10-K405 1 d10k405.txt FORM 10-K405 100 West Fifth Street Tulsa, OK 74103 ONEOK, Inc. 2001 Annual Report to the Securities and Exchange Commission FORM 10-K 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, 2001. OR ____TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 for the transition period from __________ to Commission file number 001-13643 ONEOK, Inc. (Exact name of registrant as specified in its charter) Oklahoma 73-1520922 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 100 West Fifth Street, Tulsa, OK 74103 (Address of principal (Zip Code) executive offices) Registrant's telephone number, including area code (918) 588-7000 Securities registered pursuant to Section 12(b) of the Act: Common stock, with par value of $0.01 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.X --- Aggregate market value of registrant's voting stock held by non-affiliates based on the closing trade price on March 8, 2002, was: Common stock of $ 1,167.6 million On March 8, 2002, the Company had 60,248,668 shares of common stock outstanding. DOCUMENTS INCORPORATED BY REFERENCE: Documents Part of Form 10-K Portions of the definitive proxy statement Part III dated April 10, 2002, to be delivered to shareholders in connection with the Annual Meeting of Shareholders to be held May 16, 2002. ONEOK, Inc. 2001 ANNUAL REPORT ON FORM 10-K Part I. Page No. Item 1. Business 3-18 Item 2. Properties 18-22 Item 3. Legal Proceedings 23-28 Item 4. Results of Votes of Security Holders 29-30 Part II. Item 5. Market Price and Dividends on the Registrant's 31 Common Stock and Related Shareholder Matters Item 6. Selected Financial Data 32 Item 7. Management's Discussion and Analysis of 33-61 Financial Condition and Results of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk 62-63 Item 8. Financial Statements and Supplementary Data 64-105 Item 9. Changes in and Disagreements with Accountants 105 On Accounting and Financial Disclosures Part III. Item 10. Directors, Executive Officers, Promoters, and 106 Control Persons of the Registrant Item 11. Executive Compensation 106 Item 12. Security Ownership of Certain Beneficial Owners and Management 106 Item 13. Certain Relationships and Related Transactions 106 Part IV. Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 107-110 2 PART I. ITEM 1. BUSINESS General - ONEOK, Inc., an Oklahoma corporation, was organized on May 16, 1997. On November 26, 1997, it acquired the gas business of Western Resources, Inc. (Western) and merged with ONEOK Inc., a Delaware corporation organized in 1933. It was a successor to a company founded in 1906 as Oklahoma Natural Gas Company. ONEOK, Inc. and subsidiaries (collectively, the "Company" or "ONEOK") engage in several aspects of the energy business. The Company purchases, gathers, processes, transports, stores, and distributes natural gas. The Company drills for and produces oil and natural gas, extracts, sells and markets natural gas liquids, and is engaged in the gas marketing and trading business. The Company also owns and operates an electric generating plant and engages in wholesale marketing of electricity. In addition, the Company leases and operates their headquarters office building located in downtown Tulsa, Oklahoma (leasing excess space to others) and owns and operates a related parking facility. Change in Fiscal Year - In October 1999, the Company changed its fiscal year end from August 31 to December 31. Accordingly, the Company filed a Transition Report on Form 10-Q for the four months ended December 31, 1999, the Company's Transition Period preceding the beginning of the new fiscal year. DEFINITIONS Following are definitions of abbreviations used in this Form 10-K: Bbl 42 United States (U.S.) gallons, the basic unit for measuring crude oil and natural gas condensate MBbls One thousand barrels MBbls/d One thousand barrels per day MMBbls One million barrels Btu British Thermal Unit - a measure of the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit MMBtu One million British thermal units MMMBtu/d One billion British thermal units per day Mcf One thousand cubic feet of gas MMcf One million cubic feet of gas MMcf/d One million cubic feet of gas per day Mcfe Mcf equivalent, whereby barrels of oil are converted to Mcf using six Mcfs of natural gas to one barrel of oil Bcf One billion cubic feet of gas Bcf/d One billion cubic feet of gas per day Bcfe Bcf equivalent, whereby barrels of oil are converted to Bcf using six Bcfs of natural gas to one million barrels of oil NGLs Natural gas liquids Mwh Megawatt hour ACQUISITIONS AND SALES The Company's strategy is to acquire assets that enhance the earnings potential of the Company and utilize existing assets to maximize earnings. The Company expects to continue evaluating and assessing acquisition opportunities to further complement its existing asset base. The Company also from time to time sells assets when deemed less strategic or as other conditions warrant. 3 K.Stewart Petroleum Corporation - In June 2001, the Company sold its forty percent interest in K. Stewart Petroleum Corporation (K. Stewart), a privately held exploration company for $7.7 million. The Company retained a production payment on future drilling successes. Kinder Morgan, Inc. - In April 2000, the Company acquired certain natural gas gathering and processing assets located in Oklahoma, Kansas and West Texas from Kinder Morgan, Inc. (KMI) and certain of its affiliates. The Company also acquired KMI's marketing and trading operations, as well as some storage and transmission pipelines in the mid-continent region. The Company paid approximately $123.5 million for these assets plus working capital of approximately $53 million, which was subject to adjustment. The working capital adjustment was made in the first quarter 2001, resulting in the Company receiving approximately $4 million. The Company also assumed certain liabilities including an uneconomic lease obligation related to an operating lease for a processing plant and some firm capacity lease obligations to unaffiliated parties with out-of-market terms. This acquisition includes more than 12,000 miles of gathering and transportation pipeline, natural gas processing plants with capacity of 1.26 Bcf/d and storage facilities with a combined capacity of approximately 10 Bcf. The current throughput of these gathering and processing assets is approximately 0.76 Bcf/d. Approximately 350 employees were added to the Company's workforce as part of the acquisition. Dynegy, Inc. - In March 2000, the Company acquired natural gas processing plants with an approximate capacity of 375 MMcf/d and approximately 7,000 miles of gas gathering and transmission pipeline systems in Oklahoma, Kansas and Texas from Dynegy, Inc. (Dynegy). The Company paid approximately $305 million for these assets, which included a $3 million adjustment for working capital. The current throughput of the assets is approximately 240 MMcf/d. Production of NGLs from the assets averages 25 MBbls/d. Approximately 75 employees have been added to the ONEOK workforce as part of the acquisition. The majority of these employees are in field operations in western Oklahoma, the Texas panhandle and southern Kansas. Indian Basin Gas Processing Plant - In 2000, the Company sold its 42.4 percent interest in the Indian Basin Gas Processing Plant and gathering system for $55 million to El Paso Field Services Company, a business unit of El Paso Energy Corporation. Koch - In May 1999, the Company acquired the Oklahoma midstream natural gas gathering and processing assets of Koch Midstream Enterprises (Koch) for $285 million in cash. The assets acquired include eight natural gas processing plants and approximately 3,250 miles of gathering pipeline connected to 1,460 gas wells in Oklahoma. BUSINESS SEGMENTS The Company reports operations in the following reportable segments: . Marketing and Trading . Gathering and Processing . Transportation and Storage . Distribution . Production . Power . Other Marketing and Trading - The Marketing and Trading segment, previously referred to as the Marketing segment, conducts its business through ONEOK Energy Marketing and Trading Company (OEMT) and its subsidiaries. OEMT is actively engaged in value creation through marketing and trading of natural gas to both wholesale and retail customers in 28 states using leased gas storage and firm transportation capacity from related parties and others. The Company has executed an integrated wholesale energy business strategy based on expanding their existing marketing, trading and arbitrage opportunities in the natural gas and power markets. The combination of owning or controlling strategic assets and a trusted, reliable marketing franchise is expected to allow the Company to continue to capitalize on existing marketing, trading and arbitrage opportunities. 4 The Company primarily conducts its operations in the mid-continent region of the U.S. However, the acquisitions during 2000 allowed the Marketing and Trading segment to expand its presence to the west coast, Texas, throughout the Rockies, and to the Chicago city gate areas. OEMT was the successful bidder to supply gas to Oklahoma Natural Gas Company (ONG), an affiliated company, for its gas sales requirements for five years beginning in November 2000. In response, the Company entered into firm supply arrangements with major producers and large independents that average in length from two to five years. Gathering and Processing - The Gathering and Processing segment gathers and processes natural gas and fractionates, stores and markets NGLs primarily through its subsidiaries ONEOK Field Services Company (OFS) and ONEOK NGL Marketing L.P. (NGL Marketing). These activities are conducted primarily in Oklahoma, Kansas and Texas. In early 2000, the Company acquired additional gathering and processing assets including natural gas processing plants with a combined capacity of approximately 1.6 Bcf/d, approximately 13,400 miles of gathering lines. Transportation and Storage - The Transportation and Storage segment provides natural gas transportation, storage services and non-processable gas gathering. These operations are primarily conducted through Mid Continent Market Center, L.P. and Mid Continent Transportation, Inc. (collectively referred to as the Market Center), ONEOK Gas Transportation, L.L.C. (OGT), ONEOK WesTex Transmission, Inc. (WesTex), , ONEOK Gas Storage, L.L.C. (OGS), ONEOK Sayre Storage Company (Sayre), ONEOK Texas Gas Storage L.P. (OTGS) and ONEOK Gas Gathering, L.L.C. (OGG). Acquisitions in 2000 expanded the Company's transmission and storage operations into Texas where the Company now owns and operates through its wholly owned subsidiary, OTGS, three storage facilities with approximately 10 Bcf capacity, and WesTex which operates approximately 4,733 miles of intrastate pipeline in Texas. The Texas Railroad Commission (TRC) regulates both OTGS and WesTex. In July 1999, the storage assets located in Oklahoma were removed from regulation by the Oklahoma Corporation Commission (OCC). Following that, OGS and Sayre were granted market based rate authority by the Federal Energy Regulatory Commission (FERC). In a May 2000 OCC Order, certain transportation assets in Oklahoma included in the Transportation and Storage segment became a separate regulated utility from the Distribution segment. The Market Center's operations continue to be regulated by the Kansas Corporation Commission (KCC). In October 2001, OGG was created by the merging of ONEOK Producer Services, L.L.C. entity and the OGT gathering assets. Distribution - The Distribution segment provides natural gas distribution in Oklahoma and Kansas and interstate transportation across the Oklahoma/Texas border. The Company's distribution operations in Oklahoma and Kansas are conducted through ONG and Kansas Gas Service (KGS), respectively, both divisions of ONEOK, Inc., which serve residential, commercial, and industrial customers. ONG is regulated by the OCC and KGS is regulated by the KCC. The Distribution segment serves approximately 80 percent of Oklahoma's population and 71 percent of Kansas'population. OEMT, an affiliated company, was the successful bidder to supply gas to ONG for a portion of its gas sales requirements for two to five years beginning in November 2000. The transportation is provided by OkTex Pipeline Company (OkTex), which is regulated by the FERC. Production - The Production segment produces natural gas and oil primarily in Oklahoma, Kansas and Texas through ONEOK Resources Company. The Production segment's strategy is to acquire and develop properties. During 2001, the Company participated in drilling 155 wells of which 138 were gas, 10 were oil and 7 were dry holes. Power - The Company's Power segment, which was created in January 2001, includes the operating results of the peak electric generating plant constructed by the Company. The Company's strategy is to capture the spark spread premium, which is the value added by converting natural gas to electricity. The plant began operation in mid-2001. The Company has a signed definitive agreement with an unaffiliated company for a 15-year term providing the customer with the right to purchase up to 75 megawatts per hour of the plant's generating capacity. 5 Other - The primary companies in the Other segment include ONEOK Leasing Company and ONEOK Parking Company. ONEOK Leasing Company leases and operates the Company's headquarters office building from an unaffiliated partnership. ONEOK Parking Company owns and operates a parking garage adjacent to the Company's corporate headquarters. Environmental Matters - The Company has 12 manufactured gas sites located in Kansas, which may contain potentially harmful materials that are classified as hazardous material. Hazardous materials are subject to control or remediation under various environmental laws and regulations. A consent agreement with the Kansas Department of Health and Environment (KDHE) presently governs all future work at these sites. The terms of the consent agreement allow the Company to investigate these sites and set remediation priorities based upon the results of the investigations and risk analysis. The prioritized sites will be investigated over a period of time as negotiated with the KDHE. Through December 31, 2001, the costs of the investigations and risk analysis related to these manufactured gas sites have been immaterial. Although remedial investigation and interim clean-up has begun on four sites, limited information is available about the sites. Management's best estimate of the cost of remediation ranges from $100,000 to $10 million per site based on a limited comparison of costs incurred to remediate comparable sites. These estimates do not give effect to potential insurance recoveries, recoveries through rates or from unaffiliated parties. The KCC has permitted others to recover remediation costs through rates. It should be noted that additional information and testing could result in costs significantly below or in excess of the amounts estimated above. To the extent that such remediation costs are not recovered, the costs could be material to the Company's results of operations and cash flows depending on the remediation done and number of years over which the remediation is completed. The Company's expenditures for environmental evaluation and remediation have not been significant in relation to the results of operations of the Company. Capital expenditures for environmental issues during 2001 totaled approximately $472,000. There have been no material effects upon earnings or the Company's competitive position during 2001 related to compliance with environmental regulations. Employees - The Company employed 3,657 persons at December 31, 2001. KGS employed 863 people who are subject to collective bargaining contracts as of December 31, 2001. The Company did not experience any strikes or work stoppages during 2001. The Company's current contracts with the Unions are as follows:
Union Employees Contract Expires ---------------------------------------------------------------------------------------------------------------------- United Steelworkers of America 487 June 6, 2002 International Union of Operating Engineers 17 June 6, 2002 Gas Workers Metal Trades of the United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada 11 June 6, 2002 International Brotherhood of Electrical Workers 348 June 30, 2003 ----------------------------------------------------------------------------------------------------------------------
Segment Financial Information - For financial and statistical information regarding the Company's business units by segment, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note M of Notes to Consolidated Financial Statements. 6 DESCRIPTION OF BUSINESS SEGMENTS (A) MARKETING AND TRADING General - The Company is engaged in the marketing and trading of natural gas to retail and wholesale customers in 28 states throughout the United States. Due to expanded supply, storage capabilities, and recent acquisitions, the Company markets gas from the California border, throughout the Rockies, to the Chicago city gate. Of the Company's consolidated revenues, revenues from unaffiliated customers for the Marketing and Trading segment represent approximately 63.1, 65.7 and 42.0 percent for fiscal years 2001, 2000, and 1999, respectively. Operating income from the Marketing and Trading segment, including a $37.4 million charge related to Enron, is 24.2, 15.4 and 12.0 percent of the consolidated operating income for fiscal years 2001, 2000, and 1999, respectively. The Marketing and Trading segment has no single external customer from which it receives ten percent or more of consolidated revenues. During 2001, two regulatory causes brought before the OCC related to an affiliate, ONG, also involved the Marketing and Trading segment. The first cause related to ONG's right to collect unrecovered purchased gas costs from the 2000/2001 winter. Under this cause, the OCC investigated whether ONG was treated fairly in its contract with OEMT and it was determined that ONG was treated fairly and, in fact, paid less for gas than other OEMT customers. In a second cause, Enogex, Inc. requested a rebid of gas supply and transportation service awarded to OEMT in November 2001 and the OCC declined to order a rebid. The Company engages in price risk management activities. On January 1, 2000, the Company adopted Emerging Issues Task Force Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities" (EITF 98-10) for its energy trading contracts. EITF 98-10 requires entities involved in energy trading activities to account for energy trading contracts using mark-to-market accounting. Forwards, swaps, options, and energy transportation and storage contracts utilized for trading activities are reflected at fair value as assets and liabilities from price risk management activities in the consolidated balance sheets. The fair value of these assets and liabilities is affected by the actual timing of settlements related to these contracts and current period changes resulting primarily from newly originated transactions and the impact of price movements. Changes in fair value are recognized in net revenues, on a net basis, in the consolidated statements of income. Market prices used to determine fair value of these assets and liabilities reflect management's best estimate considering various factors including closing exchange and over-the-counter quotations, time value and volatility underlying the commitments. Market prices are adjusted for the potential impact of liquidating the Company's position in an orderly manner over a reasonable period of time under present market conditions. Market Conditions and Business Seasonality - In response to a very competitive marketing and trading environment resulting from continued deregulation of the retail natural gas markets and the restructuring of the U.S. retail and wholesale electricity markets, the Company's strategy is to concentrate its efforts on capitalizing on short-term pricing volatility through marketing, trading and arbitrage opportunities provided by leasing or ownership of storage, generation and transportation assets. OEMT focuses on building and strengthening supplier and customer relationships to execute their strategy. The Marketing and Trading segment's revenue and gross margin on gas sales 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 and electricity. 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. 7 Price Risk Management - In order to mitigate the risks associated with energy trading activities, OEMT manages its portfolio of contracts and its assets in order to maximize value, minimize the associated risks and provide overall liquidity. In doing so, OEMT uses 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 C of Notes to Consolidated Financial Statements for further discussion. (B) GATHERING AND PROCESSING General - The Company's Gathering and Processing segment is engaged in the gathering and processing of natural gas and the fractionation, storage and marketing of NGLs. The Company owns and operates or leases and operates 25 gas processing plants, six of which are currently idle. It also has an ownership interest in four gas processing plants that are operated by other owners. The total capacity of the plants the Company owns, leases or has an ownership interest in is 2.2 Bcf/d. In addition, the Company owns approximately 19,300 miles of natural gas gathering systems. The Company has experienced significant growth in this segment with the acquisitions in 1999 and 2000. The Company's operating results were significantly impacted by the acquisitions in 1999 and 2000. Of the Company's consolidated revenues, revenues from unaffiliated customers for the Gathering and Processing segment represent approximately 12.0, 12.6, and 3.9 percent for fiscal years 2001, 2000, and 1999, respectively. Operating income from the Gathering and Processing segment is 14.8, 33.2, and 7.7 percent of the consolidated operating income for fiscal years 2001, 2000, and 1999, respectively. The Gathering and Processing segment has no single external customer from which it receives ten percent or more of consolidated revenues. The gas processing operation includes the extraction of NGLs from natural gas and the separation (fractionation) of mixed NGLs into component products (ethane, propane, iso butane, normal butane and natural gasoline). The Company also extracts helium at two of its plants located in Kansas. The NGL component products are used by and sold to a diverse customer base of end users for petrochemical feedstock, residential heating and cooking, and blending into motor fuels. The gathering operation, which connects unaffiliated and affiliated producing wells to the processing plants, consists of the gathering of natural gas through pipeline systems and compression and dehydration services. The Company generally processes gas under three types of contracts. Under the Company's "Percent of Proceeds" (POP) contracts, the producer is paid a percentage of the market value of the natural gas and NGLs that are processed. The Company's "Keep Whole" contracts allow the Company to replace the Btu's extracted as NGLs with equivalent Btu's of natural gas, which keeps the producer whole on Btu's and allows the Company to retain and sell the NGLs. Under "Fee" contracts, the Company is paid a cash fee for gas processing. During 2001, the Company processed an average of 1,420 MMMBtu/d of natural gas and produced an average of 74 MBbls/d of NGLs. The Company markets its NGL production through NGL Marketing and also purchases NGLs from third parties for resale. During 2001, the Company sold approximately 27,719 MBbls of NGLs to a diverse base of customers. Market Conditions and Business Seasonality - During the year, both crude oil and natural gas prices fell from $29.33 per barrel and $9.98 per MMBtu to $18.00 per barrel and $1.83 per MMBtu, respectively. The downturn of the economy reduced the demand for many NGL products, particularly ethane, which is a major component of plastic products. Additionally, record high inventories in natural gas and other petroleum products, such as propane, along with significantly warmer than normal temperatures across North America during the last quarter of 2001 lowered demand for natural gas, home heating oil and propane causing weaker prices. Many economic forecasts indicate the U.S. economy rebounding sometime in the second half of 2002, which is supported by current forward pricing. 8 Despite significant consolidation in the recent past, the U.S. midstream industry remains relatively fragmented and the Company faces competition from a variety of companies including major integrated oil companies, major pipeline companies and their affiliated marketing companies, and national and local gas gatherers, processors and marketers. Competition exists for obtaining gas supplies for gathering and processing operations, obtaining supplies of raw product for fractionation and the transportation of natural gas and NGLs. The factors that affect competition typically arise as a result of the efficiency and reliability of the operations, price and delivery capabilities. The Company has responded to these industry conditions by acquiring assets, most of which are strategically located near the Company's existing assets, reducing costs, rationalizing assets in non-core operating areas and renegotiating contracts. The principal goal of these efforts is to mitigate the variability of earnings and cash flow caused by fluctuations in commodity prices. The Gathering and Processing segment is subject to seasonality. Products used for heating are normally more in demand during the heating months of November through March. Accordingly, the prices of these products are typically higher in the winter due to greater demand. Acquisitions - In April 2000, the Company acquired certain natural gas gathering and processing assets from KMI. This acquisition included natural gas processing plants with a capacity of 1.26 Bcf/d and 6,400 miles of gathering lines. The current throughput of these gathering and processing assets is approximately 0.76 Bcf/d. Production of NGLs from these assets averages 33 MBbls/d. In March 2000, the Company acquired natural gas processing plants with a capacity of 375 MMcf/d and approximately 7,000 miles of gas gathering and transmission pipeline systems from Dynegy. The current throughput of these gathering and processing assets is approximately 240 MMcf/d. Production of natural gas liquids from these assets averages 25 MBbls/d. In May 1999, the Company acquired the Oklahoma midstream natural gas gathering and processing assets of Koch Midstream Enterprises (Koch) for $285 million in cash. The assets acquired include eight natural gas processing plants and approximately 3,250 miles of gathering pipeline connected to 1,460 gas wells in Oklahoma. Government Regulations - The FERC has traditionally maintained that a processing plant is not a facility for transportation or sale for resale of natural gas in interstate commerce and therefore is not subject to jurisdiction under the Natural Gas Act (NGA). Although the FERC has made no specific declaration as to the jurisdictional status of the Company's gas processing operations or facilities, the Company believes its gas processing plants are primarily involved in removing natural gas liquids and therefore exempt from FERC jurisdiction. The NGA also exempts natural gas gathering facilities from the jurisdiction of the FERC. Interstate transmission facilities, on the other hand, remain subject to FERC jurisdiction. The FERC has historically distinguished between these two types of facilities on a fact-specific basis. The Company believes its gathering facilities and operations meet the criteria used by the FERC to determine a non-jurisdictional gathering facility status. The Company can transport residue gas from its 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 are used to minimize volatility in NGL and natural gas prices. Accordingly, the Company, at times, uses derivative instruments to hedge the price of natural gas purchased and used for processing and operations. The Company also, from time to time, uses derivative instruments to secure a certain price for their NGL products. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Note C of Notes to the Consolidated Financial Statements. 9 (C) TRANSPORTATION AND STORAGE General - ONEOK's Transportation and Storage segment provides intrastate natural gas pipeline transportation, Section 311(a) of the NGPA interstate transportation and storage in Oklahoma, Kansas, and Texas. ONEOK's Distribution segment is the segment's major customer for intrastate natural gas pipeline transportation in both Oklahoma and Kansas. The Company conducts this business primarily through wholly owned intrastate pipeline companies with a total of 9,689 miles of pipe and wholly-owned storage companies with a capacity of approximately 58 Bcf. In Oklahoma, the Company operates OGT and OGS. These companies have approximately 3,245 miles of pipeline and five storage facilities with a combined capacity of 43 Bcf. Capacity in the storage facilities is leased to both OEMT and third parties under various terms. The Sayre gas storage facility is leased on a long-term basis to and operated by Natural Gas Pipeline Company of America. The Company retains 3 Bcf of working storage capacity in the Sayre facility for its own use. A $3.4 million expansion to increase deliverability from the OGS Depew storage field was completed in the spring of 2000. The Oklahoma transmission system transported 253.9 Bcf in 2001, 299.1 Bcf in 2000 and 234.9 Bcf in 1999. OGT provides access to the major natural gas producing areas in Oklahoma. The system intersects 11 intra/interstate pipelines at 27 interconnect points and connects 21 processing plants and approximately 130 producing fields allowing gas to be moved throughout the state. In Kansas, the Company operates the Market Center with 1,711 miles of pipeline and two gas storage facilities with approximately 5.0 Bcf of capacity. In January 2001, Yaggy, one of the two storage facilities, was idled due to operational and regulatory issues, idling approximately 3 Bcf of Kansas storage. It cannot be determined at this time when the facility will resume operations. A $10 million expansion of the Kansas transmission system was completed during 2000, which connects the Market Center system to the ONEOK-operated Bushton natural gas processing facility and the Northern Natural Gas and ANR pipelines. The Kansas transmission system transported 77.9 Bcf in 2001, 87.1 Bcf in 2000 and 72.8 Bcf in 1999. The Market Center provides access to the major natural gas producing area in Kansas. The system intersects nine intra/interstate pipelines at 18 interconnect points and connects five processing plants and approximately three producing fields. In Texas, the Company operates WesTex with approximately 4,733 miles of pipeline and OTGS with three storage facilities, one of which is currently idled. Total storage capacity is approximately 10 Bcf. Both WesTex and OTGS were acquired from KMI in April 2000. The Texas transmission system transported 206.4 Bcf in 2001 and 170.8 Bcf in 2000. WesTex provides access to the major natural gas producing areas in the Texas Panhandle and the Permian Basin. The system intersects 11 intra/interstate pipelines at 32 interconnect points and connects 11 natural gas processing plants and approximately two producing fields allowing gas to be moved to the Waha Hub for transportation to the west, including California. This pipeline allows the Company to provide service to the city of El Paso, Texas. Loop, one of three storage facilities in Texas, was idled due to operational and regulatory issues subsequent to acquisition of the facility in 2000. This idled approximately 5 Bcf of Texas storage capacity and it has not been determined when the facility will resume operations. ONEOK Gas Gathering, L.L.C. operates the gathering pipelines that are owned by the Company and connected to the Company's transmission pipelines, including gathering systems previously owned by OGT and ONEOK Producer Services, L.L.C. Of the Company's consolidated revenues, revenues from unaffiliated customers for the Transportation and Storage segment represent approximately 1.1, 1.7, and 1.5 percent for fiscal years 2001, 2000, and 1999, respectively. The majority of the Transportation and Storage segment's revenues are derived from services provided to affiliates. Operating income from the Transportation and Storage segment is 19.5, 18.6, and 27.9 percent of the consolidated operating income for fiscal years 2001, 2000, and 1999, respectively. The Transportation and Storage segment has no single external customer from which it receives ten percent or more of consolidated revenues. 10 Market Conditions and Seasonality - The Transportation and Storage segment primarily serves local distribution companies (LDC's) and large industrial customers. The Transportation and Storage segment competes directly with other intrastate and interstate pipelines and storage facilities within each of their respective states. Competition for transportation services continues to increase as the FERC and state regulatory bodies introduce more competition in the natural gas markets. Factors that affect competition are location, price and the quality of services provided. This industry is significantly affected by the strength of the economy and price volatility. The Company believes that the working capacity of its transportation and storage assets enables it to compete effectively. The Transportation and Storage segment is subject to seasonality. Volumes transported are slightly higher in the heating season since some customers transport volumes for heating needs. Historically, customers and the Company purchased and stored gas in the summer months when prices were lower and withdrew gas during the heating season; however, increased price volatility in the natural gas market can mitigate the seasonality effect by influencing decisions related to injection and withdrawal of natural gas in storage. Government Regulations -The Company received a final order from the OCC in the second quarter of 2000 that separated the distribution assets of ONG and the transmission and gathering assets of OGT and related affiliates into two separate public utilities. This order also adjusted ONG's rates for the removal of the gathering, transmission and storage assets, and established a competitive bid process for ONG's upstream service. Through the competitive bid process, OGT retained approximately 96 percent of ONG's upstream transportation requirements. Effective November 1, 1999, by order from the OCC, the Company's gathering and storage assets and services in Oklahoma were removed from utility regulation. Assets were removed from the Oklahoma customers' rate base and are now included in this segment where they are being utilized in the competitive marketplace. The Company's transportation and storage assets in Kansas are regulated by the KCC. The Company has flexibility in establishing transportation rates with customers; however, there is a maximum rate that the Market Center can charge its customers. In the first quarter of 2002, the Company filed an application with the KCC to transfer a portion of the transportation assets of the Market Center to KGS and the gathering assets to OFS. A final order is expected in mid-2002. The Company's transportation and storage assets located in Texas are regulated by the TRC. The Company has flexibility in establishing transportation rates with customers; however, if a rate cannot be agreed upon, the rate is established by the TRC. In January 2001, the Yaggy storage facility was idled due to operational and regulatory issues related to the natural gas explosions and eruptions of natural gas geysers. This idled approximately 3 Bcf of Kansas storage capacity. Also, the Loop storage facility was idled due to operational and regulatory issues subsequent to the acquisition of the facility in 2000. This idled approximately 5 Bcf of Texas' storage capacity. It has not been determined when either of the facilities will resume operations. Customers - The Transportation and Storage segment serves the affiliated companies of the Distribution segment and Marketing and Trading segment as well as a number of transporters in the utilization of the transportation and storage facilities. Each of the companies provides flexible service alternatives to serve consumers. In June 2001, the Company announced the execution of long-term agreements between OGT and InterGen North America (InterGen) for firm transportation service to InterGen's gas fueled Redbud Energy Facility in the amount of 200 MMcf/d. In June 2001, commercial operation for gas transportation began to the NRG McClain Generating Facility, which is on the OGT system, for transportation volumes up to 85 MMcf/d. 11 Acquisitions - The Company acquired transportation and storage assets located in Texas from KMI in April 2000. These assets are strategic assets to the Company in part since they give the Company access to an expanded area in the Texas and California markets. (D) DISTRIBUTION General - ONG distributes natural gas to wholesale and retail customers located in the state of Oklahoma. At December 31, 2001, ONG delivered natural gas to approximately 802,000 customers in 327 communities in Oklahoma. ONG's largest markets are the Oklahoma City and Tulsa metropolitan areas. ONG also sells natural gas to other local gas distributors serving 39 Oklahoma communities. During 2000, the Oklahoma customers of KGS were removed from the KGS customer base and became ONG customers. At December 31, 2001, KGS supplied natural gas to approximately 642,000 customers in 340 communities in Kansas. It also makes wholesale delivery to 11 customers. KGS's largest markets served include Wichita, Topeka, and Johnson County, which includes Overland Park, Kansas. Of the Company's consolidated revenues, revenues from unaffiliated customers for the Distribution segment represent approximately 22.1, 19.1 and 49.8 percent for fiscal years 2001, 2000 and 1999, respectively. Operating income from the Distribution segment is 18.3, 29.3 and 45.5 percent of the consolidated operating income for fiscal years 2001, 2000 and 1999, respectively. The Distribution segment has no single external customer from which it receives ten percent or more of consolidated revenues. Gas Supply - Gas supplies available to ONG for purchase and resale include supplies of gas under both short and long-term contracts with gas marketers, independent producers and other suppliers. Oklahoma is the third largest gas producing state in the nation, and ONG has direct access through the Transportation and Storage segment's transmission system and transmission systems belonging to unaffiliated companies to all of the major gas producing areas in Oklahoma. The Company's gas storage, transportation and gathering assets were unbundled from the utility and operate as separate entities. Gas supply and transportation bids were awarded for service beginning in the 2000/2001 heating season for two and five year terms. As a result of the process, the majority of ONG's gas supply and gas transportation needs will continue to be met by two affiliates, OEMT for supply, and OGT for upstream transportation service for five years. KGS has transportation agreements for delivery of gas that have remaining terms varying from one to twelve years with the following non-affiliated pipeline transmission companies: Williams Gas Pipelines Central, Inc. (Williams), Enbridge Pipelines - KPC, Inc. (KPC), Kinder Morgan Interstate Gas Transmission, L.L.C., Panhandle Eastern Pipeline Company, Northern Natural Gas Company and Natural Gas Pipeline of America. Additionally, approximately 20 percent of KGS's transportation service is provided by the affiliated intrastate pipeline companies referred to as the Market Center. KGS has a long-term gas purchase contract with Amoco Production Company (Amoco) for the purpose of meeting the requirements of the customers served over the Williams pipeline system. The Company anticipates that the contract will supply between 45 percent and 55 percent of KGS's demand served by the Williams pipeline system. Amoco is one of various suppliers over the Williams pipeline system and if this contract were canceled, management believes gas supplied by Amoco could be replaced with gas from other suppliers. Gas available under the contract that exceeds the needs of the Company's residential and commercial customer base is also available for sale to other parties, known as "As Available" gas sales. For the remainder of KGS's supply, the gas is purchased from a combination of direct wellhead production, natural gas processing plants, and natural gas marketers and production companies. 