completed the construction of an NGL pipeline joining our two storage facilities and now operate over 160 miles of NGL pipelines in Kansas. The total capacity of the facilities is approximately 16 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 5,600 miles of transmission pipeline with approximately 3,000 miles in Oklahoma, approximately 200 miles in Kansas, and approximately 2,400 miles in Texas. We have a peak transportation capacity of 2.9 Bcf/d and have compression and dehydration facilities located at various points throughout the pipeline system.

In addition, we own or reserve capacity in five underground storage facilities in Oklahoma, three storage facilities in Kansas and three storage facilities in Texas. 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.

Our transportation and storage facilities have interconnects with 31 different intrastate and interstate companies at 109 interconnect points, connecting 37 processing plants and approximately 139 producing fields, providing our customers with access to multiple markets and allowing gas to be moved throughout the mid-continent and west Texas areas.

Distribution

We own approximately 17,500 miles of pipeline and other distribution facilities in Oklahoma, approximately 12,300 miles of pipeline and other distribution facilities in Kansas and approximately 8,500 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.

Energy Services

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 232,000 square feet for our own use and lease the remaining space to others.

GAS AND OIL RESERVES

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

As of December 31, 2004, all of the gas and oil reserves for our Production segment are located in Oklahoma and Texas.

For quantities of our gas and oil reserves and the present value of estimated future net margins from our gas and oil reserves, see Notes T and U of the Notes to Consolidated Financial Statements included within this Annual Report on Form 10-K.

We report our proved reserves on our operated gas and oil 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 Gas and Oil Produced

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


	Years Ended December 31,
Sales	2004	2003	2002
Continuing operations
Gas (MMcf)	16,647	7,486	7,370
Oil (MBbls)	344	265	273
Discontinued component
Gas (MMcf)	—	1,472	18,036
Oil (MBbls)	—	53	241

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,
	2004		2003		2002
Average Sales Price (a)
Continuing operations
Per Mcf of gas	$	5.28	$	4.78	$	3.49
Per Bbl of oil	$	29.81	$	27.25	$	24.37
Discontinued component
Per Mcf of gas	$	—	$	4.10	$	3.19
Per Bbl of oil	$	—	$	32.28	$	25.00
Average Production Costs (b)
Continuing operations
Per Mcfe	$	0.89	$	0.90	$	0.68
Discontinued component
Per Mcfe	$	—	$	0.66	$	0.67

(a)

In determining the average sales price of gas and oil, 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 and oil hedges on the combined continuing operations and discontinued component average sales price is as follows:


	2004			2003			2002
Effect of natural gas hedges	$	(0.52	)	$	(0.30	)	$	0.25
Effect of oil hedges	$	(11.55	)	$	(3.10	)	$	—

(b)	Production costs, which include production taxes, are based on the combined wellhead market price of both continuing operations and the discontinued component, which averaged as follows:


	2004		2003		2002
Gas price per Mcf	$	5.80	$	5.18	$	3.02
Oil price per Bbl	$	41.36	$	30.88	$	24.65
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:
	2004		2003		2002
Production tax per Mcfe	$	0.31	$	0.31	$	0.21

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, 2004.


	Gas	Oil
Continuing operations
Gross wells	885.0	90.0
Net wells	374.1	38.5

Gross developed acres and net developed acres by well classification are not available. Gross developed acres for both gas and oil are 166,021 acres. Net developed acres for both gas and oil are 91,908 acres.

Undeveloped Acreage

The following table sets forth the gross and net undeveloped leasehold acreage for our Production segment at December 31, 2004.


	Gross	Net
Oklahoma	15,480	9,415
Texas	801	306

Total	16,281	9,721

Of the net undeveloped acres, approximately 99 percent are in the Anadarko Basin and Anadarko Shelf 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,
	2004	2003	2002
Development
Continuing operations
Productive	46.2	6.0	8.8
Dry	0.4	0.1	—
Discontinued component
Productive	—	—	12.0
Dry	—	—	—

Total	46.6	6.1	20.8

We did not drill any exploratory wells in 2004, 2003 or 2002.

Present Drilling Activities

At December 31, 2004, the Production segment was participating in the drilling of six wells. Our net interest in these wells amounts to 1.7 wells.

Future Obligations to Provide Gas and Oil

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

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. On June 4, 2004, we joined with the numerous other defendants in filing a motion to dismiss contending that Grynberg has not satisfied the unique jurisdictional prerequisites for maintaining an action under the False Claims Act. The motion to dismiss is set for hearing in March 2005.

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. The Plaintiffs’ Motion to Certify this suit as a class action is set for hearing on April 1, 2005.

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. The Plaintiffs’ Motion to Certify this suit as a class action is set for hearing on April 1, 2005.

In the Matter of the Natural Gas Explosion at Hutchinson, Kansas during January, 2001, Case No. 02-E-0155, before the Secretary of the Kansas 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 assessed a $180,000 civil penalty against our Kansas Gas Service division. The penalty was 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 required 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. On April 5, 2004, we entered into a Consent Order with the KDHE in which we paid a civil penalty in the amount of $180,000 and reimbursed the KDHE for its costs related to the investigation of the incident in the amount of approximately $79,000. Remediation required under the consent order is ongoing.

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 included all owners of residential 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. Both cases were adjudicated in September 2004 and resulted in jury verdicts. In the class action relating to the residential claimants, the jury awarded $5 million in actual damages, which is covered by insurance. In the business owners’ class action, the jury rendered a defense verdict awarding no actual damages. The jury rejected claims for punitive damages in both cases. In a separate hearing on Plaintiffs’ attorney fees, the Judge awarded $2,047,406 in fees and $646,090.78 in expenses, which is also covered by insurance. We are reviewing our options for appeal of the residential claimants’ class action verdict and subsequent award of attorney fees. With the exception of a related lawsuit that was filed in Sedgwick County, Kansas, which is now on appeal (see Note L of the Notes to Consolidated Financial Statements included in this Form 10-K for additional discussion on this matter), all other litigation regarding the gas explosions has been resolved.

Cornerstone 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. We and our wholly owned subsidiary, ONEOK Energy Services, L.P. (formerly ONEOK Energy Marketing and Trading Company, L.P.) were named as two of the defendants in the above-captioned lawsuit filed February

2, 2004 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. On August 17, 2004, this case was consolidated for all purposes with a related lawsuit which names a number of other defendants in the energy industry. Plaintiffs in the related case assert allegations similar to those alleged against us in this case. As of this date no class has been certified and discovery is commencing.

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. Enron Corp. filed a complaint on November 28, 2003 against Silver Oak Capital, LLC and AG Capital Recovery Partners III, LP (“AG”), instituting an adversary proceeding seeking to avoid as a fraudulent transfer, under Section 548 of the Bankruptcy Code, certain guaranties of obligations of Enron North America Corp. (“ENA”) that Enron Corp. issued to one of our subsidiaries, ONEOK Energy Services, L.P. (formerly ONEOK Energy Marketing and Trading Company, L.P.). At that time, AG was the owner of claims filed in the bankruptcies of Enron Corp. and ENA that ONEOK Energy Services, L.P. originally sold on a recourse basis to Bear Stearns & Co. Inc. in May 2002 (the “Claims”). The filing of that complaint triggered repurchase obligations that ONEOK Energy Services, L.P. honored in April 2004, and accordingly ONEOK Energy Services, L.P. purchased from AG $25 million of the Claims against Enron Corp. (the “Repurchased Claims”). ONEOK Energy Services, L.P. now owns and is enforcing the Repurchased Claims in the Enron bankruptcy case, and ONEOK Energy Services, L.P. is also defending the adversary proceeding. Additionally, Enron Corp. and ENA have filed separate objections to a portion of the Claims, alleging that the applicable proofs of claim, as filed by AG, were overstated. The filing of those objections may trigger obligations of ONEOK Energy Services, L.P. to repurchase additional portions of the Claims (the “Additional Contested Claims”), which ONEOK Energy Services, L.P. would then enforce in the same manner as the Repurchased Claims. If ONEOK Energy Services, L.P. did repurchase some or all of the Additional Contested Claims, it would then potentially be entitled to distributions under the confirmed Enron bankruptcy plan on account of those claims that would be less than the amount for which ONEOK Energy Services, L.P. might have to repurchase the Additional Contested Claims.

Samuel P. Legget, et al. v. Duke Energy Corporation et al; Case No. 13847 in the Chancery Court of Tennessee for the Twenty-Fifth Judicial District at Somerville. This action was filed against us and our wholly owned subsidiary, ONEOK Energy Services Company (formerly ONEOK Energy Marketing and Trading Company, L.P.) and several other energy trading companies on January 28, 2005. The lawsuit seeks a class certification of residential and business classes in Tennessee for recovery of damages based upon allegations of conspiracy to violate the Tennessee Trades Practices Act and injunctive relief.

In the Matter of the Application of Oklahoma Natural Gas Company, a Division of ONEOK, Inc., for a Review and Change or Modification in its Rates, Charges, Tariffs and Terms and Conditions of Service, Oklahoma Corporation Commission, Cause No. PUD 200400610. On January 28, 2005, Oklahoma Natural Gas Company, a division of ONEOK, Inc., filed an application at the Oklahoma Corporation Commission (the “OCC”) requesting annual rate relief of approximately $99.4 million, of which $38.5 million would be paid in additional income taxes. This amount includes $10.7 million of interim rate relief granted by the OCC in January 2004. Pursuant to Oklahoma statute, the OCC must hear the case and issue an order within 180 days of the date of filing. If an order does not issue within the required period, Oklahoma Natural Gas may place the rate increase into effect, subject to refund.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE 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.

PART II.

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER 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 closing prices of our common stock for the periods indicated.


	Year Ended December 31, 2004				Year Ended December 31, 2003
	High		Low		High		Low
First Quarter	$	27.70	$	21.64	$	20.20	$	16.00
Second Quarter	$	23.04	$	19.69	$	20.99	$	18.14
Third Quarter	$	26.13	$	20.61	$	21.68	$	18.75
Fourth Quarter	$	28.99	$	25.66	$	22.44	$	19.20

There were 14,748 holders of record of our common stock at February 28, 2005.

Dividends

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


	Years Ended December 31,
	2004			2003
First Quarter	$	0.19		$	0.17
Second Quarter	$	0.21		$	0.17
Third Quarter	$	0.23	(a)	$	0.17	(a)
Fourth Quarter	$	0.25	(a)	$	0.18	(a)

(a) - Declared in the previous quarter.

Equity Compensation Plan Information

The following table sets forth certain information concerning our equity compensation plans as of December 31, 2004.


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)	3,269,020	$	19.31		4,673,121	(4)

Equity compensation plans not approved by security holders (2)	260,440	$	22.41	(3)	504,124	(4)

Total	3,529,460	$	19.54		5,177,245

(1)

Includes stock options, restricted stock awards, restricted stock incentive units and performance share awards granted under our Long-Term Incentive Plan. For a brief description of the material features of this plan, see Note Q of the Notes to Consolidated Financial Statements. Column (c) also includes 2,884,600 and 256,445 shares available for future issuance under our Thrift Plan and Employee Stock Purchase Plan, respectively.

(2)

Includes our Employee Non-Qualified Deferred Compensation Plan, Deferred Compensation Plan for Non-Employee Directors, and Stock Compensation Plan for Non-Employee Directors. For a brief description of the material features of these plans, see Note Q of the Notes to Consolidated Financial Statements. Column (c) also includes 24,124 shares available for future issuance under the Employee Stock Award Program.

(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 for these plans to calculate the weighted-average exercise price in the table is $28.42, which represents the closing price of our common stock at December 31, 2004.

(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.

Issuer Purchases of Equity Securities

The following table sets forth information relating to our recent purchases of our common stock.


Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
October 1-31, 2004	53,895	(1)(2)	$	26.26	—	—
November 1-30, 2004	20,936	(1)(2)	$	27.28	—	—
December 1-31, 2004	19,985	(1)(2)	$	27.87	—	—

Total	94,816		$	26.82	—	—

(1)	Includes shares withheld pursuant to attestation of ownership and deemed tendered to us in connection with the exercise of stock options under the ONEOK, Inc. Long-Term Incentive Plan, as follows :

53,890 shares for the period October 1-31, 2004

20,859 shares for the period November 1-30, 2004

19,848 shares for the period December 1-31, 2004

(2)	Includes shares repurchased directly from employees as follows:

five shares for the period October 1-31, 2004

77 shares for the period November 1-30, 2004

137 shares for the period December 1-31, 2004

Employee Stock Award Program

Under our Employee Stock Award Program, we issued, for no consideration, to all eligible employees (all full-time employees and employees on short-term disability) one share of our common stock when the closing price of our common stock on the New York Stock Exchange (NYSE) was for the first time at or above $26 per share, and we will issue, for no consideration, one additional share of our common stock to all eligible employees when the closing price on the NYSE is for the first time at or above each one dollar increment above $26 per share. A total of 50,000 shares of our common stock are reserved for issuance under this program.

The following table sets forth information on the number of shares issued under this program during 2004.


Date	Closing Price (at or above)		Shares Issued
September 30, 2004	$	26.00	4,223
November 3, 2004	$	27.00	4,229
November 12, 2004	$	28.00	4,229

Total			12,681

On February 4, 2005, our stock closed at $29.00 per share which resulted in 4,637 shares being issued to eligible employees.

The issuance of shares under this program has not been registered under the Securities Act of 1933, as amended (1933 Act) in reliance upon SEC releases, including Release No. 6188, dated February 1, 1980, stating that there is no sale of the shares in the 1933 Act sense to employees under this type of program.

ITEM 6. SELECTED FINANCIAL DATA

In accordance with a pronouncement of the Financial Accounting Standards Board’s (FASB) Staff at the Emerging Issues Task Force (EITF) meeting in April 2001, codified as EITF Topic No. D-95 (Topic D-95) and subsequently superceded by EITF Issue No. 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128”, 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. See Note R 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 exchanged the remaining 10.9 million shares of Series A for 21.8 million shares of Series D Convertible Preferred Stock (Series D) reflecting the two-for-one stock split in 2001. The Series D had a fixed annual cash dividend rate of 92.5 cents per share. As a result of this transaction, the EITF for participating securities no longer applied to our computation of EPS beginning in February 2003. In November 2003, the Series D was converted to common stock and sold to the public by Westar. Effective January 6, 2004 the Series D was retired. There are no shares of Series A currently outstanding.

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


	Years Ended December 31,
	2004		2003		2002		2001		2000
	*(Millions of dollars, except per share amounts)*
Net margin from continuing operations	$	1,244.2	$	1,136.5	$	975.7	$	826.4	$	745.7
Operating income from continuing operations	$	490.0	$	446.1	$	371.5	$	255.6	$	324.5
Income from continuing operations	$	242.2	$	214.3	$	156.0	$	78.8	$	137.7
Total assets	$	7,192.6	$	6,211.9	$	5,809.6	$	5,853.3	$	7,360.3
Long-term debt	$	1,829.5	$	1,830.9	$	1,442.0	$	1,744.2	$	1,350.7
Redeemable preferred stock	$	—	$	—	$	0.2	$	0.2	$	0.2
Basic earnings per share - continuing operations	$	2.38	$	2.38	$	1.31	$	0.66	$	1.16
Basic earnings per share - total	$	2.38	$	1.48	$	1.40	$	0.85	$	1.23
Diluted earnings per share - continuing operations	$	2.30	$	2.13	$	1.30	$	0.66	$	1.16
Diluted earnings per share - total	$	2.30	$	1.22	$	1.39	$	0.85	$	1.23
Dividends per common share	$	0.88	$	0.69	$	0.62	$	0.62	$	0.62

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

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 an integrated natural gas company with operations throughout the mid-continent area of the United States and, more recently, in Canada.

The following discussion highlights some of our achievements and significant issues affecting us this past year. You should read the relevant sections of Management’s Discussion and Analysis and the Financial Statements for a complete explanation of the following items.

In 2004, we saw our income from continuing operations increase to $242.2 million from $214.3 million in 2003, a 13 percent increase. Operating income increased to $490.0 million in 2004 from $446.1 million in 2003, and cash flow from operations increased to $204.8 million in 2004 from $0.7 million in 2003. Our dividend was increased each quarter during 2004, to a current annual dividend of $1.00 per share of common stock. This follows two increases in our dividend during 2003.

EPS is one of the key indicators that we use to evaluate our success. Other key indicators that we use are shareholder appreciation as compared to our peer companies and return on invested capital.

The contribution to our earnings from the gas and oil reserves we acquired in December 2003 was primarily responsible for the $31.7 million increase in operating income in our Production segment.

In 2004, our gathering and processing segment increased operating income by $68.3 million over 2003, or an increase of 109 percent. This followed an 89 percent increase in 2003 over 2002. The third and fourth quarter of 2004 had the most favorable pricing environment for natural gas and NGL products as any period in the last five years.

In November 2004, we closed the purchase of Northern Plains and became the holder of the majority of the general partnership interest in the limited partnership. We will operate more than $2.5 billion of assets in a mix of mostly natural gas assets, including interstate pipelines, gathering pipelines and processing plants located in an area stretching from the Canadian Border and the Rockies to the upper Midwest.

We filed for $99.4 million in rate relief in Oklahoma on January 28, 2005, of which $38.5 million would be paid in additional income taxes. This amount includes $10.7 million of the interim rate relief granted in January 2004. We have not had an increase to our base rates in Oklahoma since 1995. Under Oklahoma state law, the OCC has 180 days to conduct a review and issue an order in response to our application. This means that any approved rate relief would be in effect prior to the 2005/2006 heating season.

The September 2003 rate increase in Kansas was in effect for the entire 2004 year. This provided $16.2 million in additional operating income, as compared to 2003, which included the rate increase for a portion of the year.

A reorganization in the Energy Services segment at July 1, 2004, changed the way we do business and present revenues in that segment. As a result of separating the management and operations of our physical marketing, retail marketing and financial trading activities, we began accounting separately for the different types of revenue earned from these activities.

Significant Acquisitions and Divestitures

In November 2004, we acquired Northern Plains, which owns 82.5 percent of the general partnership interest and 500,000 limited partnership units, together representing a 2.73 percent ownership interest, in Northern Border Partners, from CCE Holdings, LLC for $175 million. Income derived from this investment is included in other income in our Other segment.

In March 2004, we sold certain natural gas transmission and gathering pipelines and compression facilities for approximately $13 million and recorded a pre-tax gain of $6.9 million, which is included in other income in our Transportation and Storage segment.

In December 2003, we acquired 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 January 2003, we sold 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.

In January 2003, we acquired 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 557,000 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 assets relating to the

propane distribution operations were sold in May and July 2004 and the natural gas distribution investments in Mexico were sold in May 2004. Texas Gas Service operated these assets.

In December 2002, we sold 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. We recorded a loss of approximately $3.7 million in 2002 related to this sale. 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.

Regulatory

Several regulatory initiatives positively impacted the earnings and future earnings potential for the Distribution segment. These are discussed beginning on pages 43-44.

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 51.

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 EPS information had we applied the fair value provisions for options granted for the year ended December 31, 2002.

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123R, “Share-Based Payment” (Statement 123R). Statement 123R requires companies to expense the fair value of share-based payments. In addition, there are also changes related to the share-based payment expense calculation. Statement 123R is effective for the interim period beginning after June 15, 2005. We are currently assessing the impact of adopting Statement 123R, but we do not believe it will have a material impact on our financial condition and results of operations as we have been expensing share-based payments since the adoption of Statement 148 on January 1, 2003.

Critical Accounting Policies and Estimates

Our discussion and analysis of financial condition and results of 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.

The following is a summary of our most critical accounting policies, which are defined as those policies most important to the portrayal of our financial condition and results of operations and requiring management’s most difficult, subjective, or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters. We have discussed the development of and selection of our critical accounting policies and estimates with the audit committee of our Board of Directors.

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 52 for amounts in our portfolio at December 31, 2004 that were determined by prices actively quoted, prices provided by other external sources, and prices derived from other sources. The majority of our portfolio’s fair values are based on actual market prices. Transactions are also executed in 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.

Market value changes result in a change in the fair value of our derivative instruments. 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 the derivative instrument does not qualify or is not designated as part of a hedging relationship, we account for changes in fair value of the derivative in earnings are they occur. Commodity price volatility 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.

To minimize the risk of fluctuations in natural gas, NGLs and crude oil prices, we periodically enter into futures transactions and swaps in order to hedge anticipated sales and purchases of natural gas and crude oil production, fuel requirements and NGL inventories. Interest rate swaps are also used to manage interest rate risk. Under certain conditions, we designate these derivative instruments as a hedge of exposure to changes in fair values or cash flows. 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. 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 subsequently reclassified into earnings when the forecasted transaction affects earnings. Any ineffectiveness of designated hedges is reported in earnings.

Many of our purchase and sale agreements 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.

Energy-related contracts that are not derivatives pursuant to Statement 133 are no longer carried at fair value, but are accounted for on an accrual basis as executory contracts. Changes to the accounting for existing contracts as a result of the rescission of EITF 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.

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 of each reporting unit. 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, we will record an impairment charge. At December 31, 2004, we had $225.2 million of goodwill recorded on our balance sheet.

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 the 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:

•

a significant decrease in the market price of a long-lived asset or asset group,

•

a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition,

•

a significant adverse change in legal factors or in the business climate that could affect the value of a long-lived asset or asset group, including an adverse action or assessment by a regulator that would exclude allowable costs from the rate-making process,

•

an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset or asset group,

•

a current-period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group, and

•

a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

We do not currently anticipate any goodwill or asset impairments to occur within the next year. Factors that would most likely impact the recoverability of our long-term assets would include a significant and long-term decline in commodity prices, partial or complete deregulation of our regulated business, a significant decrease in the rate of return for a regulated business, a major accident affecting the use of an asset or a decrease in the supply of natural gas. We do not foresee any of these events occurring in the near term, but if such events were to occur over the long-term, the impact could be significant to our financial condition and results of operations.

Pension and Postretirement Employee Benefits - We have a defined benefit pension plan covering substantially all full-time employees and a postretirement employee benefits plan covering most employees. Nonbargaining unit employees hired after December 31, 2004 are not eligible for our defined benefit pension plan; however, they are covered by a profit sharing plan. Nonbargaining unit employees retiring between the ages of 50 and 55 who elect postretirement medical coverage, all nonbargaining unit employees hired on or after January 1, 1999, employees who are members of the International Brotherhood of Electrical Workers hired after June 30, 2003 and gas union employees hired after July 1, 2004 who elect postretirement medical coverage pay 100 percent of the retiree premium for participation in the plan. Additionally, any employees who came to us through various acquisitions may be further limited in their eligibility to participate or receive any contributions from us for postretirement medical benefits. Our actuarial consultant calculates the expense and liability related to these plans and 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.

