F O R M 1 0 - K SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 (Mark One) [x] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED] For the fiscal year ended December 31, 1999 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] For the transition period from ________ to _________ [Commission File Number 1-9260] U N I T C O R P O R A T I O N (Exact Name of Registrant as Specified in its Charter) Delaware 73-1283193 -------- ---------- (State of Incorporation) (I.R.S. Employer Identification No.) 1000 Kensington Tower 7130 South Lewis Tulsa, Oklahoma 74136 --------------- ----- (Address of Principal Executive Offices) (Zip Code) Registrant's Telephone Number, Including Area Code (918) 493-7700 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Title of each class Name of each exchange ------------------- on which registered Common Stock, par value ------------------- $.20 per share New York Stock Exchange 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 Regulation S-K (Section 229.405 of this chapter) 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. Aggregate Market Value of the Voting Stock Held By Non-affiliates on March 6, 2000 - $216,536,460 Number of Shares of Common Stock Outstanding on March 6, 2000 - 33,820,476 DOCUMENTS INCORPORATED BY REFERENCE 1. Portions of Registrant's Proxy Statement with respect to the Annual Meeting of Stockholders to be held May 3, 2000 are incorporated by reference in Part III. Exhibit Index - See Page 87 FORM 10-K UNIT CORPORATION TABLE OF CONTENTS PART I Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . 3 Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . 3 Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . 24 Item 4. Submission of Matters to a Vote of Security Holders . . 24 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters . . . . . . . . . . . . . . . . . 25 Item 6. Selected Financial Data . . . . . . . . . . . . . . . . 26 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . 27 Item 7a. Quantitative and Qualitative Disclosure about Market Risk. . . . . . . . . . . . . . . . . . . . . 34 Item 8. Financial Statements and Supplementary Data . . . . . . 36 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . 77 PART III Item 10. Directors and Executive Officers of the Registrant. . . 77 Item 11. Executive Compensation. . . . . . . . . . . . . . . . . 79 Item 12. Security Ownership of Certain Beneficial Owners and Management. . . . . . . . . . . . . . . . . . . . 79 Item 13. Certain Relationships and Related Transactions. . . . . 79 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . . . . . . . . . . . . . . . . . 80 Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . 86 2 UNIT CORPORATION Annual Report For The Year Ended December 31, 1999 PART I Item 1. Business and Item 2. Properties - ------- -------- ------- ---------- GENERAL Through our wholly owned subsidiaries, we contract to drill onshore oil and natural gas wells for others and explore, develop, acquire and produce oil and natural gas properties for ourself. We were founded in 1963 as a contract drilling company. Today our contract drilling operations and our exploration and production operations are carried out primarily in the natural gas producing provinces of the Oklahoma and Texas areas of the Anadarko and Arkoma Basins and the Texas Gulf Cost. Our contract drilling operations are also engaged in the Rocky Mountain region. Our principal executive offices are located at 1000 Kensington Tower, 7130 South Lewis, Tulsa, Oklahoma 74136; telephone number (918) 493-7700. We also have regional offices in Oklahoma City, Oklahoma, Woodward, Oklahoma, Booker, Texas, Houston, Texas and Casper, Wyoming. When used in this report, the terms Corporation, Unit, our, we and its refer to Unit Corporation and, at times, Unit Corporation and/or one or more of its subsidiaries. LAND CONTRACT DRILLING OPERATIONS We drill onshore natural gas and oil wells for a wide range of customers through our wholly owned subsidiary Unit Drilling Company. A land drilling rig consists, in part, of engines, drawworks or hoists, derrick or mast, substructure, pumps to circulate the drilling fluid, blowout preventers and drill pipe. We conduct an active maintenance and replacement program under which components are upgraded on an individual basis. Over the life of a typical rig, due to the normal wear and tear of operating 24 hours a day, several of the major components, such as engines, mud pumps and drill pipe, are replaced or rebuilt on a periodic basis, while other components, such as the substructure, mast and drawworks, can be utilized for extended periods of time with proper maintenance. We also own additional equipment used in the operation of our rigs, including large air compressors, trucks and other support equipment. On November 20, 1997, we acquired Hickman Drilling Company pursuant to a merger in which all of the holders of the outstanding common stock of Hickman Drilling received, in total, 1,300,000 shares of our common stock and promissory notes in the principal amount of $5,000,000 which area 3 payable in five equal annual installments commencing January 2, 1999. The acquisition included nine land contract drilling rigs with depth capacities ranging from 9,500 to 17,000 feet, spare drilling equipment and approximately $2.1 million in working capital. As part of the acquisition we retained Hickman Drilling's Woodward, Oklahoma, corporate office as a regional office for our contract drilling operations. In December 1997, we purchased a Mid-Continent U-36A, 650 horsepower rig with a 13,000 foot depth capacity and spare components from two additional rigs for $1 million, of which $200,000 was paid at closing with the balance to be paid over a period no longer than three years. On September 30, 1999, we completed the acquisition of 13 land drilling rigs from Parker Drilling Company and Parker Drilling Company North America, Inc., for $40 million and one million shares of our common stock. At the end of 1999, our drilling rig fleet consisted of 47 rigs with depth capacities ranging from 9,500 to 40,000 feet. At December 31, 1999, 31 of our rigs were located in the Anadarko and Arkoma Basins of Oklahoma and Texas while nine of our rigs were located in South Texas and seven in the Rocky Mountain region. At present, we do not have a shortage of drilling rig related equipment. During 1996 and through 1997, we increased our drill pipe acquisitions since certain grades of drill pipe were in high demand due to increased rig utilization. However, at any given time our ability to use all of our rigs will depend on the availability of qualified labor, drilling supplies and equipment as well as demand. Should industry conditions improve rapidly, we, as well as the drilling industry as a whole, might experience a shortage of sufficient supplies of drill pipe, other drilling equipment and qualified labor. 4 The following table sets forth, for each of the periods indicated, certain data concerning Unit's contract drilling operations: Year Ended December 31, ----------------------------------------- 1995 1996 1997 1998 1999 ------ ------ ------ ------ ------ Number of Operational Rigs Owned at End of Period 22.0 24.0 34.0(1) 34.0 47.0(2) Average Number of Rigs Owned During Period 25.0 22.7 25.1 34.0 37.3 Average Number of Rigs Utilized (3) 10.9 14.7 20.0 22.9 23.1 Utilization Rate (3) 44% 65% 80% 67% 62% Average Revenue Per Day (4) $5,081 $5,351 $6,309 $6,394 $6,582 Total Footage Drilled (Feet in 1000's) 1,196 1,468 1,736 2,203 2,211 Number of Wells Drilled 111 130 167 198 197 - ---------------------- (1) Includes 10 rigs acquired in the fourth quarter of 1997. (2) Includes 13 rigs acquired in September 1999. (3) Utilization rates are based on a 365-day year and are calculated by dividing the number of rigs utilized by the total number of rigs owned during the period, including stacked rigs. A rig is considered utilized when it is operating or being moved, assembled or dismantled under contract. (4) Represents total revenues from contract drilling operations divided by the total number of days rigs were being utilized for the period. As of February 22, 2000, 33 of our 47 drilling rigs were operating under contract. 5 The following table sets forth, as of February 22, 2000, the type and approximate depth capability of each of our drilling rigs: Approximate Depth Capability Rig# Type (feet) ----- --------------------------- ----------- 1 U-15 Unit Rig 11,000 2 BDW 650 13,000 3 BDW 650 13,500 4 U-15 Unit Rig 11,000 5 U-15 Unit Rig 11,000 6 BDW 800 15,000 7 U-15 Unit Rig 11,000 8 Gardner Denver 800 15,000 9 BDW 800 15,000 10 BDW 450T 9,500 11 Gardner Denver 700 15,000 12 BDW 800-M1 15,000 14 Gardner Denver 700 15,000 15 Mid-Continent 914-C 20,000 16 U-15 Unit Rig 11,000 17 Brewster N-75A 15,000 18 BDW 650 12,000 19 Gardner Denver 500 12,000 20 Gardner Denver 700 15,000 21 Gardner Denver 700 15,000 22 BDW 800 15,000 23 Gardner Denver 700M 15,000 24 Gardner Denver 700M 15,000 25 Gardner Denver 700 15,000 29 Brewster N-75A 15,000 30 BDW 1350-M 20,000 31 SU-15 North Texas Machine 12,000 32 Brewster N-75 15,000 34 National 110-UE 20,000 35 Continental Emsco C-1-E 20,000 36 Gardner Denver 1500-E 25,000 37 Mid-Continent 914-EC 20,000 38 Mid-Continent 1220-E 25,000 39 U-36-A 13,000 112 Ideco E-3000 30,000 166 OIME E-3000 30,000 180 OIME E-3000 30,000 182 OIME E-3000 30,000 184 OIME E-3000 30,000 201 OIME E-4000 40,000 203 OIME E-2000 20,000 232 Continental Emsco D-3 E 16,000 233 Continental Emsco C-1 E 20,000 234 Continental Emsco D-3 E 16,000 235 Continental Emsco C-1 E 20,000 237 Continental Emsco C-1 E 20,000 254 OIME E-2000 25,000 6 During the past 15 years, our contract drilling operations have encountered significant competition due to depressed levels of activity. In the last 6 months of 1996 and throughout 1997 and the first three quarters of 1998, our drilling operations showed significant improvement in rig utilization. However, in late 1998 and through the first six months of 1999 we, and the industry as a whole, experienced a significant reduction in demand. Although we experienced an increase in demand during the last half of 1999, we anticipate that competition within the industry will, for the foreseeable future, continue to adversely affect us. Drilling Contracts. Most of our drilling contracts are obtained through competitive bidding. Generally, our contracts are for a single well with the terms and rates varying depending upon the nature and duration of the work, the equipment and services supplied and other matters. The contracts obligate us to pay certain operating expenses, including wages of drilling personnel, maintenance expenses and incidental rig supplies and equipment. Usually, the contracts are subject to termination by the customer on short notice upon payment of a fee. We generally indemnify our customers against certain types of claims by our employees and claims arising from surface pollution caused by spills of fuel, lubricants and other solvents within our control. Customers generally indemnify us against claims arising from other surface and subsurface pollution other than claims resulting from our gross negligence. Our contracts generally compensate us on a daywork, footage or turnkey basis with additional compensation for special risks and unusual conditions. Under daywork contracts, we provide the drilling rig with the required personnel to the operator who supervises the drilling of the contracted well. Our compensation is based on a negotiated rate for each day the rig is utilized. Footage contracts usually require us to bear some of the drilling costs in addition to providing the rig. We are compensated on a negotiated rate, per foot drilled, upon completion of the well. Under turnkey contracts, we contract to drill a well for a lump sum amount to a specified depth and provide most of the equipment and services required. We bear the risk of drilling the well to the contract depth and are compensated when the contract provisions have been satisfied. Turnkey drilling operations, in particular, might result in losses if we underestimate the costs of drilling a well or if unforeseen events occur. To date, we have not experienced significant losses in performing turnkey contracts. For 1999, turnkey revenue represented approximately 21 percent of our contract drilling revenues as compared to 15 percent for 1998. Because the proportion of turnkey drilling is currently dictated by market conditions and the desires of customers using our services, we can't predict whether the portion of drilling conducted on a turnkey basis will increase or decrease in the future. Customers. During 1999, 10 contract drilling customers accounted for approximately 23 percent of our total contract drilling revenues. Approximately 3 percent of our total contract drilling revenues were 7 generated from drilling on oil and natural gas properties of which we were the operator (including properties owned by limited partnerships for which we acted as general partner). Further information relating to contract drilling operations is presented in Notes 1, 2 and 10 of Notes to Consolidated Financial Statements set forth in Item 8 hereof. OIL AND NATURAL GAS OPERATIONS In 1979, we began to develop our exploration and production operations to diversify our contract drilling revenues. Our wholly owned subsidiary, Unit Petroleum Company, conducts our exploration and production activities. As of December 31, 1999, we had estimated net proved reserves of 3,934 Mbbls and 170,084 MMcf. Our producing oil and natural gas interests, undeveloped leaseholds and related assets are located primarily in Oklahoma, Texas, Louisiana and New Mexico and, to a lesser extent, in Arkansas, North Dakota, Colorado, Wyoming, Montana, Alabama, Mississippi, Illinois, Michigan, Nebraska and Canada. As of December 31, 1999, we had an interest in a total of 2,419 wells in the United States and served as the operator of 519 wells. We also had an interest in 64 wells located in Canada. Our technical staff generates the majority of our development and exploration prospects. When we are the operator of a property, we generally employ our own drilling rigs and our own engineering staff supervises the drilling operation. We intend to continue the growth in our oil and natural gas operations utilizing funds generated from operations and our bank loan agreement. 8 Well and Leasehold Data. The tables below set forth certain information regarding our oil and natural gas exploration and development drilling activities for the periods indicated: Year Ended December 31, --------------------------------------------------------- 1997 1998 1999 ------------------ ----------------- ------------------ Gross Net Gross Net Gross Net -------- -------- -------- -------- -------- -------- Wells Drilled: - -------------- Exploratory: Oil - - - - - - Natural gas - - - - - - Dry - - 1 .26 - - -------- -------- -------- -------- -------- -------- Total - - 1 .26 - - ======== ======== ======== ======== ======== ======== Development: Oil 10 4.84 4 .44 1 .48 Natural gas 57 23.85 52 19.26 43 16.23 Dry 15 9.27 21 10.62 7 4.72 -------- -------- -------- -------- -------- -------- Total 82 37.96 77 30.32 51 21.43 ======== ======== ======== ======== ======== ======== Oil and Natural Gas Wells Producing or Capable of Producing: - --------------- Oil - USA 684 197.67 726 196.64 668 206.08 Oil - Canada - - - - - - Gas - USA 1,545 260.40 1,773 286.73 1,751 314.28 Gas - Canada 64 1.60 64 1.60 64 1.60 -------- -------- -------- -------- -------- -------- Total 2,293 459.67 2,563 484.97 2,483 521.96 ======== ======== ======== ======== ======== ======== 9 The following table summarizes our oil and natural gas leasehold acreage as of the end of each of the years indicated: Developed Acreage Undeveloped Acreage --------------------- --------------------- Gross Net Gross Net --------- --------- --------- --------- 1997: - ----- USA 432,824 118,926 37,844 26,116 Canada 39,040 976 18,970 18,970 --------- --------- --------- --------- 471,864 119,902 56,814 45,086 ========= ========= ========= ========= 1998: - ----- USA 569,076 130,440 52,958 35,371 Canada 39,040 976 22,763 22,763 --------- --------- --------- --------- Total 608,116 131,416 75,721 58,134 ========= ========= ========= ========= 1999: - ----- USA 488,811 130,362 55,989 35,245 Canada 39,040 976 25,293 25,293 --------- --------- --------- --------- Total 527,851 131,338 81,282 60,538 ========= ========= ========= ========= 10 Price and Production Data. The following table sets forth our average sales price, oil and natural gas production volumes and average production cost per equivalent Mcf [1 barrel (Bbl) of oil = 6 thousand cubic feet (Mcf) of natural gas] of production for the periods indicated: Year Ended December 31, ---------------------------------- 1997 1998 1999 ---------- ---------- ---------- Average Sales Price per Barrel of Oil Produced: USA $ 19.19 $ 12.81 $ 17.51 Canada - - - Average Sales Price per Mcf of Natural Gas Produced: USA $ 2.43 $ 1.90 $ 2.02 Canada $ .93 $ 1.46 $ 1.81 Oil Production (Mbbls): USA 493 443 373 Canada - - - ---------- ---------- ---------- Total 493 443 373 ========== ========== ========== Natural Gas Production (MMcf): USA 13,742 16,427 15,919 Canada 74 38 35 ---------- ---------- ---------- Total 13,816 16,465 15,954 ========== ========== ========== Average Production Expense per Equivalent Mcf: USA $ .64 $ .61 $ .58 Canada $ .33 $ .54 $ .56 11 Reserves. The following table sets forth our estimated proved developed and undeveloped oil and natural gas reserves at the end of each of the years indicated: Year Ended December 31, ---------------------------------- 1997 1998 1999 ---------- ---------- ---------- Oil (Mbbls): USA 4,131 3,245 3,934 Canada - - - ---------- ---------- ---------- Total 4,131 3,245 3,934 ========== ========== ========== Natural gas (MMcf): USA 144,661 160,795 169,515 Canada 723 523 569 ---------- ---------- ---------- Total 145,384 161,318 170,084 ========== ========== ========== Further information relating to oil and natural gas operations is presented in Notes 1, 10 and 12 of Notes to Consolidated Financial Statements set forth in Item 8 hereof. VOLATILE NATURE OF OUR OIL AND NATURAL GAS MARKETS; FLUCTUATIONS IN PRICES Our revenues, operating results, cash flows and future rate of growth are significantly affected by the prevailing prices for natural gas and oil. Historically, oil and natural gas prices and markets have been volatile, and they are likely to continue to be volatile in the future. Oil and natural gas prices declined substantially in 1998 and, despite recent improvements, could decline again. These declines had a significant negative impact on our financial results for 1998 and the first six months of 1999. We incurred a net loss for the two quarterly periods ending March 31 and June 30, 1999 before incurring net income for the two quarterly periods ending September 30 and December 31, 1999. Although we had net income for the twelve months ended December 31, 1999, depressed prices in the future would have a negative impact on our future financial results. Because our oil and natural gas reserves are predominantly natural gas, changes in natural gas prices may have a particularly large impact on our financial results. 