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, 1998 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 Common Stock, par value on which registered $.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 17, 1999 - $143,274,719 Number of Shares of Common Stock Outstanding on March 17, 1999 - 26,653,341 DOCUMENTS INCORPORATED BY REFERENCE 1. Portions of Registrant's Proxy Statement with respect to the Annual Meeting of Stockholders to be held May 5, 1999 are incorporated by reference in Part III. Exhibit Index - See Page 77 FORM 10-K UNIT CORPORATION TABLE OF CONTENTS PART I Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . 18 Item 4. Submission of Matters to a Vote of Security Holders. . . . . . . . 18 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters. . . . . . . . . . . . . . . . . . . . . . . 19 Item 6. Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . 20 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . 21 Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . 29 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . . . . . . . . . . . . 67 PART III Item 10. Directors and Executive Officers of the Registrant . . . . . . . . 67 Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . 68 Item 12. Security Ownership of Certain Beneficial Owners and Management . . . . . . . . . . . . . . . . . . . . . . . . . 68 Item 13. Certain Relationships and Related Transactions . . . . . . . . . . 69 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K. . . . . . . . . . . . . . . . . . . . . . . . . . . 69 Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 UNIT CORPORATION Annual Report For The Year Ended December 31, 1998 PART I Item 1. Business and Item 2. Properties - ----------------------------------------- GENERAL The Company, through its wholly owned subsidiaries, is engaged in the land contract drilling of oil and natural gas wells and the development, acquisition and production of oil and natural gas properties. The Company's primary exploration and production operations are conducted in the Anadarko and Arkoma Basins, which cover portions of Oklahoma, Texas, Kansas and Arkansas, with additional operations located in the South Texas Basin. Additional producing properties are located in other states, including, but not limited to, New Mexico, Louisiana, North Dakota, Colorado, Wyoming, Montana, Alabama, Mississippi, Arkansas, Illinois and Nebraska as well as in Canada. The Company's contract drilling operations are primarily located in the Oklahoma and Texas areas of the Anadarko and Arkoma Basins with additional operations in the Permian and South Texas Basins. The Company was originally incorporated in Oklahoma in 1963 as Unit Drilling Company. In 1979 it became a publicly held Delaware corporation and changed its name to Unit Drilling and Exploration Company ("UDE") to more accurately reflect the importance of its oil and natural gas business. In September 1986, pursuant to a merger and exchange offer, the Company acquired all of the assets and assumed all of the liabilities of UDE and six oil and gas limited partnerships for which UDE was the general partner, in exchange for shares of the Company's common stock (the "Exchange Offer"). The Company's principal executive offices are maintained at 1000 Kensington Tower, 7130 South Lewis, Tulsa, Oklahoma 74136; telephone number (918) 493-7700. The Company also has regional offices in Moore and Woodward, Oklahoma and Booker and Houston, Texas. When used in this report, the term "Company" refers to Unit Corporation and at times Unit Corporation and/or one or more of its subsidiaries with respect to periods from and after the Exchange Offer and to UDE with respect to periods prior thereto. OIL AND NATURAL GAS OPERATIONS In 1979, the Company began to develop its exploration and production operations to diversify its source of revenues which, up to that time, were derived from its contract drilling. Today, the Company conducts the development, production and sale of oil and natural gas together with the acquisition of producing properties through its wholly owned subsidiary, Unit Petroleum Company. As of December 31, 1998, the Company had 3,245 Mbbls and 161,318 MMcf of estimated proved oil and natural gas reserves, respectively. The Company's producing oil and natural gas interests, undeveloped leaseholds 1 and related assets are located primarily in Oklahoma, Texas, Louisiana and New Mexico and to a lesser extent in Arkansas, North Dakota, Colorado, Wyo- ming, Montana, Alabama, Mississippi, Arkansas, Illinois, Nebraska and Canada. As of December 31, 1998, the Company had an interest in a total of 2,499 wells in the United States and served as the operator of 524 wells. The Company also had an interest in 64 wells located in Canada. The majority of the Company's development and exploration prospects are generated by its technical staff. When the Company is the operator of a property, it generally employs its own drilling rigs and the Company's own engineering staff supervises the drilling operation. The Company intends to continue the growth in its oil and natural gas operations utilizing funds generated from operations and its bank revolving line of credit. Well and Leasehold Data. The Company's oil and natural gas explora- tion and development drilling activities and the number of wells in which the Company had an interest, which were producing or capable of producing, were as follows for the periods indicated: Year Ended December 31, ------------------------------------------------- 1998 1997 1996 Wells drilled: Gross Net Gross Net Gross Net - -------------- ------ ------ ------ ------ ------ ------ Exploratory: Oil.............. - - - - - - Natural gas...... - - - - - - Dry.............. 1 .26 - - - - ------ ------ ------ ------ ------ ------ Total 1 .26 - - - - ====== ====== ====== ====== ====== ====== Development: Oil.............. 4 .44 10 4.84 10 8.35 Natural gas...... 52 19.26 57 23.85 55 19.46 Dry.............. 21 10.62 15 9.27 7 4.26 ------ ------ ------ ------ ------ ------ Total 77 30.32 82 37.96 72 32.07 ====== ====== ====== ====== ====== ====== Oil and natural gas wells producing or capable of producing: - ------------------------------------------------------------ Oil - USA........ 726 196.64 684 197.67 717 197.71 Oil - Canada..... - - - - - - Gas - USA........ 1,773 286.73 1,545 260.40 1,530 242.09 Gas - Canada..... 64 1.60 64 1.60 64 1.60 ------ ------ ------ ------ ------ ------ Total 2,563 484.97 2,293 459.67 2,311 441.40 ====== ====== ====== ====== ====== ====== 2 The following table summarizes the Company's acreage as of the end of each of the years indicated: Developed Acreage Undeveloped Acreage ------------------- --------------------- Gross Net Gross Net ------- ------- ------- ------- 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 ======= ======= ======= ======= 1997 ---- USA 432,824 118,926 37,844 26,116 Canada 39,040 976 18,970 18,970 ------- ------- ------- ------- Total 471,864 119,902 56,814 45,086 ======= ======= ======= ======= 1996 ---- USA 455,713 115,326 29,245 19,124 Canada 39,040 976 - - ------- ------- ------- ------- Total 494,753 116,302 29,245 19,124 ======= ======= ======= ======= 3 Price and Production Data. The Company's 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 were as follows: Year Ended December 31, ---------------------------------- 1998 1997 1996 -------- -------- -------- Average sales price per barrel of oil produced: USA $ 12.81 $ 19.19 $ 20.40 Canada $ - $ - $ - Average sales price per Mcf of natural gas produced: USA $ 1.90 $ 2.43 $ 2.21 Canada $ 1.46 $ .93 $ 1.18 Oil production (Mbbls): USA 443 493 579 Canada - - - -------- -------- -------- Total 443 493 579 ======== ======== ======== Natural gas production (MMcf): USA 16,427 13,742 12,974 Canada 38 74 51 -------- -------- -------- Total 16,465 13,816 13,025 ======== ======== ======== Average production expense per equivalent Mcf: USA $ .61 $ .64 $ 0.68 Canada $ .54 $ .33 $ 0.27 Reserves. The following table sets forth the estimated proved developed and undeveloped oil and natural gas reserves of the Company at the end of each of the years indicated: Year Ended December 31, --------------------------------- 1998 1997 1996 ------- ------- ------- Oil (Mbbls): USA 3,245 4,131 5,204 Canada - - - ------- ------- ------- Total 3,245 4,131 5,204 ======= ======= ======= Natural gas (MMcf): USA 160,795 144,661 128,408 Canada 523 723 753 ------- ------- ------- Total 161,318 145,384 129,161 ======= ======= ======= 4 Further information relating to oil and natural gas operations is presented in Notes 1,5,12 and 14 of Notes to Consolidated Financial Statements set forth in Item 8 hereof. LAND CONTRACT DRILLING OPERATIONS Unit Drilling Company, a wholly owned subsidiary of the Company, is engaged in the land drilling of oil and natural gas wells for a wide range of customers. 