12 There is an adequate supply of natural gas available to its utility systems and the Company does not anticipate problems with securing additional gas supply as needed for its customers. However, if supply shortages occur, ONG's rate schedule "Order of Curtailment" and the KGS rate order "Priority of Service" provide for first reducing or totally discontinuing gas service to large industrial users and graduating down to requesting residential and commercial customers to reduce their gas requirements to an amount essential for public health and safety. Customers - Residential and Commercial - ONG and KGS distribute natural gas as -------------------------- public utilities to approximately 80 percent of Oklahoma's population and 71 percent of Kansas'population. Natural gas sold to residential and commercial customers, which is used primarily for heating and cooking, accounts for approximately 69 and 28 percent of gas sales, respectively in Oklahoma and 76 and 24 percent of gas sales, respectively, in Kansas. A franchise, although non-exclusive, is a right to use the municipal streets, alleys, and other public ways for utility facilities for a defined period of time for a fee. ONG has franchises in 58 municipalities including Tulsa and Oklahoma City while KGS holds franchises in 279 municipalities. In management's opinion, its franchises contain no unduly burdensome restrictions and are sufficient for the transaction of business in the manner in which it is now conducted. Industrial - Under ONG's pipeline capacity lease (PCL) program, certain ---------- customers, for a fee, can have their gas, whether purchased from ONG or another supplier, transported to their facilities utilizing lines owned by ONG or its affiliates. KGS transports gas for large industrial customers through its End-Use Customer Transportation (ECT) program. The programs allow qualifying industrial and commercial customers to purchase gas on the spot market and have it transported by ONG and KGS, respectively. Because of increased competition for the transportation of gas to PCL and ECT customers, some of these customers may be lost to affiliated or unaffiliated transporters. If the Transportation and Storage segment gained some of this business, it would result in a shift of some revenues from the Distribution segment to the Transportation and Storage segment. Competition 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. Management believes that it must maintain a competitive advantage in order to retain its customers and, accordingly, continues to focus on reducing costs. The Company is subject to competition from electric utilities offering electricity as a rival energy source and competing for the space heating, water heating, and industrial process markets. Alternative fuels such as propane and fuel oil also present competition. The principal means to compete against alternative fuels is lower prices, and natural gas continues to maintain its price advantage in the residential, commercial, and both small and large industrial markets. In residential markets, the average cost of gas is less for ONG and KGS customers than the cost of an equivalent amount of electricity. The Company provides education to customers on safety and the benefits of natural gas, which include product performance, price and environmental impact. The Company is subject to competition from other pipelines for its existing industrial load. Both ONG and KGS compete for service to the large industrial and commercial customers, however, competition continues to lower rates. A portion of ONG's PCL services and KGS's ECT services are at negotiated rates that are generally below the approved PCL and transportation tariff rates, and increased competition potentially could lower these rates. Industrial and transportation sales volumes tend to remain relatively constant throughout the year. 13 Gas sales to residential and commercial customers are seasonal, as a substantial portion of gas is used principally for heating. Accordingly, the volume of gas sales is consistently higher during the heating season (November through March) than in other months of the year. ONG's tariff rates include a temperature normalization adjustment clause during the heating season, which mitigates the effect of fluctuations in weather. KGS also implemented a weather normalization clause in December 2000, which mitigates the effect of fluctuations in weather on revenues. The WeatherProof Bill program, implemented in September 1999 is designed to mitigate the effect of weather fluctuations in Kansas for customers electing to use this program. Government Regulations - Rates charged for gas services are established by the OCC for ONG and by the KCC for KGS. Gas purchase costs are included in the Purchased Gas Adjustment (PGA) clause rate that is billed to customers. The Company does not make a profit on the cost of gas. Other changes in costs must be recovered through periodic rate adjustments approved by the OCC and KCC. There were several regulatory initiatives in 2001, some due to the extraordinary winter of 2000/2001. The highlights of these initiatives are as follows: . The OCC issued an order denying ONG the right to collect $34.6 million in outstanding gas costs incurred while serving customers during the 2000/2001 winter season. The Company appealed this order to the Oklahoma Supreme Court and asked the OCC to stay the provisions of this order pending the outcome of the Company's appeal. The OCC subsequently approved the Company's request to stay this order, allowing ONG to collect the $34.6 million, subject to refund should the Company ultimately lose the case. ONEOK took a charge against fourth-quarter earnings as a result of the Commission's order. Although the Company will continue to assert its legal rights, it is hopeful that a resolution of this issue can be negotiated. . Enogex, Inc. requested that the OCC order a rebid of the gas supply and transportation service awarded by ONG for service commencing in 2001. A majority of both the gas supply and the transportation services had been awarded to affiliates of ONG. The OCC determined that there was no basis to require a rebid. . ONG continues to take an active role in response to the OCC's Notice of Inquiry and Notice of Proposed Rulemaking regarding the use of physical and financial instruments to hedge against fuel procurement volatility. ONG exercised provisions contained in a number of its gas supply contracts that allow ONG to fix the price of a portion of its gas supply. ONG fixed the price of approximately 40% of its anticipated 2001/2002 winter gas supply deliveries. . ONG received approval from the OCC to create a Voluntary Fixed Price pilot program that will enable its residential sales customers to fix the gas cost portion of their bill for a specified winter period. The program is being proposed for customers' 2002/2003 gas bills. . During 2001, the KCC issued an Order extending the time period for which gas service disconnection during inclement weather conditions cannot be made. Due to the extension of the time period restricting disconnections, delinquent KGS customers were allowed to continue gas service, thus increasing uncollectible amounts. Higher gas costs in the 2000/2001 heating season also contributed to the increased uncollectible amounts. KGS and other distribution companies in Kansas filed a joint application with the KCC seeking approval to recover the additional uncollectible amounts incurred during the 2000/2001 heating season until reviewed in the next rate case. The KCC approved the deferral allowing the companies to seek recovery of the extraordinary uncollectible account levels experienced in the 2000/2001 winter. KGS expects to file a rate case in late 2002. No accounting treatment has yet been determined. 14 . KGS and the Market Center requested authorization from the KCC to transfer a portion of the transportation assets of the Market Center to KGS. A ruling is expected during 2002. . During 2000, the KCC issued an Order allowing KGS to recover additional costs of its gas purchase hedging program established to protect the price paid by customers for gas purchases. . The KCC approved KGS's WeatherProof Bill Program for the year 2001/2002 heating season. This plan allows customers, at their discretion, to fix their monthly payment. . The KCC granted the Company weather normalization beginning December 2000 that mitigates weather related revenue fluctuations. . In October 2001, the KCC entered a Suspension Order prohibiting the recovery of a portion of KPC gas transportation service costs through the Cost of Gas Rider. The KCC will conduct a hearing on the pass through of those costs in May 2002. KGS is involved in related litigation in the Kansas Court of Appeals, the FERC and the Federal District Court in Kansas. The dispute involves a 1997 settlement agreement entered into by KPC, KGS and the KCC staff. KGS and the KCC staff allege KPC has failed to reduce the rates it is charging KGS in accordance with the settlement agreement. In accordance with regulatory "out" provisions contained in the agreement, KGS is withholding payment to KPC to the extent KGS is not allowed to pass KPC's charges to its customers through the cost of gas rider. KGS is currently accounting for the costs as a deferred gas cost, offset by a deferred liability, and not passing the costs on to customers. The Company has settled all known claims arising out of long-term gas supply contracts containing "take-or-pay" provisions that purport to require the Company to pay for volumes of natural gas contracted for but not taken. The OCC has authorized recovery of the accumulated settlement costs over a 20 year period, expiring in 2014, or approximately $6.7 million annually through a combination of a surcharge from customers and revenue from transportation under Section 311(a) of the NGPA and other intrastate transportation revenues. There are no significant potential claims or cases pending against the Company under "take-or-pay" contracts. OkTex transports gas in interstate commerce under Section 311(a) of the NGPA and is treated as a separate entity by the FERC. Accordingly, OkTex is subject to the regulatory jurisdiction of the FERC under the NGA with respect to rates, accounts and records, the addition of facilities, the extension of services in some cases, the abandonment of services and facilities, the curtailment of gas deliveries and other matters. OkTex has the capacity to move up to 800 million cubic feet per day. In the first quarter of 2000, the FERC issued Order No. 637, which, among other things, imposed additional reporting requirements, required changes to make pipeline and secondary market services more comparable, removed the price caps on secondary market capacity for a period of two years, allowed rates to be based on seasonal or term differentiated factors and narrowed the applicability of the regulatory right of first refusal to apply only to the maximum rate contracts. The Company's interstate pipeline implemented the new regulations in May 2000. The FERC Order did not have a material effect on the Company's operations. (E) PRODUCTION General - The Company's strategy has been to concentrate ownership of natural gas and oil reserves in the mid-continent region in order to add value not only to its existing production operations but also to integrate it into its gathering and processing, marketing and trading, and transportation and storage businesses. The Company continues to focus on growing through acquisitions and developing existing properties. 15 Of the Company's consolidated revenues, revenues from unaffiliated customers for the Production segment represent approximately 1.4, 0.8 and 2.4 percent for fiscal years 2001, 2000 and 1999, respectively. Operating income from the Production segment is 19.6, 4.6 and 6.3 percent of the consolidated operating income for fiscal years 2001, 2000, and 1999, respectively. The Production segment has no single external customer from which it receives ten percent or more of consolidated revenues. Producing Reserves - The Production segment primarily focuses its production activities in natural gas. As of December 31, 2001, the Company had interest in 2,172 gas wells and 218 oil wells located primarily in Oklahoma, Kansas and Texas. A number of these wells produce from multiple zones. Production increased in 2001 as compared to 2000, primarily as a result of production from new wells drilled. Market Conditions and Business Seasonality - Natural gas prices at the beginning of 2001 were at unprecedented highs. The high prices resulted in a significant amount of drilling in the U.S. for the first half of 2001. Accordingly, lack of rig availability delayed some developmental drilling projects for the Company. The subsequent decline in gas prices during the second half of the year reduced the rig shortage and allowed the Company to resume its development projects. In addition, the Company continues to actively pursue acquisition opportunities as a low-risk method of adding reserves. The goal of the Company is to develop an economically viable reserve base through acquisition and development. The Company operates much of the reserve base. In doing so, the Company competes with many large integrated oil and gas companies and numerous independent oil and gas companies of various sizes. The Company is in a good competitive position within its operating region due to low finding costs and high quality production at locations near transportation points and markets. During 2001, the segment's production was sold to a number of affiliated and unaffiliated markets, all at market prices. Similar to the Company's other business segments, the Production segment is subject to seasonal factors. The Production segment's revenues are impacted by prices, which, historically, are higher in the winter heating months when demand is higher than in the summer and shoulder months of spring and fall. Oil prices in the U.S. are also impacted by international production and export policies. Property Acquisitions and Divestitures - The Company acquired $1.5 million of properties located in the mid-continent region of the U.S. during 2001. In June 2001, the Company sold its 40 percent equity interest in K. Stewart for $7.7 million, recognizing a gain from the sale of $0.8 million. Risk Management - The Company utilized derivative instruments in 2001 in order to hedge anticipated sales of natural gas and oil production. During 2001, approximately 74% of the Company's proved developed production was hedged with commodity swap or option collar agreements whereby the Company was able to set the price to be received for the future production and reduce the risk of declining market prices between the origination date of the swap and the month of production. At December 31, 2001, the Production segment had 11 percent of its proved developed gas production hedged for fiscal year 2002. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Note C of Notes to Consolidated Financial Statements. 16 (F) POWER General - The Company's Power segment was created in January 2001 to engage in regional wholesale power trading in the Southwest Power Pool (SPP), Electric Reliability Council of Texas, and Southeast Electric Reliability Council. The Company is also a member of the Western Systems Power Pool. Transactions conducted by the Power segment include capacity and energy. The 300-megawatt power plant, which began operations in mid-2001, is located adjacent to one of the Company's natural gas storage facilities and is configured to supply electric power during peak periods with four gas-powered turbine generators manufactured by General Electric. The Company also has leased from the SPP 200 megawatts of firm point-to-point transmission capacity from the power plant to Entergy Services' transmission system near Fort Smith, Arkansas. The Company has a signed definitive agreement with an unaffiliated company for a 15-year term providing the customer the right to purchase up to 75 megawatts per hour of the plant's generating capacity. The completed construction of this power plant complements the Company's strategy of maximizing earnings capacity of existing assets and exploring new opportunities that are expected to have a positive impact on earnings. Of the Company's consolidated revenues, revenues from unaffiliated customers for the Power segment represent approximately 0.4 percent in fiscal year 2001. Operating income from the Power segment is 1.2 percent of the consolidated operating income for fiscal year 2001. The Power segment has no single external customer from which it receives ten percent or more of consolidated revenues. Market Conditions and Business Seasonality - The Power segment primarily serves peaking requirements in the SPP. There is currently limited competition in this market; however, several peaking plants are currently being constructed in the region, which will increase competition in the future. Competition typically arises as a result of a plant's location, transmission capabilities and operational efficiency. The Company believes that the fully operational status of the plant, as compared to competitor plants that are still being constructed and the plant's ability to start up quickly with its readily available gas supply allow it to be a competitive force in its market. More importantly, the Company believes that it serves a specific niche through cross commodity trading natural gas and electricity in the power trading market, rather than producing baseload electricity. The Power segment's revenue and gross margin on power sales are subject to seasonality due to fluctuations in sales volumes and the price of natural gas and electricity. Electricity volumes are typically higher in the summer cooling months than in the winter months, reflecting increased demand due to greater cooling requirements. However, increased price volatility in the natural gas market can mitigate the seasonality effect by influencing decisions related to injection and withdrawal of natural gas in storage. Price Risk Management - The Company's strategy is to capture market volatility in the spark spread premium, which is the value added by converting natural gas to electricity. In doing so, the Power segment uses price risk management instruments, including 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 C of Notes to Consolidated Financial Statements. (G) OTHER The Company, through two subsidiaries, owns a parking garage and leases an office building (ONEOK Plaza) in downtown Tulsa, Oklahoma, in which the Company's headquarters are located. The parking garage is owned and operated by ONEOK Parking Company. ONEOK Leasing Company leases excess office space to others. The Other segment has no single external customer from which it receives ten percent or more of consolidated revenues. 17 The Other segment includes the approximate 21 percent current ownership of Magnum Hunter Resources, Inc. (MHR), which is currently accounted for under the equity method. In December 2001, MHR announced a merger with Prize Energy Corp. ("Prize"). ONEOK has informed MHR that the Company will not "top-up" its investment in the merged company, thereby decreasing its ownership to approximately 11 percent in the merged company, and ONEOK has agreed to give up one Director's position on the MHR Board of Directors. Assuming the merger is completed in 2002, the Company will begin accounting for the investment in MHR as an available for sale security and, accordingly, mark the investment to fair value through other comprehensive income. ITEM 2. PROPERTIES (A) DESCRIPTION OF PROPERTY GATHERING AND PROCESSING The Company owns and operates or leases and operates 25 natural gas processing plants in Oklahoma, Kansas and Texas, six of which are currently idle. It also has an ownership interest in four natural gas processing plants that are operated by other owners. The Company owns approximately 19,300 miles of natural gas gathering pipeline, some of which are connected to the Company's natural gas processing plants. The total capacity of the plants the Company owns, leases or has an ownership interest in is 2.2 Bcf/d, of which 0.150 Bcf/d is currently idled. The Company's natural gas processing operations utilize two types of gas processing plants, field and straddle plants. Field plants aggregate volumes from multiple producing wells into quantities that can be economically processed to extract natural gas liquids and to remove water vapor and other contaminants. Straddle plants are situated on mainline natural gas pipelines and allow operators to extract natural gas liquids under contract from a natural gas stream when the market value of natural gas liquids separated from the natural gas stream is higher than the market value of the same unprocessed natural gas stream. The Company's natural gas processing plants were operating at various capacities throughout the year. At certain times throughout the year, the Company's natural gas processing facilities operated at levels well below capacity due to the historically high natural gas prices. When this occurred, some producers sold their natural gas rather than having it processed into NGLs. The Company is rationalizing assets in non-core operating areas. Overall, the plants operated at approximately 64 percent of capacity. The Company owns and operates or leases and operates five NGL storage and terminal facilities in Kansas and Texas. The total capacity of the facilities is approximately 18,000 MBbls. The Company owns and operates or leases and operates two fractionation facilities in Oklahoma and Kansas. The total fractionation capacity of the two facilities is approximately 90,000 Bbls/d. TRANSPORTATION AND STORAGE The Company owned a combined total of approximately 3,245 miles of transmission pipeline in Oklahoma, approximately 1,711 miles in Kansas, and approximately 4,733 miles in Texas at December 31, 2001. Compression and dehydration facilities are located at various points throughout the pipeline system. In addition, the Company owns five underground storage facilities located throughout Oklahoma, two storage facilities in Kansas and three storage facilities in Texas. The storage facilities primarily consist of land and mineral leasehold agreements, wells and equipment, rights of way, and cushion gas. The total working storage capacity of these facilities is approximately 58 Bcf, of which 8 Bcf is currently idle. Four of the Oklahoma storage facilities are located in close proximity to large market areas; the other storage facility is located in western Oklahoma and is leased to and operated by another company. However, 3 Bcf of working storage capacity in that facility has been retained for the Company's use. The storage facilities in Kansas and Texas are connected to the Company's pipelines and are located near unaffiliated intrastate and interstate pipelines, providing the Company's storage customers with access to multiple markets. 18 DISTRIBUTION The Company owned approximately 16,978 miles of pipeline and other distribution facilities in Oklahoma and approximately 12,291 miles of pipeline and other distribution facilities in Kansas at December 31, 2001. The Company owns a number of warehouses, garages, meter and regulator houses, service buildings, and other buildings throughout Oklahoma and Kansas. The Company also owns a fleet of trucks and maintains an inventory of spare parts, equipment, and supplies. PRODUCTION The Company owns varying economic interests, including working, royalty and overriding royalty interests, in 2,172 gas wells and 218 oil wells, some of which are completed in multiple producing zones. Such interests are in wells located primarily in Oklahoma, Kansas, and Texas. The Company owns 191,713 net onshore developed leasehold acres and 40,140 net onshore undeveloped acres, located primarily in Oklahoma, Kansas, and Texas. The Company does not own any offshore acreage. Lease acreage in producing units is held by production. Leases not held by production are generally for a term of three years and may require payment of annual rentals. POWER The Company has constructed a 300-megawatt gas-fired merchant power plant located in Logan County, Oklahoma adjacent to an affiliate's gas storage facility. This plant is configured to supply electric power during peak periods with four gas-powered turbine generators manufactured by General Electric. It began operations in mid-2001. Total costs to construct this plant totaled approximately $120 million. OTHER The Company owns a parking garage and land, subject to a long-term ground lease. Upon this land is a seventeen-story office building with approximately 517,000 square feet of net rentable space. The Company also leases its office building under a lease term that expires in 2009 with six five-year renewal options. After the primary term or any renewal period, the Company can purchase the property at its fair market value. The Company occupies approximately 194,000 square feet for its own use and leases the remaining space to others. (B) OTHER INFORMATION Oil and gas production is defined by the Securities and Exchange Commission (SEC) to include natural gas liquids in their natural state. The Company's gathering and processing operation produces natural gas liquids. The SEC excludes the production of natural gas liquids resulting from the operations of gas processing plants as an oil and gas activity. Accordingly, the following tables exclude information concerning the production of natural gas liquids by the Company's processing operations. OIL AND GAS RESERVES All of the oil and gas reserves for the Production segment are located in the United States. Quantities of Oil and Gas Reserves - See Note S of Notes to Consolidated Financial Statements. Present Value of Estimated Future Net Revenues - See Note T of Notes to Consolidated Financial Statements. RESERVE ESTIMATES FILED WITH OTHERS None. 19 QUANTITIES OF OIL AND GAS PRODUCED The net quantities of oil and natural gas produced and sold, including intercompany transactions for the Production segment, were as follows:
Years Ended December 31, December 31, August 31, Sales 2001 2000 1999 ===================================================================================================== Oil (MBbls) 492.6 400.0 460.0 Gas (MMcf) 27,578.4 26,746.0 27,773.0 -----------------------------------------------------------------------------------------------------
Four Months Ended December 31, Sales 1999 1998 ===================================================================================================== Oil (MBbls) 138.0 145.0 Gas (MMcf) 8,306.0 7,700.0 -----------------------------------------------------------------------------------------------------
AVERAGE SALES PRICE AND PRODUCTION (LIFTING) COSTS Average sales prices and production costs for the Production segment are as follows: Years Ended December 31, December 31, August 31, 2001 2000 1999 -------------------------------------------------------------------------- Average Sales Price (a) Per Bbl of oil $ 24.89 $ 21.43 $ 13.56 Per Mcf of gas $ 3.91 $ 2.28 $ 2.12 Average Production Costs Per Mcfe (b) $ 0.68 $ 0.60 $ 0.49 -------------------------------------------------------------------------- Four Months Ended December 31, 1999 1998 -------------------------------------------------------------------------- Average Sales Price (a) Per Bbl of oil $ 18.93 $ 12.53 Per Mcf of gas $ 2.50 $ 2.03 Average Production Costs Per Mcfe (b) $ 0.60 $ 0.46 -------------------------------------------------------------------------- (a) In determining the average sales price of oil and gas, sales to affiliated companies were recorded on the same basis as sales to unaffiliated customers. (b) For the purpose of calculating the average production costs per Mcf equivalent, barrels of oil were converted to Mcf using six Mcfs of natural gas to one barrel of oil. Production costs, which include production taxes, are based on the wellhead market price, which averaged $24.89 per Bbl of oil and $4.33 per Mcf of gas in 2001 and $29.34 per Bbl of oil and $3.42 per Mcf of gas in 2000, instead of the weighted average hedged price. This contributed to the significant increase in average production costs per Mcfe. Production costs do not include depreciation or depletion. 20 WELLS AND DEVELOPED ACREAGE The table shows gross and net wells in which the Production segment has an interest at December 31, 2001. Gas Oil -------------------------------------- Gross wells 2,172 218 Net wells 622 78 -------------------------------------- Gross developed acres and net developed acres by well classification are not available. Net developed acres for both oil and gas is 191,713 acres. UNDEVELOPED ACREAGE The gross and net undeveloped leasehold acreage for the Production segment at December 31, 2001 is as follows: Gross Net -------------------------------------- Colorado 320 36 Kansas 1,228 538 Mississippi 2 1 Oklahoma 126,716 39,078 Texas 3,109 487 -------------------------------------- Total 131,375 40,140 -------------------------------------- Of the net undeveloped acres, approximately 38 percent is in the Anadarko Basin area of Oklahoma and Texas, 18 percent in the Arkoma Basin area of Oklahoma and 6 percent in the Ardmore Basin area of Oklahoma. The balance is located in major producing areas in other states including Kansas, Texas and Colorado. NET DEVELOPMENT WELLS DRILLED The net interest in total development wells drilled, by well classification, for the Production segment is as follows: Years Ended December 31, December 31, August 31, 2001 2000 1999 --------------------------------------------------------- Development Productive 29.6 28.5 22.5 Dry 0.6 1.8 1.4 --------------------------------------------------------- Total 30.2 30.3 23.9 ========================================================= Four Months Ended December 31, 1999 1998 --------------------------------------------------------- Development Productive 9.6 8.2 Dry 0.0 0.1 --------------------------------------------------------- Total 9.6 8.3 ========================================================= 21 PRESENT DRILLING ACTIVITIES On December 31, 2001, the Production segment was participating in the drilling of 6 wells. The Company's net interest in these wells amounts to 0.53 wells. FUTURE OBLIGATIONS TO PROVIDE OIL AND GAS None. 22 ITEM 3. LEGAL PROCEEDINGS United States ex rel. Jack J. Grynberg v. ONEOK, Inc., ONEOK Resources Company, ------------------------------------------------------------------------------- and Oklahoma Natural Gas Company, (CTN-8), No. CIV-97-1006-R, United States ------------------------------------------ District Court for the Western District of Oklahoma, transferred, In re Natural ------------- Gas Royalties Qui Tam Litigation, MDL Docket No. 1293, United States District --------------------------------- Court for the District of Wyoming. On June 21, 1999, ONEOK, Inc. ("ONEOK") was served with a Complaint filed by Jack J. Grynberg ("Grynberg"), purportedly on behalf of the United States pursuant to the False Claims Act (31 U.S.C. [sect] 729, et seq.). Similar complaints were filed against approximately 65 other companies that measure natural gas extracted from lands owned by the federal government or American Indian tribes. The gravamen of the complaints is that, since at least 1985, the defendants have systematically undermeasured the volumes and/or the heating content of gas purchased from federal and Indian lands, resulting in underpayment of royalties due the federal government and the various Indian tribes. Grynberg seeks to recover the underpayments, interest, treble damages, costs, including attorneys' fees, and civil penalties in the amount of $5,000 to $10,000 for each violation of the False Claims Act. The actions brought by Grynberg, together with certain other actions alleging underpayment of royalties to federal and Indian lessors, have been assigned to a multidistrict litigation (MDL) proceeding in the United States District Court for the District of Wyoming for coordination of pretrial proceedings. The Court has overruled the defendants' Motions to Dismiss, but has not yet established a scheduling order for further proceedings. No discovery relating to claims against ONEOK has commenced in the case and ONEOK intends to vigorously defend all aspects of claims made against it in this litigation. ONEOK, Inc. v. Southern Union Company, No. 99-CV-0345-H(M), United States -------------------------------------- District Court for the Northern District of Oklahoma, transferred, No. CV 00-1812-PHX-ROS, in the United States District Court for the District of Arizona, on appeal of preliminary injunction, United States Court of Appeals for the Tenth Circuit, Case No. 99-5103. On May 5, 1999, ONEOK, Inc. ("ONEOK") filed a Complaint against Southern Union Company ("Southern Union") alleging that Southern Union had breached the February 21, 1999 Confidentiality and Standstill Agreement (the "Agreement") between Southern Union and Southwest Gas Corporation ("Southwest") and had tortiously interfered with the ONEOK-Southwest merger. ONEOK alleged that it is a third-party beneficiary of the Agreement. ONEOK also sought to enjoin Southern Union from breaching the Agreement and from taking any other wrongful actions to disrupt the proposed merger of ONEOK with Southwest. On May 11, 1999, the District Court granted a Temporary Restraining Order enjoining Southern Union from any future violation of its Agreement with Southwest, including soliciting proxies from Southwest shareholders. On May 17, 1999, the Temporary Restraining Order became a Preliminary Injunction by stipulation of the parties and was appealed to the Tenth Circuit Court of Appeals. Southern Union filed its Answer to the Complaint on September 7, 1999, withdrawing some specific allegations of wrongdoing that it made in an earlier filing. Southern Union filed an Amended Answer and Counterclaims on November 10, 1999. Southern Union's Counterclaims against ONEOK are for: (1) a declaratory judgment determining that the Agreement was unenforceable; and (2) a declaratory judgment determining that Southern Union had not breached the Agreement. The Court held a status conference on August 31, 2000, and granted Southern Union's Motion to Transfer the action to the federal district court in Arizona. Based on the transfer of the case to Arizona, on February 2, 2001, the Tenth Circuit dismissed Southern Union's appeal of the Preliminary Injunction for want of appellate jurisdiction. Following transfer to Arizona, by Order filed June 5, 2001, this case was consolidated with Southern Union Company v. Southwest Gas Corporation, et al., Case No. CIV-99-1294-PHX-ROS, described below. On June 29, 2001, Southern Union filed a Motion for Summary Judgment on all of the claims asserted by ONEOK against Southern Union; in an Order dated January 4, 2002, the Court, among other things, granted Southern Union's Motion for Summary Judgment against ONEOK. Southern Union's counterclaims have not been ruled upon by the Court, but appear to have no further legal effect. Southern Union Company v. Southwest Gas Corporation, et al., No. ------------------------------------------------------------ CIV-99-1294-PHX-ROS, United States District Court for the District of Arizona. On July 19, 1999, the plaintiff, Southern Union Company ("Southern Union"), filed its Complaint against Southwest Gas Corporation ("Southwest"), ONEOK, Inc. ("ONEOK"), Michael O. Maffie, Thomas Y. Hartley and Thomas R. Sheets (jointly "Southwest Individual Defendants") and Eugene N. Dubay and John A. Gaberino, Jr. (jointly "ONEOK Individual Defendants"), James 23 M. Irvin ("Irvin") and Jack D. Rose ("Rose"). Southern Union alleged (1) that the action arose out of a fraud and racketeering scheme by Southwest and ONEOK and the individual defendants to block Southwest's shareholders from voting for Southern Union's offer to acquire Southwest and ensure that only ONEOK's offer would be approved, (2) the defendants entered into a secret campaign of deception, corruption and misrepresentation with members of regulatory commissions in order to influence their vote on the Southern Union proposal to acquire Southwest and to mislead the board and shareholders of Southwest to believe falsely that such an acquisition would face greater regulatory hurdles than the proposed Southwest-ONEOK merger, (3) Southwest and Southwest Individual Defendants fraudulently induced Southern Union to enter into a Confidentiality and Standstill Agreement (the "Agreement") with Southwest, and (4) that corruption and fraud were necessary to defeat the Southern Union offer. The Complaint alleged numerous causes of action including (1) racketeering in violation of 18 U.S.C. [sect].[sect] 1962(c) and 1962(d), and unlawful activity in violation of Arizona Criminal Code through a pattern of unlawful activities predicated on acts of extortion and a scheme or artifice to defraud against all defendants and conspiracy (the "RICO claims"), (2) fraud in the inducement, breach of contract, violation of the Securities Exchange Act of 1934, breach of covenant of good faith and fair dealing and rescission of the Agreement against Southwest, and (3) intentional interference with a business relationship and tortious interference of a contractual relationship against ONEOK, the ONEOK Individual Defendants, the Southwest Individual Defendants, Rose and Irvin. The Complaint asked for the award of an amount of not less than $750,000,000 to be trebled for racketeering and unlawful violations (with attorneys' fees and investigators' fees); compensatory damages of not less than $750,000,000 for fraud in the inducement, breach of contract, breach of covenant of good faith and fair dealing, intentional interference with a business relationship, tortious interference with contractual relationship and civil conspiracy (with interest and costs); rescission of the Agreement (with costs), punitive damages, injunctive relief under the Securities Act of 1934 and any further relief the Court deems just and proper. Thomas R. Sheets was later dismissed as a defendant by Southern Union. As a result of Motions to Dismiss being filed by certain defendants, on October 12, 1999, Southern Union filed its First Amended Verified Complaint (the "Amended Complaint"). The Amended Complaint asserted many of the same claims as the earlier Complaint. Larry Brummett and Jim Kneale were added as named defendants to the action. On May 30, 2000, Southern Union filed a dismissal with prejudice of its claims against Larry Brummett. The Court granted leave to Southern Union to file its Second Amended Complaint on August 3, 2000, but further ordered that Southern Union could make no further amendments to its Complaint. The Second Amended Complaint alleged essentially the same claims as the earlier Complaint. On August 4, 2000, the Court heard arguments on the defendants' Motions to Dismiss the federal and state RICO claims, the motions of ONEOK and Southwest to dismiss or stay the action because of previously filed actions, the Motions to Dismiss for lack of personal jurisdiction filed by several of the individual defendants, and the Motion to Dismiss filed by Jim Irvin on sovereign immunity grounds. Southern Union orally made a motion at the hearing to dismiss without prejudice its federal and state RICO claims against the ONEOK Individual Defendants, which was granted by the Court. On August 28, 2000, the Court entered an Order denying the Motions to Dismiss for lack of personal jurisdiction filed on behalf of Eugene N. Dubay and John A. Gaberino, Jr. but granted the motion filed on behalf of Jim Kneale. On that same day, the Court entered an Order denying the Motion to Dismiss filed by Jim Irvin on sovereign immunity grounds. The Court also entered an Order denying the defendants' Motions to Dismiss the federal and state RICO claims on the ground that they were precluded by the Private Securities Litigation Reform Act. On August 24, 2000, ONEOK and all the other defendants filed Motions to Dismiss the claims asserted by Southern Union in its Second Amended Complaint. On December 15, 2000, the Court withdrew its previous Order of August 28, 2000, and granted the motions of ONEOK and Southwest to dismiss the federal RICO claims made by Southern Union on the ground that they were precluded by the Private Securities Litigation Reform Act. Motions were thereafter filed to apply the Court's December 15, 2000 ruling to the other defendants and to Southern Union's state RICO claims; by Order filed May 23, 2001, the Court applied the December 15, 2000 ruling as to all defendants and dismissed Southern Union's state RICO claims against all defendants. In an Order dated June 21, 2001, the Court, among other things, granted the Motions to Dismiss all of Southern Union's claims against ONEOK, Eugene N. Dubay, and John A. Gaberino, Jr. except the claim for tortious interference with business relations and, as to Eugene N. Dubay and John A. Gaberino, Jr., the claim for tortious interference with contract. On or about June 29, 2001, ONEOK, Eugene N. Dubay, and John A. Gaberino, Jr. filed Motions for Summary Judgment. In an Order filed September 26, 2001, the Court, among other things, granted the Motions for Summary Judgment by ONEOK, Eugene N. Dubay, and John A. Gaberino, Jr. on Southern Union's 24 claim for tortious interference with business relations to the extent Southern Union is seeking lost profits damages for the failed merger with Southwest but denied the motion to the extent Southern Union is seeking out-of-pocket and punitive damages; and granted the Motions for Summary Judgment by Eugene N. Dubay and John A. Gaberino, Jr. on Southern Union's claim for tortious interference with contract. At this point, Southern Union's only remaining claim against ONEOK, Eugene Dubay and John A. Gaberino, Jr. is for out-of-pocket damages and punitive damages based on alleged tortious interference with a business relationship. Under the current Scheduling Order, final Motions for Summary Judgment may be filed by April 30, 2002 and trial is scheduled to commence on October 15, 2002. ONEOK expects to file a Motion for Summary Judgment seeking a dismissal of the remaining claims of Southern Union, including the claim for punitive damages. Based on discovery in the cases at this point, ONEOK believes that Southern Union's out-of-pocket damages potentially recoverable at trial, exclusive of legal fees and expenses, are less than $1,000,000. As in all litigation, judgments of the Court are potentially subject to appeal by the parties. ONEOK, Inc. v. Southwest Gas Corporation, No. 00-CV-063-H(E), United States ----------------------------------------- District Court for the Northern District of Oklahoma, transferred, No. CIV-00-1775-PHX-ROS, United States District Court for the District of Arizona. On January 21, 2000, as a result of its termination of the agreement for the merger of ONEOK, Inc. ("ONEOK") and Southwest Gas Corporation ("Southwest"), ONEOK brought this action against Southwest seeking a declaratory judgment determining that it had properly terminated the Merger Agreement. On March 6, 2000, Southwest filed a motion seeking either a dismissal of the action or a transfer to the federal court in Arizona. On August 23, 2000, ONEOK filed its First Amended Complaint against Southwest, adding allegations that Southwest had fraudulently induced ONEOK to enter into the Amended Merger Agreement with Southwest and had breached the Merger Agreement. At a status conference held on August 31, 2000, the Court heard argument on and granted Southwest's Motion to Transfer the action to the federal district court in Arizona. Southwest's filed its Amended Answer to ONEOK's First Amended Complaint on or about May 7, 2001, denying all claims. Following transfer to Arizona, by Order filed June 5, 2001, this case was consolidated with Southern Union Company v. Southwest Gas Corporation, et al., Case No. CIV-99-1294-PHX-ROS, described above. On or about June 29, 2001, Southwest filed a Motion for Summary Judgment on ONEOK's claims against Southwest. In an Order dated January 4, 2002, the Court, among other things, granted Southwest's Motion for Summary Judgment as to ONEOK's claims against Southwest for breach of contract and rescission, but denied Southwest's Motion for Summary Judgment as to ONEOK's claim against Southwest for fraudulent inducement. Under the current Scheduling Order, final Motions for Summary Judgment may be filed by April 30, 2002 and trial is scheduled to commence on October 15, 2002. Southwest Gas Corporation v. ONEOK, Inc., No. CIV-00-0119-PHX-ROS, United States ----------------------------------------- District Court for the District of Arizona. On January 24, 2000, Southwest Gas Corporation ("Southwest") filed a complaint against ONEOK, Inc. ("ONEOK") and Southern Union Company ("Southern Union"). Southwest alleges that: (1) under the Merger Agreement between ONEOK and Southwest, ONEOK agreed to furnish all information concerning itself that is required or customary for inclusion in the Southwest proxy statement related to the merger and that none of such information would contain any untrue statement of material facts or omit to state any material facts required to be stated therein or necessary to make the statements therein in light of the circumstances under which they are made, not misleading; (2) under the Merger Agreement ONEOK promised to use its commercially reasonable efforts to obtain all necessary governmental authorization for the merger (and consult with Southwest in respect thereto) and to take all other necessary actions and do all things necessary, proper or advisable to consummate and make effective the merger transaction; (3) ONEOK failed to make certain disclosures to the Southwest Board; (4) if ONEOK had made such disclosures, it would have caused the Board of Southwest to have questions about the chances of obtaining regulatory approvals and the Southwest Board might not have entered into an amendment of the Merger Agreement and the Board would have demanded ONEOK cure its breach of the Merger Agreement; (5) ONEOK's failure to use its commercially reasonable efforts to obtain such approval as required by the Merger Agreement; and (6) ONEOK has refused to cure its breach of and has wrongfully terminated the Merger Agreement. The Complaint alleges numerous causes of action including: (i) fraud in the inducement; (ii) fraud; (iii) breach of contract; (iv) breach of implied covenant of good faith and fair dealing; and (v) declaratory relief. The Complaint asks that the Merger Agreement be declared null and void and Southwest be awarded its actual, consequential, incidental and punitive damages in an amount in excess of 25 $75,000 for fraud in the inducement and fraud or alternatively (1) damages for breach of the contract and implied covenant in an amount in excess of $75,000, or (2) a declaration that ONEOK has breached the Merger Agreement. On February 28, 2000, Southern Union filed its Answer to the Complaint denying the claims made by Southwest. On or about April 16, 2001, ONEOK filed its Answer to Southwest's First Amended Complaint, and Counterclaims against Southwest reasserting, in essence, the claims ONEOK asserts against Southwest in Case No. CIV-00-1775-PHX-ROS, described above. On or about June 29, 2001, Southwest filed a Motion for Partial Summary Judgment in its favor on its claims against ONEOK for breach of contract and breach of the implied covenant of good faith and fair dealing. Also on or about June 29, 2001, ONEOK filed a Motion for Summary Judgment on Southwest's claims against ONEOK. In an Order dated January 4, 2002, the Court, among other things, (i) denied Southwest's Motion for Partial Summary Judgment in its favor on its claims against ONEOK for breach of contract and breach of the implied covenant of good faith and fair dealing; (ii) granted ONEOK's Motion for Summary Judgment against Southwest with respect to Southwest's claim for "benefit-of-the-bargain" or "price differential damages" (i.e., damages measured by the