Assumed health care cost trend rates have a significant effect on the amounts reported for our 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	$	2,993	$	(2,396	)
Effect on postretirement benefit obligation	$	27,713	$	(22,856	)

During 2004, we recorded net periodic benefit costs of $0.9 million related to our defined benefit pension plans and $25.0 million related to postretirement benefits. We estimate that in 2005 we will record net periodic benefit costs of $12.5 million related to our defined benefit pension plan and $30.1 million related to postretirement benefits. These increases primarily reflect our acquisition of Northern Plains, amendments in benefits payable under our gas union contracts and a change in our assumed discount rate. We will be reimbursed for approximately $2.3 million of this increase by Northern Border Partners for defined benefit pension plan expenses that we incur for them. In determining our estimated expenses for 2005, our actuarial consultant assumed an 8.75 percent expected return on plan assets and a discount rate of 6.00 percent. A decrease in our expected return on plan assets to 8.50 percent would increase our 2005 estimated net periodic benefit costs by approximately $1.5 million for our defined benefit pension plan and would not have a significant impact on our postretirement benefit plan. An increase in our assumed discount rate to 6.50 percent would decrease our 2005 estimated net periodic benefit costs by approximately $4.5 million for our defined benefit pension plan and $1.9 million for our postretirement benefit plan.

See Note K of Notes to Consolidated Financial Statements in this Form 10-K for additional information.

Contingencies - Our accounting for contingencies covers a variety of business activities including contingencies for 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.

Consolidated Operations

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


	Years Ended December 31,
Financial Results	2004		2003			2002
	*(Thousands of dollars)*
Operating revenues, excluding energy trading revenues	$	5,874,266	$	2,769,214		$	1,894,851
Energy trading revenues, net		113,814		229,782			209,429
Cost of gas and fuel		4,743,835		1,862,518			1,128,620

Net margin		1,244,245		1,136,478			975,660
Operating costs		565,510		529,553			456,339
Depreciation, depletion, and amortization		188,725		160,861			147,843

Operating income	$	490,010	$	446,064		$	371,478

Other income	$	17,730	$	8,164		$	12,426
Other expense	$	12,127	$	5,224		$	19,038

Discontinued operations, net of taxes
Income from discontinued component	$	—	$	2,342		$	10,648
Gain on sale of discontinued component	$	—	$	39,739		$	—

Cumulative effect of a change in accounting principle, net of tax	$	—	$	(143,885	)	$	—

Operating Results - Changes in commodity prices can have a significant impact on our earnings, particularly in the Production and Gathering and Processing segments. Net margin increased in 2004 compared to 2003 primarily due to:

•

a favorable pricing environment for natural gas processing,

•

improved margins resulting from the strategy of restructuring unprofitable gas purchase, gathering and processing contracts,

•

volumes produced from our Texas gas and oil properties acquired in December 2003,

•

the impact of higher prices on our Production segment, and

•

rate relief in our Distribution segment.

These increases in net margin were partially offset by the impact of reduced volatility in natural gas prices on our results from the Energy Services segment.

Operating costs and depreciation, depletion and amortization increased in 2004 compared to 2003 primarily due to:

•

additional depreciation, depletion and amortization resulting from the acquisition of the Texas gas and oil properties,

•

regulatory asset amortization resulting from the Kansas and Oklahoma rate cases,

•

increased labor and employee benefit costs and

•

increased production costs related to the acquisition of our Texas gas and oil properties.

Net margin increased in 2003 compared to 2002 primarily due to:

•

higher prices of natural gas, NGLs and crude oil,

•

restructuring of unprofitable contracts in our Gathering and Processing segment,

•

addition of our Texas gas distribution business,

•

implementation of Kansas Gas Service’s new rate schedule in September 2003, and

•

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

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

•

additional costs of operating our Texas gas distribution business and the depreciation on additional assets acquired with that business,

•

higher bad debt expenses due to higher prices, and

•

increased employee and administrative costs.

Holdings, LLC. Northern Border Partners is a master limited partnership formed in 1993 to acquire, own and manage pipeline and other midstream energy assets, focusing on fee-based transportation services with minimal commodity risk. In 2004, our equity income includes $1.3 million from Northern Border Partners.

The following tables show the components of other income and other expense for the periods indicated.


	Years Ended December 31,
	2004		2003			2002
	*(Thousands of dollars)*
Interest income	$	1,276	$	2,961		$	1,304
Income from benefit plan investments		1,671		2,559			—
Equity income		2,401		1,489			365
Gains on sale of property		11,269		292			10,485
Other		1,113		863			272

Other Income	$	17,730	$	8,164		$	12,426


	Years Ended December 31,
	2004		2003			2002
	*(Thousands of dollars)*
Donations, civic, and governmental	$	3,117	$	6,829		$	6,180
Non-operating litigation expense and claims, net		7,033		(2,506	)		10,153
Terminated acquisition expense		401		175			621
Expense from benefit plan investments		—		—			1,304
Loss on sale of property		683		6			—
Other		893		720			780

Other Expense	$	12,127	$	5,224		$	19,038

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 Energy Services segment section.

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

•

EPS,

•

return on invested capital, and

•

shareholder appreciation.

For the year ended December 31, 2004, our basic and diluted earnings per share from continuing operations is $2.38 and $2.30, respectively, representing no increase in basic earnings per share and an eight percent increase in diluted earnings per share from continuing operations compared to 2003. Return on invested capital is 14.3 percent in 2004 compared to 16.7 percent in 2003.

To evaluate shareholder appreciation, we compare ourselves to a group of 20 peer companies. For the year ended December 31, 2004, we ranked in the top 85th percentile in shareholder appreciation compared to our peers.

Production

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

As a result of our strategy to grow through acquisitions and developmental drilling, the number of wells we operate increases as we grow our producing reserves. We also 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, which are the costs incurred to extract natural gas and oil. We continually focus on reducing finding costs, which is the cost per Mcfe of adding proved reserves through drilling, and minimizing production costs.

Acquisition and Divestiture - The following acquisition and divestiture are discussed beginning on page 26:

•

purchased gas and oil properties and related flow lines in December 2003

•

sold natural gas and oil producing properties in January 2003

Development Activities - Through our developmental drilling program, we participated in drilling 70 wells in 2004, which included 66 producing gas wells, three producing oil wells and one dry hole. At December 31, 2004, 32 wells were still being drilled or completed. In 2003, we participated in drilling 20 wells, 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,
Financial Results	2004		2003		2002
	*(Thousands of dollars)*
Natural gas sales	$	87,863	$	35,818	$	25,693
Oil sales		10,254		7,221		6,654
Other revenues		4,845		949		107

Net revenues		102,962		43,988		32,454
Operating costs		28,590		15,812		8,332
Depreciation, depletion, and amortization		26,615		12,070		13,842

Operating income	$	47,757	$	16,106	$	10,280

Other income (expense), net	$	60	$	10	$	(178	)

Discontinued operations, net of taxes (Note C)
Income from discontinued component	$	—	$	2,342	$	10,648
Gain on sale of discontinued component	$	—	$	39,739	$	—

Cumulative effect of a change in accounting principle, net of tax	$	—	$	117	$	—


	Years Ended December 31,
Operating Information	2004		2003		2002
Proved reserves (a)
Continuing operations
Gas (MMcf)		203,277		221,119		61,748
Oil (MBbls)		4,067		4,127		2,461
Discontinued component
Gas (MMcf)		—		—		177,828
Oil (MBbls)		—		—		2,787
Production
Continuing operations
Gas (MMcf)		16,647		7,486		7,370
Oil (MBbls)		344		265		273
Discontinued component
Gas (MMcf)		—		1,472		18,036
Oil (MBbls)		—		53		241
Average realized price (b)
Continuing operations
Gas ($/Mcf)	$	5.28	$	4.78	$	3.49
Oil ($/Bbls)	$	29.81	$	27.25	$	24.37
Discontinued component
Gas ($/Mcf)	$	—	$	4.10	$	3.19
Oil ($/Bbls)	$	—	$	32.28	$	25.00
Capital expenditures (Thousands of dollars)
Continuing operations	$	52,902	$	18,655	$	17,810
Discontinued component	$	—	$	—	$	21,824

(a)	Proved reserves include proved undeveloped reserves which are attributed to locations directly offsetting (adjacent to) existing production.

(b)	Average realized price reflects the impact of hedging activities.

Operating Results - Natural gas and oil sales increased in 2004 compared to 2003 due to:

•

increased revenues of $45.9 million resulting from increased production primarily related to the acquisition of our Texas gas and oil producing properties in December 2003, which produced 9.0 Bcf of natural gas and 121 MBbls of oil during 2004, and

•

increased revenues of $9.2 million resulting from higher realized net wellhead natural gas prices.

Other revenues increased in 2004 as a result of flow line fees and revenues from our Texas flow line system which was included in the December 2003 purchase.

Also, in 2004, operating costs and depreciation, depletion and amortization increased primarily as a result of the acquisition of the Texas properties. The significant increases in operating costs were:

•

$4.0 million in lease operating expenses,

•

$6.5 million in overhead costs and taxes, and

•

$2.3 million in flow line expenses.

Net margin from continuing operations increased in 2003 compared to 2002 due to higher realized gas and oil 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 was the result of normal production declines on existing wells, as well as no new drilling and minimal acquisition of new wells.

Operating costs from continuing operations were higher in 2003 compared to 2002, due to:

•

higher production taxes as a result of higher prices,

•

higher well operating costs due to maintenance and workovers, and

•

higher administrative costs.

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

Reserves - The following table sets forth the changes in our proved reserves for the periods indicated for the retained gas and oil properties.


Reserves	*(Bcfe)*
December 31, 2002	76.5
Revisions in prior estimates	(8.1	)
Extensions, discoveries and other additions	15.0
Purchases of minerals in place	171.6
Production	(9.1	)

December 31, 2003	245.9
Revisions in prior estimates	(23.4	)
Extensions, discoveries and other additions	23.9
Production	(18.7	)

December 31, 2004	227.7

Production for 2003 includes ten days of production for the acquired gas and oil properties.

The following table sets forth the composition of the proved developed reserves added for the periods indicated which are included in extensions, discoveries and other additions in the reserve table above.


	Years Ended December 31,
	2004	2003
	*(Bcfe)*
Proved developed producing	3.6	6.6
Proved developed non-producing	4.4	3.3

Total proved developed	8.0	9.9

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. The following table sets forth the changes in our proved reserves for the periods indicated for the discontinued component.


Reserves	*(Bcfe)*
December 31, 2002	194.6
Sales of minerals in place	(192.8	)
Production	(1.8	)

December 31, 2003	0.0

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.

Risk Management - The volatility of energy prices has a significant impact on the profitability of this segment. We utilize derivative instruments in order to hedge anticipated sales of natural gas and oil production. The realized financial impact of the derivative transactions is included in net margin.

The following table sets forth the 2005 hedging information for our Production segment.


	Year Ending December 31, 2005
Product	Volumes Hedged	Basis-Adjusted Average Price
Natural gas
Texas	18,350 Mcf/d	$	5.89/Mcf
Oklahoma	9,500 Mcf/d	$	6.38/Mcf
Oil	15,000 Bbls/month	$	39.75/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 - Our Gathering and Processing segment is engaged in the gathering, processing and marketing of natural gas and fractionation, storage and marketing of NGLs primarily in Oklahoma, Kansas and Texas. We have active processing capacity of approximately 1.8 Bcf/d. Our Gathering and Processing segment owns approximately 13,800 miles of gathering pipelines that supply our gas processing plants.

Gathering and processing operations include the gathering of natural gas production from gas and oil wells. Through gathering systems, these volumes are aggregated into sufficient volumes to be processed to remove water vapor, solids and other contaminants and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. When the liquids are separated from the raw natural gas at the processing plants, the liquids are generally in the form of a mixed NGL stream. This stream is then separated by a distillation process, referred to as fractionation, into component products (ethane, propane, isobutane, normal butane and natural gasoline) by third party and company-owned fractionation facilities. The component products can then be stored, transported and marketed to a diverse customer base of end users.

We generally gather and process gas under three types of contracts. Characteristics of the contract types are as follows.

•

Keep Whole - Under a keep whole contract, we extract NGLs and return to the producer volumes of merchantable natural gas containing the same amount of Btus as the raw natural gas that was delivered to us. We retain the NGLs as our fee for processing. Accordingly, we must purchase and return to the producer sufficient volumes of merchantable natural gas to replace the Btus that were removed as NGLs through the gathering and processing operation, commonly referred to as “shrink”. By using this contract type, the producer is kept whole on a Btu basis. This type of contract exposes us to the keep whole spread or gross processing spread, which is the relative difference in the economic value between NGLs and natural gas on a Btu basis. We typically bear the full cost of the plant fuel consumed in processing under these contracts. The main factors that affect our keep whole margins include:

•

shrink,

•

plant fuel consumed,

•

transportation and fractionation costs incurred on the NGLs,

•

gross processing spread,

•

mid-continent natural gas prices, and

•

crude oil prices.

•

the percentages of products retained that represent our equity NGL, condensate and natural gas sales volumes,

•

transportation and fractionation rates incurred on the NGLs, and

•

the mid-continent natural gas price, crude price and the daily average OPIS price received for our equity products retained.

Additionally, we purchase natural gas at the wellhead under index-based purchase agreements that we use for operational purposes, such as fuel and shrink, with the excess being sold monthly at index-based prices.

•

We have been successful in amending contracts covering approximately 22 percent of the volumes associated with our keep whole contracts to allow us to charge conditioning fees for processing when the keep whole spread is negative. This amendment helps mitigate the impact of an unfavorable keep whole spread by effectively converting a keep whole contract to a fee contract during periods of negative keep whole spread. Our effort to add this conditioning language began in 2002 and remains a strategy that we continue to execute today. We are also continuing our strategy of restructuring any unprofitable gas purchase and gathering contracts.

Additionally, we modify plant operations to take advantage of market conditions. By changing the temperatures and pressures at which the gas is processed, we can produce more of the specific commodities that have the most favorable prices or price spread. These strategies are used to improve the net margin generated by this segment.

We are impacted by producer drilling activity, which is sensitive to geological success as well as availability of capital and commodity prices. We are exposed to volume risk from both a competitive and a production standpoint. We continue to see declines in the fields that supply our gathering and processing operations and the possibility exists that declines may surpass development from new drilling. The factors that typically affect our ability to compete are:

•

the fees charged under the contract,

•

pressures maintained on the gathering systems,

•

location of the gathering systems relative to our competitors,

•

efficiency and reliability of operations, and

•

the delivery capabilities that exist at each plant location.

ONEOK NGL Marketing sells our NGL production and also purchases NGLs from third parties for resale to a diverse base of customers. We have 89 MBbls/d of mid-continent NGL fractionation capacity. We own and operate two NGL storage facilities in Kansas, with a combined storage capacity of 16 MMBbls, which provide both long- and short-term storage services. The storage facilities have premier truck and rail loading facilities and have direct pipeline interconnects with the key NGL pipelines, NGL storage facilities and refiners in the mid-continent region. The results of our storage operations are impacted by:

•

NGL supply and demand requirements of regional refineries,

•

NGL production in the mid-continent, Rockies and Canada,

•

Midwest demand for propane,

•

the petrochemical industry’s level of capacity utilization and their specific feedstock requirements,

•

efficiency and reliability of operations, and

•

the delivery capabilities that exist at each location.

The main factors that affect our ONEOK NGL Marketing margins are:

•

fees charged for storage,

•

transportation and fractionation costs,

•

fees for marketing services, and

•

margins on NGL sales.

Acquisition and Divestiture - The following acquisition and divestiture are described beginning on page 26:

•

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

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,
Financial Results	2004		2003			2002
	*(Thousands of dollars)*
Natural gas liquids and condensate sales	$	1,243,556	$	1,041,764		$	654,930
Gas sales		669,956		640,499			380,095
Gathering, compression, dehydration and processing fees and other revenues		106,585		96,254			98,196
Cost of sales and fuel		1,728,652		1,564,380			938,843

Net margin		291,445		214,137			194,378
Operating costs		127,552		122,103			127,747
Depreciation, depletion, and amortization		32,863		29,332			33,523

Operating income	$	131,030	$	62,702		$	33,108

Other income (expense), net	$	338	$	(194	)	$	(1,119	)

Cumulative effect of a change in accounting principle, net of tax	$	—	$	(1,375	)	$	—


	Years Ended December 31,
Operating Information	2004		2003		2002
Total gas gathered (MMMBtu/d)		1,099		1,171		1,205
Total gas processed (MMMBtu/d)		1,172		1,209		1,411
Natural gas liquids sales (MBbls/d)		109		114		95
Natural gas liquids produced (MBbls/d)		62		59		73
Gas sales (MMMBtu/d)		328		330		343
Capital expenditures (Thousands of dollars)	$	32,331	$	20,598	$	43,101
Conway OPIS composite NGL price ($/gal) (based on our NGL product mix)	$	0.72	$	0.59	$	0.41
Average NYMEX crude oil price ($/Bbl)	$	41.34	$	30.98	$	25.41
Average realized condensate price ($/Bbl)	$	38.17	$	28.68	$	22.59
Average natural gas price ($/MMBtu) (mid-continent region)	$	5.54	$	5.06	$	3.00
Gross processing spread ($/MMBtu)	$	2.47	$	1.36	$	1.52

Operating Results - The increase in net margin in 2004 compared to 2003 is primarily due to:

•

an increase of $16.8 million due to favorable commodity pricing for natural gas and NGL products on our POP contracts,

•

an increase of $50.2 million attributable to our keep whole contracts due primarily to an increase in our gross processing spread, and

•

an increase of $10.2 million related to our renegotiation of certain NGL storage agreements and the addition of NGL storage and pipeline assets located in Conway, Kansas.

In 2004, particularly the third and fourth quarters, the gross processing spread, which is the relative difference in the economic value between NGLs and natural gas on a Btu basis, was considerably higher than the previous five-year average of $1.58.

Improved contractual terms for gas gathering and processing resulting from our continued efforts to restructure unprofitable gas purchase and gathering contracts continues to positively impact net margin.

The increase in operating costs in 2004 compared to 2003 is primarily attributable to approximately $3.6 million of charges associated with various contractual dispute settlements in 2004. Employee costs were also $2.7 million higher in 2004 compared to 2003.

Depreciation, depletion and amortization increased in 2004 compared to 2003 primarily due to shorter depreciation lives on certain capital expenditures, the acquisition of new properties and our normal capital expenditure program.

Increased prices for NGLs, natural gas and crude oil positively impacted net margin by $32.6 million in 2003 when compared to 2002. These increases affected:

•

NGLs and condensate sales revenues,

•

gas sales,

•

cost of sales, and

•

net revenues.

In addition, our contractual restructuring efforts and our Texas propane business, which we sold in 2004, added approximately $16.7 million and $2.7 million, respectively, to net margin in 2003. These increases were partially offset by a decrease of approximately $9.5 million due to lower gas and NGL volumes processed in 2003 as a result of natural well declines.

In the fourth quarter of 2002, we sold an Oklahoma processing plant and gathering assets which reduced 2003 net margin by approximately $19.4 million and operating costs by approximately $6 million. Operating costs were also impacted by a $5.1 million reduction in bad debt expenses in 2003. The decreases in operating costs 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.

Depreciation, depletion and amortization decreased in 2003 compared to 2002 as a result of owning fewer assets following the sale of a portion of our Oklahoma assets in 2002, which reduced depreciation expense approximately $2.8 million. This decrease was partially offset by an increase of approximately $1 million related to 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.

In 2002, other income (expense), net includes an additional loss of $1.3 million that was recognized when the Oklahoma assets were sold in December 2002.

Capital Expenditures - Capital expenditures increased in 2004 primarily due to the construction of a new 33-mile NGL pipeline that connects our Kansas NGL storage facilities at Bushton and Conway. This pipeline cost approximately $9.2 million and was in service by December 31, 2004.

Risk Management - We use derivative instruments to minimize the risks associated with price volatility. In 2004, we used a variety of instruments including physical forward sales, NYMEX natural gas futures, NYMEX crude oil futures and over-the-counter natural gas basis swaps to hedge the cash flows for the purchases and sales of natural gas, sales of condensate and sales of NGLs produced by our operations. We used physical forward sales and derivative instruments to secure a certain price for natural gas, condensate and NGL products. The keep whole spread is hedged with a combination of derivative instruments for the purchase of natural gas and derivative instruments and physical forward sales for NGLs. The realized financial impact of the derivative transactions is included in our operating income in the period that the physical transaction occurs.

The following table sets forth the 2005 hedging information for our Gathering and Processing segment for the periods indicated.


	Three Months Ending March 31, 2005			Year Ending December 31, 2005
Product	Volumes Hedged	Average Price		Volumes Hedged	Average Price
Percent of Proceeds:
Condensate (a)	135 MBbls	$	47.21/Bbl	540 MBbls	$	44.59/Bbl
NGL (b)	360 MBbls	$	0.75/gal	810 MBbls	$	0.74/gal
Natural gas (c)	1.5 Bcf	$	7.75/MMBtu	6.3 Bcf	$	6.43/MMBtu
Keep Whole:
Gross processing spread (d)	4,501 MMMBtu	$	2.73/MMBtu	6,539 MMMBtu	$	2.80/MMBtu

(a)	- Hedged with NYMEX based swaps.

(b)	- Hedged with forward sales and swaps.

(c)	- Hedged with NYMEX futures and basis swaps.

(d)	- Hedged with NYMEX futures, basis swaps and NGL forward sales.

We continue to evaluate market conditions for the remainder of 2005 to take advantage of favorable pricing opportunities for our company-owned production associated with the POP contracts, as well as our keep whole quantities.

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 some gas gathering facilities. We also provide interstate transportation service under Section 311(a) of the Natural Gas Policy Act. 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.

We operate approximately 5,600 miles of gathering and intrastate transmission pipelines in Oklahoma, Kansas and Texas where we are regulated by the OCC, KCC, and RRC, respectively. We have a peak transportation capacity of 2.9 Bcf/d. The majority of our revenues are derived from services provided to affiliates. We primarily serve LDCs, large industrial companies, irrigation, power generation facilities and marketing companies. We compete directly with other interstate and intrastate pipelines and storage facilities. Competition for transportation services continues to increase as the FERC and state regulatory bodies continue to encourage more competition in the natural gas markets. Factors that affect competition are location, natural gas prices, fees for services and quality of service provided.

Our business is affected by the economy, natural gas price volatility and weather. The strength of the economy has a direct relationship on manufacturing and the resulting demand for natural gas used in the manufacturing process. Transportation throughput fluctuates due to rainfall that impacts irrigation demand, hot temperatures that affect power generation demand and cold temperatures that affect heating demand. Volatility in the natural gas market also impacts our customers’ decisions relating to injection and withdrawal of natural gas in storage.

Periodically, reassessments are made related to the amount of operational inventory needed to operate our storage facilities. As a result, we may sell a portion of our operational gas inventory, which allows us to increase our storage capacity.

