1 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 AUGUST 31, 1999. 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) <TABLE> <S> <C> OKLAHOMA 73-1520922 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation of organization) 100 WEST FIFTH STREET, TULSA, OK 74103 (Address of principal executive offices) (Zip Code) </TABLE> Registrant's telephone number, including area code (918) 588-7000 (Former name if changes since last report.) Securities registered pursuant to Section 12(b) of the Act: <TABLE> <S> <C> COMMON STOCK, WITH PAR VALUE OF $0.01 NEW YORK STOCK EXCHANGE (Title of Each Class) (Name of Each Exchange on which Registered) </TABLE> Securities registered pursuant to Section 12(g) of the Act: (Title of Each Class) 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 nonaffiliates as of August 31, 1999, was: Common stock of $959.3 million. On August 31, 1999, the Company had 30,884,225 shares of common stock outstanding. DOCUMENTS INCORPORATED BY REFERENCE: DOCUMENTS PART OF FORM 10-K
2 ONEOK, INC. 1999 ANNUAL REPORT ON FORM 10-K <TABLE> <CAPTION> PART I. PAGE NO. <S> <C> Item 1. Business 3 - 13 Item 2. Properties 13 - 15 Item 3. Legal Proceedings 16 - 20 Item 4. Results of Votes of Security Holders 21 PART II. Item 5. Market Price and Dividends on the Registrant's Common Stock and Related Shareholder Matters 22 Item 6. Selected Financial Data 22 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 23 - 36 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 37 - 38 Item 8. Financial Statements and Supplementary Data 39 - 65 Item 9. Changes in and Disagreements with Accountants 65 On Accounting and Financial Disclosures PART III. Item 10. Directors, Executive Officers, Promoters, and Control Persons of the Registrant 66 - 68 Item 11. Executive Compensation 68 - 70 Item 12. Security Ownership of Certain Beneficial Owners and Management 71 - 73 Item 13. Certain Relationships and Related Transactions 73 PART IV. Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 74 - 77 </TABLE> 2
3 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) (see Acquisitions and Mergers below) 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) engage in several aspects of the energy business. The Company purchases, gathers, compresses, transports, stores, and distributes natural gas. It also leases pipeline capacity to others. The Company drills for and produces oil and gas, extracts and sells natural gas liquids, and is engaged in the gas marketing business. The Company has begun wholesale marketing of electricity on a limited scale and has approval from the Company's Board of Directors for construction of a 300 megawatt electric power plant in Logan County, Oklahoma. In addition, the Company leases and operates a headquarters office building (leasing excess space to others) and owns and operates a related parking facility. As a regulated natural gas utility, the Company distributes natural gas to approximately 1.4 million customers in the states of Oklahoma and Kansas. The Company's operations are reported in the following segments: o Distribution o Transportation and Storage o Marketing o Gathering and Processing o Production o Other The Distribution segment provides natural gas distribution in Oklahoma and Kansas. The Company's operations in Oklahoma are conducted through Oklahoma Natural Gas Company Division (ONG) which serves residential, commercial, and industrial customers and leases pipeline capacity. ONG is regulated by the Oklahoma Corporation Commission (OCC). The Company's operations in Kansas are conducted through Kansas Gas Service Company Division (KGS) which serves residential, commercial, and industrial customers. KGS also conducts regulated gas distribution operations in northeastern Oklahoma. The Distribution segment serves 80 percent of Oklahoma and 67 percent of Kansas. KGS is regulated by the Kansas Corporation Commission (KCC) and the OCC. The Transportation and Storage segment provides natural gas transportation and storage services. These operations are conducted through ONEOK Gas Transportation, L.L.C. (OGT), ONEOK Sayre Storage Company (Sayre), Market Center Gathering, Inc., Mid Continent Market Center, Inc. (MCMC), Mid Continent Transportation, Inc. (MCTI), ONEOK Producer Services, Inc., and ONEOK Gas Storage, L.L.C (OGS). Some of the business units in this segment, OGT, OGS and Sayre, are currently regulated by the OCC, and MCMC and MCTI's operations are regulated by the KCC. In July, 1999, the OCC approved a plan for the removal of Oklahoma storage and gathering assets from utility regulation effective November 1, 1999. The Marketing segment markets natural gas to both wholesale and retail customers in the central part of the United States and leases gas storage from others with direct access to the west coast and the Texas intrastate market through ONEOK Gas Marketing Company (OGMC). It also conducts wholesale trading of electricity on a limited scale through ONEOK Power Marketing Company. The Gathering and Processing segment conducts gas gathering and gas processing activities in Oklahoma and New Mexico through ONEOK Gas Processing, L.L.C. and ONEOK Field Services Company. The Production segment produces natural gas and oil in several states including Oklahoma, Kansas and Texas through ONEOK Resources Company. 3
4 ONEOK Leasing Company which leases and operates a headquarters office building, and ONEOK Parking Company, which owns and operates a parking garage, comprise the significant operations of the Other segment. This Form 10-K (and certain other documents that are incorporated by reference in this Form 10-K) contains statements concerning Company expectations or predictions of the future that are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are intended to be covered by the safe harbor provision of the Securities Act of 1933 and the Securities Exchange Act of 1934. Forward-looking statements are based on management's beliefs and assumptions based on information currently available. It is important to note that actual results could differ materially from those projected in such forward-looking statements. Factors that may impact forward-looking statements include, but are not limited to, the following: o the effects of weather and other natural phenomena; o increased competition from other energy suppliers as well as alternative forms of energy; o the capital intensive nature of the Company's business; o economic climate and growth in the geographic areas in which the Company does business; o the uncertainty of gas and oil reserve estimates; o the timing and extent of changes in commodity prices for natural gas, natural gas liquids, electricity, and crude oil; o the nature and projected profitability of potential projects and other investments available to the Company; o conditions of capital markets and equity markets; o Year 2000 issues; o the effects of changes in governmental policies and regulatory actions, including income taxes, environmental compliance, authorized rates, and deregulation or "unbundling" of natural gas; o the pending merger with Southwest Gas Corporation (Southwest); and o regulatory delay or conditions imposed by regulatory bodies in, and the results of litigation involving, the Southwest merger. Accordingly, while the Company believes these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. When used in Company documents, the words "anticipate," "expect," "projection," "goal" or similar words are intended to identify forward-looking statements. The Company does not have any intention or obligation to update forward-looking statements after they distribute this Form 10-K even if new information, future events or other circumstances have made them incorrect or misleading. ACQUISITIONS AND MERGERS - On December 14, 1998, the Company entered into a merger agreement with Southwest Gas Corporation subject to shareholder and regulatory approvals. The Company agreed to pay $28.50 per share of common stock in cash. On February 1, 1999, Southern Union Company (Southern Union) made an unsolicited offer to purchase the Southwest shares for $32.00 in cash. Southern Union then signed a Confidentiality and Standstill Agreement with Southwest and completed its due diligence investigation. On April 25, 1999, the Board of Directors of Southwest rejected Southern Union's proposal as not being a superior proposal. Thereafter, the Company increased its price to $30.00 per share and the merger agreement was amended. Southern Union then increased its offer to $33.50 per share and intervened in a shareholders lawsuit in California state court in an effort to block the holding of a meeting of the Southwest shareholders to consider the merger with the Company. Southern Union brought an action in Nevada federal court to block the meeting and to block proceedings before the Arizona regulatory commission. Southern Union also intervened in the regulatory proceedings in California and Nevada. After Southern Union made statements in the public press that it intended to solicit proxies in opposition to the Company/Southwest merger in breach of the Confidentiality and Standstill Agreement, the Company (as third party beneficiary) filed an action in the Oklahoma federal courts. The court entered a temporary restraining order against Southern Union. It was later converted to a preliminary injunction requiring Southern Union to abide by terms of the Agreement. The issuance of the injunction is on appeal and efforts of Southern Union to have it lifted have been unsuccessful. 4
5 On July 19, 1999, Southern Union filed an action in the federal district court of Arizona in its further effort to block regulatory approval of the merger. Named as defendants in the case are the Company, Southwest, certain officers of the companies (including the Company's Eugene N. Dubay and John A. Gaberino, Jr.), a member of the Arizona Corporation Commission and a former employee of the Commissioner's staff. Southern Union alleges a scheme of "fraud and racketeering" by the companies and the individual defendants to block Southwest shareholders from voting on the Southern Union proposal and ensuring that only the merger with the Company would be considered. It also alleges a "secret campaign of deception, corruption and misrepresentation" by the defendants to influence the vote of the Arizona regulatory commission on the merger and to "mislead" the Board of Directors of Southwest. Southern Union further alleged that it was "fraudulently induced" to enter into the Confidentiality and Standstill Agreement. The complaint asks for $750 million 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 October 12, 1999, Southern Union filed an amended complaint asserting essentially the same claims as in the earlier complaint and named additional individual defendants (including the Company's Larry W. Brummett and James C. Kneale). The Company intends to file a motion to dismiss. On August 5, 1999, both the California state court and the Arizona federal court denied Southern Union's motions for temporary restraining orders. On August 10, 1999 the shareholders of Southwest approved the merger. The merger has been approved by the Public Utility Commission of Nevada. In California, a settlement document was filed with a 30-day comment period. No comments were filed and consideration is anticipated by year end. Upon approval by the California Commission, the only remaining regulatory commission required to approve the merger is the Arizona Corporation Commission where Southern Union is now directing its primary efforts to block the merger. At the Arizona Corporation Commission, consideration of the merger is in the procedural and discovery stage. Testimony has been filed and the staff is reviewing materials. At staff's request, a hearing on the merger has been delayed until February 11, 2000. Initially operating on the theory that the Company had funneled money through an Arizona law firm to a member of the Arizona Commission in order to influence improperly the Arizona regulatory proceedings, Southern Union attempted through discovery and other means to support their theory. Being unable to substantiate such claim, it was withdrawn in the Arizona federal court case. Southern Union has now shifted to a new theory that the Company intended to enter into an arrangement with a large national investment banking firm to funnel money to an individual who was formerly on the Commission's staff. The Company has denied that it has done anything illegal or improper in its efforts to obtain approval of the merger. It has categorically denied all substantive allegations against the Company in the complaint filed in the federal district court in Arizona. The Company intends to continue to defend vigorously the Company and its good reputation and continues to pursue regulatory approval for the merger. It is possible that Southern Union will continue its litigation against the Company, Southwest and the individual defendants claiming substantial damages. The merger cannot be consummated without all regulatory approvals. If such approvals are not obtained, or if not obtained in a timely manner, the merger agreement could be terminated by either the Company or Southwest which could result in further litigation. If, at the time of consummation of the merger, there are still outstanding claims against Southwest, those claims will become claims against the Company, as successor in the merger. If any of the plaintiffs should be successful in any of their claims against the Company or Southwest and substantial damages are awarded, it could have a material adverse effect on the Company's operations, cash flow and financial position. The Company believes the Southern Union allegations are without merit and is defending itself vigorously against all claims. During the 1998 fiscal year, the Company acquired from Western Resources, Inc. (Western) all of the gas distribution assets of Western and all of the outstanding capital stock of Western's directly or indirectly wholly-owned subsidiaries, Westar Gas Marketing, Inc. and MCMC, and assumed all of the liabilities of Western that arose 5
6 primarily out of the gas business and approximately $161 million in debt of Western. Western received 2,996,702 shares of the Company's Common Stock and 19,317,584 shares of the Company's Series A Convertible Preferred Stock. Such shares and additional shares purchased by Western represent in the aggregate 9.9 percent of the Common Stock and 45 percent of the capital stock of the Company. A shareholder agreement, which includes standstill provisions, prohibits Western from increasing its position in the Company above a capital stock interest of 45 percent and maintains control of the Company in the hands of the public shareholders of the Company. The transaction added 660,000 new distribution customers, 10,068 miles of pipeline, two gas processing plants with a 200 million cubic feet per day capacity, one of which has since been sold, and a natural gas marketing company with a retail market focus to the Company. The aggregate purchase price of $824 million was funded through the issuance to Western of a combination of preferred and common stock. The excess of the purchase price over the fair value of the net assets acquired approximated $74 million and is being amortized over 40 years. The Company's strategy is to acquire additional gas distribution and transmission facilities, gas producing properties, gas processing and gathering facilities or other assets which will further enhance its existing operations and will continue to pursue such opportunities in the future. The Company also from time to time sells assets when deemed less strategic or as other conditions warrant. ENVIRONMENTAL MATTERS - In connection with the Western transaction, the Company acquired responsibility for 12 manufactured gas sites located in Kansas which may contain coal tar and other 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 ten year period. At August 31, 1999, the costs of the investigations and risk analysis have been minimal. Limited information is available about the sites and no testing has been performed. Management's best estimate of the cost of remediation ranges from $100 thousand 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 their remediation costs through rates and the Company anticipates it will be allowed to recover such costs. 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, any material costs could adversely affect the Company's results of operations and cash flows depending on the degree of remediation required and number of years over which the remediation must be 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 the 1999 fiscal year totaled $456,000. There have been no material effects upon earnings or the Company's competitive position during the 1999 fiscal year related to compliance with these regulations. EMPLOYEES - The Company employed 3,252 persons at August 31, 1999. Nine hundred twenty-one employees of KGS are subject to collective bargaining contracts. The Company did not experience any strikes or work stoppages during 1999. The Company's current contracts with the Unions are as follows: <TABLE> <CAPTION> UNION EMPLOYEES CONTRACT EXPIRES ----- --------- ---------------- <S> <C> <C> United Steelworkers of America 515 June 6, 2002 International Union of Operating Engineers 19 June 6, 2002 Gas Workers Metal Trades of the United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada 13 June 6, 2002 International Brotherhood of Electrical Workers 374 July 1, 2003 </TABLE> 6
7 FINANCIAL AND STATISTICAL 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 K of Notes to Consolidated Financial Statements. DESCRIPTION OF BUSINESS SEGMENTS (A) DISTRIBUTION GENERAL - ONG distributes natural gas to wholesale and retail customers located in the state of Oklahoma. It also leases pipeline capacity under its Pipeline Capacity Lease (PCL) program to large volume commercial and industrial customers for their use in transporting natural gas to their facilities. ONG delivered natural gas to approximately 750,000 customers at August 31, 1999, located in 295 communities in Oklahoma. ONG's largest markets are the Oklahoma City and Tulsa metropolitan areas. ONG also sells natural gas and/or leases pipeline capacity to other local gas distributors serving 46 Oklahoma communities. ONG serves an estimated population of over 2 million. KGS supplies natural gas to retail customers in 389 communities in Kansas and Oklahoma with approximately 95 percent of those gas deliveries to Kansas customers. It also makes wholesale delivery to seventeen customers. KGS's largest markets served include Johnson County, Wichita, and Topeka, Kansas, and Bartlesville, Oklahoma. Of the Company's consolidated revenues, revenues from the Distribution segment represent approximately 49.7, 52.5, and 51.0 percent for 1999, 1998, and 1997, respectively. Operating income from the Distribution segment is 44.7, 54.9, and 51.5 percent of the consolidated operating income for 1999, 1998, and 1997, respectively. 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, as well as pipeline companies, gas processors, and other suppliers that own or control reserves. 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 third party companies to all of the major gas producing areas in the state. The Company's transmission system intersects with interstate pipelines, gas processing plants, and producing fields located throughout Oklahoma, allowing natural gas to be moved where needed across the state. Additionally, the Company's transmission system is directly connected to five gas storage fields that are operated by the Company and one non-operated gas storage field. ONG has awarded bids for gas supply for the 1999/2000 heating season with the majority of that supply to come from an affiliate, OGMC. On November 1, 1999, ONG issued bids for transportation and supply for two to five year terms beginning with the 2000/2001 heating season. KGS has transportation agreements for delivery of gas which have terms varying in length from one to twenty years with the following non-affiliated pipeline transmission companies: Williams Natural Gas Company ("WNG"), Kansas Pipeline Partnership, Panhandle Eastern Pipeline Company, and various other intrastate and interstate pipelines. Gas transported under these agreements represents approximately 80 percent of the total distribution system throughput. In October 1994, KGS executed a long-term gas purchase contract ("Base Contract") with Amoco Production Company ("Amoco") for the purpose of meeting the requirements of the customers served over the WNG pipeline system. The Company anticipates that the Base Contract will supply between 55 percent and 65 percent of KGS's demand served by the WNG pipeline system. Amoco is one of various suppliers over the WNG 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 Base Contract which is excess to the needs of the Company's residential and commercial customer base is also available for sale to other parties. 7
8 The remaining 20 percent of KGS's total distribution throughput is purchased from a combination of direct wellhead production, from the outlet of natural gas processing plants, and from natural gas marketers and production companies. The ONG rate schedule's "Order of Curtailment" and the KGS rate order's "Priority of Service" provide for first reducing or totally discontinuing gas service to the very 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. There is a surplus 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. CUSTOMERS - Residential and Commercial - ONG and KGS distribute natural gas as public utilities to approximately 80 percent of Oklahoma and 67 percent of Kansas. Natural gas sales to residential and commercial customers, which are used primarily for heating and cooking, account for approximately 65 and 29 percent of gas sales, respectively in Oklahoma and 74 and 25 percent of gas sales in Kansas, respectively. Gas sales to residential and commercial customers are seasonal, as a substantial portion of such gas is used principally for space heating. Accordingly, the volume of gas sales is consistently higher during the heating season (November through April) 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. A 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. A franchise 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. Although the laws of the states of Oklahoma and Kansas prohibit exclusive utility franchises, management nevertheless believes there are advantages to having franchises in the larger municipalities in which operations are conducted. ONG has franchises in 44 municipalities including Tulsa and Oklahoma City while KGS holds franchises in 315 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 - A substantial portion of the ONG system throughput is transported for industrial customers. Under the Company's PCL program, the customer, for a fee, can have its gas, whether purchased from ONG or a third-party supplier, transported to its facilities utilizing lines owned by ONG or its affiliates. PCL services are at negotiated rates which are generally below the approved PCL tariff rates, and competition continues to drive the rates lower. Industrial sales and rentals for PCL's tend to remain relatively constant throughout the year. As contracts with PCL customers expire and there is increased competition for the transportation of gas to these customers, some of the customers may be lost to third party transporters. The Transportation and Storage segment may gain some of this business which would result in a shift of some revenues from the Distribution segment to the Transportation and Storage segment. No single customer accounted for more than ten percent of consolidated operating revenues. KGS industrial sales account for less than one percent of natural gas delivered. KGS transports gas for its large industrial customers through it's End-Use Customer Transportation (ECT) program. This program allows industrial customers to purchase gas on the spot market and have it transported by KGS. The potential impact of the loss of a significant portion of this volume is discussed at Management's Discussion and Analysis of Financial Conditions and Results of Operations, Liquidity. COMPETITION - The natural gas industry is expected to remain highly competitive. Management believes that it must maintain a competitive advantage in order to retain its customers and, accordingly, continues to focus on reducing costs and pursuing unbundling opportunities. 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 cooking markets. The principal means to compete against 8
9 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 customers and for KGS customers than the average cost of gas nationwide and considerably less than the cost of an equivalent amount of electricity. The Company is subject to competition from other pipelines for its existing industrial load. The PCL program offered by ONG, in response to such competitive pressure, allows ONG to effectively compete in these markets and maintain throughput and therefore, load factors which benefit all customer classes. KGS, through the ECT program, is able to compete with other pipelines and continue to serve its large commercial and industrial customers. Competition, however, continues to lower rates. Unbundling is another response to competition. A competitive bidding system, made possible by the unbundling of services, and more customer choice provides the opportunity for lower costs for the consumer. GOVERNMENT REGULATIONS - Rates charged for gas services are established by the OCC for ONG and by the KCC and OCC for KGS. Gas purchase costs are included in the Purchased Gas Adjustment (PGA) clause. Other costs must be recovered through periodic rate adjustments approved by the OCC and KCC. A rate case will be heard by the OCC in early 2000 in Oklahoma. A joint stipulation between the Company and the OCC staff and approved by the OCC eliminated the interim rate case previously scheduled for summer of 1999 and provided for a one-time interim rate reduction of $5 million for residential customers in Oklahoma beginning September 1, 1999. A July 1999 order from the OCC removed the Oklahoma gathering and storage assets from utility regulation effective November 1, 1999. These assets are now included in the Transportation and Storage segment where they are being utilized in the competitive marketplace. The removal of the gathering and storage assets from rate base will result in a net reduction of revenues of $29.0 million on an annualized basis, based on the allocation of costs from the 1994 rate case. The Transportation and Storage and Marketing segments are aggressively seeking new business opportunities and have replaced a substantial portion of the revenues. Additionally, a charge to be collected through the PGA for ONG's current working gas in storage will replace a portion of the revenues. These revenue adjustments are subject to review in the current rate case. An August 1999 order from the OCC distinguished between upstream (transportation) and downstream (distribution) assets and cleared the way for future unbundling activities including competitive bidding for transportation services. A temperature adjustment clause, in effect for ONG customers since 1995, reduces the effect of extremes in weather for both the Company and the customer. In a step toward unbundling, in April, 1999, the KCC approved the reduction in the minimum requirement for transportation service to 3,000 Mcf annually. This will allow KGS to expand transportation services to an additional 650 commercial and industrial customers. The Company also requested and was granted approval to allow all school districts the choice of purchasing their gas supplies from a third party. This affects over 1,000 schools. Approval of the KCC has been received allowing the Company to expand the WeatherProof Bill program to all residential and commercial customers in Kansas. The program is designed to moderate the cost KGS customers pay for natural gas in cold weather months. Under this program, which was in effect as a pilot program during fiscal 1999, the Company used commodity derivative instruments to cap the price of its anticipated winter heating season gas purchases in order to protect customers and the Company from the upward volatility during the winter heating months. In connection with the Western transaction, KGS filed a stipulation which included an agreement not to file a general rate increase for three years. 9