difference between the ONEOK-Southwest Merger Agreement price per share and the market value of Southwest's shares following termination of the Merger Agreement); and (iii) denied ONEOK's Motion for Summary Judgment in part with respect to Southwest's claims for fraud in the inducement and fraud. Under the current Scheduling Order, final Motions for Summary Judgment may be filed by April 30, 2002 and trial is scheduled to commence on October 15, 2002. Based on discovery in the cases at this point, ONEOK believes that Southwest's actual damages potentially recoverable at trial, exclusive of legal fees and expenses, are less than $5,500,000. As in any litigation, judgments of the Court are potentially subject to appeal by the parties. In re ONEOK, Inc. Derivative Litigation, No. CJ-2000-00593, District Court of ---------------------------------------- Tulsa County, Oklahoma (formerly Gaetan Lavalla, derivatively on behalf of nominal defendant ONEOK, Inc. v. Larry W. Brummett, et al., No. CJ-2000-598 and Hayward Lane, derivatively on behalf of nominal defendant ONEOK, Inc. v. Larry W. Brummett, et al.). On February 3, 2000, two substantially identical derivative actions were filed in the District Court in Tulsa, Oklahoma, by shareholders against the members of the Board of Directors of ONEOK, Inc. ("ONEOK") for violation of their fiduciary duties to ONEOK by allegedly causing or allowing ONEOK to engage in fraudulent and improper schemes designed to "sabotage" Southern Union Company's ("Southern Union") competitive bid to acquire Southwest Gas Corporation ("Southwest") and secure regulatory approval for ONEOK's own planned merger with Southwest. Such conduct allegedly caused ONEOK to be sued by both Southwest and Southern Union which exposed ONEOK to millions of dollars in liabilities. The allegations are used as a basis for causes of action for intentional breach of fiduciary duty, derivative claim for negligent breach of fiduciary duty, class and derivative claims for constructive fraud, and derivative claims for gross mismanagement. Each plaintiff seeks a declaration that the lawsuit is properly maintained as a derivative action, the defendants, and each of them, have breached their fiduciary duties to ONEOK, an injunction permanently enjoining defendants from further abuse of control and committing of gross mismanagement and constructive fraud, and asks for an award of compensatory and punitive damages and costs, disbursements and reasonable attorney fees. A Joint Motion for Consolidation of both derivative actions was filed on June 6, 2000, and Pretrial Order No. 1 was entered on that date consolidating the actions and establishing a schedule for a response to a Consolidated Petition. On July 21, 2000, the plaintiffs filed their Consolidated Petition. Stephen J. Jatras and J.M. Graves have been eliminated as defendants in the Consolidated Petition, but Eugene Dubay was added as a new defendant. The plaintiffs also dropped their class and derivative claim for constructive fraud, but added a new derivative claim for waste of corporate assets. On September 19, 2000, ONEOK, the Independent Directors (Anderson, Bell, Cummings, Ford, Fricke, Lake, Mackie, Newsom, Parker, Scott and Young), David Kyle, and Gene Dubay filed Motions to Dismiss the action for failure of the plaintiffs to make a pre-suit demand on ONEOK's Board of Directors. In addition, the Independent Directors, David Kyle, and Gene Dubay filed Motions to Dismiss the Plaintiffs' Consolidated Petition for failure to state a claim. On January 3, 2001, the Court dismissed the action without prejudice as to its claims against Larry Brummett. On February 26, 2001, the action was stayed until one of the parties notifies the court that a dissolution of the stay is requested. Quinque Operating Company, et al. v. Gas Pipelines, et al., 26/th/ Judicial ----------------------------------------------------------- District, District Court of Stevens County, Kansas, Civil Department, Case No. 99C30. On June 8, 2001, a Second Amended Petition was filed as a purported class action against approximately 225 defendants, including ONEOK, Inc. (the "Company"), one of its 26 divisions and five of its subsidiaries. The Second Amended Petition was purportedly filed on behalf of all producers and royalty owners who have lost money as a result of alleged mismeasurement of gas since 1974 from any of the approximately 225 defendants. The Second Amended Petition alleges that each of the approximately 225 defendants engaged in one or more specific "mismeasurement techniques" and conspired with one another to undermeasure the gas sold by the alleged class members. The Second Amended Petition alleges that the aggregate alleged underpayment to all purported class members since 1974 is estimated to be tens of billions of dollars. One of the named subsidiaries of the Company, ONEOK WesTex Transmission, Inc. ("ONEOK WesTex"), is a former subsidiary of Kinder Morgan, and Kinder Morgan has agreed to assume the defense of ONEOK WesTex while reserving its rights and denying that it has any obligation to indemnify the Company against any loss suffered by ONEOK WesTex as a result of this litigation. Another of the named subsidiaries of the Company, ONEOK Resources Company, was voluntarily dismissed as a defendant on December 4, 2001, because that subsidiary does not measure gas for pay purposes. Numerous other defendants also have been voluntarily dismissed for the same reason. Discovery in the case, except as to class certification and personal jurisdiction issues, has been stayed. Plaintiffs and defendants, including the ONEOK defendants, have served and responded to various discovery requests on the personal jurisdiction and class certification issues. (One of the ONEOK defendants, ONEOK Gas Transportation, LLC, is contesting personal jurisdiction.) The defendants, including the ONEOK defendants, also have filed a Motion to Dismiss the action, asserting various legal defenses to plaintiffs' claims. That motion has been fully briefed and was argued before the Court on November 29, 2001, and we are awaiting the Court's decision on it. In February 2002, plaintiffs filed a motion to file a Third Amended Petition, in order to add certain plaintiffs, dismiss Quinque Operating Company as a plaintiff, and amend certain of their substantive allegations. On February 21, 2002, the Court entered an Order allowing the filing of the plaintiff's Third Amended Petition. The Company intends to vigorously defend all aspects of the claims asserted in this case. Application of Michael Edward McAdams and John Powell Walker for Relief from ---------------------------------------------------------------------------- Improper and Excessive Gas Costs, Cause No. PUD 980000188, before the Oklahoma --------------------------------- Corporation Commission. On April 6, 1998, the Applicants filed an Application, naming ONG as the Respondent, requesting that the Commission review the gas purchase contract between ONG and Dynamic Energy Resources, Inc. (which was subsequently assigned by Dynamic to Enogex, Inc., and to Associated Natural Gas, Inc. (now Duke Energy)). Applicants allege that ONG has charged and continues to charge its ratepayers, through its PGA, excessive, imprudent and unwarranted gas purchase costs related to that contract. Applicants seek, on behalf of all ratepayers, a determination of whether ONG is passing excessive, imprudent gas costs through to its customers, and if so, to order refunds or prospective adjustments warranted to compensate the ratepayers for past and on-going overcharges. The Consumer Services Divisions ("CSD") of the Commission is also conducting a review of the contract. Applicants filed their direct testimony on February 21, 2002, alleging that ONG's liability to its ratepayers is $100.4 million. Of this amount, $44.8 million represents the alleged excess amount paid under the contract, and $55.6 million represents the opportunity cost of funds incurred by the ratepayers as a result of the alleged overcharges. CSD filed its direct testimony on February 25, 2002 alleging excess costs under the contract of $45 million and interest thereon in the amount of $22 million. CSD also alleged that ONG passed on excess costs from five other contracts (including the old Creek Systems contract) in the amount of $53 million which they recommended the OCC pursue. ONG is to file rebuttal testimony on April 21, 2002. The hearing before the Commission en banc and/or an ALJ is scheduled June 3, 2002. 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. 01C0029, 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 0157 in the District -------------------------------------------- Court of Reno County, Kansas. Two separate class action lawsuits were filed against ONEOK and several of its affiliates in early 2001 relating to certain gas explosions in or near Hutchinson, Kansas. The plaintiffs seek to certify two separate classes of claimants, which include all owners of real estate in Reno County, Kansas whose property had allegedly declined in value, and owners of businesses in Reno County whose income had allegedly suffered. The petitions seek recovery on 27 behalf of the class claimants for an amount which will fully and fairly compensate all members of the class. In addition to the foregoing cases, there are four other cases filed against ONEOK or other subsidiaries of ONEOK seeking property damage, personal injury, wrongful death claims and punitive damages relating to the gas explosion in or near Hutchinson, Kansas. ONEOK and its subsidiaries are being represented by their insurance carrier in these cases. At this point in discovery, ONEOK is unable to evaluate the merits of these cases or likelihood of success by the plaintiffs. 28 ITEM 4. RESULTS OF VOTES OF SECURITY HOLDERS (A) MATTERS SUBMITTED TO A VOTE OF SECURITY HOLDERS No matter was submitted to a vote of the Company's security holders, through the solicitation of proxies or otherwise, during the fourth quarter of the fiscal year covered by this report. EXECUTIVE OFFICERS OF THE REGISTRANT 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 49 2000 to present Chairman of the Board of Directors, President, and Chief Executive Officer Chairman of the Board, 1997 to 2000 President and Chief Operating Officer President and Chief 1995 to present Member of the Board of Directors Executive Officer 1994 to 1997 President and Chief Operating Officer of Oklahoma Natural Gas Company --------------------------------------------------------------------------------------------------------------------- James C. Kneale 50 2001 to present Senior Vice President, Treasurer, and Chief Financial Officer Senior Vice President, 1999 to 2000 Vice President, Treasurer, and Chief Financial Officer Treasurer, and Chief 1997 to 1999 President and Chief Operating Officer of Oklahoma Natural Gas Company Financial Officer 1996 to 1997 Vice President of ONEOK Resources Company --------------------------------------------------------------------------------------------------------------------- John A. Gaberino, Jr. 60 2001 to present Senior Vice President, General Counsel, and Corporate Secretary Senior Vice President, 1998 to 2001 Senior Vice President and General Counsel General Counsel, and 1994 to 1998 Stockholder, Officer and Director of Gable & Gotwals Corporate Secretary --------------------------------------------------------------------------------------------------------------------- Edmund J. Farrell 58 2001 to present Senior Vice President -- Administration Senior Vice President -- 1999 to 2001 President and Chief Operating Officer of Oklahoma Natural Gas Company Administration 1997 to 1999 Vice President of ONEOK Gas Marketing Company 1996 to 1997 Vice President -- Customer Services of Oklahoma Natural Gas Company --------------------------------------------------------------------------------------------------------------------- John W. Gibson 49 2000 to present President -- Energy, ONEOK, Inc. (1) President -- Energy 1996 to 2000 Executive Vice President, Koch Energy, Inc.; President, Koch Midstream Services; President, Koch Gateway Pipeline Company --------------------------------------------------------------------------------------------------------------------- Christopher R Skoog 38 1999 to present President -- ONEOK Energy Marketing and Trading Company, II President -- ONEOK 1995 to 1999 Vice President -- ONEOK Gas Marketing Company Energy Marketing and Trading Company, II --------------------------------------------------------------------------------------------------------------------- J.D. Holbird 52 1999 to present President -- ONEOK Resources Company President -- ONEOK 1997 to 1999 Vice President -- ONEOK Resources Company Resources Company 1996 to 1997 Vice President -- Tulsa District Oklahoma Natural Gas Company --------------------------------------------------------------------------------------------------------------------- Eugene N. Dubay 53 1997 to present President and Chief Operating Officer of Kansas Gas Service Company President and Chief 1996 to 1997 Vice President of Corporate Development Operating Officer of Kansas Gas Service Company --------------------------------------------------------------------------------------------------------------------- Samuel Combs, III 44 2001 to present President and Chief Operating Officer of Oklahoma Natural Gas Company President and Chief 1999 to 2001 Vice President Western Region Oklahoma Natural Gas Company Operating Officer of 1996 to 1999 Vice President -- Oklahoma City District Oklahoma Natural Gas Company Oklahoma Natural Gas Company ---------------------------------------------------------------------------------------------------------------------
29 ------------------------------------------------------------------------------------------------------------------ Beverly Monnet 43 2001 to present Vice President, Controller and Chief Accounting Officer Vice President, 1997 to 2001 Manager of Accounting ONEOK Resources Company Controller and Chief 1995 to 1997 Manager of Gas Accounting of Oklahoma Natural Gas Company Accounting Officer ------------------------------------------------------------------------------------------------------------------
(1) The Energy group includes the Gathering and Processing and Transportation and Storage segments. No family relationships exist between any of the executive officers nor any arrangement or understanding between any executive officer and any other person pursuant to which the officer was selected. 30 PART II. ITEM 5. MARKET PRICE AND DIVIDENDS ON THE REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS (A) MARKET INFORMATION The Company's 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 high and low sales prices of the Company's common stock for each fiscal quarter during the last two fiscal years were as follows: Years Ended December 31, 2001 December 31, 2000 ------------------------------------------------------------------------ High Low High Low ------------------------------------------------------------------------ First Quarter $ 24.34 $ 18.13 $ 13.78 $ 10.88 Second Quarter $ 22.50 $ 19.01 $ 15.07 $ 12.32 Third Quarter $ 20.48 $ 14.17 $ 19.89 $ 13.16 Fourth Quarter $ 18.40 $ 16.15 $ 25.28 $ 19.25 ------------------------------------------------------------------------ The high and low sales prices for the year ended December 31, 2000 and the first and second quarters for the year ended December 31, 2001 have been restated to give the effect of the 2001 two-for-one stock split. (B) HOLDERS There were 14,454 holders of the Company's common stock at March 8, 2002. (C) DIVIDENDS Quarterly dividends declared on the Company's common stock during the last two fiscal years were as follows: Years Ended December 31, December 31, 2001 2000 -------------------------------------------------------- First Quarter $ 0.155 $ 0.155 Second Quarter $ 0.155 $ 0.155 Third Quarter $ 0.155 $ 0.155 Fourth Quarter $ 0.155 $ 0.155 -------------------------------------------------------- The quarterly dividends for the year ended December 31, 2000 and the first and second quarters of the year ended December 31, 2001 have been restated to give the effect of the 2001 two-for-one stock split. Debt agreements pursuant to which the Company's outstanding long-term and short-term debt have been issued limit dividends and other distributions on the Company's common stock. Under the most restrictive of these provisions, $188.9 million of retained earnings is so restricted. On December 31, 2001, $226.6 million was available for dividends on the Company's common stock. The Company expects that comparable cash dividends will continue to be paid in the future. 31 ITEM 6. SELECTED FINANCIAL DATA Following are selected financial data for the Company for each of the last five years and the transition period. In accordance with a pronouncement of the Financial Accounting Standards Board's Staff at the Emerging Issues Task Force meeting in April 2001, codified as EITF Topic No. D-95 (Topic D-95), the Company revised its computation of earnings per common share (EPS). The Company restated the EPS amounts for all periods to be consistent with the revised methodology and to give effect of the two-for-one stock split in 2001. See Note Q of the Notes to the Consolidated Financial Statements.
Years Ended Years Ended December 31, August 31, ---------------------------- ------------------------------------------- 2001 2000 1999 1998 1997 ---------------------------------------------------------------------------------------------------------------------- (Millions of Dollars, except per share amounts) Operating revenues $ 6,803.1 $ 6,642.9 $ 1,838.9 $ 1,820.8 $ 1,161.6 Operating income $ 295.2 $ 333.9 $ 215.7 $ 188.8 $ 127.8 Net income $ 101.6 $ 145.6 $ 106.4 $ 101.8 $ 59.3 Total assets $ 5,879.2 $ 7,360.3 $ 3,024.9 $ 2,422.5 $ 1,237.4 Long-term debt $ 1,742.8 $ 1,350.7 $ 837.0 $ 329.3 $ 347.1 Basic earnings per share $ 0.85 $ 1.23 $ 0.86 $ 0.96 $ 1.07 Diluted earnings per share $ 0.85 $ 1.23 $ 0.86 $ 0.96 $ 1.07 Dividends per common share $ 0.62 $ 0.62 $ 0.62 $ 0.60 $ 0.60 Percent of payout 72.9% 50.4% 72.1% 62.5% 56.1% Ratio of earnings to fixed charges 2.01x 2.88x 4.06x 5.50x 3.51x Ratio of earnings to combined fixed charges and preferred stock dividend requirements 1.43x 1.93x 1.93x 2.52x 3.48x ----------------------------------------------------------------------------------------------------------------------
Four Months Ended December 31, 1999 1998 ---------------------------------------------------------------------------------------------- (Millions of Dollars, except per share amounts) Operating revenues $ 806.5 $ 580.7 Operating income $ 83.6 $ 68.1 Net income $ 35.3 $ 34.8 Total assets $ 3,241.2 $ 2,557.1 Long-term debt $ 800.7 $ 353.4 Basic earnings per share $ 0.27 $ 0.26 Diluted earnings per share $ 0.27 $ 0.26 Dividends per common share $ 0.155 $ 0.155 Percent of payout 57.4% 59.6% Ratio of earnings to fixed charges 2.98x 4.50x Ratio of earnings to combined fixed charges and preferred stock dividend requirements 1.76x 2.02x ----------------------------------------------------------------------------------------------
32 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Some of the statements contained and incorporated in this Form 10-K are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The forward-looking statements relate to the anticipated financial performance, management's plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in various circumstances. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements. Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of operations and other statements contained or incorporated in this Form 10-K identified by words such as "anticipate," "estimate," "expect," "intend," "believe," "projection" or "goal." You should not place undue reliance on the forward-looking statements. They are based on known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following: . the effects of weather and other natural phenomena on sales and prices; . increased competition from other energy suppliers as well as alternative forms of energy; . the capital intensive nature of the Company's business; . further deregulation, or "unbundling" of the natural gas business; . competitive changes in the natural gas gathering, transportation and storage business resulting from deregulation, or "unbundling," of the natural gas business; . the profitability of assets or businesses acquired by the Company; . risks of marketing, trading, and hedging activities as a result of changes in energy prices and credit worthiness of counterparties; . economic climate and growth in the geographic areas in which the Company does business; . the uncertainty of gas and oil reserve estimates; . the timing and extent of changes in commodity prices for natural gas, natural gas liquids, electricity, and crude oil; . the effects of changes in governmental policies and regulatory actions, including income taxes, environmental compliance, and authorized rates; . the results of litigation related to the Company's now terminated proposed acquisition of Southwest Gas Corporation (Southwest) or to the termination of the Company's merger agreement with Southwest; . the results of administrative proceedings and litigation involving the Oklahoma Corporation Commission and Kansas Corporation Commission; and . the other factors listed in the reports the Company has 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. 33 OPERATING ENVIRONMENT AND OUTLOOK The energy industry has undergone tremendous changes throughout the past decade. The Company's strategy has been and continues to be one of growth through acquiring assets that complement and strengthen each other, maximizing the earnings potential of existing assets through asset rationalization and consolidation and introducing regulatory initiatives that benefit the Company and its customers. The Company believes that the energy markets will continue to see deregulation, although it may be different than how certain markets have been deregulated to date. Furthermore, management believes that the natural gas and electricity markets will continue to converge and consolidate, while providing additional opportunities for growth. The Company also believes that demand for natural gas will increase due in part to the construction of a significant amount of gas-fired electric generating plants necessary to maintain adequate supply in the marketplace. The Company will continue to focus on enhancing the earnings potential of its existing assets through acquiring assets that grow the Company's operations into new market areas and complement its existing asset base. In 2001, the Company expanded its trading capabilities by marketing and trading energy from its 300 megawatt, gas-fired electric generating plant designed to capture the spark spread premium, which is the value added by converting natural gas to electricity, primarily during peak demand periods. OPERATING HIGHLIGHTS Acquisitions and Capital Expenditures - The Company increased its common ownership interest in Magnum Hunter Resources, Inc. (MHR) from approximately nine percent to over twenty-one percent in early 2001 through conversion of shares and redemption of MHR preferred stock owned by the Company to shares of MHR common stock as well as exercising warrants. As a result, the Company began accounting for the MHR investment using the equity method of accounting. In December, 2001, MHR and Prize Energy Corp. (Prize) announced plans to merge which will reduce the Company's ownership to approximately 11 percent. Assuming the merger is completed in 2002, the Company will begin accounting for the investment in MHR as an available for sale security and, accordingly, mark the investment to fair value through other comprehensive income. The MHR investment and related income is reported in the Other segment. During 2001, the Company completed construction of the $120 million Spring Creek Power Plant, located in Logan County, Oklahoma, and began operations in mid-2001. Four gas-powered turbines will provide electricity during peak demand periods. The Company spent approximately $42.3 million in 2001, $58.7 million in 2000, $13.4 million in the four months ended December 31, 1999 and $3.7 million in the year ended August 31, 1999 constructing the 300 megawatt plant In 2000, the Company made two significant asset acquisitions that greatly enhanced its Gathering and Processing, Transportation and Storage, and Marketing and Trading segments. The combined acquisitions included natural gas processing plants with a combined capacity of 1.6 Bcf/d, approximately 19,000 miles of gathering and transmission lines, natural gas storage facilities with a combined capacity of approximately 10 Bcf and contributed to a significant increase in trading. The acquisition of these assets demonstrates execution of the Company's strategy of growing through acquisition of assets that complement and strengthen each other. Regulatory- KGS was successful in obtaining temporary approval of weather normalization. KGS also obtained permanent approval of the WeatherProof Bill Program that had been a temporary program. The Company believes that the successful implementation of these initiatives and programs will reduce the impact of weather on earnings and customer bills. 34 The OCC issued an order denying ONG the right to collect $34.6 million in unrecovered gas costs incurred while serving customers during the 2000/2001 winter season. The Company appealed this order to the Oklahoma Supreme Court and asked the OCC to stay the provisions of this order pending the outcome of the Company's appeal. The OCC subsequently approved the Company's request to stay this order, which will allow ONG to collect the $34.6 million, subject to refund should the Company ultimately lose the case. Although the Company will continue to assert its legal rights, it is hopeful that a resolution of this issue can be negotiated. CRITICAL ACCOUNTING POLICIES AND ESTIMATES Our discussion and analysis of financial condition and operations are based on our consolidated financial statements, prepared in accordance with accounting principles generally accepted in the United States of America and contained within this report. Certain amounts included in or affecting our financial statements and related disclosure must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. Therefore, the reported amounts of our assets and liabilities, revenues and expenses and associated disclosures with respect to contingent assets and obligations are necessarily affected by these estimates. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. We believe that certain accounting policies are of more significance in our financial statement preparation process than others as discussed below. Energy Trading and Risk Management Activities - The Company engages in price risk management activities. As discussed in Note A of Notes to Consolidated Financial Statements under "Energy Trading and Risk Management Activities", energy trading contracts are accounted for using mark to market accounting. Forwards, swaps, options, and energy transportation and storage contracts utilized for trading activities are reflected at fair value as assets and liabilities from price risk management activities in the consolidated balance sheets. The fair value of these assets and liabilities are affected by the actual timing of settlements related to these contracts and current period changes resulting primarily from newly originated transactions and the impact of price movements. Changes in fair value are recognized in net revenues in the consolidated statement of income. Market prices used to fair value these assets and liabilities reflect management's best estimate considering various factors including closing exchange and over-the-counter quotations, time value and volatility underlying the commitments. Market prices are adjusted for the potential impact of liquidating the Company's position in an orderly manner over a reasonable period of time under present market conditions. For further information, see Note C of Notes to Consolidated Financial Statements. Regulation - The Company's intrastate transmission pipelines and distribution operations are subject to the rate regulation and accounting requirements of the OCC, KCC and TRC. Certain other transportation activities of the Company are subject to regulation by the FERC. Allocation of costs and revenues to accounting periods for rate-making and regulatory purposes may differ from bases generally applied by non-regulated operations. Such allocations to meet regulatory accounting requirements are considered to be generally accepted accounting principles for regulated utilities provided that there is a demonstrable ability to recover any deferred costs in future rates. During the rate-making process, regulatory commissions may require a utility to defer recognition of certain costs to be recovered through rates over time as opposed to expensing such costs as incurred. This allows the utility to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. This causes certain expenses to be deferred as a regulatory asset and amortized to expense as they are recovered through rates. Although no further unbundling of services is anticipated, should this occur, certain of these assets may no longer meet the criteria for deferred recognition and, accordingly, a write-off of regulatory assets and stranded costs may be required. 35 Impairments - The Company assesses for impairment of long-lived assets when indicators of impairment are present. An impairment is recognized if the undiscounted cash flows are not sufficient to recover the assets carrying amount. Impairment loss is measured by comparing the fair value of the asset to its carrying amount. Fair values are based on discounted future cash flows or information provided by sales and purchases of similar assets. See further discussion of the Company's significant accounting policies in Note A of Notes to the Consolidated Financial Statements. CONSOLIDATED OPERATIONS
Years Ended Year Ended December 31, August 31, 2001 2000 1999 ------------------------------------------------------------------------------------------------------------- Financial Results (Thousands of Dollars) Operating revenues $ 6,803,146 $ 6,642,858 $ 1,838,949 Cost of gas 5,894,361 5,845,726 1,213,478 ------------------------------------------------------------------------------------------------------------- Net revenues 908,785 797,132 625,471 Operating costs 456,243 319,848 280,045 Depreciation, depletion, and amortization 157,310 143,351 129,704 ------------------------------------------------------------------------------------------------------------- Operating income $ 295,232 $ 333,933 $ 215,722 ============================================================================================================= Other income, net $ 876 $ 18,475 $ 10,500 ============================================================================================================= Cumulative effect of a change in accounting principle $ (3,508) $ 3,449 $ - Income tax 1,357 (1,334) - ------------------------------------------------------------------------------------------------------------- Cumulative effect of a change in accounting principle, net of tax $ (2,151) $ 2,115 $ - =============================================================================================================
Operating Results - A full year of operations of the assets acquired in March and April of 2000 contributed to increased net revenues, despite lower energy prices in the latter part of 2001, and increased operating costs and depreciation, depletion and amortization. The Company's ability to successfully execute its transportation and storage arbitrage strategy also continued to favorably impact operating results. The impact of the OCC ruling related to the recovery of gas costs from the 2000/2001 winter reduced operating income by $34.6 million and the impact of the Enron bankruptcy reduced operating income by $37.4 million in 2001. The Company is pursuing all opportunities to settle the OCC matter. Included in Other income, net for 2001 is $8.1 million in income from equity investments including MHR and $3.7 million of ongoing litigation costs associated with the terminated acquisition of Southwest Gas Corporation. The reduction in the effective tax rate for 2001 is the result of changes in estimates of prior year tax liabilities recorded in the third quarter. The Company's operating results during 2000 increased compared to 1999 due to the acquisitions, greater price volatility in the U.S. natural gas markets, adoption of mark-to-market accounting for its trading activities, and higher natural gas and natural gas liquids prices. Operating costs and depreciation, depletion, and amortization increased primarily due to the acquisitions. Included in Other income, net for 2000 is the $26.7 million gain on the sale of Indian Basin, $13.4 million in income from equity investments and preferred dividends received and $13.7 million of previously deferred transaction and ongoing litigation costs associated with the terminated acquisition of Southwest Gas Corporation. Interest expense increased in 2001 compared to 2000 as a result of increased debt primarily due to financing of acquisitions and increased working capital including unrecovered purchased gas costs. The Company has interest rate swaps in place that reduced interest expense by $5.3 million in 2001 from what the expense would have been with fixed interest rates. See Note C in the Notes of Consolidated Financial Statements for further discussion of interest rate swaps. 36 Transition Period Operating Results Four Months Ended December 31, 1999 1998 ----------------------------------------------------------------------- Financial Results (Thousands of Dollars) Operating revenues $ 806,478 $ 580,701 Cost of gas 587,681 384,682 ----------------------------------------------------------------------- Net revenues 218,797 196,019 Operating costs 92,002 86,145 Depreciation, depletion, and amortization 43,227 41,736 ----------------------------------------------------------------------- Operating income $ 83,568 $ 68,138 ======================================================================= Other income,net $ 2,396 $ 4,993 ======================================================================= Operating results were strong despite warmer than normal weather. While the four month periods ended December 31, 1999 and 1998 were both warmer than normal, the Company used derivative instruments for the 1999/2000 heating season to reduce the effect of weather variances. During the Transition Period, these derivative instruments offset much of the margin variances caused by weather. This revenue was recorded in the Other segment. The operations from the assets acquired in 1999 also favorably impacted operating results. Increased borrowing, primarily due to acquisitions in fiscal 1999, resulted in increased interest expense for the four months ended December 31, 1999. Gains on sales of assets of $5.0 million were included in Other Income during the four month period ended December 31, 1998. MARKETING AND TRADING Operational Highlights - The Company's marketing and trading operation purchases, stores, markets, and trades natural gas to both the wholesale and retail sectors in 28 states. The Company has mid-continent region storage positions and transport capacity of 1 Bcf/d that allows for trade from the California border, throughout the Rockies, to the Chicago city gate. With total storage capacity of 73 Bcf, withdrawal capability of 2.1 Bcf/d and injection capability of 1.4 Bcf/d, the Company has direct access to all regions of the country with great flexibility in capturing margins associated with price volatility in the energy markets. The Company continues to enhance its strategy of focusing on higher margin business which includes providing reliable service during peak demand periods through the use of storage. 37
Years Ended Year Ended December 31, August 31, 2001 2000 1999 ---------------------------------------------------------------------------------------------------------------------- Financial Results (Thousands of Dollars) Gas sales $ 4,906,556 $ 4,658,787 $ 821,890 Cost of gas 4,804,795 4,595,199 789,955 ---------------------------------------------------------------------------------------------------------------------- Gross margin on gas sales 101,761 63,588 31,935 Other revenues 1,668 2,894 3,508 ---------------------------------------------------------------------------------------------------------------------- Net revenues 103,429 66,482 35,443 Operating costs 31,488 14,321 9,069 Depreciation, depletion, and amortization 597 887 503 ---------------------------------------------------------------------------------------------------------------------- Operating income $ 71,344 $ 51,274 $ 25,871 ====================================================================================================================== Other income, net $ 259 $ - $ - ====================================================================================================================== Cumulative effect of a change in accounting principle $ - $ 3,449 $ - Income tax - (1,334) - ---------------------------------------------------------------------------------------------------------------------- Cumulative effect of a change in accounting principle, net of tax $ - $ 2,115 $ - ======================================================================================================================
Operating Results - The increase in Marketing and Trading's gross margins on gas sales in 2001 compared to 2000 is attributable to its ability to capture higher margins by arbitraging regional price volatility through the use of its storage and transportation capacity. The Company was also able to capture wider winter/summer spreads on stored volumes and benefited from falling prices that positively impacted fuel costs associated with its long-term transportation contracts while sales volumes decreased slightly. The Company's gross margin included income recognized from mark-to-market accounting of approximately $35 million and $24 million for 2001 and 2000, respectively. Increased operating costs are due primarily to increased personnel costs required to operate the expanded base of marketing and trading activities acquired in 2000. Also, the Enron bankruptcy resulted in a $22.9 million increase in cost of gas and a $14.5 million increase in operating costs, totaling a $37.4 million negative impact on operating results for 2001. The Company's claim against Enron in bankruptcy is estimated to be $74.0 million. The increase in gross margins on gas sales in 2000 compared to 1999 is primarily attributable to the increased volumes achieved through the acquisition in 2000. The acquisition significantly increased the segment's commercial control of storage and transportation positions, primarily in the mid-continent, Rocky Mountain and Texas regions, thereby providing more leverage for its marketing and trading capabilities. Increased price volatility during 2000 compared to 1999 also contributed to increased gross margin on gas sales by providing greater marketing and trading opportunities. Gross margin on gas sales was also favorably impacted by the change in accounting principle requiring the Marketing and Trading segment to mark energy trading contracts to fair value. Increased operating costs in 2000 compared to 1999 are primarily attributable to increased personnel costs resulting from the acquisition coupled with increases in overall personnel to support the expanded base of marketing and trading activities. Operating costs also increased due to higher costs relating to technological enhancements necessary to support these activities. 38 Years Ended Year Ended December 31, August 31, 2001 2000 1999 --------------------------------------------------------------------------- Operating Information Natural gas volumes (MMcf) 977,602 990,033 389,241 Gross margin ($/Mcf) $ 0.10 $ 0.06 $ 0.08 Capital expenditures (Thousands) $ 1,184 $ 815 $ 448 Total assets (Thousands) $ 1,369,220 $ 3,035,227 $ 269,444 --------------------------------------------------------------------------- Marketing and Trading sales volumes averaged 2.7 Bcf/d in 2001 and 2000 and 1.1 Bcf/d in 1999. The increase in sales volumes compared to 1999 is primarily due to the acquisition in 2000 and increased trading activity around the Company's increased storage and transportation capacity. Gross margin per Mcf improved in 2001 compared to 2000 as the Company has now fully integrated its mid-continent marketing and trading base and is successfully executing its strategies for transportation and use of storage that focus on capturing higher margin sales. Gross margin per Mcf decreased in 2000 compared to 1999 as a result of higher baseload sales resulting from the acquisition of marketing and trading operations in 2000. The Company has since integrated those acquired contracts that complement its business strategy while terminating those contracts that do not. The decrease in total assets at December 31, 2001 compared to 2000 is primarily attributable to a decrease of $823.3 million in accounts receivable and a decrease of $782.4 million in price risk management assets which represent the fair value of the Company's commodity and derivative trading contracts and storage inventory. Both were the result of decreased natural gas prices. The increase in total assets at December 31, 2000, compared to 1999 is primarily attributable to $1.8 billion in price risk management assets and a $1.0 billion increase in accounts receivable due to increased marketing and trading activities and increased natural gas prices. Transition Period Operating Results Four months ended December 31, 1999 1998 ------------------------------------------------------------------------ Financial Results (Thousands of Dollars) Gas sales $ 382,650 243,776 Cost of gas 371,556 233,810 ------------------------------------------------------------------------ Gross margin on gas sales 11,094 9,966 Other revenues 399 2,470 ------------------------------------------------------------------------ Net revenues 11,493 12,436 Operating costs 3,344 2,730 Depreciation, depletion, and amortization 242 103 ------------------------------------------------------------------------ Operating income $ 7,907 $ 9,603 ======================================================================== The increase in gross margin is attributable to increased throughput and a more extensive use of storage. The use of storage has allowed the Company to concentrate on the day-to-day market and take advantage of volatility in that market. Emphasis on base load market had been reduced. Increased sales volumes are primarily due to the expanded niche business into Texas and the west coast. The decrease in Other revenues is due to the recovery of prior period costs in the four months ended December 31, 1998. The increase in operating costs is related to leasing storage. 39 Four months ended December 31, 1999 1998 ---------------------------------------------------------------- Operating Information Natural gas volumes (MMcf) 138,070 116,309 Gross margin ($/Mcf) $ 0.08 $ 0.08 Capital expenditures (Thousands) $ 9 $ 605 Total assets (Thousands) $ 287,375 $ 141,733 ---------------------------------------------------------------- Price Risk Management - To mitigate the financial risks arising from fluctuations in both the market price and transportation costs of natural gas, OEMT manages its portfolio of contracts and the Company's assets in order to maximize value, minimize the associated risks and provide overall liquidity. In doing so, OEMT uses 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 C of Notes to Consolidated Financial Statements. GATHERING AND PROCESSING Operational Highlights - The Gathering and Processing segment currently owns and operates or leases and operates 25 gas processing plants and has an ownership interest in four additional gas processing plants which it does not operate. Six operated plants are temporarily idle. The total processing capacity of plants operated and the Company's proportionate interest in plants not operated by the Company is 2.2 Bcf/d, of which 0.150 Bcf/d has been idled temporarily. A total of over 19,300 miles of gathering pipelines support the gas processing plants.