Acquisition and Divestiture - The following acquisition and divestiture are described beginning on page 26:

•

sold transmission and gathering pipelines and compression facilities in March 2004

•

acquired transmission assets as part of the purchase of our Texas assets in January 2003

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,
Financial Results	2004		2003			2002
	*(Thousands of dollars)*
Transportation and gathering revenues	$	101,950	$	102,812		$	89,349
Storage revenues		45,791		42,086			37,101
Gas sales and other revenues		19,694		16,401			37,784
Cost of sales and fuel		40,887		47,637			46,650

Net margin		126,548		113,662			117,584
Operating costs		49,414		46,186			46,694
Depreciation, depletion, and amortization		17,349		16,694			17,563

Operating income	$	59,785	$	50,782		$	53,327

Other income (expense), net	$	2,835	$	1,495		$	4,649

Cumulative effect of a change in accounting principle, net of tax	$	—	$	(645	)	$	—


	Years Ended December 31,
Operating Information	2004		2003		2002
Volumes transported (MMcf)		432,844		449,261		507,972
Capital expenditures (Thousands of dollars)	$	12,287	$	15,234	$	20,554
Average natural gas price ($/MMBtu) (mid-continent region)	$	5.54	$	5.06	$	3.00

Operating Results - Net margin, which increased in 2004 compared to 2003, was impacted by:

•

an increase of $8.9 million related to the sale of operational gas inventory in December 2004,

•

increased storage revenues of $2.4 million due to spot storage transactions resulting from the weather and favorable forward pricing in 2004,

•

decreased cost of sales and fuel of $1.7 million primarily related to lower transportation volumes partially offset by increased fuel consumed and higher fuel prices, resulting from increased storage activity, and

•

decreased volumes transported as a result of milder and wetter weather reducing irrigation, power generation and heating demands.

The increase in operating costs in 2004 compared to 2003 is due to:

•

increased regulatory and pipeline integrity compliance costs of $2.9 million and

•

higher employee costs and legal costs for settled litigation.

In 2004, other income (expense), net includes the gain on the sale of the Texas assets of $6.9 million, which is partially offset by litigation costs.

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

•

transportation and gathering revenues,

•

storage revenues, and

•

cost of sales and fuel.

Additionally, we saw a decrease in gas sales and other revenues in 2003 compared to 2002. In 2002, we sold 7.2 Bcf of our operational inventory, which resulted in a positive impact on net margins of $12.7 million and allowed us to increase our storage capacity available in future periods. There was no comparable transaction in 2003. The increased storage capacity allowed us to earn an additional $1.4 million of net margin in 2003.

The sale of the operational inventory in 2002 was partially offset by adjustments related to the reconciliation of third party contractual storage and pipeline imbalance positions, which decreased net margin by $8.9 million.

In 2002, other income (expense), net included gains on the sale of storage assets in Oklahoma and transmission assets in Texas.

Distribution

Overview - Our Distribution segment provides natural gas distribution services to approximately 2 million customers in Oklahoma, Kansas and Texas. Operations are conducted through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. We serve residential, commercial, industrial and transportation customers in all three states. In Oklahoma and Kansas, we also serve wholesale customers and in Texas, we also serve public authority customers. Our Distribution segment provides gas service to approximately 86 percent, 71 percent, and 14 percent of the distribution markets of Oklahoma, Kansas and Texas, respectively. Oklahoma Natural Gas and Kansas Gas Service are subject to regulatory oversight by the OCC and KCC, respectively. Texas Gas Service is subject to regulatory oversight by the various municipalities that it serves, which have primary jurisdiction in their respective areas. Texas Gas Service’s rates in areas adjacent to the various municipalities and appellate matters are subject to regulatory oversight by the RRC. This segment also includes an interstate gas transportation company, OkTex Pipeline, which is regulated by the FERC.

Our Distribution segment’s operating results are primarily impacted by the number of customers, usage and the ability to establish delivery rates that provide an authorized rate of return on our investment and cost of service. 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.

In order to consolidate the three customer service systems in our Distribution segment and provide better customer service, we are implementing a new customer service system. The system was installed in Texas and Kansas in June 2004 and September 2004, respectively. We expect to install the system in Oklahoma in the future. We have implemented control processes and performed extensive testing on this system. This resulted in us identifying certain implementation issues which we are addressing. As with any implementation, there are inherent risks and uncertainties that could negatively impact us; however, we do not believe they will have a material impact on our financial statements or internal control structure.

Acquisition - The following acquisition is described beginning on page 26:

•

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,
Financial Results	2004		2003			2002
	*(Thousands of dollars)*
Gas sales	$	1,816,697	$	1,640,323		$	1,140,257
Cost of gas		1,367,186		1,213,811			806,251

Gross margin		449,511		426,512			334,006
Transportation revenues		82,006		75,322			59,877
Other revenues		25,799		24,415			20,510

Net margin		557,316		526,249			414,393
Operating costs		341,651		312,814			243,170
Depreciation, depletion, and amortization		105,438		95,654			76,063

Operating income	$	110,227	$	117,781		$	95,160

Other income (expense), net	$	1,375	$	(278	)	$	(3,183	)

Operating Results - Gas costs are passed through to distribution customers based on the actual cost of gas purchased by the respective distribution division. Substantial swings in gas sales can occur from year to year without significantly impacting our gross margin since most factors that affect gas sales also affect cost of gas by an equivalent amount.

Gross margin increased in 2004 compared to 2003 primarily due to the implementation of new rate schedules in Kansas and Oklahoma, which added $22.0 million and $14.5 million, respectively. These increases in gross margin were partially offset by:

•

decreased revenues of $4.9 million due to the impact of reduced customer usage in Kansas and Oklahoma primarily attributable to the impact of warmer weather on customers not subject to weather normalization, and

•

increased line loss expense of $2.4 million, net of rider recoveries, in Oklahoma.

Transportation revenues increased in 2004 compared to 2003 due to the acquisitions of the distribution system at the United States Army’s Fort Bliss in El Paso, Texas and a pipeline system that extends through the Rio Grande Valley region in Texas, both in August 2003. Additionally, certain commercial and industrial customers in Oklahoma have converted to transportation rates as a result of lower volume thresholds to qualify for transportation rates, which increased transportation revenue by $1.5 million and decreased gross margin by an equivalent amount.

Operating costs, which increased in 2004 compared to 2003, were impacted by:

•

increased information technology costs of $7.6 million, primarily associated with our customer service system, and

•

increased employee costs of $18.9 million.

Depreciation, depletion and amortization expense increased due to:

•

amortization expense of $5.7 million related to the new rate schedules in Kansas and Oklahoma and

•

depreciation expense of $4.1 million related to our investment in property, plant and equipment.

In 2003, gross margin increased compared to 2002 due to:

•

the addition of Texas Gas Service operations and

•

implementation of Kansas Gas Service’s new rate schedule in September 2003.

The $14.2 million reduction in gas costs in the second quarter of 2002 that resulted from the OCC Joint Stipulation offset part of these increases.

The addition of Texas Gas Service’s operations contributed approximately $91.0 million to gross margin, $106.7 million to net margin 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 Kansas Gas Service’s new rate schedule.

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

•

the addition of Texas Gas Service’s operations,

•

increased bad debt expense resulting from higher gas costs, and

•

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,
Operating Information	2004		2003		2002
Average number of customers		2,008,835		1,990,757		1,439,657
Customers per employee		664		652		623
Capital expenditures (Thousands of dollars)	$	142,515	$	153,405	$	115,569

	Years Ended December 31,
*Volumes (MMcf***)	2004		2003		2002
Gas sales
Residential		123,388		126,998		104,559
Commercial		41,984		45,054		36,459
Industrial		2,513		3,442		3,240
Wholesale		32,265		29,823		32,082
Public Authority		2,748		2,645		—

Total volumes sold		202,898		207,962		176,340
Transportation		239,914		231,425		194,706

Total volumes delivered		442,812		439,387		371,046


	Years Ended December 31,
Margin	2004		2003		2002
	*(Thousands of dollars)*
Gas sales
Residential	$	344,486	$	325,540	$	243,914
Commercial		92,793		89,581		69,410
Industrial		3,496		3,183		2,696
Wholesale		5,347		5,033		3,089
Public Authority		3,389		3,175		—
Regulatory adjustment		—		—		14,897

Gross margin		449,511		426,512		334,006
Transportation		82,006		75,322		59,877

Total margin	$	531,517	$	501,834	$	393,883

Residential, commercial and industrial volumes decreased in 2004 compared to 2003 due to:

•

warmer weather, which primarily affects residential and commercial customers, and

•

the continued migration of commercial and industrial customers to new transportation rates as a result of lower minimum transport thresholds in Oklahoma.

Wholesale gas sales, 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 increased in 2004 compared to 2003 as fewer volumes were required to meet the needs of residential, commercial and industrial customers resulting in greater volumes available for wholesale customers.

Public authority volumes, which remained relatively flat in 2004 compared to 2003, reflect volumes used by state agencies and school districts serviced by Texas Gas Service.

Transportation volumes increased in 2004 compared to 2003 primarily due to:

•

the acquisitions of the distribution system at the United States Army’s Fort Bliss in El Paso, Texas and a pipeline system that extends through the Rio Grande Valley region in Texas,

•

the continued migration of commercial and industrial customers to new transportation rates as a result of lower minimum transport thresholds in Oklahoma, and

•

Oklahoma Natural Gas’ marketing effort to add small usage transport customers.

Overall, gas volumes increased in 2003 compared to 2002 due to the addition of our Texas Gas Service customers. The combination of greater demand by Kansas retail customers in the first quarter of 2003 due to colder weather and increased volumes of gas injected into storage resulted in lower wholesale volumes available for sale in 2003. Transportation sales were also impacted by the initial migration of commercial and industrial customers to new transportation rates due to lower minimum transport thresholds in Oklahoma in 2003.

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. Our capital expenditure program included $35.0 million, $33.5 million and $18.3 million for new business development in 2004, 2003 and 2002, respectively.

Oklahoma Regulatory Initiatives - On January 28, 2005, Oklahoma Natural Gas filed a rate case with the OCC requesting annual rate relief of approximately $99.4 million, of which $38.5 million would be paid in additional income taxes. This amount includes $10.7 million of the interim rate relief granted in January 2004 and discussed below. The OCC has 180 days to issue a final order on the rate case. If approved, the new rates will take effect prior to the 2005/2006 heating season. Until a final order is received, Oklahoma Natural Gas will operate under its current rate schedule.

On January 30, 2004, the OCC issued an order allowing Oklahoma Natural Gas annual rate relief of $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 Oklahoma Natural Gas’ service lines and gas in storage investment. The OCC’s order also approved a modified distribution main extension policy and authorized Oklahoma Natural Gas to defer expected homeland security costs. The order authorized 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 Oklahoma Natural Gas’ next

general rate case, which was filed on January 28, 2005. We believe any refund obligation is remote and, accordingly, have not recorded a reserve. Approximately $7.0 million annually is considered final and not subject to refund.

A Joint Stipulation approved by the OCC on May 16, 2002, settled a number of outstanding Oklahoma Natural Gas cases pending before the OCC. The major cases settled were the OCC’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 Oklahoma Natural Gas, our subsidiaries and affiliated companies. In addition, all of the open inquiries related to the annual audits of Oklahoma Natural Gas’ fuel adjustment clause for 1996 to 2000 were closed as a result of this Stipulation.

The Stipulation has a $33.7 million value to Oklahoma Natural Gas customers that will be realized over a three-year period. In July 2002, immediate cash savings were provided to all Oklahoma Natural Gas 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. Oklahoma Natural Gas 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. Oklahoma Natural Gas’ 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, Oklahoma Natural Gas 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. Oklahoma Natural Gas fixed the price of approximately 28 percent, 43 percent and 37 percent of its anticipated 2004/2005, 2003/2004 and 2002/2003 winter gas supply deliveries, respectively.

Kansas Regulatory Initiatives - On September 17, 2003, the KCC issued an order approving $45 million in rate relief pursuant to the stipulated settlement agreement with Kansas Gas Service. The order settled the rate case filed by Kansas Gas Service in January 2003 and allowed Kansas Gas Service to begin operating under the new rate schedules effective September 22, 2003. After amortization of previously deferred costs, annual operating income increased by approximately $25.8 million.

Texas Regulatory Initiatives - On November 12, 2003, Texas Gas Service filed an appeal with the RRC based on the denial of proposed rate filing by the cities of Port Neches, Nederland and Groves, Texas. In July 2004, the RRC approved approximately $0.9 million in annual revenue relief. The interim rates were implemented in May 2003. On October 7, 2004, Texas Gas Service filed a petition in the District Court of Travis County, Texas seeking judicial review of certain of the ratemaking decisions contained in the RRC’s final order.

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.

Energy Services

Overview - Our Energy Services segment primarily purchases, stores, transports and markets natural gas in the retail and wholesale sector throughout most of the United States. We have a large leased storage and pipeline capacity position, primarily in the mid-continent region of the United States, with total transportation capacity of 1.7 Bcf/d. With total cyclical storage capacity of 83.5 Bcf, maximum withdrawal capability of 2.3 Bcf/d and maximum injection capability of 1.5 Bcf/d spread across 18 different facilities, we have direct access to most regions of the country and flexibility to capture volatility in the energy markets. Due to the seasonality of supply and demand balances, earnings will be significantly higher during the winter months than the summer months. We recently extended our energy services operations into Canada by leasing storage and pipeline capacity, allowing us to bring gas supply from western Canada into the market areas of the upper midwestern and northeastern parts of the United States. We also trade natural gas and power on a smaller scale.

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


	Years Ended December 31,
Financial Results	2004			2003			2002
	*(Thousands of dollars)*
Energy and power revenues	$	2,820,219		$	91,004		$	71,749
Energy trading revenues, net		113,814			229,782			209,429
Other revenues		849			961			948
Cost of sales and fuel		2,756,810			85,378			67,646

Net margin		178,072			236,369			214,480
Operating costs		34,669			33,699			27,674
Depreciation, depletion, and amortization		5,611			5,708			5,298

Operating income	$	137,792		$	196,962		$	181,508

Other income (expense), net	$	(6,920	)	$	(9,272	)	$	(4,871	)

Cumulative effect of a change in accounting principle, net of tax	$	—		$	(141,982	)	$	—


	Years Ended December 31,
Operating Information	2004		2003		2002
Natural gas marketed (Bcf)		1,073		1,012		999
Natural gas gross margin ($/Mcf)	$	0.14	$	0.17	$	0.13
Electricity marketed (MMwh)		4,881		2,086		2,228
Physically settled volumes (Bcf)		2,157		2,028		1,990
Capital expenditures (Thousands of dollars)	$	1,806	$	555	$	2,340

Operating Results - Net margin was negatively impacted in 2004 compared to 2003 primarily due to:

•

a decrease of $43.7 million in margins from marketing and seasonal gas sales from storage resulting from lower inter-regional basis spreads early in 2004,

•

a decrease of $35.9 million attributable to lower natural gas price volatility and the impact it had on our trading margins, and

•

a decrease of $4.7 million resulting from weaker spark spreads in the Southwest Power Pool and ERCOT.

These decreases in net margin were partially offset by:

•

increased revenues of $9.5 million in reservation fees received for natural gas peaking services and

•

increased revenues of $20.5 million related to the seasonal spread which resulted in increased sales volumes as we recycled gas in storage during the fourth quarter of 2004.

Included in net margin is the change in value of our derivative instruments subject to fair value accounting pursuant to Statement 133, which resulted in a gain of $39.1 million and $38.7 million for 2004 and 2003, respectively.

Natural gas volumes increased in 2004 compared to 2003 due to our expanded Canadian operations and higher natural gas storage inventory levels at the beginning of 2004, which shifted purchased volumes from storage injections to regional sales.

Our natural gas storage inventory level at December 31, 2004 was 70.6 Bcf, or 76.5 percent of capacity, compared to 68.5 Bcf, or 85 percent of capacity, at December 31, 2003.

At the beginning of the third quarter of 2004, we completed a reorganization of our Energy Services segment and renewed our focus on our physical marketing and storage business. We separated the management and operations of our wholesale marketing, retail marketing and trading activities and began accounting separately for the different types of revenue earned from these activities. Prior to the third quarter, we managed the Energy Services segment on an integrated basis and presented all energy trading activity on a net basis.

Concurrent with this reorganization, we evaluated the accounting treatment related to the presentation of revenues from the different types of activities to determine which amounts should be reported on a gross or net basis under the guidance in EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB

Statement No. 133 and Not “Held for Trading Purposes” as Defined in EITF Issue No. 02-3” (EITF 03-11). For derivative instruments considered held for trading purposes that result in physical delivery, the indicators 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” were used to determine the proper treatment. These activities and all financially settled derivative contracts will continue to be reported on a net basis.

For derivative instruments that are not considered “held for trading purposes” and that result in physical delivery, the indicators in EITF 03-11 and EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19) were used to determine the proper treatment. We began accounting for the realized revenues and purchase costs of these contracts that result in physical delivery on a gross basis beginning with the third quarter of 2004. We apply the indicators in EITF 99-19 to determine the appropriate accounting treatment for non-derivative contracts that result in physical delivery. Derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are also reported on a gross basis. Prior periods have not been adjusted for this change; therefore, comparisons to prior periods may not be meaningful. Reporting of these transactions on a gross basis did not impact operating income but resulted in an increase to revenues and cost of sales and fuel.

Marketing and Storage activities primarily include physical marketing (purchase and sales) using our firm storage and transportation capacity, including cash flow and fair value hedges and other derivative instruments to manage our risk associated with these activities. The combination of owning supply, controlling strategic assets and risk management services allows us to provide commodity-diverse products and services to our customers such as peaking and load following services. Power activities are also included in the Marketing and Storage business. Retail Marketing includes revenues from providing physical marketing and supply services to residential and small commercial and industrial customers. Financial trading revenues include activities that are generally executed using financially settled derivatives. These activities are normally short term in nature with a focus of capturing short term price volatility.

The following table shows the margins by activity, beginning with our reorganization on July 1, 2004.


	Six Months Ended December 31, 2004
	*(Thousands of dollars)*
Marketing and storage, gross	$	127,851
Less: Storage and transportation costs		(72,661	)

Marketing and storage, net		55,190
Retail marketing		8,628
Financial trading		24,638

Net margin	$	88,456

The increase in net margin in 2003 compared to 2002 is attributable to the effective utilization of our storage and transport capacity to capture the increased intra-month price volatility in early 2003 when daily price volatility was higher compared to 2002.

Net margins for 2002 include mark-to-market earnings of approximately $42.6 million, which represents the change in energy marketing and risk management assets and liabilities in 2002 resulting from the application of mark-to-market accounting on all energy contracts pursuant to EITF 98-10. These mark-to-market earnings include 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.

In the first quarter of 2002, we sold our bankruptcy claims in the Enron Corp. and Enron North America Corp. (ENA) bankruptcies, which increased net margin 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 Corp. and ENA. The claims were sold with recourse under certain conditions. We have repurchased a portion of the Enron Corp. guaranty claim that Enron Corp. sought to avoid in the adversary proceeding. We are now providing the defense of the adversary proceeding for both the portion of the guaranty claim constituting the repurchased claim and also the portion of the guaranty claim previously sold. In addition to the adversary proceeding, Enron Corp. and ENA have filed a new objection to portions of the guaranty claim and to portions of the underlying claim against ENA, creating a new contested matter in the Enron Corp. and ENA bankruptcy cases which involve different legal and factual issues than those raised in the adversary proceeding. Enron Corp. and ENA allege in this matter that the guaranty claim and underlying claim against ENA are overstated. The filing of this matter may trigger additional obligations for us to repurchase some of the claims previously sold. Based on the information currently available to us, we do not expect this matter to have a material adverse effect on us.

In 2003, we also benefited from an increase in our natural gas retail operations, which expanded into Wyoming, Nebraska and Texas, and an increase in power-related margins due to our expansion into ERCOT in the fourth quarter of 2003.

Operating costs increased in 2003 compared to 2002 due to our expanded retail operations and an increase in ad valorem taxes on our storage inventory due to rate adjustments.

Other income (expense), net includes the accrual of the U.S. Commodity Futures Trading Commission (CFTC) settlement in 2003.

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 credit agreements, 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 have no material guarantees of debt or other commitments to unaffiliated parties. During 2003 and 2004, our capital expenditures were financed through operating cash flows and short and long-term debt. Capital expenditures for 2004 were $264 million compared to $215 million in 2003, exclusive of any acquisitions.

Financing - Financing is provided through our commercial paper program and long-term debt. We also have a credit agreement, as discussed below, which is used as a back-up for the commercial paper program. 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. We used commercial paper to finance the acquisition of Northern Plains.

In September 2004, we entered into a $1.0 billion five-year credit agreement. The principal amount of the credit facility may be increased by $200 million if requested by us and the corresponding incremental commitments are received from new or existing lenders. The interest rate is a floating rate based at our election on either (i) the higher of prime or one-half of one percent above the Federal Funds Overnight Rate, which is the rate that banks charge each other for the overnight borrowing of funds, or (ii) the Eurodollar rate plus a set number of basis points based on our current long-term unsecured debt ratings by Moody’s Investors Service and Standard and Poor’s Rating Services (S&P). The credit agreement contains customary affirmative and negative covenants including covenants relating to liens, investments, fundamental changes in our business, changes in the nature of our business, transactions with affiliates, the use of proceeds, a limit on our debt to capital ratio, a limit on investments in master limited partnerships and a covenant that prevents us from restricting our subsidiaries’ ability to pay dividends to ONEOK, Inc. At December 31, 2004, we had no amounts outstanding under this credit agreement.

We entered into an agreement with KBC Bank NV in April 2004. The agreement gives us access to an uncommitted line of credit for loans and letters of credit up to a maximum principal amount of $10 million. The rate charged on any outstanding amount is the higher of prime or one-half of one percent above the Fed Funds overnight rate. This agreement remains in effect until canceled by KBC Bank NV. This agreement does not contain any covenants more restrictive than those in our $1.0 billion five-year credit agreement. At December 31, 2004, we had no amounts outstanding under this credit agreement.

Certain other long-term debt agreements have negative covenants that relate to liens and sale/leaseback transactions.

The total amount of short term borrowings authorized by our Board of Directors is $1.2 billion. At December 31, 2004, we had $644 million in commercial paper outstanding and approximately $9.5 million in cash and temporary investments. We also had $1.9 billion of long-term debt outstanding, including current maturities. As of December 31, 2004, we could have

issued $1.7 billion of additional long-term debt under the most restrictive provisions contained in our various borrowing agreements.

The following table sets forth our capitalization structure for the periods indicated.


	Years Ended December 31,
	2004		2003
Long-term debt	54	%	60	%
Equity	46	%	40	%

Debt (including Notes payable)	61	%	67	%
Equity	39	%	33	%

Both 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 52 percent equity and 48 percent long-term debt at December 31, 2004. 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 55 percent equity and 45 percent long-term debt at December 31, 2004.

Since September 17, 2004, the Thrift Plan for Employees of ONEOK, Inc. and subsidiaries (the Thrift Plan) has from time to time purchased shares of our common stock on the open market to meet the purchase requirements generated by participants in the Thrift Plan. Previously, the Thrift Plan used newly issued shares to meet the participants’ purchase requirements. All participant purchases under this plan are voluntary. We use newly issued shares to meet the purchase requirements generated by our Dividend Reinvestment Plan and our Long-Term Incentive Plan.

On March 1, 2005, we had $335 million of long-term debt mature. We funded this payment with working capital and the issuance of commercial paper in the short-term market.