10 The Company has settled all known claims arising out of long-term gas supply contracts containing "take-or-pay" provisions which 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 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 remaining gas purchase contracts. OkTex Pipeline Company transports gas in interstate commerce under Section 311(a) of the NGPA and is treated as a separate entity by FERC. The Company has the capacity to move up to 200 million cubic feet per day into the Lone Star Gas Company's system in Texas and the Red River Pipeline. OkTex has complied with the requirements of Order 636. (B) TRANSPORTATION AND STORAGE GENERAL - Five underground storage facilities are owned in Oklahoma and capacity is leased to third parties under various terms with capacity in the Sayre gas storage facility leased, on a long-term basis, to and operated by the Natural Gas Pipeline Company of America. The Company retains capacity in Sayre for its own use. MCMC stores gas in two company-owned underground storage facilities in Kansas. A $10 million expansion project for the Kansas underground storage is to be completed in 2000, and is expected to increase the storage capacity from 4.6 to 6.3 Bcf. A $3.4 million expansion is expected to increase deliverability from the Depew storage field by spring 2000. A $20 million expansion of the Kansas transmission system, to be completed fall of 2000, extends the system to the Bushton processing facility operated by KN Energy. This expansion shall provide for opportunities for increased throughput and supply support for Kansas core and non-core businesses. No major expansions were developed for the Oklahoma transmission system during 1999, but the Company continues to pursue opportunities associated with power plant projects. The transmission system transported 234.9 and 285.8 Bcf in Oklahoma for 1999 and 1998, respectively, and 72.8 and 54.2 Bcf in Kansas for 1999 and 1998, respectively. A small amount of gathering pipelines owned by the Company and connected to the Company's transmission pipelines are included in this segment. The Company's transportation system provides access to all major natural gas producing areas in the state of Oklahoma. The system intersects with ten interstate pipelines at 26 interconnect points, 23 gas processing plants, and approximately 130 producing fields effectively allowing gas to be moved throughout the state. Of the Company's consolidated revenues, revenues from the Transportation and Storage segment represent approximately 1.6, 1.0 and 0.5 percent for 1999, 1998 and 1997, respectively. Operating income from the Transportation and Storage segment is 28.1, 24.8, and 26.5 percent of the consolidated operating income for 1999, 1998, and 1997, respectively. GOVERNMENT REGULATIONS - Under a July, 1999, order by the OCC, the Company's gathering and storage assets and services in Oklahoma were removed from utility regulation effective November 1, 1999. Assets, including current gas in storage, of $325.0 million were removed from rate base and are now included in this segment where they will be utilized in the competitive market place to replace earnings. A portion of the return on rate base related to these assets will be recovered from the distribution customers through a charge to be collected through the PGA for maintaining current working gas in storage. In August, 1999, the OCC approved a plan that distinguishes between upstream and downstream assets and laid the groundwork for a bidding process for transportation services that began November 1, 1999. COMPETITION - The Transportation and Storage segment competes directly with the other intrastate and interstate pipelines and storage facilities within each of their respective states. With the unbundling of services ordered by the OCC and the related competitive bid process, this segment will be competing with other companies at market - based rates to provide service to the Distribution segment and to other customers. 10
11 CUSTOMERS - The Transportation and Storage segment serves the affiliated companies of the Distribution 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 both core and non-core consumers. PROPERTY ACQUISITIONS - In March, 1999, the Company acquired assets in Kansas which consisted of 111 miles of transmission pipelines. These assets enhanced transportation access to the Wichita, Kansas area. (C) MARKETING GENERAL - The Company purchases and markets natural gas, primarily in the central part of the United States and stores gas in facilities leased from others. Due to expanded supply and storage capabilities, the Company can now market to the west coast. The marketing operation has evolved from an intrastate aggregator into an interstate aggregator. Of the Company's consolidated revenues, revenues from the Marketing segment represent approximately 41.9, 41.0 and 39.6 percent for 1999, 1998, and 1997, respectively. Operating income from the Marketing segment is 11.8, 6.5, and 6.3 percent of the consolidated operating income for 1999, 1998, and 1997, respectively. MARKET CONDITIONS - In response to a very competitive baseload marketing environment, the Company's strategy is to concentrate its efforts toward capitalizing on day-to-day pricing volatility through the use of gas storage facilities leased from others, hedging, and transportation arbitraging. Management believes that its location in the heart of the natural gas producing area of the United States as well as the benefits derived from vertically integrating the gas marketing operations with the Company's production, gathering, processing, storage, and transportation businesses, will provide the strategic advantage necessary to compete successfully. NEW PRODUCTS AND SERVICES - The Company has received approval from its Board of Directors for construction of a 300 megawatt electric power plant expected to be in service in June, 2001. In 1998, the Company was granted a rate schedule by the FERC to trade electricity at market-based wholesale rates. This has begun on a limited scale in preparation for the plant start-up in 2001. In 1997, the marketing operation was the successful bidder to provide firm and interruptible gas service to four natural gas-fired electric generating plants owned by Public Service Company of Oklahoma. PRICE RISK MANAGEMENT - In order to mitigate the financial risks arising from fluctuations in both the market price and transportation costs of natural gas, the Company routinely enters into natural gas futures, swaps, and options as a method of protecting its margins on the underlying physical transactions. However, while not material, net open positions in terms of price, volume, and specified delivery point do occur. (D) GATHERING AND PROCESSING GENERAL - The Company owns and operates nine gas processing plants and has nonoperating interests in three gas processing plants in Oklahoma and New Mexico. The Company also owns the related gathering systems connected to these plants. The gas processing operation includes the extraction of natural gas liquids (NGLs) and the separation (fractionation) of mixed NGLs into component products (ethane, propane, iso butane, normal butane and natural gasoline). The component products are used for petrochemical feedstock, residential heating and cooking, and blending into motor fuels. The gathering operation consists of the pipeline system laid to producing wells as well as compression and dehydration services. The Company has compensated its gas suppliers for fuel and shrinkage costs in one of two ways, either by returning a percentage of the proceeds from the extracted NGL's to the supplier (a "percent of proceeds" contract) or by replacing an equivalent amount of gas (a "fuel and shrink" contract). Due to the volatility of the natural gas and NGL prices, "percent of proceeds" contracts generally provide a more stable cash flow. Of the Company's consolidated revenues, revenues from the Gathering and Processing segment represent approximately 3.9, 3.5 and 6.3 percent for 1999, 1998, and 1997, respectively. Operating income from the Gathering 11
12 and Processing segment is 7.5, 8.2, and 10.1 percent of the consolidated operating income for 1999, 1998, and 1997, respectively. PROPERTY ACQUISITIONS - On April 30, 1999, the Company acquired the midstream natural gas gathering and processing assets from Koch Midstream Enterprises for $285 million. These assets included eight gas processing plants and approximately 3,250 miles of gathering pipeline connected to 1,460 gas wells located in Oklahoma. Capacity of the gas processing plants is 515 million cubic feet per day bringing total capacity to 900 million cubic feet per day. The Company's share of the capacity is 650 million cubic feet per day. Through the Western transaction in 1998, the Company acquired an additional 34 percent interest in the Indian Basin gas processing plant. An eight percent interest in the Indian Basin plant had been acquired in fiscal 1997. RISK MANAGEMENT - Derivative instruments are used to minimize volatility in NGLs and natural gas prices. (E) PRODUCTION GENERAL - The Company's strategy is to concentrate ownership of natural gas and oil reserves in its service territory in order to add value not only to its existing production operations but also to integrate it into its processing, marketing, transmission, gathering, and storage business. As a result, the Company is focusing its efforts on acquisitions and exploitation activities. Of the Company's consolidated revenues, revenues from the Production segment represent approximately 2.5, 1.7 and 2.3 percent for 1999, 1998, and 1997, respectively. Operating income from the Production segment is 7.3, 5.7, and 6.5 percent of the consolidated operating income for 1999, 1998, and 1997, respectively. PRODUCING RESERVES - Natural gas is the primary focus of the Company's production activities. As of August 31, 1999, the Company had a working interest in 1,860 gas wells and 299 oil wells located primarily in Oklahoma, Kansas and Texas. A number of these wells produce from multiple zones. MARKET CONDITIONS - The goal of the Company is to develop an economically viable reserve base through acquisition and development. The Company is an operator of the reserve base, which it controls. In doing so, the Company competes with many large integrated oil and gas companies and numerous independent oil and gas companies of various size. The Company, following industry standards, monitors well head prices on a daily basis and, on occasion, has curtailed some of its natural gas production due to low well head prices. Most production is sold to third party marketers, including OGMC, at spot-market prices. PROPERTY ACQUISITIONS - During the second quarter of fiscal 1999, the Company consummated a strategic alliance with Magnum Hunter Resources, Inc. (Magnum) adding $10 million in producing properties and becoming a 31 percent equity owner in Magnum at a cost of $50 million. The Company also closed on two other acquisitions with a purchase price of $53 million adding reserves located in Oklahoma. Property acquisitions in fiscal 1998 included gas and oil reserves located in Oklahoma and Kansas purchased from OXY USA, Inc. Other fiscal 1998 acquisitions included a 40 percent equity interest in K. Stewart Petroleum Corp., an Oklahoma City based independent oil and gas producer and Washita Production Company (Washita), a Tulsa based independent oil and gas producer. During fiscal 1997, the Company purchased PSEC, Inc., an independent oil and gas company in Oklahoma. These acquisitions contribute to the Company's long-term strategy of focusing on natural gas reserves in Oklahoma and Kansas to add value to all of the Company's gas-related operations. RISK MANAGEMENT - The Company's production segment continues to utilize derivatives in order to hedge anticipated sales of oil and natural gas production. These anticipated transactions have been hedged with commodity swaps agreements whereby the Company is able to set the price to be received for the future production and thus 12
13 reduce the risk of declining market prices between the origination date of the swap and the month of production. The Company's strategy in hedging anticipated transactions is to eliminate the variability in earnings of its production segment as a result of market fluctuations. To the extent that management does not terminate a hedge or enter into an opposing derivative, the current strategy will limit the potential gains which could result from increases in market prices above the level set by the hedge. (F) 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. Almost all downtown Tulsa Class A office space is rented and very little Class A office space is available city-wide. As a result, Class A rental rates are increasing. ITEM 2. PROPERTIES (A) DESCRIPTION OF PROPERTY DISTRIBUTION The Company owned 15,152 miles of pipeline and other distribution facilities in Oklahoma and 10,184 miles of pipeline and other distribution facilities in Kansas at August 31, 1999. The Company owns a five-story office building in Oklahoma City, Oklahoma, as well as 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 vehicles used primarily in Oklahoma and maintains an inventory of spare parts, equipment, and supplies. It leases approximately 50 percent of its vehicles operated in Kansas. TRANSMISSION AND STORAGE The Company owned a combined total of 3,787 miles of transmission and gathering pipeline in Oklahoma and 1,668 miles in Kansas at August 31, 1999. 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 and two storage facilities in Kansas. Four of the Oklahoma storage facilities are located in close proximity to its large market areas; the other storage facility is located in western Oklahoma and is leased to and operated by another company. However, 21.4 billion cubic feet of storage capacity in that facility has been retained for use by the Company. GATHERING AND PROCESSING The Company owns and operates nine gas processing plants in Oklahoma and has operating interests in three gas processing plants and related gathering systems in Oklahoma and New Mexico. The total capacity of the plants the Company has an interest ownership in is 900 million cubic feet per day. The Company's share of the capacity is 650 million cubic feet per day. The Company owns approximately 3,250 miles of gathering pipeline in Oklahoma. PRODUCTION The Company owns varying economic interests, including working, royalty and overriding royalty interests, in 2,010 gas wells and 315 oil wells, some of which are multiple completions. Such interests are in wells located primarily in Oklahoma, Kansas, and Texas. The Company owns 184,754 net onshore developed leasehold acres and 41,466 net onshore undeveloped acres, located primarily in Oklahoma, Kansas, and Texas. The Company owns no offshore acreage. 13
14 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. OTHER The Company owns a parking garage and land, subject to a long-term ground lease expiring in year 2039 with six five-year extensions available, upon which has been constructed a seventeen-story office building with approximately 517,000 square feet of net rentable space. The office building is being leased to the Company at a lease term of 25 years 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 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 are located in the United States. QUANTITIES OF OIL AND GAS RESERVES - See Note Q of Notes to Consolidated Financial Statements. PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES - See Note R of Notes to Consolidated Financial Statements. RESERVE ESTIMATES FILED WITH OTHERS None. QUANTITIES OF OIL AND GAS PRODUCED The net quantities of oil and natural gas produced and sold, including intercompany transactions, were as follows: <TABLE> <CAPTION> Sales 1999 1998 1997 - ----- ------ ------ ------ <S> <C> <C> <C> Oil (MBbls) 460 330 336 Gas (MMcf) 27,773 16,818 14,565 </TABLE> AVERAGE SALES PRICE AND PRODUCTION (LIFTING) COSTS Average sales prices and production costs are as follows: <TABLE> <CAPTION> 1999 1998 1997 ------- -------- -------- <S> <C> <C> <C> Average Sales Price (a) Per Bbl of oil $ 13.56 $ 15.70 $ 19.84 Per Mcf of gas $ 2.12 $ 2.21 $ 2.16 Average Production Costs Per Mcfe (b) $ 0.49 $ 0.50 $ 0.48 </TABLE> (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 do not include depreciation or depletion. 14
15 WELLS AND DEVELOPED ACREAGE The table shows gross and net wells in which the Company has a working interest at August 31, 1999. <TABLE> <CAPTION> Gas Oil ----- ----- <S> <C> <C> Gross wells 1,860 299 Net wells 542 140 </TABLE> Gross developed acres and net developed acres by well classification are not available. Net developed acres for both oil and gas is 184,754 acres. UNDEVELOPED ACREAGE The gross and net undeveloped leasehold acreage at the end of the fiscal year is as follows: <TABLE> <CAPTION> Gross Net --------- ------- <S> <C> <C> Alabama 26 5 Colorado 5,748 1,050 Indiana 703 50 Kansas 7,457 4,987 Mississippi 2 1 Oklahoma 358,535 33,290 Texas 51,977 2,085 </TABLE> Of the net undeveloped acres, approximately 35.3 percent lies in the Anadarko Basin area, 12.9 percent in the Arkoma Basin area and 4.3 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, is as follows: <TABLE> <CAPTION> 1999 1998 1997 ------- -------- -------- <S> <C> <C> <C> DEVELOPMENT Productive 22.5 14.0 3.8 Dry 1.4 0.6 1.5 ------ ------ ----- Total 23.9 14.6 5.3 ====== ====== ===== </TABLE> PRESENT DRILLING ACTIVITIES On August 31, 1999, the Company was participating in the drilling of 20 wells. The Company's net interest in these wells amounts to 6.4 wells. FUTURE OBLIGATIONS TO PROVIDE OIL AND GAS None. 15
16 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 (Judge Russell), in the United States District Court for the Western District of Oklahoma. The complaint asserts claims to recover alleged underpayments of royalties to the United States as a result of improper measurement of heating contents and volumes of natural gas which was purchased from federally owned or Indian lands by ONEOK, Inc., ONEOK Resources Company, and Oklahoma Natural Gas Company (collectively the "Company"). This case is what is known as a qui tam action which was brought by the plaintiff relator on behalf of the United States and himself. The complaint asserts essentially the same claims that the same plaintiff relator, Jack J. Grynberg ("Grynberg"), asserted in a previous action (United States et rel. Jack J. Grynberg v. Alaska Pipeline Company, et al., No. 95-725-TFH, in the United States District Court for the District of Columbia) against the Company and approximately sixty-five other pipeline companies. In the case, on behalf of the United States, Grynberg seeks to receive the proceeds for the underpayment of royalties, interest, treble damages, civil penalties and $5,000 to $10,000 for each violation of the Act. Grynberg also seeks to receive his expenses incurred in bringing the action, plus attorney fees and costs. This case is one of 77 similar cases filed by Grynberg. Many of the allegations in the complaint are virtually identical in all 77 cases. In addition, Grynberg has asserted claims for underpayment of royalties based upon generalized allegations of use of a portable chromatograph, affiliate transactions, use of storage facilities to purchase gas in summer months, and improper deduction of costs. On or about May 6, 1999, Grynberg filed a motion with the Judicial Panel on Multidistrict Litigation asking that all 68 actions currently pending in 8 different federal district courts be transferred and consolidated for pretrial proceedings before a single district court in either Colorado or Wyoming. The Judicial Panel accepted the filing. A notice of appearance was filed with the Judicial Panel on behalf of the Company. The Company joined with the majority of the other defendants in filing a joint recommendation to the Panel and the defendants' brief in response to Grynberg's motion to transfer in which it was argued that if the cases are to be consolidated for pretrial proceedings before a single district court, it should be transferred to the United States District Court for the District of Wyoming. An order was obtained on July 9, 1999, staying the proceedings in the Western District of Oklahoma until thirty days after the Judicial Panel for Multidistrict Litigation ruled on Grynberg's motion to transfer and for consolidation. A hearing on the motion to transfer was held on September 24, 1999 and the motion was subsequently approved transferring all the cases to the federal district court in Wyoming for pretrial proceedings under multi- district litigations procedures. ONEOK, INC. V. SOUTHERN UNION COMPANY, No. 99-CV-0345-H(M), United States District Court for the Northern District of Oklahoma, on appeal of preliminary injunction, United States Court of Appeals for the Tenth Circuit, Case Number 99-5103. On May 5, 1999, the Company filed a complaint against Southern Union Company ("Southern Union") for breaching the February 21, 1999 confidentiality and standstill agreement between Southern Union and Southwest Gas Corporation ("Southwest"). The Company is a third party beneficiary. ONEOK also sought to enjoin Southern Union from breaching the confidentiality and standstill agreement and from taking any other wrongful actions to disrupt the proposed merger of the Company with Southwest. On May 11, 1999, the District Court granted a temporary restraining order enjoining Southern Union from any future violation of its confidentiality and standstill 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. The Tenth Circuit received Southern Union's filing on May 18, 1999 and issued an order staying the injunction for the sole purpose of permitting Southern Union the opportunity to oppose Southwest's motion to transfer a related California lawsuit to the Northern District of Oklahoma and to file a motion to remand the same California lawsuit to the San Diego Superior Court. Southern Union subsequently filed supplements to its motion for stay seeking the opportunity to participate in ongoing administrative proceedings before state public utility commissions, including proceedings in Arizona, California and Nevada. On June 10, 1999, the Tenth Circuit Court of Appeals denied Southern Union's request for a stay of the District Court's injunction insofar as it pertains to state public utility commission proceedings. On June 9, 1999, Southern Union filed a motion with the Northern District of Oklahoma to dismiss the lawsuit on the grounds of lack of personal jurisdiction and improper venue and a motion to transfer the Oklahoma action to the District of Nevada (where Southwest is asserting claims against Southern Union similar to those being asserted against Southern Union by the Company), or alternatively to stay the Oklahoma 16
17 action pending the final disposition of the Nevada action. On July 19, 1999, the defendant, Southern Union, filed with the District Court a motion to vacate preliminary injunction and to suspend preliminary injunction based on newly discovered evidence alleged by the defendant to show a conspiracy between the plaintiff, ONEOK, and Southwest to corrupt the regulatory process so as to influence the Southwest Board of Directors to approve ONEOK's proposed merger and reject Southern Union's offer to acquire Southwest. A hearing on the issue of jurisdiction of the District Court to hear the motion to vacate while the order was pending on appeal to the Court of Appeals for the Tenth Circuit was held on July 23, 1999. By order dated July 23, 1999, the District Court determined that it lacked jurisdiction to modify the preliminary injunction as requested by the defendant, and the motion was denied. On August 2, 1999, ONEOK filed an amended complaint with the District Court and a motion for a contempt citation. The amended complaint added a claim for abuse of process stating that Southern Union's actions in filing the Arizona compliant (see Southern Union case below) were conducted with malice and intention to oppress ONEOK and as a result of such intentional wrongful conduct, Southern Union is liable for exemplary damages as a means of punishment and deterrence. The motion alleges that despite the preliminary injunction issued by the District Court against Southern Union, Southern Union and persons acting in concert with Southern Union have continued efforts to derail the ONEOK-Southwest merger at a critical time in the shareholder and regulatory process. On August 3, 1999, ONEOK filed a request for immediate hearing on its application for contempt citation and for an order specifically enjoining Southern Union and persons acting in concert from proceeding with the motion for temporary restraining order and preliminary injunction before the Arizona Court. A status hearing was held on August 11, 1999. On August 25, 1999, the Court denied Southern Union's motion to dismiss for lack of personal jurisdiction and motion to transfer to the District of Nevada. Southern Union was required to and did file its answer to the complaint on September 7, 1999, withdrawing its specific allegations of wrongdoing in its initial filing. In addition, Southern Union filed counterclaims against ONEOK for: (1) a declaratory judgment for fraud in the inducement and breach of the Letter Agreement; (2) a declaratory judgment for revocation of the Letter Agreement; (3) breach of the Letter Agreement and a declaratory judgment as to its non-enforceability; and (4) breach of the covenant of good faith and fair dealing. Southern Union seeks to recover damages in excess of $75,000. On August 26, 1999, ONEOK filed a motion for an emergency hearing regarding the preliminary injunction. On August 30, 1999, the Court held a hearing and took the matter under advisement. On August 31, 1999, the Court issued an order requiring Southern Union to file documents with the Court concerning its communications with the Arizona Corporation Commission. ONEOK has filed additional briefs supporting its motion. Southern Union filed additional briefs with the Tenth Circuit seeking a stay of the preliminary injunction based upon events in the other pending actions, including the subsequent remand of the Klein case. On August 23, 1999, the Tenth Circuit denied Southern Union's motion for a stay of the preliminary injunction which should leave it in place until final determination of the appeal. All briefs have been filed by the parties on the appeal as of September 1, 1999, and the appeal is awaiting decision by the Tenth Circuit. On October 12, 1999, ONEOK filed a motion to dismiss the counterclaims asserted by Southern Union in the District Court. On October 15, 1999, the District Court denied ONEOK's motion to file an amended complaint. On October 27, 1999 ONEOK filed a motion to reconsider which was denied November 4, 1999. On November 4, as a result of ONEOK's motion to dismiss, Southern Union filed an amended answer and counterclaims. In a related matter, on December 15, 1998, the case of KLEIN V. SOUTHWEST GAS CORPORATION, Superior Court of San Diego County, California, Case No. 726615, was filed as a class action against Southwest and its directors. The amended complaint alleges breach of fiduciary duty, duty of loyalty, due care, candor, good faith and fair dealing seeking to enjoin the merger between the Company and Southwest, a rescission of the merger agreement, the implementation of an auction or similar process for sale of Southwest and the voiding of the $30 million termination fee under the merger agreement. On May 4, 1999, Southern Union intervened seeking a decision that it was entitled to solicit Southwest's shareholders concerning approval of its proposed merger, rescission of a portion of the confidentiality and standstill agreement and a temporary restraining order and preliminary injunction to prevent Southwest from conducting a proxy solicitation in support of the merger during the pendency of the litigation. The case was removed to the United States District Court for the Southern District of California (Case No. 99-1004- IEG(CGA)). Southwest filed motions to dismiss the shareholder and Southern Union cases or alternatively to transfer the case to the Northern District of Oklahoma. The Shareholders' motions were heard on September 7, 1999 and August 23, 1999, respectively. Southern Union also filed a motion to remand. On June 9, 1999, Southwest signed a Memorandum of Understanding with shareholders' plaintiff counsel to settle the case with all plaintiffs except 17