12 Prices for oil and natural gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. These factors include: . political conditions in oil producing regions, including the Middle East; . the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; . the price of foreign imports; . actions of governmental authorities; . the domestic and foreign supply of oil and natural gas; . the level of consumer demand; . weather conditions; . domestic and foreign government regulations; . the price, availability and acceptance of alternative fuels; and . overall economic conditions. These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of oil and natural gas. Our oil and condensate production is sold at or near our wells under purchase contracts at prevailing prices in accordance with arrangements customary in the oil industry. Our natural gas production is sold to intrastate and interstate pipelines as well as to independent marketing firms under contracts with original terms ranging from one month to several years. Most of these contracts contain provisions for readjustment of price, termination and other terms customary in the industry. Our contract drilling operations depend on levels of activity in the oil and natural gas exploration and production in our operating markets. Both short-term and long-term trends in oil and natural gas prices affect the level of that activity. Because oil and natural gas prices are volatile, the level of exploration and production activity can also be volatile. Decreased oil and natural gas prices during 1998 and early 1999 adversely affected our contract drilling activity by lowering the demand for our rigs and reducing the rates we charged for our rigs. 13 Although oil and natural gas prices have recently improved, we expect that in the near term our customers will continue a cautious approach to exploration and development spending until price gains prove to be sustainable. Any decrease from current oil and natural gas prices would depress the level of exploration and production activity. This in turn would likely result in a decline in our contract drilling revenues, cash flows and profitability. As a result, the future demand for our drilling services is uncertain. COMPETITION All of our lines of business are highly competitive. Competition in onshore contract drilling traditionally involves such factors as price, efficiency, condition of equipment, availability of labor and equipment, reputation and customer relations. Some of our competitors in the onshore contract drilling business are substantially larger than we are and have appreciably greater financial and other resources. As a result of the decrease in demand for onshore contract drilling services over the past decade, a surplus of certain types of drilling rigs currently exists within the industry while inventories of certain components such as specific grades of drill pipe have been depleted from continued use. Accordingly, the competitive environment within which we operate is uncertain and extremely price oriented. Our oil and natural gas operations likewise encounter strong competition from major oil companies, independent operators and others. Many of these competitors have appreciably greater financial, technical and other resources and are more experienced in the exploration for and production of oil and natural gas than we are. OIL AND NATURAL GAS PROGRAMS Our subsidiary, Unit Petroleum Company, serves as the general partner of four oil and gas limited partnerships and 11 employee oil and gas limited partnerships. Each year we form an employee partnership which acquires an interest, ranging from 5% to 15% of our interest, in most oil and natural gas drilling activities and purchases of producing oil and natural gas properties that we do that year. The limited partners in the employee partnerships are either employees or directors of Unit or its subsidiaries. Under the terms of the partnership agreements, the general partner has broad discretionary authority to manage the business and operations of the partnership, including the authority to make decisions on such matters as the partnership's participation in a drilling location or a property acquisition, the partnership's expenditure of funds and the distribution of funds to partners. Because the business activities of the limited partners 14 on the one hand, and the general partner on the other hand, are not the same, conflicts of interest will exist and it is not possible to eliminate entirely such conflicts. Additionally, conflicts of interest may arise when we are the operator of an oil and natural gas well and also provide contract drilling services. In such cases, these drilling operations are done pursuant to contracts containing terms and conditions comparable to those contained in our drilling contracts with non-affiliated operators. Although we have no formal procedures for resolving such conflicts, we believe we fulfill our responsibility to each contracting party and comply fully with the terms of the agreements which regulate such conflicts. EMPLOYEES As of February 22, 2000, we had approximately 735 employees in our land contract drilling operations, 48 employees in our oil and natural gas operations and 41 in our general corporate area. None of our employees are represented by a union or labor organization nor have our operations ever been interrupted by a strike or work stoppage. We consider relations with our employees to be satisfactory. OPERATING AND OTHER RISKS Our drilling operations are subject to many hazards inherent in the drilling industry, including blowouts, cratering, explosions, fires, loss of well control, loss of hole, damaged or lost drilling equipment and damage or loss from inclement weather. Our exploration and production operations are subject to these and similar risks Any of these events could result in personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental damage and damage to the property of others. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer, and we seek to obtain indemnification from our drilling customers by contract for some of these risks. To the extent that we are unable to transfer these risks to drilling customers by contract or indemnification agreements, we seek protection through insurance. However, we cannot assure you that our insurance or our indemnification agreements, if any, will adequately protect us against liability from all of the consequences of the hazards described above. The occurrence of an event not fully insured or indemnified against, or the failure of a customer to meet its indemnification obligations, could result in substantial losses to us. In addition, we cannot assure you that insurance will be available to cover any or all of these risks. Even if available, the insurance might not be adequate to cover all of our losses, or we might decide against obtaining that insurance because of high premiums or other costs. Exploration and development operations involve numerous risks that may result in dry holes, the failure to produce oil and natural gas in commercial quantities and the inability to fully produce discovered 15 reserves. The cost of drilling, completing and operating wells is substantial and uncertain. Our operations may be curtailed, delayed or cancelled as a result of many things beyond our control, including: . unexpected drilling conditions; . pressure or irregularities in formations; . equipment failures or accidents; . adverse weather conditions; . compliance with governmental requirements; and . shortages or delays in the availability of drilling rigs or delivery crews and the delivery of equipment. The majority of the wells in which we own an interest are operated by other parties. As a result, we have little control over the operations of such wells which can act to increase our risk. Operators of these wells may act in ways that are not in our best interests. Our future performance depends upon our ability to find or acquire additional oil and natural gas reserves that are economically recoverable. In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, resulting eventually in a decrease in oil and natural gas production and lower revenues and cash flow from operations. Historically, we have succeeded in increasing reserves after taking production into account through exploitation, development and exploration. We have conducted such activities on our existing oil and natural gas properties as well as on newly acquired properties. We may not be able to continue to replace reserves from such activities at acceptable costs. Low prices of oil and natural gas may further limit the kinds of reserves that can economically be developed. Lower prices also decrease our cash flow and may cause us to decrease capital expenditures. GOVERNMENTAL REGULATIONS The production and sale of oil and natural gas is highly affected by various state and federal regulations. All states in which we conduct activities impose restrictions on the drilling, production, transportation and sale of oil and natural gas. Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission (the "FERC") regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. The FERC's jurisdiction over interstate natural gas sales was substantially modified by the Natural Gas Policy Act under which the FERC continued to regulate the maximum selling prices of certain categories of gas sold in "first sales" in interstate and intrastate commerce. Effective January 1, 1993, 16 however, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act") deregulated natural gas prices for all "first sales" of natural gas. Because "first sales" include typical wellhead sales by producers, all natural gas produced from our natural gas properties is being sold at market prices, subject to the terms of any private contracts which may be in effect. The FERC's jurisdiction over natural gas transportation was not affected by the Decontrol Act. Our sales of natural gas are affected by intrastate and interstate gas transportation regulation. Beginning in 1985, the FERC adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesale marketers of natural gas to the primary role of gas transporters. All natural gas marketing by the pipelines was required to be divested to a marketing affiliate, which operates separately from the transporter and in direct competition with all other merchants. As a result of the various omnibus rulemaking proceedings in the late 1980s and the individual pipeline restructuring proceedings of the early to mid- 1990s, the interstate pipelines are now required to provide open and nondiscriminatory transportation and transportation-related services to all producers, natural gas marketing companies, local distribution companies, industrial end users and other customers seeking service. Through similar orders affecting intrastate pipelines that provide similar interstate services, the FERC expanded the impact of open access regulations to intrastate commerce. More recently, the FERC has pursued other policy initiatives that have affected natural gas marketing. Most notable are (1) the large-scale divestiture of interstate pipeline-owned gas gathering facilities to affiliated or non-affiliated companies; (2) further development of rules governing the relationship of the pipelines with their marketing affiliates; (3) the publication of standards relating to the use of electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information on a timely basis and to enable transactions to occur on a purely electronic basis; (4) further review of the role of the secondary market for released pipeline capacity and its relationship to open access service in the primary market; and (5) development of policy and promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of- service based rates) for transportation or transportation-related services upon the pipeline's demonstration of lack of market control in the relevant service market. It remains to be seen what effect the FERC's other activities will have on the access to markets, the fostering of competition and the cost of doing business. As a result of these changes, sellers and buyers of natural gas have gained direct access to the particular pipeline services they need and are better able to conduct business with a larger number of counter parties. We believe these changes generally have improved the access to markets for 17 natural gas while, at the same time, substantially increasing competition in the natural gas marketplace. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt or what effect subsequent regulations may have on production and marketing of natural gas from our properties. In the past, Congress has been very active in the area of natural gas regulation. However, as discussed above, the more recent trend has been in favor of deregulation and the promotion of competition in the natural gas industry. Thus, in addition to "first sales" deregulation, Congress also repealed incremental pricing requirements and natural gas use restraints previously applicable. There are other legislative proposals pending in the Federal and State legislatures which, if enacted, would significantly affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, these proposals might have on the production and marketing of natural gas by us. Similarly, and despite the trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue or what the ultimate effect will be on the production and marketing of natural gas by us cannot be predicted. Our sales of oil and natural gas liquids are not regulated and are at market prices. The price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. These regulations have generally been approved on judicial review. Every five years, the FERC will examine the relationship between the annual change in the applicable index and the actual cost changes experienced by the oil pipeline industry. The first such review is scheduled for the year 2000. We are not able to predict with certainty what effect, if any, these relatively new federal regulations or the periodic review of the index by the FERC will have on us. Federal, state, and local agencies have promulgated extensive rules and regulations applicable to our oil and natural gas exploration, production and related operations. Oklahoma, Texas and other states require permits for drilling operations, drilling bonds and the filing of reports concerning operations and impose other requirements relating to the exploration of oil and natural gas. Many states also have statutes or regulations addressing conservation matters including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the 18 regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of some states limit the rate at which oil and natural gas can be produced from our properties. The federal and state regulatory burden on the oil and natural gas industry increases our cost of doing business and affects its profitability. Because these rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with those laws. SAFE HARBOR STATEMENT OF FURTHER ACTIVITY Statements in this document as well as information contained in written material, press releases and oral statements issued by or on behalf of us contain, or may contain, certain "forward-looking statements" within the meaning of federal securities laws. All statements, other than statements of historical facts, included in this document which address activities, events or developments which we expect or anticipate will or may occur in the future are forward-looking statements. The words "believes," "intends," "expects," "anticipates," "projects," "estimates," "predicts" and similar expressions are also intended to identify forward- looking statements. These forward-looking statements include, among others, such things as: . Year 2000 plans; . the amount and nature of future capital expenditures; . wells to be drilled or reworked; . oil and natural gas prices and demand; . exploitation and exploration prospects; . estimates of proved oil and natural gas reserves; . reserve potential; . development and infill drilling potential; . drilling prospects; . expansion and other development trends of the oil and natural gas industry; . business strategy; . production of oil and natural gas reserves; . expansion and growth of our business and operations; and . drilling rig utilization, revenues and costs. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties which could cause actual results to differ materially from our expectations, including: . the risk factors discussed in this document; . general economic, market or business conditions; . the nature or lack of business opportunities that may be presented to 19 and pursued by us; . demand for land drilling services; . changes in laws or regulations; and . other factors, most of which are beyond our control. In order to provide a more thorough understanding of the possible effects of some of these influences on any forward-looking statements made by us, the following discussion outlines certain factors that in the future could cause our consolidated results for 2000 and beyond to differ materially from those that may be set forth in any such forward-looking statement made by or on behalf of us. Commodity Prices The prices we receive for our oil and natural gas production have a direct impact on our revenues, profitability and cash flow as well as our ability to meet our projected financial and operational goals. The prices for natural gas and crude oil are heavily dependent on a number of factors beyond our control, including the demand for oil and/or natural gas; current weather conditions in the continental United States which can greatly influence the demand for natural gas at any given time as well as the price to be received for such natural gas; and the ability of current distribution systems in the United States to effectively meet the demand for oil and or natural gas at any given time, particularly in times of peak demand which may result due to adverse weather conditions. Oil prices are extremely sensitive to foreign influences that may be based on political, social or economic underpinnings, any one of which could have an immediate and significant effect on the price and supply of oil. In addition, prices of both natural gas and oil are becoming more and more influenced by trading on the commodities markets which, at times, has tended to increase the volatility associated with these prices resulting, at times, in large differences in such prices even on a month-to-month basis. All of these factors, especially when coupled with the fact that much of our product prices are determined on a month-to-month basis, can, and at times do, lead to wide fluctuations in the prices we receive. Based upon the results of our operations for 1999 we estimate that a change of $0.10/Mcf in the average price of natural gas and a change of $1.00/Bbl in the price of crude oil throughout such period would have resulted in approximate changes in net income before income taxes of $1,488,000 and $348,000, respectively. During 1999, substantially all of our natural gas and crude oil volumes were sold at market responsive prices. In order to reduce our exposure to short-term fluctuations in the price of oil and natural gas, we sometimes enter into hedging or swap arrangements. Our hedging or swap arrangements apply to only a portion of our production and provide only partial price protection against declines in oil and natural gas prices. These hedging or swap arrangements may 20 expose us to risk of financial loss and limit the benefit to us of increases in prices. Customer Demand Demand for our drilling services is dependent almost entirely on the needs of third parties. Based on past history, such parties' requirements are subject to a number of factors, independent of any subjective factors, that directly impact the demand for our drilling rigs. These include the availability of funds to such third parties to carry out their drilling operations during any given time period which, in turn, are often subject to downward revision based on decreases in the then current prices of oil and natural gas. Many of our customers are small to mid-size oil and natural gas companies whose drilling budgets tend to be susceptible to the influences of current price fluctuations. Other factors that affect our ability to work our drilling rigs are: the weather which, under adverse circumstances, can delay or even cause a project to be abandoned by an operator; the competition faced by us in securing the award of a drilling contract in a given area; our experience and recognition in a new market area; and the availability of labor to run our drilling rigs. Uncertainty Of Oil and Natural Gas Reserves and Well Performance There are numerous uncertainties inherent in estimating quantities of proved reserves and their values, including many factors beyond our control. The reserve data included in this document represent only estimates. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves depend on a number of variable factors, including historical production from the area compared with production from other producing areas, and assumptions concerning: . the effects of regulations by governmental agencies; . future oil and natural gas prices; . future operating costs; . severance and excise taxes; . development costs; and . workover and remedial costs. Some or all of these assumptions may vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of those reserves based on risk of recovery, and estimates of the future net cash flows from reserves prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and those variances may be material. 21 The information regarding discounted future net cash flows included in this document should not be considered as the current market value of the estimated oil and natural gas reserves attributable to our properties. As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by the following factors: . the amount and timing of actual production; . supply and demand for oil and natural gas; . increases or decreases in consumption; and . changes in governmental regulations or taxation. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our operations or the oil and natural gas industry in general. We periodically review the carrying value of our oil and natural gas properties under the full cost accounting rules of the SEC. Under these rules, capitalized costs of proved oil and natural gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenue at the unescalated prices in effect as of the end of each fiscal quarter and requires a write-down for accounting purposes if the ceiling is exceeded, even if prices were depressed for only a short period of time. We may be required to write down the carrying value of our oil and natural gas properties when oil and natural gas prices are depressed or unusually volatile. If a write-down is required, it would result in a charge to earnings but would not impact cash flow from operating activities. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date. We are continually identifying and evaluating opportunities to acquire oil and natural gas properties, including acquisitions that would be significantly larger than those consummated to date by us. We cannot assure you that we will successfully consummate any acquisition, that we will be able to acquire producing oil and natural gas properties that contain economically recoverable reserves or that any acquisition will be profitably integrated into our operations. Debt and Bank Borrowing We have experienced and expect to continue to experience substantial working capital needs due to our growth in drilling operations and our active exploration, development and exploitation programs. Historically, we have funded our working capital needs through a combination of 22 internally generated cash flow, equity financing and borrowings under our bank loan agreement. As a result of our significant working capital requirements, we currently have, and will continue to have, a large amount of indebtedness. At December 31, 1999, our long-term debt outstanding was $65.4 million. As of December 31, 1999, the amount available for borrowing under our bank loan agreement was $85 million, of which $62.4 million was outstanding. Our level of indebtedness, the cash flow needed to satisfy our indebtedness and the covenants governing our indebtedness could: . limit funds available for financing capital expenditures, our drilling program or other activities or cause us to curtail these activities; . limit our flexibility in planning for or reacting to changes in our business; . place us at a competitive disadvantage to some of our competitors that are less leveraged than us; . make us more vulnerable during periods of low oil and natural gas prices or in the event of a downturn in our business; and . prevent us from obtaining additional financing on acceptable terms or limit amounts available under our existing or any future credit facilities. Our ability to meet our debt service obligations will depend on our future performance. We cannot assure you that we will be able to meet our debt service requirements. In addition, lower oil and natural gas prices could result in future reductions in the amount available for borrowing under our bank loan agreement, reducing our liquidity and even triggering mandatory loan repayments. If the requirements of our indebtedness are not satisfied, a default would be deemed to occur and our lenders would be entitled to accelerate the payment of the outstanding indebtedness. If this occurs, we cannot assure you that we would have sufficient funds available or could obtain the financing required to meet our obligations. The amount of our existing debt as well as its future debt is, to a large extent, a function of the costs associated with the projects undertaken by us at any given time and the cash flow received by us. Generally, the costs incurred by us in our normal operations are those associated with the drilling of oil and natural gas wells, the acquisition of producing properties, and the costs associated with the maintenance of our drilling rig fleet. To some extent, these costs, particularly the first two items, are discretionary and we maintain a degree of control regarding the timing and/or the need to incur the same. However, in some cases, unforeseen circumstances may arise, such as in the case of an unanticipated opportunity to acquire a large producing property package or the need to replace a costly rig component due to an unexpected loss, which could force us to incur increased debt above that which we had expected or forecasted. 23 Likewise, for many of the reasons mentioned above, our cash flow may not be sufficient to cover our current cash requirements which would then require us to increase our debt either through bank borrowings or otherwise. Item 3. Legal Proceedings - ------- ----------------- We are a party to various legal proceedings arising in the ordinary course of our business, none of which, in our opinion, will result in judgments which would have a material adverse effect on our financial position, operating results or cash flows. Item 4. Submission of Matters to a Vote of Security Holders - ------- --------------------------------------------------- No matters were submitted to our security holders during the fourth quarter of 1999. 24 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder - ------- ------------------------------------------------------------------ Matters ------- Our common stock is traded on the New York Stock Exchange under the symbol "UNT." The following table sets forth the high and low sale prices per share of our common stock as reported in the New York Stock Exchange composite transactions for the periods indicated: 1998 1999 ------------------------- ------------------------ QUARTER High Low High Low ------- ----------- ----------- ----------- ----------- First $ 9 13/16 $ 6 7/16 $ 7 $ 3 1/2 Second $ 9 7/8 $ 5 1/2 $ 8 1/4 $ 4 7/8 Third $ 6 5/16 $ 3 3/4 $ 9 $ 6 3/4 Fourth $ 6 15/16 $ 3 5/8 $ 7 3/4 $ 4 7/8 As of February 22, 2000 our common stock was held by 2,370 holders of record. We have not declared nor paid any cash dividends on shares of our common stock since organization and currently intend to continue our policy of retaining earnings from our operations. We are prohibited by certain loan agreement provisions from declaring and paying dividends (other than stock dividends) during any fiscal year in excess of 25 percent of our consolidated net income of the preceding fiscal year, and only if working capital provided from operations during the prior year is equal to or greater than 175 percent of current maturities of long-term debt at the end of the prior year. 25 Item 6. Selected Financial Data - ------- ----------------------- Year Ended December 31, ------------------------------------------------------------ 1995 1996 1997 1998 1999 ---------- ---------- ---------- ---------- ---------- (In thousands except per share amounts) Revenues $ 53,074 $ 72,070 $ 91,864 $ 93,337 $ 97,453 ========== ========== ========== ========== ========== Income From Continuing Operations $ 3,751(1) $ 8,333 $ 11,124 $ 2,246 $ 1,486 ========== ========== ========== ========== ========== Net Income $ 3,999(1) 8,333 11,124 2,246 1,486 ========== ========== ========== ========== ========== Basic Earnings Per Common Share: Continuing operations $ .18(1) .37 .46 .09 .05 Discontinued operations $ .01 - - - - ---------- ---------- ---------- ---------- ---------- Net Income $ .19(1) $ .37 $ .46 $ .09 $ .05 ========== ========== ========== ========== ========== Diluted Earnings Per Common Share: Continuing operations $ .18(1) $ .37 $ .45 $ .09 $ .05 Discontinued operations $ .01 - - - - ---------- ---------- ---------- ---------- ---------- Net Income $ .19(1) $ .37 $ .45 $ .09 $ .05 ========== ========== ========== ========== ========== Total Assets $ 110,922 $ 137,993 $ 202,497 $ 223,064 $ 283,573 ========== ========== ========== ========== ========== Long-Term Debt $ 41,100 $ 40,600 $ 54,100 $ 72,900 $ 65,400 ========== ========== ========== ========== ========== Other Long-Term Liabilities $ 2,109 $ 2,276 $ 2,279 $ 2,301 $ 2,265 ========== ========== ========== ========== ========== Cash Dividends Per Common Share $ - $ - $ - $ - $ - ========== ========== ========== ========== ========== - ------------------ (1) Includes a $635,000 gain on compressor sale, a $850,000 gain from settlement of litigation and a net $530,000 deferred tax benefit. See Management's Discussion of Financial Condition and Results of Operations for a review of 1997, 1998 and 1999 activity. 26 Item 7. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations --------------------- Financial Condition and Liquidity - --------------------------------- Our bank loan agreement provides for a total loan facility of $100 million with a current available borrowing value of $85 million. Each year on April 1 and October 1 our banks redetermine our available borrowing value which is an amount equal to a percentage of the discounted future value of our oil and natural gas reserves plus an amount which is the greater of (i) 50 percent of the appraised value of our contract drilling rigs or (ii) two times the previous 12 months cash flow from our contract drilling rigs, limited, in either case, to $20 million. Our loan agreement provides for a revolving credit facility which terminates on May 1, 2002 followed by a three year term loan. Borrowings under our loan agreement totaled $62.4 million at December 31, 1999 and $61.0 million at February 27, 2000. We are charged a facility fee of .375 of 1 percent on any unused portion of the available borrowing value. The loan agreement also contains covenants which require us to maintain . consolidated tangible net worth of at least $75 million, . a current ratio of not less than 1 to 1, . a ratio of long-term debt, as defined in the loan agreement, to consolidated tangible net worth not greater than 1.2 to 1, . a ratio of total liabilities, as defined in the loan agreement, to consolidated tangible net worth not greater than 1.65 to 1, and . working capital provided by operations, as defined in the loan agreement, cannot be less than $18 million in any year. The interest rate on our bank debt was 7.47 percent at December 31, 1999 and 7.44 percent at February 22, 2000. At our election, any portion of our outstanding bank debt may be fixed at the London Interbank Offered Rate ("Libor Rate"), as adjusted depending on the level of our debt as a percentage of the available borrowing value. The Libor Rate may be fixed for periods of up to 30, 60, 90 or 180 days with the remainder of our bank debt being subject to the Chase Manhattan Bank, N. A. prime rate. During any Libor Rate funding period, we may not pay any part of the outstanding principal balance which is subject to the Libor Rate. Borrowings subject to the Libor Rate were $61.0 million at both December 31, 1999 and February 22, 2000. Our shareholders' equity at December 31, 1999 was $171.9 million giving us a ratio of long-term debt-to-total capitalization of 28 percent. 27 Our primary source of funds consists of the cash flow from our operating activities and borrowings under our bank loan agreement. Net cash provided by our operating activities in 1999 was $21.3 million compared to $33.5 million in 1998. We had working capital of $3.4 million at December 31, 1999. Our total 1999 capital expenditures were $76.7 million of which $20.3 million was spent on our oil and natural gas operations, $14.9 million for exploration and development drilling and $3.6 million for producing property acquisitions, and $55.7 million on our contract drilling operations. Capital expenditures for our contract drilling operations consisted primarily of $48.1 million to acquire the 13 Parker land drilling rigs with the rest for major components on our rig fleet. We anticipate that we will spend approximately $15 million in 2000 for drilling rig equipment capital expenditures. As natural gas and oil prices increased during the last six months of 1999, we increased our development drilling activity with the result that we drilled 20 wells during the fourth quarter as compared to a total of 31 wells during the first three quarters of 1999. If oil and natural gas prices remain favorable, we anticipate that we may spend approximately $30 million drilling or buying oil and natural gas properties in 2000. Most of our capital expenditures are discretionary and directed toward increasing oil and natural gas reserves and future growth. Current operations do not depend on our ability to obtain funds outside of our loan agreement. Future decisions to acquire or drill on oil and natural gas properties will depend on prevailing or anticipated market conditions, potential return on investment, future drilling potential and the availability of opportunities to obtain financing under the circumstances involved, thus providing us with a large degree of flexibility in determining when and if to incur such costs. On December 8, 1999, we signed an agreement and plan of merger with Questa Oil and Gas Co.("Questa") under which one of our wholly owned subsidiaries will be merged (the "merger") with Questa. Questa will continue as the surviving corporation and as a wholly owned subsidiary of ours. In the merger each of Questa's outstanding shares of common stock (excluding treasury shares) will be converted into the right to receive .95 shares of our common stock. Questa has 1.9 million shares outstanding. We anticipate that this merger, which is subject to a number of conditions, will close late in the first quarter of 2000 and will be accounted for as a pooling of interests. On September 30, 1999, we completed the acquisition of 13 land drilling rigs from Parker Drilling Company and Parker Drilling Company North America, Inc., for 1,000,000 shares of our common stock and $40,000,000 in cash. The cash part of this acquisition was funded through a public offering of 7,000,000 shares of our common stock which closed on September 29, 1999. We received proceeds of $50.1 million from the offering net of commission fees and other costs. 