We have 16.1 million equity units outstanding at December 31, 2004. Each unit consists of two components, an equity purchase contract and a note (see Notes H and J of Notes to Consolidated Financial Statements in this Form 10-K for additional information). In November 2005, we will remarket the notes and will put the cash received into a treasury portfolio pledged as collateral against the purchase contracts. This action will have no effect on our liquidity. In February 2006, the purchase contracts are required to be exercised. This will result in our receipt of $402.5 million and the issuance of common shares of stock, the number of which will depend upon the average closing price of our common stock for the 20 trading days prior to the date of issuance. For more information, refer to the discussion in Financing Cash Flows or to our Prospectus Supplement dated January 23, 2003.

Currently, we have $848.2 million available under one of our shelf registration statements on Form S-3, for the issuance and sale of shares of our common stock, debt securities, preferred stock, stock purchase contracts and stock purchase units. We also have $402.5 million remaining under another shelf registration statement on Form S-3 to cover the issuance of common stock required upon settlement of the forward purchase contracts that are part of the equity units.

Stock Buy Back Program - In January 2005, our Board of Directors authorized a stock buy back program to repurchase up to 7.5 million shares of our common stock currently issued and outstanding. The shares will be repurchased from time to time in open market transactions or through privately negotiated transactions at our discretion, subject to market conditions and other factors. The program will terminate after two years, unless extended by our Board of Directors.

Credit Rating - Our credit ratings are currently a “BBB+” (stable outlook) by S&P and a “Baa1” (stable outlook) by Moody’s Investors 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 ratings are the debt to capital ratio, pretax and after-tax interest 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 and we could potentially lose access to commercial paper borrowings. 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 a $1.0 billion credit agreement, which expires September 16, 2009.

Our Energy Services segment relies upon the investment grade rating of our senior unsecured long-term debt to satisfy credit requirements with most of our counterparties. If our credit ratings were to decline below investment grade, our ability to participate in energy marketing and trading activities could be significantly limited. Without an investment grade rating, we may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments. At December 31, 2004, the amount we could have been required to fund for the few counterparties with which we have a Credit Support Annex within our International Swaps and Derivatives Association Agreements is approximately $40.2 million. A decline in our credit rating below investment grade may also significantly impact other business segments.

We have reviewed our commercial paper agreement, trust indentures, building leases, equipment leases, and marketing, trading and risk contracts and other various contracts which may be subject to rating triggers and no such 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, 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 and Postretirement Benefit Plans - We calculate benefit obligations based upon generally accepted actuarial methodologies using the projected benefit obligation (PBO) for pension plans and the accumulated postretirement benefit obligation for other postretirement plans. The determination of pension costs and other postretirement obligations as of December 31 are determined using a September 30 measurement date. The benefit obligations are the actuarial present value of all benefits attributed to employee service rendered. The PBO is measured using the pension benefit formula and assumptions as to future compensation levels. A plan’s funded status is calculated as the difference between the benefit obligation and the fair value of plan assets. Our funding policy for the pension plans is to make annual contributions in accordance with regulations under the Internal Revenue Code and in accordance with generally accepted actuarial principles. Contributions made to the pension plan and postretirement benefit plan in 2004 were $6.8 million and $17.2 million, respectively. For 2005, we anticipate our total contributions to be $1.8 million and $16.1 million, respectively. We will be reimbursed approximately $2.3 million by Northern Border Partners for defined benefit pension plan expenses that we incur for them. We believe we have adequate resources to fund our obligations under our pension plan.

Oklahoma Corporation Commission - A Joint Stipulation approved by the OCC on May 16, 2002, settled a number of outstanding Oklahoma Natural Gas cases pending before the OCC. The major cases settled were the OCC’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 Oklahoma Natural Gas, our subsidiaries and affiliated companies. In addition, all of the open inquiries related to the annual audits of Oklahoma Natural Gas’ fuel adjustment clause for 1996 to 2000 were closed as a result of this Stipulation.

Cash Flow Analysis

Operating Cash Flows - Operating cash flows increased by $204.1 million for the year ended December 31, 2004, compared to the same period in 2003. The increase in operating cash flows was primarily the result of a net increase in working capital of $513.1 million in 2003 compared to a net increase in working capital of $332.0 million in 2004. These increases primarily related to increases in accounts receivable and gas inventory, partially offset by increases in accounts payable.

Working capital changes had the opposite impact on 2003 compared to 2002, contributing to a decrease in operating cash flows of $805.1 million. The high levels of gas in storage at December 31, 2003, including amounts previously classified as energy marketing and risk management assets, resulted in a substantial negative impact on operating cash flows.

The impact of higher commodity prices in 2004 and 2003 on accounts receivables, accounts payable and gas inventory 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 process 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 2004 and 2003, this lag resulted in a negative impact on cash flows. In 2002, the changes in accounts receivable and accounts payable were primarily due to the increase in net energy trading revenues.

Our Energy Services segment’s deposits, or margin requirements, increase or decrease from year to year based on the level of open positions on our contracts as well as commodity prices and price volatility. This change impacts operating cash flows.

Investing Cash Flows - Acquisitions in 2004 represent the cash purchase of Northern Plains. Increased capital expenditures in 2004 are primarily due to additional drilling by our Production segment. Proceeds from the sale of property include the sales of certain natural gas transmission and gathering pipelines, compression assets, gas distribution systems and investments in 2004.

Acquisitions in 2003 primarily represent the cash purchase of our Texas distribution 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 gas and oil company. Proceeds from the sale of equity investments represent the sale of our interest in MHR in 2002.

Financing Cash Flows - During the first quarter of 2004, we paid off $600 million in notes payable using cash generated from operating activities and proceeds from our February 2004 equity offering. During the second half of 2004, we incurred $644 million of notes payable, which includes the acquisition of Northern Plains and funds used in the ordinary course of business. This resulted in an increase of $44 million in notes payable at December 31, 2004 compared to the previous year end.

We terminated $670 million of our interest rate swap agreements in the first quarter of 2004 to lock-in savings and generate a positive cash flow of $91.8 million, which included $8.9 million of interest savings previously recognized. These interest rate swaps were previously initiated as a strategy to hedge the fair value of fixed rate long-term debt. The proceeds received upon termination of the interest rate swaps, net of amounts previously recognized, will be recognized in the income statement over the term of the debt instruments originally hedged.

During the first quarter of 2004, we sold 6.9 million shares of our common stock to an underwriter at $21.93 per share, resulting in proceeds to us, before expenses, of $151.3 million.

During the first quarter of 2003, 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 an 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,

•

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

•

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 by the ratio of $25 divided by the average closing price.

Also, during the first quarter of 2003, 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 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.

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 J and L, respectively, of Notes to the Consolidated Financial Statements in this Form 10-K.


	Payments Due by Period
Contractual Obligations	Total		2005		2006		2007		2008		2009		Thereafter
	*(Thousands of dollars)*
Long-term debt	$	1,829,491	$	341,532	$	306,547	$	6,562	$	409,080	$	107,624	$	658,146
Notes payable		644,000		644,000		—		—		—		—		—
Operating leases		287,887		47,407		60,371		42,002		39,524		37,051		61,532
Storage contracts		94,669		32,566		25,529		17,647		10,162		6,561		2,204
Firm transportation contracts		420,609		110,219		77,234		60,475		32,519		27,829		112,333
Purchase commitments, rights-of-way and other		23,513		11,202		3,140		1,937		1,943		1,752		3,539
Pension plan (a)		14,856		1,754		3,356		4,343		3,474		1,929		—
Other postretirement benefit plan (a)		80,573		16,061		15,917		16,049		16,220		16,326		—

Total contractual obligations	$	3,395,598	$	1,204,741	$	492,094	$	149,015	$	512,922	$	199,072	$	837,754

(a)	- No payment amounts are provided for our pension and other postretirement benefit plans in the “Thereafter” column since there is no termination date for these plans.

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 a 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.

Energy Marketing and Risk Management Assets and Liabilities

The following table sets forth the fair value component of the energy marketing and risk management assets and liabilities, excluding derivative instruments that have been declared as either fair value or cash flow hedges.


Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities

(Thousands of dollars)



Net fair value of contracts outstanding at December 31, 2003	$	(18,354	)
Contracts realized or otherwise settled during the period		(6,847	)
Fair value of new contracts when entered into during the period		40,188
Other changes in fair value		2,964

Net fair value of contracts outstanding at December 31, 2004	$	17,951

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 energy marketing and risk management assets and liabilities. 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, 2004 and 2003 includes energy commodity contracts considered derivatives under Statement 133, including forwards, futures, swaps and options.

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


	Fair Value of Contracts at December 31, 2004
Source of Fair Value (1)	Matures through March 2005		Matures through March 2008			Matures through March 2010			Matures after March 2010		Total Fair Value
	*(Thousands of dollars)*
Prices actively quoted (2)	$	1,580	$	11,586		$	—		$	—	$	13,166
Prices provided by other external sources (3)		14,550		(14,181	)		(3,703	)		210		(3,124	)
Prices derived from quotes, other external sources and other assumptions (4)		2,766		2,709			2,331			103		7,909

Total	$	18,896	$	114		$	(1,372	)	$	313	$	17,951

(1)	Fair value is the mark-to-market component of forwards, futures, swaps, and options, net of applicable reserves. These fair values are reflected as a component of assets and liabilities from energy marketing and 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 Energy Services segment’s financial and commodity risk from fixed-price transactions at December 31, 2004.


	Investment Grade Credit Quality (1)			Below Investment Grade Credit Quality
	*(Thousands of dollars)*
Gas and electric utilities	$	14,423		$	(11,402	)
Financial institutions		6,766			—
Oil and gas producers		(7,983	)		7,073
Industrial and commercial		(24,050	)		1,490
Other		(6,185	)		(1,270	)

Net value of fixed-price transactions	$	(17,029	)	$	(4,109	)

(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

In December 2004, the FASB issued Statement 123R. Statement 123R requires companies to expense the fair value of share-based payments. In addition, there are also changes related to the share-based payment expense calculation. Statement 123R is effective for the interim period beginning after June 15, 2005. We are currently assessing the impact of adopting Statement 123R, but we do not believe it will have a material impact on our condition and results of operations since we have been expensing share-based payments since the adoption of Statement 148 on January 1, 2003.

In December 2003, the FASB issued FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities” (FIN 46R) that addresses the consolidation of variable interest entities. We adopted FIN 46R in the first quarter of 2004. FIN 46R had no impact on our consolidated financial statements for 2004.

The EITF is currently deliberating EITF Issue No. 04-5, “Investor’s Accounting for an Investment in a Limited Partnership When the Investor is the Sole General Partner and the Limited Partners Have Certain Rights” (EITF 04-5). Since the changes proposed in EITF 04-5 would result in different guidance in accounting for general partners that are in different industries, the FASB Staff is planning to amend SOP 78-9, Accounting for Investments in Real Estate Ventures to be consistent with EITF 04-5. SOP 78-9-a, “Interaction of AICPA Statement of Position 78-9, Accounting for Investments in Real Estate Ventures, and EITF Issue No. 04-5, “Investor’s Accounting for an Investment in a Limited Partnership When the Investor Is the Sole General Partner and the Limited Partners Have Certain Rights” (SOP 78-9-a) will have the presumption that a general partner controls a limited partnership and therefore should consolidate the partnership. This presumption can be overcome if the limited partners have kick-out or substantive participating rights. We could be required to consolidate Northern Border Partners; however we will begin to evaluate the impact and transition method if or when SOP 78-9-a and EITF 04-5 are finalized. The anticipated effective date of SOP 78-9-a and EITF 04-5 is January 1, 2006.

Other

Environmental - We are 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 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 NGLs, or at any facility 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 six sites with regulatory closure achieved at two of these locations, and have begun assessments at the remaining sites. The site situations are not similar and we have no previous experience with similar remediation efforts. We have completed some analysis of the remaining six sites, but are unable to accurately estimate individual or aggregate costs that may be required 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, was approximately $700,000. Total remedial costs for each of the remaining sites are expected to exceed $500,000 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.

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 a civil penalty against us, based on alleged violations of several KDHE

regulations. On April 5, 2004, we entered into a Consent Order with the KDHE in which we paid a civil penalty in the amount of $180,000 and reimbursed the KDHE for its costs related to the investigation of the incident in the amount of approximately $79,000. In addition, the Consent Order requires us to conduct an environmental remediation and a geoengineering study. Based on information currently available to us, we do not believe there are any material adverse effects resulting from the Consent Order.

In February 2004, a jury awarded the plaintiffs in a lawsuit involving property damage alleged to relate to the gas explosions and eruptions, $1.7 million in actual damages. In April 2004, the judge in this case awarded punitive damages in the amount of $5.25 million. We have filed an appeal of the jury verdict and the punitive damage award. Based on information currently available to us, we believe our legal reserves and insurance coverage is adequate and that this matter will not have a material adverse effect on us.

The two class action lawsuits 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 in January 2001 resulted in jury verdicts in September 2004. The jury awarded the plaintiffs in the residential class $5 million in actual damages, which is covered by insurance. In the other class action relating to business claims, the jury awarded no actual damages. The jury rejected claims for punitive damages in both cases. We are reviewing our options for appealing the verdict rendered in the residential claimants’ class action.

With the exception of appeals, all litigation regarding the Yaggy facility has been resolved.

Enron - We have repurchased a portion of the Enron Corp. guaranty claim that Enron Corp. and ENA sought to avoid in the adversary proceeding. We are now providing the defense of the adversary proceeding for both the portion of the guaranty claim constituting the repurchased claim and also the portion of the guaranty claim previously sold. Based on information currently available to us, we do not expect the adversary proceeding to have a material adverse effect on us.

In addition to the adversary proceeding, Enron Corp. and ENA have filed a new objection to portions of the guaranty claim and to portions of the underlying claim against ENA, creating a new contested matter in the Enron Corp. and ENA bankruptcy cases which involve different legal and factual issues than those raised in the adversary proceeding. Enron Corp. and ENA allege in this matter that the guaranty claim and underlying claim against ENA are overstated. The filing of this matter may trigger additional obligations for us to repurchase some of the claims previously sold. Based on the information currently available to us, we do not expect this matter to have a material adverse effect on us.

Forward-Looking Statements and Risk Factors

Some of the statements contained and incorporated in this Annual Report on 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 and legal proceedings, market conditions and other matters. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in various circumstances. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of operations and other statements contained or incorporated in this Form 10-K generally 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 forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions, risks and other factors referred to specifically in connection with forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others:

•

risks associated with any reduction in our credit ratings,

•

the effects of weather and other natural phenomena on energy sales and prices,

•

competition from other energy suppliers as well as alternative forms of energy,

•

the capital intensive nature of our business,

•

further deregulation of the natural gas business,

•

competitive changes in the natural gas gathering, transportation and storage business resulting from deregulation 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 counterparties,

•

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

•

the uncertainty of estimates, including accruals, cost of environmental remediation, and gas and oil reserves,

•

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

•

the effects of changes in governmental policies and regulatory actions, including, changes with respect to income taxes, environmental compliance, and 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 risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks,

•

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 and bond 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 or the risk of delay in growth or recovery in the U.S. economy,

•

risks associated with the adequate supply of natural gas to our gathering and processing facilities, including production declines which outpace new drilling,

•

risks inherent in the implementation of new software, such as our customer service system, and the impact on the timeliness of information for financial reporting,

•

the risk that material weaknesses or significant deficiencies in our internal controls over financial reporting could emerge or that minor problems could become significant,

•

the impact of the outcome of pending and future litigation, 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.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Non-Regulated Businesses, Including Energy Services - 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 five years, gas in storage utilized by the Energy Services segment, NGLs in storage utilized by ONEOK NGL Marketing, 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 Energy Services 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 Operation 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 Operation 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 - Kansas Gas Service uses derivative instruments to hedge the cost of anticipated gas purchases during the winter heating months to protect Kansas Gas Service customers from upward volatility in the market price of natural gas. At December 31, 2004, Kansas Gas Service had derivative instruments in place to hedge the cost of natural gas purchases for 4.4 Bcf, representing part of their gas purchase requirements for the 2004/2005 winter heating months. Gains or losses associated with the Kansas Gas Service hedges are included in and recoverable through the monthly PGA.

From time to time, Texas Gas Service 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, 2004, Texas Gas Service had no derivative instruments in place to hedge the cost of natural gas purchases. Gains or losses associated with the derivative instruments would be included in and recoverable through the monthly PGA.

Value-at-Risk (VAR) Disclosure of Market Risk - We measure market risk in the energy marketing and risk management, trading and non-trading portfolios of our non-regulated businesses using a 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. 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 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’ energy marketing and risk management, non-trading and 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.

The potential impact on our future earnings, as measured by the VAR, was $9.6 million and $11.0 million at December 31, 2004 and 2003, respectively. The following table details the average, high and low VAR calculations.


	Years Ended December 31,
Value-at-Risk	2004		2003
	*(Millions of dollars)*
Average	$	3.8	$	3.9
High	$	17.7	$	17.1
Low	$	0.6	$	0.5

The variations in the VAR data are reflective of market volatility and changes in the portfolios 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. The audit committee of our Board of Directors has oversight responsibilities for our risk management limits and 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 Treasurer and the Vice President of Audit Services and Risk Control, who are assigned responsibility for establishing and enforcing the policies, procedures and limits. 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 and Currency Risk

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, 2004, the interest rate on 59.4 percent of our debt was fixed, after considering the effect of interest rate swaps.

During the first quarter of 2004, we terminated $670 million of our interest rate swap agreements to lock in savings and received $91.8 million, which includes $8.9 million of interest rate savings previously recorded. These interest rate swaps were previously initiated as a strategy to hedge the fair value of fixed rate, long-term debt. The net proceeds received upon termination of the interest rate swaps were $81.9 million, after reduction for ineffectiveness and unpaid interest. Ineffectiveness related to these hedges of approximately $1.0 million is included in interest expense. Through December 31, 2004, $8.1 million in interest expense savings has been recognized and the remaining amount of $73.8 million will be recognized in the income statement over the remaining term of the debt instruments originally hedged. Consequently, the remaining savings in interest expense will be recognized over the following periods:


2005	$	10.0 million
2006	$	10.0 million
2007	$	10.0 million
2008	$	10.0 million
Thereafter	$	33.8 million

We entered into new swap agreements to replace the terminated agreements. Currently, $740 million of fixed rate debt is swapped to floating. The floating rate debt is based on both the three and six-month London InterBank Offered Rate (LIBOR), depending upon the swap. Based on the current LIBOR strip, the weighted average rate on the $740 million of debt will be reduced from 6.81 percent to 4.54 percent. This, along with the amortization of the terminated swaps, will result in an estimated savings of $16.8 million during 2005. The swaps and amortization resulted in approximately $24.4 million in savings in 2003 and $27.6 million in savings during 2004. At December 31, 2004, we had a net liability of $17.6 million recorded in energy marketing and risk management liabilities to reflect the fair value of the current interest rate swaps. Long-term debt reflects the offset to the fair value of the swaps, with a decrease in overall debt of $17.6 million.

At December 31, 2004, 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 $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.

Currency Rate Risk - With our Energy Services segment’s expansion into Canada, we are subject to currency exposure related to our firm transportation and storage contracts. Our objective with respect to currency risk is to reduce the exposure due to exchange-rate fluctuations. We use physical forward transactions, which result in an actual two-way flow of currency on the settlement date since we exchange U.S. dollars for Canadian dollars with another party. The notional amounts in the physical forward transactions approximate the timing and payment amounts related to our firm transportation and storage contracts. We have not designated these transactions for hedge accounting treatment; therefore, the gains and losses associated with the change in fair value are recorded in operating income. At December 31, 2004, our exposure to risk from currency translation was not material.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

ONEOK, Inc.:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that ONEOK, Inc. maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). ONEOK, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that ONEOK, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, ONEOK, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of ONEOK, Inc. and subsidiaries as of December 31, 2004 and 2003, 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, 2004, and our report dated March 7, 2005 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

Tulsa, Oklahoma

March 7, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, 2004 and 2003 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, 2004. 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 the standards of the Public Company Accounting Oversight Board (United States). 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, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.

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, and the provisions of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, effective January 1, 2002.

We also audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of ONEOK, Inc.’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 7, 2005, expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

KPMG LLP

Tulsa, Oklahoma

March 7, 2005

This page intentionally left blank.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME


	Years Ended December 31,
	2004		2003			2002
	*(Thousands of dollars, except per share amounts)*
Revenues
Operating revenues, excluding energy trading revenues	$	5,874,266	$	2,769,214		$	1,894,851
Energy trading revenues, net		113,814		229,782			209,429

Total Revenues		5,988,080		2,998,996			2,104,280

Cost of sales and fuel		4,743,835		1,862,518			1,128,620

Net Margin		1,244,245		1,136,478			975,660

Operating Expenses
Operations and maintenance		498,778		463,116			401,328
Depreciation, depletion, and amortization		188,725		160,861			147,843
General taxes		66,732		66,437			55,011

Total Operating Expenses		754,235		690,414			604,182

Operating Income		490,010		446,064			371,478

Other income		17,730		8,164			12,426
Other expense		12,127		5,224			19,038
Interest expense		103,468		104,185			106,405

Income before Income Taxes		392,145		344,819			258,461

Income taxes		149,967		130,527			102,485

Income from Continuing Operations		242,178		214,292			155,976
Discontinued operations, net of taxes (Note C):
Income from operations of discontinued component		—		2,342			10,648
Gain on sale of discontinued component		—		39,739			—
Cumulative effect of changes in accounting principles, net of tax (Note A and D)		—		(143,885	)		—

Net Income		242,178		112,488			166,624
Preferred stock dividends		—		24,211			37,100

Income Available for Common Stock	$	242,178	$	88,277		$	129,524

Earnings Per Share of Common Stock (Note R)
Basic:
Earnings per share from continuing operations	$	2.38	$	2.38		$	1.31
Earnings per share from operations of discontinued component		—		0.02			0.09
Earnings per share from gain on sale of discontinued component		—		0.36			—
Earnings per share from cumulative effect of changes in accounting principles		—		(1.28	)		—

Net Earnings Per Share, Basic	$	2.38	$	1.48		$	1.40

Diluted:
Earnings per share from continuing operations	$	2.30	$	2.13		$	1.30
Earnings per share from operations of discontinued component		—		0.02			0.09
Earnings per share from gain on sale of discontinued component		—		0.35			—
Earnings per share from cumulative effect of changes in accounting principles		—		(1.28	)		—

Net Earnings Per Share, Diluted	$	2.30	$	1.22		$	1.39

Average Shares of Common Stock (Thousands)
Basic		101,965		80,569			99,914
Diluted		105,461		96,999			100,528

Dividends Declared Per Share of Common Stock	$	0.88	$	0.69		$	0.62

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS


	December 31, 2004		December 31, 2003
	*(Thousands of dollars)*
Assets
Current Assets
Cash and cash equivalents	$	9,458	$	12,172
Trade accounts and notes receivable, net		1,432,425		970,141
Materials and supplies		22,475		18,962
Gas in storage		593,028		500,439
Energy marketing and risk management assets (Note D)		388,672		233,013
Deposits		32,394		42,424
Other current assets		40,365		46,184

Total Current Assets		2,518,817		1,823,335

Property, Plant and Equipment
Production		455,964		404,254
Gathering and Processing		1,066,612		1,036,080
Transportation and Storage		705,115		699,676
Distribution		2,916,440		2,813,800
Energy Services		128,120		126,315
Other		134,199		99,549

Total Property, Plant and Equipment		5,406,450		5,179,674
Accumulated depreciation, depletion and amortization		1,619,629		1,487,848

Net Property, Plant and Equipment		3,786,821		3,691,826

Deferred Charges and Other Assets
Regulatory assets, net (Note E)		203,547		213,915
Goodwill (Note F)		225,188		225,615
Energy marketing and risk management assets (Note D)		71,310		67,294
Prepaid pensions		127,649		120,618
Investments and other		259,317		69,283

Total Deferred Charges and Other Assets		887,011		696,725

Total Assets	$	7,192,649	$	6,211,886

See accompanying Notes to Consolidated Financial Statements.