18 Southern Union. The Memorandum of Understanding sets forth the parties' agreement in principle settling all shareholders' claims and is subject to several conditions, including consummation of the merger and entry of final judgment of dismissal with prejudice that is binding on all shareholders from December 11, 1998 through the date that the shareholders approve the merger. On June 25, 1999, the Klein plaintiffs filed a third amended complaint and withdrew the motion to remand the case back to state court. On the same day, Southwest withdrew its motion to dismiss the Klein plaintiffs' claims and motion to transfer the case to Oklahoma as to the Klein plaintiffs. On August 3, 1999, the United States District Court remanded the case back to state court. Southern Union immediately filed a motion for a temporary restraining order seeking to delay the Southwest shareholders' meeting scheduled for August 10, 1999. A hearing was held on the motion on August 5, 1999 at which time the court denied the motion for a temporary restraining order. On September 3, 1999, the Court granted Southwest's motion to stay pending resolution of the federal court actions in Nevada and Arizona. On September 13, 1999, Southern Union requested an ex parte hearing on the order granting stay which was denied. However, the Court did allow Southern Union to file a 5-page brief on its request which appears to be a motion to reconsider the stay. Southwest was allowed and filed a response brief on September 22, 1999. On September 24, 1999, the Court dismissed the Southern Union action and stated that Southern Union could not refile until the federal court actions are complete. 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 Gas 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 M. Irvin ("Irvin") and Jack D. Rose ("Rose"). Southern Union alleges (1) that the action arises 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 alleges numerous causes of action including (1) racketeering in violation of 18 U.S.C. Section 1962(c) and 1962(d), 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, (2) fraud in the inducement, breach of contracts, 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 asks 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 dealings, 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. On August 2, 1999, Southern Union filed a motion with the district court for a temporary restraining order and preliminary injunction requesting, among other things, that ONEOK and Southwest be enjoined from participating in any regulatory approval procedures before the Arizona Corporation Commission or the California Public Utility Commission regarding approval of the pending ONEOK-Southwest Merger and from otherwise proceeding with or consummating the proposed merger. The motion was later modified to limit the request to the regulatory matters. A hearing was held on the motion on August 5, 1999 at which time the judge denied the motion for a temporary restraining order. On August 27, 1999, motions to dismiss the complaint for failure to state a cause of action were filed on behalf of ONEOK and the other defendants who had been served. Thomas R. Sheets with Southwest had previously been dismissed from the action. Rather than respond to the motion, on October 12, 1999, Southern Union filed an 18
19 amended complaint asserting the same claims as the earlier complaint. Larry Brummett and James C. Kneale were added as additional defendants. The Company has filed a new motion to dismiss. SOUTHWEST GAS CORPORATION MERGER. There are proceedings in process before the Arizona Corporation Commission, Public Utility Commission of California and the Public Utility Commission of Nevada requesting authorization to implement the Agreement and Plan of Merger, dated December 14, 1998, as amended. On July 1, 1999, the Public Utility Commission of Nevada issued an order approving the merger transaction. On July 30, 1000, a settlement conference was held and a settlement document filed in the merger approval proceeding before the Public Utility Commission of California. No comments were received during the 30-day comment period. The Company anticipates the California settlement will be considered for approval by year end. The Arizona Corporation Commission ("ACC") issued a procedural schedule on October 22, 1999 setting the application for merger approval for hearing on February 11, 2000. ONEOK, Southwest, the ACC staff and Arizona's consumer advocate have filed a stipulation and agreement recommending that the transaction be approved. JOINT APPLICATION OF OKLAHOMA NATURAL GAS COMPANY, A DIVISION OF ONEOK, INC., ONEOK GAS TRANSPORTATION COMPANY, A DIVISION OF ONEOK, INC., AND KANSAS GAS SERVICE COMPANY, A DIVISION OF ONEOK, INC., FOR APPROVAL OF THEIR UNBUNDLING PLAN FOR NATURAL GAS SERVICES UPSTREAM OF THE CITY GATES OR AGGREGATION POINTS, Cause PUD No. 980000177, before the Oklahoma Corporation Commission. On April 1, 1998, the Divisions filed a joint application to unbundle natural gas services upstream of the city gate. The following parties were granted intervention: Attorney General, Enogex, Inc., Public Service Company of Oklahoma, Transok, LLC, Williams Gas Pipelines Central, Inc., American Central Energy, LLC, Conoco, Inc., Oklahoma Industrial Energy Consumers, Williams Energy Services Company. A hearing was held on the merits before a Special Referee beginning July 6, 1998 and continuing through July 16, 1998. An Order was entered by the Commission on July 31, 1998. On August 6, 1998, a petition-in-error was filed with the Oklahoma Supreme Court appealing the order of the Commission. The Commission filed a motion to dismiss with the Oklahoma Supreme Court on August 17, 1998. The Commission issued an amended order on August 19, 1998, which the Company alleges is invalid due to the pending appeal. On September 1, 1998, the Company filed a response to the motion to dismiss of the Commission. On September 8, 1998, the Company filed a petition-in-error with the Oklahoma Supreme Court appealing the amended order. On October 5, 1998, the Oklahoma Supreme Court determined that the interim order was an appealable order and denied the motions to dismiss the appeal. In respect to the amended interim order, on October 22, 1998, the Oklahoma Supreme Court issued an order direction that the motion to dismiss the appeal filed by the Commission be withdrawn as moot and that the Company's motion to dismiss the petition was held in abeyance until the decision stage of the appeal. The Company filed its brief on April 19, 1999. On June 4, 1999, the Company and the Oklahoma Corporation Commission filed a joint motion in the Oklahoma Supreme Court to stay further appellate proceedings and for leave to proceed before the Commission. A joint stipulation was entered into and approved by the Oklahoma Corporation Commission. The joint stipulation established a process pursuant to which hearings would be conducted to identify the distribution, transmission, storage and gathering assets of ONEOK and to deregulate gathering and storage services if the Commission determines that competition exists for such services. The joint stipulation provides that the Company will dismiss its appeal upon the satisfaction of certain conditions. In light of the joint stipulation, the Company and the Commission Staff requested that the Supreme Court stay further appellate proceedings and allow the parties to proceed before the Commission. A stay was granted until August 31, 1999. On September 8, 1999, the Supreme Court granted a motion to further extend the stay until October 15, 1999, to allow the parties to work toward a resolution of the issues. On October 21, 1999, the Supreme Court granted a stay for an additional 20 days. As settlement had not been reached by the parties, the Company filed a motion to extend the stay until conclusion of the Commission proceeding. On November 2, 1999, the Supreme Court directed the parties to respond to its motion by November 17, 1999. Also on November 5, 1999, the commission staff filed a response to the motion and a motion to dismiss the appeal as moot. APPLICATION OF ERNEST G. JOHNSON, DIRECTOR OF THE PUBLIC UTILITY DIVISION, OKLAHOMA CORPORATION COMMISSION, TO REVIEW THE RATES, CHARGES, SERVICES AND SERVICE TERMS OF OKLAHOMA NATURAL GAS COMPANY, A DIVISION OF ONEOK, INC., AND ALL AFFILIATED COMPANIES AND ANY AFFILIATE OR NONAFFILIATE TRANSACTION RELEVANT TO SUCH INQUIRY, Cause PUD No. 980000683, Oklahoma Corporation Commission. On December 18, 1998, the Director of 19
20 the Commission's Public Utility Division filed an application on behalf of the Commission Staff to initiate a proceeding to review Oklahoma Natural's rates, charges, and services and any relevant affiliate and non-affiliate transactions, and to establish rates upon completion of such review. On May 13, 1999, the Company and the Commission Staff entered into a joint stipulation, which was orally approved by the Commission on May 26, 1999. Pursuant to the joint stipulation, the rates to customers of Oklahoma Natural Gas Company and Kansas Gas Service Company would be reduced by $5 million, which would be in lieu of the interim hearing. The joint stipulation also set up a process for the resolution of other issues presented in this case and Oklahoma Natural Gas Company's rate case (Cause PUD No. 990000166), which is consolidated with this case, including whether utility rate regulation for gathering and storage services should be discontinued if competition is determined to exist. Oklahoma Natural Gas Company will competitively bid for gas supply for the 1999-2000 heating season, and will competitively bid for upstream transportation services this fall, with service to commence November 1, 2000. On June 16, 1999, however, the joint stipulation was rejected by the Commission. On July 1, 1999, the Company filed a motion to approve a new joint stipulation. The principal difference between the new stipulation and the prior joint stipulation is that the $5 million interim rate reduction would be credited to residential customers only on the September, 1999 billing. The stipulation was signed by the other parties to the proceeding except the Attorney General of the State of Oklahoma. The Corporation Commission issued an order approving the stipulation on July 9, 1999. The Attorney General filed for a writ of prohibition from the Oklahoma Supreme Court. On July 12, 1999, the Oklahoma Supreme Court denied the Attorney General's emergency motion to stay the Commission hearings pertaining to deregulation of the Company's gathering and storage assets. The hearings proceeded and the Commission issued an order on July 15, 1999, deregulating the gathering and storage assets effective November 1, 1999. Hearings were held on August 24 and 25, 1999, pursuant to the stipulation to identify and designate the Company's distribution and transmission assets. Subsequent to the hearing, a distribution and transmission stipulation was executed by Oklahoma Natural Gas Company, ONEOK Gas Transportation, L.L.C., Enogex, Transok and the Attorney General which designated assets as either upstream transmission assets or downstream distribution assets and addressed competitive bidding. The stipulation was approved unanimously by the Commission and an order issued August 30, 1999. On September 20, 1999, Oklahoma Natural Gas filed updated financial information and requested a $33.6 million rate increase. 20
21 ITEM 4. RESULTS OF VOTES OF SECURITY HOLDERS (A) MATTERS SUBMITTED TO A VOTE OF SECURITY HOLDERS No matter was submitted during the fourth quarter of the fiscal year covered by this report to a vote of the Company's security holders, through the solicitation of proxies or otherwise. (B) 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 their successors are duly elected. <TABLE> <CAPTION> NAME AND POSITION AGE BUSINESS EXPERIENCE IN PAST FIVE YEARS - ----------------- ----- -------------------------------------- <S> <C> <C> LARRY W. BRUMMETT 49 1997 to present Chairman of the Board of Directors and Chief Executive Officer Chairman of the Board 1994 to 1997 Chairman of the Board of Directors, President, and Chief Executive and Chief Executive Officer Officer - ------------------------------------------------------------------------------------------------------------------------------ DAVID L. KYLE 47 1997 to present President and Chief Operating Officer President of ONEOK 1995 to present Member of the Board of Directors and Chief Operating Officer 1994 to 1997 President and Chief Operating Officer of Oklahoma Natural Gas Company - ------------------------------------------------------------------------------------------------------------------------------ JOHN A. GABERINO, JR. 58 1998 to present Senior Vice President and General Council Senior Vice President 1994 to 1998 Stockholder, Officer and Director of Gable Gotwals Mock Schwabe Kihle and General Council Gaberino and predecessor firms - ------------------------------------------------------------------------------------------------------------------------------ JAMES C. KNEALE 48 1999 to present Vice President, Treasurer, and Chief Financial Officer (Principal Vice President, Treasurer, Financial and Accounting Officer) and Chief Financial Officer 1997 to 1999 President and Chief Operating Officer of Oklahoma Natural Gas Company (Principal Financial and 1996 to 1997 Vice President of ONEOK Resources Company Accounting Officer) 1995 to 1996 Vice President - Tulsa District of Oklahoma Natural Gas Company 1994 to 1995 Vice President - Accounting of Oklahoma Natural Gas Company - ------------------------------------------------------------------------------------------------------------------------------ BARRY D. EPPERSON 54 1997 to present Vice President, Controller, and Chief Accounting Officer Vice President, Controller, 1994 to 1997 Vice President - Accounting of Oklahoma Natural Gas Company and Chief Accounting Officer - ------------------------------------------------------------------------------------------------------------------------------ EUGENE N. DUBAY 50 1997 to present President and Chief Operating Officer of Kansas Gas Service Company President and Chief Operating 1996 to 1997 Vice President of Corporate Development Officer of Kansas Gas Service 1994 to 1995 Executive Vice President and Chief Operating Officer of Missouri Gas Company Energy - ------------------------------------------------------------------------------------------------------------------------------ EDMUND J. FARRELL 56 1999 to present President and Chief Operating Officer of Oklahoma Natural Gas Company President and Chief Operating 1997 to 1999 Vice President of ONEOK Gas Marketing Company Officer of Oklahoma Natural Gas 1996 to 1997 Vice President - Customer Services of Oklahoma Natural Gas Company Company 1995 to 1996 Vice President - Corporate Communications and Strategic Planning 1994 to 1995 President of Oklahoma Alliance for Manufacturing Excellence, Inc. - ------------------------------------------------------------------------------------------------------------------------------ </TABLE> 21
22 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 market prices of the Company's common stock for each fiscal quarter during the last two fiscal years were as follows: <TABLE> <CAPTION> 1999 1998 --------------------- ---------------------- HIGH LOW High Low -------- --------- -------- --------- <S> <C> <C> <C> <C> First Quarter $37 15/16 $ 29 15/16 $ 37 5/8 $31 3/16 Second Quarter $37 3/16 $ 26 $ 40 11/16 $33 3/8 Third Quarter $30 1/2 $ 24 1/2 $ 44 1/4 $34 5/8 Fourth Quarter $33 1/8 $ 29 3/16 $ 40 15/16 $29 3/4 </TABLE> (B) HOLDERS There were 11,485 holders of the Company's common stock at August 31, 1999. (C) DIVIDENDS Quarterly dividends declared on the Company's common stock during the last two fiscal years were as follows: <TABLE> <CAPTION> 1999 1998 ------ ------ <S> <C> <C> First Quarter $0.31 $ 0.30 Second Quarter $0.31 $ 0.30 Third Quarter $0.31 $ 0.30 Fourth Quarter $0.31 $ 0.30 </TABLE> Debt agreements pursuant to which the Company's outstanding long-term and short-term debt has been issued limit dividends and other distributions on the Company's common stock. Under the most restrictive of these provisions, $50.1 million of retained earnings is so restricted. On August 31, 1999, $251.4 million was available for dividends on the Company's common stock. ITEM 6. SELECTED FINANCIAL DATA Following are selected financial data for the Company for each of the last five years. <TABLE> <CAPTION> 1999 1998 1997 1996 1995 --------- -------- -------- -------- -------- (Millions of Dollars, except per share amounts) <S> <C> <C> <C> <C> <C> Operating Revenues $ 1,842.8 $1,820.8 $1,161.9 $1,218.8 $ 954.2 Operating income $ 219.6 $ 188.8 $ 128.1 $ 115.2 $ 105.2 Net income $ 106.4 $ 101.8 $ 59.3 $ 52.8 $ 42.8 Total assets $ 3,024.9 $2,422.5 $1,237.4 $1,219.9 $1,181.2 Long-term debt $ 837.0 $ 329.3 $ 347.1 $ 351.9 $ 363.9 Diluted earnings per share $ 2.06 $ 2.23 $ 2.13 $ 1.93 $ 1.58 Dividends per common share $ 1.24 $ 1.20 $ 1.20 $ 1.18 $ 1.12 Percent of payout 60.2% 53.8% 56.2% 61.1% 70.9% Ratio of earnings to fixed charges 4.06X 5.50x 3.51x 3.28x 2.70x Ratio of earnings to combined fixed charges 1.93X 2.52x 3.48x 3.24x 2.67x and preferred stock dividend requirements </TABLE> 22
23 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS This Form 10-K (and certain other documents that are incorporated by reference in this Form 10-K) contains statements concerning Company expectations or predictions of the future that are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are intended to be covered by the safe harbor provision of the Securities Act of 1933 and the Securities Exchange Act of 1934. Forward-looking statements are based on management's beliefs and assumptions based on information currently available. It is important to note that actual results could differ materially from those projected in such forward- looking statements. Factors that may impact forward-looking statements include, but are not limited to, the following: o the effects of weather and other natural phenomena; o increased competition from other energy suppliers as well as alternative forms of energy; o the capital intensive nature of the Company's business; o economic climate and growth in the geographic areas in which the Company does business; o the uncertainty of gas and oil reserve estimates; o the timing and extent of changes in commodity prices for natural gas, natural gas liquids, electricity, and crude oil; o the nature and projected profitability of potential projects and other investments available to the Company; o conditions of capital markets and equity markets; o Year 2000 issues; o the effects of changes in governmental policies and regulatory actions, including income taxes, environmental compliance, authorized rates, and deregulation or "unbundling" of natural gas business; o the pending merger with Southwest Gas Corporation (Southwest); and o regulatory delay or conditions imposed by regulatory bodies in, and the results of litigation involving, the Southwest merger. Accordingly, while the Company believes these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. When used in Company documents, the words "anticipate", "expect", "projection", "goal", or similar words are intended to identify forward-looking statements. The Company does not have any intention or obligation to update forward-looking statements after they distribute this Form 10-K even if new information, future events or other circumstances have made them incorrect or misleading. OPERATING ENVIRONMENT AND OUTLOOK Management believes changes in the natural gas business have and will continue to significantly affect the manner in which natural gas and related services are marketed. Through a strategic review of its business and of ongoing developments in the natural gas distribution and energy related industry regarding competition, regulation, and consolidation, management concluded that the domestic natural gas business was undergoing a process of deregulation which would lead, over the next several years, to "unbundling" of services at the residential level. Management further concluded that markets for electricity and natural gas were converging and consolidating and that these trends and competition for customers would alter the structure and business practices of companies serving these markets in the future. In order to better position the Company competitively, management determined that it should seek both to expand its current operations and to become a provider of energy services not limited to natural gas through acquisitions or strategic alliances with companies that would enhance and expand its natural gas distribution, marketing, production, gathering, processing and transportation business. In a step toward this goal, ONEOK Power Marketing has begun construction of a $90 million electric generation plant. Gas powered and located near one of the Company's underground gas storage facilities, the plant will be designed to provide peaking capacity. 23
24 The Company continues to take steps to strengthen its competitive edge and position it to be a leader in the industry. The pending merger of the Company and Southwest is another of these steps. The merger will create the largest stand-alone gas distribution company in the United States serving 2.6 million customers in five states. The transaction is expected to be completed during 2000, subject to various conditions including regulatory approvals. Southwest shareholders approved the agreement on August 10, 1999. The Company and certain of its officers as well as Southwest have been named as defendants in a lawsuit brought by Southern Union Company in connection with the proposed acquisition in the total amount of $750 million. 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 Company, as third party beneficiary, has filed a lawsuit against Southern Union for breach of a confidentiality agreement with Southern Union and Southwest. The parties are presently involved in discovery. The Company believes the Southern Union allegations are without merit and is defending itself vigorously against all claims. As a result of the acquisition of the gas business of Western Resources, Inc. (Western) November, 1997, the Company became the eighth largest natural gas distributor in the country serving approximately 1.4 million customers in two states. The Company continues to increase its investment in hydrocarbon reserves in its service territory, focusing on exploitation activities rather than exploratory drilling, and has increased its ownership of gathering and processing facilities in areas where it owns significant natural gas production and development acreage. The Company anticipates growth through acquisition opportunities that will add value to all of the Company's operations. The Company also sells assets from time to time when deemed less strategic or as other conditions warrant. OPERATING HIGHLIGHTS UNBUNDLING - Unbundling has the potential to enhance customer choices, provide savings to consumers, increase throughput, and allow broader use of the Company's assets. In January, 1998, the Oklahoma Corporation Commission (OCC) approved rule-making for the restructuring of Oklahoma's natural gas utility industry. Under the rules, the Company is required to unbundle its upstream (transportation) activities. During the fourth quarter of fiscal 1999, the OCC approved a plan distinguishing between upstream and downstream (distribution) activities, a plan which laid the groundwork for unbundling of services. Under a July, 1999, order by the OCC, certain of the Company's gathering and storage assets will be removed from utility regulation effective November 1, 1999. The Company has withdrawn its appeal to the Oklahoma Supreme Court related to the OCC's earlier unbundling order. The Company awarded bids for gas supply in Oklahoma for the 1999/2000 heating season. On November 1, 1999, the Company will issue bids for transportation and supply for two to five year terms beginning with the 2000/2001 heating season. In Kansas, the Company received approval from the Kansas Corporation Commission (KCC) in April, 1999 to reduce the minimum requirement for transportation service to 3,000 Mcf annually from 6,000 Mcf annually allowing more customers to choose their natural gas supplier. This will allow the Company to expand transportation services to an additional 650 commercial and industrial customers. The KCC also approved a proposal that would allow approximately 1,000 schools the opportunity to transport gas supplies. 24
25 CONSOLIDATED OPERATIONS <TABLE> <CAPTION> 1999 1998 1997 ----------- ----------- ----------- (Thousands of Dollars) FINANCIAL RESULTS <S> <C> <C> <C> Operating revenues $ 1,842,810 $ 1,820,758 $ 1,161,927 Cost of gas 1,156,024 1,220,009 725,960 ----------- ----------- ----------- Net Revenue 686,786 600,749 435,967 Operating costs 337,499 310,285 233,343 Depreciation, depletion, and amortization 129,704 101,653 74,509 ----------- ----------- ----------- Operating income $ 219,583 $ 188,811 $ 128,115 =========== =========== =========== Other income $ 6,639 $ 14,644 $ -- =========== =========== =========== </TABLE> RESULTS OF OPERATIONS - The Company's operations showed gains for the year, despite weather which was warmer than normal. Operating income increased for all segments except Distribution in fiscal 1999. These increases reflect the effect of additional gas reserves acquired, additional gathering revenues from acquisitions, operational changes and efficiencies, general market conditions and an aggressive marketing campaign by the Company's gas marketing operation. For the year, operating income increased 16.3 percent over 1998. During 1998, the Company's operations showed strong gains for the year as a result of the Company's acquisition strategy and operating efficiencies achieved. Acquisition of the gas business from Western added $45 million to operating income for the last three quarters of fiscal 1998 despite a warmer than normal winter. The majority of this increase is reflected in the Distribution segment which increased $37.7 million (57.2 percent) over 1997. The Transportation and Storage segment and the Marketing segment also benefitted from the Western transaction. Other income of $14.6 million represents the gain on the sale of certain gas processing plants. RISK MANAGEMENT - To minimize the risk from fluctuations in the price of natural gas, oil, natural gas liquids (NGLs) and weather, the Company uses derivative instruments such as future contracts, swaps, and options (collectively, derivatives) to hedge existing physical gas inventory, purchase or sale commitments, and degree days. None of these derivatives are held for speculative purposes and, in general, the Company's risk management policy requires that positions taken with derivatives be offset by positions in physical transactions or other derivatives. KGS uses derivatives to hedge the cost of anticipated gas purchases during the winter heating months to protect its customers from upward volatility in the market price of natural gas. The gain or loss resulting from such derivatives is combined with the physical cost of gas and recovered from the customer through the gas purchase clause in rates. The Company's Production segment utilizes derivatives in order to hedge anticipated sales of oil and natural gas production. With the use of derivatives, the Company is able to set the price to be received for the future production thus eliminating the risk of declining market prices between the origination date of the derivative and the month of production. The Company's strategy in hedging anticipated transactions is to eliminate the variability in earnings of its Production segment as a result of market fluctuations. To the extent that management does not terminate a hedge or enter into an opposing derivative, the current strategy will limit the potential gains which could result from increases in market prices above the level set by the hedge. The Company adheres to policies and procedures which limit its exposure to market risks from open positions and monitors daily its exposure to market risk. The results of the Company's derivative trading activities continue to meet its stated objectives. For further discussion, see Item 7A - Quantitative and Qualitative Disclosures About Market Risk and Note C of "Notes to Consolidated Financial Statements." YEAR 2000. The Year 2000 (Y2K) issue arose because most computer systems, including application software (IT applications) and computer technology embedded in plant and equipment (Embedded Technology) were constructed using a two digit date field that assumed the first two digits are always "19". On January 1, 2000, these systems may 25