Years Ended Year Ended December 31, August 31, 2001 2000 1999 ------------------------------------------------------------------------------------------------------------------------ Financial Results (Thousands of Dollars) Natural gas liquids and condensate sales $ 587,842 $ 536,470 $ 52,757 Gas sales 635,569 426,364 23,032 Gathering, compression, dehydration and processing fees and other revenues 91,406 73,879 8,001 Cost of Sales 1,125,196 812,701 52,479 ------------------------------------------------------------------------------------------------------------------------ Net revenues 189,621 224,012 31,311 Operating costs 116,853 90,501 11,207 Depreciation, depletion, and amortization 29,201 22,692 3,562 ------------------------------------------------------------------------------------------------------------------------ Operating income $ 43,567 $ 110,819 $ 16,542 ======================================================================================================================== Other income, net $ (178) $ 26,460 $ ========================================================================================================================
Operating Results - A full year of operation of assets acquired in early 2000 contributed to increased revenues and cost of sales for 2001 compared to 2000. However, decreased processing spreads and lower natural gas prices resulted in lower net revenues for 2001. In the first quarter of 2001, there were negative processing spreads for the first time in more than 10 years and inter-month volatility during the year was the greatest it has been at any time during that same 10-year period. The overall processing spread for 2001 was approximately 75% of the 10-year average of $1.29 per MMBtu. During the year, both crude oil and natural gas prices fell from $29.33 per barrel and $9.98 per MMBtu to $18.00 per barrel and $1.83 per MMBtu, respectively. The downturn of the economy reduced the demand for many NGL products, particularly ethane, which is a major component of plastic products. Additionally, record high inventories in natural gas and other petroleum products, such as propane, along with significantly warmer than normal temperatures across North America during the heating season lowered demand for natural gas, home heating oil and propane causing weaker than expected prices in 2001. 40 Increased operating costs and depreciation, depletion, and amortization were also the result of a full year of operation for the assets acquired. Net revenues increased in 2000 compared to 1999 due to the assets acquired in early 2000 and a full year of operation of assets acquired in early 1999. The average NGL price per gallon increased significantly in 2000. Fee-based revenues increased in 2000 compared to 1999 as a result of the acquisitions in 2000. Operating costs and depreciation, depletion and amortization increased for 2000 compared to 1999 as a result of the acquisitions and the related goodwill. The increase in operating costs is primarily attributable to increased personnel and related benefit costs resulting from the additional employees gained through the acquisitions and additional lease expense resulting from the Bushton lease, which was acquired from KMI in 2000. Other income for 2000 consists of the gain on the sale of the Company's interest in the Indian Basin processing plant.
Years Ended Year Ended December 31, August 31, 2001 2000 1999 ------------------------------------------------------------------------------------------ Gas Processing Plants Operating Information Total gas gathered (MMMBtu/D) 1,572 1,329 229 Total gas processed (MMMBtu/D) 1,420 1,206 187 Natural gas liquids sales (MBbls) 27,719 23,984 4,559 Natural gas liquids produced (Bbls/d) 74,238 68,999 7,642 Gas sales (MMBtu) 142,828 115,180 10,534 Capital expenditures (Thousands) $ 51,442 $ 32,383 $ 8,557 Total assets (Thousands) $ 1,322,438 $ 1,507,546 $ 343,133 ------------------------------------------------------------------------------------------
Volumes of natural gas gathered and processed, NGL sales, NGLs produced and gas sales increased for 2001 compared to 2000 primarily due to a full year of operations of the assets acquired in 2000, which provided increased processing and fractionation capacity. Average NGL prices for 2001 decreased compared to 2000, which offset the impact of the increased volumes. The Conway OPIS composite NGL price based on the Company's NGL product mix for 2001 decreased 12 percent from $0.531/gal to $0.465/gal. Average natural gas prices increased for the same period despite decreases during the last half of 2001. The gas price for the mid-continent region increased 11 percent in 2001 from an average of $3.74/MMBtu to an average of $4.15/MMBtu. For 2000, the increase over 1999 for total gas gathered, gas processed, NGL sales, NGLs produced and gas sales is primarily due to the acquisitions in early 2000 and a full year of operations from the acquisition in April 1999. The increase in capital expenditures from 2000 to 2001 and from 1999 to 2000 is primarily due to the acquisitions. Additional increases in 2000 and 2001 are related to the Company consolidating its plants in Texas to lower operating costs and optimize recoveries. The decrease in total assets from 2000 to 2001 is due to decreases in cash and accounts receivable due to decreased prices. The increase in total assets from 1999 to 2000 is primarily attributable to a $619.3 million increase in property, plant and equipment acquired in the 2000 acquisitions and a $99.1 million increase in accounts receivable. The increase in accounts receivable is due to both increased business and increased prices. Risk Management - At December 31, 2001, the Gathering and Processing segment had a portion of its natural gas costs and NGL production hedged. The Company also used derivative instruments during 2001 to minimize risk associated with price volatility and expects to utilize such instruments during 2002. See Item 7A - Quantitative and Qualitative Disclosures About Market Risk and Note C of Notes to Consolidated Financial Statements. 41 Transition Period Operating Results
Four Months Ended December 31, 1999 1998 -------------------------------------------------------------------------------------------------- Financial Results (Thousands of Dollars) Natural gas liquids and condensate sales $ 43,290 $ 8,951 Gas sales 28,824 4,157 Gathering, compression, dehydration and processing fees and other revenues 6,787 1,398 Cost of sales 59,488 8,388 -------------------------------------------------------------------------------------------------- Net revenues 19,413 6,118 Operating costs 8,588 2,262 Depreciation, depletion, and amortization 2,513 681 -------------------------------------------------------------------------------------------------- Operating income $ 8,312 $ 3,175 ==================================================================================================
Revenues increased in the Transition Period over the same period in 1998 due to the acquisition of the midstream natural gas gathering and processing assets in April 1999. Operating costs and depreciation also increased due to the additional assets and the cost of operating those assets. Average NGL price per gallon increased as prices continued to experience an upward correction from the abnormally low prices prevalent throughout much of 1998 and early 1999. Four Months Ended December 31, 1999 1998 ---------------------------------------------------------------------- Gas Processing Plants Operating Information Total gas gathered (MMMBtu/D) 481 127 Total gas processed (MMMBtu/D) 397 115 Natural gas liquids sales (MBbls) 3,007 927 Natural gas liquids produced (Bbls/d) 7,022 7,642 Gas sales (MMBtu) 10,643 2,303 Capital expenditures (Thousands) $ 14,613 $ 974 Total assets (Thousands) $ 368,904 $45,709 ---------------------------------------------------------------------- TRANSPORTATION AND STORAGE Operational Highlights - The Transportation and Storage segment represents the Company's intrastate transmission pipelines and natural gas storage facilities. The Company has five storage facilities in Oklahoma, two in Kansas and three in Texas with a combined working capacity of approximately 58 Bcf, of which 8 Bcf is idled. The Company's intrastate transmission pipelines operate in Oklahoma, Kansas and Texas and are regulated by the OCC, KCC and TRC, respectively. 42
Years Ended Year Ended December 31, August 31, 2001 2000 1999 -------------------------------------------------------------------------------------- Financial Results (Thousands of Dollars) Transportation revenues $ 117,999 $ 94,112 $ 78,720 Storage revenues 37,645 38,464 27,763 Gas sales and other revenues 23,326 35,882 1,402 Cost of fuel and gas 49,626 42,876 4,975 -------------------------------------------------------------------------------------- Net revenues 129,344 125,582 102,910 Operating costs 52,497 44,785 28,919 Depreciation, depletion, and amortization 19,190 18,639 13,852 -------------------------------------------------------------------------------------- Operating income $ 57,657 $ 62,158 $ 60,139 ====================================================================================== Other income, net $ 2,578 $ 3,240 $ 6,495 ======================================================================================
Operating results -Transportation revenues increased for 2001 compared to 2000 due to higher retained fuel from a full year of operation of assets acquired in early 2000. This increase was partially offset by a reduction in volumes transported associated with reduced demand for irrigation due to higher natural gas prices, making gas-powered irrigation uneconomical for many farmers, and warmer than normal temperatures during the fourth quarter of 2001. The expiration of gas sales contracts acquired in early 2000 resulted in a decrease of $4.6 million in gas sales revenue in 2001. While revenues from unaffiliated companies decreased as gas sales contracts expired, revenues from transportation contracts replaced the margin generated by those expired gas sales contracts. The increase in cost of fuel in 2001 compared to 2000 is due to a full year of operation of the assets acquired in 2000 and increased gas prices. Operating costs increased due to higher ad valorem taxes, labor and other operating costs associated with a full year of operation of the assets acquired in 2000. Depreciation, depletion and amortization also increased in 2001 due to the 2000 acquisitions. For 2000 compared to 1999, transportation revenues increased due to higher retained fuel despite reduced tariff rates paid by an affiliate for transportation services. Storage revenues increased due to increased capacity of approximately 10 Bcf resulting from the acquisition of storage facilities in 2000. Although storage revenues increased due to the acquisition, overall storage volumes as a percent of working capacity were down significantly because summer/winter pricing differentials were lower than in prior years. Gas sales and other revenues and cost of gas increased due to gas sales contracts acquired in 2000 and leasing fees related to a pipeline acquired in 2000. Operating costs and depreciation, depletion, and amortization increased in 2000 compared to 1999 primarily as a result of increased plant operating costs and personnel costs resulting from acquisitions. Other income, net represents income from equity investments in Potato Hills and Sycamore Gathering. In 1999, approximately $5.0 million of gains on sales of assets were also included. Years Ended Year Ended December 31, August 31, 2001 2000 1999 -------------------------------------------------------------------------- Operating Information Volumes transported (MMcf) 538,221 557,052 348,397 Capital expenditures (Thousands) $ 35,911 $ 37,701 $ 32,618 Total assets (Thousands) $ 797,331 $ 661,894 $ 373,742 -------------------------------------------------------------------------- Volumes of natural gas transported decreased in 2001 due a return to normal weather as compared to 2000. This decrease was partially offset by an increase in volumes transported due to operating the assets acquired in 2000 for a full year. The increase in volumes transported in 2000 compared to 1999 was primarily driven by the acquisitions in 2000 and colder weather. 43 Total assets increased in 2001 due to increases in cash and accounts receivables. Total assets increased in 2000 due to increases in property, plant and equipment and in accounts receivable primarily due to the acquisitions. Regulatory Initiatives - In a May 2000 OCC Order, the Company's transportation assets in Oklahoma included in the Transportation and Storage segment became a separate regulated utility from the Distribution segment. Pursuant to a July 1999 OCC Order, the Company's gathering and storage assets and related services in Oklahoma were removed from utility regulation effective November 1, 1999 resulting in gathering and storage assets being removed from rate base. ONG issued bids for upstream and downstream services in the fall of 1999 with bids awarded in the spring of 2000. Through the bidding process, the Transportation and Storage segment retained 96 percent of ONG's transportation services. With unbundling of transportation services and deregulation of gathering and storage, the Company is now competing for business at market-based rates. During 2001, an OCC cause related to an affiliate, ONG, also involved the Marketing and Trading segment and the Transportation and Storage segment. In this cause, Enogex, Inc. requested a rebid of gas supply and transportation service. If OEMT had lost the gas supply bid previously awarded, OEMT would no longer need companies in the Transportation and Storage segment to transport the gas supply. The OCC declined to order a rebid. An application has been filed with the KCC requesting approval to transfer a portion of the transportation assets in the Market Center to KGS. The operation of these assets is regulated by the KCC. The Market Center transportation system provides access to the major natural gas producing areas in Kansas intersecting with nine intra/interstate pipelines at 18 interconnect points, four processing plants, and approximately three producing fields effectively allowing gas to be moved throughout the state. With the transfer of these assets, KGS will be able to provide itself with firm transportation service. Transition Period Operating Results Four Months Ended December 31, 1999 1998 ----------------------------------------------------------------------- Financial Results (Thousands of Dollars) Transportation revenues $ 24,733 $ 25,956 Storage revenues 14,171 9,099 Gas sales and other revenues 247 942 Cost of fuel and gas 4,660 2,047 ----------------------------------------------------------------------- Net revenues 34,491 33,950 Operating costs 10,184 10,963 Depreciation, depletion, and amortization 5,124 4,554 ----------------------------------------------------------------------- Operating income $ 19,183 $ 18,433 ======================================================================= Other income, net $ 1,074 $ 4,993 ======================================================================= The Company's strategy to increase its storage utilization through greater injection and withdrawal capabilities has resulted in increased storage revenues for the Transition Period compared to the same period in 1998 as well as increased compressor fuel expense. Decreased transportation rates paid by an affiliate resulted in decreased transportation revenues for the Transition Period compared to the same period in 1998. 44 Four Months Ended, December 31, 1999 1998 -------------------------------------------------------------- Operating Information Volumes transported (MMcf) 117,055 115,970 Capital expenditures (Thousands) $ 5,837 $ 13,163 Total assets (Thousands) $ 437,561 $ 507,573 -------------------------------------------------------------- DISTRIBUTION Operational Highlights - The Distribution segment provides natural gas distribution services in Oklahoma and Kansas. The Company's operations in Oklahoma are conducted through ONG that serves residential, commercial, and industrial customers and leases pipeline capacity. The Company's operations in Kansas are conducted through KGS that serves residential, commercial, and industrial customers. The Distribution segment serves about 80 percent of the population of Oklahoma and about 71 percent of the population of Kansas. ONG and KGS are subject to regulatory oversight by the OCC and KCC, respectively.
Years Ended Year Ended December 31, August 31, 2001 2000 1999 ------------------------------------------------------------------------------------------- Financial Results (Thousands of Dollars) Gas sales $ 1,434,184 $ 1,198,604 $ 848,813 Cost of gas 1,157,575 896,660 530,489 ------------------------------------------------------------------------------------------- Gross margin 276,609 301,944 318,324 PCL and ECT Revenues 55,206 59,205 58,037 Other revenues 21,578 16,128 17,100 ------------------------------------------------------------------------------------------- Net revenues 353,393 377,277 393,461 Operating costs 230,137 211,629 219,945 Depreciation, depletion, and amortization 69,159 67,717 75,443 ------------------------------------------------------------------------------------------- Operating income $ 54,097 $ 97,931 $ 98,073 =========================================================================================== Other income, net $ (946) $ - $ - ===========================================================================================
Operating Results - Gas sales and cost of gas increased in 2001 compared to 2000 due to a higher weighted average cost of gas. Although prices of natural gas decreased in the latter part of 2001 from their historically high levels during the winter of 2000/2001, those costs were still billed and recovered throughout most of 2001. Since gas costs are recognized as they are recovered from the ratepayer, the mechanism providing recovery of gas costs and regulatory actions in Oklahoma delayed much of the recovery of high gas costs in late 2000 until 2001 and, accordingly, delayed recognition of the costs. In the fourth quarter of 2001, the Company recorded a $34.6 million charge to cost of gas as a result of the OCC's order limiting ONG's recovery of gas purchase expense related to the 2000/2001 winter. This resulted in a decrease in gross margin on gas sales in 2001 compared to 2000. KGS gross margin increased $3.0 million in 2001 over 2000 due to impact of the Weather Normalization Program offsetting the warmer weather. ECT revenues decreased $3.4 million in 2001 from 2000 due largely to lower volumes delivered to electric generation customers due to milder summer weather. Gross margin on gas sales decreased in 2000 compared to fiscal 1999, primarily due to warmer weather in Kansas which impacted margins by $15.4 million during a period in which the Company did not have weather normalization and reduced tariff rates resulting from unbundling in Oklahoma. The impact of these decreases on gross margin was partially offset by $5.3 million resulting from additional "As Available" gas sales. 45 Operating cost for 2001 increased over 2000 due to additional bad debt expense of $19.2 million incurred as a result of the increased natural gas prices during the winter of 2000/2001. This was partially offset by a reduction in operating costs due to the continuation of a successful cost containment program. The decrease in operating costs in 2000 compared to 1999 resulted from a cost containment program and decreased costs resulting from fewer employees. The decrease in depreciation, depletion, and amortization is the result of the extension of estimated useful lives for assets located in Oklahoma. The revised estimated lives were approved by the OCC in a rate order granted in May 2000 that reduced depreciation expense and revenues by approximately $10.5 million annually for Oklahoma assets and transferred certain transportation assets from the Distribution segment to the Transportation and Storage segment. The same order directed ONG to assume responsibility for certain customer service lines and allowed ONG to defer the costs associated with the service lines until addressed in the next rate case filing. Years Ended Year Ended December 31, August 31, 2001 2000 1999 -------------------------------------------------------------- Gross Margin per Mcf Oklahoma Residential $2.71 $2.76 $3.04 Commercial $2.18 $1.97 $2.47 Industrial $1.34 $1.09 $1.23 Pipeline capacity leases $0.30 $0.27 $0.25 Kansas Residential $2.45 $2.44 $2.44 Commercial $1.82 $1.91 $1.81 Industrial $1.43 $1.85 $2.28 End-use customer transportation $0.61 $0.63 $0.49 -------------------------------------------------------------- The decrease in Kansas' commercial and industrial gross margins per Mcf for 2001 from 2000 results from the full year impact of the tariff rate reduction that took effect in July 2000. Oklahoma's gross margin per Mcf increased for commercial and industrial due to adjustments to gas purchase expense and a deferral of revenues from a line loss rider from 2000 to 2001. A full year of tariff rate reductions in 2001 partially offset this increase and resulted in a decrease to gross margin per Mcf for residential. The decrease in Oklahoma's gross margin per Mcf for residential, commercial and industrial customers in 2000 compared to 1999 is primarily due to decreased tariff rates resulting from unbundling in Oklahoma. The increase in Kansas' gross margin per Mcf for commercial customers is largely due to the Company reducing its minimum capacity requirements for customers to become eligible for ECT services pursuant to a regulatory order. This resulted in several commercial customers becoming ECT customers and the remaining commercial customers are low volume, high margin customers. The decrease in Kansas' industrial gross margin per Mcf is primarily due to a tariff rate reduction. 46
Years Ended Year Ended December 31, August 31, 2001 2000 1999 --------------------------------------------------------------------------------------- Operating Information Average Number of Customers Oklahoma 794,008 784,746 748,445 Kansas 642,436 633,698 656,761 --------------------------------------------------------------------------------------- Total 1,436,444 1,418,444 1,405,206 ======================================================================================= Customers per employee Oklahoma 639 586 546 Kansas 579 555 510 ======================================================================================= Capital Expenditures (Thousands) $ 129,937 $ 124,983 $ 98,685 ======================================================================================= Total Assets (Thousands) $ 1,688,670 $ 2,007,351 $ 1,722,381 =======================================================================================
The consolidation of the KGS-Oklahoma regulated service with ONG in 2000 resulted in the transfer of approximately 35,000 customers from Kansas to Oklahoma. The Company's capital expenditure program includes expenditures for extending service to new areas, modifying customer service lines, increasing system capabilities, and general replacements and betterments. It is the Company's practice to maintain and periodically upgrade facilities to assure safe, reliable, and efficient operations. The capital expenditure program included $22.4 million, $21.4 million, and $19.8 million for new business development in 2001, 2000, and 1999, respectively. Years Ended Year ended December 31, August 31, 2001 2000 1999 --------------------------------------------------------------------- Volumes (MMcf) Gas sales Residential 102,976 107,154 105,566 Commercial 40,578 40,713 41,398 Industrial 4,101 5,582 5,575 Wholesale 31,060 34,781 34,846 --------------------------------------------------------------------- Total volumes sold 178,715 188,230 187,385 PCL and ECT 136,975 158,100 177,701 --------------------------------------------------------------------- Total volumes delivered 315,690 346,330 365,086 ==================================================================== The decrease in volumes sold is due to warmer weather in 2001 compared to 2000 and, for industrial and wholesale sales, the movement of some customers to the PCL program. The decrease in PCL and ECT volumes is primarily due to some customers that use significant quantities of gas in their manufacturing process suspending manufacturing operations in late 2000 and early 2001 due to historically high natural gas prices. These decreases were partially offset by the Company reducing its minimum capacity requirements for customers to become eligible for PCL and ECT services pursuant to a regulatory order. The reduction of the minimum requirements allowed more low volume customers to be added to the customer base. Regulatory Initiatives -The extraordinarily cold winter of 2000/2001 produced a number of regulatory initiatives. The OCC issued an order denying ONG the right to collect $34.6 million in outstanding gas costs incurred while serving customers during the 2000/2001 winter season. The Company appealed this order to the Oklahoma Supreme Court and asked the OCC to stay the provisions of this order pending the outcome of the Company's appeal. The OCC subsequently approved the Company's request to stay this order allowing ONG to collect the $34.6 million, subject to refund should the Company ultimately lose the case. ONEOK took a charge against fourth-quarter earnings as a result of the Commission's order. Although the Company will continue to assert its legal rights, it is hopeful that a resolution of this issue can be negotiated. 47 ONG continues to take an active role in response to the OCC's Notice of Inquiry regarding the use of physical and financial instruments to hedge against fuel procurement volatility. ONG exercised provisions contained in a number of its gas supply contracts that allow the Company to fix the price of a portion of its gas supply. ONG fixed the price of approximately 40% of its anticipated 2001/2002 winter gas supply deliveries. The Company received approval from the OCC to create a Voluntary Fixed Price pilot program that will enable its general sales customers to fix the gas cost portion of their bill for a specified winter period. The program is being initiated as a means of providing customers with a means of controlling their 2002/2003 gas bills. During 2001, the KCC issued an Order extending the time period for which gas service disconnection during inclement weather conditions cannot be made. Due to the extension of the time period restricting disconnections, delinquent KGS customers were allowed to continue gas service, thus increasing uncollectible amounts. Higher gas costs in the 2000/2001 heating season also contributed to the increased uncollectible amounts. KGS and other distribution companies in Kansas filed a joint application with the KCC seeking approval to recover the additional uncollectible amounts incurred during the 2000/2001 heating season until reviewed in the next rate case. The KCC approved the deferral allowing the companies to seek recovery of the extraordinary uncollectible account levels experienced in the 2000/2001 winter. KGS expects to file a rate case in late 2002. No accounting treatment has yet been determined. During 2000, the KCC issued an Order allowing KGS to recover additional costs of its gas purchase hedging program established to protect the price paid by customers for gas purchases. The KCC approved KGS's WeatherProof Bill Program that had been a temporary program. This plan allows customers, at their discretion, to fix their monthly payment. The KCC also granted KGS weather normalization in December 2000 that prevents weather related revenue fluctuations. Transition Period Operating Results Four Months Ended December 31, 1999 1998 ---------------------------------------------------------------------------- Financial Results (Thousands of Dollars) Gas sales $ 316,901 $ 286,317 Cost of gas 209,354 180,795 ---------------------------------------------------------------------------- Gross margin 107,547 105,522 PCL and ECT revenues 18,230 19,582 Other revenues 4,093 4,554 ---------------------------------------------------------------------------- Net revenues 129,870 129,658 Operating costs 69,455 73,004 Depreciation, depletion, and amortization 24,815 24,603 ---------------------------------------------------------------------------- Operating income $ 35,600 $ 32,051 ============================================================================ Gross margins on gas sales increased primarily due to reduced transportation costs paid to an affiliate. A reduction in revenues due to the gathering and storage assets being removed from rate base, as previously discussed, offset part of that increase. PCL and ECT revenues and volumes decreased primarily due to the loss of three customers and the effect of warm weather including the temporary shut-down of two power plants served by the Distribution segment. The volume decrease was partially offset by an increase in rates. Operating costs decreased due to reductions in labor expense, employee benefits, and other operating efficiencies. The Distribution segment continues its strategy of increased operational efficiency while maintaining quality customer service. 48 Four Months Ended December 31, 1999 1998 --------------------------------------------------------------- Gross Margin per Mcf Oklahoma Residential $2.88 $2.96 Commercial $2.48 $2.51 Industrial $1.16 $1.27 Pipeline capacity leases $0.25 $0.23 Kansas Residential $2.76 $2.85 Commercial $2.07 $1.86 Industrial $1.97 $2.70 End-use customer transportation $0.60 $0.48 --------------------------------------------------------------- Four Months Ended December 31, 1999 1998 --------------------------------------------------------------- Operating Information Number of customers 1,435,647 1,421,280 Customers per employee 546 527 Capital expenditures (Thousands) $ 34,167 $ 24,636 Total assets (Thousands) $ 1,776,273 $ 1,804,631 --------------------------------------------------------------- Four Months Ended December 31, 1999 1998 --------------------------------------------------------------- Volumes (MMcf) Gas sales Residential 31,908 31,244 Commercial 11,415 12,005 Industrial 1,795 1,684 Wholesale 12,062 13,150 --------------------------------------------------------------- Total volumes sold 57,180 58,083 PCL and ECT 49,634 63,824 --------------------------------------------------------------- Total volumes delivered 106,814 121,907 =============================================================== Certain costs to be recovered through the rate making process have been recorded as regulatory assets in accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (Statement 71). Total regulatory assets resulting from this deferral process are approximately $222.4 million for the Distribution segment. Although no further unbundling of services is anticipated, should this occur, certain of these assets may no longer meet the criteria for following Statement 71, and accordingly, a write-off of regulatory assets and stranded costs may be required. PRODUCTION Operational Highlights - The Company's strategy is to concentrate ownership of hydrocarbon reserves in the mid-continent region in order to add value not only to its existing production operations but also to the related gathering and processing, marketing, transportation, and storage businesses. Accordingly, the Company focuses on exploitation activities rather than exploratory drilling. As a result of a growth strategy through acquisitions and developmental drilling, the number of wells the Company operates has increased. In its role as operator, the Company controls operating decisions that impact production volumes and lifting costs. The Company continually focuses on reducing finding costs and minimizing production costs. 49 During 2001, the Company acquired approximately $1.5 million in gas and oil properties. Through the Company's developmental drilling program, 155 wells were drilled during 2001 compared to 103 wells completed in 2000, an increase of more than 50 percent. Risk Management - The volatility of energy prices has a significant impact on the profitability of this segment As of December 31, 2001, 11 percent of anticipated 2002 proved developed producing well volumes, totaling approximately 2.3 Bcf, was hedged at an average price of $3.17 per Mcf. In 2001, 74 percent of proved developed producing well volumes, totaling approximately 17 Bcf, was hedged at an average price of $3.60 per Mcf. See Item 7A - Quantitative and Qualitative Disclosure about Market Risk and Note C of Notes to the Consolidated Financial Statements.
Years Ended Years Ended December 31, August 31, 2001 2000 1999 ----------------------------------------------------------------------------------------------------------------- Financial Results (Thousands of Dollars) Natural gas sales $ 107,846 $ 60,966 $ 58,776 Oil sales 12,262 8,571 6,169 Other revenues 209 818 1,949 ------------------------------------------------------------------------------------------------------------------ Net revenues 120,317 70,355 66,894 Operating costs 27,361 24,228 19,128 Depreciation, depletion, and amortization 35,017 30,884 34,073 ------------------------------------------------------------------------------------------------------------------ Operating income $ 57,939 $ 15,243 $ 13,693 ================================================================================================================== Other income, net $ 1,175 $ 545 $ 1,704 ================================================================================================================== Cumulative effect of a change in accounting principle $ (3,508) $ - $ - Income tax 1,357 - - ------------------------------------------------------------------------------------------------------------------ Cumulative effect of a change in accounting principle, net of tax $ (2,151) $ - $ - ==================================================================================================================
Operating Results - Net revenues increased significantly in 2001 compared to 2000 due to higher average gas prices for 2001, particularly during the first half of the year. The Company also benefited from higher oil and gas production in 2001 compared to 2000. Operating costs increased in 2001 due to higher production taxes resulting from higher oil and gas revenues. Depreciation, depletion and amortization increased in 2001 compared to 2000 due primarily from higher production, along with a slightly higher depletion rate. Net revenues increased in 2000 compared to 1999, due to higher natural gas and oil prices. The Company hedged the majority of its production in 2000. The impact of slightly higher commodity prices realized by the Company on revenues was partially offset by natural declines in production that was not replaced by new production. Operating costs increased in 2000 as compared with 1999 as a result of higher production taxes. Depreciation, depletion and amortization decreased in 2000 compared to 1999 due to decreased production and a lower average depletion rate resulting from low finding costs on current discoveries. Other income, net in 2001 primarily represents the gain from the sale of the Company's 40 percent interest in K. Stewart. 50
Years Ended Years Ended December 31, August 31, 2001 2000 1999 ---------------------------------------------------------------------------------------------------------------------------------- Operating Information Proved reserves Gas (MMcf) 232,967 254,721 254,102 Oil (MBbls) 4,511 4,339 4,197 Production Gas (MMcf) 27,578 26,746 27,773 Oil (MBbls) 493 400 460 Average realized price (a) Gas (Mcf) $ 3.91 $ 2.28 $ 2.12 Oil (Bbls) $ 24.89 $ 21.43 $ 13.56 Capital expenditures (Thousands) $ 55,974 $ 34,035 $ 16,046 Total assets (Thousands) $ 321,720 $ 308,041 $ 310,715 ---------------------------------------------------------------------------------------------------------------------------------- (a) The average realized price, above, reflects the impact of hedging activities.
The Production segment added 9.8 Bcfe of net reserves in 2001 after adjustments, including 20.8 Bcfe proved developed, 8.0 Bcfe proved behind pipe, 12.5 Bcfe proved undeveloped, offset by 31.5 Bcfe of downward revisions of proved reserve due to lower year-end 2001 prices and the resulting shorter economic life of some wells and the reduction of proved undeveloped reserve estimates as they were converted to proved developed reserves. Production for the year ended December 31, 2001 was 30.5 Bcfe. Capital expenditures above primarily relate to the drilling program, which consisted of drilling costs of approximately $53.2 million, $32.8 million, and $13.7 million in 2001, 2000, and 1999, respectively. Transition Period Operating Results Four Months Ended December 31, 1999 1998 -------------------------------------------------------------------------- Financial Results (Thousands of Dollars) Natural gas sales $ 20,789 $ 15,757 Oil sales 2,613 1,742 Other revenues 69 163 -------------------------------------------------------------------------- Net revenues 23,471 17,662 Operating costs 7,245 5,227 Depreciation, depletion, and amortization 9,715 10,292 -------------------------------------------------------------------------- Operating income $ 6,511 $ 2,143 ========================================================================== Other income, net $ (11) $ - ========================================================================== 51 Increased production from a successful developmental drilling program and properties acquired were the primary reasons for the increases in volumes for the Transition Period compared to the same period in 1998. Gas and oil prices for the Transition Period also increased compared to the same period in 1998. Operating costs also increased, compared to 1998, due to the Company operating and owning an interest in an increased number of wells. Four Months Ended December 31, 1999 1998 ------------------------------------------------------------------------------ Operating Information Proved reserves Gas (MMcf) 246,979 165,933 Oil (MBbls) 4,160 3,112 Production Gas (MMcf) 8,306 7,700 Oil (MBbls) 138 145 Average realized price (a) Gas (Mcf) $ 2.50 $ 2.03 Oil (Bbls) $ 18.93 $ 12.53 Capital expenditures (Thousands) $ 6,411 $ 4,581 Total assets (Thousands) $ 301,821 $ 275,840 ============================================================================== (a) The average realized price, above, reflects the impact of hedging activities. POWER Operational Highlights - The Company created the Power segment in January 2001 to include the operating results of the electric generating plant constructed by the Company. The 300-megawatt electric power plant is located adjacent to one of the Company's natural gas storage facilities and is configured to supply electric power during peak periods with four gas-powered turbine generators manufactured by General Electric. The Company's strategy is to capture the value added by converting natural gas to electricity, the spark spread premium, during peak demand periods. The plant began operations in mid-2001. The construction of this power plant complements the Company's strategy of maximizing earnings capacity of existing assets and exploring new opportunities that are expected to have a positive impact on earnings.