CONSOLIDATED BALANCE SHEETS


	December 31, 2004			December 31, 2003
	*(Thousands of dollars)*
Liabilities and Shareholders’ Equity
Current Liabilities
Current maturities of long-term debt	$	341,532		$	6,334
Notes payable		644,000			600,000
Accounts payable		1,185,351			813,895
Accrued taxes		36,346			102,637
Accrued interest		32,807			32,999
Customers’ deposits		39,478			34,692
Unrecovered purchased gas costs		64,322			51,378
Energy marketing and risk management liabilities (Note D)		409,633			246,474
Deferred income taxes		16,861			6,194
Other		144,465			130,174

Total Current Liabilities		2,914,795			2,024,777

Long-term Debt, excluding current maturities		1,543,202			1,878,264
Deferred Credits and Other Liabilities
Deferred income taxes		644,512			559,356
Energy marketing and risk management liabilities (Note D)		102,865			66,956
Lease obligation		86,817			100,292
Other deferred credits		294,754			340,849

Total Deferred Credits and Other Liabilities		1,128,948			1,067,453

Total Liabilities		5,586,945			4,970,494

Commitments and Contingencies (Note L)
Shareholders’ Equity
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 107,143,722 shares and outstanding 104,106,285 shares at December 31, 2004; issued 98,194,674 shares and outstanding 95,194,666 shares at December 31, 2003		1,071			982
Paid in capital		1,017,603			815,870
Unearned compensation		(1,413	)		(3,422	)
Accumulated other comprehensive loss (Note G)		(9,591	)		(17,626	)
Retained earnings		649,240			495,971
Treasury stock, at cost: 3,037,437 shares at December 31, 2004 and 3,000,008 shares at December 31, 2003		(51,206	)		(50,383	)

Total Shareholders’ Equity		1,605,704			1,241,392

Total Liabilities and Shareholders’ Equity	$	7,192,649		$	6,211,886

See accompanying Notes to Consolidated Financial Statements.

This page intentionally left blank.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2004			2003			2002
	*(Thousands of Dollars)*
Operating Activities
Income from continuing operations	$	242,178		$	214,292		$	155,976
Depreciation, depletion, and amortization		188,725			160,861			147,843
Gain on sale of assets		(10,586	)		(286	)		(2,863	)
Gain on sale of equity investments		—			—			(7,622	)
Income from equity investments		(2,401	)		(1,489	)		(365	)
Deferred income taxes		91,238			111,788			165,723
Stock based compensation expense		14,330			6,289			2,121
Allowance for doubtful accounts		13,309			14,073			12,478
Changes in assets and liabilities (net of acquisition effects):
Accounts and notes receivable		(476,017	)		(156,887	)		(122,733	)
Inventories		(96,510	)		(428,408	)		27,334
Unrecovered purchased gas costs		12,944			54,954			41,522
Deposits		10,030			(42,424	)		41,781
Regulatory assets		(15,395	)		(4,586	)		611
Accounts payable and accrued liabilities		322,387			100,961			239,167
Energy marketing and risk management assets and liabilities		(22,033	)		27,651			(19,038	)
Other assets and liabilities		(67,390	)		(64,348	)		83,322

Cash Provided by (Used in) Continuing Operations		204,809			(7,559	)		765,257
Cash Provided by Discontinued Operations		—			8,285			43,789

Cash Provided by Operating Activities		204,809			726			809,046

Investing Activities
Changes in other investments, net		2,786			(1,126	)		2,015
Acquisitions		(176,709	)		(690,302	)		(4,036	)
Capital expenditures		(264,110	)		(215,148	)		(210,652	)
Proceeds from sale of property		21,241			3,084			102,390
Proceeds from sale of equity investment		—			—			57,461
Other investing activities		(5,603	)		3,635			3,444

Cash Used in Continuing Operations		(422,395	)		(899,857	)		(49,378	)
Cash Provided by (Used in) Discontinued Operations		—			280,669			(22,393	)

Cash Used in Investing Activities		(422,395	)		(619,188	)		(71,771	)

Financing Activities
Borrowing (payments) of notes payable, net		44,000			334,500			(333,606	)
Issuance of debt		—			404,964			3,500
Termination of interest rate swaps		82,915			—			—
Payment of debt issuance costs		—			(2,564	)		—
Payment of debt		(1,364	)		(16,148	)		(305,623	)
Purchase of Series A Convertible Preferred Stock		—			(300,000	)		—
Purchase of common stock		—			(50,000	)		—
Issuance of common stock		189,777			224,412			—
Issuance (purchase) of treasury stock, net		(823	)		12,616			3,673
Dividends paid		(89,229	)		(71,242	)		(74,510	)
Other financing activities		(10,404	)		20,574			14,584

Cash Provided by (Used in) Financing Activities		214,872			557,112			(691,982	)

Change in Cash and Cash Equivalents		(2,714	)		(61,350	)		45,293
Cash and Cash Equivalents at Beginning of Period		12,172			73,522			28,229

Cash and Cash Equivalents at End of Period	$	9,458		$	12,172		$	73,522

See accompanying Notes to Consolidated Financial Statements.

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, 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
Common 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.

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, 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
Common 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

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 loss	—	—			—			—			—		—

Total comprehensive income

Re-issuance of treasury stock		—			—			—			—		1,608
Common stock offering	13,800,000	—			—			—			138		227,893
Common 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
Net income	—	—			—			—			—		—
Other comprehensive income	—	—			—			—			—		—

Total comprehensive income

Receipts and forfeitures of restricted stock	—	—			—			—			—		—
Common stock offering	6,900,000	—			—			—			69		151,248
Common stock issuance pursuant to various plans	2,049,048	—			—			—			20		38,736
Offering costs	—	—			—			—			—		(296	)
Stock-based employee compensation expense	—	—			—			—			—		12,045
Common stock dividends - $0.88 per share	—	—			—			—			—		—

December 31, 2004	107,143,722	—		$	—		$	—		$	1,071	$	1,017,603

See accompanying Notes to Consolidated Financial Statements.

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 loss		—			(12,080	)		—			—			(12,080	)

Total comprehensive income														100,408

Re-issuance of treasury stock		—			—			—			15,458			17,066
Common stock offering		—			—			—			—			228,031
Common 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
Net income		—			—			242,178			—			242,178
Other comprehensive income		—			8,035			—			—			8,035

Total comprehensive income														250,213

Receipts and forfeitures of restricted stock		44			—			—			(823	)		(779	)
Common stock offering		—			—			—			—			151,317
Common stock issuance pursuant to various plans		—			—			—			—			38,756
Offering costs		—			—			—			—			(296	)
Stock-based employee compensation expense		2,285			—			—			—			14,330
Common stock dividends - $0.88 per share		(320	)		—			(88,909	)		—			(89,229	)

December 31, 2004	$	(1,413	)	$	(9,591	)	$	649,240		$	(51,206	)	$	1,605,704

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(A) SUMMARY OF ACCOUNTING POLICIES

Nature of Operations - We are a diversified energy company. We purchase, gather, process, transport, store, and distribute natural gas. We drill for and produce natural gas and oil; extract, fractionate, store, transport, sell and market natural gas liquids (NGLs); and are engaged in natural gas, crude oil, NGLs and electricity marketing, retail marketing and trading activities. We are the largest natural gas distributor in Oklahoma and Kansas 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; Kansas City, Wichita, and Topeka, Kansas; and Austin and El Paso, Texas. Our energy services operations provide services to customers in many states. We acquired Northern Plains Natural Gas Company and its wholly owned subsidiary Pan Border Gas Company (collectively, Northern Plains) in November 2004. As a result of this acquisition we are the majority general partner of Northern Border Partners, one of the largest publicly-traded limited partnerships. Northern Border Partners acquires, owns and manages pipelines and other midstream energy assets and is a leading transporter of natural gas imported from Canada into the United States.

Critical Accounting Policies

Derivatives and Risk Management Activities - We engage in wholesale energy marketing, retail marketing, trading, and risk management activities. We account for derivative instruments utilized in connection with these activities and services 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. Many of our purchase and sale agreements 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.

Under Statement 133, entities are required to record derivative instruments 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 our portfolio’s fair values are based on actual market prices. Market value changes result in a change in the fair value of our derivative instruments. 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 the derivative instrument does not qualify or is not designated as part of a hedging relationship, we account for changes in fair value of the derivative in earnings as they occur. Commodity price volatility may have a significant impact on the gain or loss in any given period.

Energy-related contracts that are not derivatives pursuant to Statement 133 are no longer carried at fair value, but are accounted for on an accrual basis as executory contracts. 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.

See Note D for more discussion of derivatives and risk management activities.

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, we will record an impairment charge. See Note F for more discussion of goodwill.

Examples of long-lived asset impairment indicators include:

•

a significant decrease in the market price of a long-lived asset or asset group,

•

a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition,

•

an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset or asset group,

•

a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

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 unless we have the ability to exercise significant influence over operating and financial policies of our investee, in which case we apply the equity method. Our investment in the general and limited partner interests in Northern Border Partners is accounted for by the equity 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. Cost of current gas in storage for Oklahoma Natural Gas is determined under the last-in, first-out (LIFO) methodology. The estimated replacement cost of current gas in storage was $37.3 million and $28.3 million at December 31, 2004 and 2003, respectively, compared to its value under the LIFO method of $38.9 million and $32.6 million at December 31, 2004 and 2003, respectively. Current natural gas and NGLs in storage for all other companies are determined using the weighted average cost of gas method.

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 (6.2 percent in 2004 and 6.4 percent in 2003) 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 rates for Oklahoma Natural Gas and ONEOK Gas Transportation property regulated by the Oklahoma Corporation Commission (OCC), Kansas Gas Service and Mid Continent Market Center property regulated by the Kansas Corporation Commission (KCC), and Texas Gas Service and ONEOK WesTex Transmission property regulated by the Texas Railroad Commission (RRC) and various municipalities in Texas is set forth in the following table for the periods indicated.


	Years Ended December 31,
Regulated Property	2004		2003		2002
Oklahoma Natural Gas	2.9	%	2.8	%	3.0	%
Kansas Gas Service	3.2	%	3.3	%	3.4	%
Texas Gas Service	3.2	%	3.2	%		(a)
ONEOK Gas Transportation	2.1	%	2.1	%	2.0	%
Mid-Continent Market Center	3.6	%	3.5	%	3.8	%
ONEOK WesTex Transmission	2.2	%	2.1	%	2.1	%

(a)

- We acquired Texas Gas Service in January 2003.

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 our regulated properties.


	Remaining Life	Service Years
Distribution property	18-25	39-45
Transmission property	18-35	40-45
Other property	6-29	15-25

Production Property - We use 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 gas and oil reserves.

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 are depreciated using the straight-line method over its estimated useful life.

Environmental Expenditures - We accrue 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 gas and oil production volumes are delivered to the purchaser.

Our 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 we accrue unbilled revenues at the end of each month. Tariff rates for residential and commercial Oklahoma Natural Gas, Kansas Gas Service and some Texas Gas Service 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 service fee is included in the authorized rate design for Texas Gas Service in 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, RRC and various municipalities in Texas. For all other operations the effect is recognized in income in the period that includes the enactment date. We continue to amortize previously deferred investment tax credits for ratemaking purposes over the period prescribed by the OCC, KCC, RRC and various municipalities in Texas.

Regulation - Our intrastate transmission pipelines and distribution operations are subject to the rate regulation and accounting requirements of the OCC, KCC, RRC and various municipalities in Texas. Other transportation activities are subject to regulation by the Federal Energy Regulatory Commission (FERC). Oklahoma Natural Gas, Kansas Gas Service, Texas Gas Service 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 us to defer recognition of certain costs to be recovered through rates over time as opposed to expensing such costs as incurred. This allows us 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 provisions of Statement 71, a write-off of regulatory assets and stranded costs may be required. See Note E for more discussion of our regulatory assets.

Asset Retirement Obligations - On January 1, 2003, we 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 we recognize the fair value of a liability for an asset retirement obligation in the period when 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, we 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, we 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 loss of approximately $2.1 million, net of tax, in the first quarter of 2003. The related depreciation and amortization expense is immaterial to our consolidated financial statements.

In accordance with long-standing regulatory treatment, we collect through rates the estimated costs of removal on certain 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, these non-legal asset removal obligations should be accounted for as a regulatory liability under Statement 71. Historically, the regulatory authorities which have jurisdiction over our regulated operations have not required us to track this amount; rather these costs are addressed prospectively as depreciation rates are set in each general rate order. We have made an estimate of our removal cost liability using current rates since the last general rate order in each of our 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. We have reclassified the estimated non-legal asset removal obligation from accumulated deprecation, depletion and amortization to non-current liabilities in other deferred credits on our balance sheets as of December 31, 2004 and 2003. 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, we 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). We 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, we accounted for our 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 common share (EPS) as if we had applied the fair-value recognition provisions of Statement 123 to stock-based employee compensation in the periods presented.


	Years Ended December 31,
	2004		2003		2002
	*(Thousands of dollars, except per share amounts)*
Net income, as reported	$	242,178	$	112,488	$	166,624
Add: Stock option compensation included in net income, net of related tax effects		9,228		4,650		1,974
Deduct: Total stock option compensation expense determined under fair value based method for all awards, net of related tax effects		10,415		5,864		4,027

Pro forma net income	$	240,991	$	111,274	$	164,571

Earnings per share:
Basic - as reported	$	2.38	$	1.48	$	1.40
Basic - pro forma	$	2.36	$	1.46	$	1.38
Diluted - as reported	$	2.30	$	1.22	$	1.39
Diluted - pro forma	$	2.29	$	1.21	$	1.37

beginning after June 15, 2005. We are currently assessing the impact of adopting Statement 123R, but we do not believe it will have a material impact on our financial condition and results of operations as we have been expensing share-based payments since the adoption of Statement 148 on January 1, 2003.

Earnings per Common Share - Basic earnings per share of common stock are calculated based on the daily weighted average number of shares of common stock outstanding during the period. Diluted earnings per share of common stock are calculated based on the daily weighted average number of shares of common stock outstanding during the period plus potentially dilutive components. The dilutive components are calculated based on the dilutive effect for each quarter. For any fiscal year period consisting of two or more quarters, the dilutive components for each quarter are averaged to arrive at the fiscal year to date dilutive component.

Labor Force - We employed 4,657 people at December 31, 2004. Approximately 18 percent of the workforce, all of whom are employed by Kansas Gas Service, is covered by collective bargaining agreements with 8 percent covered by agreements that expire in 2006 and 10 percent covered by agreements that expire in 2009.

Use of Estimates - Certain amounts included in or affecting our financial statements and related disclosures 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. Items which may be estimated include, but are not limited to, the economic useful life of assets, gas and oil reserves, 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 our assets and liabilities, revenues and expenses, and related disclosures are necessarily affected by these estimates.

We evaluate these estimates on an ongoing basis using historical experience, consultation with experts and other methods we consider reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on our 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, primarily related to current and noncurrent deferred taxes and assets and liabilities from energy marketing and risk management activities, have been reclassified to conform to the 2004 presentation. These reclassifications did not impact previously reported net income or shareholders’ equity.

Definitions

Following are definitions of abbreviations that may be used in these Notes to Consolidated Financial Statements:


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
Mwh		Megawatt hour

(B) ACQUISITIONS AND DIVESTITURES

Additionally in 2004, we sold our gas distribution systems in Eagle Pass, Texas and Mexico and our propane operations in separate transactions. We received a combined $7.4 million and recognized a net pre-tax gain of approximately $3.5 million.

In December 2003, we acquired 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.

In October 2003, we sold certain Texas transmission assets for approximately $3.1 million. We recorded a charge against accumulated depreciation of approximately $7.8 million in accordance with Statement 71 and the regulatory accounting requirements of the FERC and RRC.

In January 2003, we sold 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. See Note C.

In January 2003, we acquired 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 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 557,000 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 assets relating to the propane distribution operations were sold in May and July 2004 and the natural gas distribution investments in Mexico were sold in May 2004. Texas Gas Service operated these assets.

Additionally in 2003, we acquired, in separate transactions, the gas distribution system at the United States Army’s Fort Bliss in El Paso, Texas and a pipeline system that extends through the Rio Grande Valley region in Texas for approximately $6.0 million.

The unaudited pro forma information in the following table presents a summary of our 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 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 we believe the amount is immaterial.


	Pro Forma Year Ended December 31, 2002
	(Thousands of dollars, except per share amounts)
Operating Revenues	$	2,191,193
Net Margin	$	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 our concentration in the mid-continent region of the United States by adding to our 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.

In December 2002, we sold 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. We recorded a loss of approximately $3.7 million in 2002 related to this sale. 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 June 2002, we sold our remaining shares of Magnum Hunter Resources (MHR) common stock for a pre-tax gain of approximately $7.6 million, which is included in other income. We retained approximately 1.5 million stock purchase warrants with an exercise price of $15 per share, which we exchanged for 1.5 million shares of MHR common stock in February 2005.

(C) DISCONTINUED OPERATIONS

In January 2003, we sold approximately 70 percent of the natural gas and oil producing properties of our 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 our financial statements and related notes for all periods shown are reflected as discontinued operations. Our 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. We 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,
	2004		2003		2002
	*(Thousands of dollars)*
Natural gas sales	$	—	$	6,036	$	57,520
Oil sales		—		1,705		6,024
Other revenues		—		—		407

Net margin		—		7,741		63,951
Operating costs		—		1,985		21,660
Depreciation, depletion, and amortization		—		1,937		24,836

Operating income		—		3,819		17,455

Income taxes		—		1,477		6,807

Income from discontinued component	$	—	$	2,342	$	10,648

Gain on sale of discontinued component, net of tax of $21.5 million	$	—	$	39,739	$	—

(D) ENERGY MARKETING AND RISK MANAGEMENT ACTIVITIES AND FAIR VALUE OF FINANCIAL INSTRUMENTS

Risk Policy and Oversight - 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 our risk management policies.

We control the scope of risk management, marketing and trading operations through a comprehensive set of policies and procedures involving senior levels of management. The audit committee of our Board of Directors has oversight responsibilities for our risk management limits and policies. Our 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. We have a corporate risk control organization led by the Senior Vice President of Financial Services and Treasurer and the Vice President of Audit and Risk Control, who are assigned responsibility for establishing and enforcing the policies, procedures and limits. 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.

Accounting Treatment - We account for derivative instruments and hedging activities in accordance with Statement 133. Under Statement 133, entities are required to record all derivative instruments 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 the derivative instrument does not qualify or is not designated as part of a hedging relationship, we account for changes in fair value of the derivative instrument in earnings as they occur. We record these changes in fair value as energy trading revenues, net in our Consolidated Statements of Income. 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 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.

As required by Statement 133, we formally document 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. We specifically identify the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item. We assess 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 and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3” (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.

At the beginning of the third quarter of 2004, we completed a reorganization of our Energy Services segment and renewed our focus on our physical marketing and storage business. We separated the management and operations of our wholesale marketing, retail marketing and trading activities and began accounting separately for the different types of revenue earned from these activities. Prior to the third quarter, we managed the Energy Services segment on an integrated basis and presented all energy trading activity on a net basis.

Concurrent with this reorganization, we evaluated the accounting treatment related to the presentation of revenues from the different types of activities to determine which amounts should be reported on a gross or net basis under the guidance in EITF 03-11. For derivative instruments considered held for trading purposes that result in physical delivery, the indicators 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” were used to determine the proper treatment. These activities and all financially settled derivative contracts will continue to be reported on a net basis.

For derivative instruments that are not considered “held for trading purposes” and that result in physical delivery, the indicators in EITF 03-11 and EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19) were used to determine the proper treatment. We began accounting for the realized revenues and purchase costs of these contracts that result in physical delivery on a gross basis beginning with the third quarter of 2004. We apply the indicators in EITF 99-19 to determine the appropriate accounting treatment for non-derivative contracts that result in physical delivery. Derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are also reported on a gross basis. No prior periods have been adjusted for this change; therefore, comparisons to prior periods may not be meaningful. Reporting of these transactions on a gross basis did not impact operating income but resulted in an increase to revenues and cost of sales and fuel.

In 2002 we accounted for energy marketing and risk management activities for our 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 energy marketing and 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.

Energy Marketing and Risk Management Activities - Our operating results are impacted by commodity price fluctuations. We routinely enter into derivative financial instruments to minimize the risk of commodity price fluctuations related to anticipated sales of natural gas and crude oil production, purchase and sale commitments, fuel requirements, transportation and storage contracts, and natural gas and NGL inventories. We are also subject to the risk of interest rate fluctuations 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.

The Energy Services segment includes our wholesale and retail natural gas marketing and storage, retail and financial trading operations. The Energy Services segment generally attempts to manage the commodity risk of its fixed-price physical purchase and sale commitments in terms of contract volumes and the timing of performance and delivery obligations through the use of derivative instruments. With respect to the net open positions that exist within our financial trading operations, fluctuating commodity market prices can impact our 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 our financial condition at a point in time is not necessarily indicative of the impact of price movements throughout the year.

Operating margins associated with the Gathering and Processing segment’s natural gas gathering, processing and fractionation activities are sensitive to changes in natural gas, condensate and NGL prices, principally as a result of contractual terms under which natural gas is processed and products are sold. We use physical forward sales and derivative instruments to secure a certain price for natural gas, condensate and NGL products. Our Production segment utilizes derivative instruments in order to hedge anticipated sales of natural gas and oil production. Our Distribution segment uses derivative instruments to hedge a portion of our natural gas purchases.