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. An active maintenance and replacement program during the life of a drilling rig permits upgrading of components 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 as required, while other components, such as the substructure, mast and drawworks, can be utilized for extended periods of time with proper maintenance. The Company also owns additional equipment used in the operation of its rigs, including large air compres- sors, trucks and other support equipment. On November 20, 1997, the Company acquired Hickman Drilling Company, an Oklahoma corporation pursuant to an Agreement and Plan of Merger ("the Merger Agreement"), dated November 20, 1997 entered into by and between the Company, the Company's wholly owned subsidiary Unit Drilling Company, Hickman Drilling Company and all of the holders of the outstanding capital stock of Hickman Drilling Company (the "Selling Stockholders"). Under the terms of this acquisition, the Selling Stockholders received, in aggregate, 1,300,000 shares of Common Stock and promissory notes in the aggregate principal amount of $5,000,000 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 the Company retained Hickman Drilling Company's Woodward, Oklahoma corporate office as a regional office for its contract drilling operations. In December 1997, the Company also purchased a Mid- Continent U-36A, 650 horsepower rig with a 13,000 feet depth capacity and spare components from two additional rigs for a total consideration of $1 million, of which $200,000 was paid at closing and the balance is to be paid over a period ending no later than three years. The balance is to be paid out monthly with the monthly amount to be calculated on the basis of a predetermined daily rate multiplied by the number of days in such month that the acquired rig is employed for the account of the seller, all as more fully specified in the acquisition agreement. If the balance of the purchase price has not been fully paid at the end of three years the remaining amount is to be paid in cash to the seller. 5 With the acquisitions noted above, the Company's drilling rig fleet expanded to 34 rigs with depth capacities ranging from 7,000 to 25,000 feet. At December 31, 1998, 29 of the Company's rigs were located in the Anadarko and Arkoma Basins of Oklahoma and Texas while five of its larger horsepower rigs were located in South Texas. In the Anadarko and Arkoma Basins the Company's primary focus is on the utilization of its medium depth rigs which have a depth range of 8,000 to 14,000 feet. These medium depth rigs are suited to the contract drilling currently undertaken by operators in these two basins. At present, the Company does not have a shortage of drilling rig related equipment. During 1996 and through 1997, the Company increased its drill pipe acquisitions since certain grades of drill pipe were in high demand, due to increased rig utilization. However, at any given time, the Company's ability to utilize its full complement of drilling rigs is dependent upon the availability of qualified labor, drilling supplies and equipment as well as demand. Should industry conditions improve rapidly, there is no assurance that sufficient supplies of drill pipe, other drilling equipment and qualified labor will be readily available, not only within the Company, but in the industry as a whole. The following table sets forth, for each of the periods indicated, certain data concerning the Company's contract drilling operations: Year Ended December 31, --------------------------------- 1998 1997 1996 1995 1994 ---- ---- ---- ---- ---- Number of operational rigs owned at end of period 34 34(1) 24 22 25 Average number of rigs utilized (2) 22.9 19.2 14.7 10.9 9.5 Number of wells drilled 198 167 130 111 95 Total footage drilled (feet in 1000's) 2,203 1,736 1,468 1,196 1,027 - ------------------- (1) Includes 10 rigs acquired in the fourth quarter of 1997. (2) Utilization rates are based on a 365-day year. A rig is considered utilized when it is operating or being moved, assembled or dismantled under contract. As of February 23, 1999, 22 of the Company's 34 drilling rigs were operating under contract. 6 The following table sets forth, as of February 23, 1999, the type and approximate depth capability of each of the Company's 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 16,000 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 During the previous decade, the Company's contract drilling services encountered significant competition due to depressed levels of activity in contract drilling. In the last 6 months of 1996 and throughout 1997 and the first three quarters of 1998, the Company's drilling operation showed significant improvements in rig utilization. However, in late 1998, the Company and the industry as a whole experienced a significant reduction in demand. The Company anticipates that competition within the industry will, for the foreseeable future, continue to adversely affect the Company. Drilling Contracts. Most of the Company's drilling contracts are obtained through competitive bidding. Generally, the 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 7 matters. The contracts obligate the Company 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. The Company generally indemnifies its customers against certain types of claims by the Company's employees and claims arising from surface pollution caused by spills of fuel, lubricants and other solvents within the control of the Company. Such customers generally indemnify the Company against claims arising from other surface and subsurface pollution other than claims resulting from the Company's gross negligence. The contracts may provide for compensation to the Company on a day rate, footage or turnkey basis with additional compensation for special risks and unusual conditions. Under daywork contracts, the Company provides the drilling rig with the required personnel to the operator who supervises the drilling of the contracted well. Compensation to the Company is based on a negotiated rate per day as the rig is utilized. Footage contracts usually require the Company to bear some of the drilling costs in addition to providing the rig. The Company is compensated on a rate per foot drilled basis upon completion of the well. Under turnkey contracts, the Company contracts to drill a well to a specified depth and provides most of the equipment and services required. The Company bears the risk of drilling the well to the contract depth and is compensated when the contract provisions have been satisfied. Turnkey drilling operations, in particular, might result in losses if the Company underestimates the costs of drilling a well or if unforeseen events occur. To date, the Company has not experienced significant losses in performing turnkey contracts. For 1998, turnkey revenue represented approximately 15 percent of the Company's contract drilling revenues. Because the proportion of turnkey drilling is currently dictated by market conditions and the desires of customers using the Company's services, the Company is unable to predict whether the portion of drilling conducted on a turnkey basis will increase or decrease in the future. Customers. During the fiscal year ended December 31, 1998, 10 contract drilling customers accounted for approximately 24 percent of the Company's total revenues and approximately 5 percent of the Company's total revenues were generated by drilling on oil and natural gas properties of which the Company was the operator (including properties owned by limited partnerships for which the Company acted as general partner). Such drill- ing was pursuant to contracts containing terms and conditions comparable to those contained in the Company's customary drilling contracts with non- affiliated operators. Further information relating to contract drilling operations is presented in Notes 1, 2 and 12 of Notes to Consolidated Financial State- ments set forth in Item 8 hereof. 