Years Ended Year Ended December 31, August 31, 2001 2000 1999 -------------------------------------------------------------------------------------------- Financial Results (Thousands of Dollars) Power sales $ 28,092 $ - $ - Cost of power 21,234 - - -------------------------------------------------------------------------------------------- Gross margin on power sales 6,858 - - Operating costs 1,358 - - Depreciation, depletion, and amortization 2,014 - - -------------------------------------------------------------------------------------------- Operating income $ 3,486 $ - $ - ============================================================================================ Other income, net $ (6) $ - $ - ============================================================================================
Operating Results - Power sales consist primarily of peaking sales rather than baseload contracts. Gross margin on power sales for 2001 were less than that which would be expected had the plant been in operation for a full year. Cooler weather during the summer of 2001 and low power prices both negatively impacted gross margins. The majority of the cost of power is generated by the peaking plant rather than purchased from unaffiliated companies. 52 Years Ended Year Ended December 31, August 31, 2001 2000 1999 ------------------------------------------------------------------------- Operating Information Power volumes (MMwh) 467 - - Gross margin ($/MMwh ) $ 14.69 $ - $ - Capital expenditures (Thousands) $ 42,302 $ 58,697 $ 3,748 Total assets (Thousands) $ 122,404 $ 77,426 $ 4,047 ------------------------------------------------------------------------- Prior to January 1, 2001, capital expenditures for the construction of the peak electric generating plant had been included in the Marketing and Trading segment. These capital expenditures have been reclassified and included in the Power segment for the periods shown in this report. Capital expenditures for the four months ended December 31, 1999 were $13.4 million. Primarily all capital expenditures incurred through 2001 relate to the construction of the plant. Price Risk Management - The Company's strategy is to capture market volatility in the spark spread premium. In doing so, the Power segment uses 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 C of Notes to Consolidated Financial Statements. LIQUIDITY AND CAPITAL RESOURCES A part of the Company's strategy has been and continues to be growth through acquisitions that strengthen and complement existing assets. The Company anticipates capital expenditures for 2002, exclusive of any acquisitions that may be made, to be approximately $242 million, which is less than previous years. The Company has relied primarily on a combination of operating cash flow and borrowings from a combination of commercial paper issuances, lines of credit, and capital markets for its liquidity and capital resource requirements. The Company expects to continue to use these sources for its liquidity and capital resource needs on both a short and long-term basis. Financing is provided through the Company's commercial paper program, long-term debt and, if needed, through a revolving credit facility. Other options to obtain financing include, but are not limited to, issuance of equity, asset securitization and sale/leaseback of facilities. The Company currently has a $500 million shelf registration in effect covering debt securities, including convertible debt and common stock. During 2001, capital expenditures were financed through operating cash flows and long-term debt. The Company's credit rating may be affected by a material change in financial ratios or a material adverse event. The most common criteria for assessment of the Company's credit rating are the debt to capital ratio, pre-tax and after-tax interest coverage and liquidity. If the Company's credit rating were downgraded, the interest rates on the commercial paper would increase, therefore, increasing the Company's cost to borrow funds. In the event, that the Company was unable to borrow funds under the commercial paper program, the Company has access to an $850 million revolving credit facility. In addition, downgrades in the Company's credit rating could impact the Marketing and Trading segment's ability to do business by requiring the Company to post margins with the few counterparties with which the Company has a Credit Support Annex within its International Swaps and Derivatives Association Agreement. 53 The Company has reviewed its commercial paper agreement, trust indentures, building leases, Bushton equipment leases, and marketing, trading and risk contracts and no rating triggers were identified. Rating triggers are defined as provisions that would create an automatic default or acceleration of indebtedness based on a change in the Company's credit rating. The revolving credit agreement does contain a provision that would cause the cost to borrow funds to increase based on the amount borrowed under this agreement if the Company's credit rating is negatively adjusted. This credit agreement also contains a default provision based on a material adverse change of the Company, but an adverse rating change is not defined as a default or material adverse change. The Company currently does not borrow funds under this agreement. The Company also has no guarantees of debt or other commitments to unaffiliated parties. The OCC staff filed an application on February 1, 2001 to review the gas procurement practices of ONG in acquiring its gas supply for the 2000/2001 heating season to determine if they were consistent with least cost procurement practices and whether the Company's decisions resulted in fair, just and reasonable costs being borne by its customers. An order issued on November 20, 2001 denied the recovery of a portion of the Company's unrecovered purchased gas cost account related to the unrecovered gas costs from the 2000/2001 winter effective December 1, 2001, leaving ONG with an estimated $34.6 million in unrecovered gas costs . The Company appealed this order to the Oklahoma Supreme Court and asked the OCC to stay the provisions of this order pending the outcome of the Company's appeal. The OCC subsequently approved the Company's request to stay the order. The stay allows ONG to continue recovery of this $34.6 million in gas costs subject to refund if the Oklahoma Supreme Court ultimately rules against the Company. The Company believes that decisions made by the Company were prudent based upon the facts and circumstances existing at the time the decisions were made, which is the standard applicable to the proceeding as stated by the OCC. The Company will defend itself vigorously; however, the Company has taken a charge of $34.6 million in the fourth quarter of 2001 as a result of this order. This charge is recorded as an increase in gas purchase expense in the Distribution segment. During 2001, the Company put in place a stock buyback plan for up to 10 percent of its capital stock. The program authorizes the Company to make purchases of its common stock on the open market with the timing and terms of purchases and the number of shares purchased to be determined by management based on market conditions and other factors. The purchased shares are held in treasury and available for general corporate purposes, funding of stock-based compensation plans, resale at a future date, or retirement. Purchases are financed with short-term debt or are made from available funds. At December 31, 2001, the Company had not purchased any stock under the plan. The Company is subject to commodity price volatility. Significant fluctuations in commodity price in either physical or financial energy contracts may impact the Company's overall liquidity due to the impact the commodity price change has on items such as the cost of gas held in storage, recoverability and timing of regulated natural gas costs, increased margin requirements, collectibility of certain energy related receivables and working capital. The Company believes that its current commercial paper program and debt capacity is adequate to meet liquidity requirements from commodity price volatility. CASH FLOW ANALYSIS Operating Cash Flows - In 2001, the changes in cash flows provided by operating activities primarily reflect changes in working capital accounts, deferred income taxes and price risk management assets and liabilities. The increase in deferred income taxes, a non-cash item, is due to accelerated depreciation in 2001. The increase in price risk management assets and liabilities is primarily due to $35 million in mark-to-market income, which is a non-cash item, and an increase in the Marketing and Trading segment's gas in storage, which is included in price risk management assets on the consolidated balance sheet. The level of gas held in storage is higher at December 31, 2001 compared to December 31, 2000 due to warmer weather in 2001. Cash flow from operating activities was positively impacted in the current year due to the reduction of accounts receivable, which was partially offset by increased cash used for payment of accounts payable and gas in storage and reduced recovery of unrecovered purchased gas costs. Receivables and payables were higher than normal at December 31, 2000, due to higher gas prices and the integration of the businesses acquired in 2000. 54 In 2000, the changes in cash flow provided by operating activities primarily reflect changes in working capital accounts and an increase in assets and liabilities in price risk management activities. The significant changes in working capital accounts, including accounts receivable, gas in storage, accounts payable and deferred credits and other liabilities is primarily a result of the acquisitions and the increase in operations resulting from those acquisitions in 2000 and historically higher gas prices. The increase in price risk management activities is due to the adoption of mark-to-market accounting in 2000. Investing Cash Flows - Cash paid for capital expenditures for the year ended December 31, 2001 was $341.6 million. This includes approximately $42.3 million for the construction of the electric generating plant. For the year ended December 31, 2000, capital expenditures were $311.4 million, which included $58.7 million for the construction of the electric generating plant. In 2001, the Company was reimbursed by an unaffiliated company for approximately $14 million of the costs incurred to construct a pipeline in the Transportation and Storage segment. Due to regulatory treatment, this amount is recorded as a deferred credit in the balance sheet and amortized to income. The Company also received approximately $7.9 million related to the sale of assets in the Production segment. Acquisitions in 2001 include $14.5 million of purchase price adjustments, which resulted in an increase to goodwill adjustments, relating to the Kinder Morgan acquisitions. The increase in capital expenditures for the year ended December 31, 2001 compared to the same period one year ago is primarily attributable to increased costs of sustaining a higher asset base due to the acquisitions in 2000. Cash used in investing activities increased in 2000 due to the acquisition of KMI and Dynegy. The increase in capital expenditures is related to the construction of the electric generating plant and recurring capital expenditures necessary to adequately maintain existing assets. Financing Cash Flows - The Company's capitalization structure is 42 percent equity and 58 percent long-term debt at December 31, 2001, compared to 48 percent equity and 52 percent long-term debt at December 31, 2000. At December 31, 2001, $1.7 billion of long-term debt was outstanding. As of that date, the Company could have issued $1,064.5 million of additional long-term debt under the most restrictive provisions contained in its various borrowing agreements. The Board of Directors has authorized up to $1.2 billion of short term financing to be procured as necessary for the operation of the Company. The Company has an $850 million Revolving Credit Facility with Bank of America, N.A. and other financial institutions with a maturity date of June 27, 2002. This credit facility is primarily used to support the commercial paper program. At December 31, 2001, $599 million of commercial paper was outstanding, which includes approximately $28 million of temporary investments and $275 million used to purchase natural gas that was injected into storage. At March 8, 2002, $413 million of commercial paper was outstanding, which includes approximately $118 million of temporary investments and $165 million used to purchase natural gas that was injected in to storage. In April 2001, the Company issued a $400 million, ten year, fixed rate note to refinance short-term debt. In July 2001, the Company entered into interest rate swaps on this debt with a term equal to the term of the notes. The interest rate under these swaps resets periodically based on the three-month London InterBank Offered Rate (LIBOR) or the six-month LIBOR at the reset date. In October 2001, the Company entered into an agreement to lock in the interest rates for each reset period under the swap agreements through the first quarter of 2003. In December 2001, the Company entered into interest rate swaps on a total of $200 million in fixed rate long-term debt through the term of the note. The interest rate under these swaps resets periodically based on the six-month LIBOR at the reset date. The average interest rate of the $600 million in notes is 6.971 percent. Under the current swap agreements, the average interest rate of the notes is an all-in LIBOR rate of approximately 3.516 percent. The all-in LIBOR rate refers to the average LIBOR rate plus or minus the ONEOK basis spread for all swaps. The swaps resulted in approximately $5.3 million of interest rate savings in 2001. 55 On July 18, 2001, the Company filed a "shelf" registration statement on Form S-3 pursuant to which the Company may offer debt securities and shares of the Company's common stock in one or more offerings with a total initial offering price of up to $500 million. On December 28, 2001, the Company filed a Post-Effective Amendment with the intent to allow the Company to offer convertible debt under this existing shelf registration. CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS The following table discloses the Company's contractual obligations to make future payments under the Company's current debt agreements, operating lease agreements and fixed price contracts. For further discussion of the debt and operating lease agreements, see Notes I and K, respectively, of Notes to the Consolidated Financial Statements.
Payments Due by Period -------------------------------------------------------------------------------- Contractual Obligations Total 2002 2003 2004 2005 2006 Thereafter ---------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Long-term debt $ 1,744,160 $ 250,000 $ 10,000 $ 50,000 $ 360,000 $ 310,000 $ 764,160 Notes payable 599,106 599,106 - - - - - Operating leases 284,821 33,042 25,137 24,567 27,372 40,683 134,020 Storage contracts 32,039 15,433 6,282 3,236 3,150 3,150 788 Firm transportation contracts 39,657 11,717 5,916 4,502 3,872 3,470 10,180 Purchase commitments, rights-of-way and other 15,788 3,190 2,711 2,642 2,597 2,475 2,173 ---------------------------------------------------------------------------------------------------------------- Total Contractual Obligations $ 2,715,571 $ 912,488 $ 50,046 $ 84,947 $ 396,991 $ 359,778 $ 911,321 ================================================================================================================
Long-term debt as reported in the consolidated balance sheets includes unamortized debt discount and the mark-to-market effect of interest rate swaps. Operating leases and purchase commitments, rights-of-way and other included approximately $0.9 million and $1.7 million for 2007, respectively, of annual commitments but are not included in the above table beyond 2007 due to the impracticality of calculating the future commitment. The Distribution segment is party to fixed price transportation contracts; however, the costs associated with these contracts are recovered through rates as allowed by the applicable regulatory agency and are excluded from the above table. TRADING ACTIVITIES Forwards, swaps, options, and energy transportation and storage contracts utilized for trading activities are reflected at fair value as assets and liabilities from price risk management activities in the consolidated balance sheets. The amounts include the cost of gas in storage, option premiums and the mark to market component (fair value). The following is a detail of the fair value component of the price risk management assets and liabilities, which result from the Marketing and Trading segment's energy trading portfolio. ------------------------------------------------------------------------------ (Thousands of Dollars) Net fair value of contracts outstanding at December 31, 2000 $ 24,219 Contracts realized or otherwise settled during the period (28,580) Fair value of new contracts when entered into during the period 81,026 Changes in fair values attributable to changes in valuation techniques and assumptions - Other changes in fair value (1) (17,053) ------------------------------------------------------------------------------ Net fair value of contracts outstanding at December 31, 2001 $ 59,612 ============================================================================== (1) Other changes in fair value primarily relate to a charge to expense for unrealized gains associated with swaps and options with Enron as a result of Enron's bankruptcy filing. 56 The net fair value of contracts outstanding at December 31, 2001 includes energy trading contracts accounted for under mark-to-market accounting. The net fair value of contracts outstanding includes the effect of settled energy contracts and current period charges resulting primarily from newly originated transactions and the impact of price movements on the fair value of price risk management assets and liabilities attributable to the Marketing and Trading segment's activities. The following is a detail of the Marketing and Trading segment's maturity of energy trading contracts based on heating injection and withdrawal periods from April through March. This maturity schedule is consistent with the Marketing and Trading segment's trading strategy. The Marketing and Trading segment has contracted over 40 Bcf of storage with an affiliate, which is excluded from outstanding fair value at December 31, 2001, in accordance with accounting principles generally accepted in the United States of America.
Fair Value of Contracts at December 31, 2001 -------------------------------------------------------------------------------- Matures Matures Matures Matures Total through through through after fair Source of Fair Value March 2003 March 2006 March 2008 March 2008 value --------------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Prices actively quoted (1) $ (22,627) $ (1,603) $ - $ - $ (24,230) Prices provded by other external sources (2) $ 124,474 913 (4,149) (1,567) $ 119,671 Prices based on models and other valuation models (3) $ (61,564) 30,509 4,065 (8,839) $ (35,829) --------------------------------------------------------------------------------------------------------------------------------- Total $ 40,283 $ 29,819 $ (84) $ (10,406) $ 59,612 =================================================================================================================================
(1) Prices actively quoted - values are derived from energy market price quotes from national commodity trading exchanges that primarily trade future and option commodity contracts. (2) Prices provided by other external sources - values are obtained through energy commodity brokers or electronic trading platforms, whose primary service is to match-up willing buyers and sellers of energy commodities. Because of the vast energy broker network, energy price information by location is readily available. (3) Prices based on models and other valuation models - values include primarily natural gas storage and transportation capacity contracted by OEMT. Values derived in this category utilize market price information from the aforementioned categories as well as other modeling assumptions that include, among others, assumptions for liquidity, credit, time value and other external attributes. Values attributable to storage models are determined on a heating injection/withdraw model. 57 The following table details OEMT's financial and commodity risk from fixed-price transactions: Investment Below Investment Grade Credit Grade Credit Quality (1) Quality -------------------------------------------------------------------------------- (Thousands of Dollars) Gas and electric utilities $ 44,361 $ 1,084 Financial institutions (14,739) - Oil and gas producers (13,046) (7,044) Industrial and commercial 12,631 3,819 Other (448) (263) -------------------------------------------------------------------------------- Total 28,759 (2,404) Credit and other reserves (320) (755) -------------------------------------------------------------------------------- Net value of fixed-price transactions $ 28,439 $ (3,159) ================================================================================ (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 Poor's or Moody's rating of BBB- or Baa3, respectively. Related Party Transactions - KGS has a shared service agreement with Western, which is the holder of the Company's preferred stock. The shared services include call center backup, meter readings, customer billing operations and customer service. KGS paid Western approximately $4.9 million in 2001 related to this shared service agreement. Off-Balance Sheet Arrangements - The Company has no off-balance sheet special purpose entities or asset securitization. Enron - Certain of the financial instruments discussed in Note C of Notes to the Consolidated Financial Statements have Enron North America as the counterparty. Enron Corporation and various subsidiaries, including Enron North America (Enron), filed for protection from creditors under Chapter 11 of the United States Bankruptcy Code on December 3, 2001. The Company has provided an allowance for forward financial positions and also established an allowance for uncollectible accounts relating to previously settled financial and physical positions with Enron at December 31, 2001. The Company estimates its claim against Enron to be approximately $74 million. Although the ultimate resolution of any claims ONEOK may have against Enron cannot be determined at this time, the Company believes any future losses would have an immaterial effect on the Company's financial position, cash flows and results of operations. The filing of the voluntary bankruptcy proceeding by Enron created a possible technical default related to various financing leases tied to the Company's Bushton gas processing plant in south central Kansas. The Company acquired the Bushton gas processing plant and related leases from Kinder Morgan in April 2000. Kinder Morgan had previously acquired the plant and leases from Enron. Enron is one of three guarantors of these Bushton plant leases; however, the Company is the primary guarantor. In January 2002, the Company was granted a waiver on the possible technical default related to these leases. The Company will continue to make all payments due under these leases. 58 Uncollectible Amounts - During 2001, the KCC issued an Order extending the time period for which gas service disconnection during inclement weather conditions cannot be made. Due to the extension of the time period restricting disconnections, delinquent KGS customers were allowed to continue gas service, thus increasing uncollectible amounts. Higher gas costs in the 2000/2001 heating season also contributed to the increased uncollectible amounts. KGS and other distribution companies in Kansas filed a joint application with the KCC seeking approval to recover the additional uncollectible amounts incurred during the 2000/2001 heating season until reviewed in the next rate case. The KCC approved the deferral allowing the companies to seek recovery of the extraordinary uncollectible account levels experienced in the 2000/2001 winter. KGS expects to file a rate case in late 2002. No accounting treatment has yet been determined. Southwest Litigation - In connection with the now terminated proposed acquisition of Southwest Gas Corporation (Southwest), the Company is party to various lawsuits. The Company and certain of its officers, as well as Southwest and certain of its officers, and others have been named as defendants in a lawsuit brought by Southern Union Company (Southern Union). The Southern Union allegations include, but are not limited to, Racketeer Influenced and Corrupt Organizations Act violations and improper interference in a contractual relationship between Southwest and Southern Union. The original claim asked for $750 million damages to be trebled for racketeering and unlawful violations, compensatory damages of not less than $750 million and rescission of the Confidentiality and Standstill Agreement, punitive damages and injunctive relief. On June 29, 2001, the Company filed Motions for Summary Judgment. On September 26, 2001, the Court entered an order that, among other things, denied the Motions for Summary Judgment by the Company on Southern Union's claim for tortious interference with a prospective relationship with Southwest; however, the Court's ruling limited any recovery by Southern Union to out-of-pocket damages and punitive damages. The Company expects to file a Motion for Summary Judgment seeking a dismissal of this single remaining claim and for punitive damages. Based on discovery at this point, the Company believes that Southern Union's out-of-pocket damages potentially recoverable at trial, exclusive of legal fees and expenses, are less than $1.0 million. Southwest filed a lawsuit against the Company and Southern Union alleging, among other things, fraud and breach of contract. Southwest is seeking damages in excess of $75,000. In an order dated January 4, 2002, the Court denied Southwest's Motion for Partial Summary Judgment in its favor on its claims against the Company, granted in part the Company's Motion for Summary Judgment against Southwest, and denied the Company's Motion for Summary Judgment in part with respect to Southwest's claims for fraud in the inducement and fraud. Based on discovery at this point, the Company believes that Southwest's actual damages potentially recoverable at trial, exclusive of legal fees and expenses, are less than $5.5 million. The lawsuits described above have been consolidated for purposes of trial. The Court has entered an order setting the cases for jury trial on October 15, 2002. Two substantially identical derivative actions were filed by shareholders against members of the Board of Directors of the Company for alleged violation of their fiduciary duties to the Company by causing or allowing the Company to engage in certain fraudulent and improper schemes related to the planned merger with Southwest for alleged waste of corporate assets. These two cases were consolidated into one case. Such conduct allegedly caused the Company to be sued by both Southwest and Southern Union, which exposed the Company to millions of dollars in liabilities. The plaintiffs seek an award of compensatory and punitive damages and costs, disbursements and reasonable attorney fees. The Company and its Independent Directors and officers named as defendants filed Motions to Dismiss the action for failure of the plaintiffs to make a pre-suit demand on the Company's Board of Directors. In addition, the Independent Directors and certain officers filed Motions to Dismiss the actions for failure to state a claim. On February 26, 2001, the action was stayed until one of the parties notifies the Court that a dissolution of the stay is requested. 59 Except as set forth above or in the Legal Proceedings, the Company is unable to estimate the possible loss, if any, associated with these matters. If substantial damages were ultimately awarded, it could have a material adverse effect on the Company's results of operations, cash flows and financial position. The Company is defending itself vigorously against all claims asserted by Southern Union and Southwest and all other matters relating to the now terminated proposed acquisition of Southwest. For more information, see Legal Proceedings. Hutchinson Litigation - Two separate class action lawsuits have been filed against the Company in connection with the natural gas explosions and eruptions of natural gas geysers that occurred in Hutchinson, Kansas in January 2001. Although no assurances can be given, management believes that the ultimate resolution of these matters will not have a material adverse effect on its financial position or results of operations. ONEOK and its subsidiaries are being represented by their insurance carrier in these cases. The Company is vigorously defending itself against all claims. For more information, see Legal Proceedings. Environmental - The Company has 12 manufactured gas sites located in Kansas, which may contain potentially harmful materials that are classified as hazardous material. Hazardous materials are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE presently governs all future work at these sites. The terms of the consent agreement allow the Company to investigate these sites and set remediation priorities based upon the results of the investigations and risk analysis. The prioritized sites will be investigated over a period of time as negotiated with the KDHE. Through December 31, 2001, the costs of the investigations and risk analysis related to these manufactured gas sites have been immaterial. Although remedial investigation and interim clean-up has begun on four sites, limited information is available about the sites. Management's best estimate of the cost of remediation ranges from $100,000 to $10 million per site based on a limited comparison of costs incurred to remediate comparable sites. These estimates do not give effect to potential insurance recoveries, recoveries through rates or from third parties. The KCC has permitted others to recover remediation costs through rates. It should be noted that additional information and testing could result in costs significantly below or in excess of the amounts estimated above. To the extent that such remediation costs are not recovered, the costs could be material to the Company's results of operations and cash flows depending on the remediation done and number of years over which the remediation is completed. In January 2001, the Yaggy storage facility, located in Hutchison, Kansas, was idled following natural gas explosions and eruptions of natural gas geysers. There are no known long-term environmental effects from the Yaggy storage facility, however, the Company continues to perform tests in cooperation with the KDHE. Impact of Recently Issued Accounting Pronouncements - In July 2001, the FASB issued Statement of Financial Accounting Standards No. 141, "Business Combinations" (Statement 141), Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" (Statement 142), and Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (Statement 143). In October, 2001, the FASB issued Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (Statement 144). Statement 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001. Statement 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually in accordance with the provisions of Statement 142. The Company adopted the provisions of Statement 141 effective July 1, 2001, and Statement 142 effective January 1, 2002. In connection with the Company's adoption of Statement 142, the Company is required to perform an assessment of whether there is an indication that goodwill, including equity-method goodwill, is impaired as of the date of adoption. Any transitional impairment loss will be recognized as a cumulative effect of a change in accounting principle in the Company's 2002 statement of earnings. 60 As of December 31, 2001, the Company has unamortized goodwill in the amount of $113.9 million. In addition, the Company has approximately $30.1 million of goodwill related to its equity investments. The entire amount will be subject to the transition provisions of Statement 142. Amortization expense related to goodwill was $4.4 million and $3.2 million for the years ended December 31, 2001 and 2000, respectively. The Company discontinued the amortization of goodwill effective January 1, 2002, with the adoption of Statement 142. In accordance with provisions of Statement 142, the Company will complete its analysis of goodwill for impairment no later than June 30, 2002. Statement 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Statement 143 is effective for fiscal years beginning after June 15, 2002. Statement 144 retains the requirement to report separately discontinued operations and extends that reporting to a component of an entity that either has been disposed of or is classified as held for sale. Statement 144 is effective for fiscal years beginning after December 15, 2001, and for interim periods within those fiscal years. The Company is currently assessing the impact of Statements 143 and 144 on its financial condition and results of operations. 61 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Risk Management - The Company, substantially through its nonutility segments, is exposed to market risk in the normal course of its business operations and to the impact of market fluctuations in the price 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. The Company's primary exposure arises from fixed price purchase or sale agreements which extend for periods of up to 48 months, gas in storage inventories utilized by the marketing and trading operation, and anticipated sales of natural gas and oil production. To a lesser extent, the Company is exposed to risk of changing prices or the cost of intervening transportation resulting from purchasing gas at one location and selling it at another (hereinafter referred to as basis risk). To minimize the risk from market fluctuations in the price of natural gas, NGLs and crude oil, the Company uses 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. The Company adheres to policies and procedures that limit its exposure to market risk from open positions and monitors market risk exposure. The Company has from time to time used weather derivative swaps to manage the risk of fluctuations in heating degree days (HDD) during the heating season. Under the weather derivative swap agreements, the Company receives a fixed payment per degree day below the contracted normal HDD and pays a fixed amount per degree day above the contracted normal HDD. The swaps contain a contract cap that limits the amount either party is required to pay. At December 31, 2001, the Company is not a party to any weather derivative swaps. KGS uses derivative instruments to hedge the cost of some anticipated gas purchases during the winter heating months to protect their customers from upward volatility in the market price of natural gas. At December 31, 2001, KGS had derivative instruments in place to hedge the cost of gas purchases for 6,500 MMMbtu. For further discussion of trading activities and models and assumptions used in the trading activities see the Critical Accounting Policies and Estimates section of Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. Also, see Note C of Notes to Consolidated Financial Statements. Interest Rate Risk - The Company is subject to the risk of fluctuation in interest rates in the normal course of business due to the Company utilizing variable rate debt. The Company manages interest rate risk through the use of fixed rate debt, floating rate debt and interest rate swaps. In July 2001, the Company entered into interest rate swaps on a total of $400 million in fixed rate long-term debt. The interest rate under these swaps resets periodically based on the three-month LIBOR or the six-month LIBOR at the reset date. In October 2001, the Company entered into an agreement to lock in the interest rates for each reset period under the swap agreements through the first quarter of 2003. In December 2001, the Company entered into interest rate swaps on a total of $200 million in fixed rate long-term debt. At December 31, 2001, a hypothetical 10 percent change in interest rates would result in an annual $4.4 million change in interest costs related to short-term and floating rate debt based on principal balances outstanding at these dates. At December 31, 2000 the Company had no interest rate swaps. Value-at-Risk Disclosure of Market Risk - ONEOK measures entity-wide market risk in its trading, price risk management, and its non-trading portfolios using value-at-risk (VAR). 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. ONEOK relies on VAR to determine the potential reduction in the trading and price risk management portfolio values arising from changes in market conditions over a defined period. 62 ONEOK's VAR exposure represents an estimate of potential losses that would be recognized for its trading and price risk management portfolio of derivative financial instruments, physical contracts and gas in storage assuming hypothetical movements in commodity market assumptions with no change in positions and are not necessarily indicative of actual results that may occur. VAR does not represent the maximum possible loss nor any expected loss that may occur because actual future gains and losses will differ from those estimated based on actual fluctuations in commodity prices, operating exposures and timing thereof, and the changes in the Company's trading and price risk management portfolio of derivative financial instruments and physical contracts. At December 31, 2001, the Company's estimated potential one-day favorable or unfavorable impact on future earnings, as measured by the VAR, using a 95 percent confidence level and diversified correlation assuming one day to liquidate positions was $5.1 million and the average of such value during the year ended December 31, 2001 was estimated at $3.6 million. Risk Policy and Oversight - ONEOK controls the scope of risk management, marketing and trading operations through a comprehensive set of policies and procedures involving senior levels of management. The Company's Board of Directors affirms the risk limit parameters with its audit committee having oversight responsibilities for the policies. A risk oversight committee, comprised of corporate and business segment officers, oversees all activities related to commodity price, credit and interest rate risk management, marketing and trading activities. The committee also proposes risk metrics including VAR and position loss limits. ONEOK has a corporate risk control organization lead by the Vice-President of Risk Control, which is assigned responsibility for establishing and enforcing the policies, procedures and limits and evaluating the risks inherent in proposed transactions. Key risk control activities include credit review and approval, credit and performance risk measurement and monitoring, validation of transactions, portfolio valuation, VAR and other risk metrics. To the extent open commodity positions exist, fluctuating commodity prices can impact the financial results and financial position of the Company either favorably or unfavorably. As a result, the Company cannot predict with precision the impact risk management decisions may have on the business, operating results or financial position. 63 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEPENDENT AUDITORS' REPORT To the Board of Directors and Shareholders ONEOK, Inc.: We have audited the accompanying consolidated balance sheets of ONEOK, Inc. and subsidiaries as of December 31, 2001, 2000, and 1999, and the related consolidated statements of income, shareholders' equity, and cash flows for the years ended December 31, 2001 and 2000, the year ended August 31, 1999 and the four months ended December 31, 1999. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of ONEOK, Inc. and subsidiaries as of December 31, 2001, 2000, and 1999, and the results of their operations and their cash flows for the years ended December 31, 2001 and 2000, the year ended August 31, 1999, and the four months ended December 31, 1999, in conformity with accounting principles generally accepted in the United States of America. As discussed in Notes A and C to the consolidated financial statements, the Company adopted the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, effective January 1, 2001 and the provisions of Emerging Issues Task Force 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, effective January 1, 2000. KPMG LLP Tulsa, Oklahoma February 14, 2002 64 ONEOK, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF INCOME
Year Year Four Months Year Ended Ended Ended Ended December 31, December 31, December 31, August 31, 2001 2000 1999 1999 ---------------------------------------------------------------------------------------------------------------- (Thousands of Dollars, except per share amounts) Operating Revenues (Note A) $ 6,803,146 $ 6,642,858 $ 806,478 $ 1,838,949 Cost of gas 5,894,361 5,845,726 587,681 1,213,478 ---------------------------------------------------------------------------------------------------------------- Net Revenues 908,785 797,132 218,797 625,471 ---------------------------------------------------------------------------------------------------------------- Operating Expenses Operations and maintenance 394,367 266,545 77,247 240,330 Depreciation, depletion, and amortization 157,310 143,351 43,227 129,704 General taxes 61,876 53,303 14,755 39,715 ---------------------------------------------------------------------------------------------------------------- Total Operating Expenses 613,553 463,199 135,229 409,749 ---------------------------------------------------------------------------------------------------------------- Operating Income 295,232 333,933 83,568 215,722 ---------------------------------------------------------------------------------------------------------------- Other income, net 876 18,475 2,396 10,500 Interest expense 140,158 118,630 27,883 52,809 Income taxes 52,234 90,286 22,737 67,056 ---------------------------------------------------------------------------------------------------------------- Income before cumulative effect of a change in accounting principle 103,716 143,492 35,344 106,357 Cumulative effect of a change in accounting principle, net of tax (Note A) (2,151) 2,115 - - ---------------------------------------------------------------------------------------------------------------- Net Income 101,565 145,607 35,344 106,357 Preferred stock dividends 37,100 37,100 12,367 37,247 ---------------------------------------------------------------------------------------------------------------- Income Available for Common Stock $ 64,465 $ 108,507 $ 22,977 $ 69,110 ================================================================================================================ Earnings Per Share of Common Stock (Note Q) Basic $ 0.85 $ 1.23 $ 0.27 $ 0.86 ================================================================================================================ Diluted $ 0.85 $ 1.23 $ 0.27 $ 0.86 ================================================================================================================ Average Shares of Common Stock (Thousands) Basic 99,449 98,340 100,742 103,102 Diluted 99,671 98,388 100,768 103,142
See accompanying Notes to Consolidated Financial Statements. 65 ONEOK, Inc. and Subsidiaries CONSOLIDATED BALANCE SHEETS
December 31, December 31, December 31, 2001 2000 1999 ------------------------------------------------------------------------------------------------------------- Assets (Thousands of Dollars) Current Assets Cash and cash equivalents $ 28,229 $ 249 $ 72 Trade accounts and notes receivable, net 677,796 1,627,714 371,313 Materials and supplies 20,310 18,119 10,360 Gas in storage 82,694 57,800 124,511 Deferred income taxes - 10,425 8,383 Purchased gas cost adjustment 45,098 1,578 8,105 Assets from price risk management activities (Note C) 587,740 1,416,368 - Customer deposits 41,781 120,800 40,928 Other current assets 78,321 71,906 31,714 ------------------------------------------------------------------------------------------------------------- Total Current Assets 1,561,969 3,324,959 595,386 ------------------------------------------------------------------------------------------------------------- Property, Plant and Equipment Marketing and Trading 3,979 2,795 2,047 Gathering and processing 1,040,195 1,001,994 385,260 Transportation and Storage 792,641 773,198 526,537 Distribution 1,985,177 1,860,181 1,766,057 Production 482,404 428,701 405,298 Power 118,193 75,891 17,193 Other 85,168 64,056 41,301 ------------------------------------------------------------------------------------------------------------- Total Property, Plant and Equipment 4,507,757 4,206,816 3,143,693 Accumulated depreciation, depletion, and amortization 1,234,789 1,110,803 1,021,915 ------------------------------------------------------------------------------------------------------------- Net Property 3,272,968 3,096,013 2,121,778 ------------------------------------------------------------------------------------------------------------- Deferred Charges and Other Assets Regulatory assets, net (Note E) 232,520 238,605 247,486 Goodwill 113,868 92,909 80,743 Assets from price risk management activities (Note C) 475,066 405,666 - Investments and other 222,768 202,193 195,847 ------------------------------------------------------------------------------------------------------------- Total Deferred Charges and Other Assets 1,044,222 939,373 524,076 ------------------------------------------------------------------------------------------------------------- Total Assets $ 5,879,159 $ 7,360,345 $ 3,241,240 =============================================================================================================
See accompanying Notes to Consolidated Financial Statements. 66 ONEOK, Inc. and Subsidiaries CONSOLIDATED BALANCE SHEETS