26 incorrectly recognize the date as January 1, 1900. Some IT applications and Embedded Technology may incorrectly process critical financial and operating information or stop processing altogether. Management, under the direction of the Board of Directors, has implemented a program to proactively address the Y2K challenge. Beginning in 1996, the Company inventoried existing programs and systems and began the conversion process that is designed to make the Company Y2K compatible. The Company installed a new IBM Year 2000 compatible mainframe computer in August 1997. The Company believes that it has fully identified and remediated its critical automated business systems and the sensitive equipment for Y2K readiness. Testing of the remediated systems and equipment is underway and will continue throughout the remainder of 1999. The Company has assessed its operational risks related to suppliers and vendors with whom it conducts business. Based on this assessment, the Company has completed the process of contacting suppliers and vendors with whom the Company conducts business concerning their state of readiness and plans to complete Y2K compatibility of their systems. The Company tests such third-party compliance to the extent deemed reasonable and necessary to determine compliance. The primary business risk associated with Y2K is the Company's ability to continue to transport and distribute gas to its customers without significant interruption. In the event the Company and/or its suppliers and vendors are unable to remediate the Y2K problem prior to January 1, 2000, operations of the Company could be significantly impacted. In order to mitigate this risk, the Company has developed contingency plans to continue operations through January 1, 2000 and beyond. The contingency plans include strategically located backup electric generators, alternative telecommunication systems, including cellular phones, radios and satellite phones, key personnel meeting sites and command centers, establishment of natural gas service curtailment and rerouting procedures, computer record backup systems and specific staffing for manual operation of key supply points. In May 1999, the Company completed the asset acquisition from Koch Midstream Enterprises. The Company contracted with an independent third party to inventory, assess, and remediate the assets acquired to assure Y2K compliance. This work has been completed and reviewed by the Company. The Company believes its essential systems and equipment are ready for the Year 2000 and should be able to provide uninterrupted service provided its key vendors and suppliers are Y2K ready. There can be no assurance that the Company's systems will work entirely as anticipated, or that the systems of other companies on which the Company relies, will be converted in a timely manner or that any such failure to be Y2K ready would not have a material adverse effect on the Company operations, liquidity and financial conditions. The Company's direct cost to date is approximately $1.7 million for Y2K conversion. This does not include the cost of programs and equipment that are being replaced in the ordinary course of business that are Y2K compatible. The Company estimates it will spend an additional $300,000 in direct costs. ACCOUNTING POLICIES - For the periods presented, certain operations of the Company are subject to accounting requirements of the OCC, KCC, and the provisions of Statement of Financial Accounting Standards No. 71 "Accounting for the Effects of Certain Types of Regulation." Accordingly, the allocation of costs and revenues to accounting periods for ratemaking and regulatory purposes may differ from those generally applied by companies not regulated. 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. Pursuant to the provisions of SFAS No. 71, the regulated operations of the Company have recognized regulatory assets of $246.7 million, of which $108.0 million is not currently being recovered in rates and has not been subject to filing and/or approval in a rate proceeding. As the Company continues to unbundle its services, certain of these assets will no longer meet the criteria for following SFAS No. 71, and accordingly, a write-off of regulatory assets and stranded costs may be required. The Company does not anticipate these costs will be significant. 26
27 SEGMENT OPERATIONS - The Company revised its presentation of business segment information beginning with this Form 10-K. The former regulated operations are now reported in two different segments; the Distribution segment and the Transportation and Storage segment. ONEOK Producer services is now reported in the Transportation and Storage segment rather than the Gathering and Processing operation as before. Transportation operations previously reported as part of the production operation and the marketing operation have been transferred to the Transportation and Storage segment. Prior periods have been restated to reflect these changes. The following segments characterize the Company's business units: o Distribution o Transportation and Storage o Marketing o Gathering and Processing o Production o Other DISTRIBUTION The Distribution segment provides natural gas distribution services in Oklahoma and Kansas. The Company's operations in Oklahoma are conducted through Oklahoma Natural Gas Company Division (ONG) which serves residential, commercial, and industrial customers and leases pipeline capacity. The Company's operations in Kansas are conducted through Kansas Gas Service Company Division (KGS) which serves residential, commercial, and industrial customers. KGS also conducts regulated gas distribution operations in northeastern Oklahoma. The Distribution segment serves about 80 percent of Oklahoma and about 67 percent of Kansas. ONG is subject to regulatory oversight by the OCC. KGS is subject to regulatory oversight by the KCC and the OCC. Assets of $972.6 million were acquired through the transaction with Western in the 1998 fiscal year. <TABLE> <CAPTION> 1999 1998 1997 --------- --------- --------- (Thousands of Dollars) FINANCIAL RESULTS <S> <C> <C> <C> Gas sales $ 848,813 $ 883,786 $ 544,884 Cost of gas 519,566 585,452 369,853 --------- --------- --------- Gross margin on gas sales 329,247 298,334 175,031 PCL and ECT revenues 58,037 60,658 38,103 Other revenues 17,100 19,384 12,118 --------- --------- --------- Net revenues 404,384 378,376 225,252 Operating costs 230,868 208,513 116,325 Depreciation, depletion, and amortization 75,443 66,214 42,980 --------- --------- --------- Operating Income $ 98,073 $ 103,649 $ 65,947 ========= ========= ========= 1999 1998 1997 --------- --------- --------- GROSS MARGIN PER McF Oklahoma Residential $ 3.04 $ 2.99 $ 2.94 Commercial $ 2.47 $ 2.40 $ 2.19 Industrial $ 1.23 $ 1.13 $ 0.95 Pipeline capacity leases $ 0.25 $ 0.24 $ 0.19 Kansas Residential $ 2.44 $ 2.24 - Commercial $ 1.81 $ 1.75 - Industrial $ 2.28 $ 1.92 - End-use customer transportation $ 0.49 $ 0.56 - ------- ------ ------ </TABLE> 27
28 <TABLE> <CAPTION> 1999 1998 1997 ---------- ---------- ---------- OPERATING INFORMATION <S> <C> <C> <C> Number of customers Oklahoma 748,445 739,684 733,621 Kansas 656,761 652,330 -- ---------- ---------- ---------- Total 1,405,206 1,392,014 733,621 ========== ========== ========== Capital expenditures (Thousands) Oklahoma $ 39,631 $ 41,059 $ 39,825 Kansas 59,054 36,139 -- ---------- ---------- ---------- Total $ 98,685 $ 77,198 $ 39,825 ========== ========== ========== Total assets (Thousands) $1,722,381 $1,771,999 $ 855,587 ========== ========== ========== Customers per employee Oklahoma 546 475 477 Kansas 510 489 -- ---------- ---------- ---------- </TABLE> OPERATIONAL HIGHLIGHTS - The Company dominates the core energy service markets in Oklahoma and Kansas with over a 90 percent market share for water heating, cooking, and home heating. Annual cost comparisons with electricity for these same services in Oklahoma and Kansas indicate that gas costs were at least 50 percent less, the largest difference being in home heating at 70 percent less. On a gas to gas comparison, the Company's rates in Oklahoma and Kansas were lower than the regional and national averages for residential, firm industrial, and interruptible service. The transaction with Western in the 1998 fiscal year added approximately 660,000 new distribution customers and 1,400 employees. Cost controls were strengthened throughout the organization. Total employees were reduced through attrition without compromising customer safety or service. REGULATORY INITIATIVES - In August, 1999, the OCC approved a plan to distinguish between upstream and downstream activities in Oklahoma. The Company began taking bids for transportation services this fall with bids to be awarded in spring 2000 for service beginning November 1, 2000. As contracts with PCL customers expire, these contracts may be renewed with the Distribution segment, the Transportation and Storage segment of the Company or nonaffiliated service providers. Consequently, this could result in reduced revenues in the Distribution segment. Two rate cases were combined in Oklahoma, eliminating an interim rate case scheduled for the summer of 1999 and providing for a one-time interim rate reduction beginning September 1, 1999 of $5 million for residential customers in Oklahoma. Hearings on the consolidated rate case are scheduled for spring 2000. In April, 1999, the Company received approval from the KCC to reduce the minimum requirement for transportation service to 3,000 Mcf annually from 6,000 annually allowing more customers to choose their natural gas supplier. The KCC also approved a proposal that would allow approximately 1,000 schools the opportunity to transport gas supplies. Also in 1999, approval was received to expand the Company's WeatherProof Bill program to all residential and commercial customers in Kansas. Customers electing to use this program will receive a set bill each month based on the customer's projected average usage. CAPITAL EXPENDITURES - The Company's capital expenditure program includes expenditures for extending service to new areas, 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 $19.8 million, $15.6 million and $10.4 million for new business development in 1999, 1998 and 1997, respectively. 28
29 OPERATING RESULTS - Fiscal 1999 was the first complete year of service to the 660,000 customers added in the Western acquisition. However, warmer than normal weather, particularly in Kansas which was 16 percent warmer than normal and where there is no temperature normalization, reduced net revenues and more than offset the effect of having a full twelve months of gas sales volumes and revenues. Operating costs and depreciation, depletion and amortization increased in fiscal 1999 due to having the acquisition recorded for one full year compared to nine months for fiscal 1998. Operating costs per customer on a weighted average basis decreased to $164.29 in fiscal 1999 from $169.67 in fiscal 1998. This is a decrease of $5.38 per weighted average customer or 3.2%. Net revenues and operating expenses increased in 1998 fiscal year over 1997 fiscal year primarily due to inclusion of KGS's operations in fiscal 1998. The statistics presented for the 1998 fiscal year include volumes attributable to KGS since December 1, 1997. 1999 1998 1997 ------- ------- ------ VOLUMES (MMcf) Gas sales Residential 105,566 103,700 58,241 Commercial 41,398 42,486 29,408 Industrial 5,575 7,304 11,384 PCL and ECT 212,547 241,262 173,134 ------- ------- ------- Total gas sales, PCL and ECT 365,086 394,752 272,167 ======= ======= ======= TRANSPORTATION AND STORAGE OPERATIONAL HIGHLIGHTS - A $10 million project to increase the capacity of the two storage fields in Kansas is scheduled for completion in 2000. Total storage capacity in Kansas will be increased by almost 40 percent to 6.3 Bcf. A $3.4 million expansion is expected to increase deliverability from the Depew storage field in Oklahoma by spring 2000. In 1998, work was completed which increased injection capabilities by 70 percent and increased withdrawal capabilities by over 80 percent in one Oklahoma storage field. In another Oklahoma storage field, the injection capabilities were increased by 50 percent and the withdrawal capabilities were doubled. 1999 1998 1997 --------- -------- -------- (Thousands of Dollars) FINANCIAL RESULTS Transportation revenues $ 73,521 $ 68,759 $ 68,167 Storage revenues 27,763 14,772 -- Other revenues 8,102 7,170 2,332 --------- -------- -------- Net revenues 109,386 90,701 70,499 Operating costs 33,894 31,052 28,136 Depreciation, depletion, and amortization 13,852 12,818 8,395 --------- -------- -------- Operating income $ 61,640 $ 46,831 $ 33,968 ========= ======== ======== 1999 1998 1997 --------- -------- -------- OPERATING INFORMATION Volumes transported (MMcf) 307,726 340,059 313,074 Current gas in storage (MMcf) 1,014 804 -- Capital expenditures (Thousands) $ 32,618 $ 50,271 $ 27,922 Total assets (Thousands) $ 373,742 $ 351,692 $221,233 --------- --------- -------- REGULATORY INITIATIVES - Under a July, 1999, order by the OCC, the Company's gathering and storage assets and services in Oklahoma will be removed from utility regulation effective November 1, 1999. Gathering and storage assets, including current gas in storage, of $325.0 million will be removed from rate base. In August, 1999, the OCC approved a plan that distinguishes between upstream and downstream assets. The Distribution segment issued bids for these services in the fall of 1999 with bids to be awarded in the spring of 2000. With unbundling and deregulation of gathering and storage service the Company will be able to compete for business at market-based rates. 29
30 OPERATING RESULTS - The Company's strategy to increase its storage utilization and its injection and withdrawal capabilities has created opportunities for increased earnings. In 1999,volumes transported decreased while prices increased and volumes stored, along with the related prices, increased in fiscal 1999 over fiscal 1998. Increased injection and storage capabilities led to the increase storage revenues. In fiscal 1998, margins from gas stored for others increased operating income by $14.8 million over fiscal 1997. In fiscal 1998, gas volumes transported increased but were offset by decreased prices. MARKETING OPERATIONAL HIGHLIGHTS - The Company's marketing operation purchases, stores and markets natural gas at both the retail and wholesale level, primarily in the producing areas of the United States. The Company continues to develop its niche into new market areas by arbitraging storage in the day trading market rather than focusing on the baseload market. Gas volumes increased in 1999 primarily from the Company's expansion into the Permian/Waha region of the United States. The Company now leases from others more than 29 Bcf of storage capacity which gives direct access to the west coast and Texas intrastate markets. Construction of a 300 megawatt electric power plant has been approved by the Company's Board of Directors. The plant, to be located in Logan County, Oklahoma, adjacent to a Company natural gas storage facility, will be configured to supply electric power during peak periods with four gas-powered turbine generators manufactured by General Electric. Application has been made with the Oklahoma Air Quality Board for a permit, and the plant is expected to be operational June, 2001. In 1997, the Company was the successful bidder to serve four gas-fired electric generating plants owned by Public Service Company of Oklahoma. <TABLE> <CAPTION> 1999 1998 1997 --------- --------- --------- (Thousands of Dollars) FINANCIAL RESULTS <S> <C> <C> <C> Gas sales $ 821,890 $ 774,455 $ 484,674 Cost of gas 789,955 758,687 470,878 --------- --------- --------- Gross margin on gas sales 31,935 15,768 13,796 Other revenues 3,508 4,159 (1,475) --------- --------- --------- Net revenues 35,443 19,927 12,321 Operating costs 9,069 7,024 3,707 Depreciation, depletion, and amortization 503 561 482 --------- --------- --------- Operating income $ 25,871 $ 12,342 $ 8,132 ========= ========= ========= 1999 1998 1997 --------- --------- --------- OPERATING INFORMATION Natural gas volumes (MMcf) 389,241 334,364 205,204 Capital expenditures (Thousands) $ 4,196 $ - $ 373 Total assets (Thousands) $ 273,491 $ 130,100 $ 64,190 --------- --------- --------- </TABLE> PRICE RISK MANAGEMENT - In order to mitigate the financial risks arising from fluctuations in both the market price and transportation costs of natural gas, the Company routinely enters into natural gas futures contracts, swaps, and options as a method of protecting its margins on the underlying physical transactions. However, while not material, net open positions in terms of price, volume, and specified delivery point do occur. For further discussion, see Item 7A - Quantitative and Qualitative Disclosures About Market Risk. OPERATING RESULTS - The increase in gross margins is attributable to increased throughput and a more extensive use of storage. Warmer than normal temperatures across the country during this year's winter resulted in significant downward movement in prices which allowed the Company to take advantage of volatility. Increased sales volumes are primarily due to the expanded niche business into Texas and the west coast. The increase in operating costs is due to the additional expenses related to leasing storage and start-up costs for ONEOK Power Marketing Company. The Company has been granted a rate schedule by the Federal Energy Regulatory Commission (FERC) to trade electricity at market-based wholesale rates and has begun trading on a limited scale. 30
31 The increase in gross margins in fiscal 1998 over fiscal 1997 is primarily attributable to increased throughput due to customers added in the Western transaction and the addition of service to four gas-fired electric generating plants. Gross margins per Mcf were lower due primarily to less volatility in weather in 1998. GATHERING AND PROCESSING OPERATIONAL HIGHLIGHTS - On April 30, 1999, the Company acquired the midstream natural gas gathering and processing assets from Koch Midstream Enterprises (Koch). These assets included approximately 3,250 miles of gathering pipeline connected to 1,460 gas wells located in Oklahoma gathering approximately 350 million cubic feet per day. Also included is a 100 percent interest in eight gas processing plants with a total capacity of 515 million cubic feet per day. These plants are currently processing about 280 million cubic feet per day. The Company will add a new 25 million cubic feet per day processing plant (the Fox Plant) which will be started up in the fall of 1999. Through the Western transaction in fiscal 1998, the Company acquired the Minneola Gas Processing Plant located in Kansas and an additional 34 percent interest in the Indian Basin Gas Processing Plant. An eight percent interest in the Indian Basin had been acquired in fiscal 1997. The Minneola Gas Processing Plant was sold to Duke in February, 1999. <TABLE> <CAPTION> 1999 1998 1997 -------- -------- -------- (Thousands of Dollars) <S> <C> <C> <C> FINANCIAL RESULTS Natural gas liquids and condensate sales $ 51,747 $ 59,668 $ 72,803 Gas sales 23,032 15,281 14,334 Gathering revenues 4,416 -- -- Other revenues 4,595 3,608 (65) --------- --------- -------- Total revenues 83,790 78,557 87,072 Cost of sales 52,479 53,162 63,895 --------- --------- -------- Gross margin 31,311 25,395 23,177 Operating costs 11,207 7,725 7,905 Depreciation, depletion, and amortization 3,562 2,249 2,393 --------- --------- -------- Operating income $ 16,542 $ 15,421 $ 12,879 ========= ========= ======== Other income $ 4,994 $ 14,644 $ -- ========= ========= ========= </TABLE> <TABLE> <CAPTION> 1999 1998 1997 -------- -------- -------- <S> <C> <C> <C> OPERATING INFORMATION Average NGL's price ($/Gal) $ 0.263 $ 0.302 $ 0.365 Average gas price ($/MMcf) $ 2.04 $ 2.30 $ 2.38 Capital expenditures (Thousands) $ 8,557 $ 4,735 $ 10,563 Total assets (Thousands) $ 343,133 $ 86,955 $ 46,602 Total gas gathered (Mcf/D) 229,255 219,971 231,010 Total gas processed (Mcf/D) 187,036 198,172 210,286 Natural gas liquids sales (MGal) 191,462 194,580 196,840 Gas sales (MMMbtu) 10,534 5,771 6,109 Natural Gas Liquids by Component (%) Ethane 47 42 51 Propane 26 31 25 Iso butane 5 4 5 Normal butane 9 10 9 Natural gasoline 13 13 10 Contracts % Percent of Proceeds (average for year) 65 54 17 Fuel and Shrink (average for year) 35 46 83 --------- --------- --------- </TABLE> Note: At August 31, 1999, with Koch acquisition, Percent of Proceeds contracts are 34%, Fuel and Shrink contracts are 66% of total gas processed. 31
32 CAPITAL EXPENDITURES - In April, 1999, the Company acquired all of the Oklahoma midstream natural gas gathering and processing assets of Koch for $285 million. Capital expenditures for fiscal 1999 included $3 million for the Fox plant. The 1998 fiscal year capital was required to sustain operations and projects related to these operations. Fiscal 1997 capital expenditures included $9 million incurred to purchase an interest in the Indian Basin Gas Processing Plant as well as sustain and improve operations. OPERATING RESULTS - Revenues increased in fiscal 1999 due to the acquisition of the midstream assets from Koch. Average NGL price per gallon increased in late fiscal 1999, although the average price for fiscal 1999 was lower than fiscal 1998, as prices continued to experience an upward correction from the abnormally low prices prevalent throughout much of fiscal 1999 and 1998. The increase in prices corresponded in time with the increase in volumes from the Koch acquisition. The price of NGLs moves in a direct relationship to crude prices. Operating costs and depreciation, depletion and amortization also increased due to the additional assets and the cost of operating those assets. At 1999 fiscal year end, total gas gathered and total gas processed were 688 MMcf per day and 561 MMcf per day, three times the fiscal 1999 average. This increase in the average per day is due to the Koch acquisition in April, 1999. Other income in fiscal 1999 and 1998 consisted of the gains on sales of assets. RISK MANAGEMENT - Derivative instruments are used to minimize risk of volatility in NGL's and gas prices. PRODUCTION OPERATIONAL HIGHLIGHTS - The Company's strategy is to concentrate ownership of hydrocarbon reserves in its service territory 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 recent acquisitions, the number of wells the Company operates has increased. In its role as operator, the Company controls operating decisions which impact production volumes and lifting costs. <TABLE> <CAPTION> 1999 1998 1997 -------- -------- -------- (Thousands of Dollars) <S> <C> <C> <C> FINANCIAL RESULTS Natural gas sales $ 58,776 $ 38,323 $ 33,715 Oil sales 6,169 5,192 6,663 Other revenues 4,309 367 137 -------- -------- -------- Net revenues 69,254 43,882 40,515 Operating costs 19,128 14,312 12,342 Depreciation, depletion, and amortization 34,073 18,872 19,899 -------- -------- -------- Operating income $ 16,053 $ 10,698 $ 8,274 ======== ======== ======== Other income $ 1,645 $ -- $ -- ======== ======== ======== </TABLE> <TABLE> <CAPTION> 1999 1998 1997 -------- -------- -------- <S> <C> <C> <C> OPERATING INFORMATION Proved reserves Gas (MMcf) 254,101 178,047 83,293 Oil (MBbls) 4,197 3,272 2,014 Production Gas (MMcf) 27,773 16,818 14,565 Oil (MBbls) 460 330 336 Average price Gas (Mcf) $ 2.12 $ 2.21 $ 2.16 Oil (Bbls) $ 13.56 $ 15.70 $ 19.84 Capital expenditures (Thousands) $ 95,431 $167,669 $ 32,911 Total assets (Thousands) $361,806 $282,765 $ 94,496 ======== ======== ======== </TABLE> 32
33 RISK MANAGEMENT - Since the volatility of energy prices has a significant impact on the profitability of this segment, the Company utilizes commodity derivative instruments in order to offset this risk. As of August 31, 1999, approximately 86 percent of anticipated gas production in 2000 has been hedged primarily with swap agreements. This compares to 50 percent of 1999 production hedged at August 31, 1998. See Item 7A - Quantitative and Qualitative Disclosure about Market Risk. CAPITAL EXPENDITURES - The Company's strategy is to concentrate ownership of natural gas and oil reserves in its service territory in order to add value not only to its existing production operations but also to integrate it into its processing, marketing, gathering and storage business. As a result, the Company is focusing its efforts on acquisitions and exploitation activities. During the second quarter of fiscal 1999, the Company consummated the strategic alliance with Magnum Hunter Resources, Inc. (Magnum) adding $10 million in producing properties and becoming a 31 percent equity owner in Magnum at a cost of $50 million. The Company also closed on two other properties with a purchase price of $53 million adding reserves located in Oklahoma. The Company purchased natural gas and oil reserves from OXY USA, Inc. (Oxy) in fiscal 1998. The reserves are located in Oklahoma and Kansas and include more than 400 wells. Net production is approximately 30 million cubic feet of gas per day and 400 barrels of oil per day and includes a gas sweetening plant. The purchase price was approximately $131 million. Based on estimated reserves, this transaction almost doubled the Company's oil and gas reserves. A 40 percent equity interest in the K. Stewart Petroleum Corp., was acquired on June 2, 1998. The acquisition creates opportunities to expand ownership of oil and gas reserves in the Anadarko Basin and for the Company to achieve its strategic objective of growing its reserves base in areas where it has other energy-related operations. The acquisition of Washita Production Company (Washita) was closed in December, 1997. This acquisition, valued at approximately $20 million, was made with a combination of cash and ONEOK, Inc. common stock. The transaction included 235 producing wells and significant behind pipe and development drilling opportunities with proven reserves of approximately 23 billion cubic feet equivalent. The wells are primarily located in the Anadarko and Arkoma Basin of Oklahoma and include some properties in the Hugoton Basin of Kansas. During 1997, the Company purchased PSEC, Inc. (PSEC), an independent oil and gas company in Oklahoma. The transaction included 180 wells with proven reserves of 20 Bcf of natural gas and 167,000 barrels of oil. A 42 percent interest in the Sycamore Gas Gathering System, acquired as part of this transaction, is included in the Gathering and Processing Segment. The purchase was financed with $9.3 million in long-term debt and 334,252 shares of ONEOK Inc. common stock. Capital expenditures primarily related to a limited developmental drilling program were approximately $13.7 million, $16.5 million, and $6.7 million in 1999, 1998, and 1997, respectively. OPERATING RESULTS - Increased production from a successful developmental drilling program and properties acquired during fiscal 1999 and 1998 were the primary reasons for the increases in volumes in those years. Gas prices for the 1999 fiscal year decreased compared to the 1998 fiscal year, an industry-wide trend. Operating costs and depreciation, depletion, and amortization also increased over one year ago due to the Company operating and owning an interest in an increased number of wells. However, the Company, through efforts to contain costs, reduced production costs per Mcf equivalent to $0.49 in 1999 from $0.50 in 1998. The increased gas production in 1998 over 1997 is primarily related to the additional proved reserves acquired as a result of the OXY, PSEC and Washita property acquisitions. Production from these properties more than offset the natural decline in production from other fields. The increase in operating costs in 1998 as compared to 1997 is indicative of the increase in the total number of fields owned by the Company. 33