8 VOLATILE NATURE OF THE COMPANY'S OIL AND NATURAL GAS MARKETS; FLUCTUATIONS IN PRICES The Company's revenue and profitability are substantially dependent upon prevailing prices for natural gas and crude oil. Oil and natural gas prices have historically been volatile and are expected by the Company to continue to be volatile in the future. These prices vary based on factors beyond the control of the Company, including the extent of domestic produc- tion and importation of crude oil and natural gas, the proximity and capacity of oil and natural gas pipelines, costs of gathering natural gas, the marketing of competitive fuels, general fluctuations in the supply and demand for oil and natural gas, the effect of federal and state regulation of production, refining, transportation and sales, the use and allocation of oil and natural gas and their substitute fuels and general national and worldwide economic conditions. In addition, natural gas spot prices received by the Company are influenced by weather conditions impacting the continental United States. The Company's oil and condensate production is sold at or near the Company's wells under purchase contracts at prevailing prices in accordance with arrangements which are customary in the oil industry. The Company's 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 which are customary in the industry. The worldwide supply of oil has been largely dependent upon rates of production of foreign reserves. Although the demand for oil has increased in the United States, imports of foreign oil continue to increase. Future domestic oil prices will depend largely upon the actions of foreign producers with respect to rates of production and it is virtually impossible to predict what actions those producers will take in the future. Prices may also be affected by political, social and other factors relating to the Middle East. In view of the many uncertainties affecting the supply and demand for oil and natural gas, the Company is unable to predict future oil and natural gas prices or the overall effect, if any, that a decline in demand or oversupply of such products would have on the Company. COMPETITION All lines of business in which the Company engages are highly com- petitive. Competition in land contract drilling traditionally involves such factors as price, efficiency, condition of equipment, availability of labor and equipment, reputation and customer relations. Some of the Company's competitors in the land contract drilling business are sub- stantially larger than the Company and have appreciably greater financial and other resources. As a result of the decrease in demand for land 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 the Company's drilling operations presently operates is uncertain and extremely price oriented. 9 The Company's 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 the Company. OIL AND NATURAL GAS PROGRAMS The Company currently serves as a general partner to 4 oil and gas limited partnerships and 10 employee oil and gas limited partnerships. The employee partnerships acquire an interest fixed annually, ranging from 5% to 15% of the Company's interest, in most oil and natural gas drilling activities and purchases of producing oil and natural gas properties participated in by the Company. The limited partners in the employee partnerships are either employees or directors of the Company or its sub- sidiaries. Under the terms of the partnership agreements of each limited part- nership, the general partner, which in each case is Unit Petroleum Company, 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 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 where the Company is the operator of an oil and natural gas well and also provides contract drilling services. Although the Company has no formal procedures for resolving such conflicts, the Company believes it fulfills its responsibility to each contracting party and complies fully with the terms of the agreements which regulate such conflicts. EMPLOYEES As of February 23, 1999, the Company had approximately 453 employees in its land contract drilling operations, 47 employees in its oil and natu- ral gas operations and 44 in its general corporate area. None of the Company's employees are represented by a union or labor organization nor have the Company's operations ever been interrupted by a strike or work stoppage. The Company considers relations with its employees to be satisfactory. OPERATING AND OTHER RISKS The Company's land contract drilling and oil and natural gas operations are subject to a variety of oil field hazards such as fire, explosion, blowouts, cratering and oil spills or certain other types of possible surface and subsurface pollution, any of which can cause personal injury and loss of life and severely damage or destroy equipment, suspend drilling operations and cause substantial damage to surrounding areas or property of others. As protection against some, but not all, of these operating hazards, the Company maintains broad insurance coverage, including all-risk physical damage, employer's liability and comprehensive general liability. In all states in which the Company operates except Oklahoma, the Company maintains a large deductible worker's compensation 10 policy that insures for losses exceeding $200,000. In Oklahoma, starting in August 1991, the Company elected to become self insured. In consideration therewith, the Company purchased an excess liability reinsurance policy to insure losses exceeding $250,000. The Company believes that to the extent reasonably practicable such insurance coverages are adequate. The Company's insurance policies do not, however, provide protection against revenue losses incurred by reason of business inter- ruptions caused by the destruction or damage of major items of equipment nor certain types of hazards such as specific types of environmental pollution claims. In view of the difficulties which may be encountered in renewing such insurance at reasonable rates, no assurance can be given that the Company will be able to maintain the amount of insurance coverage which it considers adequate at reasonable rates. Moreover, loss of or serious damage to any of the Company's equipment, although adequately covered by insurance, could have an adverse effect upon the Company's earning capacity. The Company's oil and natural gas operations are also subject to all of the risks and hazards typically associated with the search for and production of oil and natural gas. These include the necessity of ex- pending large sums of money for the location and acquisition of properties and for drilling exploratory wells. In such exploratory work, many failures and losses may occur before any accumulation of oil or natural gas may be found. If oil or natural gas is encountered, there is no assurance that it will be capable of being produced or will be in quantities sufficient to warrant development or that it can be satisfactorily mar- keted. The Company's future natural gas and crude oil revenues and production, and therefore cash flow and income, are highly dependent upon the Company's level of success in acquiring or finding additional reserves. Without continuing reserve additions through exploration or acquisitions, the Company's reserves and production will decline. GOVERNMENTAL REGULATIONS The production and sale of oil and natural gas is highly affected by various state and federal regulations. All states in which the Company conducts activities impose restrictions on the drilling, production and sale of oil and natural gas, which often include requirements relating to well spacing, waste prevention, production limitations, pollution preven- tion and clean-up, obtaining drilling permits and similar matters. The following discussion summarizes, in part, the regulations of the United States oil and natural gas industry and is not intended to constitute a complete discussion of the many statutes, rules, regulations and governmental orders to which the Company's operations may be subject. The Company's activities are subject to existing federal and state laws and regulations governing environmental quality and pollution control. Various states and governmental agencies are considering, and some have adopted, laws and regulations regarding environmental control which could adversely affect the business of the Company. Such laws and regulations may substantially increase the costs of doing business and may prevent or delay the commencement or continuation of given operations. Compliance with such legislation and regulations, together with any penalties resulting from noncompliance therewith, will increase the cost of oil and natural gas drilling, development, production and processing. In the opinion of the Company's management, its operations to date comply in all 11 material respects with applicable environmental legislation and regula- tions; however, in view of the many uncertainties with respect to the current controls, including their duration, interpretation and possible modification, the Company can not predict the overall effect of such controls on its operations. On July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 (the "Wellhead Decontrol Act") became effective. Under the Wellhead Decontrol Act, all remaining price and non-price controls of first sales under the NGA and NGPA were removed effective January 1, 1993. Prices for deregulated categories of natural gas fluctuate in response to market pressures which currently favor purchasers and disfavor producers. As a result of the deregulation of a greater proportion of the domestic United States natural gas market and an increase in the availability of natural gas transportation, a competitive trading market for natural gas has developed. During the past several years, the Federal Energy Regulatory Commission ("FERC") has adopted several regulations designed to accomplish a more competitive, less regulated market for natural gas. These regulations have materially affected the market for natural gas. The major elements of several of these initiatives remain subject to appellate review. One of the initiatives FERC adopted was order 636. In brief, the primary requirements of Order 636 are as follows: pipelines must separate their sales and transportation