28 On November 20, 1997, we acquired Hickman Drilling Company pursuant to an agreement and plan of merger entered into by and between us, Hickman Drilling Company and all of the holders of the outstanding capital stock of Hickman Drilling Company. As part of this acquisition, the former shareholders of Hickman held, as of December 31, 1999, promissory notes in the aggregate outstanding principal amount of $4.0 million. These notes are payable in equal annual installments on January 2, 2000 through January 2, 2003. The notes bear interest at the Chase Prime Rate which at December 31, 1999 was 8.5 percent and February 22, 2000 was 8.75 percent. At February 22, 2000, the promissory notes outstanding totaled $3.0 million. Due to a settlement agreement which terminated at December 31, 1997, we have a liability of $1.3 million at December 31, 1999, representing proceeds received from a natural gas purchaser as prepayment for natural gas. The $1.3 million is payable in equal annual payments from June 1, 2000 to June 1, 2002. The prices we received for our oil in 1999 increased throughout the year ending 135 percent higher than the prices we received during February 1999, when oil prices were at their lowest for the year. While oil prices steadily increased during the year, natural gas prices were volatile. Our average natural gas price in December 1999 as compared to January 1999 was 31 percent higher but dropped 28 percent in one month from November 1999 to December 1999. For the year, the average natural gas price we received was $2.02 per Mcf and the average oil price we received was $17.51 per barrel. Natural gas prices are influenced by weather conditions and supply imbalances, particularly in the domestic market, and by world wide oil price levels. Domestic oil price levels continue to be primarily influenced by world market developments. Since natural gas comprises approximately 88 percent of our total oil and natural gas reserves, large drops in spot market natural gas prices have a significant adverse effect on the value of our oil and natural gas reserves and price declines could cause us to reduce the carrying value of our oil and natural gas properties. Any price decreases, if sustained, would also adversely affect our future cash flow by reducing our oil and natural gas revenues and, if continued over an extended period, could lessen not only the demand for our contract drilling rigs but also the rate we would receive. Any declines in natural gas and oil prices could also adversely affect the semi-annual determination of the loan value under our bank loan agreement since this determination is based on the value of our oil and natural gas reserves and our drilling rigs. Such a reduction would reduce the amount available to us under our loan agreement which, in turn, would affect our ability to carry out our capital projects. Generally, during the past 15 years, our contract drilling operations have encountered significant competition although in the last six months of 1996, all of 1997 and the first nine months of 1998 we experienced significant improvement in rig utilization. However, in late 1998 and through the first six months of 1999 we, along with the drilling industry as a whole, experienced a significant reduction in demand for our drilling 29 rigs. While we experienced an increase in demand during the last six months of 1999, we anticipate that competition within our industry will, for the foreseeable future, continue to influence the use of our drilling rigs. In addition to competition, our ability to use our drilling rigs at any given time depends on a number of other factors, including the price of both oil and natural gas, the availability of labor and our ability to supply the type of equipment required. We expect these factors will also continue to influence the use of our rigs in 2000. At December 31, 1999, we had tax net operating loss carryforwards ("NOL's") of approximately $61.8 million, the benefit of which has been recognized in our financial statements as we believe it to be more likely than not that these NOL's will be utilized by us. Approximately $1.4 million of the NOL's expire in 2000 and approximately $12.3 million expire in 2001. Should we be unable to generate sufficient income in these years to allow the utilization of the NOL's, a charge to expense will be required to give recognition to any loss of the NOL's. In the third quarter of 1994, our board of directors authorized us to purchase up to 1,000,000 shares of our outstanding common stock on the open market. Since that time, 160,100 shares have been repurchased at prices ranging from $2.50 to $9.69 per share. In the first quarter of 1997, 1998 and 1999, we used 23,892, 19,863 and 25,000 of the purchased shares, respectively, as our matching contribution to our 401(k) Employee Thrift Plan. At December 31, 1999 we held no treasury shares. Year 2000 Statement - ------------------- We spent approximately $130,000 to make our software and hardware compliant for the transition into the year 2000. We have not experienced any material problems during the transition into the new year and have not received reports of any material problems from any of our suppliers or customers. Effects of Inflation - -------------------- In previous years the effects of inflation on our operations have been minimal due to low inflation rates. However, during the last six months of 1996, throughout 1997 and in the last half of 1999, as drilling rig day rates and drilling rig utilization increased, the impact of inflation increased as the availability of equipment, third party services and qualified labor decreased. How inflation will effect us in the future will depend on the increase, if any, we realize in our drilling rig rates and the prices we receive for our oil and natural gas. If industry activity suddenly and substantially increases, shortages in support equipment such as drill pipe, third party services and qualified labor could occur 30 resulting in additional corresponding increases in our material and labor costs. These conditions may limit our ability to realize improvements in operating profits. New Accounting Pronouncement - ---------------------------------- On June 15, 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (FAS 133). In June 1999, FAS 133 was amended by FAS 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB No. 133 - an amendment of FASB Statement No. 133" (FAS 137). FAS 133 is now effective for all fiscal quarters of fiscal years beginning after June 15, 2000 (January 1, 2001 for Unit). FAS 133 requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, the type of hedge transaction. We anticipate that, based on the nature of our use of derivative instruments, the adoption of FAS 133 will not have a significant effect on our results of operations or financial position. Results of Operations - --------------------- 1999 versus 1998 - ---------------- Net income for 1999 was $1,486,000, compared with $2,246,000 in 1998. Lower natural gas and oil prices in the first half of 1999 reduced both the demand for our drilling rigs and the rates we received for the drilling rigs that were operating. Our oil and natural gas revenues increased 5 percent in 1999 due to a 6 percent and 37 percent increase in the average prices we received for natural gas and oil, respectively. For the year, natural gas production decreased by 3 percent and oil production decreased by 16 percent when compared to 1998. Our oil production is declining because we have emphasized in recent years the drilling of development wells aimed at replacing and increasing our natural gas reserves. Our natural gas production decreased because we curtailed our development drilling program during the first half of 1999 while oil and natural gas prices were depressed. As prices began to improve during the last six months of 1999, our natural gas production increased as we increased our drilling program. Natural gas production for the fourth quarter of 1999 exceeded 1998's fourth quarter production by 3 percent. In 1999, revenues from our contract drilling operations increased by 4 percent as the average number of drilling rigs being used increased from 31 22.9 in 1998 to 23.1 in 1999. Revenues per rig per day increased 3 percent between the comparative years. During the first nine months of 1999 as compared to the same period of 1998, our average drilling rig utilization was down 22 percent and our average revenues per rig day was down 4 percent. The acquisition of the Parker drilling rigs added 6.5 rigs to our utilization rate in the fourth quarter of 1999 at dayrates substantially higher than those achieved in our other marketing area. As a result, that acquisition had a strong impact on our contract drilling fourth quarter and year-end operating results, adding $5.6 million in revenues. Daywork revenues represented 61 percent of our total drilling revenues in 1999 and 64 percent in 1998. Operating margins (revenues less operating costs) for our oil and natural gas operations were 67 percent in 1999 and 64 percent in 1998. This increase resulted primarily from the increase in the average oil and natural gas prices we received and a 3 percent decrease in operating costs between the comparative years. Our contract drilling operating margins decreased from 18 percent in 1998 to 14 percent in 1999. This reduction was generally due to decreases during the first nine months of 1999 in both daily drilling rig revenue rates and utilization and increases in operating costs. Total contract drilling operating costs were up 9 percent in 1999 versus 1998 due to increased labor costs and related benefit costs, including workers' compensation. Contract drilling depreciation increased 19 percent due to the impact of higher depreciation per operating day associated with the newly acquired Parker rigs. Depreciation, depletion and amortization ("DD&A") of our oil and natural gas properties increased 1 percent as the average DD&A rate per Mcfe increased 5 percent to $0.88 in 1999. The DD&A rate increase was partially offset by the previously discussed decrease in production. General and administrative expenses increased 4 percent as certain employee benefit costs and outside services increased. Interest expense increased 6 percent as our average outstanding debt increased 10 percent during 1999. The average interest rate decreased from 7.11 percent in 1998 to 7.00 percent in 1999. On May 3, 1999, our contract drilling offices in Moore, Oklahoma were struck by a tornado destroying two buildings and damaging various vehicles and drilling equipment. In May 1999, we received $500,000 of insurance proceeds for the destroyed buildings, and as a result, in the second quarter of 1999, we recognized a gain of $315,000 recorded as part of other revenues. Other claims for the contents of the two buildings and damaged equipment and damage removal covered under other insurance policies have been filed. We do not expect any financial loss to be incurred from these claims. 32 1998 versus 1997 - ---------------- Net income for 1998 was $2,246,000, compared with $11,124,000 in 1997. Increases in the number of rigs utilized and increased natural gas production were more than offset by substantial decreases in the average price received for both oil and natural gas and to a lesser extent from reduced oil production and contract drilling rates. Oil and natural gas revenues decreased 13 percent in 1998 due to a 21 percent and 33 percent decrease in average natural gas and oil prices received, respectively along with a 10 percent reduction in oil production. These decreases were partially offset by a 19 percent increase in natural gas production. Oil production declined from 1997 levels due to our emphasis over the past three years in drilling development wells which focused on replacing and increasing natural gas reserves. Average natural gas spot market prices received by us decreased 20 percent. The natural gas previously subject to the settlement agreement, which ended at December 31, 1997 and contained provisions for prices higher than current spot market prices, is now being sold at spot market prices consistent with the rest of the natural gas sold by us. The impact of higher prices received under the settlement agreement increased pre-tax income by approximately $540,000 in 1997. In 1998, revenues from contract drilling operations increased by 16 percent as average rig utilization increased from 19.2 rigs operating in 1997 to 22.9 rigs operating in 1998. Daywork revenues per rig per day decreased 3 percent between the comparative years. During the first three quarters of 1998, our monthly rig utilization consistently remained at or above 23 rigs with daywork revenue per rig per day declining by 8 percent from the January 1998 rate. In the fourth quarter utilization dropped 27 percent from the previous quarter and dayrates decreased another 6 percent. Total daywork revenues represented 64 percent of total drilling revenues in 1998 and 72 percent in 1997. Turnkey and footage contracts typically provide for higher revenues since a greater portion of the expense of drilling the well is borne by the drilling contractor. Operating margins (revenues less operating costs) for our natural gas and oil operations were 64 percent in 1998 compared to 71 percent in 1997. Decreased operating margins resulted primarily from the decrease in average natural gas and oil prices received by us between the two years. Total operating costs were 9 percent higher in 1998 compared to 1997 as we continue to add producing properties. Operating margins for contract drilling decreased from 21 percent in 1997 to 18 percent in 1998. Margins in 1998 were lower primarily due to decreases in both daily rig rates and utilization in the fourth quarter of 1998. Total operating costs for contract drilling were up 20 percent in 1998 versus 1997 due to increased drilling rig utilization and costs associated with the November 1997 Hickman Acquisition. 33 Contract drilling depreciation increased 37 percent in response to increased rig utilization and additional drilling capital expenditures throughout 1997 and 1998. Depreciation, depletion and amortization ("DD&A") of oil and natural gas properties increased 27 percent as we increased our equivalent barrels of production by 14 percent and our average DD&A rate per Mcfe increased 11 percent to $0.83 in 1998. General and administrative expenses increased 6 percent as certain employee costs increased. Interest expense increased 65 percent as our average outstanding debt increased 65 percent during 1998. The average interest rate decreased from 7.28 percent in 1997 to 7.11 percent in 1998. Item 7a. Quantitative and Qualitative Disclosures about Market Risk - -------- ---------------------------------------------------------- Our operations are exposed to market risks primarily as a result of changes in commodity prices and interest rates. Commodity Price Risk - Our major market risk exposure is in the pricing of our oil and natural gas production. The price we receive is primarily driven by the prevailing worldwide price for crude oil and market prices applicable to our natural gas production. Historically, prices we have received for our oil and natural gas production have been volatile and such volatility is expected to continue. To reduce the impact of price fluctuations, we periodically use hedging strategies to hedge the price we will receive for a portion of our future oil and natural gas production. During six different months of 1999 we had swap transactions applying to approximately 22 to 44 percent of our daily gas production. These transactions yielded a reduction in our natural gas revenues of $487,000. At December 31, 1999, we did not have any forward of future contracts relating to the production of our oil and natural gas. In the first quarter of 2000, we entered into swap transactions in an effort to lock in a portion of our production at the higher oil prices which currently exist. These transactions apply to approximately 60 percent of our daily natural gas production covering the period from April 1, 2000 to July 31, 2000 and 30 percent of our oil production for August and September of 2000, at prices ranging from $24.42 to $27.01. Interest Rate Risk - Our interest rate exposure relates to our long- term debt, all of which bears interest at variable rates based on the prime rate or the London Interbank Offered Rate ("Libor rate"). At our election, borrowings under our revolving credit and term loan may be fixed at the Libor rate for periods up to 180 days. Historically, we have not utilized any financial instruments, such as interest rate swaps, to attempt to manage the exposure to increases in interest rates. However, we may consider the use of such financial instruments in the future based on our 34 assessment of future interest rates. The impact on annual cash flow before taxes of a one percent change in the floating rate bases on our average outstanding long-term debt in 1999 would have been approximately $711,000. 35 Item 8. Financial Statements and Supplementary Data - ----------------------------------------------------- UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS As of December 31, ---------------------- 1998 1999 ---------- ---------- (In thousands) ASSETS - ------ Current Assets: Cash and cash equivalents $ 446 $ 478 Accounts receivable (less allowance for doubtful accounts of $274 and $573) 13,149 21,528 Materials and supplies 3,298 3,259 Prepaid expenses and other 2,650 2,475 ---------- ---------- Total current assets 19,543 27,740 ---------- ---------- Property and Equipment: Drilling equipment 123,258 177,238 Oil and natural gas properties, on the full cost method 271,960 291,760 Transportation equipment 2,955 3,448 Other 6,870 7,593 ---------- ---------- 405,043 480,039 Less accumulated depreciation, depletion, amortization and impairment 207,883 230,233 ---------- ---------- Net property and equipment 197,160 249,806 ---------- ---------- Other Assets 6,361 6,027 ---------- ---------- Total Assets $ 223,064 $ 283,573 ========== ========== The accompanying notes are an integral part of the consolidated financial statements 36 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS - CONTINUED As of December 31, ---------------------- 1998 1999 ---------- ---------- (In thousands) LIABILITIES AND SHAREHOLDERS' EQUITY - ----------------------------------- Current Liabilities: Current portion of long-term liabilities and debt $ 1,801 $ 1,719 Accounts payable 8,517 14,285 Accrued liabilities 7,362 7,977 Contract advances 310 358 ---------- ---------- Total current liabilities 17,990 24,339 ---------- ---------- Long-Term Debt 72,900 65,400 ---------- ---------- Other Long-Term Liabilities (Note 4) 2,301 2,265 ---------- ---------- Deferred Income Taxes 18,583 19,712 ---------- ---------- Commitments and Contingencies (Note 9) Shareholders' Equity: Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued - - Common stock, $.20 par value, 40,000,000 shares authorized, 25,563,165 and 33,815,676 shares issued, respectively 5,113 6,763 Capital in excess of par value 82,187 139,487 Retained earnings 24,121 25,607 Treasury stock, at cost (25,000 and 0 shares, respectively) (131) - ---------- ---------- Total shareholders' equity 111,290 171,857 ---------- ---------- Total Liabilities and Shareholders' Equity $ 223,064 $ 283,573 ========== ========== The accompanying notes are an integral part of the consolidated financial statements 37 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31, -------------------------------------- 1997 1998 1999 ---------- ---------- ---------- (In thousands except per share amounts) Revenues: Contract drilling $ 46,199 $ 53,528 $ 55,479 Oil and natural gas 45,581 39,703 41,540 Other 84 106 434 ---------- ---------- ---------- Total revenues 91,864 93,337 97,453 ---------- ---------- ---------- Expenses: Contract drilling: Operating costs 36,419 43,729 47,721 Depreciation 4,216 5,766 6,851 Oil and natural gas: Operating costs 13,201 14,328 13,898 Depreciation, depletion and amortization 12,625 16,069 16,197 General and administrative 4,621 4,891 5,071 Interest 2,921 4,815 5,081 ---------- ---------- ---------- Total expenses 74,003 89,598 94,819 ---------- ---------- ---------- Income Before Income Taxes 17,861 3,739 2,634 ---------- ---------- ---------- Income Tax Expense: Current 118 139 19 Deferred 6,619 1,354 1,129 ---------- ---------- ---------- Total income taxes 6,737 1,493 1,148 ---------- ---------- ---------- Net Income $ 11,124 $ 2,246 $ 1,486 ========== ========== ========== Net Income Per Common Share: Basic $ .46 $ .09 $ .05 ========== ========== ========== Diluted $ .45 $ .09 $ .05 ========== ========== ========== The accompanying notes are an integral part of the consolidated financial statements 38 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY Year Ended December 31, 1997, 1998 and 1999 Capital In Excess Common Of Par Retained Treasury Stock Value Earnings Stock Total -------- ---------- --------- -------- ---------- (In thousands) Balances, January 1, 1997 $ 4,831 $ 62,735 $ 10,751 $ (107) $ 78,210 Net income - - 11,124 - 11,124 Activity in employee compensation plans (57,524 shares) 12 718 - 89 819 Issuance of stock for acquisition (1,300,000 shares) 260 18,590 - - 18,850 Purchase of treasury stock (15,000 shares) - - - (138) (138) -------- ---------- --------- -------- ---------- Balances, December 31, 1997 5,103 82,043 21,875 (156) 108,865 Net income - - 2,246 - 2,246 Activity in employee compensation plans (48,329 shares) 10 144 - 156 310 Purchase of treasury stock (25,000 shares) - - - (131) (131) -------- ---------- --------- -------- ---------- Balances, December 31, 1998 5,113 82,187 24,121 (131) 111,290 Net income - - 1,486 - 1,486 Activity in employee compensation plans (252,511 shares) 50 680 - 131 861 Sale of Common Stock (7,000,000 shares) 1,400 48,682 - - 50,082 Issuance of stock for acquisition (1,000,000 shares) 200 7,938 - - 8,138 -------- ---------- --------- -------- ---------- Balances, December 31, 1999 $ 6,763 $ 139,487 $ 25,607 $ - $ 171,857 ======== ========== ========= ======== ========== The accompanying notes are an integral part of the consolidated financial statements 39 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, ---------------------------------- 1997 1998 1999 ---------- ---------- ---------- (In thousands) Cash Flows From Operating Activities: Net Income $ 11,124 $ 2,246 $ 1,486 Adjustments to reconcile net income to net cash provided (used) by operating activities: Depreciation, depletion, and amortization 17,199 22,186 23,367 Loss (gain) on disposition of assets (94) 17 (400) Employee stock compensation plans 244 561 436 Bad debt expense 250 - 255 Deferred tax expense 6,619 1,354 1,129 Changes in operating assets and liabilities increasing (decreasing) cash: Accounts receivable (1,762) 6,664 (8,634) Materials and supplies (1,233) 237 39 Prepaid expenses and other (211) (444) 175 Accounts payable 2,062 948 2,503 Accrued liabilities 1,430 (27) 1,383 Contract advances (1,208) 218 48 Other liabilities (70) (447) (442) ---------- ---------- ---------- Net cash provided by operating activities 34,350 33,513 21,345 ---------- ---------- ---------- The accompanying notes are an integral part of the consolidated financial statements 40 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED Year Ended December 31, ---------------------------------- 1997 1998 1999 ---------- ---------- ---------- (In thousands) Cash Flows From Investing Activities: Capital expenditures (including producing property acquisitions) $ (45,115) $ (53,654) (68,313) Cash received on acquisition of drilling company (Note 2) 1,611 - - Proceeds from disposition of property and equipment 792 964 1,372 (Acquisition) disposition of other assets (314) (93) 91 ---------- ---------- ---------- Net cash used in investing activities (43,026) (52,783) (66,850) ---------- ---------- ---------- Cash Flows From Financing Activities: Borrowings under line of credit 34,400 52,700 61,600 Payments under line of credit (25,900) (32,900) (68,100) Net payments on notes payable and other long-term debt - (470) (1,081) Proceeds from sale of common stock 225 59 50,144 Book overdrafts (Note 1) - - 2,974 Acquisition of treasury stock (138) (131) - ---------- ---------- ---------- Net cash provided by financing activities 8,587 19,258 45,537 ---------- ---------- ---------- Net Increase (Decrease) in Cash and Cash Equivalents (89) (12) 32 Cash and Cash Equivalents, Beginning of Year 547 458 446 ---------- ---------- ---------- Cash and Cash Equivalents, End of Year $ 458 $ 446 $ 478 ========== ========== ========== Supplemental Disclosure of Cash Flow Information: Cash paid during the year for: Interest $ 2,910 $ 4,064 $ 5,660 Income taxes $ 102 $ 507 - The accompanying notes are an integral part of the consolidated financial statements 41 UNIT CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - --------------------------------------------------- Principles of Consolidation The consolidated financial statements include the accounts of Unit Corporation and its directly and indirectly wholly owned subsidiaries. The investment in limited partnerships is accounted for on the proportionate consolidation method, whereby Unit's share of the partnerships' assets, liabilities, revenues and expenses is included in the appropriate classification in the accompanying consolidated financial statements. Nature of Business Unit is engaged in the land contract drilling of natural gas and oil wells and the exploration, development, acquisition and production of oil and natural gas properties. Our current contract drilling operations are focused primarily in the natural gas producing provinces of the Oklahoma and Texas areas of the Anadarko and Arkoma Basins, the Texas Gulf Cost and the Rocky Mountain regions. Unit's primary exploration and production operations are also conducted in the Anadarko and Arkoma Basins and in the Texas Gulf Coast area. The majority of its contact drilling and exploration and production activities are oriented toward drilling for and producing natural gas. At December 31, 1999, Unit had an interest in a total of 2,483 wells and served as operator of 519 of those wells. Unit provides land contract drilling services for a wide range of customers using the drilling rigs which it owns and operates. In 1999, 40 of the Company's 47 rigs were in operation. Drilling Contracts Unit recognizes revenues generated from "daywork" drilling contracts as the services are performed, which is similar to the percentage of completion method. Under "footage" and "turnkey" contracts, Unit bears the risk of completion of the well therefore, revenues and expenses are recognized using the completed contract method. The duration of all three types of contracts range typically from 20 to 90 days. The entire amount of a loss, if any, is recorded when the loss is determinable. The costs of uncompleted drilling contracts include expenses incurred to date on "footage" or "turnkey" contracts, which are still in process at the end of the period, and are included in other current assets. 42 Cash Equivalents and Book Overdrafts Unit includes as cash equivalents, certificates of deposits and all investments with maturities at date of purchase of three months or less which are readily convertible into known amounts of cash. Book overdrafts are checks that have been issued prior to the end of the period, but not presented to Unit's bank for payment prior to the end of the period. At December 31, 1999, book overdrafts of $2.9 million have been included in accounts payable. Property and Equipment Drilling equipment, transportation equipment and other property and equipment are carried at cost. Renewals and betterments are capitalized while repairs and maintenance are expensed. Depreciation of drilling equipment is recorded using the units-of-production method based on estimated useful lives, including a minimum provision of 20 percent of the active rate when the equipment is idle. Unit uses the composite method of depreciation for drill pipe and collars and calculates the depreciation by footage actually drilled compared to total estimated remaining footage. Depreciation of other property and equipment is computed using the straight- line method over the estimated useful lives of the assets ranging from 3 to 15 years. Realization of the carrying value of our property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets. Changes in such estimates could cause Unit to reduce the carrying value of our property and equipment. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is generally reflected in operations. For dispositions of drill pipe and drill collars, an average cost for the appropriate feet of drill pipe and drill collars is removed from the asset account and charged to accumulated depreciation and proceeds, if any, are credited to accumulated depreciation. 43 Goodwill Goodwill represents the excess of the cost of the acquisition of Hickman Drilling Company over the fair value of the net assets acquired and is being amortized on the straight-line method over 25 years. Goodwill is evaluated periodically for impairment, when it appears an impairment may have occurred. If an impairment is determined, the amount of such impairment is calculated based on the estimated fair market value of the related assets. Net goodwill reported in other assets at December 31, 1998 and 1999 was $5,818,000 and $5,575,000, respectively with accumulated amortization at December 31, 1998 and 1999 of $264,000 and $507,000, respectively. Oil and Natural Gas Operations Unit accounts for its oil and natural gas exploration and development activities on the full cost method of accounting prescribed by the Securities and Exchange Commission ("SEC"). Accordingly, all productive and non-productive costs incurred in connection with the acquisition, exploration and development of oil and natural gas reserves are capitalized and amortized on a composite units-of-production method based on proved oil and natural gas reserves. Independent petroleum engineers annually review Unit's determination of its oil and natural gas reserves. The average composite rates used for depreciation, depletion and amortization ("DD&A") were $0.75, $0.83 and $0.88 per Mcfe in 1997, 1998 and 1999, respectively. The calculation of DD&A includes estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values. In the event the unamortized cost of oil and natural gas properties being amortized exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period during which such excess occurs. The full cost ceiling is based principally on the estimated future discounted net cash flows from Unit's oil and natural gas properties. As discussed in Note 12, such estimates are imprecise. Changes in these estimates or declines in oil and natural gas prices could cause Unit in the near-term to reduce the carrying value of our oil and natural gas properties. No gains or losses are recognized upon the sale, conveyance or other disposition of oil and natural gas properties unless a significant reserve amount is involved. The SEC's full cost accounting rules prohibit recognition of income in current operations for services performed on oil and natural gas properties in which Unit has an interest or on properties in which a partnership, of which Unit is a general partner, has an interest. Accordingly, in 1997 and 1998, Unit recorded $314,000 and $437,000 of contract drilling profits, respectively, as a reduction of the carrying value of its oil and natural gas properties rather than including these profits in current operations. No contract drilling profits were realized on such interests in 1999. 44 Limited Partnerships Unit's wholly owned subsidiary, Unit Petroleum Company, is a general partner in fifteen oil and natural gas limited partnerships sold privately and publicly. Some of Unit's officers, directors and employees own interests in most of these partnerships. Unit shares partnership revenues and costs in accordance with formulas prescribed in each limited partnership agreement. The partnerships also reimburse Unit for certain administrative costs incurred on behalf of the partnerships. Income Taxes Measurement of current and deferred income tax liabilities and assets is based on provisions of enacted tax law; the effects of future changes in tax laws or rates are not included in the measurement. Valuation allowances are established where necessary to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable for the year and the change during that year in deferred tax assets and liabilities. Natural Gas Balancing We use the sales method for recording natural gas sales. This method allows for recognition of revenue, which may be more or less than our share of pro-rata production from certain wells. Based upon our 1999 average natural gas price of $2.05 per Mcf received (exclusive of hedging activities), Unit estimates its balancing position to be approximately $4.6 million on under-produced properties and approximately $3.0 million on over- produced properties. Unit's policy is to expense the pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the balancing position on wells in which Unit has imbalances are not material. Employee and Director Stock Based Compensation Unit applies APB Opinion 25 in accounting for its stock option plans for its employees and directors. Under this standard, no compensation expense is recognized for grants of options, which include an exercise price equal to or greater than the market price of the stock on the date of grant. Accordingly, based on Unit's grants in 1997, 1998 and 1999 no compensation expense has been recognized. As provided by Financial Accounting Standard No. 123 "Accounting for Stock-Based Compensation," Unit has disclosed the pro forma effects of recording compensation for such option grants based on fair value in Note 6 to the financial statements. 45 Self Insurance Unit utilizes self insurance programs for employee group health and worker's compensation. Self insurance costs are accrued based upon the aggregate of estimated liabilities for reported claims and claims incurred but not yet reported. Financial Instruments and Concentrations of Credit Risk Financial instruments, which potentially subject Unit to concentrations of credit risk, consist primarily of trade receivables with a variety of national and international oil and natural gas companies. Unit does not generally require collateral related to receivables. Such credit risk is considered by management to be limited due to the large number of customers comprising Unit's customer base. During 1999, one purchaser of Unit's oil and natural gas production accounted for approximately 11 percent of consolidated revenues. At December 31, 1999 accounts receivable from one oil and natural gas purchaser was approximately $2.7 million. In addition, at December 31, 1998 and 1999, Unit had a concentration of cash of $1.5 million and $0.4 million, respectively, with one bank. Hedging Activities To reduce the impact of fluctuations in the market prices of oil and natural gas, Unit periodically utilizes hedging strategies such as futures transactions or swaps to hedge the price of a portion of its future oil and natural gas production. Results of these hedging transactions are reflected in oil and natural gas sales in the month of the hedged production. At December 31, 1998 and 1999, Unit had no such hedging or derivative transactions. Accounting Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Impact of Financial Accounting Pronouncements On June 15, 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (FAS 133). In June 1999, FAS 133 was amended by FAS 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB No. 133 - an amendment of FASB Statement No. 133" (FAS 137). FAS 133 is now effective for all fiscal quarters of fiscal years beginning after June 15, 2000 46 (January 1, 2001 for Unit). FAS 133 requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, the type of hedge transaction. Management of Unit anticipates that, based on the nature of its use of derivative instruments, the adoption of FAS 133 will not have a significant effect on Unit's results of operations or financial position. NOTE 2 - ACQUISITIONS - --------------------- On September 30, 1999, Unit acquired 13 land drilling rigs from Parker Drilling Company and Parker Drilling Company North America, Inc. Under the terms of the acquisition, the sellers received 1,000,000 shares of Unit's common stock valued at $8,138,000 and $40,000,000 in cash. The cash portion of the consideration was funded through an offering of 7,000,000 shares of Unit's common stock, which closed on September 29, 1999. The proceeds received by Unit from the offering were $50,082,000 net of commission fees and other costs. The acquisition has been accounted for as a purchase and the results of operations of the acquired rigs have been included in the consolidated financial statements since the date of acquisition. Unaudited summary pro forma results of operations for Unit, reflecting the above described acquisition as if it had occurred at the beginning of the year ended December 31, 1998 and December 31, 1999, are as follows, respectively; revenues, $126,324,000 and $112,346,000; net income $5,649,000 and $2,853,000; and net income per common share (diluted), $0.17 and $0.08. The pro forma results of operations are not necessarily indicative of the actual results of operations that would have occurred had the purchase actually been made at the beginning of the respective period nor of the results which may occur in the future. On November 20, 1997, we acquired Hickman Drilling Company. The selling stockholders of Hickman Drilling Company received, in the aggregate, 1,300,000 shares of common stock valued at $18,850,000 and promissory notes of $5,000,000 to be paid in five equal annual installments commencing January 2, 1999. The acquisition has been accounted for as a purchase and the results of Hickman Drilling Company have been included in the accompanying consolidated financial statements since the date of acquisition. 47 NOTE 3 - EARNINGS PER SHARE - --------------------------- The following data shows the amounts used in computing earnings per share. WEIGHTED INCOME SHARES PER-SHARE (NUMERATOR) (DENOMINATOR) AMOUNT ------------- ------------- ---------- For the Year Ended December 31, 1997: Basic earnings per common share $ 11,124,000 24,327,000 $ 0.46 ========== Effect of dilutive stock options - 380,000 ------------- ------------- Diluted earnings per common share $ 11,124,000 24,707,000 $ 0.45 ============= ============= ========== For the Year Ended December 31, 1998: Basic earnings per common share $ 2,246,000 25,544,000 $ 0.09 ========== Effect of dilutive stock options - 340,000 ------------- ------------- Diluted earnings per common share $ 2,246,000 25,884,000 $ 0.09 ============= ============= ========== For the Year Ended December 31, 1999 Basic earnings per common share $ 1,486,000 27,813,000 $ 0.05 ========== Effect of dilutive stock options - 274,000 ------------- ------------- Diluted earnings per common share $ 1,486,000 28,087,000 $ 0.05 ============= ============= ========== 48 The following options and their average exercise prices were not included in the computation of diluted earnings per share because the option exercise prices were greater than the average market price on common shares for the years ended December 31,: 1997 1998 1999 ---------- ---------- ---------- Options 2,500 191,000 196,500 ========== ========== ========== Average exercise price $ 11.32 $ 8.60 $ 8.49 ========== ========== ========== NOTE 4 - LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES - ------------------------------------------------------- Long-term debt consisted of the following as of December 31, 1998 and 1999: 1998 1999 ---------- ---------- (In thousands) Revolving credit and term loan, with interest at December 31, 1998 and 1999 of 6.3 percent and 7.5 percent, respectively $ 68,900 62,400 Notes payable for Hickman Drilling Company acquisition with interest at December 31, 1998 and 1999 of 7.8 percent and 8.5 percent, respectively 5,000 4,000 ---------- ---------- 73,900 66,400 Less current portion 1,000 1,000 ---------- ---------- Total long-term debt $ 72,900 $ 65,400 ========== ========== At December 31, 1999, Unit's bank loan agreement provided for a total loan commitment of $100 million consisting of a revolving credit facility through May 1, 2002 and a term loan thereafter, maturing on May 1, 2005. Borrowings under the loan agreement are limited to a borrowing value, which as of December 31, 1999 was $85 million. The loan value under the revolving credit facility is subject to a semi-annual re-determination calculated as the sum of a percentage of the discounted future value of Unit's oil and natural gas reserves, as determined by the banks, plus the greater of (i) 50 percent of the appraised value of Unit's contract drilling rigs or (ii) two times the previous 12 months cash flow from the contract drilling rigs, limited in either case to $20 million. Any declines in commodity prices would adversely impact the determination of the borrowing value. 