34 LIQUIDITY AND CAPITAL RESOURCES In April, 1999, the Company registered a shelf filing for $500 million in debt securities. The filing allows the Company to sell the debt securities over a two year period. These funds will be used in the future for general corporate purposes including repayment and refinancing of debt, acquisitions, working capital, capital expenditures and repurchases and redemptions of securities. In August, 1999, the Company issued $300 million in debt securities under this shelf filing, with the funds used primarily to fund the Koch acquisition. In July, 1999, the Company filed a registration statement to register preferred trust securities of $300 million. No securities have been issued under that registration. A $600 million short-term unsecured revolving credit facility was entered into with several banks in July, 1999. CASH FLOW ANALYSIS Cash provided by operating activities continues as the primary source for meeting operating cash requirements and dividend payout. However, due to seasonal fluctuations and additional capital requirements, the Company periodically accesses funds through short-term credit agreements and, if necessary, through long-term borrowing. The Company believes that internally generated funds and existing credit agreements will be sufficient to meet its debt service, dividend payment, and capital expenditure requirements, excluding significant capital acquisitions. The following discussion of cash flows should be read in conjunction with the Company's "Consolidated Statement of Cash Flows" and the supplemental cash flow information included in Note M of "Notes to Consolidated Financial Statements." OPERATING CASH FLOWS Operating cash flows for fiscal 1999 decreased due to increased prepayments related to hedging activities, increases in unrecovered purchased gas cost, increased accounts receivables primarily due to increased sales and increased regulatory assets. Operating cash flows for 1998 as compared to 1997 are higher as a result of the liquidation of the abnormally high net working capital acquired in the Western acquisition, increased operating income and favorable changes in assets and liabilities, including recovery of purchased gas costs. Cash provided by operating activities for the years ended August 31, 1999, 1998, and 1997 was $131.6, $346.5, and $152.1 million, respectively. INVESTING CASH FLOWS Cash used in investing activities totaled $549.3, $299.7, and $88.8 million in 1999, 1998, and 1997 respectively. CAPITAL EXPENDITURES - Capital expenditures totaled $533 million in 1999. This included $285 million for the acquisition of Oklahoma midstream assets by the Gathering and Processing segment. In 1998, capital expenditures totaled $306 million which included $164 million for acquisition of production and processing assets. Capital expenditures totaled $112 million in 1997. Capital expenditures for 2000 are estimated to be $236 million excluding acquisitions. ASSET SALES - Approximately $16.5 million of proceeds was received in fiscal 1999 from the sale of one-half interest in Sycamore and the Caddo gas processing plant. In 1998, approximately $30 million of proceeds was received from the sale of gas processing assets. 34
35 FINANCING CASH FLOW During fiscal 1999, the Company issued $700 million in debt securities. These funds were used for general corporate purposes including acquisitions, repayment of some short-term debt and refinancing certain long-term debt. Cash provided by financing activities for 1999 was $422.0 million, cash used in financing activities in 1998 and 1997 was $61.1, and $49.4 million, respectively. SHORT-TERM DEBT - At August 31, 1999, $264 million in commercial paper was outstanding. The Company has a $600 million short-term unsecured revolving credit facility. The short-term credit agreement primarily provides a back-up line of credit for commercial paper in addition to providing short-term funds. Maximum short-term debt from all sources as approved by the Company's Board of Directors is $750 million. Fluctuations in the amount of cash provided by/used in financing activities is primarily a factor of short-term borrowing and the increase in preferred stock dividend requirements for 1999 and 1998 and significant long-term borrowing in 1999. LONG-TERM DEBT - At August 31, 1999, $837 million of long-term debt was outstanding. As of that date, the Company could have issued $724 million of additional long-term debt under the most restrictive provisions contained in its various borrowing agreements. At August 31, 1999, the equity component was 52 percent as compared to 68 percent a year ago. In December, 1997, Moody's Investors Service announced that it had upgraded the Company's debt rating from A3 to A2 due to the benefits expected from the acquisition of the gas business, including strengthened market and financial positions. The debt rating by Standard and Poor's Corporation was upgraded from A- to A. In December 1998, the Company was placed on CreditWatch with negative implications, reflecting the Company's plan to acquire Southwest. SOUTHWEST - Financing for the Company's proposed acquisition of Southwest is expected to be provided through a combination of a short-term bridge loan, long-term notes and equity. In addition, the Company will assume approximately $900 million of Southwest long-term indebtedness. STOCK AND DIVIDENDS - The Company had approximately 31 million shares of common stock outstanding at August 31, 1999. The Common stock dividends were $1.24, $1.20, and $1.20 per share in 1999, 1998, and 1997, respectively. Convertible preferred stock dividends were $1.86 and $1.55 per share in 1999, and $1.80 and $1.50 per share in 1998 for Series A and Series B, respectively. Preferred stock dividends were $1.78 per share in 1997. Through the Company's Stock Purchase and Dividend Reinvestment Program, $3.9 million, $4.1 million and $5.5 million of dividends and optional cash payments were reinvested into common stock in 1999, 1998 and 1997, respectively. On March 18, 1999, the Company authorized a stock buyback plan for up to 15 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. Purchases began May 25, 1999, with 715,080 shares purchased through August 31, 1999. The purchased shares will be held in treasury and will be available for general corporate purposes, funding of stock-based compensation plans, resale at a future date, or retirement. Purchases will be financed with short-term debt or made from available funds. LIQUIDITY The Distribution segment continues to face competitive pressure to serve the transportation market which includes all customers who consume 30,000 MMBtu or more annually. The loss of a substantial portion of that load due to third party bypass, without recoupment of the revenues from that loss, could have a materially adverse effect on the 35
36 Company's financial condition. However, since 1995, rates have been structured to reduce the Company's risk in serving its large volume customers. OTHER ENVIRONMENTAL - In connection with the Western transaction, the Company acquired responsibility for 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 ten year period. At August 31, 1999, the costs of the investigations and risk analysis have been minimal. Limited information is available about the sites and no testing has been performed. Management's best estimate of the cost of remediation ranges from $100 thousand 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. NEW ACCOUNTING PRONOUNCEMENTS - Statement of Financial Accounting Standards No. 133, Accounting for Derivatives Instruments and Hedging Activities (Statement 133), was issued by the FASB in June 1998. Statement 133 standardizes the accounting for derivatives instruments, including certain derivative instruments embedded in other contracts. Under the standard, entities are required to carry 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 hedge 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 gain or loss is reported in earnings immediately. Statement 133 required the Company to adopt this statement by September 1, 1999. Statement 133 was amended by Statement No. 137 in June, 1999 which delayed implementation until fiscal years beginning after June 15, 2000, with early adoption permitted. The Company has not determined the impact of adopting Statement 133. In December 1998, the Emerging Issues Task Force reached consensus on Issue 98-10, "Accounting for Contracts involved in Energy Trading and Risk Management Activities" (EITF 98-10). EITF 98-10 is effective for fiscal years beginning after December 15, 1998 and requires energy trading contracts to be recorded at fair value on the balance sheet, with the changes in fair value included in earnings. Although the Company has not completed its assessment of the impact of adopting EITF 98-10, it believes that its contracts are designated as and effective as hedges of non trading activities and are not considered energy trading contracts. Accordingly, the Company does not believe the adoption of EITF 98-10 will have a material impact on the financial position or results of operations of the Company. 36
37 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 to the impact of market fluctuations in the price of natural gas and oil. 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 gas marketing operation, and anticipated sales of oil and gas 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 and oil, the Company uses commodity derivative instruments such as future contracts, swaps and options to hedge existing or anticipated purchase and sale agreements, existing physical gas in storage, and basis risk. None of these derivatives are held for speculative purposes. The Company adheres to policies and procedures which limit its exposure to market risk from open positions and monitors its exposure to market risk. The results of the Company's derivative hedging activities continue to meet its stated objective. The Company's regulated distribution operations are exposed to market risk in the normal course of business operations due to the impact of fluctuations on gas sales resulting from weather as measured by heating degree days (HDD). Market risk refers to the risk of loss in cash flows and future earnings arising from adverse fluctuation in gross margins on gas sales. Kansas Gas Service has exposure arising from variances in gas consumption by residential and commercial customers caused by fluctuations in HDD from normal because it does not have a temperature adjustment clause in its rate structure. ONG has a TAC, which partially offsets this risk. From time to time, ONEOK uses weather derivative swaps to manage the effect of warm weather on its operations. All of the Company's long-term debt is fixed-rate and, therefore, does not expose the Company to the risk of earnings or cash flow loss due to changes in market interest rates. Kansas Gas Service 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. The gain or loss resulting from such derivatives is combined with the physical cost of gas and recovered from the customer through the gas purchase clause in rates. The Company has no market risk associated with such activities and, accordingly, these derivatives have been omitted from the value-at-risk disclosures below. VALUE-AT-RISK DISCLOSURE OF MARKET RISK - The estimation of potential losses that could arise from changes in market conditions is typically accomplished through the use of statistical models that seek to predict risk of loss based on historical price and volatility patterns. The value-at-risk (VAR) measurement used by the Company is based on J.P. Morgan's RiskMetrics(TM) model, which measures recent volatility and correlation in the price of natural gas and oil, pulls through current price levels and net deltas, and applies estimates made by management regarding the time required to liquidate positions and the degree of confidence placed in the accuracy of the volatility and correlation estimates. The Company's VAR calculation presents a comprehensive market risk disclosure by combining its commodity derivative portfolio used to hedge price and basis risk together with the current portfolio of firm physical purchase and sale contracts and nonutility gas-in-storage inventory. At August 31, 1999, 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, diversified correlation and assuming three days to liquidate positions is immaterial. The Company's calculated VAR exposure represents an estimate of potential losses that would be recognized for its portfolio of derivative financial instruments and firm physical contracts and nonutility gas-in-storage assuming hypothetical movements in future market rates and are not necessarily indicative of actual results that may occur. It 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 the market rates, operating exposures, and the timing thereof, and changes in the Company's portfolio of derivative financial instruments and firm physical contracts. Under the weather derivative swap agreements, the Company receives a fixed payment per degree day below the 37
38 contracted normal HDD and pays a fixed amount per degree day above the contracted normal HDD. The swaps also contain a contract cap that limits the amount either party is required to pay. The Company estimates its VAR exposure on these swaps to be the total contract cap it would be required to pay if the weather were significantly coder that normal. At August 31, 1999, the total VAR for the 1999/2000 heating season is approximately $17.7 million. The Company believes that this risk would be substantially offset by an increase in gas sales margins resulting from additional gas sold due to the colder than normal temperatures. 38
39 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING The management of ONEOK, Inc. is responsible for all information included in the Annual Report whether audited or unaudited. The financial statements have been prepared in accordance with generally accepted accounting principles, applied in a consistent manner, and necessarily included some amounts that are based on the best estimates and judgements of management. Management maintains a system of internal accounting policies, procedures, and controls designed to provide reasonable assurance that assets are safeguarded against loss or unauthorized use and that the financial records are reliable for preparing financial statements. ONEOK, Inc. maintains an internal auditing staff responsible for evaluating the adequacy and application of financial and operating controls and for testing compliance with management's policies and procedures. The accompanying consolidated financial statements of ONEOK, Inc. and subsidiaries as of August 31, 1999 and 1998, and for each of the years in the three-year period ended August 31, 1999, have been audited by KPMG LLP, independent certified public accountants. Their audits include reviews of the system of internal controls to the extent considered necessary to determine the audit procedures required to support their opinion on the consolidated financial statements. The Independent Auditors' Report appears herein. The Board of Directors performs its oversight role for reviewing the accounting and auditing procedures and financial reporting of ONEOK, Inc. through its Audit Committee. Both KPMG LLP and the Company's internal auditors have free access to the Audit Committee, without the presence of management, to discuss accounting, auditing, and financial reporting matters. 39
40 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 August 31, 1999 and 1998, and the related consolidated statements of income, shareholders' equity, and cash flows for each of the years in the three-year period ended August 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 generally accepted auditing standards. 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 August 31, 1999 and 1998, and the results of their operations and cash flows for each of the years in the three-year period ended August 31, 1999, in conformity with generally accepted accounting principles. KPMG LLP Tulsa, Oklahoma October 21, 1999 40
41 ONEOK, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME <TABLE> <CAPTION> 1999 1998 1997 ----------- ----------- ----------- (Thousands of Dollars, except per share amounts) <S> <C> <C> <C> Operating Revenues $ 1,842,810 $ 1,820,758 $ 1,161,927 Cost of gas 1,156,024 1,220,009 725,960 ----------- ----------- ----------- Net Revenues 686,786 600,749 435,967 ----------- ----------- ----------- Operating Expenses Operations and maintenance 297,784 277,068 210,852 Depreciation, depletion, and amortization 129,704 101,653 74,509 General Taxes 39,715 33,217 22,491 ----------- ----------- ----------- Total Operating Expenses 467,203 411,938 307,852 ----------- ----------- ----------- Operating Income 219,583 188,811 128,115 ----------- ----------- ----------- Other Income 6,639 14,644 -- Interest 52,809 35,075 34,008 Income Taxes 67,056 66,585 34,839 ----------- ----------- ----------- Net Income 106,357 101,795 59,268 Preferred Stock Dividends 37,247 26,979 285 ----------- ----------- ----------- Income Available for Common Stock $ 69,110 $ 74,816 $ 58,983 =========== =========== =========== Earnings Per Share of Common Stock - Basic $ 2.19 $ 2.44 $ 2.13 =========== =========== =========== Earnings Per Share of Common Stock - Diluted $ 2.06 $ 2.23 $ 2.13 =========== =========== =========== Dividends Per Share of Common Stock $ 1.24 $ 1.20 $ 1.20 =========== =========== =========== Average Shares of Common Stock - Basic 31,498,002 30,674,475 27,644,181 Average Shares of Common Stock - Diluted 51,570,723 45,729,363 27,644,181 </TABLE> See accompanying notes to consolidated financial statements. 41
42 ONEOK, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS <TABLE> <CAPTION> August 31, 1999 1998 ---------- ---------- (Thousands of Dollars) <S> <C> <C> ASSETS CURRENT ASSETS Cash and cash equivalents $ 4,402 $ 86 Trade accounts and notes receivable 228,336 177,649 Materials and supplies 10,792 10,046 Gas in storage 108,159 128,334 Advance payments for gas 3,600 3,619 Deferred income taxes 9,702 10,094 Purchased gas cost adjustment 4,552 -- Other current assets 69,724 8,245 ---------- ---------- Total Current Assets 439,267 338,073 ---------- ---------- PROPERTY, PLANT AND EQUIPMENT Distribution 1,771,400 1,717,800 Transportation and Storage 483,983 424,489 Marketing 5,786 5,051 Gathering and Processing 358,439 68,688 Production 399,613 327,970 Other 38,405 57,932 ---------- ---------- Total Property, Plant and Equipment 3,057,626 2,601,930 Accumulated depreciation, depletion, and amortization 988,797 915,769 ---------- ---------- Net Property 2,068,829 1,686,161 ---------- ---------- DEFERRED CHARGES AND OTHER ASSETS Investments 73,777 10,505 Regulatory assets, net 246,658 229,543 Goodwill 81,560 77,422 Other 114,854 80,783 ---------- ---------- Total Deferred Charges and Other Assets 516,849 398,253 ---------- ---------- Total Assets $3,024,945 $2,422,487 ========== ========== </TABLE> See accompanying notes to consolidated financial statements. 42
43 ONEOK, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS <TABLE> <CAPTION> August 31, 1999 1998 - ---------- ----------- ----------- (Thousands of Dollars <S> <C> <C> LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Current maturities of long-term debt $ 22,817 $ 16,909 Notes payable 263,747 212,000 Accounts payable 183,759 136,601 Dividends payable 9,275 9,007 Accrued taxes 11,186 16,829 Accrued interest 7,042 7,814 Customers' deposits 17,139 17,042 Purchased gas cost adjustment -- 12,168 Other 28,617 32,443 ----------- ----------- Total Current Liabilities 543,582 460,813 ----------- ----------- LONG-TERM DEBT, excluding current maturities 810,087 312,355 DEFERRED CREDITS AND OTHER LIABILITIES Deferred income taxes 323,624 313,955 Other deferred credits 173,193 166,493 ----------- ----------- Total Deferred Credits and Other Liabilities 496,817 480,448 ----------- ----------- Total Liabilities 1,850,486 1,253,616 ----------- ----------- COMMITMENTS AND CONTINGENCIES (Note I) SHAREHOLDERS' EQUITY Convertible Preferred Stock, $0.01 par value: Series A authorized 20,000,000 shares; issued and outstanding 19,946,448 shares at August 31, 1999 and 1998 199 199 Series B authorized 30,000,000 shares; issued and outstanding 0 shares at August 31, 1999 and 83,826 shares at August 31, 1998 -- 1 Common stock, $0.01 par value: authorized 100,000,000 shares; issued 31,599,305 shares and outstanding 30,884,225 shares at August 31, 1999 and issued and outstanding 31,576,287 shares at August 31, 1998 316 316 Paid in capital 894,978 897,547 Retained earnings 301,536 270,808 Treasury stock at cost: 715,080 shares at August 31, 1999 (22,570) -- ----------- ----------- Total Shareholders' Equity 1,174,459 1,168,871 ----------- ----------- Total Liabilities and Shareholders' Equity $ 3,024,945 $ 2,422,487 =========== =========== </TABLE> See accompanying notes to consolidated financial statements. 43
44 ONEOK, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS <TABLE> <CAPTION> 1999 1998 1997 ----------- ----------- ---------- (Thousands of Dollars <S> <C> <C> <C> Operating Activities Net income $ 106,357 $ 101,795 $ 59,268 Depreciation, depletion, and amortization 129,704 101,653 74,509 Gain on sale of assets (6,639) (14,644) -- Net (income) losses from other investments (3,861) -- 257 Deferred income taxes 14,925 (7,623) (2,988) Other -- (2,577) -- Changes in assets and liabilities (Increase) decrease in accounts and notes receivable (50,687) 53,400 18,401 (Increase) decrease in inventories 19,429 1,232 13,226 (Increase) decrease in other assets (88,930) 13,472 (10,096) (Increase) decrease in regulatory assets (6,261) -- 384 Increase (decrease) in accounts payable and accrued liabilities 41,320 51,957 (14,897) Changes in purchased gas cost adjustment (16,720) 54,257 10,539 Increase (decrease) in deferred credits and other liabilities (7,034) (6,396) 3,448 --------- --------- --------- Cash Provided by Operating Activities 131,603 346,526 152,051 --------- --------- --------- Investing Activities Changes in other investments, net (59,422) (3,778) 1,698 Acquisitions, net (296,287) (24,421) -- Capital expenditures, net of salvage (210,076) (301,515) (90,530) Proceeds from sale of property 16,500 30,000 -- --------- --------- --------- Cash Used in Investing Activities (549,285) (299,714) (88,832) --------- --------- --------- Financing Activities Issuance (payment) of notes payable, net 51,747 5,302 (5,230) Issuance of debt 695,888 -- -- Payment of debt (224,868) (17,859) (14,000) Issuance of common stock 1,380 6,257 7,363 Acquisition of treasury stock (22,570) -- -- Dividends paid (76,281) (54,803) (28,033) Acquisition and cancellation of preferred stock (3,298) -- (9,540) --------- --------- --------- Cash Provided by (Used in) Financing Activities 421,998 (61,103) (49,440) --------- --------- --------- Change in Cash and Cash Equivalents 4,316 (14,291) 13,779 Cash and Cash Equivalents at Beginning of Year 86 14,377 598 --------- --------- --------- Cash and Cash Equivalents at End of Year $ 4,402 $ 86 $ 14,377 ========= ========= ========= </TABLE> See accompanying notes to consolidated financial statements. 44
45 ONEOK, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY <TABLE> <CAPTION> Preferred Common Paid-in Retained Treasury Stock Stock Capital Earnings Stock Total ----------- ----------- ----------- ----------- ----------- ----------- (Thousands of Dollars) <S> <C> <C> <C> <C> <C> <C> AUGUST 31, 1996 $ 9,000 $ 272 $ 206,812 $ 207,611 $ -- $ 423,695 Net income -- -- -- 59,268 -- 59,268 Issuance of common stock -- 9 22,710 -- -- 22,719 Preferred stock dividends - $2.375 per share -- -- -- (321) -- (321) Redemption of Series A Preferred Stock (9,000) -- -- (540) -- (9,540) Common stock dividends - $1.20 per share -- -- -- (33,195) -- (33,195) ----------- ----------- ----------- ----------- ----------- ----------- AUGUST 31, 1997 -- 281 229,522 232,823 -- 462,626 Net income -- -- -- 101,795 -- 101,795 Issuance of common stock Acquisitions -- 33 93,648 -- -- 93,681 Stock Purchase Plans -- 2 6,255 -- -- 6,257 Convertible preferred stock dividends - $1.80 and $1.50 per share for Series A and B, respectively -- -- -- (26,979) -- (26,979) Issuance of Series A and Series B Convertible Preferred Stock 200 -- 568,122 -- -- 568,322 Common stock dividends - $1.20 per share -- -- -- (36,831) -- (36,831) ----------- ----------- ----------- ----------- ----------- ----------- 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 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 =========== =========== =========== =========== =========== =========== </TABLE> See accompanying notes to consolidated financial statements. 45
46 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (A) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF PRESENTATION - ONEOK, Inc. acquired the gas business of Western Resources, Inc. (Western) on November 26, 1997. The transaction was effective November 30, 1997, for financial reporting purposes. See Note B of Notes to Consolidated Financial Statements. NATURE OF OPERATIONS - ONEOK, Inc. and subsidiaries (collectively, the Company) is a diversified energy company engaged in the production, processing, gathering, storage, transportation, distribution, and marketing of environmentally clean fuels and products. The Company manages its business in six segments: Distribution, Transportation and Storage, Marketing, Gathering and Processing, Production, and Other. The Company's Distribution segment provides natural gas distribution services in Oklahoma and Kansas through its divisions Oklahoma Natural Gas Company and Kansas Gas Service Company. The Transportation and Storage segment owns and leases natural gas storage facilities and transports gas in Oklahoma and Kansas. The Marketing segment purchases and markets natural gas, primarily in the central area of the United States and began trading electricity on a limited basis in 1999. The Company owns and operates gas processing plants as well as gathering pipeline in Oklahoma through its Gathering and Processing segment. The Production segment produces natural gas and oil and owns natural gas and oil reserves. The Company's Other segment, whose results of operations are not material, operates and leases the Company's headquarters building and parking facility. 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. REGULATION - The distribution, transportation and portions of the storage and gathering operations of the Company are subject to the rate regulation and accounting requirements of the Oklahoma Corporation Commission (OCC) and of the Kansas Corporation Commission (KCC). Certain other transportation activities of the Company are subject to regulation by the Federal Energy Regulatory Commission (FERC). Accordingly, these operations follow the accounting and reporting guidance contained in Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation." Allocation of costs and revenues to accounting periods for ratemaking and regulatory purposes may differ from bases generally applied by nonregulated companies. 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. A July, 1999 order by the OCC removed the Oklahoma gathering and storage assets from utility regulation effective November 1, 1999. An August, 1999 order from the OCC distinguished between upstream (transportation) and downstream (distribution) assets and cleared the way for competitive bidding of upstream services to begin fall, 1999. 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 it is recovered through rates. Total regulatory assets resulting from this deferral process are approximately $247 million and $230 million at August 31, 1999 and 1998, respectively. As the Company continues to unbundle its services, certain of these assets will no longer meet the criteria for following SFAS No. 71, and accordingly, a write-off of regulatory assets and stranded costs may be required. However, the Company does not anticipate that these costs will be significant. See Note D of Notes to Consolidated Financial Statements. 46
47 REVENUE RECOGNITION - The Company recognizes 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. Oklahoma Natural Gas Company's (ONG'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 marketing, gathering and processing, and production are recognized on the sales method. Credit is granted to these customers under customary terms. REGULATED PROPERTY - Regulated properties are stated at cost which includes personnel costs, general and administrative costs, and allowance for funds used during construction. The allowance for funds used during construction represents the capitalization of estimated average cost of borrowed funds (7.8 percent, 8.6 percent, and 8.6 percent, in 1999, 1998, and 1997, respectively) used during the construction of major projects and is recorded as a credit to earnings. 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 3.8 percent in 1999, and 3.7 percent in 1998 and 1997. The average depreciation rates for properties regulated by the KCC were approximately 3.2 percent in 1999 and 3.3 percent in 1998. The average depreciation rates for Mid Continent Market Center (MCMC) properties were 3.1 percent in 1999 and 3.4 percent in 1998. 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. <TABLE> <CAPTION> REMAINING SERVICE LIFE (YEARS) --------- ------- <S> <C> <C> Distribution property 22-25 40 Gathering property 5-33 47 Storage property 5-19 40 Transmission property 18-33 47 Other property 6-24 40 - ------------------------------------------------------------------------- </TABLE> PRODUCTION PROPERTY - The Company uses the successful-efforts method to account for costs incurred in the acquisition and exploration of oil and natural gas 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 proven 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. INVENTORIES - Materials and supplies are priced at average cost. Noncurrent gas in storage is classified as property and is priced at cost. 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 $23.1 million and $73.6 million at August 31, 1999 and 1998, respectively, compared to its value under the lifo method of $18.1 million and $68.3 million at August 31, 1999 and 1998, respectively. Current gas in storage for all other companies is determined using the weighted average cost of gas method. 47