December 31, December 31, December 31, 2001 2000 1999 ---------------------------------------------------------------------------------------------------------------------- Liabilities and Shareholders' Equity (Thousdands of Dollars) Current Liabilities Current maturities of long-term debt $ 250,000 $ 10,767 $ 21,767 Notes payable 599,106 824,106 462,242 Accounts payable 390,479 1,247,519 237,653 Accrued taxes 11,528 8,735 359 Accrued interest 31,954 24,161 16,628 Customers' deposits 21,697 18,319 18,212 Liabilities from price risk management activities (Note C) 381,409 1,296,041 - Other 132,244 96,913 29,852 ------------------------------------------------------------------------------------------------------------------------ Total Current Liabilities 1,818,417 3,526,561 786,713 ------------------------------------------------------------------------------------------------------------------------ Long-term Debt, excluding current maturities 1,498,012 1,336,082 775,074 Deferred Credits and Other Liabilities Deferred income taxes 499,432 382,363 349,883 Liabilities from price risk management activities (Note C) 491,374 543,278 - Lease obligation 122,011 137,131 - Other deferred credits 184,623 209,973 178,046 ------------------------------------------------------------------------------------------------------------------------ Total Deferred Credits and Other Liabilities 1,297,440 1,272,745 527,929 ------------------------------------------------------------------------------------------------------------------------ Total Liabilities 4,613,869 6,135,388 2,089,716 ------------------------------------------------------------------------------------------------------------------------ Commitments and Contingencies (Note K) Shareholders' Equity Convertible Preferred Stock, $0.01 par value: Series A authorized 20,000,000 shares; issued and outstanding 19,946,448 shares at December 31, 2001, December 31, 2000, and December 31, 1999 199 199 199 Common stock, $0.01 par value: authorized 300,000,000 shares;issued 63,438,441 shares and outstanding 60,002,218 shares at December 31, 2001; issued 63,198,610 shares and outstanding 59,176,550 shares at December 31, 2000; issued 63,198,610 shares and outstanding 59,109,246 shares at December 31, 1999 634 316 316 Paid in capital (Note G) 902,269 895,668 894,976 Unearned compensation (2,000) (1,128) (1,846) Accumulated other comprehensive income (Note D) (1,780) - - Retained earnings 415,513 387,789 317,985 Treasury stock at cost: 3,436,223 shares at December 31, 2001; 4,022,060 shares at December 31, 2000 and 4,089,364 shares at December 31, 1999 (49,545) (57,887) (60,106) ------------------------------------------------------------------------------------------------------------------------ Total Shareholders' Equity 1,265,290 1,224,957 1,151,524 ------------------------------------------------------------------------------------------------------------------------ Total Liabilities and Shareholders' Equity $ 5,879,159 $ 7,360,345 $ 3,241,240 ========================================================================================================================
See accompanying Notes to Consolidated Financial Statements. 67 ONEOK, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Year Four Months Year Ended Ended Ended Ended December 31, December 31, December 31, August 31, 2001 2000 1999 1999 ----------------------------------------------------------------------------------------------------------------- Operating Activities (Thousands of Dollars) Net income $ 101,565 $ 145,607 $ 35,344 $ 106,357 Depreciation, depletion, and amortization 157,310 143,351 43,227 129,704 Unrecovered purchased gas cost adjustment 34,579 - - - Gain on sale of assets (1,120) (27,050) - (6,639) Gain on sale of equity investments (758) - - - Income from equity investments (8,109) (4,025) (1,063) (1,560) Deferred income taxes 134,933 26,143 28,317 14,925 Amortization of restricted stock 1,110 632 108 - Allowance for doubtful accounts 43,495 6,048 436 4,029 Other 188 692 - 293 Changes in assets and liabilities: Accounts and notes receivable 909,324 (1,262,449) (143,413) (54,716) Inventories (11,906) (41,669) (15,920) 19,429 Unrecovered purchased gas costs (78,099) 6,527 (3,553) (16,720) Regulatory assets (8,387) (6,303) (3,841) (6,261) Other assets 37,201 (97,402) (5,457) (88,930) Accounts payable and accrued liabilities (984,999) 1,168,871 84,627 41,320 Price risk management assets and liabilities (198,611) (64,574) - - Deferred credits and other liabilities (6,211) 78,559 (1,812) (7,034) ----------------------------------------------------------------------------------------------------------------- Cash Provided by Operating Activities 121,505 72,958 17,000 134,197 ----------------------------------------------------------------------------------------------------------------- Investing Activities Changes in other investments, net 1,194 68 994 (59,422) Acquisitions (16,015) (494,904) (17,482) (344,494) Capital expenditures (341,567) (311,403) (76,016) (164,170) Proceeds from sale of property 7,911 60,659 - 16,500 Proceeds from sale of equity investment 7,425 - - - ----------------------------------------------------------------------------------------------------------------- Cash Used in Investing Activities (341,052) (745,580) (92,504) (551,586) ----------------------------------------------------------------------------------------------------------------- Financing Activities Borrowing of notes payable, net (225,000) 361,864 198,495 51,747 Change in bank overdraft 141,923 (168,145) (22,699) - Issuance of debt 401,367 590,000 - 695,888 Payment of debt (7,583) (39,992) (36,952) (224,868) Issuance of common stock 5,447 - - 1,087 Issuance (acquisition) of treasury stock, net 5,214 (453) (39,610) (22,570) Dividends paid (73,841) (70,475) (28,060) (76,281) Acquisition and cancellation of preferred stock - - - (3,298) ----------------------------------------------------------------------------------------------------------------- Cash Provided by Financing Activities 247,527 672,799 71,174 421,705 ----------------------------------------------------------------------------------------------------------------- Change in Cash and Cash Equivalents 27,980 177 (4,330) 4,316 Cash and Cash Equivalents at Beginning of Period 249 72 4,402 86 ----------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Period $ 28,229 $ 249 $ 72 $ 4,402 =================================================================================================================
See accompanying Notes to Consolidated Financial Statements. 68 ONEOK, Inc. and Subsidiaries CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
Other Preferred Common Paid-in Unearned Comprehensive Retained Treasury Stock Stock Capital Compensation Income Earnings Stock Total (Thousands of Dollars) ----------------------------------------------------------------------------------------------------------------------------------- August 31, 1998 $ 200 $ 316 $ 897,547 $ - $ - $ 270,808 $ - $ 1,168,871 Net income - - - - - 106,357 - 106,357 Issuance of common stock Stock Purchase Plans - - 1,380 - - - - 1,380 Convertible preferred stock dividends - $1.86 and $1.55 per share for Series A and Series B, respectively - - - - - (37,247) - (37,247) Acquisition and Cancellation of Series B Convertible Preferred Stock (1) - (3,949) - - 652 - (3,298) Acquisition of Treasury Stock - - - - - - (22,570) (22,570) Common stock dividends - $1.24 per share - - - - - (39,034) - (39,034) ----------------------------------------------------------------------------------------------------------------------------------- August 31, 1999 $ 199 $ 316 $ 894,978 $ - $ - $ 301,536 $ (22,570) $ 1,174,459 Net income - - - - - 35,344 - 35,344 Re-issuance of treasury stock - - (2) - - (131) 141 8 Convertible preferred stock dividends - $.465 per share for Series A - - - - - (9,275) - (9,275) Acquisition of treasury stock - - - - - - (39,610) (39,610) Issuance of restricted stock - - - (1,933) - - 1,933 - Amortization of restricted stock - - - 108 - - - 108 Common stock dividends - $0.31 per share - - - (21) - (9,489) - (9,510) ----------------------------------------------------------------------------------------------------------------------------------- December 31, 1999 $ 199 $ 316 $ 894,976 $(1,846) $ - $ 317,985 $ (60,106) $ 1,151,524 ===================================================================================================================================
See accompanying Notes to Consolidated Financial Statements. 69 ONEOK, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY Other Preferred Common Paid-in Unearned Comprehensive Retained Treasury Stock Stock Capital Compensation Income Earnings Stock Total ----------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) December 31, 1999 $ 199 $316 $894,976 $(1,846) $ - $ 317,985 $(60,106) $1,151,524 Net income - - - - - 145,607 - 145,607 Re-issuance of treasury stock - - - - - (2,572) 14,196 11,624 Issuance of common stock Stock purchase plans - - 692 - - - - 692 Convertible preferred stock dividends - $1.86 per share for Series A - - - - - (37,100) - (37,100) Acquisition of treasury stock - - - - - - (11,812) (11,812) Issuance of restricted stock - - - (137) - - 137 - Amortization of restricted stock - - - 632 - - - 632 Forfeitures of restricted stock - - - 302 - - (302) - Common stock dividends - $1.24 per share - - - (79) - (36,131) - (36,210) ----------------------------------------------------------------------------------------------------------------- December 31, 2000 $ 199 $316 $895,668 $(1,128) $ - $ 387,789 $(57,887) $1,224,957 Net income - - - - - 101,565 - 101,565 Other comprehensive income - - - - (1,780) - - (1,780) ========= Total comprehensive income 99,785 Effect of two-for-one stock split - 317 (317) - - - - Re-issuance of treasury stock - - 866 - - - 7,278 8,144 Issuance of common stock Stock purchase plans - 1 5,317 - - - - 5,318 Convertible preferred stock dividends - $1.86 per share for Series A - - - - - (37,100) - (37,100) Acquisition of treasury stock - - - - - - (29) (29) Issuance of restricted stock - - 715 (1,932) - - 1,217 - Amortization of restricted stock - - - 1,110 - - - 1,110 Forfeitures of restricted stock - - 20 78 - - (124) (26) Common stock dividends - $0.62 per share - - - (128) - (36,741) - (36,869) ----------------------------------------------------------------------------------------------------------------- December 31, 2001 $ 199 $634 $902,269 $(2,000) $ (1,780) $ 415,513 $(49,545) $1,265,290 =================================================================================================================
70 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (A) SUMMARY OF ACCOUNTING POLICIES Nature of Operations - ONEOK, Inc. and subsidiaries (collectively, the "Company" or "ONEOK") is a diversified energy company engaged in the production, processing, gathering, storage, transportation, distribution, and marketing of natural gas, electricity and natural gas liquids. The Company manages its business in seven segments: Marketing and Trading, Gathering and Processing, Transportation and Storage, Distribution, Production, Power and Other. The Marketing and Trading segment purchases and markets natural gas, primarily in the mid-continent region of the United States. The Company owns and operates gas processing plants as well as gathering pipelines in Oklahoma, Kansas and Texas through its Gathering and Processing segment. The Transportation and Storage segment owns and leases natural gas storage facilities and transports gas in Oklahoma, Kansas and Texas. The Company's Distribution segment provides natural gas distribution services in Oklahoma and Kansas through its divisions Oklahoma Natural Gas Company (ONG) and Kansas Gas Service Company (KGS). The Production segment produces natural gas and oil and owns natural gas and oil reserves. The Power segment produces and markets electricity to wholesale customers. The Company's Other segment, whose results of operations are not material, operates and leases the Company's headquarters building and parking facility and has an investment in Magnum Hunter Resources, Inc., an independent oil and gas company. Critical Accounting Policies Energy Trading and Risk Management Activities- The Company engages in price risk management activities for both trading and non-trading purposes. On January 1, 2000, the Company adopted Emerging Issues Task Force Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities" (EITF 98-10) for its energy trading contracts. EITF 98-10 requires entities involved in energy trading activities to account for energy trading contracts using mark-to-market accounting. Prior to the adoption of EITF 98-10, the Company accounted for its trading activities on the accrual method based on settlement of physical and financial positions. The adoption of EITF 98-10 was accounted for as a change in accounting principle and the cumulative effect at January 1, 2000 of $2.1 million, net of tax, was recognized. Forwards, swaps, options, and energy transportation and storage contracts utilized for trading activities are reflected at fair value as assets and liabilities from price risk management activities in the consolidated balance sheets. The fair value of these assets and liabilities are affected by the actual timing of settlements related to these contracts and current period changes resulting primarily from newly originated transactions and the impact of price movements. Changes in fair value are recognized in net revenues in the consolidated statements of income. Market prices used to fair value these assets and liabilities reflect management's best estimate considering various factors including closing exchange and over-the-counter quotations, time value and volatility underlying the commitments. Market prices are adjusted for the potential impact of liquidating the Company's position in an orderly manner over a reasonable period of time under present market conditions. See Note C of Notes to Consolidated Financial Statements. 71 Regulation - The Company's intrastate transmission pipelines and distribution operations are subject to the rate regulation and accounting requirements of the Oklahoma Corporation Commission (OCC), Kansas Corporation Commission (KCC) and Texas Railroad Commission (TRC). Certain other transportation activities of the Company are subject to regulation by the Federal Energy Regulatory Commission (FERC). ONG and KGS follow the accounting and reporting guidance contained in Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation (Statement 71). Allocation of costs and revenues to accounting periods for rate-making and regulatory purposes may differ from bases generally applied by non-regulated operations. Such allocations to meet regulatory accounting requirements are considered to be generally accepted accounting principles for regulated utilities provided that there is a demonstrable ability to recover any deferred costs in future rates. During the rate-making process, regulatory commissions may require a utility to defer recognition of certain costs to be recovered through rates over time as opposed to expensing such costs as incurred. This allows the utility to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. This causes certain expenses to be deferred as a regulatory asset and amortized to expense as they are recovered through rates. Total regulatory assets resulting from this deferral process are approximately $232.5 million, $238.6 million and $247.5 million at December 31, 2001, 2000 and 1999, respectively. Although no further unbundling of services is anticipated, should this occur, certain of these assets may no longer meet the criteria for following Statement 71 and, accordingly, a write-off of regulatory assets and stranded costs may be required. However, the Company does not anticipate that these costs, if any, will be significant. See Note E of Notes to the Consolidated Financial Statements. KGS has a two-year rate moratorium, which expires in November 2002. ONG is not subject to a rate moratorium. Impairments - The Company accounts for the impairment of long-lived assets to be recognized when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets carrying amount. The impairment loss is measured by comparing the fair value of the asset to its carrying amount. Fair values are based on discounted future cash flows or information provided by sales and purchases of similar assets. The Company evaluates impairment of assets on the lowest possible level. 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 twenty percent to 50 percent-owned affiliates are accounted for on the equity method. Investments in less than twenty percent owned affiliates are accounted for on the cost method. Cash and Cash Equivalents - Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less. Inventories - Materials and supplies are valued at average cost. Noncurrent gas in storage is classified as property and is valued at cost. The Marketing and Trading segment's gas in storage, which is recorded in current price risk management assets, is carried at fair value. Cost of current gas in storage for ONG is determined under the last-in, first-out, (LIFO) methodology. The estimated replacement cost of current gas in storage valued under the lifo method was $1.3 million, $12.3 million, and $7.3 million at December 31, 2001, 2000 and 1999, respectively, compared to its value under the LIFO method of $3.0 million, $4.6 million, and $5.7 million at December 31, 2001, 2000 and 1999, respectively. Current gas in storage for all other companies is determined using the weighted average cost of gas method. Derivative Instruments and Hedging Activities - To minimize the risk from fluctuations in the price of natural gas and crude oil, the Company's non-trading segments periodically enter into futures transactions, swaps, and options in order to hedge anticipated sales of natural gas and crude oil production, fuel requirements and inventories in its natural gas liquids business. Interest rate swaps are also used to manage interest rate risk. 72 Prior to 2001, in order to qualify as a hedge, the price movements in the underlying commodity derivatives had to be sufficiently correlated with the hedged transaction. Gains and losses from hedging transactions were recognized in income and reflected as cash flows from operating activities in the periods for which the underlying commodity or interest rate transactions were hedged. If the necessary correlation to the commodity or interest rate transaction being hedged was not maintained, the Company ceased to account for the contract as a hedge and recognized a gain or loss in current earnings to the extent the contract results had not been offset by the effects of the price or interest rate changes on the hedged item. If the underlying commodity or interest rate transaction being hedged by the derivative was disposed of or otherwise terminated, the gain or loss associated with such derivatives was no longer deferred and was recognized in the period the underlying was eliminated. On January 1, 2001, the Company adopted the provisions of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (Statement 133), amended by Statement No. 137 and Statement No. 138. Statement 137 delayed the implementation of Statement 133 until fiscal years beginning after June 15, 2000. Statement 138 amended the accounting and reporting standards of Statement 133 for certain derivative instruments and hedging activities. Statement 138 also amends Statement 133 for decisions made by the Financial Accounting Standards Board (FASB) relating to the Derivatives Implementation Group (DIG) process. The FASB DIG is addressing Statement 133 implementation issues, the ultimate resolution of which may impact the application of Statement 133. Under Statement 133, entities are required to record all derivative instruments in the balance sheet 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, on the reason for holding it. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposures to changes in fair values, cash flows, or foreign currencies. If the hedged exposure is a fair value exposure, 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. If the hedged exposure is a cash flow exposure, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income (outside earnings) and subsequently reclassified into earnings when the forecasted transaction affects earnings. Any amounts excluded from the assessment of hedge effectiveness, as well as the ineffective portion of the hedge, are reported in earnings immediately. See Note C of Notes to Consolidated Financial Statements. 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 (6.0 percent, 6.9 percent, 6.8 percent, and 7.8 percent, in fiscal years 2001 and 2000, the four months ended December 31, 1999, and the year ended August 31, 1999, respectively) used during the construction of major projects and is recorded as a credit to interest expense. Depreciation is calculated using the straight-line method based upon rates prescribed for ratemaking purposes. The average depreciation rate for property that is regulated by the OCC approximated 2.9 percent in fiscal year 2001, 3.0 percent in fiscal year 2000, 4.1 percent in the four months ended December 31, 1999, and 3.8 percent in the year ended August 31,1999. The average depreciation rates for properties regulated by the KCC, excluding Mid-Continent Market Center (the Market Center), were approximately 3.4 percent in fiscal year 2001, 3.3 percent in fiscal year 2000, 3.4 percent in the four months ended December 31, 1999, and 3.2 percent in the year ended August 31, 1999. The average depreciation rates for the Market Center properties were 3.4 percent in fiscal year 2001, 3.3 percent in fiscal year 2000, 3.1 percent in the four months ended December 31, 1999, and 3.1 percent in the year ended August 31, 1999. 73 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. Remaining Service Life Years ---------------------------------------------------------------------- Distribution property 22-25 40 Transmission property 18-33 47 Other property 6-24 40 ----------------------------------------------------------------------
Production Property - The Company uses the successful-efforts method to account for costs incurred in the acquisition and development of natural gas and oil reserves. Costs to acquire mineral interests in proved reserves and to drill and equip development wells are capitalized. Geological and geophysical costs and costs to drill exploratory wells which do not find proved reserves are expensed. Unproved oil and gas properties, which are individually significant, are periodically assessed for impairment. The remaining unproved oil and gas properties are aggregated and amortized based upon remaining lease terms and exploratory and developmental drilling experience. Depreciation and depletion are calculated using the unit-of-production method based upon periodic estimates of proved oil and gas reserves. Other Property - Gas processing plants and all other properties are stated at cost. Gas processing plants are depreciated using various rates based on estimated lives of available gas reserves. All other property and equipment is depreciated using the straight-line method over its estimated useful life. Goodwill -Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is amortized over a period of 30 to 40 years. The Company assesses the recoverability of this intangible asset by determining whether the amortization of the goodwill balance over its remaining life can be recovered through undiscounted future operating cash flows of the acquired operation. The amount of goodwill impairment, if any, is measured based on projected discounted future operating cash flows using a discount rate reflecting the Company's average cost of funds. The assessment of the recoverability of goodwill will be impacted if estimated future operating cash flows are not achieved. Environmental Expenditures - The Company accrues for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as further information develops or circumstances change. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable. Revenue Recognition - The Company's Marketing and Trading, Gathering and Processing, Transportation and Storage, Distribution and Power segments recognize revenue when services are rendered or product is delivered. Major industrial and commercial gas distribution customers are invoiced as of the end of each month. Certain gas distribution customers, primarily residential and some commercial, are invoiced on a cycle basis throughout the month, and the Company accrues unbilled revenues at the end of each month. ONG's and KGS's tariff rates for residential and commercial customers contain a temperature normalization clause that provides for billing adjustments from actual volumes to normalized volumes during the winter heating season. Revenues from the Production segment are recognized on the sales method when oil and gas production volumes are delivered to the purchaser. 74 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 and KCC and for all other operations, is recognized in income in the period that includes the enactment date. The Company continues to amortize previously deferred investment tax credits over the period prescribed by the OCC and KCC for ratemaking purposes. Common Stock Options and Awards -The Company follows Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" (Statement 123) which permits, but does not require, a fair value based method of accounting for stock-based employee compensation. Alternatively, Statement 123 allows companies to continue applying the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25), however, such companies are required to disclose pro forma net income and earnings per share as if the fair value based method had been applied. The Company has elected to continue to apply the provisions of APB 25 for purposes of computing compensation expense and has provided the pro forma disclosure provisions of Statement 123 in Note P of Notes to Consolidated Financial Statements. Earnings Per Common Share - In accordance with a pronouncement of the Financial Accounting Standards Board's Staff at the Emerging Issues Task Force meeting in April 2001, codified as EITF Topic No. D-95 (Topic D-95), the Company revised its computation of earnings per common share (EPS). In accordance with Topic D-95, the dilutive effect of the Company's Series A Convertible Preferred Stock is now considered in the computation of basic EPS, utilizing the "if-converted" method. Under the Company's "if-converted" method, the dilutive effect of the Series A Convertible Preferred Stock on EPS cannot be less than the amount that would result from the application of the "two-class" method of computing EPS. The "two-class" method is an earnings allocation formula that determines EPS for the common stock and the participating Series A Convertible Preferred Stock according to dividends declared and participating rights in the undistributed earnings. The Series A Convertible Preferred Stock is a participating instrument with the Company's common stock with respect to the payment of dividends. For all periods presented, the "two-class" method resulted in additional dilution. Accordingly, EPS for such periods reflects this further dilution. The Company restated the EPS amounts for all periods to be consistent with the revised methodology. See Note Q of Notes to Consolidated Financial Statements. Use of Estimates - Certain amounts included in or affecting the Company's financial statements and related disclosures must be estimated, requiring the Company to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. Items which may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, obligations under employees 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, the results of litigation and various other recorded or disclosed amounts. Accordingly, the reported amounts of the Company's assets and liabilities, revenues and expenses and related disclosures are necessarily affected by these estimates. The Company evaluates these estimates on an ongoing basis using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on the Company's financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Reclassification - Certain amounts in prior period consolidated financial statements have been reclassified to conform to the 2001 presentation. 75 (B) ACQUISITIONS AND DISPOSITIONS On April 5, 2000, the Company acquired certain natural gas gathering and processing assets located in Oklahoma, Kansas and West Texas from Kinder Morgan, Inc. (KMI). The Company also acquired KMI's marketing and trading operations, as well as some storage and transmission pipelines in the mid-continent region. The Company paid approximately $123.5 million for these assets plus working capital of approximately $53 million, which was subject to adjustment. The working capital adjustment was made in the first quarter 2001, resulting in the Company receiving approximately $4.0 million. The Company also assumed an operating lease for a processing plant for which the Company established a liability of approximately $157.7 million for an uneconomic lease obligation. The Company also assumed some firm capacity lease obligations to unaffiliated parties for which the Company established a reserve of approximately $220.1 million for out-of-market terms of those obligations. The acquisition was accounted for as a purchase. The results of operations of this acquisition are included in the consolidated statement of income subsequent to the purchase date. The table of unaudited pro forma information set forth below, presents a summary of consolidated results of operations of the Company as if the acquisition of the businesses acquired from KMI had occurred at the beginning of the periods 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 the results that may be expected in the future. Pro Forma Years Ended December 31, August 31, 2000 1999 --------------------------------------------------------------------------------- (Thousands of Dollars except per share amounts) Operating revenues $ 7,596,667 $5,623,102 Net income $ 153,087 $ 107,271 Income available for common shareholders $ 115,987 $ 70,024 Earnings Per Share of Common Stock - Diluted $ 1.29 $ 0.87 ---------------------------------------------------------------------------------
In March 2000, the Company completed the sale of its 42.4 percent interest in Indian Basin Gas Processing Plant and gathering system for $55 million. In March 2000, the Company completed the acquisition of assets located in Oklahoma, Kansas, and the Texas panhandle from Dynegy, Inc. for $305 million in cash, which included a $3 million adjustment for working capital. The assets include gathering systems, gas processing facilities, and transmission pipelines. On January 20, 2000, the Board of Directors of the Company voted unanimously to terminate the merger agreement with Southwest Gas Corporation (Southwest) in accordance with the terms of the merger agreement. The Company charged $3.7 million of ongoing litigation costs to Other income, net for the year ended December 31, 2001. The Company charged $13.7 million of previously deferred transaction and litigation costs to Other income, net for the year ended December 31, 2000. See Note K of Notes to Consolidated Financial Statements. In May 1999, the Company acquired the Oklahoma midstream natural gas gathering and processing assets of Koch Midstream Enterprises (Koch) for $285 million in cash. The assets acquired include eight natural gas processing plants and approximately 3,250 miles of gathering pipeline connected to 1,460 gas wells in Oklahoma. 76 (C) PRICE RISK MANAGEMENT ACTIVITIES AND FINANCIAL INSTRUMENTS Market risks are monitored by a risk control group which operates independently from the operating segments that create or actively manage these risk exposures. The risk control group ensures compliance with the Company's risk management policies. Risk Policy and Oversight - The Company controls the scope of risk management, marketing and trading operations through a comprehensive set of policies and procedures involving senior levels of management. The Company's Board of Directors affirms the risk limit parameters with its audit committee having oversight responsibilities for the policies. A risk oversight committee, comprised of corporate and business segment officers, oversees all activities related to commodity price, credit and interest rate risk management, marketing and trading activities. The committee also proposes risk metrics including value-at-risk (VAR) and position loss limits. The Company has a corporate risk control organization lead by the Vice-President of Risk Control, which is assigned responsibility for establishing and enforcing the policies, procedures and limits and evaluating the risks inherent in proposed transactions. Key risk control activities include credit review and approval, credit and performance risk measurement and monitoring, validation of transactions, portfolio valuation, VAR and other risk metrics. To the extent open commodity positions exist, fluctuating commodity prices can impact the financial results and financial position of the Company either favorably or unfavorably. As a result, the Company cannot predict with precision the impact risk management decisions may have on the business, operating results or financial position. Trading Activities The Company's operating results are impacted by commodity price fluctuations. The Company routinely enters into derivative financial instruments in order to minimize the risk of commodity price fluctuations related to its purchase and sale commitments, fuel requirements, transportation and storage contracts and inventories in its natural gas marketing and trading business. The Marketing and Trading segment includes the Company's wholesale and retail natural gas marketing and trading operations. The Marketing and Trading segment generally attempts to balance its fixed-price physical and financial purchase and sales commitments in terms of contract volumes and the timing of performance and delivery obligations. To the extent a net open position exists, fluctuating commodity market prices can impact the Company's financial position and results of operations, either favorably or unfavorably. The net open positions are actively managed and the impact of the changing prices on the Company's financial condition at a point in time is not necessarily indicative of the impact of price movements throughout the year. Fair value - The fair value and the average fair value of derivative financial instruments, purchase and sale commitments, fuel requirements, transportation and storage contracts and inventories related to trading price risk management activities held during 2001 and 2000 are set forth as follows: Fair Value Average Fair Value (a) December 31, 2001 December 31, 2001 Assets Liabilities Assets Liabilities --------------------------------------------------------------------------- (Thousands of Dollars) Energy commodities $ 1,039,611 $ 854,219 $ 1,094,946 $ 975,359 ---------------------------------------------------------------------------
(a) Computed using the ending balance at the end of each quarter. 77 Fair Value Average Fair Value (a) December 31, 2000 December 31, 2000 Assets Liabilities Assets Liabilities --------------------------------------------------------------------------- (Thousands of Dollars) Energy commodities $ 1,822,034 $ 1,839,319 $ 1,254,446 $ 1,394,605 ---------------------------------------------------------------------------
(a) Computed using the ending balance at the end of each quarter. The Company did not hold any other commodity type contracts for trading price risk management purposes at December 31, 2001. Notional value - The notional contractual quantities associated with trading price risk management activities are set forth as follows: Volumes Volumes Purchased Sold --------------------------------------------------------- December 31, 2001: Natural gas options (Bcf) 118.3 107.7 Crude oil options (MBbls) 5.6 5.4 Natural gas swaps (Bcf) 1,917.9 1,898.4 Crude oil swaps (MBbls) - 6.0 Natural gas futures (Bcf) 159.9 220.7 Crude oil futures (MBbls) 19.9 69.8 --------------------------------------------------------- December 31, 2000: Natural gas options (Bcf) 75.3 65.7 Crude oil options (MBbls) - - Natural gas swaps (Bcf) 683.6 733.8 Crude oil swaps (MBbls) - - Natural gas futures (Bcf) 114.3 112.7 Crude oil futures (MBbls) - - ---------------------------------------------------------
Notional amounts reflect the volume and indicated activity of transactions but do not represent the amounts exchanged by the parties or cash requirements associated with these financial instruments. Accordingly, notional amounts do not accurately measure the Company's exposure to market or credit risk. Credit Risk - In conjunction with the market valuation of its energy commodity contracts, the Company provides reserves for risks associated with its contract commitments, including credit risk. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company maintains credit policies with regard to its counterparties that management believes significantly minimize overall credit risk. These policies include an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements which allow for netting of positive and negative exposures associated with a single counterparty. Counterparties in its trading portfolio consist primarily of financial institutions, major energy companies, and local distribution companies. This concentration of counterparties may impact the Company's overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Based on the Company's policies, its exposures and its credit and other reserves, the Company does not anticipate a material adverse effect on financial position or results of operations as a result of counterparty nonperformance. 78 Non-Trading Activities Financial instruments are also utilized for non-trading purposes to hedge natural gas and crude oil production anticipated sales, fuel requirements and inventories in its natural gas liquids business to hedge the impact of fair value fluctuations. The Company is subject to the risk of fluctuation in interest rates in the normal course of business. The Company manages interest rate risk through the use of fixed rate debt, floating rate debt and, at times, interest rate swaps. Operating margins associated with the Gathering and Processing segment's natural gas gathering, processing and fractionation activities are sensitive to changes in natural gas liquids prices, principally as a result of contractual terms under which natural gas is processed and products are sold and the availability of inlet volumes. Also, certain processing plant assets are impacted by changes in, and the relationship between, natural gas and natural gas liquids prices, which, in turn influences the volumes of gas processed. In 2000, the Company entered into derivative instruments related to the production of natural gas, most of which expired in 2001. These derivative instruments were designed as cash flow hedges to hedge the Production segment's exposure to changes in the price of natural gas. Changes in the fair value of the derivative instruments are reflected initially in other comprehensive income (loss) and subsequently realized in earnings when the forecasted transaction affects earnings. The Company recorded a cumulative effect charge of $2.2 million, net of tax, in the income statement and $28 million, net of tax, in accumulated other comprehensive loss to recognize at fair value the ineffective and effective portions, respectively, of the losses on all derivative instruments that are designated as cash flow hedging instruments, which primarily consisted of costless option collars and swaps on natural gas production. The Company recognized $3.5 million in earnings, representing the ineffective portion of the cash flow hedges for the year ended December 31, 2001. The Company realized an $18.4 million loss in earnings that was reclassified from accumulated other comprehensive loss resulting from the settlement of contracts when the natural gas was sold. These gains and losses are reported in Operating Revenues. Other comprehensive income of $1.8 million at December 31, 2001 includes approximately $1.3 million related to a cash flow hedge for 2002 production, which will be realized within the next year when the financial transactions affect earnings. In July 2001, the Company entered into interest rate swaps, which were designated fair value hedges, on a total of $400 million in fixed rate long-term debt. The interest rate under these swaps resets periodically based on the three-month LIBOR or the six-month LIBOR at the reset date. In October 2001, the Company entered into an agreement to lock in the interest rates for each reset period under the swap agreements through the first quarter of 2003. In December 2001, the Company entered into interest rate swaps, which were designated fair value hedges, on a total of $200 million in fixed rate long-term debt. The Company recorded a $7.4 million net increase in price risk management assets and liabilities to recognize the interest rate swaps at fair value. Long-term debt was also increased to recognize the change in fair value of the related hedged liability. See Note I of Notes to Consolidated Financial Statements Fair value - The following table represents the estimated fair values of derivative instruments related to the Company's non-trading price risk management activities. The fair value is the carrying value for these instruments at December 31,2001 and they have no carrying value at December 31, 2000 and August 31, 1999. 79 Approximate Fair Value ---------------------------------------------------------------- (Thousands of Dollars) December 31, 2001 Natural gas commodities - cash flow hedges $ 1,249 Interest rate swaps - fair value hedges $ 7,379 Natural gas commodities - other $ (3,997) ---------------------------------------------------------------- December 31, 2000 Natural gas commodities $ (41,623) ---------------------------------------------------------------- August 31, 1999 Natural gas commodities $ (11,540) ---------------------------------------------------------------- Notional value - The Company was a party to natural gas commodity derivative instruments including swaps and options covering 19.0 Bcf and 32.9 Bcf of natural gas for December 31, 2001 and 2000, respectively. The Company utilized derivative contracts to mitigate its risk associated with weather for the month of November 2000 to reduce the impact of degree day deviations from normal weather. The Company did not have any weather hedges in place at December 31, 2001 and 2000. Credit Risk - The Company maintains credit policies with regard to its counterparties that management believes significantly minimize overall credit risk. These policies include an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements which allow for netting of positive and negative exposures associated with a single counterparty. The counterparties to the non-trading instruments include large integrated energy companies. Accordingly, the Company does not anticipate a material adverse effect on financial position or results of operations as a result of counterparty nonperformance. Financial Instruments The following table represents the carrying amounts and estimated fair values of the Company's financial instruments, excluding trading activities, which are marked to market, and non-trading commodity instruments, which are listed in the table above. Approximate Book Value Fair Value ----------------------------------------------------------------- (Thousands of Dollars) December 31, 2001 Cash and cash equivalents $ 28,229 $ 28,229 Accounts and notes receivable $ 677,796 $ 677,796 Notes payable $ 599,106 $ 599,106 Long-term debt $ 1,751,539 $ 1,773,798 ----------------------------------------------------------------- Approximate Book Value Fair Value ----------------------------------------------------------------- (Thousands of Dollars) December 31, 2000 Cash and cash equivalents $ 249 $ 249 Accounts and notes receivable $ 1,627,714 $ 1,627,714 Notes payable $ 824,106 $ 824,106 Long-term debt $ 1,350,689 $ 1,302,104 ----------------------------------------------------------------- 80 Approximate Book Value Fair Value ---------------------------------------------------------------- (Thousands of Dollars) December 31,1999 Cash and cash equivalents $ 72 $ 72 Accounts and notes receivable $ 371,313 $ 371,313 Notes payable $ 462,242 $ 462,242 Long-term debt $ 800,731 $ 753,298 ---------------------------------------------------------------- The fair value of cash and cash equivalents, accounts and notes receivable and notes payable approximate book value due to their short term nature. The estimated fair value of long-term debt has been determined using quoted market prices of the same or similar issues, discounted cash flows, and/or rates currently available to the Company for debt with similar terms and remaining maturities. (D) COMPREHENSIVE INCOME The table below gives an overview of Other comprehensive income at December 31, 2001, which includes the cumulative effect of a change in accounting principle due to the adoption of Statement 133, realized and unrealized gains and losses on derivative instruments and an adjustment to the Company's pension liability.
Year Ended December 31, 2001 ----------------------------------------------------------------------------------- (Thousands of Dollars) Net income $ 101,565 Other comprehensive income (loss): Cumulative effect of a change in accounting principle $ (45,556) Unrealized gains on derivative instruments 28,491 Realized losses in net income 18,383 Minimum pension liability adjustment (4,252) ----------- Other comprehensive loss before taxes (2,934) Income tax benefit on other comprehensive loss 1,154 -------------------------- Other comprehensive loss $ (1,780) ----------- Comprehensive income $ 99,785 ====================================================================================
81 (E) REGULATORY ASSETS The table presents a summary of regulatory assets, net of amortization, at December 31, 2001, 2000 and 1999.