49 Borrowings under the revolving credit facility bear interest at the Chase Manhattan Bank, N.A. prime rate ("Prime Rate") or the London Interbank Offered Rates ("Libor Rate") plus 1.00 to 1.50 percent depending on the level of debt as a percentage of the total borrowing base. Subsequent to May 1, 2002, borrowings under the loan agreement bear interest at the Prime Rate or the Libor rate plus 1.25 to 1.75 percent depending on the level of debt as a percentage of the total loan value. At Unit's election, any portion of the debt outstanding may be fixed at the Libor Rate for 30, 60, 90 or 180 days. During any Libor Rate funding period the outstanding principal balance of the note to which such Libor Rate option applies may not be paid. Borrowings under the Prime Rate option may be paid anytime in part or in whole without premium or penalty. Unit paid an origination fee of $85,000 at inception of the loan agreement and a facility fee of 3/8 of one percent is charged for any unused portion of the borrowing value. Some of Unit's drilling rigs are collateral for such indebtedness and the balance of Unit's assets are subject to a negative pledge. The loan agreement includes prohibitions against (i) the payment of dividends (other than stock dividends) during any fiscal year in excess of 25 percent of the consolidated net income of Unit during the preceding fiscal year, and only if working capital provided from operations during said year is equal to or greater than 175 percent of current maturities of long- term debt at the end of such year, (ii) the incurrence by Unit or any of its subsidiaries of additional debt with certain very limited exceptions and (iii) the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any property of Unit or any of its subsidiaries, except in favor of its banks. The loan agreement also requires that Unit maintain consolidated net worth of at least $75 million, a current ratio of not less than 1 to 1, a ratio of long-term debt, as defined in the loan agreement, to consolidated tangible net worth not greater than 1.2 to 1 and a ratio of total liabilities, as defined in the loan agreement, to consolidated tangible net worth not greater than 1.65 to 1. In addition, working capital provided by operations, as defined in the loan agreement, cannot be less than $18 million in any year. In November 1997, we completed the acquisition of Hickman Drilling Company. In association with this acquisition, we issued an aggregate of $5.0 million in promissory notes payable in five equal annual installments commencing January 2, 1999, with interest at the Prime Rate. 50 Other long-term liabilities consisted of the following as of December 31, 1998 and 1999: 1998 1999 ---------- ---------- (In thousands) Natural gas purchaser prepayment $ 1,759 $ 1,317 Separation benefit plan 1,012 1,419 Rig acquisition 331 248 ---------- ---------- 3,102 2,984 Less current portion 801 719 ---------- ---------- Total other long-term liabilities $ 2,301 $ 2,265 ========== ========== At December 31, 1999, Unit has a prepayment balance of $1.3 million representing proceeds received from a purchaser for prepayment of natural gas under a natural gas settlement agreement, which terminated on December 31, 1997. This amount is net of natural gas recouped and net of certain amounts disbursed to other owners for their proportionate share of the prepayments. At termination, the December 31, 1997 prepayment balance of $2.2 million became payable in equal annual payments over a five year period. The annual payment of $441,000 is due on June 1 of each year thru June 1, 2002. Unit has other long-term liabilities of $1,667,000, consisting of $248,000 from the December 9, 1997 acquisition of a Mid-Continent U-36-A, 650 horsepower rig plus additional spare rig equipment and $1,419,000 accrued in connection with its Separation Benefit Plan. The debt for rig equipment is payable over a maximum of three years from the closing date of the acquisition. Estimated annual principal payments under the terms of long-term debt and other long-term liabilities and debt from 2000 through 2004 are $1,719,000, $1,440,000, $13,571,000, $21,800,000 and $20,800,000. Based on the borrowing rates currently available to Unit for debt with similar terms and maturities, long-term debt at December 31, 1999 approximates its fair value. 51 NOTE 5 - INCOME TAXES - --------------------- A reconciliation of the income tax expense, computed by applying the federal statutory rate to pre-tax income to Unit's effective income tax expense is as follows: 1997 1998 1999 ---------- ---------- ---------- (In thousands) Income tax expense computed by applying the statutory rate $ 6,073 $ 1,271 $ 896 State income tax, net of federal benefit 733 150 105 Goodwill and other (69) 72 147 ---------- ---------- ---------- Income tax expense (benefit) $ 6,737 $ 1,493 $ 1,148 ========== ========== ========== Deferred tax assets and liabilities are comprised of the following at December 31, 1998 and 1999: 1998 1999 ----------- ----------- (In thousands) Deferred tax assets: Allowance for losses and nondeductible accruals $ 1,680 $ 2,370 Net operating loss carryforward 12,541 23,475 Statutory depletion carryforward 2,260 2,260 Investment tax credit carryforward 530 335 Alternative minimum tax credit carryforward 431 431 ----------- ----------- Gross deferred tax assets 17,442 28,871 Valuation allowance (530) (335) Deferred tax liability- Depreciation, depletion and amortization (35,495) (48,248) ----------- ----------- Net deferred tax liability $ (18,583) $ (19,712) =========== =========== 52 The deferred tax asset valuation allowance reflects that the investment tax credit carryforwards may not be utilized before the expiration dates due in part to the effects of anticipated future exploratory and development drilling costs. The reduction in the valuation allowance was the result of the expiration of investment tax credit carryforwards in 1999. Realization of the deferred tax asset is dependent on generating sufficient taxable income prior to expiration of loss carryforwards. Although realization is not assured, management believes it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near- term if estimates of future taxable income during the carryforward period are reduced. At December 31, 1999, Unit has net operating loss carryforwards for regular tax purposes of approximately $61,776,000 and net operating loss carryforwards for alternative minimum tax purposes of approximately $39,733,000 which expire in various amounts from 2000 to 2019. Unit has investment tax credit carryforwards of approximately $335,000 which expire in 2000. In addition, a statutory depletion carryforward of approximately $5,948,000, which may be carried forward indefinitely, is available to reduce future taxable income, subject to statutory limitations. NOTE 6 - EMPLOYEE BENEFIT AND COMPENSATION PLANS - ------------------------------------------------ In December 1984, the Board of Directors approved the adoption of an Employee Stock Bonus Plan ("the Plan") whereby 330,950 shares of common stock were authorized for issuance under the Plan. On May 3, 1995, Unit's shareholders approved and amended the Plan to increase by 250,000 shares the aggregate number of shares of common stock that could be issued under the Plan. Under the terms of the Plan, bonuses may be granted to employees in either cash or stock or a combination thereof, and are payable in a lump sum or in annual installments subject to certain restrictions. On January 4, 1999, 87,376 shares of common stock were issued for payment of Unit's 1998 year-end bonuses. No shares were issued under the Plan in 1997 and 1998. Unit also has a Stock Option Plan, which provides for the granting of options for up to 1,500,000 shares of common stock to officers and employees. The plan permits the issuance of qualified or nonqualified stock options. Options granted become exercisable at the rate of 20 percent per year one year after being granted and expire after ten years from the original grant date. The exercise price for options granted to date was based on the fair market value on the date of the grant. 53 Activity pertaining to the Stock Option Plan is as follows: WEIGHTED NUMBER AVERAGE OF EXERCISE SHARES PRICE ----------- ---------- Outstanding at January 1, 1997 636,800 $ 4.13 Granted 24,000 9.00 Exercised (56,440) 2.71 Canceled (30,200) 7.89 ----------- ---------- Outstanding at December 31, 1997 574,160 4.28 Granted 227,000 3.96 Exercised (21,300) 2.71 Canceled (10,500) 7.05 ----------- ---------- Outstanding at December 31, 1998 769,360 4.19 Exercised (109,760) 2.76 Canceled (2,000) 10.00 ----------- ---------- Outstanding at December 31, 1999 657,600 $ 4.41 =========== ========== OUTSTANDING OPTIONS ------------------------------------- WEIGHTED AVERAGE WEIGHTED NUMBER REMAINING AVERAGE EXERCISE OF CONTRACTUAL EXERCISE PRICES SHARES LIFE PRICE ----------------------- ----------- ----------- ----------- $ 2.37 - $ 4.00 506,100 5.7 years $ 3.14 $ 7.25 - $11.32 151,500 7.1 years $ 8.66 54 EXERCISABLE OPTIONS ----------------------- WEIGHTED NUMBER AVERAGE EXERCISE OF EXERCISE PRICES SHARES PRICE ------------------------------------ ----------- ----------- $ 2.37 - $ 4.00 333,500 $ 2.82 $ 7.25 - $11.32 80,700 $ 8.70 Options for 383,000, 427,000 and 414,200 shares were exercisable with weighted average exercise prices of $3.01, $3.42 and $3.96 at December 31, 1997, 1998 and 1999, respectively. In February and May 1992, the Board of Directors and shareholders, respectively, approved the Unit Corporation Non-Employee Directors' Stock Option Plan (the "Directors' Plan"). An aggregate of 100,000 shares of Unit's common stock may be issued upon exercise of the stock options. On the first business day following each annual meeting of stockholders of Unit, each person who is then a member of the Board of Directors of Unit and who is not then an employee of Unit or any of its subsidiaries will be granted an option to purchase 2,500 shares of common stock. The option price for each stock option is the fair market value of the common stock on the date the stock options are granted. No stock options may be exercised during the first six months of its term except in case of death and no stock options are exercisable after ten years from the date of grant. 55 Activity pertaining to the Directors' Plan is as follows: WEIGHTED NUMBER AVERAGE OF EXERCISE SHARES PRICE ----------- ---------- Outstanding at January 1, 1997 55,000 $ 3.85 Granted 12,500 8.94 Exercised (7,500) 2.67 ----------- ---------- Outstanding at December 31, 1997 60,000 5.06 Granted 12,500 9.00 ----------- ---------- Outstanding at December 31, 1998 72,500 5.74 Granted 12,500 6.90 Exercised (5,000) 5.13 Cancelled (2,500) 8.94 ----------- ---------- Outstanding at December 31, 1999 77,500 $ 5.86 =========== ========== OUTSTANDING AND EXERCISABLE OPTIONS ------------------------------------- WEIGHTED AVERAGE WEIGHTED NUMBER REMAINING AVERAGE EXERCISE OF CONTRACTUAL EXERCISE PRICES SHARES LIFE PRICE ----------------------- ----------- ----------- ----------- $ 1.75 - $ 3.75 32,500 4.2 years $ 3.00 $ 6.87 - $ 9.00 45,000 8.7 years $ 7.93 56 Unit applies APB Opinion 25 in accounting for Unit's Stock Option Plan and Non-Employee Director's Stock Option Plan. Accordingly, based on the nature of Unit's grants of options, no compensation cost has been recognized in 1997, 1998 and 1999. Had compensation been determined on the basis of fair value pursuant to FASB Statement No. 123, net income and earnings per share would have been reduced as follows: 1997 1998 1999 --------- --------- --------- Net Income (In thousands): As reported $ 11,124 $ 2,246 $ 1,486 ========= ========= ========= Pro forma $ 10,748 $ 1,933 $ 1,090 ========= ========= ========= Basic Earnings per Share: As reported $ .46 $ .09 $ .05 ========= ========= ========= Pro forma $ .44 $ .08 $ .04 ========= ========= ========= Diluted Earnings per Share: As reported $ .45 $ .09 $ .05 ========= ========= ========= Pro forma $ .43 $ .07 $ .04 ========= ========= ========= The fair value of each option granted is estimated using the Black- Scholes model. Unit's estimate of stock volatility was 0.52, 0.53 and 0.55 in 1997, 1998 and 1999, respectively, based on previous stock performance. Dividend yield was estimated to remain at zero with a risk free interest rate of 5.80, 4.95 and 6.70 percent in 1997, 1998 and 1999, respectively. Expected life ranged from 1 to 10 years based on prior experience depending on the vesting periods involved and the make up of participating employees. The aggregate fair value of options granted during 1997 and 1998 under the Stock Option Plan were $136,000 and $527,000, respectively. No options were issued under the Stock Option Plan in 1999. Under the Non-Employee Director's Stock Option Plan the aggregate fair value of options granted during 1997, 1998 and 1999 were $74,000, $71,000 and $58,000, respectively. Under Unit's 401(k) Employee Thrift Plan, employees who meet specified service requirements may contribute a percentage of their total compensation, up to a specified maximum, to the plan. Each employee's contribution, up to a specified maximum, may be matched by Unit in full or on a partial basis. The Company made discretionary contributions under the plan of 23,892, 46,892 and 105,819 shares of common stock and recognized expense of $329,000, $536,000 and $464,000 in 1997, 1998 and 1999, respectively. 57 Unit provides a salary deferral plan ("Deferral Plan") which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits which occurs at either termination of employment, death or certain defined unforeseeable emergency hardships. Funds set aside in a trust to satisfy Unit's obligation under the Deferral Plan at December 31, 1998 and 1999 totaled $1,035,000 and $1,165,000, respectively. Unit recognizes payroll expense and records a liability at the time of deferral. Effective January 1, 1997, Unit adopted a separation benefit plan ("Separation Plan"). The Separation Plan allows eligible employees whose employment with Unit is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to 4 week's salary for every whole year of service completed with Unit up to a maximum of 104 weeks. Benefits received under the Separation Plan will be reduced by the amount of any other benefits received from other disability or severance plans, which may be in effect during the payment period. To receive payments the recipient must waive any claims against Unit in exchange for receiving the separation benefits. On October 28, 1997, Unit adopted a Separation Benefit Plan for Senior Management ("Senior Plan"). The Senior Plan provides certain officers and key executives of Unit with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. Unit recognized expense of $577,000 and $502,000 in 1998 and 1999, respectively, for benefits associated with anticipated payments from both separation plans. NOTE 7 - TRANSACTIONS WITH RELATED PARTIES - ------------------------------------------ Unit formed private limited partnerships (the "Partnerships") with certain qualified employees, officers and directors from 1984 through 1999, with a subsidiary of Unit serving as General Partner. The Partnerships were formed for the purpose of conducting oil and natural gas acquisition, drilling and development operations and serving as co-general partner with Unit in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with Unit in most drilling operations and most producing property acquisitions commenced by Unit for its own account during the period from the formation of the Partnership through December 31 of each year. 58 Amounts received in the years ended December 31 from both public and private Partnerships for which Unit is a general partner are as follows: 1997 1998 1999 --------- --------- --------- (In thousands) Contract drilling $ 135 $ 180 $ 94 Well supervision and other fees $ 384 $ 415 $ 425 General and administrative expense reimbursement $ 119 $ 133 $ 138 Related party transactions for contract drilling and well supervision fees are the related party's share of such costs. These costs are billed to related parties on the same basis as billings to unrelated parties for such services. General and administrative reimbursements are both direct general and administrative expense incurred on the related party's behalf and indirect expenses allocated to the related parties. Such allocations are based on the related party's level of activity and are considered by management to be reasonable. A subsidiary of Unit paid the Partnerships, for which Unit or a subsidiary is the general partner, $32,000, $21,000 and $9,000 during the years ended December 31, 1997, 1998 and 1999, respectively, for purchases of natural gas production. NOTE 8 - SHAREHOLDER RIGHTS PLAN - -------------------------------- Unit maintains a Shareholder Rights Plan (the "Plan") designed to deter coercive or unfair takeover tactics, to prevent a person or group from gaining control of Unit without offering fair value to all shareholders and to deter other abusive takeover tactics, which are not in the best interest of shareholders. Under the terms of the Plan, each share of common stock is accompanied by one right, which given certain acquisition and business combination criteria, entitles the shareholder to purchase from Unit one one-hundredth of a newly issued share of Series A Participating Cumulative Preferred Stock at a price subject to adjustment by Unit or to purchase from an acquiring Company certain shares of its common stock or the surviving company's common stock at 50 percent of its value. The rights become exercisable 10 days after Unit learns that an acquiring person (as defined in the Plan) has acquired 15 percent or more of the outstanding common stock of Unit or 10 business days after the 59 commencement of a tender offer, which would result in a person owning 15 percent or more of such shares. Unit can redeem the rights for $0.01 per right at any date prior to the earlier of (i) the close of business on the tenth day following the time Unit learns that a person has become an acquiring person or (ii) May 19, 2005 (the "Expiration Date"). The rights will expire on the Expiration Date, unless redeemed earlier by Unit. NOTE 9 - COMMITMENTS AND CONTINGENCIES - --------------------------------------- Unit leases office space under the terms of operating leases expiring through January 31, 2005. Future minimum rental payments under the terms of the leases are approximately $478,000, $465,000, $393,000, $386,000 and $386,000 in 2000, 2001, 2002, 2003 and 2004, respectively. Total rent expense incurred by the Company was $373,000, $412,000 and $422,000 in 1997, 1998 and 1999, respectively. Unit had letters of credit supported by its Loan Agreement totaling $30,000 at December 31, 1999. Unit as a 40 percent owner in a corporation which provides gas gathering services, guarantees certain indebtedness of that corporation up to a maximum of $2 million (approximately $1,308,000 at December 31, 1999). The guarantee extends for a period ending on June 21, 2001. The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership agreements along with the employee oil and gas limited partnerships require, upon the election of a limited partner, that Unit repurchase the limited partner's interest at amounts to be determined by appraisal in the future. Such repurchases in any one year are limited to 20 percent of the units outstanding. Unit made repurchases of $15,000 in 1998 and $10,000 in 1999 for such limited partners' interests and did not make any such repurchases in 1997. Unit is a party to various legal proceedings arising in the ordinary course of its business none of which, in management's opinion, will result in judgments which would have a material adverse effect on Unit's financial position, operating results or cash flows. 