services; pipelines must provide open access transportation services that are equal in quality for all natural gas suppliers and must provide access to storage on an open access contract basis; pipelines that provide firm sales service on May 18, 1992 must offer a "no-notice" firm transportation service under which firm shippers may receive delivery of natural gas on demand up to their firm entitlement without incurring daily balancing and scheduling penalties; pipelines must provide all shippers with equal and timely access to information relevant to the availability of their open access transportation services; open access pipelines must allow firm transportation customers to downstream pipelines to acquire capacity on upstream pipelines held by downstream pipelines; pipelines must implement a capacity releasing program so that firm shippers can release unwanted capacity to those desiring capacity (which program replaces previous "capacity brokering" and "buy-sell" programs); existing bundled firm sales entitlement are converted to unbundled firm sales entitlement and to unbundled firm transportation rights on the effective date of a particular pipeline's blanket sales certificate; and pipeline transportation rights must be developed under the Straight Fixed Variable (SFV) method of cost classification, allocation and rate design unless the FERC permits the pipeline to use some other method. The FERC will not permit a pipeline to change the new resulting rates until the FERC accepts the pipeline's formal restructuring plans. In essence, the goal of Order 636 is to make a pipeline's position as natural gas merchant indistinguishable from that of a non-pipeline supplier. It, therefore, pushes the point of sale of natural gas by pipelines upstream, perhaps all the way to the wellhead. Order 636 also requires pipelines to give firm transportation customers flexibility with respect to receipt and delivery points (except that a firm shipper's choice of delivery point cannot be downstream of the existing primary delivery point) and to allow "no-notice" service (which means that natural gas is 12 available not only simultaneously but also without prior nomination, with the only limitation being the customer's daily contract demand) if the pipeline offered no-notice city-gate sales service on May 18, 1992. Thus, this separation of pipelines' sales and transportation allows non-pipeline sellers to acquire firm downstream transportation rights and thus to offer buyers what is effectively a bundled city-gate sales service and it permits each customer to assemble a package of services that serves its individual requirements. But it also makes more difficult the coordination of natural gas supply and transportation. A corollary to these changes is that all pipelines will be permitted to sell natural gas at market-based rates. The results of these changes may be the increased availability of firm transportation and the reduction of interruptible transportation, with a corresponding reduction in the rates for off-peak and interruptible transportation. Due to the continuing evolutionary nature of Order 636 and its implementation, it is not possible to project the overall potential impact on transportation rates for natural gas or market prices of natural gas. The future interpretation and application by FERC of these rules and its broad authority, or of the state and local regulations by the relevant agencies, could affect the terms and availability of transportation services for transportation of natural gas to customers and the prices at which natural gas can be sold by the Company. For instance, as a result of Order 636, more interstate pipeline companies have begun divesting their gathering systems, either to unregulated affiliates or to third persons, a practice which could result in separate, and higher, rates for gathering a producer's natural gas. In proceedings during mid and late 1994 allowing various interstate natural gas companies' spindowns or spinoffs of gathering facilities, the FERC held that, except in limited circumstances of abuse, it generally lacks jurisdiction over a pipeline's gathering affiliates, which neither transport natural gas in interstate commerce nor sell gas in interstate commerce for resale. However, pipelines spinning down gathering systems have to include two Order No. 497 standards of conduct in their tariffs: nondiscriminatory access to transportation for all sources of supply and no tying of pipeline transportation service to any service by the pipeline's gathering affiliate. In addition, if unable to reach a mutually acceptable gathering contract with a present user of the gathering facilities, the FERC required that the pipeline must offer a two-year "default contract" to existing users of the gathering facilities. However, on appeal, while the United States Court of Appeals for the District of Columbia upheld the FERC's allowing the spinning down of gathering facilities to a non-regulated affiliate, in Conoco Inc. v. FERC, 90 F.3d 536, 552-53 (D.C. Cir. 1996)the D.C. Circuit remanded the FERC's default contract mechanism. On February 18, 1997, the United States Supreme Court denied review of the D.C. Circuit's decision. Additional proceedings that might affect the natural gas industry are pending before the FERC and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue. Sales of petroleum liquids by the Company are not currently regulated and are made at market prices; however, the FERC is considering a proposal that could increase transportation rates for petroleum liquids. A number of legislative proposals have also been introduced in Congress and the state legislatures of various states, that, 13 if enacted, would significantly affect the petroleum industry. Such proposals involve, among other things, the imposition of land and use controls and certain measures designed to prevent petroleum companies from acquiring assets in other energy areas. In addition, there is always the possibility that if market conditions change dramatically in favor of oil and natural gas producers that some new form of "windfall profits" or severance tax may be proposed and imposed upon oil or natural gas. At the present time it is impossible to predict which proposals, if any, will actually be enacted by Congress or the various state legislatures. The Company believes that it is complying with all orders and regulations applicable to its operations. However, in view of the many uncertainties with respect to the current controls, including their duration and possible modification together with any new proposals that may be enacted, the Company cannot predict the overall effect, if any, of such controls on Company operations. Certain states in which the Company operates control production from wells through regulations establishing the spacing of wells, limiting the number of days in a given month during which a well can produce and otherwise controlling the rate of allowable production. As noted above, the Company's operations are subject to numerous federal and state laws and regulations regarding the control of contamination of the environment. These laws and regulations may require the acquisition of a permit before or after drilling commences, prohibit drilling activities on certain lands lying within wilderness areas or where pollution arises and impose substantial liabilities for pollution resulting from drilling operations, particularly operations in offshore waters or on submerged lands. A past, present, or future release or threatened release of a hazardous substance into the air, water, or ground by the Company or as a result of disposal practices may subject the Company to liability under the Comprehensive Environmental Response, Compensation and Liability Act, as amended ("CERCLA"), the Resource Conservation Recovery Act ("RCRA"), the Clean Water Act, and/or similar state laws, and any regulations promulgated pursuant thereto. Under CERCLA and similar laws, the Company may be fully liable for the cleanup costs of a release of hazardous substances even though it contributed to only part of the release. While liability under CERCLA and similar laws may be limited under certain circumstances, the limits are so high that the maximum liability would likely have a significant adverse effect on the Company. In certain circumstances, the Company may have liability for releases of hazardous substances by previous owners of Company properties. CERCLA currently excludes petroleum from its definition of "hazardous substances." However, Congress may delete this exclusion for petroleum, in which case the Company would be required to manage its petroleum production and wastes from its exploration and production activities as CERCLA hazardous substances. In addition, RCRA classifies certain oil field wastes as "non-hazardous." Congress may delete this exemption for oilfield waste, in which case the Company would have to manage much of its oilfield waste as hazardous. Additionally, the discharge or substantial threat of a discharge of oil by the Company into United States waters or onto an adjoining shoreline may subject the Company to liability under the Oil Pollution Act of 1990 and similar state laws. While liability under the Oil Pollution Act of 1990 is limited under certain circumstances, the maximum liability under those limits would still likely have a significant adverse effect on the Company. 