December 31, December 31, December 31 2001 2000 1999 ----------------------------------------------------------------------------------------- (Thousands of Dollars) Recoupable take-or-pay $ 75,336 $ 79,324 $ 84,343 Pension costs 11,124 15,306 19,487 Postretirement costs other than pension 60,170 61,069 62,207 Transition costs 21,598 22,199 22,746 Reacquired debt costs 22,351 23,209 24,068 Income taxes 28,365 30,727 23,337 Other 13,576 6,771 11,298 ----------------------------------------------------------------------------------------- Regulatory assets, net $ 232,520 $ 238,605 $ 247,486 =========================================================================================
The remaining recovery period for these assets that the Company is not earning a return on is set forth in the table below. Remaining Recovery December 31, 2001 Period ------------------------------------------------------------------------------- (Thousands of Dollars) (Months) Postretirement costs other than pension -- Oklahoma $7,876 141 Income taxes - Oklahoma $9,374 114-130 Transition costs $21,598 431 ------------------------------------------------------------------------------- The OCC directed ONG to assume responsibility for, and ownership of, customer service lines and has authorized the Company to defer as regulatory assets the depreciation and operation and maintenance expenses incurred in connection with this plan. The recovery methodology, amount, and calculation of these deferrals will be addressed in ONG's next rate case filing. Through December 2001, the Company has deferred approximately $801,000 associated with this Commission directive. These deferred costs are included in the caption "Other" in the above table of regulatory assets. The OCC has authorized ONG to defer the incremental costs associated with a five-year cathodic protection program to be implemented to comply with the OCC's Pipeline Safety Department inspection reports. The recovery methodology and amount of these deferred expenses will be addressed in ONG's next rate case filing. Through December 2001, the Company has deferred approximately $1.9 million associated with this program. These deferred costs are included in the caption "Other" in the above table of regulatory assets. The OCC has authorized recovery of the take-or-pay settlement, pension and postretirement benefit costs over a 10 to 20 year period. KGS has been deferring and recording postretirement benefits in excess of pay-as-you-go as a regulatory asset as authorized by the KCC. See Note J of Notes to Consolidated Financial Statements. The KCC has allowed certain transition costs to be amortized and recovered in rates over a 40-year period with no rate of return on the unrecovered balance. Management believes that all transition costs recorded as a regulatory asset will be recovered through rates based on the accounting orders received and regulatory precedents established by the KCC. The Company amortizes reacquired debt costs, which includes unamortized debt costs, in accordance with the accounting rules prescribed by the OCC and KCC. These costs have been included in recent rate filings with the OCC and will be included in future rate filings with the KCC as a component of interest. 82 In accordance with various rate orders received from the KCC and the OCC, KGS has not yet collected through rates the amounts necessary to pay a significant portion of the net deferred income tax liabilities. As management believes it is probable that the net future increases in income taxes payable will be recovered from customers, it has recorded a regulatory asset for these amounts. Recovery through rates resulted in amortization of regulatory assets of approximately $11.3 million and $10.6 million for the years ended December 31, 2001 and 2000, respectively, $3.1 million for the four months ended December 31, 1999, and $13.7 million for the year ended August 31, 1999. (F) CAPITAL STOCK The Company has approximately 176 million shares of authorized and unreserved common stock available for issue. The Company issued Series A Convertible Preferred Stock, par value $0.01 per share, at the time of the November 1997 transaction with Western Resources, Inc. The holders of Series A Convertible Preferred Stock are entitled to receive a dividend payment, with respect to each dividend period of the common stock, equal to 3.0 times the dividend amount declared in respect of each share of common stock for the first five years of the agreement. In November 2002, the rate is reduced to 2.5 times the dividend amount declared in respect of each share of common stock, and at no time will the dividend be less than $1.80 per share on an aggregate annual basis. The dividend multiple has been adjusted to reflect the two-for-one common stock split described below. The terms of Series B Convertible Preferred Stock were the same as Series A Convertible Preferred Stock, except that the dividend amount was equal to the greater of 2.5 times the common stock dividend, and at no time will the dividend be less than $1.50 per share on an aggregate annual basis during the first five years after the agreement and not less than $1.80 on an aggregate annual basis thereafter. In 1999, the Company acquired and canceled all of the Series B Convertible Preferred Stock it had issued in 1998 and 1999. Series C Preferred Stock is designed to protect ONEOK, Inc. shareholders from coercive or unfair takeover tactics. Holders of Series C Preferred Stock are entitled to receive, in preference to the holders of ONEOK common stock, quarterly dividends in an amount per share equal to the greater of $0.50 or subject to adjustment, 100 times the aggregate per share amount of all cash dividends, and 100 times the aggregate per share amount (payable in kind) of all non-cash dividends. No Series C Preferred Stock has been issued. The Series A Convertible Preferred Stock is convertible, subject to certain restrictions, at the option of the holder, into ONEOK, Inc., Common Stock at the rate of two shares for each share of Series A Convertible Preferred Stock. On January 18, 2001, the Company's Board of Directors approved, and on May 17, 2001, the shareholders of the Company voted in favor of, a two-for-one common stock split, which was effected through the issuance of one additional share of common stock for each share of common stock outstanding to holders of record on May 23, 2001, with distribution of the shares on June 11, 2001. The Company retained the current par value of $0.01 per share for all shares of common stock. Shareholders' equity reflects the stock split by reclassifying from Paid in Capital to Common Stock an amount equal to the cumulative par value of the additional shares issued to effect the split. All share and per share amounts contained herein for all periods reflect this stock split. Outstanding convertible preferred stock is assumed to convert to common stock on a two-for-one basis in the calculations of earnings per share. During 2001, the Company began a second stock buyback plan for up to 10 percent of its capital stock. The program authorizes the Company to make purchases of its common stock on the open market with the timing and terms of purchases and the number of shares purchased to be determined by management based on market conditions and other factors. Through December 31, 2001, no shares have been purchased under this plan. The purchased shares are held in treasury and available for general corporate purposes, funding of stock-based compensation plans, resale at a future date, or retirement. Purchases are financed with short-term debt or are made from available funds. 83 During 1999, the Company initiated a stock buyback plan for up to 15 percent of its capital stock. The program authorized the Company to make purchases of its common stock on the open market with the timing and terms of purchases and the number of shares purchased to be determined by management based on market conditions and other factors. This plan was terminated in April 2001. Through April 30, 2001, the shares purchased under this plan totaled 5.1 million, which has been adjusted for the two-for-one stock split. The purchased shares are held in treasury and available for general corporate purposes, funding of stock-based compensation plans, resale at a future date, or retirement. Purchases were financed with short-term debt or were made from available funds. This plan expired in 2001. The Board of Directors has reserved 12.0 million shares of ONEOK, Inc.'s common stock for the Direct Stock Purchase and Dividend Reinvestment Plan, of which 424,000 shares were issued in fiscal year 2001, 190,000 shares were issued in fiscal year 2000, 56,000 shares were issued in the four months ended December 31, 1999, and 254,000 shares were issued in the year ended August 31, 1999. In January 2001, the Company amended and restated, in entirety, the existing Direct Stock Purchase and Dividend Reinvestment Plan. The Company has reserved approximately 13.2 million shares for the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries less the number of shares issued to date under this plan. Under the most restrictive covenants of the Company's loan agreements, $226.6 million (54.5 percent) of retained earnings were available to pay dividends at December 31, 2001. (G) PAID IN CAPITAL Paid in capital was $338.1 million, $331.5 million and $330.8 million for common stock at December 31, 2001, 2000 and 1999, respectively. Paid in capital for convertible preferred stock was $564.2 million at December 31, 2001, 2000 and 1999. (H) LINES OF CREDIT AND SHORT-TERM NOTES PAYABLE Commercial paper and short-term notes payable totaling $599.1 million, of which $275.0 million was used to purchase natural gas that was injected into storage, was outstanding at December 31, 2001. Commercial paper and short-term notes payable totaling $824.1 million and $462.2 million were outstanding at December 31, 2000 and 1999, respectively. The commercial paper and notes carried average interest rates of 4.25 percent, 6.53 percent, and 6.47 percent at December 31, 2001, 2000 and 1999, respectively. The Company has a $850 million short-term unsecured revolving credit facility, which provides a back-up line of credit for commercial paper in addition to providing short-term funds. Interest rates and facility fees are based on prevailing market rates and the Company's credit ratings. No amounts were outstanding under the line of credit and no compensating balance requirements existed at December 31, 2001. Maximum short-term debt from all sources as approved by the Company's Board of Directors is $1.2 billion. (I) LONG-TERM DEBT The aggregate maturities of long-term debt outstanding at December 31, 2001, are $250 million; $10 million; $50 million; $360 million; and $310 million for 2002 through 2006, respectively, including $6 million, which is callable at the option of the holder in each of those years. All long-term notes payable at December 31, 2001, are unsecured. In 2001, the Company issued a $400 million note at a rate of 7.125%. The proceeds from the note were used to refinance short-term debt. The Company issued $240 million of two-year floating rate notes in April 2000. The interest rate for these notes resets quarterly at a 0.65 percent spread over the three month London InterBank Offered Rate (LIBOR). The proceeds from the notes were used to fund acquisitions. In March 2000, the Company issued $350 million of five year, 7.75 percent, fixed rate notes to refinance short-term debt and finance acquisitions. 84 The Company is subject to the risk of fluctuation in interest rates in the normal course of business. The Company manages interest rate risk through the use of fixed rate debt, floating rate debt and, at times, interest rate swaps. In July 2001, the Company entered into interest rate swaps on a total of $400 million in fixed rate long-term debt. The interest rate under these swaps resets periodically based on the three-month LIBOR or the six-month LIBOR at the reset date. In October 2001, the Company entered into an agreement to lock in the interest rates for each reset period under the swap agreements through the first quarter of 2003. In December 2001, the Company entered into interest rate swaps on a total of $200 million in fixed rate long-term debt. The Company recorded a $7.4 million net increase in price risk management assets to recognize at fair value its derivatives that are designated as fair value hedging instruments. Long-term debt was increased by approximately $7.4 million to recognize the change in fair value of the related hedged liability. The swaps generated $5.3 million of interest rate savings during 2001. See further discussion of interest rate risk in Note C of Notes to the Consolidated Financial Statements. December 31, December 31, December 31, 2001 2000 1999 ------------------------------------------------------------------------------- (Thousands of Dollars) Long-term Notes Payable 6.43% due 2000 $ - $ - $ 5,000 7.25% due 2001 - 767 1,535 3.95% due 2002 240,000 240,000 - 8.44% due 2004 40,000 40,000 40,000 7.75% due 2005 350,000 350,000 - 7.75% due 2006 300,000 300,000 300,000 8.32% due 2007 24,000 28,000 32,000 6.00% due 2009 100,000 100,000 100,000 7.125% due 2011 400,000 - - 6.40% due 2019 94,913 96,502 99,308 9.70% due 2019 - - 8,826 9.75% due 2020 - - 15,305 6.50% due 2028 93,880 95,420 98,757 6.875% due 2028 100,000 100,000 100,000 ------------------------------------------------------------------------------- Total Long-term Notes Payable 1,742,793 1,350,689 800,731 Change in fair value of hedged debt 7,379 - - Other long-term debt 1,367 - - Unamortized debt discount 3,527 3,840 3,890 Current maturities 250,000 10,767 21,767 ------------------------------------------------------------------------------- Long-term debt $ 1,498,012 $ 1,336,082 $ 775,074 =============================================================================== (J) EMPLOYEE BENEFIT PLANS Retirement Plans - The Company has defined benefit and defined contribution retirement plans covering substantially all employees. Company officers and certain key employees are also eligible to participate in supplemental retirement plans. The Company generally funds pension costs at a level equal to the minimum amount required under the Employee Retirement Income Security Act of 1974. Other Postretirement Benefit Plans - The Company sponsors welfare care plans that provide postretirement medical benefits and life insurance benefits to substantially all employees who retire under the Retirement Plans with at least five years of service. Non-bargaining unit employees retiring between the ages of 50 and 55 have access to the Company provided medical benefits. Non-bargaining unit employees retiring at age 55 or older are eligible for both the Company provided medical and life insurance benefits. The plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance. 85 The Company elected to delay recognition of the accumulated postretirement benefit obligation (APBO) and amortize it over 20 years as a component of net periodic postretirement benefit cost. The following tables set forth the Company's pension and other postretirement benefit plans benefit obligations, fair value of plan assets, and funded status at December 31, 2001, 2000 and 1999.
Pension Benefits Postretirement Benefits December 31, December 31, ----------------------------------------- ---------------------------------------- 2001 2000 1999 2001 2000 1999 -------------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Change in Benefit Obligation Benefit obligation, beginning of period $ 481,879 $ 495,061 $ 504,865 $ 136,157 $ 146,589 $ 160,371 Service cost 9,751 9,365 2,829 3,074 3,566 1,297 Interest cost 36,188 34,806 11,431 10,195 10,312 3,636 Participant contributions - - - 1,476 1,173 334 Plan amendments - - - - (7,816) (10,893) Actuarial (gain)/loss 21,504 (25,965) (13,973) 13,626 (5,228) (4,786) Benefits paid (33,226) (31,388) (10,091) (9,969) (12,439) (3,370) -------------------------------------------------------------------------------------------------------------------------------- Benefit obligation, end of period $ 516,096 $ 481,879 $ 495,061 $ 154,559 $ 136,157 $ 146,589 ================================================================================================================================ Change in Plan Assets Fair value of assets, beginning of period $ 747,635 $ 640,330 $ 660,386 $ 24,110 $ 17,837 $ 17,500 Actual return on assets (128,527) 137,791 (10,198) 374 1,941 (674) Employer contributions 1,407 902 233 3,263 4,332 1,011 Benefits paid (33,226) (31,388) (10,091) - - - -------------------------------------------------------------------------------------------------------------------------------- Fair value of assets, end of period $ 587,289 $ 747,635 $ 640,330 $ 27,747 $ 24,110 $ 17,837 ================================================================================================================================ Funded status - over(under) $ 71,193 $ 265,756 $ 145,269 $ (126,812) $ (112,048) $ (128,752) Unrecognized net asset (1,248) (1,715) (2,182) - - - Unrecognized transition obligation - - - 22,903 24,758 34,332 Unrecognized prior service cost 6,112 6,934 7,756 - - 877 Unrecognized net (gain)loss 27,177 (188,392) (79,969) 25,976 9,689 16,356 Activity subsequent to measurement date - - - 586 (793) (998) -------------------------------------------------------------------------------------------------------------------------------- (Accrued)prepaid pension cost $ 103,234 $ 82,583 $ 70,874 $ (77,347) $ (78,394) $ (78,185) ================================================================================================================================ Actuarial Assumptions Discount rate 7.35% 7.75% 7.25% 7.35% 7.75% 7.25% Expected rate of return 9.85% 9.25% 9.25% 9.85% 9.25% 9.25% Compensation increase rate 4.50% 4.50% 4.50% 4.50% 4.50% 4.50%
86
Pension Benefits Year Year Four Months Year Ended Ended Ended Ended December 31, December 31, December 31, August 31, 2001 2000 1999 1999 --------------------------------------------------------------------------------------------------------------- Components of Net Periodic Benefit Cost Service cost $ 9,751 $ 9,365 $ 2,829 $ 9,282 Interest cost 36,188 34,806 11,431 32,832 Expected return on assets (61,161) (55,566) (17,581) (46,846) Amortization of unrecognized net asset at adoption (467) (467) (156) (467) Amortization of unrecognized prior service cost 822 822 274 177 Amortization of (gain)/loss (4,377) 233 92 786 --------------------------------------------------------------------------------------------------------------- Net periodic benefit cost $ (19,244) $ (10,807) $ (3,111) $ (4,236) ===============================================================================================================
Postretirement Benefits Year Year Four Months Year Ended Ended Ended Ended December 31, December 31, December 31, August 31, 2001 2000 1999 1999 ----------------------------------------------------------------------------------------------------------------- Components of Net Periodic Benefit Cost Service cost $ 3,074 $ 3,566 $ 1,297 $ 4,036 Interest cost 10,195 10,312 3,636 10,055 Expected return on assets (2,364) (1,792) (616) (1,325) Amortization of unrecognized net transition obligation at adoption 1,954 2,512 1,025 3,235 Amortization of unrecognized prior service cost - - 66 - Amortization of loss 234 430 154 688 ----------------------------------------------------------------------------------------------------------------- Net periodic benefit cost $ 13,093 $ 15,028 $ 5,562 $ 16,689 =================================================================================================================
For measurement purposes, a 6.10 percent annual rate of increase in the per capita cost of covered medical benefits (i.e., medical cost trend rate) was assumed for 2001. The rate was assumed to decrease gradually to 5 percent by the year 2003 and remain at that level thereafter. The medical cost trend rate assumption has a significant effect on the amounts reported. For example, increasing the assumed medical cost trend by one percentage point in each year would increase the accumulated postretirement benefit obligation as of December 31, 2001, by $12.3 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year ended December 31, 2001, by $1.3 million. Decreasing the assumed medical cost trend by one percentage point in each year would decrease the accumulated postretirement benefit obligation as of December 31, 2001, by $10.3 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year ended December 31, 2001, by $1 million. Employee Thrift Plan - The Company has a Thrift Plan covering substantially all employees. Employee contributions are discretionary. Subject to certain limits, employee contributions are matched by the Company. The cost of the plan was $8.8 million and $6.7 million in fiscal years 2001 and 2000, respectively; $2.3 million for the four months ended December 31, 1999; and $6.3 million for the year ended August 31, 1999. Postemployment Benefits - The Company pays postemployment benefits to former or inactive employees after employment but before normal retirement in compliance with specific separation agreements. Regulatory Treatment - The OCC has approved the recovery of ONG pension costs and other postretirement benefit costs through rates. The costs recovered through rates are based on current funding requirements and the net periodic postretirement benefit cost for pension and postretirement costs, respectively. Differences, if any, between the expense and the amount ordered through rates are charged to earnings. 87 Prior to the acquisition of the assets regulated by the KCC in fiscal 1998, Western had established a corporate-owned life insurance ("COLI") program which it believed in the long term would offset the expenses of its postretirement and postemployment benefit plans. Accordingly, the KCC issued an order permitting the deferral of postretirement and postemployment benefit expenses in excess of amounts recognized on a pay-as-you-go basis. The Company did not acquire the COLI program. In connection with the KCC's approval of the acquisition, the KCC granted the Company the benefit of all previous accounting orders issued to Western and requested that the Company submit a plan of recovery either through a general rate increase or through specific cost savings or revenue increases. Based on regulatory precedents established by the KCC and the accounting order, which permits the Company to seek recovery through rates, management believes that it is probable that accrued postretirement and postemployment benefits can be recovered in rates. The Company plans to file for recovery of these costs when the rate moratorium expires and anticipates that recovery will be allowed over a period not to exceed approximately 10 years. If these costs cannot be recovered in rates charged to customers, the Company would be required to record a one-time charge to expense for the regulatory asset established for postretirement and postemployment benefit costs totaling approximately $52.3 million at December 31, 2001. (K) COMMITMENTS AND CONTINGENCIES Leases - The initial term of the Company's headquarters building, ONEOK Plaza, is for 25 years, expiring in 2009, with six five-year renewal options. At the end of the initial term or any renewal period, the Company can purchase the property at its fair market value. Annual rent expense for the lease will be approximately $6.8 million until 2009. Rent payments were $9.3 million in fiscal years 2001 and 2000, $2.9 million for the four months ended December 31, 1999, and $5.8 million for the year ended August 31,1999. Estimated future minimum rental payments for the lease are $9.3 million for each of the years ending December 31, 2002 through 2009. The Company has the right to sublet excess office space in ONEOK Plaza. The Company received rental revenue of $3.5 million in fiscal years 2001 and 2000, $1.0 million for the four months ended December 31, 1999, and $2.8 million for the year ended August 31,1999, for various subleases. Estimated minimum future rental payments to be received under existing contracts for subleases are $3.2 million in 2002, $2.7 million in 2003, $2.1 million in 2004, $1.3 million in 2005, $1.2 million in 2006 and a total of $0.7 million thereafter. Other operating leases include a gas processing plant, office buildings, and equipment. Future minimum lease payments under non-cancelable operating leases (with initial or remaining lease terms in excess of one year) as of December 31, 2001 are $33.0 million in 2002, $25.1 million in 2003, $24.6 million in 2004, $27.4 million in 2005 and $40.7 million in 2006. The above amounts include the following minimum lease payments relating to the lease of a gas processing plant: $21.3 million in 2002, $16.2 million in 2003, $20.9 million in 2004, $24.2 million in 2005 and $37.7 million in 2006. The Company has a liability for uneconomic lease terms relating to the gas processing plant. Accordingly, the liability is amortized to rent expense in the amount of $13.0 million per year over the term of the lease. Enron - Certain of the financial instruments discussed previously in Note C of the Notes to the Consolidated Financial Statements have Enron North America as the counterparty. Enron Corporation and various subsidiaries, including Enron North America (Enron), filed for protection from creditors under Chapter 11 of the United States Bankruptcy Code on December 3, 2001. The Company has provided an allowance for forward financial positions and also established an allowance for uncollectible accounts relating to previously settled financial and physical positions with Enron at December 31, 2001. The Company estimates its claim against Enron to be approximately $74 million. The ultimate resolution of any claims ONEOK may have against Enron cannot be determined at this time. 88 The filing of the voluntary bankruptcy proceeding by Enron created a possible technical default related to various financing leases tied to the Company's Bushton gas processing plant in south central Kansas. The Company acquired the Bushton gas processing plant and related leases from KMI in April 2000. KMI had previously acquired the plant and leases from Enron. Enron is one of three guarantors of these Bushton plant leases; however, the Company is the primary guarantor. In January 2002, the company was granted a waiver on the possible technical default related to these leases. The Company will continue to make all payments due under these leases. Southwest Gas Corporation - In connection with the now terminated proposed acquisition of Southwest Gas Corporation (Southwest), the Company is party to various lawsuits. The Company and certain of its officers, as well as Southwest and certain of its officers, and others have been named as defendants in a lawsuit brought by Southern Union Company (Southern Union). The Southern Union allegations include, but are not limited to, Racketeer Influenced and Corrupt Organizations Act violations and improper interference in a contractual relationship between Southwest and Southern Union. The original claim asked for $750 million damages to be trebled for racketeering and unlawful violations, compensatory damages of not less than $750 million and rescission of the Confidentiality and Standstill Agreement. On June 29, 2001, the Company filed Motions for Summary Judgment. On September 26, 2001, the Court entered an order that, among other things, denied the Motions for Summary Judgment by the Company on Southern Union's claim for tortious interference with a prospective relationship with Southwest; however, the Court's ruling limited any recovery by Southern Union to out-of-pocket damages and punitive damages. The Company expects to file a Motion for Summary Judgment seeking a dismissal of this single remaining claim and for punitive damages. Based on discovery at this point, the Company believes that Southern Union's out-of-pocket damages potentially recoverable at trial, exclusive of legal fees and expenses, are less than $1.0 million. Southwest filed a lawsuit against the Company and Southern Union alleging, among other things, fraud and breach of contract. Southwest is seeking damages in excess of $75,000. In an order dated January 4, 2002, the Court denied Southwest's Motion for Partial Summary Judgment in its favor on its claims against the Company, granted in part the Company's Motion for Summary Judgment against Southwest, and denied the Company's Motion for Summary Judgment in part with respect to Southwest's claims for fraud in the inducement and fraud. Based on discovery at this point, the Company believes that Southwest's actual damages potentially recoverable at trial, exclusive of legal fees and expenses, are less than $5.5 million. The lawsuits described above have been consolidated for purposes of trial. The Court has entered an order setting the cases for jury trial on October 15, 2002. Two substantially identical derivative actions were filed by shareholders against members of the Board of Directors of the Company for alleged violation of their fiduciary duties to the Company by causing or allowing the Company to engage in certain fraudulent and improper schemes related to the planned merger with Southwest for alleged waste of corporate assets. These two cases were consolidated into one case. Such conduct allegedly caused the Company to be sued by both Southwest and Southern Union, which exposed the Company to millions of dollars in liabilities. The plaintiffs seek an award of compensatory and punitive damages and costs, disbursements and reasonable attorney fees. The Company and its Independent Directors and officers named as defendants filed Motions to Dismiss the action for failure of the plaintiffs to make a pre-suit demand on the Company's Board of Directors. In addition, the Independent Directors and certain officers filed Motions to Dismiss the actions for failure to state a claim. On February 26, 2001, the action was stayed until one of the parties notifies the Court that a dissolution of the stay is requested. Except as set forth above, the Company is unable to estimate the possible loss, if any, associated with these matters. If substantial damage were ultimately awarded, it could have a material adverse effect on the Company's results of operations, cash flows and financial position. The Company is defending itself vigorously against all claims asserted by Southern Union and Southwest and all other matters relating to the now terminated proposed acquisition of Southwest. 89 Environmental - The Company has 12 manufactured gas sites located in Kansas, which may contain potentially harmful materials that are classified as hazardous material. Hazardous materials are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE presently governs all future work at these sites. The terms of the consent agreement allow the Company to investigate these sites and set remediation priorities based upon the results of the investigations and risk analysis. The prioritized sites will be investigated over a period of time as negotiated with the KDHE. Through December 31, 2001, the costs of the investigations and risk analysis related to these manufactured gas sites have been immaterial. Although remedial investigation and interim clean-up has begun on four sites, limited information is available about the sites. Management's best estimate of the cost of remediation ranges from $100,000 to $10 million per site based on a limited comparison of costs incurred to remediate comparable sites. These estimates do not give effect to potential insurance recoveries, recoveries through rates or from unaffiliated parties. The KCC has permitted others to recover remediation costs through rates. It should be noted that additional information and testing could result in costs significantly below or in excess of the amounts estimated above. To the extent that such remediation costs are not recovered, the costs could be material to the Company's results of operations and cash flows depending on the remediation done and number of years over which the remediation is completed. In January 2001, the Yaggy storage facility, located in Hutchison, Kansas, was idled following natural gas explosions and eruptions of natural gas geysers. There are no known long-term environmental effects from the Yaggy storage facility, however, the Company continues to perform tests in cooperation with the KDHE. Other - The OCC staff filed an application on February 1, 2001 to review the gas procurement practices of ONG in acquiring its gas supply for the 2000/2001 heating season to determine if they were consistent with least cost procurement practices and whether the Company's decisions resulted in fair, just and reasonable costs being borne by its customers. In a hearing on October 31, 2001, the OCC issued an oral ruling that ONG not be allowed to recover the balance in the Company's unrecovered purchased gas cost (UPGC) account related to the unrecovered gas costs from the 2000/2001 winter effective with the first billing cycle for the month following the issuance of a final order. A final order, which was issued on November 20, 2001, halted the recovery process effective December 1, 2001. On December 12, 2001, the OCC approved a request to stay the order and will allow ONG to commence collecting gas charges, subject to refund should the Company ultimately lose the case. The stay will be in effect while the matter is before the Oklahoma Supreme Court. Although the Company believes that decisions made by the Company were prudent based upon the facts and circumstances existing at the time the decisions were made, which is the standard applicable to the Proceeding as stated by the OCC, the Company has taken a charge of $34.6 million in the fourth quarter of 2001 as a result of this order. This charge is recorded as an increase in gas purchase expense in the Distribution segment. The Company will continue to assert its legal rights and is hopeful that a resolution of this issue can be negotiated. Two separate class action lawsuits have been filed against the Company in connection with the natural gas explosions and eruptions of natural gas geysers that occurred in Hutchinson, Kansas in January 2001. Although no assurances can be given, management believes that the ultimate resolution of these matters will not have a material adverse effect on its financial position or results of operations. ONEOK and its subsidiaries are being represented by their insurance carrier in these cases. The Company is vigorously defending itself against all claims. In April 1998, an application filed with the OCC alleged that ONG has charged and continues to charge its ratepayers, through its PGA, excessive, imprudent and unwarranted gas purchase costs related to a contract with Dynamic Energy Resources, Inc. The Consumer Services Divisions (CSD) of the OCC conducted a review of the contract. The applicants and the CSD filed their direct testimony in February 2002. ONG is to file rebuttal testimony on April 21, 2002. The hearing before the Commission is scheduled for June 3, 2002. 90 The Company is a party to other litigation matters and claims, which are normal in the course of its operations, and while the results of litigation and claims cannot be predicted with certainty, management believes the final outcome of such matters will not have a materially adverse effect on consolidated results of operations, financial position, or liquidity. (L) INCOME TAXES The provisions for income taxes are as follows:
Year Year Four Months Year Ended Ended Ended Ended December 31, December 31, December 31, August 31, 2001 2000 1999 1999 ------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Current income taxes Federal $ (69,273) $ 55,764 $ (6,345) $ 48,760 State (13,426) 8,379 765 3,371 ------------------------------------------------------------------------------------------------------------- Total current income taxes (82,699) 64,143 (5,580) 52,131 ------------------------------------------------------------------------------------------------------------- Deferred income taxes Federal 127,750 23,947 25,938 13,671 State 7,183 2,196 2,379 1,254 ------------------------------------------------------------------------------------------------------------- Total deferred income taxes 134,933 26,143 28,317 14,925 ------------------------------------------------------------------------------------------------------------- Total provision for income taxes before cummulative effect of a change in accounting principle 52,234 90,286 22,737 67,056 ------------------------------------------------------------------------------------------------------------- Total provision for income taxes for the cummulative effect of a change in accounting principle (1,356) 1,334 - - ------------------------------------------------------------------------------------------------------------- Total provision for income taxes $ 50,878 $ 91,620 22,737 $67,056 =============================================================================================================
Following is a reconciliation of the provision for income taxes.
Year Year Four Months Year Ended Ended Ended Ended December 31, December 31, December 31, August 31, 2001 2000 1999 1999 ----------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Pretax income $152,442 $233,778 $58,081 $173,413 Federal statutory income tax rate 35% 35% 35% 35% ----------------------------------------------------------------------------------------------------------------- Provision for federal income taxes 53,355 81,822 20,328 60,695 Amortization of distribution property investment tax credit (764) (807) (302) (1,103) State income taxes, net of federal tax benefit (4,058) 6,874 2,044 5,737 Other, net 2,345 3,731 667 1,727 ----------------------------------------------------------------------------------------------------------------- Actual income tax expense $ 50,878 $91,620 $22,737 $ 67,056 =================================================================================================================
The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities are shown in the accompanying table. 91
December 31, December 31, December 31, 2001 2000 1999 --------------------------------------------------------------------------------------------------- (Thousands of Dollars) Deferred tax assets Accrued liabilities not deductible until paid $ 180,331 $ 173,493 $ 8,383 Net operating loss carryforward 36,972 1,665 1,317 Regulatory assets 9,956 4,734 3,760 Other 2,057 4,277 1,982 --------------------------------------------------------------------------------------------------- Total deferred tax assets 229,316 184,169 15,442 Valuation allowance for net operating loss carryforward expected to expire prior to utilization 6,693 1,230 882 --------------------------------------------------------------------------------------------------- Net deferred tax assets 222,623 182,939 14,560 Deferred tax liabilities Excess of tax over book depreciation and depletion 578,876 461,560 262,515 Investment in joint ventures 12,198 11,280 11,414 Regulatory assets 95,836 78,186 75,407 Other 38,472 3,851 6,724 --------------------------------------------------------------------------------------------------- Total deferred tax liabilities 725,382 554,877 356,060 --------------------------------------------------------------------------------------------------- Net deferred tax liabilities $ 502,759 $ 371,938 $341,500 ===================================================================================================
The Company has remaining net operating loss carryforwards for federal and state income tax purposes of approximately $84 million and $115 million, respectively, at December 31, 2001, which expire, unless previously utilized, at various dates through the year 2020. At December 31, 2001, the Company had $6.7 million in deferred investment tax credits recorded in other deferred credits, which will be amortized over the next 14 years. (M) SEGMENT INFORMATION Management has divided its operations into the following reportable segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. The Company conducts its operations through seven segments: (1) the Marketing and Trading segment markets natural gas to wholesale and retail customers; (2) the Gathering and Processing segment gathers and processes natural gas and fractionates, stores and markets natural gas liquids; (3) the Transportation and Storage segment transports and stores natural gas for others; (4) the Distribution segment distributes natural gas to residential, commercial and industrial customers and leases pipeline capacity to others; (5) the Production segment produces natural gas and oil; (6) the Power segment markets electricity to wholesale customers, and (7) the Other segment primarily operates and leases the Company's headquarters building and a related parking facility and owns an investment in Magnum Hunter Resources, Inc. The accounting policies of the segments are substantially the same as those described in the summary of significant accounting policies. Intersegment sales are recorded on the same basis as sales to unaffiliated customers. All corporate overhead costs relating to a reportable segment have been allocated for the purpose of calculating operating income. The Company's equity method investments do not represent operating segments of the Company. The Power segment has a signed definitive agreement with an unaffiliated company for a 15-year term providing the customer with the right to purchase approximately 25 percent of the plant's generating capacity. There are no single external customers from which the Company receives ten percent or more of consolidated revenues. 92
Gathering Transportation YearEnded Marketing and and and Other and December 31, 2001 Trading Processing Storage Distribution Production Power Eliminations ----------------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Sales to unaffiliated customers $ 4,293,526 $ 814,963 $ 76,837 $1,506,420 $ 94,144 $ 28,092 $ (10,836) Intersegment sales 614,698 499,854 102,133 4,548 26,173 - (1,247,406) ----------------------------------------------------------------------------------------------------------------------------------- Total Revenues $ 4,908,224 $ 1,314,817 $ 178,970 $1,510,968 $120,317 $ 28,092 $ (1,258,242) ----------------------------------------------------------------------------------------------------------------------------------- Netrevenues $ 103,429 $ 189,621 $ 129,344 $ 353,393 $120,317 $ 6,858 $ 5,823 Operating costs $ 31,488 $ 116,853 $ 52,497 $ 230,137 $ 27,361 $ 1,358 $ (3,451) Depreciation, depletion and amortization $ 597 $ 29,201 $ 19,190 $ 69,159 $ 35,017 $ 2,014 $ 2,132 Operatingincome $ 71,344 $ 43,567 $ 57,657 $ 54,097 $ 57,939 $ 3,486 $ 7,142 Cumulative effect of a change in accounting principle, net of tax $ - $ - $ - $ - $ (2,151) $ - $ - Incomefromequity investments $ - $ - $ 2,946 $ - $ 111 $ - $ 5,052 Total assets $ 1,369,220 $ 1,322,438 $ 797,331 $1,688,670 $321,720 $122,404 $ 257,376 Capital expenditures $ 1,184 $ 51,442 $ 35,911 $ 129,937 $ 55,974 $ 42,302 $ 24,817 ----------------------------------------------------------------------------------------------------------------------------------- Gathering Transportation Year Ended Marketing and and and Other and December 31, 2000 Trading Processing Storage Distribution Production Power Eliminations ----------------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Sales to unaffiliated customers $4,362,024 $ 839,388 $ 111,644 $1,270,369 $ 50,686 $ - $ 8,747 Intersegment sales 299,657 197,325 56,814 3,568 19,669 - (577,033) ----------------------------------------------------------------------------------------------------------------------------------- Total Revenues $4,661,681 $ 1,036,713 $ 168,458 $1,273,937 $ 70,355 $ - $ (568,286) ----------------------------------------------------------------------------------------------------------------------------------- Net revenues $ 66,482 $ 224,012 $ 125,582 $ 377,277 $ 70,355 $ - $ (66,576) Operating costs $ 14,321 $ 90,501 $ 44,785 $ 211,629 $ 24,228 $ - $ (65,616) Depreciation, depletion and amortization $ 887 $ 22,692 $ 18,639 $ 67,717 $ 30,884 $ - $ 2,532 Operating income $ 51,274 $ 110,819 $ 62,158 $ 97,931 $ 15,243 $ - $ (3,492) Cumulative effect of a change in accounting principle, net of tax $ 2,115 $ - $ - $ - $ - $ - $ - Income from equity investments $ - $ - $ 3,240 $ - $ 125 $ - $ 660 Total assets $3,035,227 $ 1,507,546 $ 661,894 $2,007,351 $308,041 $ 77,426 $ (237,140) Capital expenditures $ 815 $ 32,383 $ 37,701 $ 124,983 $ 34,035 $ 58,697 $ 22,789 -----------------------------------------------------------------------------------------------------------------------------------
YearEnded December 31, 2001 Total ----------------------------------------------- Sales to unaffiliated customers $6,803,146 Intersegment sales $ - ----------------------------------------------- Total Revenues $6,803,146 ----------------------------------------------- Netrevenues $ 908,785 Operating costs $ 456,243 Depreciation, depletion and amortization $ 157,310 Operatingincome $ 295,232 Cumulative effect of a change in accounting principle, net of tax $ (2,151) Incomefromequity investments $ 8,109 Total assets $5,879,159 Capital expenditures $ 341,567 ----------------------------------------------- Year Ended December 31, 2000 Total ----------------------------------------------- Sales to unaffiliated customers $6,642,858 Intersegment sales $ - ----------------------------------------------- Total Revenues $6,642,858 ----------------------------------------------- Net revenues $ 797,132 Operating costs $ 319,848 Depreciation, depletion and amortization $ 143,351 Operating income $ 333,933 Cumulative effect of a change in accounting principle, net of tax $ 2,115 Income from equity investments $ 4,025 Total assets $7,360,345 Capital expenditures $ 311,403 -----------------------------------------------
93
Marketing Gathering Transportation Four Months Ended and and and Other and December 31, 1999 Trading Processing Storage Distribution Production Power Eliminations ------------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Sales to unaffiliated customers $365,224 $ 63,869 $ 13,283 $ 337,890 $ 18,692 $ - $ 7,520 Intersegment sales 17,825 15,032 25,868 1,334 4,779 - (64,838) ------------------------------------------------------------------------------------------------------------------------------- Total Revenues $383,049 $ 78,901 $ 39,151 $ 339,224 $ 23,471 $ - $ (57,318) ------------------------------------------------------------------------------------------------------------------------------- Net revenues $ 11,493 $ 19,413 $ 34,491 $ 129,870 $ 23,471 $ - $ 59 Operating costs $ 3,344 $ 8,588 $ 10,184 $ 69,455 $ 7,245 $ - $ (6,814) Depreciation, depletion and amortization $ 242 $ 2,513 $ 5,124 $ 24,815 $ 9,715 $ - $ 818 Operating income $ 7,907 $ 8,312 $ 19,183 $ 35,600 $ 6,511 $ - $ 6,055 Income (loss) from equity investments $ - $ - $ 1,074 $ - $ (11) $ - $ - Total assets $287,375 $368,904 $437,561 $1,776,273 $301,821 $19,330 $ 49,976 Capital expenditures $ 9 $ 14,613 $ 5,837 $ 34,167 $ 6,411 $13,445 $ 1,534 ------------------------------------------------------------------------------------------------------------------------------- Four Months Ended December 31, 1999 Total ------------------------------------------- Sales to unaffiliated customers $ 806,478 Intersegment sales $ - ------------------------------------------- Total Revenues $ 806,478 ------------------------------------------- Net revenues $ 218,797 Operating costs $ 92,002 Depreciation, depletion and amortization $ 43,227 Operating income $ 83,568 Income (loss) from equity investments $ 1,063 Total assets $3,241,240 Capital expenditures $ 76,016 -------------------------------------------
Marketing Gathering Transportation Year Ended and and and Other and August 31, 1999 Trading Processing Storage Distribution Production Power Eliminations -------------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Sales to unaffiliated customers $772,331 $ 72,277 $ 27,892 $ 915,782 $ 44,026 $ - $ 6,641 Intersegment sales 53,067 11,513 79,993 8,168 22,868 - (175,609) -------------------------------------------------------------------------------------------------------------------------------- Total Revenues $825,398 $ 83,790 $107,885 $ 923,950 $ 66,894 $ - $(168,968) -------------------------------------------------------------------------------------------------------------------------------- Net revenues $ 35,443 $ 31,311 $102,910 $ 393,461 $ 66,894 $ - $ (4,548) Operating costs $ 9,069 $ 11,207 $ 28,919 $ 219,945 $ 19,128 $ - $ (8,223) Depreciation, depletion and amortization $ 503 $ 3,562 $ 13,852 $ 75,443 $ 34,073 $ - $ 2,271 Operating income $ 25,871 $ 16,542 $ 60,139 $ 98,073 $ 13,693 $ - $ 1,404 Income from equity investments $ - $ - $ 1,501 $ - $ 59 $ - $ - Total assets $269,444 $343,133 $373,742 $1,722,381 $310,715 $ 4,047 $ 1,483 Capital expenditures $ 448 $ 8,557 $ 32,618 $ 98,685 $ 16,046 $ 3,748 $ 4,068 -------------------------------------------------------------------------------------------------------------------------------- Year Ended August 31, 1999 Total ------------------------------------------- Sales to unaffiliated customers $ 1,838,949 Intersegment sales $ - ------------------------------------------- Total Revenues $ 1,838,949 ------------------------------------------- Net revenues $ 625,471 Operating costs $ 280,045 Depreciation, depletion and amortization $ 129,704 Operating income $ 215,722 Income from equity investments $ 1,560 Total assets $ 3,024,945 Capital expenditures $ 164,170 -------------------------------------------
(N) 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. A summary of the unaudited quarterly results of operations for the years ended December 31, 2001 and 2000, respectively, follows: 94
Year Ended First Second Third Fourth December 31, 2001 Quarter Quarter Quarter Quarter --------------------------------------------------------------------------------------------------- (Thousands of dollars, except per share amounts) Operating revenues $2,956,924 $1,402,399 $1,126,696 $1,317,127 Operating income $ 143,046 $ 71,942 $ 55,733 $ 24,511 Other income (expense) $ 3,299 $ 566 $ (1,914) $ (1,075) Income taxes $ 41,800 $ 12,651 $ 301 $ (2,518) Net Income (Loss) $ 64,859 $ 23,608 $ 18,787 $ (5,689) Earnings per share of common stock Basic $ 0.55 $ 0.20 $ 0.16 $ (0.05) Diluted $ 0.54 $ 0.20 $ 0.16 $ (0.05) Dividends per share of common stock $ 0.155 $ 0.155 $ 0.155 $ 0.155 Average shares of common stock outstanding Basic 99,214 99,407 99,521 99,648 Diluted 99,596 99,733 99,633 99,887 --------------------------------------------------------------------------------------------------- Year Ended First Second Third Fourth December 31, 2000 Quarter Quarter Quarter Quarter --------------------------------------------------------------------------------------------------- (Thousands of dollars, except per share amounts) Operating revenues $ 822,713 $1,385,565 $1,754,234 $2,680,346 Operating income $ 105,821 $ 76,067 $ 48,525 $ 103,520 Other income (expense) $ 15,517 $ (952) $ (1,073) $ 4,983 Income taxes $ 38,446 $ 19,610 $ 5,029 $ 27,201 Net Income $ 63,022 $ 27,162 $ 10,086 $ 45,337 Earnings per share of common stock Basic $ 0.53 $ 0.23 $ 0.01 $ 0.38 Diluted $ 0.53 $ 0.23 $ 0.01 $ 0.38 Dividends per share of common stock $ 0.155 $ 0.155 $ 0.155 $ 0.155 Average shares of common stock outstanding Basic 98,376 98,284 98,292 98,408 Diluted 98,378 98,292 98,300 98,752 ---------------------------------------------------------------------------------------------------
During the fourth quarter of 2001, the Company took a charge of $34.6 million against operating income related to unrecovered gas costs associated with the 2000/2001 winter. The Company also took a charge of $37.4 million against operating income during the same period related to the Enron bankruptcy filing. For further discussion of these charges, see Note K of the Notes to Consolidated Financial Statements. 95 (O) SUPPLEMENTAL CASH FLOW INFORMATION The table presents supplemental information relative to the Company's cash flows for the years ended December 31, 2001 and 2000, the four months ended December 31, 1999, and the year ended August 31, 1999.