Fair Value Hedges - During the first quarter of 2004, we terminated $670 million of our interest rate swap agreements to lock in savings and received $91.8 million, which includes $8.9 million of interest rate savings previously recorded. These interest rate swaps were previously initiated as a strategy to hedge the fair value of fixed-rate, long-term debt. The net proceeds received upon termination of the interest rate swaps were $81.9 million, after reduction for ineffectiveness and unpaid interest. Ineffectiveness related to these hedges of approximately $1.0 million is included in interest expense. Through December 31, 2004, $8.1 million in interest expense savings has been recognized and the remaining amount of $73.8 million will be recognized in the income statement over the remaining term of the debt instruments originally hedged. Consequently, the remaining savings in interest expense will be recognized over the following periods:


2005	$	10.0 million
2006	$	10.0 million
2007	$	10.0 million
2008	$	10.0 million
Thereafter	$	33.8 million

In the first quarter of 2004, we entered into new swap agreements to replace the terminated agreements. Currently, $740 million of fixed rate debt is swapped to floating. The floating rate debt is based on both the three and six-month London InterBank Offered Rate (LIBOR), depending upon the swap. At December 31, 2004, we had a net liability of $17.6 million to reflect the fair value of the current interest rate swaps. Long-term debt reflects the offset to the fair value of the swaps with a decrease in overall debt of $17.6 million. See Note J.

The Energy Services segment uses basis swaps to hedge the fair value of certain firm transportation commitments. Net gains or losses from the fair value hedges are recorded to cost of sales and fuel. The ineffectiveness related to these hedges was not material in 2004, 2003 or 2002.

Cash Flow Hedges - The Energy Services segment uses futures and basis swaps to hedge the cash flows associated with its anticipated purchases and sales of natural gas and cost of fuel used in transportation of gas. Accumulated other comprehensive loss at December 31, 2004, includes net losses of approximately $5.3 million, net of tax, related to these hedges that will be realized within the next 49 months, of which $8.7 million in net losses will be recognized in the next 12 months. The Production and Gathering and Processing segments periodically enter into derivative instruments to hedge the cash flows associated with their exposure to changes in the price of natural gas and oil. Accumulated other comprehensive loss at December 31, 2004, includes losses of approximately $2.5 million, net of tax, for the production hedges and gains of approximately $2.2 million, net of tax, for the gathering and processing hedges, both of which will be realized in the income statement within the next 12 months.

Our regulated businesses also use derivative instruments from time to time. Gains or losses associated with these derivative instruments are included in and recoverable through the monthly purchased gas adjustment. At December 31, 2004, Kansas Gas Service had derivative instruments in place to hedge the cost of natural gas purchases for 4.4 Bcf, which represents part of their gas purchase requirements for the 2005 winter heating months.

Net gains and losses are reclassified out of accumulated other comprehensive loss to operating revenues or cost of sales and fuel when the anticipated purchase or sale occurs. Ineffectiveness related to these cash flow hedges was approximately $12.3 million, $7.7 million and $1.4 million in 2004, 2003 and 2002, respectively. Additionally, losses of approximately $4.6 million were recognized from accumulated other comprehensive loss in 2004, due to the discontinuance of cash flow hedge treatment on certain transactions since it was probable that the forecasted transactions would not occur. There were no losses in 2003 or 2002 due to the discontinuance of cash flow hedge treatment.

Fair Value - The following table represents the fair value of our energy marketing and risk management assets and liabilities for the periods indicated. Any income statement effect related to hedges in the Distribution segment will be recovered through the cost of gas. The fair value is the carrying value for these instruments at December 31, 2004 and 2003.


	Years Ended December 31,
	2004				2003
	Assets		Liabilities		Assets		Liabilities
	*(Thousands of dollars)*
Production - cash flow hedges	$	1,891	$	6,007	$	5,875	$	6,413
Gathering and processing - cash flow hedges		7,662		4,353		—		—
Distribution - cash flow hedges		—		1,015		3,537		—
Energy services - cash flow hedges		188,111		210,702		35,550		67,666
Energy services - fair value hedges		15,540		12,779		10,843		2,203
Interest rate swaps - fair value hedges		4,160		21,758		55,750		—
Financial trading and non-trading instruments		242,618		255,884		188,752		237,148

Total fair value	$	459,982	$	512,498	$	300,307	$	313,430

Based on quarterly measurements, the average fair values during 2004 for financial trading and non-trading assets and liabilities was approximately $292.7 million and $324.3 million, respectively. For 2003, the amounts were $136.1 million and $194.8 million, respectively.

Fair value estimates consider the market in which the transactions are executed. We utilize third party references for pricing points from NYMEX and third party over-the-counter brokers to establish 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.

Credit Risk - We maintain credit policies with regard to our counterparties that we believe 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.

Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies (LDCs). This concentration of counterparties may impact our 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 our policies, exposures, credit and other reserves, we do 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 our financial instruments, excluding energy marketing and risk management assets and liabilities, which are listed in the table above.


	Book Value		Approximate Fair Value
	*(Thousands of dollars)*
December 31, 2004
Cash and cash equivalents	$	9,458	$	9,458
Accounts and notes receivable	$	1,432,425	$	1,432,425
Notes payable	$	644,000	$	644,000
Accounts payable	$	1,185,351	$	1,185,351
Accrued interest	$	32,807	$	32,807
Long-term debt	$	1,886,243	$	1,949,965


	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
Accounts payable	$	813,895	$	813,895
Accrued interest	$	32,999	$	32,999
Long-term debt	$	1,886,777	$	2,010,596

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 us 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, 2004 and 2003.


	December 31, 2004		December 31, 2003
	*(Thousands of dollars)*
Recoupable take-or-pay	$	58,412	$	64,171
Pension costs		13,125		18,060
Postretirement costs other than pension		52,477		59,118
Transition costs		16,209		16,691
Reacquired debt costs		19,777		20,635
Deferred taxes		18,471		21,782
Weather normalization		9,936		1,075
Ad valorem tax		5,659		—
Service lines		1,517		3,250
Other		7,964		9,133

Regulatory assets, net	$	203,547	$	213,915

At December 31, 2004, we were not earning a return on $28.2 million of these regulatory assets. The remaining recovery period for these assets ranges from one to 33 years.

On January 30, 2004, the OCC approved Oklahoma Natural Gas’ request that it be allowed to recover costs that it has incurred since 2000 when it assumed responsibility for its customers’ service lines and enhanced efforts to protect pipelines from corrosion. The order also allows Oklahoma Natural Gas to recover costs related to its investment in gas in storage and rising levels of fuel-related bad debts. The OCC’s order also approved a modified distribution main extension policy and authorized Oklahoma Natural Gas to defer expected homeland security costs. The order allows rate relief of $17.7 million annually, with $10.7 million as interim and subject to refund until a final determination at the Company’s next general rate case, which was filed on January 28, 2005. We believe that any refund obligation is remote and, accordingly, have not recorded a reserve. Approximately $7.0 million annually is considered final and not subject to refund. With the approval of Oklahoma Natural Gas’ request, we began amortizing the deferred costs associated with these OCC directives over an 18 month period. At December 31, 2004, we had approximately $2.8 million remaining to be amortized, compared to $6.0 million at December 31, 2003. These deferred costs are included in the captions “Service lines” and “Other” in the regulatory assets table above.

On September 17, 2003, the KCC issued an order approving a $45 million in rate relief pursuant to a stipulated settlement agreement with Kansas Gas Service. The order primarily authorized the recovery of $26.4 million of deferred postretirement

and postemployment 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.

“Weather normalization” represents the revenue over- or under-recovered through the weather normalization adjustment program in Kansas. This amount is deferred as a regulatory asset for a twelve-month period. Kansas Gas Service then applies an adjustment to the customers’ bills for twelve months to refund the over-collected revenue or bill the under-collected revenue.

The OCC has authorized Oklahoma Natural Gas’ recovery of the take-or-pay settlement, pension and postretirement benefit costs over a 10 to 20 year period.

We amortize 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.

The $5.7 million “Ad valorem tax” represents an increase in Kansas Gas Service’s taxes above the amount approved in the September 2003 rate case. Kansas law permits a utility to file a tariff to recover additional ad valorem tax expense incurred above the amount currently recovered in the cost of service rate. This excess amount is recoverable through a surcharge and can be recovered, provided the utility reports the change in rates to the KCC, on an annual basis. Kansas Gas Service filed the tariff and received approval from the KCC during the third quarter of 2004.

Recovery through rates resulted in amortization of regulatory assets of approximately $16.6 million, $11.8 million and $11.9 million for the years ended December 31, 2004, 2003 and 2002, respectively.

(F) GOODWILL

We 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. We performed our annual test of goodwill as of January 1, 2004 and there was no impairment indicated.

The changes in the carrying amount of goodwill for the years ended December 31, 2004 and 2003 are as follows.


	Balance December 31, 2002		Adjustments		Balance December 31, 2003		Adjustments			Balance December 31, 2004
	*(Thousands of dollars)*
Gathering and Processing	$	34,343	$	—	$	34,343	$	—		$	34,343
Transportation and Storage		22,183		105		22,288		(252	)		22,036
Distribution		51,368		107,361		158,729		(175	)		158,554
Energy Services		5,616		4,639		10,255		—			10,255

Total consolidated	$	113,510	$	112,105	$	225,615	$	(427	)	$	225,188

The 2004 adjustments to goodwill resulted from the sale of the gas distribution system in Eagle Pass, Texas by the Distribution segment in December 2004 and from the sale of certain natural gas transmission and gathering pipelines and compression facilities by the Transportation and Storage segment in March 2004. The 2003 adjustments to goodwill resulted from the preliminary purchase price allocation of our Texas assets acquired in January 2003.

(G) COMPREHENSIVE INCOME

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


	Years Ended December 31,
	2004					2003
	*(Thousands of dollars)*
Net income				$	242,178				$	112,488
Unrealized losses on derivative instruments	$	(29,680	)			$	(29,203	)
Unrealized holding gains (losses) arising during the period		(227	)				396
Realized losses in net income		45,420					3,306
Minimum pension liability adjustment		(2,400	)				5,782

Other comprehensive income (loss) before taxes		13,113					(19,719	)
Income tax (expense) benefit on other comprehensive income (loss)		(5,078	)				7,639

Other comprehensive income (loss)				$	8,035				$	(12,080	)

Comprehensive income				$	250,213				$	100,408

Accumulated other comprehensive loss at December 31, 2004 and 2003, primarily includes unrealized gains and losses on derivative instruments and minimum pension liability adjustments.

(H) CAPITAL STOCK

Series A Convertible Preferred Stock - We issued Series A Convertible Preferred Stock (Series A), 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, we 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 our Series A. We exchanged the remaining shares for 21.8 million shares of our newly-created Series D Convertible Preferred Stock (Series D). See further discussion in the Westar section of this Note. There are no shares of Series A currently outstanding.

Series B Convertible Preferred Stock - There are no shares of Series B Convertible Preferred Stock currently outstanding.

Series C Preferred Stock - Series C Preferred Stock (Series C) is designed to protect our shareholders from coercive or unfair takeover tactics. Holders of Series C are entitled to receive, in preference to the holders of ONEOK, Inc. 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 has been issued.

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

Common Stock - At December 31, 2004, we had approximately 179 million shares of authorized and unreserved common stock available for issuance.

Since September 17, 2004, the Thrift Plan for Employees of ONEOK, Inc. and subsidiaries (the Thrift Plan) has from time to time purchased shares of our common stock on the open market to meet the purchase requirements generated by participants in the Thrift Plan. Previously, the Thrift Plan used newly issued shares to meet the participants’ purchase requirements. All participant purchases of our common stock under the Thrift Plan are voluntary. We currently use newly issued shares to meet the purchase requirements generated by our Dividend Reinvestment Plan and the Long-Term Incentive Plan.

The Board of Directors has reserved 12.0 million shares of our common stock for the Direct Stock Purchase and Dividend Reinvestment Plan, of which 151,000 shares, 172,000 shares and 188,000 shares were issued in 2004, 2003 and 2002,

respectively. We have reserved approximately 13.2 million shares for the Thrift Plan, less the number of shares issued to date under this plan.

In January 2005, our Board of Directors authorized a stock buy back program to repurchase up to 7.5 million shares of our common stock currently issued and outstanding. The shares will be repurchased from time to time in open market transactions or through privately negotiated transactions at our discretion, subject to market conditions and other factors. The program will terminate after two years, unless extended by our Board of Directors.

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

2003 Public Offerings - During the first quarter of 2003, we conducted public offerings of our common stock and equity units. In connection with these offerings, we issued a total of 13.8 million shares of our 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 equity unit, or $390.4 million. Each equity unit consists of a stock purchase contract for the purchase of our common stock and, initially, a senior note described in Note J. 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,

•

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

•

Westar - On January 9, 2003, we entered into an agreement with Westar to repurchase a portion of the shares of our 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. The Series A were convertible into two shares of common stock for each share of Series A, reflecting our two-for-one stock split in 2001, and the Series D 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 us 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 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 on our common stock for the previous year was greater than 92.5 cents and such conversion would not have subjected us to the Public Utility Holding Company Act of 1935.

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. The shareholder agreement 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 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 who did not own more than five percent of our outstanding 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 for approximately 21.8 million shares of our newly-created Series D. Upon the cash redemption of the Series A, the shares were converted to approximately 18.1 million shares of common stock in accordance with the terms of the Series A 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. We had registered for resale 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 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 its remaining equity in us, which included all the shares of common stock Westar owned and all of our Series D, which converted to shares of common stock when sold.

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

Commercial paper and short-term notes payable totaling $644.0 million and $600.0 million were outstanding at December 31, 2004 and 2003, respectively. The commercial paper and short-term notes payable carried average interest rates of 1.77 percent and 1.24 percent at December 31, 2004 and 2003, respectively. We have a $1.0 billion five-year unsecured credit facility, which provides a back-up line of credit for commercial paper in addition to providing short-term funds. The principal amount of the credit facility may be increased by $200 million if requested by us and the corresponding incremental commitments are received from new or existing lenders. The interest rate is a floating rate based at our election on (i) either the higher of prime or one-half of one percent above the Federal Funds Overnight Rate, which is the rate that banks charge each other for the overnight borrowing of funds, or (ii) the Eurodollar rate plus a set number of basis points based on our current long-term unsecured debt ratings by Moody’s Investors Service and Standard and Poor’s Rating Services (S&P). The credit agreement contains customary affirmative and negative covenants including covenants relating to liens, investments, fundamental changes in our business, changes in the nature of our business, transactions with affiliates, the use of proceeds, a limit on our debt to capital ratio, a limit on investments in master limited partnerships and a covenant that prevents us from restricting our subsidiaries’ ability to pay dividends to ONEOK, Inc.. No amounts were outstanding under the line of credit and no compensating balance requirements existed at December 31, 2004.

We entered into an agreement with KBC Bank NV in April 2004. The agreement gives us access to an uncommitted line of credit for loans and letters of credit up to a maximum principal amount of $10 million. The rate charged on any outstanding amount is the higher of prime or one-half of one percent above the Fed Funds overnight rate, which is the rate that banks charge each other for the overnight borrowing of funds. This agreement remains in effect until canceled by KBC Bank NV. This agreement does not contain any covenants more restrictive than those in our $1.0 billion five-year credit agreement.

Maximum short-term debt from all sources, as approved by our Board of Directors, is $1.2 billion.

(J) LONG-TERM DEBT

The aggregate maturities of long-term debt outstanding at December 31, 2004, are $341.5 million; $306.5 million; $6.6 million; $409.1 million; and $107.6 million for 2005 through 2009, respectively, including $6.0 million, which is callable at option of the holder in each of those years. Additionally, $185.7 million is callable at par at our option from now until maturity, which is 2019 for $93.3 million and 2028 for $92.4 million.

In the first quarter of 2003, we issued long-term debt concurrent with our public equity offering. We 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 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 associated with the discounting will be approximately $3.5 million over three years.

In June 2002, we issued $3.5 million of long-term variable rate debt, which is secured by our corporate airplane, at an interest rate of 1.25 percent over LIBOR. All remaining long-term notes payable are unsecured. In August 2002, we completed a tender offer to purchase all of the outstanding 8.44 percent Senior Notes due 2004 and the 8.32 percent 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 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.

We are subject to the risk of fluctuation in interest rates 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. Currently, $740 million of fixed rate debt is swapped to floating. The floating rate debt is based on both three and six-month LIBOR. Based on the current LIBOR strip, the weighted average rate on the $740 million will be reduced from 6.81 percent to 4.54 percent. At December 31, 2004, we had a net liability of $17.6 million recorded in energy marketing and risk management liabilities to reflect the fair value of the current interest rate swaps. Long-term debt reflects the offset to the fair value of the swaps with a decrease in overall debt of $17.6 million. See further discussion of interest rate risk in Note D.

The following table sets forth our long-term debt for the periods indicated.


	December 31,
	2004			2003
	*(Thousands of dollars)*
Long-term notes payable
7.75% due 2005	$	335,000		$	335,000
7.75% due 2006		300,000			300,000
4.0% due 2008		402,500			402,500
LIBOR + 1.25% due 2009		2,694			3,027
6.0% due 2009		100,000			100,000
7.125% due 2011		400,000			400,000
7.25% due 2013		2,240			2,421
6.4% due 2019		93,303			93,679
6.5% due 2028		92,395			92,865
6.875% due 2028		100,000			100,000
8.0% due 2051		1,359			1,362

Total long-term notes payable		1,829,491			1,830,854
Change in fair value of hedged debt		56,752			55,923
Unamortized debt discount		(1,509	)		(2,179	)
Current maturities		(341,532	)		(6,334	)

Long-term debt	$	1,543,202		$	1,878,264

Certain debt agreements have negative covenants that relate to liens and sale/leaseback transactions. On March 1, 2005, we had $335 million of long-term debt mature. We funded this payment with working capital and the issuance of commercial paper in the short-term market.

(K) EMPLOYEE BENEFIT PLANS

Retirement and Other Postretirement Benefit Plans

Retirement Plans - We have defined benefit and defined contribution retirement plans covering substantially all employees. Nonbargaining unit employees hired after December 31, 2004 are not eligible for our defined benefit pension plan; however, they are covered by a profit sharing plan. Certain officers and key employees are also eligible to participate in supplemental retirement plans. We generally fund pension costs at a level equal to the minimum amount required under the Employee Retirement Income Security Act of 1974.

We 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 $681.3 million and $625.9 million at December 31, 2004 and 2003, respectively.

Other Postretirement Benefit Plans - We sponsor 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. 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, employees who are members of the International Brotherhood of Electrical Workers hired after June 30, 2003 and gas union employees hired after July 1, 2004 who elect postretirement medical coverage, pay 100 percent of the retiree premium for participation in the plan. Additionally, any employees who came to us through various acquisitions may be further limited in their eligibility to participate or receive any contributions from us for postretirement medical benefits.

In May 2004, the FASB issued FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2) as guidance on how employers should account for provisions of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Reform Act). We adopted FSP FAS 106-2 in the second quarter of 2004. FSP FAS 106-2 superseded FASB Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, which we adopted in the first quarter of 2004. The Medicare Reform Act allows employers who sponsor a postretirement health care plan that provides a prescription drug benefit to receive a subsidy for the cost of providing that drug benefit. In order for employers to receive the subsidy payment under the Medicare Reform Act, the value of the offered prescription drug plan must be at least actuarially equivalent to the standard prescription drug coverage provided under Medicare Part D. Due to our lower deductibles and better coverage of drug costs, we believe that our plan is of greater value than Medicare Part D and will meet the actuarially equivalent definitions. The reduction in the accumulated postretirement benefit obligation related to benefits attributed to past service was $15.6 million. The amortization for the actuarial experience gain as a component of the net amortization was $1.2 million for the year ended December 31, 2004. The reduction in current period service cost due to the subsidy was $0.5 million for the year ended December 31, 2004. There was a $1.0 million reduction to the interest cost on the accumulated postretirement benefit obligation for the year ended December 31, 2004. We believe that our plan will continue to provide drug benefits that are at least actuarially equivalent to Medicare Part D, that our plan will continue to be the primary plan for our retirees and that we will receive the subsidy. We do not expect that the Medicare Reform Act will have a significant effect on our retirees’ participation in our postretirement benefit plan.

Measurement - We use a September 30 measurement date for the majority of our plans. Our plans were remeasured as of November 30, 2004 due to the Northern Plains acquisition. This remeasurement will affect our pension and postretirement benefit expense beginning March 1, 2005.

Obligations and Funded Status - The following tables set forth our pension and other postretirement benefit plans benefit obligations, fair value of plan assets and funded status at December 31, 2004 and 2003.


	Pension Benefits December 31,						Postretirement Benefits December 31,
	2004			2003			2004			2003
	*(Thousands of dollars)*
Change in Benefit Obligation
Benefit obligation, beginning of period	$	683,888		$	601,830		$	236,394		$	177,904
Service cost		15,834			14,872			5,954			5,391
Interest cost		41,916			42,602			13,587			12,418
Participant contributions		—			—			2,806			2,278
Plan amendments		2,890			—			3,254			3,818
Liability gain due to Medicare Reform		—			—			(24,039	)		—
Actuarial loss		32,541			18,751			34,427			45,069
Acquisitions		—			44,606			—			6,932
Benefits paid		(43,233	)		(38,773	)		(16,644	)		(17,416	)

Benefit obligation, end of period	$	733,836		$	683,888		$	255,739		$	236,394

Change in Plan Assets
Fair value of assets, beginning of period	$	613,872		$	526,516		$	39,168		$	30,269
Actual return on assets		82,821			91,783			4,821			3,319
Employer contributions		6,839			5,842			2,590			3,967
Acquisitions		—			28,504			—			1,613
Benefits paid		(43,233	)		(38,773	)		—			—
Reimbursement		—			—			(350	)		—

Fair value of assets, end of period	$	660,299		$	613,872		$	46,229		$	39,168

Funded status - under	$	(73,537	)	$	(70,016	)	$	(209,510	)	$	(197,226	)
Unrecognized net asset		—			(314	)		28,398			31,854
Unrecognized prior service cost		11,753			5,494			5,600			2,537
Unrecognized net loss		202,586			199,713			107,065			103,171
Activity subsequent to measurement date		—			—			4,131			3,707

Prepaid (accrued) cost	$	140,802		$	134,877		$	(64,316	)	$	(55,957	)

Prepaid (accrued) cost for pension benefits includes a prepaid benefit of $154.7 million and a liability of $13.9 million at December 31, 2004. At December 31, 2003, the components of (accrued) prepaid cost for pension benefits included a prepaid benefit of $146.2 million and a liability of $11.3 million.

Components of Net Periodic Benefit Cost

The following tables set forth the components of net periodic benefit cost for our pension and other postretirement benefit plans for the periods indicated.


	Pension Benefits Years Ended December 31,
	2004			2003			2002
	*(Thousands of dollars)*
Components of Net Periodic Benefit Cost (Income)
Service cost	$	15,834		$	14,872		$	10,662
Interest cost		41,916			42,602			36,782
Expected return on assets		(60,165	)		(64,264	)		(67,195	)
Amortization of unrecognized net asset at adoption		(314	)		(467	)		(467	)
Amortization of unrecognized prior service cost		765			613			790
Amortization of (gain)/loss		2,878			2,235			(1,345	)

Net periodic benefit cost (income)	$	914		$	(4,409	)	$	(20,773	)


	Postretirement Benefits Years Ended December 31,
	2004			2003			2002
	*(Thousands of dollars)*
Components of Net Periodic Benefit Cost
Service cost	$	5,954		$	5,391		$	3,587
Interest cost		13,587			12,418			10,990
Expected return on assets		(3,811	)		(3,154	)		(2,791	)
Amortization of unrecognized net transition obligation at adoption		3,456			3,456			1,954
Amortization of unrecognized prior service cost (income)		190			(125	)		—
Amortization of loss		5,620			3,997			979

Net periodic benefit cost	$	24,996		$	21,983		$	14,719

Actuarial Assumptions - The following table sets forth the weighted-average assumptions used to determine benefit obligations at December 31, 2004 and 2003.