14 Violation of environmental legislation and regulations may result in the imposition of fines or civil or criminal penalties and, in certain circumstances, the entry of an order for the abatement of the conditions, or suspension of the activities, giving rise to the violation. The Company believes that the Company has complied with all orders and regulations applicable to its operations. However, in view of many uncertainties with respect to the current controls, including their duration and possible modification, the Company cannot predict the overall effect of such controls on such operations. Similarly, the Company cannot predict what future environmental laws may be enacted or regulations may be promulgated and what, if any, impact they would have on operations. SAFE HARBOR STATEMENT OF FURTHER ACTIVITY In the normal course of its business, the Company, in an effort to help keep its shareholders and the public informed about the Company's operations, may, from time to time, issue certain statements, either in writing or orally, that contain or may contain forward looking information. Generally, these statements relate to projections involving the anticipated revenues to be received from the Company's oil and natural gas production or drilling operations, the utilization rate of its drilling rigs, growth of its oil and natural gas reserves, well performance, and the Company's anticipated debt. Statements in this Annual Report on Form 10-K under the captions "Business" and "Management's Discussion and Analysis of Financial Condition and Results of Operations", as well as oral statements that may be made by the Company or by officers, directors or employees of the Company acting on the Company's behalf, that are not historical facts constitute "forward- looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Words such as "believes", "anticipates" and similar expressions, although not inclusive, identify forward-looking statements. Such forward-looking statements are subject to a number of factors that may tend to influence the accuracy of the statements and the projections upon which the statements are based. As noted elsewhere in this report, all phases of the Company's operations are subject to a number of influences outside the control of the Company, any one of which, or a combination of which, could materially affect the results of the Company's operations. All future written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by such factors. In order to provide a more thorough understanding of the possible effects of some of these influences on any forward looking statements made by the Company, the following discussion outlines certain factors that in the future could cause the Company's consolidated results for 1999 and beyond to differ materially from those that may be set forth in any such forward-looking statement made by or on behalf of the Company. 15 Commodity Prices The prices received by the Company for its oil and natural gas production have a direct impact on the Company's revenues, profitability and cash flow as well as its ability to meet its projected financial and operational goals. The prices for natural gas and crude oil are heavily dependent on a number of factors beyond the control of the Company, including, but not limited to, 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 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 difference in such prices even on a month to month basis. All these factors, especially when coupled with the fact that much of the Company's product prices are determined on a month to month basis, can, and at times do, lead to wide fluctuations in the prices received by the Company. Based upon the results of operations for the year ended December 31, 1998, the Company estimates 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 $1,541,000 and $414,000, respectively. During 1998, substantially all of the natural gas and crude oil volume of the Company were sold at market responsive prices. Customer Demand Demand for the Company's 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 the Company's drilling rigs. These include the funds available to such companies 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 the Company's 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 the Company's ability to work its drilling rigs are the weather, which can, under adverse circumstances, delay or even cause a project to be abandoned by an operator, the competition faced by the Company in securing the award of a drilling contract in a given area, the experience and recognition of the Company in a new market area, and the availability of labor to run the Company's drilling rigs. 16 Uncertainty Of Oil And Natural Gas Reserves And Well Performance There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the control of the Company. Estimating quantities of proved reserves is imprecise. Such estimates are based upon certain assumptions pertaining to future production levels, future natural gas and crude oil prices, timing and amount of development expenditures and future operating costs, using currently available geologic, engineering and economic data, some or all of which may prove to be incorrect over time. As a result of changes in these assumptions that will occur in the future, and based upon further production history, results of future exploration and development activities, future natural gas and crude oil prices and other factors, the reported quantity of reserves may be subject to upward or downward revision. In addition to the foregoing, projections regarding the potential production and reserve capabilities of newly drilled and/ or completed wells are subject to additional uncertainties that may significantly influence such projections. Such wells have a very limited production history, if any, on which to base future forecasts of their capabilities. Since an established rate of production is a primary factor used by reservoir engineers to forecast oil and natural gas reserves as well as a well's production rate, the lack of this information decreases the Company's ability to accurately project such information. In addition, there are inherent risks in both the drilling and completion phases of a new well which could cause a well bore to be prematurely abandoned due either to the loss of the well bore in the physical sense or due to the costs associated with operational problems which could render further operations uneconomical. Debt and Bank Borrowing The amount of the Company's existing debt as well as its future debt is, to a large extent, a function of the costs associated with the projects undertaken by the Company at any given time and the cash flow received by the Company. Generally, the costs incurred by the Company in its 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 its drilling rig fleet. To some extent, these costs, particularly the first two items, are discretionary and the Company maintains a degree of control regarding the timing and/ or the need to incur the same. However, in some cases, unforseen 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 the Company to incur increased debt above that which it had expected or forecast. Likewise, for many of the reasons mentioned above, the Company's cash flow may not be sufficient to cover its current cash requirements which would then require the Company to increase its debt either through bank borrowings or otherwise. 17 International Operations and Risks Currently all of the Company's contract land drilling operations are conducted within the continental United States. Should, however, the Company at some point in the future undertake international drilling operations, such operations would be subject to a number of risks including foreign exchange restrictions, currency fluctuations, foreign taxation, changing political conditions and foreign and domestic policies, expropriation, nationalization, nullification, modification or renegotiation of contracts, war and civil disturbances or other risks that may limit or disrupt markets. In addition, the Company would incur certain additional costs in establishing and running such operations. Item 3. Legal Proceedings - -------------------------- The Company is a party to various legal proceedings arising in the ordinary course of its business none of which, in the Company's opinion, should result in judgments which would have a material adverse effect on the Company. Item 4. Submission of Matters to a Vote of Security Holders - ------------------------------------------------------------ No matters were submitted to the security holders during the fourth quarter of the Company's calendar year ended December 31, 1998. 