48 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 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 on gas distribution and transmission properties over the period prescribed by the OCC and KCC for ratemaking purposes. COMMODITY PRICE RISK MANAGEMENT - To minimize the risk from market fluctuations in the price of natural gas and oil, the Company enters into futures transactions, swaps, and options in order to hedge certain natural gas in storage, existing physical gas purchases or sales commitments, as well as anticipated sales of natural gas production. In order to qualify as a hedge, the price movements in the underlying commodity derivatives must be sufficiently correlated with the hedged transaction. Changes in the market value of these financial instruments utilized as hedges are (1) recognized as an adjustment of the carrying value in the case of existing assets and liabilities, (2) included in the measurement of the transaction that satisfies the commitment in the case of existing commitments, and (3) included in the measurement of the subsequent transaction in the case of anticipated transactions. In cases where anticipated transactions do not occur, deferred gains and losses are recognized when such transactions were scheduled to occur. Some of these financial instruments carry off-balance sheet risks. See Note C of Notes to Consolidated Financial Statements. 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 production assets on the lowest possible level, (a field by field basis) rather than using a total company basis for its proved properties. USE OF ESTIMATES - Management has made a number of estimates and assumptions relating to reporting of assets and liabilities and the disclosure of contingent assets and liabilities to prepare these financial statements in conformity with generally accepted accounting principles. Actual results could differ from these estimates. GOODWILL - The Company amortizes goodwill, which represents the excess of the purchase price over the fair value of net assets acquired, over a period of 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. EARNINGS PER COMMON SHARE - Basic earnings per share are calculated based on the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share are calculated based on the weighted average number of shares of common stock outstanding plus potentially dilutive securities. ENVIRONMENTAL EXPENDITURES - The Company accrues for losses associated with environmental remediation obligations when such losses are probable and reasonably estimatable. 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. 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. COMMON STOCK OPTIONS AND AWARDS - The Company follows SFAS No. 123, "Accounting for Stock-Based Compensation" which permits, but does not require, a fair value based method of accounting for stock-based employee compensation. Alternatively, SFAS No. 123 allows companies to continue applying the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25"), however, 48
49 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 SFAS No. 123 in Note N of Notes to Consolidated Financial Statements. RECLASSIFICATION. Certain amounts in the 1997 and 1998 consolidated financial statements have been reclassified to conform with the 1999 presentation. In particular, the Company reclassified other income, including gains on sales of assets from operating revenue to a separate caption, and now presents operating income. (B) ACQUISITION On November 26, 1997, Old ONEOK acquired from Western all of the gas distribution assets of Western and all of the outstanding capital stock of Western's directly or indirectly wholly-owned subsidiaries, Westar Gas Marketing, Inc. and MCMC, and assumed all of the liabilities of Western that arose primarily out of the gas business and approximately $161 million in debt of Western; and Old ONEOK merged with and into New ONEOK, with New ONEOK as the surviving corporation. The shares of Old ONEOK common stock were converted on a one-for-one basis into shares of stock of New ONEOK, and Western received 2,996,702 shares of the Company's Common Stock and 19,317,584 shares of the Company's Series A Convertible Preferred Stock. Such shares and additional shares purchased by Western at the closing of the transaction represented in the aggregate 9.9 percent of the outstanding Common Stock or 45 percent of the Capital Stock of the Company. A shareholder agreement, which includes standstill provisions, prevents Western from increasing its position in the Company above a common stock interest of 45 percent on a fully converted basis and maintains control of the Company in the hands of the public shareholders of the Company. The acquisition was accounted for as a purchase and, accordingly, the operating results of the properties acquired from Western are included in the consolidated financial statements since December 1, 1997. The aggregate purchase price was approximately $824 million, including debt assumed and transaction costs. The aggregate purchase price, which was funded through the issuance of a combination of preferred and common stock, was allocated based on the estimated fair value of the net assets. The excess of the purchase price over the fair value of the net assets acquired approximated $74 million and is being amortized over 40 years. (C) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT FINANCIAL INSTRUMENTS - The following table presents the carrying amounts and fair values of certain of the Company's financial instruments. Fair value is defined as the amount at which the instrument could be exchanged in a current transaction between willing parties. The estimated fair value of long-term debt and notes payable has been determined using quoted market prices of same or similar issues, discounted cash flows, and/or rates currently available to the Company for debt with similar terms and remaining maturities. The fair value of natural gas and oil swaps, options, and futures contracts generally reflect the estimated amounts that the Company would pay or receive to terminate the contracts at the reporting date, thereby taking into account the unrealized gains and losses on open contracts. There is no readily available market for natural gas swaps. The items presented without a carrying value are off-balance sheet financial instruments. All of the Company's financial instruments are held for purposes other than trading. <TABLE> <CAPTION> Approximate Fair Book Value Value ---------- ---------------- (Thousands of Dollars) <S> <C> <C> AUGUST 31, 1999 CASH AND CASH EQUIVALENTS $ 4,402 $ 4,402 ACCOUNTS AND NOTES RECEIVABLE $ 228,336 $ 228,336 NATURAL GAS SWAPS -- $ 6,359 NATURAL GAS OPTIONS -- $ 6,522 NATURAL GAS FUTURES -- $ (24,421) NOTES PAYABLE $ 263,747 $ 263,747 LONG-TERM DEBT $ 836,975 $ 790,961 - --------------------------------------------------------------------- </TABLE> 49
50 <TABLE> <CAPTION> Approximate Fair Book Value Value ---------- ---------------- (Thousands of Dollars) <S> <C> <C> August 31, 1998 Cash and cash equivalents $ 86 $ 86 Accounts and notes receivable $ 177,649 $ 177,649 Natural gas swaps -- $ 750 Natural gas options -- $ 3,486 Natural gas futures -- $ 9,971 Notes payable $ 212,000 $ 212,000 Long-term debt $ 329,264 $ 358,207 - ---------------------------------------------------------------------- </TABLE> RISK MANAGEMENT - The Company's operations subject earnings to variability based on fluctuations in the market price and transportation costs of natural gas and oil and in the temperature during the heating season. The Company's exposure arises from fixed price purchase or sale agreements which extend for periods of up to 48 months, certain gas storage inventories, and anticipated sales of oil and gas production. In order to mitigate the financial risks associated with such activities, the Company routinely enters into natural gas and oil futures contracts, swaps, and options, collectively referred to herein as derivatives. Net open positions in terms of price, volume, and specified delivery point do occur. The Company is using derivative contracts to mitigate its risk associated with weather for the winter of 1999/2000 and reduce the impact of degree day variances from normal. The futures contracts are purchased and sold on the New York Mercantile Exchange (NYMEX) or the Kansas City Board of Trade (KCBOT) and require the Company to buy or sell natural gas at a fixed price. Swap agreements generally require one party to make payments based on the difference between a fixed price or fixed differential from the NYMEX or KCBOT price while the other party pays a price based on a published index. Swaps and options allow the Company to commit to purchase gas at one location and sell it at another location without assuming unacceptable risk with respect to changes in the price of gas or the cost of the intervening transportation. Natural gas options held to hedge price risk provide the right, but not the requirement, to buy or sell natural gas at a fixed price. The Company utilizes options to limit overall price risk exposure. None of these derivatives are held for speculative purposes and, in general, the Company's risk management policy requires that positions taken with derivatives be offset by positions in physical transactions or other derivatives. The notional value of futures contracts purchased and sold is $316.2 million and $407.2 million, respectively, at August 31, 1999. The term "notional amount" refers to the current contract unit price times the contract volume for the relevant derivative. In general, such amounts are not indicative of the cash requirements associated with these derivatives. The notional amount is intended to be indicative of the Company's level of activity in such derivatives, although the amounts at risk are significantly smaller because, in general, changes in market value of these derivatives are offset by changes in the value associated with the underlying physical transaction or other derivatives. <TABLE> <CAPTION> Estimated Volumes Volumes Fair Value Purchased Sales Gain (Loss)(A) --------- -------- -------------- (Volumes in Mmcf, Thousands of Dollars) <S> <C> <C> <C> AUGUST 31, 1999 OPTIONS 238,420 38,390 $ 6,522 SWAPS 49,545 47,110 $ 6,359 FUTURES 113,730 156,140 $ (24,421) - ----------------------------------------------------------------- August 31, 1998 Options 4,543 2,536 $ 3,486 Swaps 49,281 44,715 $ 750 Futures 5,375 35,492 $ 9,971 - ----------------------------------------------------------------- </TABLE> (A) represents the estimated amount which would have been recognized upon termination of the relevant derivatives as of the date indicated. The amount which is ultimately charged or credited to earnings is affected by subsequent changes in the fair value of these derivatives. 50
51 NYMEX- and KCBOT-traded futures and option contracts are guaranteed by NYMEX and KCBOT and have nominal credit risk. All other derivative transactions expose the Company to off-balance sheet risk in the event of non performance by the counterparts. In order to minimize this risk, the Company analyzes each counterpart's financial condition prior to entering into an agreement, establishes credit limits, and monitors the appropriateness of these limits on an on-going basis. Swap agreements are generally settled at the expiration of the contract term and may be subject to margin requirements with the counterparty. NYMEX- and KCBOT-traded futures and options contracts require daily cash settlement in margin accounts with brokers. (D) REGULATORY ASSETS The table presents a summary of regulatory assets, net of amortization, outstanding at August 31, 1999 and 1998. <TABLE> <CAPTION> August 31, 1999 1998 - ---------- --------- --------- (Thousands of Dollars) <S> <C> <C> Recoupable take-or-pay $ 85,996 $ 90,708 Pension costs 20,881 25,061 Postretirement costs other than pension 61,830 59,963 Other 8,521 8,917 Transition costs 22,903 18,447 Reacquired debt costs 22,413 -- Income taxes 24,114 26,447 - -------------------------------------------------------------------- Regulatory assets, net $ 246,658 $ 229,543 ==================================================================== </TABLE> The remaining recovery period for these assets that the Company is not earning a return on is set forth in the table below. <TABLE> <CAPTION> REMAINING RECOVERY PERIOD (MONTHS) ------------------ <S> <C> Postretirement costs other than pension - Oklahoma 169 Income taxes - Oklahoma 142 - 158 Transition costs 459 - ---------------------------------------------------- </TABLE> The OCC has authorized recovery of the take-or-pay settlement, pension and postretirement benefit costs over a 10 to 20 year period. Kansas Gas Service 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 H of Notes to Consolidated Financial Statements. The KCC has allowed certain transition costs to be amortized and recovered in rates over a forty 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. In accordance with various rate orders received from the KCC and the OCC, Kansas Gas Service 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. Amortization expense related to regulatory assets was approximately $13.7 million, $11.4 million, and $10.1 million in 1999, 1998, and 1997, respectively. 51
52 (E) CAPITAL STOCK The Company has approximately 68 million shares of unrestricted common stock available for issue. The Company redeemed all of its outstanding shares of Series A Preferred Stock, par value $50 per share, at its stated voluntary liquidation value of $53 per share during the third quarter of fiscal 1997. The Company issued Series A Convertible Preferred Stock, par value $0.01 per share, at the time of the transaction with Western. 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 1.5 times the dividend amount declared in respect of each share of common stock for the first five years of the agreement. After five years, the rate will be 1.25 times the dividend amount declared in respect of each share of common stock, and at no time, will the dividend be less that $1.80 per share. The terms of Series B Convertible Preferred Stock are the same as Series A Convertible Preferred Stock, except that the dividend amount is equal to the greater of 1.25 times the common stock dividend or $1.50 per share. 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 $1 or subject to adjustment, 100 times the aggregate per share amount of all cash dividends, and 100 times the aggregate per share amount of all non-cash dividends. No Series C Preferred Stock has been issued. The Series A and Series B Convertible Preferred Stock is convertible, subject to certain restrictions, at the option of the holder, into ONEOK, Inc., Common Stock at the rate of one share for each share of Series A or Series B Convertible Preferred Stock. During 1999, the Company initiated a stock buyback plan for up to 15 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 August 31, 1999, the shares purchased totaled 715,080. The purchased shares will be held in treasury and will be available for general corporate purposes, funding of stock-based compensation plans, resale at a future date, or retirement. Purchases will be financed with short-term debt or made from available funds. The Board of Directors has reserved 3.0 million shares of ONEOK, Inc's common stock for the Direct Stock Purchase and Dividend Reinvestment Plan of which 127 thousand shares were issued in 1999 and 142 thousand shares were issued in 1998; and has reserved approximately 7.2 million shares for the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries. Under the most restrictive covenants of the Company's loan agreements, $251.4 million (83.4 percent) of retained earnings at August 31, 1999, was available to pay dividends. (F) LINES OF CREDIT AND SHORT-TERM NOTES PAYABLE Commercial paper and short-term notes payable totaling $264 million and $212 million were outstanding at August 31, 1999 and 1998, respectively. The commercial paper and notes carried average interest rates of 5.42 percent and 5.83 percent at August 31, 1999 and 1998, respectively. The Company has a $600 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 compensating balance requirements existed at August 31, 1999. Maximum short-term debt from all sources as approved by the Company's Board of Directors is $750 million. (G) LONG-TERM DEBT All long-term notes payable at August 31, 1999, are unsecured. The aggregate current maturities of long-term debt for each of the five years ending August 31, 2004, are $22.8 million; $18.2 million; $14.7 million; $14.7 million; 52
53 and $14.7 million, respectively, including $7.1 million which is callable at the option of the holder in each of those years. During fiscal 1999, the Company refinanced $116.2 million of the 9.7% and $59.7 million of the 9.75% long-term notes payable with new debt at a lower interest rate. In connection therewith, the Company paid a redemption premium of $18 million. See Note D of Notes to the Consolidated Financial Statements. <TABLE> <CAPTION> August 31, 1999 1998 - ---------- -------- -------- (Thousands of Dollars) <S> <C> <C> Long-term Notes Payable 6.20% due 1999 $ -- $ 8,000 6.43% due 2000 5,000 5,000 6.5% due 2001 1,534 5,393 8.44% due 2004 40,000 40,000 7.75% due 2006 300,000 - 8.32% due 2007 32,000 36,000 6.00% due 2009 100,000 - 6.40% due 2019 99,794 - 9.70% due 2019 8,826 125,000 9.75 % due 2020 15,305 75,000 8.70% due 2021 34,871 34,871 6.50% due 2028 99,645 - 6 7/8% due 2028 100,000 - - ----------------------------------------------------------- Total Long-term Notes Payable 836,975 329,264 Unamortized debt discount 4,071 - Current maturities 22,817 16,909 - ----------------------------------------------------------- Long-term debt $810,087 $312,355 =========================================================== </TABLE> (H) EMPLOYEE BENEFIT PLANS RETIREMENT PLANS - The Company has defined benefit 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 and accidental death and dismemberment benefits to substantially all employees who retire under the Retirement Plans at age 55 or older with at least five years of service. The plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance. The Company elected to delay recognition of the accumulated postretirement benefit obligation (APBO) of approximately $72.2 million and amortize it over 20 years as a component of net periodic postretirement benefit cost. 53
54 In 1999, the Company adopted SFAS No. 132, "Employers' Disclosures About Pensions and Other Postretirement Benefits," which standardized the disclosure requirements for pensions and other postretirement benefits. SFAS No. 132 did not change the measurement or recognition of amounts related to those plans. Prior-year amounts were reclassified to conform to the new standard. The status of the Company's pension and other postretirement benefit plans are summarized in the tables below. <TABLE> <CAPTION> PENSION BENEFITS POSTRETIREMENT BENEFITS 1999 1998 1999 1998 -------- --------- ---------- --------- (Thousands of Dollars) <S> <C> <C> <C> <C> CHANGE IN BENEFIT OBLIGATIONS Benefit obligation, beginning of year $500,327 $ 327,127 $ 153,326 $ 76,068 Acquisition -- 128,279 -- 51,106 Service cost 9,282 7,221 4,036 2,570 Interest cost 32,832 30,875 10,055 8,223 Participant contributions -- -- 2,260 8,632 Plan amendments 7,600 -- 1,956 -- Actuarial loss (gain) (15,501) 32,404 (4,081) 13,604 Benefits paid (29,675) (25,579) (7,181) (6,877) - ------------------------------------------------------------------------------------------------------------ Benefit obligation, end of year $504,865 $ 500,327 $ 160,371 $ 153,326 ============================================================================================================= CHANGE IN PLAN ASSETS Fair value of assets, beginning of year $595,308 $ 326,384 $ 14,075 $ 5,871 Acquisition -- 174,468 -- -- Actual return on assets 93,854 116,640 (111) 2,296 Employer contributions 899 3,395 3,536 5,910 Benefits paid (29,675) (25,579) -- (2) - ------------------------------------------------------------------------------------------------------------ Fair value of assets, end of year $660,386 $ 595,308 $ 17,500 $ 14,075 ============================================================================================================ Funded status - over (under) $155,521 $ 94,981 $ (142,871) $(139,251) Unrecognized net asset (2,338) (2,805) -- -- Unrecognized transition obligation -- -- 43,048 48,522 Unrecognized prior service cost 8,030 607 4,195 -- Unrecognized net (gain) / loss (93,683) (30,388) 18,379 18,095 Activity subsequent to measurement date -- -- (1,306) (915) - ------------------------------------------------------------------------------------------------------------ (Accrued) / prepaid pension cost $ 67,530 $ 62,395 $ (78,555) $ (73,549) ============================================================================================================ ACTUARIAL ASSUMPTIONS Discount rate 7.00% 6.75% 7.00% 6.75% Expected rate of return 9.00% 9.00% 8.00% 8.00% Compensation increase rate 4.50% 4.00% 4.50% 4.00% </TABLE> <TABLE> <CAPTION> PENSION BENEFITS POSTRETIREMENT BENEFITS 1999 1998 1997 1999 1998 1997 -------- -------- -------- ------- -------- --------- <S> <C> <C> <C> <C> <C> <C> COMPONENTS OF NET PERIODIC BENEFIT COST Service cost $ 9,282 $ 7,221 $ 5,126 $ 4,036 $ 2,570 $ 1,744 Interest cost 32,832 30,875 23,766 10,055 8,224 5,599 Expected return on assets (46,846) (38,686) (25,490) (1,325) (739) (297) Amortization of unrecognized net asset at adoption (467) (467) (467) -- -- -- Amortization of unrecognized net transition obligation at adoption -- -- 3,235 3,235 3,608 Amortization of unrecognized prior service cost 177 177 120 -- (212) -- Amortization of net (gain) / loss 786 146 546 688 -- (108) - ------------------------------------------------------------------------------------------------------------------------ Net periodic benefit cost $ (4,236) $ (734) $ 3,601 $16,689 $ 13,078 $ 10,546 ======================================================================================================================== </TABLE> For measurement purposes, a 7.2 percent annual rate of increase in the per capita cost of covered medical benefits (i.e., medical cost trend rate) was assumed for 1999, 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 August 31, 1999, by $14.6 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year ended 54
55 August 31, 1999, by $1.4 million. Decreasing the assumed medical cost trend by one percentage point in each year would decrease the accumulated postretirement benefit obligation as of August 31, 1999, by $11.9 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year ended August 31, 1999, by $1.1 million. EMPLOYEE THRIFT PLANS - The Company has Thrift Plans covering substantially all employees. Employee contributions are discretionary. Subject to certain limits, employee contributions are matched by the Company. The annual cost of the plans was $6.3 million in 1999; $4.7 million in 1998; and $3.4 million in 1997. POSTEMPLOYMENT BENEFITS - The Company pays postemployment benefits to former or inactive employees after employment but before normal retirement. 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. 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 and anticipates that recovery will be allowed over a period not to exceed 20 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 the regulatory asset established for postretirement and postemployment benefit costs totaling approximately $52.7 million at August 31, 1999. (I) 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. Rent for the lease accrues annually at $6.8 million until 2009. Rent payments were $5.8 million for 1999, 1998, and 1997. Estimated future minimum rental payments for the lease are $7.6 million for the year ending August 31, 2000, and $9.3 million for each of the years ending August 31, 2001 through 2009. The Company has the right to sublet excess office space in ONEOK Plaza. The Company received $2.8 million, $2.8 million, and $2.7 million in rental revenue during 1999, 1998, and 1997, respectively, for various subleases. Estimated minimum future rental payments to be received under existing contracts for subleases are $2.9 million in 2000, $2.9 million in 2001, $2.8 million in 2002, $2.4 million in 2003, $1.8 million in 2004, and a total of $2.9 million thereafter. Other operating leases include office buildings and equipment. The total estimated payments for these leases are $2.5 million in 2000, $1.5 million in 2001, and $1.4 million in 2002, $1.2 million in 2003 and $0.6 million in 2004. SOUTHWEST GAS CORPORATION - During the year ended August 31, 1999, the Company and Southwest Gas Corporation (Southwest) entered into a definitive agreement whereby the Company agreed to acquire Southwest for $30 per share in an all cash transaction valued at $918 million. The total transaction cost, including assumed debt, is estimated at $1.8 billion. The transaction is expected to be completed during 2000, subject to various conditions including regulatory approvals. Southwest shareholders approved the agreement on August 10, 1999. The Company and 55
56 certain of its officers as well as Southwest have been named as defendants in a lawsuit brought by Southern Union Company in connection with the proposed acquisition in the total amount of $750 million. 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 Company, as third party beneficiary, has filed a lawsuit against Southern Union for breach of a confidentiality agreement with Southern Union and Southwest. The parties are presently involved in discovery. If any of the plaintiffs should be successful in any of their claims against the Company or Southwest and substantial damages are awarded, it could have a material adverse effect on the Company's operations, cash flow, and financial position. The Company believes the Southern Union allegations are without merit and is defending itself vigorously against all claims. ENVIRONMENTAL - In connection with the Western transaction, the Company acquired responsibility for 12 manufactured gas sites located in Kansas which may contain coal tar and other 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 ten year period. At August 31, 1999, the costs of the investigations and risk analysis have been minimal. Limited information is available about the sites and no testing has been performed. Management's best estimate of the cost of remediation ranges from $100 thousand 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 their 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 degree of remediation required and number of years over which the remediation must be completed. OTHER - 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. (J) INCOME TAXES The provisions for income taxes are as follows: <TABLE> <CAPTION> 1999 1998 1997 -------- ------- ------- (Thousands of Dollars) <S> <C> <C> <C> Current income taxes Federal $ 48,760 $62,462 $32,207 State 3,371 11,746 5,620 - ------------------------------------------------------------------------ Total current income taxes 52,131 74,208 37,827 - ------------------------------------------------------------------------ Deferred income taxes Federal 13,671 (6,325) (2,551) State 1,254 (1,298) (437) - ------------------------------------------------------------------------ Total deferred income taxes 14,925 (7,623) (2,988) - ------------------------------------------------------------------------ Total provision for income taxes $ 67,056 $66,585 $34,839 ======================================================================== </TABLE> 56