	Pension Benefits December 31,				Postretirement Benefits December 31,
	2004		2003		2004		2003
Discount rate	6.00	%	6.25	%	6.00	%	6.25	%
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, 2004 and 2003.


	Pension Benefits December 31,				Postretirement Benefits December 31,
	2004		2003		2004		2003
Discount rate		(a)	6.80	%		(a)	6.80	%
Expected long-term return on plan assets	8.75	%	9.00	%	8.75	%	9.00	%
Compensation increase rate	4.00	%	4.00	%	4.50	%	4.50	%

(a)	- The discount rate was 6.25% for the first nine months and 6.75% for the remaining three months of 2004.

The overall expected long-term rate of return on plan assets assumption is an equally weighted blend of historical return, building block, and economic growth/yield to maturity projections that we determined based on consultations with our independent investment consultants.

Health Care Cost Trend Rates - The following table sets forth the assumed health care cost trend rates at December 31, 2004 and 2003.


	2004		2003
Health care cost trend rate assumed for next year	10	%	9	%
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	2009		2007


	One-Percentage Point Increase		One-Percentage Point Decrease
	*(Thousands of dollars)*
Effect on total of service and interest cost	$	2,993	$	(2,396	)
Effect on postretirement benefit obligation	$	27,713	$	(22,856	)

Plan Assets - The following table sets forth our pension and postretirement benefit plan weighted-average asset allocations at December 31, 2004 and 2003.


	Pension Benefits				Postretirement Benefits
	Percentage of Plan Assets at December 31,				Percentage of Plan Assets at December 31,
Asset Category	2004		2003		2004		2003
U.S. equities	57	%	56	%	68	%	76	%
International equities	11	%	9	%	12	%	12	%
Investment grade bonds	5	%	8	%	17	%	11	%
High yield bonds	9	%	10	%	0	%	0	%
Cash and cash equivalents	2	%	0	%	3	%	0	%
Insurance contracts	15	%	16	%	0	%	0	%
Other	1	%	1	%	0	%	1	%

Total	100	%	100	%	100	%	100	%

Our 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.


Corporate bonds / Insurance contracts	20	%
High yield corporate bonds	10	%
Large-cap value equities	16	%
Large-cap growth equities	16	%
Mid-cap equities	10	%
Small-cap equities	10	%
International equities	15	%
Alternative investments	2	%
Venture capital	1	%

As part of our 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 our stock.

Contributions - For 2004, $6.8 million and $17.2 million of contributions were made to our pension plan and other postretirement benefit plan, respectively. We presently anticipate our total 2005 contributions will be $1.8 million for the pension plan and $16.1 million for the other postretirement benefit plan.

Pension Benefit Payments - The benefits expected to be paid in 2005-2009 are $42.5 million, $43.7 million, $45.0 million, $46.3 million and $48.2 million, respectively. The aggregate benefits expected to be paid in the five years from 2010-2014 are $267.8 million. The expected benefits to be paid are based on the same assumptions used to measure our benefit obligation at December 31, 2004, and include estimated future employee service.

Regulatory Treatment - The OCC and KCC have approved the recovery of pension costs and other postretirement benefits costs through rates for Oklahoma Natural Gas and Kansas Gas Service, 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 recovered through rates are charged to earnings.

Other Employee Benefit Plans

Thrift Plan - We have a Thrift Plan covering substantially all employees. Employee contributions are discretionary. Subject to certain limits, we match employee contributions. The cost of the plan was $10.4 million, $9.6 million and $8.5 million in 2004, 2003 and 2002, respectively.

Profit Sharing Plan - We have a profit sharing plan for all nonbargaining unit employees hired after December 31, 2004. Nonbargaining unit employees who were employed prior to January 1, 2005, were given a one-time opportunity to make an irrevocable election to participate in the profit sharing plan and not accrue any additional benefits under our defined benefit pension plan after December 31, 2004. We plan to make a contribution to the profit sharing plan each quarter equal to one percent of each participant’s compensation during the quarter. Additional discretionary employer contributions may be made at the end of each year. Employee contributions are not allowed under the plan.

(L) COMMITMENTS AND CONTINGENCIES

Leases - The initial lease term of our 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, we 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 2004, 2003 and 2002. Estimated future minimum rental payments for the lease are $9.3 million for each of the years ending December 31, 2005 through 2009.

We have the right to sublet excess office space in ONEOK Plaza. We received rental revenue of $2.8 million, $2.8 million and $3.2 million in 2004, 2003 and 2002, respectively. Estimated minimum future rental payments to be received under existing contracts for subleases are $2.7 million in 2005, $2.5 million in 2006, $1.2 million in 2007, $1.2 million in 2008 and $0.7 million in 2009.

Other operating leases include a gas processing plant, office buildings, and equipment. Future minimum lease payments under non-cancelable operating leases as of December 31, 2004, are $38.1 million in 2005, $51.1 million in 2006, $32.7 million in 2007, $30.2 million in 2008 and $27.8 million in 2009. These amounts include the following minimum lease payments relating to the lease of a gas processing plant for which we have a liability as a result of uneconomic lease terms: $24.2 million in 2005, $37.7 million in 2006, $24.2 million in 2007, $24.2 million in 2008 and $24.0 million in 2009. 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.

licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to the 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 NGLs, or at any facility 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 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 customers, could have a material adverse effect on our business, financial condition and results of operations.

Yaggy Facility - In January 2001, our 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 a civil penalty against us, based on alleged violations of several KDHE regulations. On April 5, 2004, we entered into a Consent Order with the KDHE in which we paid a civil penalty in the amount of $180,000 and reimbursed the KDHE for its costs related to the investigation of the incident in the amount of approximately $79,000. In addition, the Consent Order requires us to conduct an environmental remediation and a geoengineering study. Based on information currently available to us, we do not believe there are any material adverse effects resulting from the Consent Order.

The two class action lawsuits filed against us in connection with the natural gas explosions and eruptions of natural gas geysers that occurred at, and in the vicinity of, our Yaggy facility in January 2001 resulted in jury verdicts in September 2004. The jury awarded the plaintiffs in the residential class $5 million in actual damages, which is covered by insurance. In the other class action relating to business claims, the jury awarded no actual damages. The jury rejected claims for punitive damages in both cases. We are reviewing our options for appealing the verdict rendered in the residential claimants’ class action.

With the exception of appeals, all litigation regarding our Yaggy facility has been resolved.

Enron - We have repurchased a portion of the Enron Corp. guaranty claim that Enron Corp. and Enron North American Corp. (ENA) sought to avoid in the adversary proceeding. We are now providing the defense of the adversary proceeding for both the portion of the guaranty claim constituting the repurchased claim and also the portion of the guaranty claim previously sold. Based on information currently available to us, we do not expect the adversary proceeding to have a material adverse effect on us.

Other - The OCC staff filed an application on February 1, 2001, to review the gas procurement practices of Oklahoma Natural Gas 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 our procurement decisions resulted in fair, just and reasonable costs being borne by Oklahoma Natural Gas customers. In May 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, 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 Oklahoma Natural Gas customers in the form of billing credits with $1.0 million available for former customers returning to the Oklahoma Natural Gas system. If the additional $1.0 million is not fully refunded to customers returning to the Oklahoma Natural Gas system by December 2005, the remainder will be included in the final billing credit. Oklahoma Natural Gas replaced certain gas contracts, which is expected to reduce gas costs by approximately $13.8 million, due to avoided reservation fees between April 2003 and October 2005. Additional savings of approximately $8.0 million from the use of storage service in lieu of those contracts are expected to occur between November 2003 and March 2005. Any expected savings from the use of storage that are not achieved, any remaining billing credits not issued to returning customers and an additional $1.8 million credit will be added to the final billing credit scheduled to be provided to customers in December 2005.

We are a party to other litigation matters and claims, which are normal in the course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position, or liquidity.

(M) INCOME TAXES

The following table sets forth our provisions for income taxes for the periods indicated.


	Years Ended December 31,
	2004		2003			2002
	*(Thousands of dollars)*
Current income taxes
Federal	$	51,926	$	16,921		$	(53,306	)
State		6,803		1,818			(9,932	)

Total current income taxes from continuing operations		58,729		18,739			(63,238	)

Deferred income taxes
Federal		80,669		112,242			139,243
State		10,569		(454	)		26,480

Total deferred income taxes from continuing operations		91,238		111,788			165,723

Total provision for income taxes before cumulative effect/discontinued operations		149,967		130,527			102,485

Total provision for income taxes for the cumulative effect of a change in accounting principle		—		(90,456	)		—
Discontinued operations		—		22,895			6,807

Total provision for income taxes	$	149,967	$	62,966		$	109,292

The following table is a reconciliation of our provision for income taxes for the periods indicated.


	Years Ended December 31,
	2004			2003			2002
	*(Thousands of dollars)*
Pretax income from continuing operations	$	392,145		$	344,819		$	258,460
Federal statutory income tax rate		35	%		35	%		35	%

Provision for federal income taxes		137,251			120,687			90,461
Amortization of distribution property investment tax credit		(608	)		(522	)		(651	)
State income taxes, net of federal tax benefit		11,292			13,283			10,756
Other, net		2,032			(2,921	)		1,919

Income tax expense	$	149,967		$	130,527		$	102,485

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,
	2004		2003			2002
	*(Thousands of dollars)*
Deferred tax assets
Employee benefits and other accrued liabilities	$	39,412	$	41,068		$	58,119
Purchased gas adjustment		22,884		(3,912	)		(9,904	)
Net operating loss carryforward		8,886		28,844			33,440
Other comprehensive income		6,376		11,454			134
Other		41,698		97,704			1,857

Total deferred tax assets		119,256		175,158			83,646
Valuation allowance for net operating loss carryforward expected to expire prior to utilization		3,426		6,208			12,123

Net deferred tax assets		115,830		168,950			71,523
Deferred tax liabilities
Excess of tax over book depreciation and depletion		726,224		680,597			617,848
Investment in joint ventures		8,934		8,323			8,081
Regulatory assets		30,786		33,294			34,566
Other		11,259		12,286			16,520

Total deferred tax liabilities		777,203		734,500			677,015

Net deferred tax liabilities before discontinued operations		661,373		565,550			605,492

Discontinued operations		—		—			40,285

Net deferred tax liabilities	$	661,373	$	565,550		$	645,777

We have remaining net operating loss carryforwards for state income tax purposes of approximately $157.0 million, which will expire, unless utilized, at various dates through 2023. The valuation allowance attributable to our state net operating losses was $60.5 million, $3.4 million tax effected, at December 31, 2004. The valuation allowance reflects management’s uncertainty as to the realization of a portion of our state net operating losses before they expire. All federal net operating loss carryforwards have been utilized.

At December 31, 2004, we had $5.5 million in deferred investment tax credits related to regulated operations recorded in other deferred credits, which will be amortized over the next 11 years.

We had accrued income taxes of approximately $0.5 million and $71.0 million at December 31, 2004 and 2003, respectively.

(N) SEGMENT INFORMATION

We have divided our 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 NGLs; (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, and transports gas; (5) the Energy Services segment markets natural gas and oil to wholesale and retail customers and markets electricity to wholesale customers; and (6) the Other segment, which acquired Northern Plains in November 2004, primarily consists of Northern Plains and the operating and leasing operations of our headquarters building and a related parking facility.

The Production segment primarily sells to gatherers and processors in the natural gas industry. The main customers for the Gathering and Processing segment are petrochemical and refining companies along with propane wholesalers and natural gas marketing companies. Companies serviced by the Transportation and Storage segment include LDCs, power generators, natural gas marketing companies and petrochemical companies. The Distribution segment provides natural gas to residential, commercial, industrial, wholesale, public authority and transportation customers. The Energy Services segment buys and

sells natural gas and power to LDCs, municipalities, producers, large industrials, power generators, retail aggregators and other marketing companies as well as residential and small commercial/industrial companies.

As discussed in Note D, at the beginning of the third quarter of 2004 we completed a reorganization of our Energy Services segment and separated the management and operations of our physical marketing, retail marketing and trading activities. We began accounting separately for the different types of revenue earned from these activities with certain revenues accounted for on a gross rather than a net basis.

The accounting policies of the segments are described in Note A. Intersegment gross sales are recorded on the same basis as sales to unaffiliated customers. Corporate overhead costs relating to a reportable segment have been allocated for the purpose of calculating operating income. Our equity method investments do not represent operating segments.

In 2004, we had one customer, BP PLC (BP), from which we received $745.1 million, or approximately 12 percent of consolidated revenues. The Energy Services segment received $664.4 million of the total revenues received million from BP, or approximately 11 percent, of consolidated revenues. We have no other single external customer from which we received ten percent or more of our consolidated gross revenues for the periods covered by this report.

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

Regulated

Non-Regulated

Total

Year Ended December 31, 2004

Transportation

and

Storage

Distribution

Energy Services

Gathering

and

Processing

Production

Other and

Eliminations

(Thousands of dollars)

Sales to unaffiliated customers

65,678

1,924,502

2,599,470

1,512,397

98,719

(326,500

)

5,874,266

Energy trading revenues, net

—

113,814

—

113,814

Intersegment sales (a)

101,757

—

221,598

507,700

4,243

(835,298

)

—

Total Revenues

167,435

1,924,502

2,934,882

2,020,097

102,962

(1,161,798

)

5,988,080

Net margin

126,548

557,316

178,072

291,445

102,962

(12,098

)

1,244,245

Operating costs

49,414

341,651

34,669

127,552

28,590

(16,366

)

565,510

Depreciation, depletion and amortization

17,349

105,438

5,611

32,863

26,615

849

188,725

Operating income

59,785

110,227

137,792

131,030

47,757

3,419

490,010

Income from equity investments

1,122

—

1,279

2,401

Total assets

801,746

2,774,279

2,021,221

1,217,563

393,380

(15,540

)

7,192,649

Capital expenditures

12,287

142,515

1,806

32,331

52,902

22,269

264,110

(a)	- Intersegment sales for Energy Services were $327.3 million for the six months ended June 30, 2004. These are included in energy trading revenues, net above.


	Regulated					Non-Regulated											Total
Year Ended December 31, 2003	Transportation and Storage			Distribution		Energy Services			Gathering and Processing			Production		Other and Eliminations			Total
	*(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 revenues, net		—			—		229,782			—			—		—			229,782
Intersegment sales (a)		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 margin	$	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	$	1,397		$	—	$	—		$	—		$	—	$	92		$	1,489
Total assets	$	867,743		$	2,682,531	$	1,610,957		$	1,307,445		$	345,506	$	(602,296	)	$	6,211,886
Capital expenditures (continuing operations)	$	15,234		$	153,405	$	555		$	20,598		$	18,655	$	6,701		$	215,148
(a) - Intersegment sales for Energy Services were $487.3 million for the year ended December 31, 2003. These are included in energy trading revenues, net above.

	Regulated					Non-Regulated											Total
Year Ended December 31, 2002	Transportation and Storage			Distribution		Energy Services			Gathering and Processing			Production		Other and Eliminations			Total
	*(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 revenues, net		—			—		209,429			—			—		—			209,429
Intersegment sales (a)		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 margin	$	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		$	—	$	—		$	—		$	—	$	(1,016	)	$	365
Total assets	$	815,301		$	1,901,661	$	1,831,939		$	1,246,866		$	348,222	$	(334,395	)	$	5,809,594
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
(a) - Intersegment sales for Energy Services were $299.2 million for the year ended December 31, 2002. These are included in energy trading revenues, net above.

(O) 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, 2004	First Quarter			Second Quarter		Third Quarter		Fourth Quarter
	*(Thousands of dollars, except per share amounts)*
Total Revenues	$	1,030,575		$	632,139	$	1,726,762	$	2,598,604
Net margin	$	392,759		$	230,052	$	246,100	$	375,334
Operating income	$	195,108		$	53,606	$	59,503	$	181,793
Income from continuing operations	$	105,153		$	17,789	$	20,839	$	98,397
Net Income	$	105,153		$	17,789	$	20,839	$	98,397
Earnings per share from continuing operations
Basic	$	1.06		$	0.17	$	0.20	$	0.95
Diluted	$	1.04		$	0.17	$	0.19	$	0.90

Year Ended December 31, 2003	First Quarter			Second Quarter		Third Quarter		Fourth Quarter
	*(Thousands of dollars, except per share amounts)*
Total Revenues	$	1,086,710		$	494,988	$	568,270	$	849,028
Net margin	$	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

(P) SUPPLEMENTAL CASH FLOW INFORMATION

The following tables set forth supplemental information relative to our cash flow for the periods indicated.


	Years Ended December 31,
	2004		2003			2002
	*(Thousands of dollars)*
Cash paid during the year
Interest (including amounts capitalized)	$	37,526	$	115,939		$	109,763
Income taxes paid (received)	$	125,062	$	(16,302	)	$	(90,306	)
Noncash transactions
Cumulative effect of changes in accounting principles
Rescission of EITF 98-10 (price risk management assets and liabilities)	$	—	$	141,832		$	—
Adoption of Statement 143	$	—	$	2,053		$	—
Issuance of restricted stock, net	$	—	$	3,201		$	2,628
Treasury stock transferred to compensation plans	$	—	$	4,450		$	1,958


	Years Ended December 31,
	2004		2003			2002
	*(Thousands of dollars)*
Acquisitions
Property, plant, and equipment	$	—	$	537,855		$	4,036
Current assets		534		70,027			—
Current liabilities		—		(60,106	)		—
Regulatory assets and goodwill		—		114,283			—
Investments		176,175		—			—
Lease obligation		—		(4,715	)		—
Deferred credits		—		(22,900	)		—
Deferred income taxes		—		55,858			—

Cash paid for acquisitions - continuing operations	$	176,709	$	690,302		$	4,036

Cash paid for acquisitions - discontinued operations	$	—	$	—		$	764

During the first quarter of 2004, we received $81.9 million in net proceeds upon the termination of interest rate swap agreements. This significantly reduced net cash paid for interest during 2004. Through December 31, 2004, $8.1 million in interest rate expense savings has been recognized and the remaining amount will be recognized in the income statement over the remaining term of the debt instruments originally hedged. See Note D.

(Q) STOCK BASED COMPENSATION

Deferred Compensation Plans

Employee Non-Qualified Deferred Compensation Plan - The ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan (the Prior Deferred Comp 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 a portion of 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’s employment. Participants are immediately 100 percent vested. Short-term deferral accounts are credited with a deemed investment return based on the five year treasury bond fund. Long-term deferral accounts are credited with a deemed investment return based on various investment options, which, beginning in May 2004, do not include an option to invest in our common stock. At the distribution date, cash is distributed to participants based on the fair market value of the deemed investment of the participant account at that date.

On December 16, 2004, our Board of Directors approved certain amendments to our Prior Deferred Comp Plan, including amendments providing that the Prior Deferred Comp Plan would terminate and be frozen effective December 31, 2004, as to eligibility of any new participants and the deferral of any compensation by a participant under the Prior Deferred Comp Plan after that date. Participants in the Prior Deferred Comp Plan will be paid compensation they had deferred under the Prior Deferred Comp Plan on or before December 31, 2004, in accordance with the terms of the Prior Deferred Comp Plan.

Also, on December 16, 2004, our Board of Directors adopted the 2005 Employee Deferred Compensation Plan (the 2005 Deferred Comp Plan), which became effective January 1, 2005. The 2005 Deferred Comp Plan provides for deferral of compensation and payment of benefits in substantially the same manner as provided under the Prior Deferred Comp Plan. However, the 2005 Deferred Comp Plan contains certain different provisions intended to comply with the requirements of the newly enacted Section 409A of the Internal Revenue Code. Those provisions relate to participant elections to defer compensation, the timing of payments and distributions under the 2005 Deferred Comp Plan, prohibition of any foreign trust for the 2005 Deferred Comp Plan, new defined terms, and certain other conforming provisions and features.

Deferred Compensation Plan for Non-Employee Directors - The ONEOK, Inc. Deferred Compensation Plan for Non-Employee Directors provides our directors, who are not our employees, the option to defer all or a portion of their compensation for their service on our 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

100

their annual retainer and/or meeting fees and receive such fees on a deferred basis in the form of shares of common stock under our Long-Term Incentive Plan. Shares are distributed to non-employee directors at the fair market value of our common stock at the date of distribution.

Long-Term Incentive Plan

General - The ONEOK, Inc. Long-Term Incentive Plan (the LTIP) provides for the granting of stock-based compensation, including incentive stock options, non-statutory stock options, stock bonus awards, restricted stock awards, restricted stock unit awards and performance unit awards to key employees and the granting of stock awards to non-employee directors. We have reserved a total of approximately 7.8 million shares of common stock for issuance under the plan. The maximum number of shares for which options or other awards may be granted to any employee during any year is 300,000. The number of shares of stock to be paid and distributed to non-employee directors is determined by dividing the dollar amount of the director fees that are to be paid in common stock on any payment date by the fair market value of a share of common stock on that date.

In February 2005, our Board of Directors approved the ONEOK, Inc. Equity Compensation Plan, which will replace the LTIP. Subject to shareholder approval, 3.0 million shares of our common stock will be available for issuance.

Options - Under the LTIP, stock options may be granted to key employees. The LTIP is administered 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. Prior to 2002, our stock option agreements provided for restored options to be granted. A restored option is 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 a period determined by the Committee and stated in the option. 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. Restored options are exercisable at any time after six months following the grant date and expire on the expiration of the original grant.

Restricted Stock Awards - Under the LTIP, restricted stock awards may be granted to key employees with ownership of the common stock vesting over a period determined by the Committee and stated in the award. Those granted to date vest over a three-year period. Compensation expense is recognized on a straight-line basis over the period of the award. Shares awarded may not be sold during the vesting period. Dividends on restricted stock awards are reinvested in common stock.

Restricted Stock Incentive Units - Under the LTIP, restricted stock incentive units may be granted to key employees with ownership of the incentive unit vesting over a period determined by the Committee and stated in the award. Those granted to date vest over a three-year period at which time the grantee is entitled to receive two-thirds of the grant in shares of our common stock and one-third of the grant in cash. No dividends are paid on the restricted stock incentive units. Compensation expense is recognized on a straight-line basis over the period of the award.

Performance Unit Awards - Under the LTIP, performance unit awards may be granted to key employees. The performance units vest at the expiration of a period determined by the Committee and stated in the award if certain performance criteria are met by the company. Those granted to date vest at the expiration of a three-year period. Upon vesting, a holder of performance shares is entitled to receive a number of shares of our common stock equal to a percentage (0 percent to 200 percent) of the performance shares granted based on our total shareholder return over vesting period, compared to the total shareholder return of a peer group of 20 other companies over the same period. Compensation expense is recognized on a straight-line basis over the period of the award with adjustments as needed based on company performance. Awards granted in 2004 entitle the grantee to receive two-thirds of the grant in shares of our common stock and one-third of the grant in cash, while awards granted in 2003 were common stock only.