18 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder - -------------------------------------------------------------------------- Matters - ------- As of February 23, 1999, the Company had 2,543 holders of record of its common stock the only form of stock issued as of that date. The Company has not paid any cash dividends on shares of its common stock since its organization and currently intends to continue its policy of retaining earnings from the Company's operations. The Company is 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 its consolidated net income of 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. The table below reflects the high and low sales prices per share of the Company's common stock as reported by the New York Stock Exchange, Inc. for the period indicated: 1998 1997 -------------------- -------------------- QUARTER High Low High Low ------- --------- --------- --------- --------- First $ 9 13/16 $ 6 7/16 $12 1/4 $ 7 1/2 Second $ 9 7/8 $ 5 1/2 $11 7/8 $ 7 7/8 Third $ 6 5/16 $ 3 3/4 $15 3/8 $ 9 5/8 Fourth $ 6 15/16 $ 3 5/8 $15 13/16 $ 8 7/16 19 Item 6. Selected Financial Data - -------------------------------- Year Ended December 31, --------------------------------------------------- 1998 1997 1996 1995 1994 ------- ------- ------- ------- ------- (In thousands except per share amounts) Revenues $93,337 $91,864 $72,070 $53,074 $43,895 ======= ======= ======= ======= ======= Income From Continuing Operations $ 2,246 $11,124 $ 8,333 $ 3,751 (1) $ 4,628 (2) ======= ======= ======= ======= ======= Net Income $ 2,246 $11,124 $ 8,333 $ 3,999 (1) $ 4,794 (2) ======= ======= ======= ======= ======= Basic Earnings Per Common Share: Continuing Operations $.09 $.46 $.37 $.18 (1) $.22 (2) Discontinued Operation - - - .01 .01 ---- ---- ---- ---- ---- Net Income $.09 $.46 $.37 $.19 (1) $.23 (2) ==== ==== ==== ==== ==== Diluted Earnings Per Common Share: Continuing Operations $.09 $.45 $.37 $.18 (1) $.22 (2) Discontinued Operation - - - .01 .01 (2) ---- ---- ---- ---- ---- Net Income $.09 $.45 $.37 $.19 (1) $.23 ==== ==== ==== ==== ==== Total Assets $223,064 $202,497 $137,993 $110,922 $103,933 ======== ======== ======== ======== ======== Long-Term Debt $ 72,900 $ 54,100 $ 40,600 $ 41,100 $ 37,300 ======== ======== ======== ======== ======== Other Long-Term Liabilities $ 2,301 $ 2,279 $ 2,276 $ 2,109 $ 2,673 ======== ======== ======== ======== ======== 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. (2) Includes a $742,000 gain on sale of a natural gas gathering system. See Management's Discussion of Financial Condition and Results of Operations for a review of 1998, 1997 and 1996 activity. 20 Item 7. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations - --------------------- Financial Condition and Liquidity - --------------------------------- The Company's loan agreement ("Loan Agreement"), provides for a total facility 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 revolving credit facility are limited to a borrowing value which is subject to a semi-annual redetermination. As of the latest borrowing value determination, $85 million of the commitment is available to the Company. The Loan Agreement contains certain covenants which require the Company 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 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. At December 31, 1998, borrowings under the Loan Agreement totaled $68.9 million. At February 23, 1999, borrowings under the Loan Agreement totaled $71.0 million with $11.4 million available for future borrowings. The interest rate on the bank debt was 6.27 and 6.31 percent at December 31, 1998 and February 23, 1999, respectively. At the Company's election, any portion of the debt outstanding may be fixed at the London Interbank Offered Rate ("Libor Rate"), as adjusted per the Loan Agreement depending on the level of debt as a percentage of the total borrowing base, for 30, 60, 90 or 180 days with the remainder of the outstanding debt subject to the Chase Manhattan Bank, N. A. prime rate ("Chase Prime Rate"). During any Libor Rate funding period, the Company may not pay in part or in whole the outstanding principal balance of the note to which such Libor Rate option applies. At both December 31, 1998 and February 23, 1999, $63.0 million of borrowings were subject to the Libor Rate as adjusted. A commitment fee of 3/8 of 1 percent is charged for any unused portion of the borrowing base. Shareholders' equity at December 31, 1998 was $111.3 million, making the Company's ratio of long-term debt-to-equity .66 to 1. The Company's primary source of liquidity and capital resources in the near- and long- term will consist of cash flow from operating activities and available borrowings under the Loan Agreement. Net cash provided by operating activities in 1998 was $33.5 million as compared to $34.4 million in 1997. At December 31, 1998 and January 31, 1999, the Company had working capital of $1.6 million and $1.0 million, respectively. The Company's capital expenditures during 1998 were $50.1 million. The Company's oil and natural gas operations had capital expenditures of $38.4 million, with $24.9 million and $9.0 million used for exploration and development drilling and producing property acquisitions, respectively. Capital expenditures made by the Company's contract drilling operations were $11.5 million in 1998. Drilling capital expenditures in 1998 were for drill pipe and collars, the refurbishment of one drilling rig previously stacked and major overhauls on large rig components of drilling rigs in 21 service. The Company's drilling rigs are composed of large components some of which, on a rotational basis, are required to be overhauled to assure continued proper performance. Such capital expenditures will continue in future years with approximately $2.5 million projected for 1999. During 1999, the Company's oil and natural gas exploration subsidiary plans to continue its developmental drilling program. However, lower spot market natural gas prices in the fourth quarter of 1998 have increased the potential availability of economical producing property acquisitions and, as a result, a larger portion of the Company's capital expenditure budget may be shifted to producing property acquisitions in 1999. The majority of the Company's capital expenditures are discretionary and primarily directed toward increasing reserves and future growth. Current operations are not dependent on the Company's ability to obtain funds outside of the Company's Loan Agreement. The decision to acquire or drill on oil and natural gas properties at any given time depends on market conditions, potential return on investment, future drilling potential and the availability of opportunities to obtain financing given the circumstances involved, thus providing the Company with a large degree of flexibility in incurring such costs. Depending, in part, on commodity pricing, the Company plans to spend approximately $20 million on its exploration capital expenditure program in 1999. On November 20, 1997, the Company acquired Hickman Drilling Company, pursuant to an Agreement and Plan of Merger ("the Merger Agreement"), entered into by and between the Company, Hickman Drilling Company and all of the holders of the outstanding capital stock of Hickman Drilling Company (the "Selling Stockholders"). Under the terms of this acquisition, the Selling Stockholders received, in aggregate, 1,300,000 shares of Common Stock and promissory notes in the aggregate principal amount of $5,000,000 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. The notes bear interest at the Chase Prime Rate which at both December 31, 1998 and February 23, 1999 was 7.75 percent. In December 1997, the Company also purchased a Mid- Continent U-36-A, 650 horsepower rig with a 13,000 feet depth capacity and spare components from two additional rigs for a total consideration of $1 million, of which $200,000 was paid at closing and the balance is being paid out over a period ending no later than three years after the acquisition date. The balance is paid out monthly with the monthly amount calculated on the basis of a predetermined daily rate multiplied by the number of days in such month that the acquired rig is employed for the account of the seller, all as more fully specified in the acquisition agreement. If the balance of the purchase price has not been fully paid at the end of three years the remaining amount is to be paid in cash to the seller. At December 31, 1998, the balance remaining under this purchase agreement was $331,000. In March of 1998, a Vice President of South America Drilling Operations was hired to facilitate the Company's efforts to expand its contract drilling operations outside the continental United States, specifically into areas of South America. Drilling markets in South America have the potential to provide higher profit margins and higher profit contributions, with longer term multi-year contracts which could also provide a leveling effect on drilling rig utilization. The Company 22 has not