57 Following is a reconciliation of the provision for income taxes. <TABLE> <CAPTION> 1999 1998 1997 -------- -------- ------- (Thousands of Dollars) <S> <C> <C> <C> Pretax income $173,413 $168,380 $94,107 Federal statutory income tax rate 35% 35% 35% - ----------------------------------------------------------------------------------------------- Provision for federal income taxes 60,695 58,933 32,937 Amortization of distribution property investment tax credit (1,103) (938) (655) State income taxes, net of federal tax benefit 5,737 6,253 2,936 Other, net 1,727 2,337 (379) - ----------------------------------------------------------------------------------------------- Actual income tax expense $ 67,056 $ 66,585 $34,839 =============================================================================================== </TABLE> 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. <TABLE> <CAPTION> August 31, 1999 1998 - ---------- -------- -------- (Thousands of Dollars) <S> <C> <C> Deferred tax assets Accrued liabilities not deductible until paid $ 16,856 $ 6,089 Net operating loss carry forward 1,315 854 Regulatory assets 8,728 4,894 Other 3,444 -- - ------------------------------------------------------------------------ Total deferred tax assets 30,343 11,837 Valuation allowance for net operating loss carryforward expected to expire prior to utilization 880 854 - ------------------------------------------------------------------------ Net deferred tax assets 29,463 10,983 - ------------------------------------------------------------------------ Deferred tax liabilities Excess of tax over book depreciation and depletion 265,493 220,064 Investment in joint ventures 7,458 4,543 Regulatory assets 66,932 77,454 Other 3,502 12,783 - ------------------------------------------------------------------------ Total deferred tax liabilities 343,385 314,844 - ------------------------------------------------------------------------ Net deferred tax liabilities $313,922 $303,861 ======================================================================== </TABLE> The Company has remaining net operating loss carry-forwards for income tax purposes of approximately $17.0 million at August 31, 1999, which expire, unless previously utilized, at various dates through the year 2011. At August 31, 1999, the Company had $8.5 million in deferred investment tax credits recorded in other deferred credits which will be amortized over the next 16 years. (K) SEGMENT INFORMATION In 1999, the Company adopted SFAS 131, "Disclosures about Segments of an Enterprise and Related Information." This statement requires the Company to define and report the Company's business segments based on how management currently evaluates its business. Management has segmented its business based on differences in products and services and management responsibility. The Company conducts its operations through six segments: (1) the Distribution segment distributes natural gas to residential, commercial and industrial customers and leases pipeline capacity to others; (2) the Transportation and Storage segment transports and stores natural gas for others; (3) the Marketing segment markets natural gas to wholesale and retail customers and markets electricity to wholesale customers; (4) the Gathering and Processing segment gathers and processes natural gas and natural gas liquids; (5) the Production segment produces natural gas and oil; and (6) the Other segment primarily operates and leases the Company's headquarters building and a related parking facility. The accounting policies of the segments are substantially the same as those described in the summary of significant accounting policies. Intersegment oil and gas sales are recorded on the same basis as sales to unaffiliated customers. 57
58 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 Company has no single external customer from which it receives ten percent or more of its revenues. <TABLE> <CAPTION> Gathering Transportation and Eliminations 1999 Distribution and Storage Marketing Processing Production and Other Total ---- ------------ -------------- --------- ---------- ---------- ------------ ---------- (Thousands of Dollars) <S> <C> <C> <C> <C> <C> <C> <C> Sales to unaffiliated customers $ 915,782 $ 29,393 $ 772,331 $ 72,277 $ 46,386 $ 6,641 $1,842,810 Intersegment sales 8,168 79,993 53,067 11,513 22,868 (175,609) -- - --------------------------------------------------------------------------------------------------------------------------- Total Revenues $ 923,950 $ 109,386 $ 825,398 $ 83,790 $ 69,254 $ (168,968) $1,842,810 - --------------------------------------------------------------------------------------------------------------------------- Net Revenues $ 404,384 $ 109,386 $ 35,443 $ 83,790 $ 69,254 $ (15,471) $ 686,786 Operating Expenses $ 230,868 $ 33,894 $ 9,069 $ 63,686 $ 19,128 $ (19,146) $ 337,499 Depreciation, depletion and amortization $ 75,443 $ 13,852 $ 503 $ 3,562 $ 34,073 $ 2,271 $ 129,704 Operating Income $ 98,073 $ 61,640 $ 25,871 $ 16,542 $ 16,053 $ 1,404 $ 219,583 Income from Equity Investments $ -- $ 1,501 $ -- $ -- $ 2,360 $ -- $ 3,861 Total Assets $ 1,722,381 $ 373,742 $ 273,491 $ 343,133 $ 361,806 $ (49,608) $3,024,945 Capital Expenditures $ 98,685 $ 32,618 $ 4,196 $ 8,557 $ 95,431 $ 4,068 $ 243,555 - --------------------------------------------------------------------------------------------------------------------------- </TABLE> <TABLE> <CAPTION> Gathering Transportation and Eliminations 1998 Distribution and Storage Marketing Processing Production and Other Total ---- ------------ -------------- --------- ---------- ---------- ------------ ---------- (Thousands of Dollars) <S> <C> <C> <C> <C> <C> <C> <C> Sales to unaffiliated customers $ 956,044 $ 17,399 $ 746,744 $ 63,248 $ 31,570 $ 5,753 $1,820,758 Intersegment sales 7,784 73,302 31,870 15,309 12,312 (140,577) -- - --------------------------------------------------------------------------------------------------------------------------- Total Revenues $ 963,828 $ 90,701 $ 778,614 $ 78,557 $ 43,882 $ (134,824) $1,820,758 - --------------------------------------------------------------------------------------------------------------------------- Net Revenues $ 378,376 $ 90,701 $ 19,927 $ 78,557 $ 43,882 $ (10,694) $ 600,749 Operating Expenses $ 208,513 $ 31,052 $ 7,024 $ 60,887 $ 14,312 $ (11,503) $ 310,285 Depreciation, depletion and amortization $ 66,214 $ 12,818 $ 561 $ 2,249 $ 18,872 $ 939 $ 101,653 Operating Income $ 103,650 $ 46,831 $ 12,342 $ 15,421 $ 10,698 $ (131) $ 188,811 Income from Equity Investments $ -- $ -- $ -- $ -- $ -- $ -- $ -- Total Assets $ 1,771,999 $ 351,692 $ 130,100 $ 86,955 $ 282,765 $ (201,024) $2,422,487 Capital Expenditures $ 77,198 $ 50,271 $ -- $ 4,735 $ 167,669 $ 6,533 $ 306,406 - --------------------------------------------------------------------------------------------------------------------------- </TABLE> <TABLE> <CAPTION> Gathering Transportation and Eliminations 1997 Distribution and Storage Marketing Processing Production and Other Total ---- ------------ -------------- --------- ---------- ---------- ------------ ---------- (Thousands of Dollars) <S> <C> <C> <C> <C> <C> <C> <C> Sales to unaffiliated customers $ 592,603 $ 5,229 $ 459,698 $ 72,739 $ 26,497 $ 5,161 $1,161,927 Intersegment sales 2,502 65,270 23,501 14,333 14,018 (119,624) -- - --------------------------------------------------------------------------------------------------------------------------- Total Revenues $ 595,105 $ 70,499 $ 483,199 $ 87,072 $ 40,515 $ (114,463) $1,161,927 - --------------------------------------------------------------------------------------------------------------------------- Net Revenues $ 225,252 $ 70,499 $ 12,321 $ 87,072 $ 40,515 $ 308 $ 435,967 Operating Expenses $ 116,325 $ 28,136 $ 3,707 $ 71,800 $ 12,342 $ 1,033 $ 233,343 Depreciation, depletion and amortization $ 42,980 $ 8,395 $ 482 $ 2,393 $ 19,899 $ 360 $ 74,509 Operating Income $ 65,947 $ 33,968 $ 8,132 $ 12,879 $ 8,274 $ (1,085) $ 128,115 Income from Equity Investments $ -- $ -- $ -- $ -- $ -- $ -- $ -- Total Assets $ 855,587 $ 221,233 $ 64,190 $ 46,602 $ 94,496 $ (44,701) $1,237,407 Capital Expenditures $ 39,825 $ 27,922 $ 373 $ 10,563 $ 32,911 $ 413 $ 112,007 - --------------------------------------------------------------------------------------------------------------------------- </TABLE> 58
59 (L) QUARTERLY FINANCIAL DATA (UNAUDITED) Total operating revenues are consistently greater from November through May due to the large volume of natural gas sold to customers for heating. A summary of the unaudited quarterly results of operations for 1999 and 1998 follows: <TABLE> <CAPTION> First Second Third Fourth 1999 Quarter Quarter Quarter Quarter ---- --------- --------- --------- --------- (Thousands of Dollars, Except Per Share Amounts) <S> <C> <C> <C> <C> Operating revenues $ 374,936 $ 592,664 $ 418,080 $ 457,130 Operating income $ 29,999 $ 125,137 $ 45,166 $ 19,281 Other income $ 4,993 $ -- $ -- $ 1,646 Income taxes $ 9,387 $ 44,596 $ 10,985 $ 2,089 Net Income $ 14,250 $ 68,532 $ 21,196 $ 2,379 Earnings (loss) per share of common stock Basic $ 0.16 $ 1.87 $ 0.38 $ (0.22) Diluted $ 0.16 $ 1.33 $ 0.38 $ (0.22) Dividends per share of common stock $ 0.31 $ 0.31 $ 0.31 $ 0.31 Average shares of common stock outstanding (000's) Basic 31,535 31,594 31,634 31,233 Diluted 31,578 51,687 31,640 31,233 - ---------------------------------------------------------------------------------------------------------- </TABLE> <TABLE> <CAPTION> First Second Third Fourth 1998 Quarter Quarter Quarter Quarter ---- --------- --------- --------- --------- (Thousands of Dollars, Except Per Share Amounts) <S> <C> <C> <C> <C> Operating revenues $ 314,160 $ 707,410 $ 444,048 $ 355,140 Operating income $ 28,486 $ 116,605 $ 50,050 $ (6,330) Other income $ -- $ 14,644 $ -- $ -- Income taxes $ 7,438 $ 46,611 $ 17,270 $ (4,734) Net Income (loss) $ 12,520 $ 73,836 $ 26,936 $ (11,497) Earnings (loss) per share of common stock Basic $ 0.44 $ 2.06 $ 0.57 $ (0.65) Diluted $ 0.44 $ 1.43 $ 0.52 $ (0.65) Dividends per share of common stock $ 0.30 $ 0.30 $ 0.30 $ 0.30 Average shares of common stock outstanding (000's) Basic 28,268 31,466 31,536 31,586 Diluted 28,268 51,576 51,589 31,586 - ---------------------------------------------------------------------------------------------------------- </TABLE> 59
60 (M) SUPPLEMENTAL CASH FLOW INFORMATION The table presents supplemental information relative to the Company's cash flows for the years ended August 31, 1999, 1998, and 1997. <TABLE> <CAPTION> 1999 1998 1997 --------- --------- --------- (Thousands of Dollars) <S> <C> <C> <C> Cash paid during the year Interest (including amounts capitalized) $ 50,498 $ 34,637 $ 39,993 Income taxes $ 59,466 $ 73,772 $ 34,618 Noncash transactions Gas received as payment in kind $ 135 $ 280 $ 478 Issuance of common stock related to Stock Performance Plan $ -- $ -- $ -- Dividend reinvestment plan $ -- $ -- $ 5,482 Acquisitions Plant, property and equipment $ 289,931 $ 642,742 -- Current assets -- 232,738 -- Current liabilities -- (42,575) -- Debt assumed -- (161,698) -- Regulatory assets and goodwill 10,817 169,983 -- Deferred debits -- 62,633 -- Deferred credits -- (89,655) -- Deferred income taxes (4,461) (127,744) -- Capital stock -- (662,003) -- --------- --------- Cash paid $ 296,287 $ 24,421 $ -- ======================================================================================== </TABLE> (N) STOCK BASED COMPENSATION LONG-TERM INCENTIVE PLAN - The Long-term Incentive Plan (Plan) provides for the granting of incentive stock options, fixed stock options, and stock bonus awards to key employees. This Plan replaces the Key Employee Stock Purchase Plan. Under the Plan, options may be granted by the Executive Compensation Committee (the Committee) at any time within ten years expiring 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 in the event that the optionee surrenders shares of common stock which the optionee already owns in full or partial payment of the options price under this option and/or surrenders shares of common stock to satisfy withholding tax obligations incident to the exercise of this option. A restored option has an option price equal to the fair market value of the common stock on the date on which the exercise of the option resulted in the grant of the restored option. The Company has reserved one million shares of common stock for the Plan. 60
61 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. Options issued to date can be exercised after one year from grant date and must be exercised no more than ten years after grant date. Activity to date has been as follows: <TABLE> <CAPTION> Weighted Number of Average Shares Exercise Price --------- -------------- <S> <C> <C> Outstanding August 31, 1996 107,400 $ 23.69 Granted 100,700 $ 26.88 Exercised (20,700) $ 23.69 Expired (2,200) $ 26.69 Restored 4,147 $ 30.71 - -------------------------------------------------------------------- Outstanding August 31, 1997 189,347 $ 25.54 Granted 262,576 $ 33.39 Exercised (96,047) $ 25.55 Expired (4,900) $ 33.94 - -------------------------------------------------------------------- Outstanding August 31, 1998 350,976 $ 31.30 Granted 265,724 $ 35.22 Exercised (27,950) $ 26.88 Expired (2,500) $ 34.90 Restored 35,845 $ 35.95 - -------------------------------------------------------------------- Outstanding August 31, 1999 622,095 $ 33.09 - -------------------------------------------------------------------- Options Exercisable August 31, 1997 88,347 $ 24.00 August 31, 1998 94,469 $ 25.78 August 31, 1999 354,995 $ 31.49 </TABLE> At August 31, 1999, the Company had 283,524 outstanding options with exercise prices ranging between $23.69 to $34.03 and a weighted average remaining life of 7.68 years. All of these options were exercisable at August 31, 1999 with a weighted average exercise price of $30.26. The Company also had 338,571 options outstanding at August 31, 1999 with exercise prices ranging between $35.22 and $42.53 and a weighted average remaining life of 8.78 years. Of these options, 71,471 were exercisable at August 31, 1999 at a weighted average exercise price of $35.46. EMPLOYEE STOCK PURCHASE PLAN - In 1995, the Company authorized the Employee Stock Purchase Plan and reserved 350,000 shares of common stock for it. Almost 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 beginning-of-year or end-of-year market price. Approximately 54 percent, 60 percent and 55 percent of eligible employees participated in the plan in fiscal 1999, 1998 and 1997, respectively. Under the plan, the Company sold 97,091 shares in December 1998, 105,923 shares in December 1997 and 107,080 shares in December 1996. 61
62 ACCOUNTING TREATMENT - The Company continues to apply APB 25 in accounting for both plans and accordingly, no compensation has been recognized in the consolidated financial statements. Had the Company applied the provisions of SFAS 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: <TABLE> <CAPTION> 1999 1998 1997 -------- -------- ------- <S> <C> <C> <C> Net Income (000's) As reported $106,357 $101,795 $59,268 Pro forma $ 99,887 $ 98,592 $58,247 Earnings per share - Diluted As reported $ 2.06 $ 2.23 $ 2.13 Pro forma $ 1.94 $ 2.16 $ 2.10 ============================================================= </TABLE> 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 0.2151 for 1999, 0.2720 for 1998 and 0.2264 for 1997. Dividend yield is estimated to be 4.0 for 1999, 3.9 percent for 1998 and 3.7 percent for 1997, with a risk-free interest rate of 5.983 percent, 5.032 percent, and 6.590 percent in 1999, 1998, and 1997, respectively. 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 under the Plan were $13.86, $8.75, and $11.58 for 1999, 1998, and 1997, respectively. (O) EARNINGS PER SHARE INFORMATION The following is a reconciliation of the numerators and denominators of the basic and diluted EPS computations. The effect of dilutive options in fiscal 1997 is insignificant. <TABLE> <CAPTION> Per Share August 31, 1999 Income Shares Amount - --------------- -------- -------- --------- (Thousands, except per share amounts) <S> <C> <C> <C> Basic EPS Income available to common stockholders $ 69,110 31,498 $ 2.19 Effect of Dilutive Securities Options -- 20 Convertible preferred stock 37,247 20,053 -------- -------- Diluted EPS Income available to common stockholders + assumed conversions $106,357 51,571 $ 2.06 =============================================================================== </TABLE> <TABLE> <CAPTION> Per Share August 31, 1998 Income Shares Amount - --------------- -------- -------- --------- (Thousands, except per share amounts) <S> <C> <C> <C> Basic EPS Income available to common stockholders $ 74,816 30,674 $ 2.44 Effect of Dilutive Securities Options -- 53 Convertible preferred stock 26,979 15,002 -------- -------- Diluted EPS Income available to common stockholders + assumed conversions $101,795 45,729 $ 2.23 =============================================================================== </TABLE> <TABLE> <CAPTION> Per Share August 31, 1997 Income Shares Amount - --------------- -------- -------- --------- (Thousands, except per share amount) <S> <C> <C> <C> Basic and Diluted EPS Income available to common stockholders $ 58,983 27,644 $ 2.13 =============================================================================== </TABLE> 62
63 (P) OIL AND GAS PRODUCING ACTIVITIES The following is historical revenue and cost information relating to the Company's production operations: <TABLE> <CAPTION> 1999 1998 1997 -------- -------- -------- (Thousands of Dollars) <S> <C> <C> <C> Capitalized costs at end of year Unproved properties $ 4,245 $ 3,505 $ 2,994 Proved properties 393,096 320,055 155,208 - ------------------------------------------------------------------------------------------------- Total capitalized costs 397,341 323,560 158,202 Accumulated depreciation, depletion, and amortization 120,109 100,601 83,457 - ------------------------------------------------------------------------------------------------- Net capitalized costs $277,232 $222,959 $ 74,745 ================================================================================================= Costs incurred during the year Property acquisition costs (unproved) $ 948 $ 601 $ 174 Exploitation costs $ 17 $ 6 $ 71 Development costs $ 13,659 $ 15,315 $ 6,683 Purchase of minerals in place $ 79,385 $151,019 $ 21,489 - ------------------------------------------------------------------------------------------------- </TABLE> 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. <TABLE> <CAPTION> 1999 1998 1997 -------- -------- -------- (Thousands of Dollars) <S> <C> <C> <C> Net revenues from production Sales to unaffiliated customers $ 42,077 $ 30,003 $ 24,141 Gas sold to affiliates 22,868 12,312 14,018 - ------------------------------------------------------------------------------------ Net revenues from production 64,945 42,315 38,159 - ------------------------------------------------------------------------------------ Production costs 14,516 9,478 7,918 Exploitation costs 17 351 (12) Depreciation, depletion, and amortization 33,771 18,210 19,246 Income taxes 6,359 5,522 4,258 - ------------------------------------------------------------------------------------ Total expenses 54,663 33,561 31,410 - ------------------------------------------------------------------------------------ Results of operations from producing activities $ 10,282 $ 8,754 $ 6,749 ==================================================================================== </TABLE> (Q) 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 1999, 1998, and 1997 fiscal years. 63
64 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 and revised, either upward or downward, as warranted by additional performance data. <TABLE> <CAPTION> Oil Gas (MBbls) (MMcf) ------- ------- <S> <C> <C> August 31, 1996 2,010 74,068 Revisions of prior estimates 115 2,108 Extensions, discoveries, and other additions 111 3,009 Purchases of minerals in place 155 19,214 Sales of minerals in place (41) (515) Production (336) (14,565) - ----------------------------------------------------------------- August 31, 1997 2,014 83,319 Revisions of prior estimates (223) (1,255) Extensions, discoveries, and other additions 167 23,251 Purchases of minerals in place 1,645 89,724 Sales of minerals in place (1) (174) Production (330) (16,818) - ----------------------------------------------------------------- August 31, 1998 3,272 178,047 Revisions of 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 ================================================================= Proved developed reserves August 31, 1997 1,615 62,115 August 31, 1998 2,228 134,346 August 31, 1999 2,540 175,771 - ----------------------------------------------------------------- </TABLE> (R) DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED) Estimates of the standard measure of discounted future cash flows from proved reserves of oil and natural gas shown in the accompanying table are based on prices at the end of the year. Gas prices are escalated only for fixed and determinable amounts under provisions of applicable regulations in some contracts. 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. <TABLE> <CAPTION> 1999 1998 1997 --------- -------- -------- (Thousands of Dollars) <S> <C> <C> <C> Future cash inflows $ 639,721 $423,331 $218,708 Future production and development costs 194,077 129,128 67,962 Future income taxes 53,442 32,025 33,514 - -------------------------------------------------------------------------------------- Future net cash flows 392,202 262,178 117,232 10 percent annual discount for estimated timing of cash flows 161,156 99,549 40,621 - -------------------------------------------------------------------------------------- Standardized measure of discounted future net cash flows relating to oil and gas reserves $ 231,046 $162,629 $ 76,611 ====================================================================================== </TABLE> 64
65 The changes in standardized measure of discounted future net cash flow relating to proved oil and gas reserves are as follows: <TABLE> <CAPTION> 1999 1998 1997 -------- -------- -------- (Thousands of Dollars) <S> <C> <C> <C> Beginning of year $162,629 $ 76,611 $ 67,316 Changes resulting from: Sales of oil and gas produced, net of production costs (50,120) (32,837) (30,241) Net changes in price, development, and production costs 13,629 (6,269) 12,478 Extensions, discoveries, additions, and improved recovery, less related costs 37,379 26,217 5,047 Purchases of minerals in place 67,120 94,031 19,747 Sales of minerals in place (9,326) (142) (1,000) Revisions of previous quantity estimates 10,477 (2,750) 3,159 Accretion of discount 17,317 9,865 8,084 Net change in income taxes (11,618) 3,055 (7,372) Other, net (6,081) (5,152) (607) - ------------------------------------------------------------------------------------------ End of year $231,406 $162,629 $ 76,611 ========================================================================================== </TABLE> ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None 65
66 PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS, AND CONTROL PERSONS OF THE REGISTRANT (A) DIRECTORS OF THE REGISTRANT EDWYNA G. ANDERSON Director since 1995 Age 69 Mrs. Anderson served as General Counsel of Duquesne Light Company from September 1988 until retirement in October 1994. She also served as Special Counsel to the President of Duquesne Light Company from October 1994 until March 1995, when she retired from that position. WILLIAM L. FORD Director since 1981 Age 56 Mr. Ford has served as President of Shawnee Milling Company since 1979. He serves on the boards of numerous civic and business organizations and not-for-profit associations. BERT H. MACKIE Director since 1989 Age 57 Mr. Mackie has been with Security National Bank since 1962, and is currently President and a director. Mr. Mackie serves on the Board of Governors of the United States Postal Service. GARY D. PARKER Director since 1991 Age 54 Mr. Parker, a certified public accountant, is also the majority shareholder of Moffitt, Parker & Company, Inc., and has been President of the firm since 1982. He is a director of First National Bank and Trust Company of Muskogee, Oklahoma. LARRY W. BRUMMETT Director since 1994 Age 49 Mr. Brummett has been employed by the Company for more than 24 years. He was employed by ONEOK's Oklahoma Natural Gas Company division as an engineer trainee in June 1974 and, after receiving a number of promotions within the division, was elected Vice President of Tulsa District September 1, 1986, and Executive Vice President in May 1990. He was elected Executive Vice President of ONEOK Inc. January 21, 1993. He was elected President and Chief Executive Officer February 17, 1994, and was elected to the additional position of Chairman of the Board effective June 1, 1994. Mr. Brummett is a director of the American Gas Association; Southern Gas Association; Oklahoma State Chamber of Commerce; Metropolitan Chamber of Commerce, Tulsa; and the Oklahoma City Branch of the Federal Reserve Bank. He is also an officer or director of numerous civic and business organizations and not-for-profit associations. DOUGLAS ANN NEWSOM, PH.D. Director since 1982 Age 65 Dr. Newsom is a Professor within the Department of Journalism at Texas Christian University, Fort Worth, Texas. In addition to her teaching position, Dr. Newsom is a textbook author and public relations counselor. Ms. Newsom has been a member of the Advisory Council of GRI for fifteen years. 66
67 J. D. SCOTT Director since 1979 Age 67 Mr. Scott served as President, Chief Executive Officer and Chairman of the Board of ONEOK Inc. from January 1987 until he retired in 1994. DOUGLAS T. LAKE Director since 1998 Age 49 Mr. Lake, Executive Vice President and Chief Strategic Officer of Western Resources, Inc., became a director of ONEOK, Inc. in October 1998. He joined Western Resources, Inc. in September 1998, having previously served as Senior Managing Director of the investment Banking Department of Bear Stearns & Co. Inc. He is Chairman of the Board of Directors of Protection One, Inc., and is currently a Director of Guardian International, Inc. WILLIAM M. BELL Director since 1981 Age 64 Mr. Bell is President and a director of Bank One, Oklahoma, N.A. He serves on the boards of numerous civic and business organizations and not-for-profit associations. DOUGLAS R. CUMMINGS Director since 1989 Age 69 Mr. Cummings has been President of Cummings Oil Company since 1972. He is an officer or director of numerous civic and business organizations and not-for-profit associations. HOWARD R. FRICKE Director since 1997 Age 63 Mr. Fricke is Chairman of the Board and Chief Executive Officer of Security Benefit Group of Companies. He joined the Security Benefit Group of Companies in 1988, having previously served as chairman and chief executive officer of the Anchor National Company in Phoenix, Arizona. He is currently a director of Payless ShoeSource, Inc., and UMB Financial Corp. He also serves on the board of directors of the American Council for Life Insurance and Life Officer Management Association. DAVID L. KYLE Director since 1995 Age 47 Mr. Kyle is the President and Chief Operating Officer of ONEOK, Inc. He was employed by Oklahoma Natural Gas Company, a division of ONEOK Inc., in 1974 as an engineer trainee. He served in a number of positions prior to being elected Vice President of Gas Supply September 1, 1986, and Executive Vice President May 17, 1990. He was elected President September 1, 1994. He was elected President of ONEOK Inc. effective September 1, 1997. (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 ONEOK believes that during Fiscal 1999 all Securities and Exchange Commission filings of its officers, directors and ten percent shareholders complied with the requirements of Section 16 of the Securities Exchange Act, based on a review of forms filed, or written notice that no annual forms were required, except for two reports covering two purchases of stock made by Ms. Douglas Ann Newsom's spouse, which were reported late on a Form 4 filed for April 67