Year Year Four Months Year Ended Ended Ended Ended December 31, December 31, December 31, August 31, 2001 2000 1999 1999 -------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Cash paid during the year Interest (including amounts capitalized) $ 132,364 $ 111,097 $ 16,605 $ 50,498 Income taxes $ 13,050 $ 57,579 $ - $ 59,466 -------------------------------------------------------------------------------------------------------------------- Noncash transactions Treasury stock transferred to compensation plans $ - $ 61 $ 2,071 $ - Gas received as payment in kind $ - $ - $ - $ 135 -------------------------------------------------------------------------------------------------------------------- Acquisitions Property, plant, and equipment $ 1,515 $ 832,849 $ 17,482 $ 338,138 Current assets - 74,012 - - Current liabilities - (20,996) - - Regulatory assets and goodwill 14,500 17,663 - 10,817 Lease obligation - (157,651) - - Price risk management activities - (239,660) - - Deferred credits - (11,313) - - Deferred income taxes - - - (4,461) -------------------------------------------------------------------------------------------------------------------- Cash paid - acquisitions $ 16,015 $ 494,904 $ 17,482 $ 344,494 ====================================================================================================================
(P) STOCK BASED COMPENSATION Stock Splits - Due to the 2001 stock split, the number of shares and related exercise prices have been adjusted to maintain both the total market value of common stock underlying the options and Employee Stock Purchase Plan (ESPP) share elections, and the relationship between the fair market value of the common stock and the exercise price of the options and ESPP share elections. STOCK OPTION PLANS Long-Term Incentive Plan - The ONEOK, Inc. Long-Term Incentive Plan provides for the granting of incentive stock options, non-statutory stock options, stock bonus awards, and restricted stock awards to key employees and the granting of stock awards to non-employee directors. The Company has reserved approximately 7.8 million shares of common stock for the plan less the number of shares previously issued under the plan. The maximum numbers of shares for which options or other awards may be granted to any employee during any year is 300,000. Under the plan, options may be granted by the Executive Compensation Committee (the Committee). Stock options and awards may be granted at any time until all shares authorized are transferred, except that no incentive stock option may be granted under the plan after August 17, 2005. Options may be granted which are not exercisable until a fixed future date or in installments. The plan also provides for restored options to be granted in the event an optionee surrenders shares of common stock which 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. 96 Options issued to date become void upon voluntary termination of employment other than retirement. In the event of retirement or involuntary termination, the optionee may exercise the option within three months. In the event of death, the option may be exercised by the personal representative of the optionee within a period to be determined by the Committee and stated in the option. A portion of the options issued to date can be exercised after one year from grant date and an option must be exercised no later than ten years after grant date. Stock Compensation Plan for Non-Employee Directors - The ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors provides for the granting of incentive stock bonus awards, performance unit awards, restricted stock awards, and non-qualified stock options to Non-Employee Directors. The Company has reserved 700,000 shares less the number of shares previously issued under the plan. The maximum number of shares of common stock with respect to which options or other awards may be granted to any Non-Employee Director during any year is 20,000. Under the plan, options may be granted by the Committee at any time on or before January 18, 2011. Options may be exercisable in full at the time of grant or may become exercisable in one or more installments. The plan also provides for restored options in the event that the optionee surrenders shares of common stock which 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 the exercise of an option resulted in the grant of the restored option. Options issued to date become void upon termination of service as a Non-Employee Director. Such options must be exercised no later than ten years after the date of grant of the option. In the event of death, the option may be exercised by the personal representative of the optionee. 97 Stock option activity has been restated to give effect to the 2001 two-for-one stock split. Activity to date has been as follows:
Weighted Number of Average Shares Exercise Price ----------------------------------------------------------------- Outstanding August 31, 1998 701,952 $ 15.65 Granted 531,448 $ 17.61 Exercised (55,900) $ 13.44 Expired (5,000) $ 17.45 Restored 71,690 $ 17.98 ----------------------------------------------------------------- Outstanding August 31, 1999 1,244,190 $ 16.55 Granted 617,400 $ 14.58 Exercised (2,000) $ 11.85 Expired (6,000) $ 17.61 Restored 1,726 $ 13.69 ----------------------------------------------------------------- Outstanding December 31, 1999 1,855,316 $ 15.89 Granted 8,000 $ 13.16 Exercised (342,822) $ 15.38 Expired (74,200) $ 16.01 Restored 55,062 $ 21.45 ----------------------------------------------------------------- Outstanding December 31, 2000 1,501,356 $ 16.19 Granted 1,102,000 $ 22.43 Exercised (118,750) $ 15.27 Expired (179,672) $ 19.57 Restored 3,538 $ 22.49 ----------------------------------------------------------------- Outstanding December 31, 2001 2,308,472 $ 18.96 ================================================================= Options Exercisable ----------------------------------------------------------------- August 31, 1999 709,990 $ 15.75 December 31, 1999 841,540 $ 16.05 December 31, 2000 813,894 $ 16.27 December 31, 2001 941,572 $ 16.57 -----------------------------------------------------------------
At December 31, 2001, the Company had 1,157,952 outstanding options with exercise prices ranging between $11.85 to $17.78 and a weighted average remaining life of 7.02 years. Of these options, 803,252 were exercisable at December 31, 2001 with a weighted average exercise price of $16.04. The Company also had 1,150,520 options outstanding at December 31, 2001 with exercise prices ranging between $17.78 and $26.67 and a weighted average remaining life of 8.62 years. Of these options, 138,320 were exercisable at December 31, 2001 at a weighted average exercise price of $19.64. Restricted Stock Awards - Under the Long-Term Incentive Plan, restricted stock awards also may be granted to key officers and employees. Ownership of the common stock vests over a three year period. Shares awarded may not be sold during the vesting period. The fair market value of the shares associated with the restricted stock awards is recorded as unearned compensation in shareholders' equity and is amortized to compensation expense over the vesting period. The dividends on the restricted stock awards are reinvested in common stock. These shares fully vest three years after the grant date of the restricted stock awards. The average price of shares granted was $22.31 and $13.16 for the years ended December 31, 2001 and 2000, respectively. 98 Restricted stock information has been restated to give effect to the 2001 two-for-one stock split. Restricted stock activity to date is as follows: Number of Shares ---------------------------------------- Outstanding August 31, 1999 - Granted 132,600 Released to participants - Forfeited - Dividends 1,394 ---------------------------------------- Outstanding December 31,1999 133,994 Granted 4,000 Released to participants (7,848) Forfeited (20,780) Dividends 5,448 ---------------------------------------- Outstanding December 31, 2000 114,814 Granted 90,400 Released to participants (2,424) Forfeited (6,676) Dividends 6,463 ---------------------------------------- Outstanding December 31, 2001 202,577 ======================================== Employee Stock Purchase Plan - In 1995, the Company authorized the Employee Stock Purchase Plan (ESPP) and the Company currently has 2.8 million shares reserved for the ESPP less the number of shares issued to date under this plan. Subject to certain exclusions, all full-time employees are eligible to participate. Under the terms of the plan, employees can choose to have up to ten percent of their annual earnings withheld to purchase the Company's common stock. The Committee may allow contributions to be made by other means provided that in no event will contributions from all means exceed ten percent of the employee's annual earnings. The purchase price of the stock is 85 percent of the lower of its grant date or exercise date market price. Approximately 56 percent, 56 percent, and 54 percent of eligible employees participated in the plan in fiscal years 2001, 2000, and 1999, respectively. Under the plan, the Company sold 192,593 shares in fiscal year 2001, 523,044 shares in fiscal year 2000, and 176,058 shares in fiscal year 1999. Accounting Treatment - The Company continues to apply APB 25 in accounting for both plans. Accordingly, no compensation cost has been recognized in the consolidated financial statements for the Company's options and the Employee Stock Purchase Plan. Had the Company applied the provisions of Statement 123 to determine the compensation cost under these plans, the Company's pro forma net income and diluted earnings per share would have been as follows:
Year Year Four Months Year Ended Ended Ended Ended December 31, December 31, December 31, August 31, 2001 2000 1999 1999 ----------------------------------------------------------------------------------------------------- Net Income (Thousands of dollars, except per share amounts) As reported $ 101,565 $ 145,607 $ 35,344 $ 106,357 Pro Forma $ 85,415 $ 135,893 $ 27,066 $ 99,887 Earnings per share - Diluted As reported $ 0.85 $ 1.23 $ 0.27 $ 0.86 Pro Forma $ 0.71 $ 1.15 $ 0.20 $ 0.81 =====================================================================================================
99 The fair market value of each option granted is estimated based on the Black-Scholes model. Based on previous stock performance, volatility is estimated to be 0.2309 for fiscal year 2001, 0.2406 for fiscal year 2000, 0.2414 for the four months ended December 31, 1999, and 0.2151 for the year ended August 31, 1999. The average dividend amount is estimated to be $0.615 per share for fiscal year 2001, $0.61 per share for fiscal year 2000, the four months ended December 31, 1999, and the year ended August 31, 1999, with a risk-free interest rate of 5.497 percent of fiscal year 2001, 5.665 percent for fiscal year 2000, 5.664 percent for the four months ended December 31, 1999, and 5.983 percent for the year ended August 31, 1999. Expected life ranged from 1 to 10 years based upon experience to date and the make-up of the optionees. Fair value of options granted at fair market value under the Plan were $8.14 and $13.29 for the years ended December 31, 2001 and 2000, respectively, $11.52 for the four months ended December 31, 1999, and $13.86 for the year ended August 31, 1999. Fair value of options granted above fair market value under the Plan was $7.92 for the year ended December 31, 2001. The average exercise price of options granted above fair market value is $23.49 for the year ended December 31, 2001. (Q) EARNINGS PER SHARE INFORMATION The following is a reconciliation of the basic and diluted EPS computations.
Year Ended December 31, 2001 Per Share Income Share Amount --------------------------------------------------------------------------------------- (Thousands, except per share amounts) Basic EPS Income available for common stock $ 64,465 59,557 Convertible preferred stock 37,100 39,892 -------------------------- Income available for common stock and assumed conversion of preferred stock 101,565 99,449 $ 1.02 ========================== Further dilution from applying the "two- class" method (0.17) --------- Basic earnings per share $ 0.85 ========= Effect of Other Dilutive Securities Options - 222 -------------------------- Diluted EPS Income available for common stock and assumed exercise of stock options $ 101,565 99,671 $ 1.02 ========================== Further dilution from applying the "two- class" method (0.17) --------- Diluted earnings per share $ 0.85 =======================================================================================
100
Year Ended December 31, 2000 Per Share Income Share Amount ---------------------------------------------------------------------------------------- (Thousands, except per share amounts) Basic EPS Income available for common stock $ 108,507 58,448 Convertible preferred stock 37,100 39,892 -------------------------- Income available for common stock and assumed conversion of preferred stock 145,607 98,340 $ 1.48 ========================== Further dilution from applying the "two- class" method (0.25) --------- Basic earnings per share $ 1.23 ========= Effect of Other Dilutive Securities Options - 48 -------------------------- Diluted EPS Income available for common stock and assumed exercise of stock options $ 145,607 98,388 $ 1.48 ========================== Further dilution from applying the "two- class" method (0.25) --------- Diluted earnings per share $ 1.23 =======================================================================================
Four Months Ended December 31, 1999 Per Share Income Share Amount --------------------------------------------------------------------------------------- (Thousands, except per share amounts) Basic EPS Income available for common stock $ 22,977 60,850 Convertible preferred stock 12,367 39,892 -------------------------- Income available for common stock and assumed conversion of preferred stock 35,344 100,742 $ 0.35 ========================== Further dilution from applying the "two- class" method (0.08) --------- Basic earnings per share $ 0.27 ========= Effect of Other Dilutive Securities Options - 26 -------------------------- Diluted EPS Income available for common stock and assumed exercise of stock options $ 35,344 100,768 $ 0.35 ========================== Further dilution from applying the "two- class" method (0.08) --------- Diluted earnings per share $ 0.27 =======================================================================================
101
Year Ended August 31, 1999 Per Share Income Share Amount ======================================================================================= (Thousands, except per share amounts) Basic EPS Income available for common stock $ 69,110 62,996 Convertible preferred stock 37,247 40,106 -------------------------- Income available for common stock and assumed conversion of preferred stock 106,357 103,102 $ 1.03 ========================== Further dilution from applying the "two- class" method (0.17) --------- Basic earnings per share $ 0.86 ========= Effect of Other Dilutive Securities Options - 40 -------------------------- Diluted EPS Income available for common stock and assumed exercise of stock options $ 106,357 103,142 $ 1.03 ========================== Further dilution from applying the "two- class" method (0.17) --------- Diluted earnings per share $ 0.86 =======================================================================================
There were 158,989, 113,836, 180,010, and 82,070 option shares excluded from the calculation of Diluted Earnings per Share for the years ended December 31, 2001 and 2000, the four months ended December 31, 1999, and the year ended August 31, 1999, respectively, due to being antidilutive for the periods. The following is a reconciliation of the basic and diluted EPS computations on income before the cumulative effect of a change in accounting principle to net income.
Year Year Four Months Year Ended Ended Ended Ended December 31, December 31, December 31, August 31, 2001 2000 1999 1999 ----------------------------------------------------------------------------------------------- Basic EPS (Per share amounts) Income available for common stock before cumulative effect of a change in accounting principle $ 0.87 $ 1.21 $ 0.27 $ 0.86 Cumulative effect of a change in accounting principle, net of tax (0.02) 0.02 - - ------------ ------------ ------------ ------------ Income available for common stock $ 0.85 $ 1.23 $ 0.27 $ 0.86 Diluted EPS Income available for common stock before cumulative effect of a change in accounting principle $ 0.87 $ 1.21 $ 0.27 $ 0.86 Cumulative effect of a change in accounting principle, net of tax (0.02) 0.02 - - ------------ ------------ ------------ ------------ Income available for common stock $ 0.85 $ 1.23 $ 0.27 $ 0.86 ===============================================================================================
102 (R) OIL AND GAS PRODUCING ACTIVITIES The following is historical cost information relating to the Company's production operations:
Year Year Four Months Year Ended Ended Ended Ended December 31, December 31, December 31, August 31, 2001 2000 1999 1999 ----------------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Capitalized costs at end of year Unproved properties $ 4,223 $ 2,210 $ 4,224 $ 4,245 Proved properties 475,151 423,824 398,748 393,096 ----------------------------------------------------------------------------------------------------------------------------------- Total capitalized costs 479,374 426,034 402,972 397,341 Accumulated depreciation, depletion and amortization 177,622 146,749 128,220 120,109 ----------------------------------------------------------------------------------------------------------------------------------- Net capitalized costs $ 301,752 $ 279,285 $ 274,752 $ 277,232 =================================================================================================================================== Costs incurred during the year Property acquisition costs (unproved) $ 2,334 $ 878 $ 103 $ 948 Exploitation costs $ 8 $ 10 $ 6 $ 17 Development costs $ 53,220 $ 32,817 $ 6,254 $ 13,659 Purchase of minerals in place $ 1,572 $ 4,751 $ - $ 79,385 -----------------------------------------------------------------------------------------------------------------------------------
The accompanying schedule presents the results of operations of the Company's oil and gas producing activities. The results exclude general office overhead and interest expense attributable to oil and gas production.
Year Year Four Months Year Ended Ended Ended Ended December 31, December 31, December 31, August 31, 2001 2000 1999 1999 ------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Net revenues Sales to unaffiliated customers $ 93,935 $ 49,868 $ 18,623 $ 42,077 Gas sold to affiliates 26,173 19,669 4,779 22,868 -------------------------------------------------------------------------------------------------------------------------- Net revenues from production 120,108 69,537 23,402 64,945 -------------------------------------------------------------------------------------------------------------------------- Production costs 20,991 17,575 5,465 14,516 Exploitation costs 8 10 6 17 Depreciation, depletion and amortization 35,017 30,465 9,588 33,771 Income taxes 24,999 8,311 3,226 6,359 ------------------------------------------------------------------------------------------------------------------------- Total expenses 81,015 56,361 18,285 54,663 ------------------------------------------------------------------------------------------------------------------------- Results of operations from producing activities $ 39,093 $ 13,176 $ 5,117 $ 10,282 ==========================================================================================================================
(S) OIL AND GAS RESERVES (UNAUDITED) Following are estimates of the Company's proved oil and gas reserves, net of royalty interests and changes herein, for the fiscal years 2001, 2000, the four months ended December 31, 1999, and the year ended August 31,1999. The Company emphasizes that the volumes of reserves shown are estimates, which, by their nature, are subject to later revision. The estimates are made by the Company utilizing all available geological and reservoir data as well as production performance data. These estimates are reviewed annually both internally and by an independent reserve engineer and revised, either upward or downward, as warranted by additional performance data. 103 Oil Gas (MBbls) (MMcf) ------------------------------------------------------------------- August 31, 1998 3,272 178,047 Revisions in prior estimates 300 8,397 Extensions, discoveries and other additions 376 37,202 Purchases of minerals in place 884 61,286 Sales of minerals in place (175) (3,057) Production (460) (27,773) ------------------------------------------------------------------ August 31, 1999 4,197 254,102 Revisions in prior estimates 18 (8,086) Extensions, discoveries and other additions 84 9,276 Purchases of minerals in place - - Sales of minerals in place (1) (7) Production (138) (8,306) ------------------------------------------------------------------ December 31, 1999 4,160 246,979 Revisions in prior estimates 221 9,134 Extensions, discoveries and other additions 661 29,193 Purchases of minerals in place 215 945 Sales of minerals in place (518) (4,784) Production (400) (26,746) ------------------------------------------------------------------ December 31, 2000 4,339 254,721 Revisions in prior estimates (536) (28,233) Extensions, discoveries and other additions 1,198 33,397 Purchases of minerals in place 3 936 Sales of minerals in place - (276) Production (493) (27,578) ------------------------------------------------------------------ December 31, 2001 4,511 232,967 ================================================================== Proved developed reserves August 31, 1999 2,540 175,771 December 31, 1999 2,451 169,060 December 31, 2000 2,495 182,052 December 31, 2001 2,723 161,725 ------------------------------------------------------------------ (T) DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED) Estimates of the standard measure of discounted future cash flows from proved reserves of oil and natural gas are shown in the following table. 104
Year Year Four Months Year Ended Ended Ended Ended December 31, December 31, December 31, August 31, 2001 2000 1999 1999 ------------------------------------------------------------------------------------------------------------------------ (Thousands of Dollars) Future cash inflows $ 669,328 $ 2,498,525 $ 632,751 $ 639,721 Future production and development costs 200,741 400,767 194,332 194,077 Future income taxes 119,864 742,505 62,533 53,442 ------------------------------------------------------------------------------------------------------------------------ Future net cash flows 348,723 1,355,253 375,886 392,202 10 percent annual discount for estimated timing of cash flows 149,101 599,370 149,527 161,156 ------------------------------------------------------------------------------------------------------------------------ Standardized measure of discounted future net cash flows relating to oil and gas reserves $ 199,622 $ 755,883 $ 226,359 $ 231,046 =========================================================================================================================
Future cash inflows are computed by applying year-end prices (averaging $19.84 per barrel of oil, adjusted for transportation and other charges, and $2.49 per Mcf of gas at December 31, 2001) to the year-end quantities of proved reserves. As of December 31, 2001, a portion of proved developed gas production in 2002 has been hedged. The effects of these hedges are not reflected in the computation of future cash flows above. 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 changes in standardized measure of discounted future net cash flow relating to proved oil and gas reserves are as follows:
Year Year Four Months Year Ended Ended Ended Ended December 31, December 31, December 31, August 31, 2001 2000 1999 1999 ---------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Beginning of period $ 755,883 $ 226,359 $ 231,046 $ 162,629 Changes resulting from: Sales of oil and gas produced, net of production costs (99,117) (51,962) (17,938) (50,120) Net changes in price, development, and production costs (825,483) 783,763 3,523 13,269 Extensions, discoveries, additions, and improved recovery, less related costs 50,353 102,607 9,981 37,379 Purchases of minerals in place 1,572 4,751 - 67,120 Sales of minerals in place (2,247) (5,761) (24) (9,326) Revisions of previous quantity estimates (136,171) 43,318 (8,454) 10,477 Accretion of discount 116,776 25,826 8,750 17,317 Net change in income taxes 345,485 (376,438) (6,174) (11,618) Other, net (7,429) 3,420 5,649 (6,081) ---------------------------------------------------------------------------------------------------------------------- End of period $ 199,622 $ 755,883 $ 226,359 $ 231,046 ======================================================================================================================
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable. 105 PART III. ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS, AND CONTROL PERSONS OF THE REGISTRANT (A) DIRECTORS OF THE REGISTRANT Information concerning the directors of the Company is shown in the 2002 definitive Proxy Statement which is incorporated herein by this reference. (B) EXECUTIVE OFFICERS OF THE REGISTRANT Information concerning the executive officers of the Company is included in Part I of this Form 10-K. (C) COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT Information on compliance with Section 16(a) of the Exchange Act is included in the 2002 definitive Proxy Statement which is incorporated herein by this reference. ITEM 11. EXECUTIVE COMPENSATION Information on executive compensation is shown in the 2002 definitive Proxy Statement, which is incorporated herein by this reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT (A) SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS Information concerning the ownership of certain beneficial owners is shown in the 2002 definitive Proxy Statement which is incorporated herein by this reference. (B) SECURITY OWNERSHIP OF MANAGEMENT Information on security ownership of directors and officers is shown in the 2002 definitive Proxy Statement which is incorporated herein by this reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Information on certain relationships and related transactions is shown in the 2002 definitive Proxy Statement, which is incorporated herein by this reference. 106 PART IV. ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (A) DOCUMENTS FILED AS A PART OF THIS REPORT (1) Exhibits (3)(a) 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)(b) Certificate of Merger of ONEOK, Inc. (Formerly WAI, Inc.) Filed November 26, 1997 (Incorporated by reference from Exhibit (1)(b) to Form 10-Q dated May 31, 1998). (3)(c) Amended Certificate of Incorporation of ONEOK, Inc., filed January 16, 1998 (Incorporated by reference from Exhibit (1)(b) to Form 10-Q dated May 31, 1998). (3)(d) Certificate of Merger of ONEOK, Inc., filed April 3, 1998. (3)(e) Certificate of Merger of ONEOK, Inc., filed April 28, 2000. (3)(f) Amendment to Certificate of Incorporation of ONEOK, Inc. filed May 23, 2001 (Incorporated by reference from Exhibit 4.15 to Registration Statement on Form S-3 filed July 18, 2001, Commission File No. 333-65392). (3)(g) By-laws of ONEOK, Inc., as amended (Incorporated by reference from Exhibit (3)(d) to the Company's Annual Report on Form 10-K for the year ended August 31, 1999). (3)(h) Registration Rights Agreement dated March 1, 2000, among the Company and the Initial Purchaser described therein (Incorporated by reference from the Registration Statement on Form S-4 filed March 13, 2000). (4)(a) 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 31, 1997, Commission File No. 333-27467). (4)(b) Certificate of Designation for Series C Participating Preferred Stock of ONEOK, Inc., filed November 26, 1997 (Incorporated by reference from Exhibit No. 1 to Form 8-A, filed November 26, 1997). NOTE: Certain instruments defining the rights of holders of long-term debt are not being filed as exhibits hereto pursuant to Item 601(b)(4)(iii) of Registration S-K. The Company agrees to furnish copies of such agreements to the SEC upon request. (4)(c) Rights Agreement, dated November 26, 1997, between ONEOK, Inc. and Liberty Bank and Trust Company of Oklahoma City, N.A., as Rights Agent (Incorporated by reference from Exhibit 2.3 to Amendment No. 3 to Registration Statement on Form S-4 filed August 31, 1997, Commission File No. 333-27467). (4)(d) Shareholder Agreement, dated November 26, 1997, between Western Resources, Inc. and ONEOK, Inc. (Incorporated by reference from Exhibit 2.2 to Amendment No. 3 to Registration Statement on Form S-4 filed August 31, 1997, Commission File No. 333-27467). (4)(e) Indenture, dated September 24, 1998, between ONEOK, Inc. and Chase Bank of Texas 107 (Incorporated by reference from Exhibit 4.1 to Registration Statement on Form S-3 filed August 26, 1998). (4)(f) Indenture dated December 28, 2001, between ONEOK, Inc. and SunTrust Bank (Incorporated by reference Exhibit 4.1 to Post-Effective Amendment No. 1 to Registration Statement on Form S-3 filed December 31, 2001). (4)(g) 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)(h) 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)(i) 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)(j) 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)(k) Fifth Supplemental Indenture dated August 17, 1999, between ONEOK, Inc. and Chase Bank of Texas (Incorporated by reference from Exhibit 4 on Form 8-K filed August 17, 1999). (4)(l) Sixth Supplemental Indenture dated March 1, 2000, between ONEOK, Inc. and Chase Bank of Texas (Incorporated by reference from the Registration Statement on Form S-4 filed March 13, 2000, Commission File No. 333-32254). (4)(m) Seventh Supplemental Indenture dated April 24, 2000, between ONEOK, Inc. and Chase Bank of Texas (Incorporated by reference from Exhibit 4 to the Company's current report on Form 8-K filed April 24, 2000). (4)(n) Eighth Supplemental Indenture dated April 6, 2001, between ONEOK, Inc. and The Chase Manhattan Bank (Incorporated by reference from Exhibit 4.9 to Registration Statement on Form S-3 filed July 18, 2001, Commission File No. 333-65392). (10)(a) ONEOK, Inc. Long-Term Incentive Plan (10)(b) ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors (Incorporated by reference from the Form S-8 filed January 24, 2001). (10)(c) ONEOK, Inc. Supplemental Executive Retirement Plan as amended and restated February 21, 2002. (10)(d) Termination agreements between ONEOK, Inc., and ONEOK, Inc. Executives dated January 1, 1999 (Incorporated by reference from the Form 10-K dated August 31, 1999). (10)(e) Indemnification agreement between ONEOK Inc., and ONEOK Inc. Officers and Directors (Incorporated by reference from the Form 10-K dated August 31, 1999). (10)(f) ONEOK, Inc. Annual Officer Incentive Plan 108 (10)(g) ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan, as amended and restated February 15, 2001 (10)(h) 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)(i) First Amendment to Ground Lease between ONEOK Leasing Company and Southwestern Associates dated October 1, 1984 (Incorporated by reference from Form 10-K dated August 31, 1984). (10)(j) Sublease Between RMZ Corp. and ONEOK Leasing Company dated May 15, 1983 (Incorporated by reference from Form 10-K dated August 31, 1983). (10)(k) 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)(l) 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)(m) Private Placement Agreement ONEOK Inc. and Paine Webber Incorporated, dated April 6, 1993, (Medium-Term Notes, Series A, up to U.S. $150,000,000) (Incorporated by reference from Form 10-K dated August 31, 1993). (10)(n) Issuing and Paying Agency Agreement between Bank of America Trust Company of New York, as Issuing and Paying Agent, and ONEOK Inc, (Medium-Term Notes, Series A, up to U.S. $150,000,000) (Incorporated by reference from Form 10-K dated August 31, 1993). (10)(o) $850,000,000 364-Day Credit Agreement dated June 28, 2001, among ONEOK, Inc., Bank of America, N.A., as Administrative Agent and as a Lender, Letter of Credit Issuer and Swing Line Lender, Bank One, N.A. and First Union National Bank as Co-Syndicate Agents and ABN Amro Bank N.V. and Fleet National Bank as Co-Documentation Agents (Incorporated by reference from Form 10-Q dated June 30, 2001) (12)(a) Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirement for the years ended December 31, 2001 and 2000. (12)(b) Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirement for the four months ended December 31, 1999 and 1998 (Incorporated by reference from Form 10-K dated December 31, 2000). (12)(c) Computation of Ratio of Earnings to Fixed Charges for the years ended December 31, 2001 and 2000. (12)(d) Computation of Ratio of Earnings to Fixed Charges for the four months ended December 31, 1999 and 1998 (Incorporated by reference from Form 10-K dated December 31, 2000). (21) Required information concerning the registrant's subsidiaries. (23) Independent Auditors' Consent (99)(a) ONEOK, Inc. Direct Stock Purchase and Dividend Reinvestment Plan (Incorporated by reference from the Form S-3 filed January 30, 2001). 109 (2) Financial Statements Page No. (a) Independent Auditors' Report. 64 (b) Consolidated Statements of Income for the years ended 65 December 31, 2001 and 2000, August 31, 1999 and the four months ended December 31, 1999. (c) Consolidated Balance Sheets at December 31, 2001, 2000 66-67 and 1999. (d) Consolidated Statements of Cash Flows for the years 68 ended December 31, 2001 and 2000, August 31, 1999 and the four months ended December 31, 1999. (e) Consolidated Statements of Shareholders' Equity for the 69-70 years ended December 31, 2001 and 2000, August 31, 1999 and the four months ended December 31, 1999. (f) Notes to Consolidated Financial Statements. 71-105 (3) Financial Statement Schedules All schedules are omitted because of the absence of the conditions under which they are required. (B) REPORTS ON FORM 8-K November 14, 2001 - Filed the transcript of the conference call with analysts to discuss third quarter earnings. November 21, 2001 - Announced that the Company will ask the Oklahoma Supreme court to overturn an Oklahoma Corporation Commission order that unfairly denies the Company the right to collect $34.6 million in outstanding gas costs incurred to serve customers last winter. December 3, 2001 - Announced that the Company will take a charge of 18 cents per share of common stock in the fourth quarter as the result of an order from the Oklahoma Corporation Commission that unfairly denies the Company the right to collect outstanding gas costs incurred to serve customers last winter. December 3, 2001 - Announced that the Company's net exposure to Enron as of November 29, 2001 was less than $40 million pre-tax. December 21, 2001 - Announced revised earnings guidance for 2001. January 8, 2002 - Announced that the federal district court ruled that Southwest Gas Corporation cannot attempt to pursue its alleged $308 million claim against the Company. January 18, 2002 - Announced that the Company had been granted a waiver on a possible technical default related to various financing leases tied to the Company's Bushton processing plant. 110 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, on this 14th day of March 2002. ONEOK, Inc. Registrant By: /s/Jim Kneale ----------------------------------------- Jim Kneale Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer) 111 Signatures Pursuant to the requirements of Section 13 or 15(d) 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, on this 14th day of March 2002. /s/ David L. Kyle /s/ Beverly Monnet ---------------------------- ------------------------------------ David L. Kyle Beverly Monnet Chairman of the Board, Vice President, Controller and Chief Executive Officer Chief Accounting Officer and Director (Principal Accounting Officer) /s/ Edwyna G. Anderson /s/ Bert H. Mackie ---------------------------- ------------------------------------ Edwyna G. Anderson Bert H. Mackie Director Director /s/ William M. Bell /s/ Douglas A. Newsom ---------------------------- ------------------------------------ William M. Bell Douglas A. Newsom Director Director /s/ Douglas R. Cummings /s/ Gary D. Parker ---------------------------- ------------------------------------ Douglas R. Cummings Gary D. Parker Director Director /s/ John B. Dicus /s/ J.D. Scott ---------------------------- ------------------------------------ John B. Dicus J. D. Scott Director Director /s/ William L. Ford ---------------------------- ------------------------------------ William L. Ford Pattye L. Moore Director Director /s/ Douglas T. Lake ---------------------------- Douglas T. Lake Director 112