60 NOTE 10 - INDUSTRY SEGMENT INFORMATION - -------------------------------------- In 1998, Unit adopted Statement of Financial Accounting Standard No. 131, "Disclosures about Segments of an Enterprise and Related Information." Unit has two business segments: Contract Drilling and Oil and Natural Gas, representing its two strategic business units offering different products and services. The Contract Drilling segment provides land contract drilling of oil and natural gas wells and the Oil and Natural Gas segment is engaged in the development, acquisition and production of oil and natural gas properties. The accounting policies of the segments are the same as those described in the Summary of Significant Accounting Policies (Note 1). Management evaluates the performance of Unit's operating segments based on operating income, which is defined as operating revenues less operating expenses and depreciation, depletion and amortization. Unit has natural gas production in Canada, which is not significant. 61 1997 1998 1999 ---------- ---------- ---------- (In thousands) Revenues: Contract drilling $ 46,199 $ 53,528 $ 55,479 Oil and natural gas 45,581 39,703 41,540 Other 84 106 434 ---------- ---------- ---------- Total revenues $ 91,864 $ 93,337 $ 97,453 ========== ========== ========== Operating Income (1): Contract drilling $ 5,564 $ 4,033 $ 907 Oil and natural gas 19,755 9,306 11,445 ---------- ---------- ---------- Total operating income 25,319 13,339 12,352 General and administrative expense (4,621) (4,891) (5,071) Interest expense (2,921) (4,815) (5,081) Other income (expense)- net 84 106 434 ---------- ---------- ---------- Income before income taxes $ 17,861 $ 3,739 $ 2,634 ========== ========== ========== Identifiable Assets (2): Contract drilling $ 66,188 $ 69,147 $ 125,853 Oil and natural gas 132,332 150,718 154,513 ---------- ---------- ---------- Total identifiable assets 198,520 219,865 280,366 Corporate assets 3,977 3,199 3,207 ---------- ---------- ---------- Total assets $ 202,497 $ 223,064 $ 283,573 ========== ========== ========== 62 1997 1998 1999 ---------- ---------- ---------- (In thousands) Capital Expenditures: Contract drilling $ 35,193 $ 11,485 $ 55,656 Oil and natural gas 33,525 38,409 20,348 Other 1,464 216 738 ---------- ---------- ---------- Total capital expenditures $ 70,182 $ 50,110 $ 76,742 ========== ========== ========== Depreciation, Depletion and Amortization: Contract drilling $ 4,216 $ 5,766 $ 6,851 Oil and natural gas 12,625 16,069 16,197 Other 358 351 319 ---------- ---------- ---------- Total depreciation, depletion and amortization $ 17,199 $ 22,186 $ 23,367 ========== ========== ========== - ---------------------- (1) Operating income is total operating revenues less operating expenses, depreciation, depletion and amortization and does not include non- operating revenues, general corporate expenses, interest expense or income taxes. (2) Identifiable assets are those used in Unit's operations in each industry segment. Corporate assets are principally cash and cash equivalents, short-term investments, corporate leasehold improvements, furniture and equipment. 63 NOTE 11 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) - -------------------------------------------------------------- Summarized quarterly financial information for 1998 and 1999 is as follows: Three Months Ended --------------------------------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 ----------- ----------- ------------ ----------- Year ended (In thousands except per share amounts) December 31, 1998: Revenues $ 24,249 $ 26,054 $ 23,627 $ 19,407 =========== =========== =========== =========== Gross profit(1) $ 3,471 $ 4,450 $ 3,537 $ 1,881 =========== =========== =========== =========== Income (loss) before income taxes $ 1,163 $ 2,053 $ 1,136 $ (613) =========== =========== =========== =========== Net income (loss) $ 725 $ 1,235 $ 654 $ (368) =========== =========== =========== =========== Earnings (loss) per common share: Basic (2) $ .03 $ .05 $ .03 $ (.01) =========== =========== =========== =========== Diluted (2) $ .03 $ .05 $ .03 $ (.01) =========== =========== =========== =========== December 31, 1999: Revenues $ 19,697 $ 19,479 $ 22,613 $ 35,664 =========== =========== =========== =========== Gross profit(1) $ 456 $ 749 $ 3,729 $ 7,418 =========== =========== =========== =========== Income (loss) before income taxes $ (1,976) $ (1,355) $ 1,226 $ 4,739 =========== =========== =========== =========== Net income (loss) $ (1,274) $ (874) $ 690 $ 2,944 =========== =========== =========== =========== Earnings (loss) per common share: Basic (2) $ (.05) $ (.03) $ .03 $ .09 =========== =========== =========== =========== Diluted (3) $ (.05) $ (.03) $ .03 $ .09 =========== =========== =========== =========== 64 - ------------------ (1) Gross Profit excludes other revenues, general and administrative expense and interest expense. (2) As a result of shares issued during the year, earnings per share for the year's four quarters, which is based on average shares outstanding during each quarter, does not equal the annual earnings per share, which is based on the average shares outstanding during the year. (3) Due to the effect of additional shares sold in the equity offering and issued for the Parker rig acquisition and the effect of price changes of Unit's stock, diluted earnings per share for the year's four quarters, which includes the effect of potential dilutive common shares calculated during each quarter, does not equal the annual diluted earnings per share, which includes the effect of such potential dilutive common shares calculated for the entire year. 65 NOTE 12 - OIL AND NATURAL GAS INFORMATION - ----------------------------------------- The capitalized costs at year end and costs incurred during the year were as follows: USA CANADA TOTAL ----------- --------- ----------- (In thousands) 1997: Capitalized costs: Proved properties $ 225,166 $ 480 $ 225,646 Unproved properties 7,935 78 8,013 ----------- --------- ----------- 233,101 558 233,659 Accumulated depreciation, depletion, amortization and impairment (115,000) (405) (115,405) ----------- --------- ----------- Net capitalized costs $ 118,101 $ 153 $ 118,254 =========== ========= =========== Cost incurred: Unproved properties $ 3,540 $ 78 $ 3,618 Producing properties 1,518 - 1,518 Exploration 1,785 - 1,785 Development 26,604 - 26,604 ----------- --------- ----------- Total costs incurred $ 33,447 $ 78 $ 33,525 =========== ========= =========== 1998: Capitalized costs: Proved properties $ 261,299 $ 480 $ 261,779 Unproved properties 9,900 281 10,181 ----------- --------- ----------- 271,199 761 271,960 Accumulated depreciation, depletion, amortization and impairment (130,894) (412) (131,306) ----------- --------- ----------- Net capitalized costs $ 140,305 $ 349 $ 140,654 =========== ========= =========== Cost incurred: Unproved properties $ 4,297 $ 203 $ 4,500 Producing properties 9,026 - 9,026 Exploration 2,270 - 2,270 Development 22,613 - 22,613 ----------- --------- ----------- Total costs incurred $ 38,206 $ 203 $ 38,409 =========== ========= =========== 66 USA CANADA TOTAL ----------- --------- ----------- (In thousands) 1999: Capitalized costs: Proved properties $ 281,274 $ 508 $ 281,782 Unproved properties 9,596 382 9,978 ----------- --------- ----------- 290,870 890 291,760 Accumulated depreciation, depletion, amortization and impairment (146,840) (420) (147,260) ----------- --------- ----------- Net capitalized costs $ 144,030 $ 470 144,500 =========== ========= =========== Cost incurred: Unproved properties $ 1,693 $ 101 $ 1,794 Producing properties 3,608 28 3,636 Exploration 1,908 - 1,908 Development 13,010 - 13,010 ----------- --------- ----------- Total costs incurred $ 20,219 $ 129 $ 20,348 =========== ========= =========== 67 The results of operations for producing activities are provided below. USA CANADA TOTAL ----------- --------- ----------- (In thousands) 1997: Revenues $ 42,830 $ 69 $ 42,899 Production costs (10,678) (24) (10,702) Depreciation, depletion and amortization (12,537) (16) (12,553) ----------- --------- ----------- 19,615 29 19,644 Income tax expense (7,394) (17) (7,411) ----------- --------- ----------- Results of operations for producing activities (excluding corporate overhead and financing costs) $ 12,221 $ 12 $ 12,233 =========== ========= =========== 1998: Revenues $ 36,861 $ 55 $ 36,916 Production costs (11,572) (20) (11,592) Depreciation, depletion and amortization (15,893) (8) (15,901) ----------- --------- ----------- 9,396 27 9,423 Income tax expense (3,752) (9) (3,761) ----------- --------- ----------- Results of operations for producing activities (excluding corporate overhead and financing costs) $ 5,644 $ 18 $ 5,662 =========== ========= =========== 1999: Revenues $ 38,687 $ 63 $ 38,750 Production costs (10,566) (20) (10,586) Depreciation, depletion and amortization (15,946) (8) (15,954) ----------- --------- ----------- 12,175 35 12,210 Income tax expense (4,748) (14) (4,762) ----------- --------- ----------- Results of operations for producing activities (excluding corporate overhead and financing costs) $ 7,427 $ 21 $ 7,448 =========== ========= =========== 68 Estimated quantities of proved developed oil and natural gas reserves and changes in net quantities of proved developed and undeveloped oil and natural gas reserves were as follows (unaudited): USA CANADA TOTAL ---------------- ---------------- ---------------- NATURAL NATURAL NATURAL OIL GAS OIL GAS OIL GAS BBLS MCF BBLS MCF BBLS MCF ------- -------- ------- -------- ------- -------- (In thousands) 1997: Proved developed and undeveloped reserves: Beginning of year 5,204 128,408 - 753 5,204 129,161 Revision of previous estimates (927) (12,780) - 44 (927) (12,736) Extensions, discoveries and other additions 399 41,108 - - 399 41,108 Purchases of minerals in place 6 2,618 - - 6 2,618 Sales of minerals in place (58) (951) - - (58) (951) Production (493) (13,742) - (74) (493) (13,816) ------- -------- ------- -------- ------- -------- End of Year 4,131 144,661 - 723 4,131 145,384 ======= ======== ======= ======== ======= ======== Proved developed reserves: Beginning of year 4,509 107,536 - 326 4,509 107,862 End of year 3,406 115,071 - 295 3,406 115,366 1998: Proved developed and undeveloped reserves: Beginning of year 4,131 144,661 - 723 4,131 145,384 Revision of previous estimates (1,142) (5,207) - (162) (1,142) (5,369) Extensions, discoveries and other additions 445 31,460 - - 445 31,460 Purchases of minerals in place 257 6,840 - - 257 6,840 Sales of minerals in place (3) (532) - - (3) (532) Production (443) (16,427) - (38) (443) (16,465) ------- -------- ------- -------- ------- -------- End of Year 3,245 160,795 - 523 3,245 161,318 ======= ======== ======= ======== ======= ======== Proved developed reserves: Beginning of year 3,406 115,071 - 295 3,406 115,366 End of year 2,365 119,415 - 421 2,365 119,836 69 USA CANADA TOTAL ---------------- ---------------- ---------------- NATURAL NATURAL NATURAL OIL GAS OIL GAS OIL GAS BBLS MCF BBLS MCF BBLS MCF ------- -------- ------- -------- ------- -------- (In thousands) 1999: Proved developed and undeveloped reserves: Beginning of year 3,245 160,795 - 523 3,245 161,318 Revision of previous estimates 834 (375) - 81 834 (294) Extensions, discoveries and other additions 137 17,644 - - 137 17,644 Purchases of minerals in place 105 7,710 - - 105 7,710 Sales of minerals in place (14) (340) - - (14) (340) Production (373) (15,919) - (35) (373) (15,954) ------- -------- ------- -------- ------- -------- End of Year 3,934 169,515 - 569 3,934 170,084 ======= ======== ======= ======== ======= ======== Proved developed reserves: Beginning of year 2,365 119,415 - 421 2,365 119,836 End of year 2,990 127,737 - 467 2,990 128,204 70 Oil and natural gas reserves cannot be measured exactly. Estimates of oil and natural gas reserves require extensive judgments of reservoir engineering data and are generally less precise than other estimates made in connection with financial disclosures. Unit utilizes Ryder Scott Company, independent petroleum consultants, to review our reserves as prepared by our reservoir engineers. Proved reserves are those quantities which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and natural gas reservoirs under existing economic and operating conditions. Proved developed reserves are those reserves, which can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required. Estimates of oil and natural gas reserves require extensive judgments of reservoir engineering data as previously explained. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. Indeed the uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves. The information set forth herein is, therefore, subjective and, since judgments are involved, may not be comparable to estimates submitted by other oil and natural gas producers. In addition, since prices and costs do not remain static and no price or cost escalations or de-escalations have been considered, the results are not necessarily indicative of the estimated fair market value of estimated proved reserves nor of estimated future cash flows. 71 The standardized measure of discounted future net cash flows ("SMOG") was calculated using year-end prices and costs, and year-end statutory tax rates, adjusted for permanent differences, that relate to existing proved oil and natural gas reserves. SMOG as of December 31 is as follows (unaudited): USA CANADA TOTAL ----------- --------- ----------- (In thousands) 1997: Future cash flows $ 427,292 $ 1,684 $ 428,976 Future production and development costs (153,220) (312) (153,532) Future income tax expenses (63,868) (794) (64,662) ----------- --------- ----------- Future net cash flows 210,204 578 210,782 10% annual discount for estimated timing of cash flows (71,768) (187) (71,955) ----------- --------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 138,436 $ 391 $ 138,827 =========== ========= =========== 1998: Future cash flows $ 388,887 $ 1,089 $ 389,976 Future production and development costs (154,843) (271) (155,114) Future income tax expenses (47,305) (160) (47,465) ----------- --------- ----------- Future net cash flows 186,739 658 187,397 10% annual discount for estimated timing of cash flows (62,770) (259) (63,029) ----------- --------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 123,969 $ 399 $ 124,368 =========== ========= =========== 1999: Future cash flows $ 504,192 $ 1,281 $ 505,473 Future production and development costs (195,063) (344) (195,407) Future income tax expenses (72,325) (175) (72,500) ----------- --------- ----------- Future net cash flows 236,804 762 237,566 10% annual discount for estimated timing of cash flows (84,219) (285) (84,504) ----------- --------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 152,585 $ 477 $ 153,062 =========== ========= =========== 72 The principal sources of changes in the standardized measure of discounted future net cash flows were as follows (unaudited): USA CANADA TOTAL ----------- --------- ----------- (In thousands) 1997: Sales and transfers of oil and natural gas produced, net of production costs $ (32,152) $ (45) $ (32,197) Net changes in prices and production costs (111,745) (651) (112,396) Revisions in quantity estimates and changes in production timing (19,377) 47 (19,330) Extensions, discoveries and improved recovery, less related costs 46,787 - 46,787 Purchases of minerals in place 2,235 - 2,235 Sales of minerals in place (2,282) - (2,282) Accretion of discount 26,227 147 26,374 Net change in income taxes 33,473 345 33,818 Other - net (4,776) (58) (4,834) ----------- --------- ----------- Net change (61,610) (215) (61,825) Beginning of year 200,046 606 200,652 ----------- --------- ----------- End of year $ 138,436 $ 391 $ 138,827 =========== ========= =========== 1998: Sales and transfers of oil and natural gas produced, net of production costs $ (25,289) $ (35) $ (25,324) Net changes in prices and production costs (35,654) (186) (35,840) Revisions in quantity estimates and changes in production timing (17,020) (335) (17,355) Extensions, discoveries and improved recovery, less related costs 24,256 - 24,256 Purchases of minerals in place 6,062 - 6,062 Sales of minerals in place (603) - (603) Accretion of discount 16,719 91 16,810 Net change in income taxes 16,083 486 16,569 Other - net 979 (13) 966 ----------- --------- ----------- Net change (14,467) 8 (14,459) Beginning of year 138,436 391 138,827 ----------- --------- ----------- End of year $ 123,969 $ 399 $ 124,368 =========== ========= =========== 73 USA CANADA TOTAL ----------- --------- ----------- (In thousands) 1999: Sales and transfers of oil and natural gas produced, net of production costs $ (28,121) $ (44) $ (28,165) Net changes in prices and production costs 34,004 23 34,027 Revisions in quantity estimates and changes in production timing (4,945) 44 (4,901) Extensions, discoveries and improved recovery, less related costs 19,208 - 19,208 Purchases of minerals in place 7,272 - 7,272 Sales of minerals in place (320) - (320) Accretion of discount 13,664 44 13,708 Net change in income taxes (14,038) 7 (14,031) Other - net 1,892 4 1,896 ----------- --------- ----------- Net change 28,616 78 28,694 Beginning of year 123,969 399 124,368 ----------- --------- ----------- End of year $ 152,585 $ 477 $ 153,062 =========== ========= =========== Unit's SMOG and changes therein were determined in accordance with Statement of Financial Accounting Standards No. 69. Certain information concerning the assumptions used in computing SMOG and their inherent limitations are discussed below. Management believes such information is essential for a proper understanding and assessment of the data presented. The assumptions used to compute SMOG do not necessarily reflect management's expectations of actual revenues to be derived from those reserves nor their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever- changing nature of such reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to errors inherent in predicting the future, variations from the expected production rate could result from factors outside of management's control, such as unintentional delays in development, environmental concerns or changes in prices or regulatory controls. Also, the reserve valuation assumes that all reserves will be disposed of by production. However, other factors such as the sale of reserves in place could affect the amount of cash eventually realized. Future cash flows are computed by applying year-end prices of oil and natural gas relating to proved reserves to the year-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements in existence at year-end. 74 Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at the end of the year, based on continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year- end statutory tax rates to the future pretax net cash flows relating to proved oil and natural gas reserves less the tax basis of Unit's properties. The future income tax expenses also give effect to permanent differences and tax credits and allowances relating to Unit's proved oil and natural gas reserves. Care should be exercised in the use and interpretation of the above data. As production occurs over the next several years, the results shown may be significantly different as changes in production performance, petroleum prices and costs are likely to occur. 