previously conducted international contract drilling operations, but it anticipates that such operations would involve a number of additional political, economic, currency, tax and other risks and costs not generally encountered in its domestic operations. To date, the Company has not entered into any contracts for international work. Prior to December 31, 1997, the Company received monthly payments on behalf of itself and other parties (collectively the "Committed Interest") from a natural gas purchaser pursuant to a settlement agreement (the "Settlement Agreement"). The monthly payments paid by the purchaser for natural gas not taken (the "Prepayment Balance") were subject to recoupment in volumes of natural gas through a period ending on the earlier of recoupment or December 31, 1997 (the "Recoupment Period"). At December 31, 1997, the Settlement Agreement and the natural gas purchase contracts which were subject to the Settlement Agreement terminated. As a result of the Settlement Agreement, the December 31, 1997 Prepayment Balance of $2.2 million became payable in equal annual payments over a five year period. The first payment of $441,000 was due and paid on June 1, 1998. The price per Mcf under the Settlement Agreement was substantially higher than current spot market prices. The impact of the higher price received under the Settlement Agreement increased pre-tax income approximately $540,000 and $650,000 in 1997 and 1996, respectively. The natural gas previously subject to the Settlement Agreement is now being sold at spot market prices consistent with primarily all of the rest of the natural gas sold by the Company. Oil and natural gas prices received by the Company were volatile throughout 1998. Average oil prices received by the Company in December 1998, as compared to January 1998, dropped by 35 percent. Average natural gas prices in December 1998, as compared to January 1998, were one percent higher after recovering from a 20 percent decrease in August and September of 1998. The Company's average price received for oil during 1998 was $12.81 and the average natural gas price was $1.90. Average oil prices and natural gas spot prices received in February 1999 were up 5 percent for oil and down 16 percent for natural gas, when compared with December 31, 1998 average prices. The large drop in natural gas prices in February 1999 had a significant impact to the value of the Company's natural gas reserves as reported at December 31, 1998. If this lower natural gas price had occurred at year-end 1998, it would have caused the Company to reduce the carrying value of its natural gas properties by approximately $22.0 million before taxes. If prices do not recover from this February level and depending on other variables, the Company will record a provision to reduce the carrying value of oil and natural gas properties in the first quarter of 1999. Oil prices within the industry remain largely dependent upon world market developments for crude oil. Prices for natural gas are influenced by weather conditions and supply imbalances, particularly in the domestic market, and by world wide oil price levels. Declines in natural gas or oil prices could also adversely effect the Company operationally by, for example, adversely impacting future demand for its drilling rigs or financially by reducing the price received for its oil and natural gas sales and also by adversely effecting the semi-annual borrowing value determination under the Company's Loan Agreement since this determination is calculated on the value of the Company's oil and natural gas reserves. 23 At December 31, 1998, the Company did not have any hedge against the fluctuation in the price of oil and natural gas nor did the Company maintain any forward or future contracts relating to the production of its oil and natural gas. In the first quarter of 1999, the Company initiated swap transactions to help manage its exposure to commodity price risk in the month to month sale of natural gas. These transactions cover approximately 20 percent of the Company's daily production and cover the period from March 1, 1999 to June 30, 1999. These activities have been designated as hedging activities by the Company and will be accounted for as such. Increases (decreases) in the fair value of these instruments will generally offset increases (decreases) in the spot market prices of natural gas. Implicit gains or losses, resulting from changes in the fair value of hedges which have not yet been settled, are not recognized to the extent that they relate to changes in the spot price of anticipated natural gas sales. Gains or losses arising from hedge transactions are recorded in sales in the month of the hedged transaction. As a result of the depressed condition existing in the contract drilling industry over much of the past decade, the Company's ability to fully utilize its complement of drilling rigs during portions of 1997 and 1998 when there was a rapid increase in drilling activity was limited due to the lack of qualified labor and certain support equipment not only within the Company, but in the industry as a whole. The Company's ability to utilize its drilling rigs at any given time is dependent on a number of factors, including but not limited to, the price of both oil and natural gas, the availability of labor and the Company's ability to supply the type of equipment required. Although the Company currently does not have a shortage of rig labor or support equipment, the Company's management expects that these factors will continue to influence the Company's rig utilization especially if demand should rapidly increase. In the third quarter of 1994, the Company's Board of Directors authorized the Company to purchase up to 1,000,000 shares of the Company's 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. During the first quarters of 1998, 1997 and 1996, 19,863, 23,892 and 44,686 of the purchased shares, respectively, were reissued as the Company's matching contribution to its 401(k) Employee Thrift Plan. At December 31, 1998, 25,000 treasury shares were held by the Company. Year 2000 Statement - ------------------- The Company has initiated a comprehensive assessment of its information technology ("IT") and non-information technology ("non-IT") systems to try and ensure that such systems will be Year 2000 compliant. The Year 2000 problem exists because many existing computer programs use only the last two digits to define the year. Therefore, these computer programs do not recognize years that begin with a "20" and assume that all years begin with a "19". If not corrected many computer applications could fail or create erroneous results which could cause disruption of operations not only for the Company but also for its customers and suppliers, so the Company has also initiated an assessment of its customers' and suppliers' efforts to become year 2000 compliant. 24 Evaluation of the Company's IT systems began in house during 1997. The Company's IT systems consist mainly of office computers, related computer programs and mangement financial information software. The Company believes nearly all of the Company's hardware is Year 2000 compliant and approximately 20 percent of its related computer programs and software are Year 2000 compliant. The Company has expended approximately $92,000 and estimates it will expend an additional $40,000 to bring the remaining systems compliant by the end of the second quarter of 1999. The Company's non-IT systems consist of office equipment and other systems associated with its oil and natural gas properties and its drilling rigs. The Company began assessing these non-IT systems and the associated cost during the fourth quarter of 1998. The assessment and replacement of equipment, if any, should be completed by the end of the second quarter of 1999. The Company anticipates that the cost associated with non-IT systems will be minimal. During the third quarter of 1998, the Company issued questionnaires to its key suppliers and customers to assess their preparation for Year 2000 compliance. The Company received responses from 41 percent of these entities. Approximately 90 percent of the responses indicated that these entities are aware of and are in the process of resolving their Year 2000 issues. During the first quarter of 1999, the Company will issue second request questionnaires to those key suppliers and customers who did not respond to the questionnaires issued during the third quarter of 1998. Upon the return of the second request questionnaires from these non- affiliated entities, the Company will review their responses and will begin the process of assessing the preparedness of these entities. As noted, the Company currently anticipates that all of its internal systems and equipment will be Year 2000 compliant by the end of the second quarter of 1999 and that the associated costs will not have a material adverse effect on the Company's results of operations and financial condition. However, the failure to properly assess or timely implement a material Year 2000 