101

Stock Compensation Plan for Non-Employee Directors

General - The ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors (the DSCP) provides for the granting of stock bonus awards, including performance unit awards, restricted stock awards, restricted stock unit awards and options. Under the DSCP, these awards may be granted by the Committee at any time on or before January 18, 2011. We have reserved a total of 700,000 shares of common stock for issuance under the DSCP. The maximum number of shares of common stock which can be issued to a participant under the DSCP during any year is 20,000.

Options - 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 must be exercised no later than ten years after the date of grant of the option. In the event of retirement or termination, the optionee may exercise the option within a period determined by the Committee. In the event of death, the option may be exercised by the personal representative of the optionee over a period of time determined by the Committee.

Performance Unit Awards and Restricted Stock Awards - Under the DSCP, performance unit awards and restricted stock awards may be granted at the discretion of the Committee under terms set by the Committee. These awards may be settled in cash or unrestricted shares of common stock. No performance unit awards or restricted stock awards have been made to non-employee directors under the DSCP.

Stock Option Activity

The following table sets forth the stock option activity under the LTIP and DSCP for employees and non-employee directors for the periods indicated.


	Number of Shares		Weighted Average Exercise Price
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
Exercised	(921,837	)	$	17.85
Expired	(58,048	)	$	19.14
Restored	384,980		$	23.80

Outstanding December 31, 2004	2,622,784		$	19.79

Options Exercisable
December 31, 2002	1,378,270		$	18.20
December 31, 2003	1,651,840		$	18.94
December 31, 2004	1,541,209		$	20.03

At December 31, 2004, we had 1,386,287 outstanding options with exercise prices ranging between $11.85 to $17.77 and a weighted average remaining life of 6.71 years. Of these options, 711,911 were exercisable at December 31, 2004, with a weighted average exercise price of $17.22.

102

We also had 1,224,746 options outstanding at December 31, 2004, with exercise prices ranging between $17.78 and $26.67 and a weighted average remaining life of 5.62 years. Of these options, 829,298 were exercisable at December 31, 2004, at a weighted average exercise price of $22.44.

Additionally, we had 11,751 outstanding options at December 31, 2004 with exercise prices ranging between $26.68 and $28.52 and a weighted average remaining life of 4.87 years. None of these options were exercisable at December 31, 2004.

Restricted Stock Awards Activity

The following table sets forth the restricted stock activity for the restricted stock awards under the LTIP. There were no restricted stock awards under the DSCP.


	Number of Shares		Weighted Average Exercise Price
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
Released to participants	(96,549	)	$	22.28
Forfeited	(2,597	)	$	17.26
Dividends	13,763		$	23.27

Outstanding December 31, 2004	371,377		$	16.43

Restricted Stock Incentive Unit Activity

The following table sets forth the restricted stock activity for the restricted stock incentive units under the LTIP. There were no restricted stock units under the DSCP.


	Number of Shares	Weighted Average Exercise Price
Outstanding December 31, 2003	—	$	—
Granted	144,255	$	20.22

Outstanding December 31, 2004	144,255	$	20.22

103

Performance Unit Activity

The following table sets forth the performance unit activity for the performance unit wards awards under the LTIP. There were no performance unit awards under the DSCP.


	Number of Units	Weighted Average Exercise Price
Outstanding December 31, 2002	—	$	—
Granted	115,263	$	15.29

Outstanding December 31, 2003	115,263	$	15.29
Granted	191,811	$	20.20

Outstanding December 31, 2004	307,074	$	18.36

Employee Stock Purchase Plan

The ONEOK, Inc. Employee Stock Purchase Plan (the ESPP) currently has 2.8 million shares reserved for issuance. 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 base pay withheld to purchase our 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 base pay. The purchase price of the stock is 85 percent of the lower of its grant date or exercise date market price. Approximately 54 percent, 58 percent and 61 percent of employees participated in the plan in 2004, 2003 and 2002, respectively. Under the plan, we sold 449,090 shares at $18.84 per share in 2004, 296,125 shares at $16.23 per share in 2003, and 285,200 shares at $15.06 per share in 2002.

In February 2005, our Board of Directors approved the ONEOK, Inc. Employee Stock Purchase Plan, as amended. Upon shareholder approval, our common stock available for issuance under this plan will be increased to 3.8 million shares.

Accounting Treatment

We applied APB 25 in accounting for our equity benefit plans through 2002. Accordingly, no compensation expense was recognized in the consolidated financial statements for our stock options and our ESPP. We 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 our pro forma net income and EPS information had we 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 21.3 percent for 2004, 30.3 percent for 2003, and 22.1 percent for 2002; dividend yield of 3.9 percent for 2004, 3.5 percent for 2003, and 3.6 percent for 2002; and risk-free interest rate of 3.4 percent for 2004, 4.0 percent for 2003, and 5.1 percent for 2002.

The expected life ranged from one to 10 years based upon experience to date and the make-up of the optionees. The fair value of options granted at fair market value under the Plan were $3.53, $4.67 and $3.88 for the years ended December 31, 2004, 2003 and 2002, respectively.

(R) EARNINGS PER SHARE INFORMATION

Through February 5, 2003, we computed our EPS in accordance with EITF Topic No. D-95 (Topic D-95), which was subsequently superceded by EITF Issue No. 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128”. The dilutive effect of our Series A was considered in the computation of basic EPS utilizing the “if-converted” method. Under the “if-converted” method, the dilutive effect of our Series A 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 our common stock and our participating Series A according to dividends declared and participating rights in the undistributed earnings. Our Series A was a participating instrument with our common stock with respect to the payment of dividends. For the year ended December 31, 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

104

reflects this further dilution. As a result of our repurchase and exchange of our Series A in February 2003, we no longer applied the provisions of Topic D-95 to our EPS computations beginning in February 2003.

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


	Year Ended December 31, 2004
	Income		Shares	Per Share Amount
	*(Thousands, except per share amounts)*
Basic EPS from continuing operations
Income from continuing operations available for common stock	$	242,178	101,965	$	2.38
Diluted EPS from continuing operations
Effect of other dilutive securities:
Mandatory convertible units		—	2,723
Options and other dilutive securities		—	773

Income from continuing operations available for common stock and common stock equivalents	$	242,178	105,461	$	2.30


	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

105


	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

There were 17,734, 151,448 and 167,116 option shares excluded from the calculation of diluted EPS for the years ended December 31, 2004, 2003 and 2002, respectively, since their inclusion would be antidilutive.

The repurchase and exchange of our Series A from Westar in February 2003 was recorded at fair value. In accordance with 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, was considered a preferred dividend. The premium recorded on the repurchase and exchange of the Series A was approximately $44.2 million and $53.4 million, respectively, for a total premium of $97.6 million. As a result of our adoption of Topic D-95, we 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, resulting in a net premium of $3.1 million, which is reflected as a dividend on the Series A in the EPS calculation above for the year ended December 31, 2003.

106

(S) OIL AND GAS PRODUCING ACTIVITIES

The following table sets forth our historical cost information relating to our production operations for the periods indicated.


	Continuing Operations Years Ended December 31,							Discontinued Component Years Ended December 31,
	2004			2003		2002		2004		2003		2002
	*(Thousands of dollars)*
Capitalized costs at end of year
Unproved properties	$	618		$	461	$	409	$	—	$	—	$	7,073
Flow lines		17,569			15,250		—		—		—		—
Proved properties (1)		437,777			385,566		143,492		—		—		364,461

Total capitalized costs		455,964			401,277		143,901		—		—		371,534
Accumulated depreciation, depletion and amortization		87,935			61,725		58,383		—		—		148,798

Net capitalized costs	$	368,029		$	339,552	$	85,518	$	—	$	—	$	222,736

Costs incurred during the year
Property acquisition costs (unproved)	$	236		$	212	$	326	$	—	$	—	$	4,118
Development costs	$	52,731		$	18,472	$	15,336	$	—	$	—	$	19,809
Purchase of minerals in place	$	(65	)	$	240,512	$	2,899	$	—	$	—	$	764

(1)	Proved properties includes $5.8 million and $5.1 million for asset retirement obligations capitalized as additional costs per Statement 143 at December 31, 2004 and 2003, respectively.

The following table sets forth the results of our 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,
	2004		2003		2002		2004		2003		2002
	*(Thousands of dollars)*
Net revenues
Sales to unaffiliated customers	$	98,431	$	40,178	$	29,890	$	—	$	7,524	$	50,354
Gas sold to affiliates		4,243		2,860		2,456		—		217		13,190

Net revenues from production		102,674		43,038		32,346		—		7,741		63,544

Production costs		18,870		8,407		6,158		—		1,186		13,346
Depreciation, depletion and amortization		25,704		11,475		12,668		—		1,937		24,836
Income taxes		21,991		8,298		5,230		—		1,477		9,810

Total expenses		66,565		28,180		24,056		—		4,600		47,992

Results of operations from producing activities	$	36,109	$	14,858	$	8,290	$	—	$	3,141	$	15,552

107

(T) OIL AND GAS RESERVES (UNAUDITED)

The volumes of reserves shown are estimates, which, by their nature, are subject to later revision. We estimate the reserves 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 our proved oil and gas reserves, net of royalty interests and changes herein, for the periods indicated.


	Continuing Operations				Discontinued Component
	Oil *(MBbls)*		Gas *(MMcf)*		Oil *(MBbls)*		Gas *(MMcf)*
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		—		—
Revisions in prior estimates	(289	)	(21,633	)	—		—
Extensions, discoveries and other additions	573		20,440		—		—
Sales of minerals in place	—		(2	)	—		—
Production	(344	)	(16,647	)	—		—

December 31, 2004	4,067		203,277		—		—

Proved developed reserves
December 31, 2002	1,521		40,230		2,001		128,778
December 31, 2003	2,070		132,451		—		—
December 31, 2004	2,457		130,250		—		—

(U) 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,
	2004		2003		2002		2004		2003		2002
	*(Thousands of dollars)*
Future cash inflows	$	1,348,023	$	1,453,999	$	365,637	$	—	$	—	$	883,816
Future production costs		273,329		269,779		70,574		—		—		173,299
Future development costs		81,939		94,579		20,934		—		—		23,067
Future income taxes		243,138		298,229		93,415		—		—		224,756

Future net cash flows		749,617		791,412		180,714		—		—		462,694
10 percent annual discount for estimated timing of cash flows		389,751		400,407		77,736		—		—		205,411

Standardized measure of discounted future net cash flows relating to oil and gas reserves	$	359,866	$	391,005	$	102,978	$	—	$	—	$	257,283

108

Future cash inflows are computed by applying year-end prices (averaging $42.63 per barrel of oil, adjusted for transportation and other charges, and $5.75 per Mcf of gas at December 31, 2004) to the year-end quantities of proved reserves. As of December 31, 2004, a portion of 2005 proved developed gas production 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 $4.1 million.

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,
	2004			2003			2002			2004		2003			2002
	*(Thousands of dollars)*
Beginning of period	$	391,005		$	102,978		$	55,853		$	—	$	257,283		$	143,769
Changes resulting from:
Sales of gas and oil produced, net of production costs		(81,537	)		(34,631	)		(26,199	)		—		(3,818	)		(50,198	)
Net changes in price, development, and production costs		(36,566	)		7,086			62,196			—		—			133,586
Development costs incurred		52,731			18,472			15,336			—		—			19,809
Extensions, discoveries, additions, and improved recovery, less related costs		27,869			61,718			31,759			—		—			31,676
Purchases of minerals in place		(65	)		363,367			2,899			—		—			764
Sales of minerals in place		—			—			(1	)		—		(253,465	)		(322	)
Revisions of previous quantity estimates		(65,644	)		(14,796	)		(23,291	)		—		—			49,513
Accretion of discount		41,609			19,512			7,749			—		—			19,042
Net change in income taxes		26,299			(94,646	)		(31,583	)		—		—			(77,951	)
Other, net		4,165			(38,055	)		8,260			—		—			(12,405	)

End of period	$	359,866		$	391,005		$	102,978		$	—	$	—		$	257,283

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

Not applicable.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Securities and Exchange Act of 1934, as amended (the “Act”) is recorded, processed, summarized and reported, within the time periods specified in the U.S. Securities and Exchange Commission’s rules and forms. Under the supervision and with the participation of senior management, including our Chairman and Chief Executive Officer (“Principal Executive Officer”) and our Chief Financial Officer (“Principal Financial Officer”), we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Act. Based on this evaluation, our Principal Executive Officer and our Principal Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2004 to ensure the timely disclosure of required information in our periodic Securities and Exchange Commission filings.

109

Changes in Internal Controls Over Financial Reporting

We have not made any changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Act) during the fiscal year ended December 31, 2004 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting except for the finalization of controls related to the implementation of our new customer service system that was implemented for portions of our Distribution segment. This system was developed in order to consolidate three customer service systems. We installed the system in Texas and Kansas in June 2004 and September 2004, respectively. We expect to install the system in Oklahoma in the future.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, we evaluated the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under that framework and applicable Securities and Exchange Commission rules, our management concluded that our internal control over financial reporting was effective as of December 31, 2004. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included herein.

ITEM 9B. OTHER INFORMATION

Not applicable.

110

PART III.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Directors of the Registrant

Information concerning the directors of the Company is set forth in our 2005 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 2005 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 2005 definitive Proxy Statement and is incorporated herein by this reference.

Nominating Committee Procedures

Information concerning the nominating committee procedures is set forth in our 2005 definitive Proxy Statement and is incorporated herein by this reference.

ITEM 11. EXECUTIVE COMPENSATION

Information on executive compensation is set forth in our 2005 definitive Proxy Statement and is incorporated herein by this reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Security Ownership of Certain Beneficial Owners

Information concerning the ownership of certain beneficial owners is set forth in our 2005 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 2005 definitive Proxy Statement and is incorporated herein by this reference.

Equity Compensation Plan Information

Information concerning our equity compensation plans is included in Part II, Item 5. Market for Registrant’s Common Equity and Related Shareholder Matters of this Annual Report on Form 10-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information on certain relationships and related transactions is set forth in our 2005 definitive Proxy Statement and is incorporated herein by this reference.

111

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information concerning the principal accountant’s fees and services is set forth in our 2005 definitive Proxy Statement and is incorporated herein by this reference.

112

PART IV.

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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 for the quarter ended May 31, 1998, filed June 26, 1998).

3.2		Amended Certificate of Incorporation of ONEOK, Inc. filed January 16, 1998 (incorporated by reference from Exhibit (1)(a) to Form 10-Q for the quarter ended May 31, 1998, filed June 26, 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 filed July 19, 2001, 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 (incorporated by reference from Exhibit 3.4 to Form 10-K for the fiscal year ended December 31, 2003, filed March 3, 2004).

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 (incorporated by reference from Exhibit 3.5 to Form 10-K for the fiscal year ended December 31, 2003, filed March 3, 2004).

3.6		Bylaws of ONEOK, Inc. (incorporated by reference from Exhibit 3 to Form 10-Q for the quarter ended March 31, 2004, filed April 30, 2004).

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 Amendment No 3. to Registration Statement on Form S-4 filed August 6, 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 Registration Statement on Form 8-A filed November 28, 1997).

4.2		Form of Common Stock Certificate (incorporated by reference from Exhibit 1 to Registration Statement on Form 8-A filed November 21, 1997).

4.3		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, Commission File No. 333-62279).

113


4.4		Indenture dated December 28, 2001, between ONEOK, Inc. and SunTrust Bank (incorporated by reference from Exhibit 4.1 to Amendment No. 1 to Registration Statement on Form S-3 filed December 28, 2001, Commission File No. 333-65392).

4.5		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).

4.6		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).

4.7		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).

4.8		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).

4.9		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).

4.10		Sixth Supplemental Indenture dated March 1, 2000, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 4.11 to the Registration Statement on Form S-4 filed March 13, 2000, Commission File No. 333-32254).

4.11		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 26, 2000).

4.12		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 19, 2001, Commission File No. 333-65392).

4.13		First Supplemental Indenture, dated as of January 28, 2003, between ONEOK, Inc. and SunTrust Bank (incorporated by reference from Exhibit 4.22 to Registration Statement on Form 8-A/A filed January 31, 2003).

4.14		Form of Senior Note Due 2008 (included in Exhibit 4.13).

4.15		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 for the fiscal year ended December 31, 2002, filed March 10, 2003).

4.16		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 Registration Statement on Form 8-A/A filed January 31, 2003).

4.17		Form of Corporate Unit (included in Exhibit 4.16).

4.18		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 31, 2003).

114


4.19		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 31, 2003).

4.20		Form of $0.925 Series D Non-Cumulative Convertible Preferred Stock Certificate (incorporated by reference from Exhibit 4.1 to Form 8-K filed February 7, 2003).

4.21		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) filed February 6, 2003).

10		ONEOK, Inc. Long-Term Incentive Plan (incorporated by reference from Exhibit 10(a) to Form 10-K for the fiscal year ended December 31, 2001, filed March 14, 2002).

10.1		ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors (incorporated by reference from Exhibit 99 to Form S-8 filed January 25, 2001).

10.2		ONEOK, Inc. Supplemental Executive Retirement Plan terminated and frozen December 31, 2004 (incorporated by reference from Exhibit 10.1 to Form 8-K filed on December 20, 2004).

10.3		ONEOK, Inc. 2005 Supplemental Executive Retirement Plan dated January 1, 2005 (incorporated by reference from Exhibit 10.2 to Form 8-K filed on December 20, 2004).

10.4		Termination Agreements between ONEOK, Inc. and ONEOK, Inc. executives, as amended, dated January 1, 2003 (incorporated by reference from Exhibit 10.3 to Form 10-K for the fiscal year ended December 31, 2002, filed March 10, 2003).

10.5		Indemnification Agreement between ONEOK, Inc. and ONEOK, Inc. officers and directors, as amended, dated January 1, 2003 (incorporated by reference from Exhibit 10.4 to Form 10-K for the fiscal year ended December 31, 2002, filed March 10, 2003).

10.6		ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference from Exhibit 10(f) to Form 10-K for the fiscal year ended December 31, 2001, filed March 14, 2002).

10.7		ONEOK, Inc. Employee Nonqualified Deferred Compensation Plan, as amended December 16, 2004 (incorporated by reference from Exhibit 10.3 to Form 8-K filed December 20, 2004).

10.8		ONEOK, Inc. 2005 Nonqualified Deferred Compensation Plan dated January 1, 2005 (incorporated by reference from Exhibit 10.4 to Form 8-K filed December 20, 2004).

10.9		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 for the fiscal year ended December 31, 2002, filed March 10, 2003).

10.10		Ground Lease between ONEOK Leasing Company and Southwestern Associates dated May 15, 1983 (incorporated by reference from Form 10-K dated August 31, 1983).

10.11		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).

115


10.12		Sublease between RMZ Corp. and ONEOK Leasing Company dated May 15, 1983 (incorporated by reference from Form 10-K dated August 31, 1984).

10.13		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).

10.14		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).

10.15		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).

10.16		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).

10.17		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 10.1 to Form 8-K filed February 7, 2003).

10.18		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).

10.19		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 filed February 7, 2003).

10.20		Registration Rights Agreement dated March 1, 2000, among the Company and the Initial Purchaser described therein (incorporated by reference from Exhibit 4.14 to Registration Statement on Form S-4 filed March 13, 2000, Commission File No. 333-32254).

10.21		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 August 5, 2003).

10.22		$1,000,000,000 Credit Agreement dated as of September 17, 2004, among ONEOK, Inc., as the Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, Citibank, N.A., as L/C Issuer and The Lenders Party Hereto (incorporated by reference from Exhibit 10.1 to Form 8-K filed September 20, 2004).

10.23		$10,000,000 Credit Agreement dated as of April 20, 2004 between ONEOK, Inc., as the Borrower, and KBC Bank, N.V.

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 for the quarter ended September 30, 2003, filed November 5, 2003).

10.25		Purchase Agreement between CCE Holdings, LLC and ONEOK, Inc. dated as of September 16, 2004.

10.26		ONEOK, Inc. Profit Sharing Plan dated January 1, 2005 (incorporated by reference from Exhibit 99 to Registration Statement on Form S-8 filed December 30, 2004).

116


10.27		ONEOK, Inc. Employee Stock Purchase Plan, as amended and restated February 17, 2005 (incorporated by reference from Exhibit 10.2 to the Form 8-K filed February 23, 2005).

10.28		Form of Non-Statutory Stock Option Agreement (incorporated by reference from Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2004, filed March 11, 2004).

10.29		Form of Restricted Stock Award Agreement (incorporated by reference from Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2004, filed March 11, 2004).

10.30		Form of Performance Shares Award Agreement (incorporated by reference from Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2004, filed March 11, 2004).

10.31		Form of Restricted Stock Incentive Award Agreement (incorporated by reference from Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2004, filed March 11, 2004).

10.32		Form of Performance Shares Award Agreement (incorporated by reference from Exhibit 10.5 to Form 10-Q for the quarter ended September 30, 2004, filed March 11, 2004).

10.33		ONEOK, Inc. Equity Compensation Plan, subject to shareholder approval (incorporated by reference from Exhibit 10.1 to Form 8-K filed February 23, 2005).

12		Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements for the years ended December 31, 2004, 2003, 2002, 2001 and 2000.

12.1		Computation of Ratio of Earnings to Fixed Charges for the years ended December 31, 2004, 2003, 2002, 2001 and 2000.

21		Required information concerning the registrant’s subsidiaries.

23		Consent of Independent Registered Public Accounting Firm.

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)).

(2)	Financial Statements


		Page No.
(a)	Report of Independent Registered Public Accounting Firm	58

(b)	Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002.	61

(c)	Consolidated Balance Sheets as of December 31, 2004 and 2003.	62-63

117


(d)	Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002.	65

(e)	Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2004, 2003, and 2002.	66-69

(f)	Notes to Consolidated Financial Statements	70-109

(3)	Financial Statement Schedules

All schedules have been omitted because of the absence of conditions under which they are required.

118

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 7, 2005	By:	/s/ Jim Kneale
		Jim Kneale
		Executive Vice President -
		Finance and Administration
		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 7th day of March 2005.


/s/ David L. Kyle				/s/ Curtis L. Dinan
David L. Kyle				Curtis L. Dinan
Chairman of the Board, President,				Senior Vice President and
Chief Executive Officer and				Chief Accounting Officer
Director

/s/ William M. Bell				/s/ Pattye L. Moore
William M. Bell				Pattye L. Moore
Director				Director

/s/ James C. Day				/s/ Douglas A. Newsom
James C. Day				Douglas A. Newsom
Director				Director

/s/ Julie H. Edwards				/s/ Gary D. Parker
Julie H. Edwards				Gary D. Parker
Director				Director

/s/ William L. Ford				/s/ Eduardo A. Rodriguez
William L. Ford				Eduardo A. Rodriguez
Director				Director

/s/ Bert H. Mackie				/s/ Mollie B. Williford
Bert H. Mackie				Mollie B. Williford
Director				Director

119