75 REPORT OF INDEPENDENT ACCOUNTANTS The Shareholders and Board of Directors Unit Corporation In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, changes in shareholders' equity and cash flows present fairly in all material respects, the financial position of Unit Corporation and its subsidiaries at December 31, 1998 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. In addition, in our opinion, the accompanying financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these financial statements in accordance with auditing standards generally accepted in the United States which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. PricewaterhouseCoopers LLP Tulsa, Oklahoma February 22, 2000 76 Item 9. Changes in and Disagreements with Accountants on Accounting and - ------- --------------------------------------------------------------- Financial Disclosure. --------------------- None. PART III Item 10. Directors and Executive Officers of the Registrant - -------- -------------------------------------------------- The table below and accompanying footnotes set forth certain information concerning each executive officer of Unit. Unless otherwise indicated, each has served in the positions set forth for more than five years. Executive officers are elected for a term of one year. There are no family relationships between any of the persons named. NAME AGE POSITION - ---------------- --- ---------------------------------------- King P. Kirchner 72 Chairman of the Board, Chief Executive Officer and Director John G. Nikkel 65 President, Chief Operating Officer and Director Earle Lamborn 65 Senior Vice President, Drilling and Director Philip M. Keeley 58 Senior Vice President, Exploration and Production Larry D. Pinkston 45 Vice President, Treasurer and Chief Financial Officer Mark E. Schell 42 General Counsel and Secretary - ------------ Mr. Kirchner, a co-founder of Unit, has been the Chairman of the Board and a director since 1963 and was President until November 1983. Mr. Kirchner is a Registered Professional Engineer within the State of Oklahoma, having received degrees in Mechanical Engineering from Oklahoma State University and in Petroleum Engineering from the University of Oklahoma. 77 Mr. Nikkel joined Unit in 1983 as its President and a director. From 1976 until January 1982 when he co-founded Nike Exploration Company, Mr. Nikkel was an officer and director of Cotton Petroleum Corporation, serving as the President of that Company from 1979 until his departure. Prior to joining Cotton, Mr. Nikkel was employed by Amoco Production Company for 18 years, last serving as Division Geologist for Amoco's Denver Division. Mr. Nikkel presently serves as President and a director of Nike Exploration Company. Mr. Nikkel received a Bachelor of Science degree in Geology and Mathematics from Texas Christian University. Mr. Lamborn has been actively involved in the oil field for over 45 years, joining Unit's predecessor in 1952 prior to it becoming a publicly- held corporation. He was elected Vice President, Drilling in 1973 and to his current position as Senior Vice President and director in 1979. Mr. Keeley joined Unit in November 1983 as a Senior Vice President, Exploration and Production. Prior to that time, Mr. Keeley co-founded (with Mr. Nikkel) Nike Exploration Company in January 1982 and serves as Executive Vice President and a director of that company. From 1977 until 1982, Mr. Keeley was employed by Cotton Petroleum Corporation, serving first as Manager of Land and from 1979 as Vice President and a director. Before joining Cotton, Mr. Keeley was employed for four years by Apexco, Inc. as Manager of Land and prior thereto he was employed by Texaco, Inc. for nine years. He received a Bachelor of Arts degree in Petroleum Land Management from the University of Oklahoma. Mr. Pinkston joined Unit in December 1981. He had served as Corporate Budget Director and Assistant Controller prior to being appointed as Controller in February 1985. He has been Treasurer since December 1986 and was elected to the position of Vice President and Chief Financial Officer in May 1989. He holds a Bachelor of Science Degree in Accounting from East Central University of Oklahoma and is a Certified Public Accountant. Mr. Schell joined Unit in January of 1987, as its Secretary and General Counsel. From 1979 until joining Unit, Mr. Schell was Counsel, Vice President and a member of the Board of Directors of C & S Exploration, Inc. He received a Bachelor of Science degree in Political Science from Arizona State University and his Juris Doctorate degree from the University of Tulsa Law School. He is a member of the Oklahoma and American Bar Association as well as being a member of the American Corporate Counsel Association and the American Society of Corporate Secretaries. The balance of the information required in this Item 10 is incorporated by reference from Unit's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company's 2000 annual meeting of stockholders. 78 Item 11. Executive Compensation - -------- ---------------------- Information required by this item is incorporated by reference from Unit's Proxy Statement to be filed with the Securities and Exchange Commission in connection with Unit's 2000 annual meeting of stockholders. Item 12. Security Ownership of Certain Beneficial Owners and Management - -------- -------------------------------------------------------------- Information required by this item is incorporated by reference from Unit's Proxy Statement to be filed with the Securities and Exchange Commission in connection with Unit's 2000 annual meeting of stockholders. Item 13. Certain Relationships and Related Transactions - -------- ---------------------------------------------- Information required by this item is incorporated by reference from Unit's Proxy Statement to be filed with the Securities and Exchange Commission in connection with Unit's 2000 annual meeting of stockholders. 79 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on - -------- ------------------------------------------------------ Form 8-K --------- (a) Financial Statements, Schedules and Exhibits: 1. Financial Statements: --------------------- Included in Part II of this report: Consolidated Balance Sheets as of December 31, 1998 and 1999 Consolidated Statements of Operations for the years ended December 31, 1997, 1998 and 1999 Consolidated Statements of Changes in Shareholders' Equity for the years ended December 31, 1997, 1998 and 1999 Consolidated Statements of Cash Flows for the years ended December 31, 1997, 1998 and 1999 Notes to Consolidated Financial Statements Report of Independent Accountants 2. Financial Statement Schedules: ------------------------------ Included in Part IV of this report for the years ended December 31, 1997, 1998 and 1999: Schedule II - Valuation and Qualifying Accounts and Reserves Other schedules are omitted because of the absence of conditions under which they are required or because the required information is included in the consolidated financial statements or notes thereto. The exhibit numbers in the following list correspond to the numbers assigned such exhibits in the Exhibit Table of Item 601 of Regulation S-K. 3. Exhibits: -------- 2.1 Agreement and Plan of Merger dated November 21, 1997, by and among the Registrant, Unit Drilling Company, the Shareholders and Hickman Drilling Company (filed as an Exhibit to Unit's Form 8-K dated November 21, 1997, which is incorporated herein by reference). 80 2.2 Asset Purchase Agreement dated August 12, 1999, by and among Unit Corporation, Parker Drilling Company and Parker Drilling Company North America, Inc. (filed as Exhibit 99.1 to Unit's Form 8-K dated September 23, 1999, which is incorporated herein by reference). 2.3 Agreement and Plan of Merger, dated as of December 8, 1999, among Unit Corporation, Questa Oil & Gas Co. and Unit Acquisition Company (filed as Appendix A to the Proxy Statement/Prospectus which forms a part of Unit's Registration Statement on Form S-4 as S.E.C. File No. 333-94325, which is incorporated herein by reference). 2.4 Form of Stockholder Agreement, between Unit Corporation and the directors and executive officers of Questa Oil & Gas Co. (filed as Exhibit 2.2 of Unit's Registration Statement on Form S-4 as S.E.C. File No. 333-94325, which is incorporated herein by reference). 3.1.3 Restated Certificate of Incorporation of Unit Corporation dated February 2, 1994 (filed as Exhibit 3.1 to Unit's Registration Statement on Form S-3 as S.E.C. file No. 333- 83551, which is incorporated herein by reference). 3.2.2 By-Laws of Unit Corporation (filed as an Exhibit to Unit's Registration Statement on Form S-3 as S.E.C. file No. 333- 83551, which is incorporated herein by reference). 4.1 Form of Promissory Note to be issued to the Shareholders of Hickman Drilling Company pursuant to the Agreement and Plan of Merger dated November 21, 1997 (filed as an Exhibit to Unit's Form 8-K dated November 21, 1997, which is incorporated herein by reference). 4.2.3 Form of Common Stock Certificate (filed as Exhibit 4.1 on Form S-3 as S.E.C. File No. 333-83551, which is incorporated herein by reference). 4.2.6 Rights Agreement between Unit Corporation and Chemical Bank, as Rights Agent (filed as Exhibit 1 to Unit's Form 8- A filed with the S.E.C. on May 23, 1995, File No. 1-92601 and incorporated herein by reference). 81 10.1.23 Loan Agreement dated April 30, 1998 (filed as an Exhibit to Unit's Quarterly Report under cover of Form 10-Q for the quarter ended June 30, 1998, which is incorporated herein by reference). 10.1.24 First Amendment to the Loan Agreement effective as of May 1, 1999 between and among Unit Corporation, Bank of Oklahoma, N.A., BankBoston, N.A., Bank of America, N.A. and Local Oklahoma Bank, N.A. (filed as an Exhibit to Unit's Quarterly Report under cover of Form 10-Q for the quarter ended September 30, 1999, which is incorporated herein by reference). 10.2.2 Unit 1979 Oil and Gas Program Agreement of Limited Partnership (filed as Exhibit I to Unit Drilling and Exploration Company's Registration Statement on Form S-1 as S.E.C. File No. 2-66347, which is incorporated herein by reference). 10.2.10 Unit 1984 Oil and Gas Program Agreement of Limited Partnership (filed as an Exhibit 3.1 to Unit 1984 Oil and Gas Program's Registration Statement Form S-1 as S.E.C. File No. 2-92582, which is incorporated herein by reference). 10.2.18 Unit 1991 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit's Annual Report under cover of Form 10-K for the year ended December 31, 1991, which is incorporated herein by reference). 10.2.19 Unit 1992 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit's Annual Report under cover of Form 10-K for the year ended December 31, 1992, which is incorporated herein by reference). 10.2.20 Unit 1993 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit's Annual Report under cover of Form 10-K for the year ended December 31, 1992, which is incorporated herein by reference). 10.2.21*Unit Drilling and Exploration Employee Bonus Plan (filed as Exhibit 10.16 to Unit's Registration Statement on Form S-4 as S.E.C. File No. 33-7848, which is incorporated herein by reference). 10.2.22*The Company's Amended and Restated Stock Option Plan (filed as an Exhibit to Unit's Registration Statement on Form S-8 as S.E.C. File No's. 33-19652, 33-44103 and 33- 64323 which is incorporated herein by reference) 82 10.2.23*Unit Corporation Non-Employee Directors' Stock Option Plan (filed as an Exhibit to Form S-8 as S.E.C. File No. 33- 49724, which is incorporated herein by reference). 10.2.24*Unit Corporation Employees' Thrift Plan (filed as an Exhibit to Form S-8 as S.E.C. File No. 33-53542, which is incorporated herein by reference). 10.2.25 Unit Consolidated Employee Oil and Gas Limited Partnership Agreement. (filed as an Exhibit to Unit's Annual Report under cover of Form 10-K for the year ended December 31, 1993, which is incorporated herein by reference). 10.2.26 Unit 1994 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit's Annual Report under cover of Form 10-K for the year ended December 31, 1993, which is incorporated herein by reference). 10.2.27*Unit Corporation Salary Deferral Plan (filed as an Exhibit to Unit's Annual Report under cover of Form 10-K for the year ended December 31, 1993, which is incorporated herein by reference). 10.2.28 Unit 1995 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit's Annual Report, under cover of Form 10-K for the year ended December 31, 1994, which is incorporated herein by reference). 10.2.29 Unit 1996 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit's Annual Report under cover of Form 10-K for the year ended December 31, 1995, which is incorporated herein by reference). 10.2.30*Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (filed as an Exhibit to Unit's Annual Report under the cover of Form 10-K for the year ended December 31, 1996, which is incorporated herein by reference). 10.2.31 Unit 1997 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit's Annual Report under the cover of Form 10-K for the year ended December 31, 1996). 83 10.2.32 Unit Corporation Separation Benefit Plan for Senior Management (filed as an Exhibit to Unit's Quarterly Report under cover of Form 10-Q for the quarter ended September 30, 1997, which is incorporated herein by reference). 10.2.33 Unit 1998 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit's Annual Report under the cover of Form 10-K for the year ended December 31, 1997). 10.2.34 Unit 1999 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to Unit's Annual Report under the cover of Form 10-K for the year ended December 31, 1998). 10.2.35 Unit 2000 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed herewith). 21 Subsidiaries of the Registrant (filed herewith). 23 Consent of Independent Accountants (filed herewith). 27 Financial Data Schedules (filed herewith). * Indicates a management contract or compensatory plan identified pursuant to the requirements of Item 14 of Form 10-K. (b) Reports on Form 8-K: On October 12, 1999, we filed a report on Form 8-K under Item 2 reporting the acquisition of 13 land contract drilling rigs from Parker Drilling Company and Parker Drilling Company North America, Inc. On December 10, 1999, we filed a report on Form 8-K/A under Item 7 reporting the financial statements of business acquired and pro forma financial information for the acquisition of 13 land contract drilling rigs for Parker Drilling Company and Parker Drilling Company North America, Inc. On December 15, 1999, we filed a report on Form 8-K under Item 5 reporting the announcement of a definitive agreement and plan of merger with Questa Oil and Gas Co. 84 Schedule II UNIT CORPORATION AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Allowance for Doubtful Accounts: Additions Balance Balance at charged to Deductions at beginning costs & & net end of Description of period Expenses write-offs period ----------- ---------- ---------- ---------- ---------- (In thousands) Year ended December 31, 1997 $ 104 $ 250 $ - $ 354 ========== ========== ========== ========== Year ended December 31, 1998 $ 354 $ - $ 80 $ 274 ========== ========== ========== ========== Year ended December 31, 1999 $ 274 $ 305 $ 6 $ 573 ========== ========== ========== ========== Deferred Tax Asset Valuation Allowance: Balance Balance at At beginning end of Description of period Additions Deductions period ----------- ---------- ---------- ---------- ---------- (In thousands) Year ended December 31, 1997 $ 3,530 $ - $ 1,978 $ 1,552 ========== ========== ========== ========== Year ended December 31, 1998 $ 1,552 $ - $ 1,022 $ 530 ========== ========== ========== ========== Year ended December 31, 1999 $ 530 $ - $ 195 $ 335 ========== ========== ========== ========== 85 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. UNIT CORPORATION DATE: March 9, 2000 By: /s/ John G. Nikkel ------------------ --------------------------- JOHN G. NIKKEL President and Chief Operating Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 9th day of March, 2000. Name Title - ------------------------------- ----------------------------------- /s/ King P. Kirchner - ------------------------------- Chairman of the Board and Chief KING P. KIRCHNER Executive Officer, Director /s/ John G. Nikkel - ------------------------------- President and Chief Operating JOHN G. NIKKEL Officer, Director /s/ Earle Lamborn - ------------------------------- Senior Vice President, Drilling, EARLE LAMBORN Director /s/ Larry D. Pinkston - ------------------------------- Vice President, Chief Financial LARRY D. PINKSTON Officer and Treasurer /s/ Stanley W. Belitz - ------------------------------- Controller STANLEY W. BELITZ /s/ J. Michael Adcock - ------------------------------- Director J. MICHAEL ADCOCK /s/ Don Cook - ------------------------------- Director DON COOK /s/ William B. Morgan - ------------------------------- Director WILLIAM B. MORGAN /s/ John S. Zink - ------------------------------- Director JOHN S. ZINK /s/ John H. Williams - ------------------------------- Director JOHN H. WILLIAMS 86 EXHIBIT INDEX ----------------------- Exhibit No. Description Page - ------ ----------------------------------------------- ----- 10.2.35 Unit 2000 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership. 21 Subsidiaries of the Registrant. 23 Consent of Independent Accountants. 27 Financial Data Schedules. 87
Date: 3/9/2000 Form: 10-K - Annual Report