68 1999. Ms. Newsom disclaims ownership of these shares. ITEM 11. EXECUTIVE COMPENSATION <TABLE> <CAPTION> LONG-TERM COMPENSATION ANNUAL COMPENSATION AWARDS PAYOUTS --------------------------------------------------------------------------------- SECURITIES OTHER RESTRICTED UNDERLYING ANNUAL STOCK OPTIONS/ LTIP ALL OTHER NAME AND PRINCIPAL POSITION SALARY(1) BONUS COMPENSATION AWARD(S) SARS(2) PAYOUTS COMPENSATION(3) YEAR ($) ($) ($) ($) # ($) ($) ----------- ----------- ---------- ------------ ----------- ----------- ---------- --------------- <S> <C> <C> <C> <C> <C> <C> <C> <C> L. W. BRUMMETT 1999 489,667 181,700 NONE NONE 31,200 NONE 20,325 Chairman of the Board, 1998 435,800 634,900 NONE NONE 44,179(4) NONE 12,800 and Chief Executive Officer 1997 400,933 500,000 NONE NONE 10,000 NONE 9,400 ----------- ----------- ---------- ------------ ----------- ----------- ---------- --------------- D. L. KYLE 1999 354,669 114,500 NONE NONE 21,000 NONE 14,412 President and 1998 317,472 400,000 NONE NONE 30,801(4) NONE 12,800 Chief Operating Officer 1997 297,600 375,000 NONE NONE 8,000 NONE 9,400 ----------- ----------- ---------- ------------ ----------- ----------- ---------- --------------- E. N. DUBAY 1999 234,667 48,100 NONE NONE 12,000 NONE 12,910 President - Kansas 1998 201,233 209,900 NONE NONE 10,000 NONE 10,000 Gas Service Company 1997 166,850 250,000 NONE NONE 2,500 NONE 3,200 ----------- ----------- ---------- ------------ ----------- ----------- ----------- --------------- J. A. GABERINO, Jr. 1999 235,000 38,500 NONE NONE 7,100 NONE 9,762 Senior Vice President 1998 131,250 78,400 NONE NONE 0 NONE 0 and General Counsel 1997 0 0 NONE NONE 0 ----------- ----------- ---------- ------------ ----------- ----------- ----------- --------------- J. C. KNEALE 1999 216,676 48,100 NONE NONE 6,500 NONE 12,300 Vice President, Treasurer, 1998 191,677 167,900 NONE NONE 9,965(4) NONE 9,234 and Chief Financial Officer 1997 143,733 105,340 NONE NONE 4,429(4) NONE 8,620 ----------- ----------- ---------- ------------ ----------- ----------- ----------- --------------- J. D. NEAL 1999 128,917 20,700 NONE NONE 4,000 NONE 7,595 RETIRED 05/31/99 1998 168,000 85,400 NONE NONE 5,900 NONE 9,600 Vice President, Treasurer, and Chief Financial Officer 1997 166,066 102,600 NONE NONE 2,500 NONE 9,400 ----------- ----------- ---------- ------------ ----------- ----------- ----------- --------------- </TABLE> 1. Included in this column are fees received in Fiscal 1999 by Mr. Brummett and Mr. Kyle for serving on the Board of Directors of Magnum Hunter Resources, Inc. ONEOK Resources Company is a 10% owner of Magnum Hunter Resources, Inc. 2. No SARs were granted in Fiscal Year 1999 to any of the named executive officers. 3. The table below shows the components of this column for Fiscal 1999: <TABLE> <CAPTION> Company Contributions Company Match to ONEOK, Inc. to Thrift Plan Employee Non-Qualified Deferred Compensation Plan --------------------- ------------------------------------------------- <S> <C> <C> L. W. Brummett $10,325.00 $10,000.00 David L. Kyle 10,012.00 4,400.00 Eugene N. Dubay 12,910.00 0.00 John A. Gaberino, Jr. 9,762.00 0.00 James C. Kneale 12,300.00 0.00 Jerry D. Neal 7,595.00 0.00 </TABLE> 4. A portion of the securities underlying these grants are restored or "reloaded" options. The stock option agreement provided that an additional option may be granted if, and when, the optionee exercises all or part of the option using Common Stock to pay the purchase price of the option or to satisfy tax obligations incident to the exercise of the option. The restored option will be exercisable for the number of shares tendered to pay the option price or to satisfy any tax obligation, and will be exercisable at any time after the date of grant (or at any other time as determined by the Company) and will expire on the expiration date of the original grant. The number of restored options included in these grants are as follows: <TABLE> <S> <C> <C> L. W. Brummett 11,662 shares at an exercise price of $35.75 Expires 11-16-05 7,517 shares at an exercise price of $35.75 Expires 10-10-06 D. L. Kyle 5,919 shares at an exercise price of $35.75 Expires 11-16-05 1,369 shares at an exercise price of $35.75 Expires 11-16-05 6,013 shares at an exercise price of $35.75 Expires 10-10-06 J. C. Kneale 1,974 shares at an exercise price of $34.03 Expires 10-10-06 1,391 shares at an exercise price of $42.53 Expires 11-16-05 1,929 shares at an exercise price of $30.69 Expires 11-16-05 </TABLE> 68
69 AGGREGATED OPTION EXERCISES AND YEAR-END VALUES The following table shows information for the Named Executive Officers, concerning: o exercises of stock options and SARs(1) during Fiscal 1999; and o the amount and values of unexercised stock options and SARs as of August 31, 1999. AGGREGATED OPTIONS/SAR EXERCISES IN 1999 AND YEAR-END OPTION/SAR VALUES <TABLE> <CAPTION> NUMBER OF SECURITIES UNDERLYING UNEXERCISED VALUE OF UNEXERCISED OPTIONS AT FISCAL IN-THE-MONEY OPTIONS AT SHARES YEAR END (#) FISCAL YEAR-END ($) (2) ACQUIRED ON EXERCISE VALUE REALIZED NAME (#) ($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE - -------------------------- ----------- -------------- ------------ ------------- ------------- ------------- <S> <C> <C> <C> <C> <C> <C> L. W. BRUMMETT 0 0 44,179 31,200 $ 0.00 $ 0.00 Chairman of the Board and Chief Executive Officer - ------------------------------------------------------------------------------------------------------------------------------------ D. L. KYLE 0 0 30,801 21,000 $ 0.00 $ 0.00 President and Chief Operating Officer - ------------------------------------------------------------------------------------------------------------------------------------ E. N. DUBAY 0 0 10,000 12,000 $ 0.00 $ 0.00 President - Kansas Gas Service Company - ------------------------------------------------------------------------------------------------------------------------------------ J. A. GABERINO, Jr. 0 0 0 7,100 $ 0.00 $ 0.00 Senior Vice President and General Counsel - ----------------------------------------------------------------------------------------------------------------------------------- J. C. KNEALE 0 0 9,965 6,500 $ 0.00 $ 0.00 Vice President, Treasurer, and Chief Financial Officer - ----------------------------------------------------------------------------------------------------------------------------------- J. D. NEAL RETIRED 05/31/99 0 0 10,900 0 $ 27,650.00 $ 0.00 Vice President, Treasurer, and Chief Financial Officer - ----------------------------------------------------------------------------------------------------------------------------------- </TABLE> (1) No Stock Appreciation Rights ("SARs") were granted in Fiscal 1999. (2) Based on per share price for ONEOK, Inc. Common Stock of $30.812 per share. The price reflects the average of the high and low trading price on the New York Stock Exchange on August 31, 1999. 69
70 OPTION GRANT TABLE The following table represents additional information concerning the option awards shown in the Summary Compensation Table for Fiscal Year 1999. These options to purchase common stock were granted to the Named Executive Officers under the ONEOK, Inc. Long-Term Incentive Plan. OPTION GRANTS IN FISCAL YEAR 1999(1) <TABLE> <CAPTION> POTENTIAL REALIZABLE VALUE AT ASSUMED ANNUAL RATES OF INDIVIDUAL GRANTS STOCK PRICE APPRECIATION FOR OPTION TERM(3) - ------------------------------------------------------------------------------------------------------------------------------ PERCENT OF TOTAL OPTIONS SECURITIES GRANTED TO EXERCISE UNDERLYING EMPLOYEES OR BASE 5% 10% OPTIONS IN FISCAL PRICE EXPIRATION GRANTED(2) YEAR ($/SHARE) DATE NAME DATE NUMBER ============================== ====================== ============= =========== ============== =========== ============== <S> <C> <C> <C> <C> <C> <C> <C> L. W. BRUMMETT 10-15-98 31,200 10.98% $ 35.218 10-15-08 $ 691,046 $1,751,247 Chairman of the Board and Chief Executive Officer - ------------------------------------------------------------------------------------------------------------------------------ D. L. KYLE 10-15-98 21,000 7.39% $ 35.218 10-15-08 $ 465,127 $1,178,724 President and Chief Operating Officer - ------------------------------------------------------------------------------------------------------------------------------ E. N. DUBAY 10-15-98 12,000 4.22% $ 35.218 10-15-08 $ 265,787 $ 673,556 President - Kansas Gas Service Company - ------------------------------------------------------------------------------------------------------------------------------ J. A. GABERINO, Jr 10-15-98 7,100 2.50% $ 35.218 10-15-08 $ 157,257 $ 398,521 Senior Vice President and General Counsel - ------------------------------------------------------------------------------------------------------------------------------ J. C. KNEALE 10-15-98 6,500 2.29% $ 35.218 10-15-08 $ 143,968 $ 364,843 Vice President, Treasurer, and Chief Financial Officer - ------------------------------------------------------------------------------------------------------------------------------ J. D. NEAL 10-15-98 4,000 1.41% $ 35.218 10-15-08 $ 88,596 $ 224,519 RETIRED 05/31/99 Vice President, Treasurer, and Chief Financial Officer - ------------------------------------------------------------------------------------------------------------------------------ </TABLE> 1. No Stock Appreciation Rights ("SARs") were granted in Fiscal 1999. 2. Each option was awarded with an exercise price equal to the fair market value of a share of ONEOK, Inc. Common Stock on the date of the grant and will become exercisable in four equal installments commencing one year from the grant date. 3. These amounts represent assumed rates of appreciation only and are not intended to forecast future appreciation of the Common Stock price. Actual gains, if any, on stock option exercises depend on the future performance of the Common Stock and overall market conditions. There can be no assurances that the potential values reflected in this table will be achieved. 70
71 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT (A) SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS <TABLE> <CAPTION> TITLE OF CLASS AND NAME & ADDRESS OF AMT. AND NATURE OF PERCENT OF CLASS BENEFICIAL OWNER BENEFICIAL OWNERSHIP ----------------- -------------------- ----------------- COMMON STOCK: - ------------------------------------------------------------------------------------------------------------- <S> <C> <C> Bank of Oklahoma, N.A. 3,475,105 11.25% Trustee for the Thrift Plan for Employees of ONEOK, Direct Inc. and Subsidiaries; P.O. Box 2300, Tulsa, OK 74192 - ------------------------------------------------------------------------------------------------------------- Western Resources, Inc.(1) 2,881,564 9.33% 818 Kansas Avenue Topeka, KS 66612-1217 Westar Capital, Inc.(2) 45,791 0.15% 818 Kansas Avenue Topeka, KS 66612-1217 ------------------------------- 2,927,355 9.48% - ------------------------------------------------------------------------------------------------------------- PREFERRED STOCK (SERIES A): - ------------------------------------------------------------------------------------------------------------- Western Resources, Inc.(1) 19,946,448 100% 818 Kansas Avenue Topeka, KS 66612-1217 - ------------------------------------------------------------------------------------------------------------- </TABLE> 1 As of 08/31/99 Western Resources, Inc. and its affiliates owned approximately 45% of the outstanding shares of the capital stock of the Corporation. Holders of the outstanding convertible preferred stock are not entitled to vote on any matters being considered at this Annual Meeting. 2 Westar Capital, Inc. is an affiliate of Western Resources, Inc. 71
72 (B) SECURITY OWNERSHIP OF MANAGEMENT The following table shows how much ONEOK, Inc. Common Stock each Named Executive Officer and director owned as of August 31, 1999. No director or executive officer beneficially owns more than 1% of the Common Stock, and directors and executive officer as a group beneficially own approximately 1.89% of the Common Stock. DIRECTORS' & OFFICERS' STOCK OWNERSHIP <TABLE> <CAPTION> TOTAL OF SHARES OF SHARES OF COMMON STOCK COMMON DIRECTORS' BENEFICIALLY OWNED PLUS STOCK DEFERRED DIRECTORS' DEFERRED BENEFICIALLY COMPENSATION COMPENSATION PLAN NAME OWNED(1) PLAN PHANTOM STOCK(2) PHANTOM STOCK ==== ============ ===================== ======================= <S> <C> <C> <C> Edwyna G. Anderson 382 206 588 - -------------------------------------------------------------------------------------------------------------------- William M. Bell(3) 2,813 1,389 4,202 - -------------------------------------------------------------------------------------------------------------------- Larry W. Brummett(4,5) 96,569 -- 96,569 - -------------------------------------------------------------------------------------------------------------------- Douglas R. Cummings 2,200 938 3,138 - -------------------------------------------------------------------------------------------------------------------- Eugene N. Dubay(4,5) 22,451 -- 22,451 - -------------------------------------------------------------------------------------------------------------------- William L. Ford(6) 4,101 2,241 6,342 - -------------------------------------------------------------------------------------------------------------------- Howard R. Fricke -- 2,045 2,045 - -------------------------------------------------------------------------------------------------------------------- John A. Gaberino, Jr.(4,5) 11,190 -- 11,190 - -------------------------------------------------------------------------------------------------------------------- James C. Kneale(4,5,7) 30,507 -- 30,507 - -------------------------------------------------------------------------------------------------------------------- David L. Kyle(4,5) 74,748 -- 74,748 - -------------------------------------------------------------------------------------------------------------------- Douglas T. Lake 6,289 226 6,515 - -------------------------------------------------------------------------------------------------------------------- Bert H. Mackie 2,172 938 3,110 - -------------------------------------------------------------------------------------------------------------------- Jerry D. Neal(4,5,8) 37,424 -- 37,424 - -------------------------------------------------------------------------------------------------------------------- Douglas Ann Newsom(9) 1,990 -- 1,990 - -------------------------------------------------------------------------------------------------------------------- Gary D. Parker(10) 4,663 431 5,094 - -------------------------------------------------------------------------------------------------------------------- J.D. Scott(5) 128,483 -- 128,483 - -------------------------------------------------------------------------------------------------------------------- Stanton L. Young 62,500 -- 62,500 - -------------------------------------------------------------------------------------------------------------------- All directors and executive officers as a group including those named above 614,243 8,414 622,657 - -------------------------------------------------------------------------------------------------------------------- </TABLE> 1. This column includes ONEOK, Inc. stock held by directors and officers, or by certain members of their families for which the directors and officers have sole or shared voting or investment power, shares of Common Stock they hold in the ONEOK, Inc. Direct Stock Purchase and Dividend Reinvestment Plan, and ONEOK, Inc. securities directors and officers have the right to acquire within 60 days of August 31, 1999. 2. Phantom Stock has a value equal to shares of Common Stock, but Phantom Stock has no voting rights or other shareholder rights. Phantom Stock suffers all the risks, and enjoys all the rewards, of changes in the price of Common Stock. 3. Includes 697 shares held in the Bell Family 1982 Revocable Trust. 4. The amounts shown include shares of ONEOK, Inc. Common Stock which the following persons have the right to acquire as a result of the exercise of stock options within 60 days after August 31, 1999 under the ONEOK, Inc. Long-Term Incentive Plan: <TABLE> <S> <C> L. W. Brummett 51,979 shares Eugene N. Dubay 13,000 shares John A. Gaberino, Jr. 1,775 shares </TABLE> 72
73 <TABLE> <S> <C> James C. Kneale 11,590 shares David L. Kyle 36,051 shares Jerry D. Neal 10,900 shares All directors and executive officers as a group including those names above 168,695 shares 5. The amounts shown include shares of ONEOK, Inc. Common Stock of the Company in the custody of the Trustee for the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries as of August 31, 1999: L. W. Brummett 18,724 shares Eugene N. Dubay 5,346 shares John A. Gaberino, Jr. 9,308 shares James C. Kneale 12,595 shares David L. Kyle 27,624 shares Jerry D. Neal 18,036 shares J. D. Scott 76,928 shares All directors and executive officers as a group including those names above 244,104 shares </TABLE> 6. Includes 1,136 shares owned by the 1979 Leslie A. Ford Trust, of which William L. Ford is a trustee. Mr. Ford is not a beneficial owner of these shares and disclaims ownership thereof. 7. Includes 3,475 shares owned by Mrs. James C. Kneale. Mr. Kneale disclaims ownership of these shares. Mr. Kneale also holds 640 shares in trust for his daughter. 8. Mr. Neal retired from the company effective 05/31/99. 9. Includes 1,000 shares owned by Ms. Newsom's spouse. Ms. Newsom disclaims ownership of these shares. 10. Includes 470 shares owned by Mrs. Gary D. Parker. In addition, Mr. Parker is holding 1,400 shares in trust as the Trustee of the Phillip Wilkinson Irrevocable Trust under agreement dated 07/13/95. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None 73
74 PART IV. ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (A) DOCUMENTS FILED AS A PART OF THIS REPORT <TABLE> <CAPTION> (1) Exhibits <S> <C> <C> (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-4filed August 6, 1997). (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) Amendment to 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) By-laws of ONEOK, Inc., as amended. (4)(a) Article "Fourth" of the Certificate of Incorporation of ONEOK, Inc. (Preferred Stock and Common Stock), Incorporated by reference from Exhibit 3.1 to Amendment No. 3 to Registration Statement on Form S-4 filed August 31, 1997) (4)(b) 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). (4)(c) Certificate of Designation for Series C Participating Preferred Stock of ONEOK, Inc., filed November 26, 1998 (Incorporated by reference from Exhibit No. 1 to Form 8-A, filed November 26, 1997). (4)(d) Indenture, dated November 28, 1989, between ONEOK Inc. and Security Pacific National Bank, incorporated by reference from Form S-3 Registration Statement No. 33-31979. (4)(e) Indenture, dated December 1, 1990, between ONEOK Inc. and Security Pacific National Bank, incorporated by reference from Form 10-K dated August 31, 1991. (4)(f) First Supplemental Indenture dated December 1, 1990, between ONEOK Inc. and Security Pacific National Bank, incorporated by reference from Form 10-K dated August 31, 1991. (4)(g) Second Supplemental Indenture dated October 1, 1991, between ONEOK Inc. and Security Pacific National Bank, incorporated by reference from Form 10-K dated August 31, 1991. 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)(h) 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). (4)(i) 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). </TABLE> 74
75 <TABLE> <S> <C> <C> (4)(j) Indenture, dated September 24, 1998, between ONEOK, Inc. and Chase Bank of Texas, incorporated by reference from Exhibit 4.1 to Registration Statement on Form S-3 filed August 26, 1998. (4)(k) 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)(l) 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)(m) 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)(n) 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. (4)(o) 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. (10)(a) ONEOK, Inc. Key Employee Annual Incentive Plan as amended and accepted on November 26, 1997. (10)(b) ONEOK, Inc. Long-Term Incentive Plan, incorporated by reference from Exhibit 99 on Form 8- K dated June 18, 1999. (10)(c) ONEOK, Inc. Supplemental Executive Retirement Plan as amended and restated July 1, 1999. (10)(d) Termination agreements between ONEOK, Inc., and ONEOK, Inc. Executives dated January 1, 1999. (10)(e) Indemnification agreement between ONEOK Inc., and ONEOK Inc. Officers and Directors. (10)(f) 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)(g) 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)(h) Sublease Between RMZ Corp. and ONEOK Leasing Company dated May 15, 1983, incorporated by reference from Form 10-K dated August 31, 1983. (10)(i) 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)(j) 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)(k) 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. </TABLE> 75
76 <TABLE> <S> <C> <C> (10)(l) 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)(m) $600,000,000 364-Day Credit Agreement date July 2, 1999, among ONEOK, Inc., Bank of America National Trust and Savings Association, as Administrative Agent and as a Bank, Letter of Credit Issuing Bank and Swing Line Bank, and the other financial institutions party hereto incorporated by reference from Form 8-K filed November 8, 1999. (12) Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirement. (12)(a) Computation of Ratio of Earnings to Fixed Charges. (21) Required information concerning the registrant's subsidiaries. (23) Independent Auditors' Consent, filed herewith on page 66. (27)(a) Financial Data Schedule for year ended August 31, 1999. (27)(b) Financial Data Schedule for year ended August 31, 1998. (27)(c) Financial Data Schedule for year ended August 31, 1997. </TABLE> <TABLE> <CAPTION> (2) Financial Statements Page No. <S> <C> (a) Independent Auditors' Report. 40 (b) Consolidated Statements of Income for the years ended August 31, 1999, 1998, and 1997. 41 (c) Consolidated Balance Sheets at August 31, 1999 and 1998. 42 - 43 (d) Consolidated Statements of Cash Flows for the years ended August 31, 1999, 1998, and 1997. 44 (e) Consolidated Statements of Shareholder's Equity for the years ended August 31, 1998, 1997, and 1996. 45 (f) Notes to Consolidated Financial Statements. 46 - 65 (3) Financial Statement Schedules None. </TABLE> (B) REPORTS ON FORM 8-K June 22, 1999 - announced the Public Utility Commission of Nevada has approved the proposed merger between the Company and Southwest Gas. July 12, 1999 - updated financial information relating to the Southwest Gas and required pro forma financial information. July 28, 1999 - announced plans for moving into the electric generation and power marketing business. August 6, 1999 - information relating to legal matters on the pending Southwest Gas merger. 76
77 August 9, 1999 - announced Southern Union Company's failure in two separate court actions to delay shareholder vote and the regulatory approval process for the pending Southwest Gas merger. August 11, 1999 - announced the approval of the pending Southwest Gas merger by the shareholders of Southwest Gas. August 17, 1999 - announced public offering for $300 million 7 3/4% notes. October 14, 1999 - Chairman and CEO Larry Brummett addressed Oklahoma Corporation Commission to say the false allegations about a 1993 gas purchase contract may jeopardize the planned merger with Southwest Gas. October 21, 1999 - announced fiscal year change. November 8, 1999 - short-term credit agreement signed. OTHER MATTERS None. 77
78 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 18th day of November 1999. ONEOK, Inc. Registrant By: Jim Kneale ------------------------------------ Jim Kneale Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer) 78
79 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 18th day of November 1999. <TABLE> <S> <C> Larry W. Brummett David L. Kyle - ------------------------------------ ----------------------------------- Larry W. Brummett David L. Kyle Chairman of the Board, President, Chief Operating Chief Executive Officer Officer and Director and Director Edwyna G. Anderson Bert H. Mackie - ------------------------------------ ----------------------------------- Edwyna G. Anderson Bert H. Mackie Director Director William M. Bell Douglas A. Newsom - ------------------------------------ ----------------------------------- William M. Bell Douglas A. Newsom Director Director Douglas R. Cummings Gary D. Parker - ------------------------------------ ----------------------------------- Douglas R. Cummings Gary D. Parker Director Director William L. Ford - ------------------------------------ ----------------------------------- William L. Ford J. D. Scott Director Director Stanton L. Young - ------------------------------------ ----------------------------------- Howard R. Fricke Stanton L. Young Director Director Douglas T. Lake - ------------------------------------ Douglas T. Lake Director </TABLE> 79
80 EXHIBIT INDEX <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION -------- ----------- <S> <C> (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-4filed August 6, 1997). (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) Amendment to 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) By-laws of ONEOK, Inc., as amended. (4)(a) Article "Fourth" of the Certificate of Incorporation of ONEOK, Inc. (Preferred Stock and Common Stock), Incorporated by reference from Exhibit 3.1 to Amendment No. 3 to Registration Statement on Form S-4 filed August 31, 1997) (4)(b) 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). (4)(c) Certificate of Designation for Series C Participating Preferred Stock of ONEOK, Inc., filed November 26, 1998 (Incorporated by reference from Exhibit No. 1 to Form 8-A, filed November 26, 1997). (4)(d) Indenture, dated November 28, 1989, between ONEOK Inc. and Security Pacific National Bank, incorporated by reference from Form S-3 Registration Statement No. 33-31979. (4)(e) Indenture, dated December 1, 1990, between ONEOK Inc. and Security Pacific National Bank, incorporated by reference from Form 10-K dated August 31, 1991. (4)(f) First Supplemental Indenture dated December 1, 1990, between ONEOK Inc. and Security Pacific National Bank, incorporated by reference from Form 10-K dated August 31, 1991. (4)(g) Second Supplemental Indenture dated October 1, 1991, between ONEOK Inc. and Security Pacific National Bank, incorporated by reference from Form 10-K dated August 31, 1991. 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)(h) 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). (4)(i) 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). (4)(j) Indenture, dated September 24, 1998, between ONEOK, Inc. and Chase Bank of Texas, incorporated by reference from Exhibit 4.1 to Registration Statement on Form S-3 filed August 26, 1998. (4)(k) 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)(l) 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)(m) 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)(n) 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. (4)(o) 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. (10)(a) ONEOK, Inc. Key Employee Annual Incentive Plan as amended and accepted on November 26, 1997. (10)(b) ONEOK, Inc. Long-Term Incentive Plan, incorporated by reference from Exhibit 99 on Form 8- K dated June 18, 1999. (10)(c) ONEOK, Inc. Supplemental Executive Retirement Plan as amended and restated July 1, 1999. (10)(d) Termination agreements between ONEOK, Inc., and ONEOK, Inc. Executives dated January 1, 1999. (10)(e) Indemnification agreement between ONEOK Inc., and ONEOK Inc. Officers and Directors. (10)(f) 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)(g) 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)(h) Sublease Between RMZ Corp. and ONEOK Leasing Company dated May 15, 1983, incorporated by reference from Form 10-K dated August 31, 1983. (10)(i) 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)(j) 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)(k) 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)(l) 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)(m) $600,000,000 364-Day Credit Agreement date July 2, 1999, among ONEOK, Inc., Bank of America National Trust and Savings Association, as Administrative Agent and as a Bank, Letter of Credit Issuing Bank and Swing Line Bank, and the other financial institutions party hereto incorporated by reference from Form 8-K filed November 8, 1999. (12) Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirement. (12)(a) Computation of Ratio of Earnings to Fixed Charges. (21) Required information concerning the registrant's subsidiaries. (23) Independent Auditors' Consent, filed herewith on page 66. (27)(a) Financial Data Schedule for year ended August 31, 1999. (27)(b) Financial Data Schedule for year ended August 31, 1998. (27)(c) Financial Data Schedule for year ended August 31, 1997. </TABLE>