problem could result in a disruption in the Company's normal business activities or operations. Such failures, depending on the extent and nature, could materially and adversely effect the Company's operations and financial condition. As a result, the Company will continue to evaluate its Year 2000 exposure, both internally and externally. Since a portion of the Company's overall evaluation of its Year 2000 readiness will, of necessity, be based on the information to be supplied by and the readiness of the Company's key suppliers and customers, the Company cannot currently determine the impact, if any, such third parties will have on the Company's Year 2000 exposure. As noted, the Company intends to evaluate this information as, if and when it is made available to it. To date, the Company has not developed a contingency plan. 25 Effects of Inflation - --------------------- The effects of inflation on the Company's operations in previous years have been minimal due to low inflation rates. However, during third and fourth quarters of 1996 and throughout 1997 as drilling rig day rates and drilling rig utilization increased, the impact of inflation intensified as the availability of related equipment, third party services and qualified labor decreased. In 1998, the impact of inflation was reduced as oil and natural gas prices became depressed. The impact on the Company in the future will depend on the relative increase, if any, the Company may realize in its drilling rig rates and the selling price of its oil and natural gas. If industry activity suddenly increases substantially, shortages in support equipment such as drill pipe, third party services and qualified labor will occur resulting in additional corresponding increases in material and labor costs. These market conditions may limit the Company's ability to realize improvements in operating profits. Results of Operations - --------------------- 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 day 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 the Company's 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 the Company 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 the Company. 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, the Company's 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 from the previous quarter. 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 born by the drilling contractor. 26 Operating margins (revenues less operating costs) for the Company's oil and natural gas 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 the Company between the two years. Total operating costs were 9 percent higher in 1998 compared to 1997 as the Company continues 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. 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 the Company increased its equivalent barrels of production by 14 percent and the Company's average DD&A rate per equivalent barrel increased 11 percent to $4.99 in 1998. General and administrative expenses increased 6 percent as certain employee costs increased. Interest expense increased 65 percent as the Company's 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. 1997 versus 1996 - ---------------- Net income for 1997 was $11,124,000, compared with $8,333,000 in 1996. Increases in rig utilization, contract drilling day rates, average natural gas prices received and natural gas production from new wells drilled during the year all combined to produce the increase in 1997 net income. Oil and natural gas revenues increased 6 percent in 1997 due to a 6 percent and 10 percent increase in natural gas production and average natural gas prices received, respectively. These increases were partially offset by a 15 percent decline in oil production and a 6 percent decrease in average oil prices received by the Company in 1997. Oil production declined from 1996 levels due to the Company's emphasis over the past two years in drilling development wells which focused on replacing and increasing natural gas reserves. Average natural gas spot market prices received by the Company increased 11 percent while volumes produced from certain wells included under the Settlement Agreement, which ended at December 31, 1997 and contained provisions for prices higher than current spot market prices, dropped 7 percent. The impact of higher prices received under the Settlement Agreement increased pre-tax income by approximately $540,000 and $650,000 in 1997 and 1996, respectively. In 1997, revenues from contract drilling operations increased by 60 percent as average rig utilization increased from 14.7 rigs operating in 1996 to 19.2 rigs operating in 1997, and daywork revenues per rig per day increased 22 percent. During the first three quarters of 1997, the Company's monthly rig utilization consistently remained above 18 rigs with 27 daywork revenue per rig per day steadily climbing by 15 percent. In October utilization dropped slightly below 18 rigs before the Company acquired 9 rigs through the Hickman acquisition in late November 1997 and another rig in December 1997, raising the Company's rig count to 34 rigs and its utilization in December to 26.2 rigs. Daywork revenue per rig per day continued to rise in the fourth quarter, but the Company's average dayrate declined 9 percent in December compared to November since the acquired rigs, due to their depth capabilities, earned lower dayrates. Total daywork revenues represented 72 percent of total drilling revenues in 1997 and 68 percent in 1996. Turnkey and footage contracts typically provide for higher revenues since a greater portion of the expense of drilling the well is born by the drilling contractor. Operating margins (revenues less operating costs) for the Company's oil and natural gas operations were 71 percent in 1997 compared to 69 percent in 1996. Increased operating margins resulted primarily from the increase in natural gas production and the increase in natural gas prices received by the Company between the two years. Total operating costs were 2 percent lower in 1997 compared to 1996. Operating margins for contract drilling increased from 16 percent in 1996 to 21 percent in 1997. Margins in 1997 improved due to increases in daily rig rates and utilization. Total operating costs for contract drilling were up 50 percent in 1997 versus 1996 due to increased drilling rig utilization. Contract drilling depreciation increased 43 percent in response to increased rig utilization and additional drilling capital expenditures throughout 1997. Depreciation, depletion and amortization ("DD&A") of oil and natural gas properties increased 17 percent as the Company increased its equivalent barrels of production by 2 percent and the Company's average DD&A rate per equivalent barrel increased 15 percent to $4.49 in 1997. General and administrative expenses increased 12 percent as certain employee costs and outside services increased. Interest expense decreased 8 percent as the average interest rate on the Company's outstanding bank debt decreased from 7.69 percent in 1996 to 7.27 percent in 1997. Average bank debt also decreased 4 percent during 1997. Prior to 1996, the Company's effective income tax rate was significantly impacted by its net operating loss carryforwards. As of December 31, 1995, the Company's net operating loss and statutory depletion carryforwards were fully recognized for financial reporting purposes; therefore, the Company's effective income tax rate in 1996 and 1997 increased to approximately the statutory rate. 28 Item 8. Financial Statements and Supplementary Data - ----------------------------------------------------- UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS As of December 31, ------------------------- ASSETS 1998 1997 ---------- ---------- (In thousands) Current Assets: Cash and cash equivalents $ 446 $ 458 Accounts receivable (less allowance for doubtful accounts of $274 and $354) 13,149 19,813 Materials and supplies 3,298 3,535 Prepaid expenses and other 2,650 2,206 ---------- ---------- Total current assets 19,543 26,012 ---------- ---------- Property and Equipment: Drilling equipment 123,258 119,155 Oil and natural gas properties, on the full cost method 271,960 233,659 Transportation equipment 2,955 2,825 Other 6,870 6,948 ---------- ---------- 405,043 362,587 Less accumulated depreciation, depletion, amortization and impairment 207,883 192,613 ---------- ---------- Net property and equipment 197,160 169,974 ---------- ---------- Other Assets 6,361 6,511 ---------- ---------- Total Assets $ 223,064 $ 202,497 ========== ========== The accompanying notes are an integral part of the consolidated financial statements 29 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS - CONTINUED As of December 31, ------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY 1998 1997 ---------- ---------- (In thousands) Current Liabilities: Current portion of long-term liabilities and debt $ 1,801 $ 727 Accounts payable 8,517 11,112 Accrued liabilities 7,362 7,762 Contract advances 310 92 ---------- ---------- Total current liabilities 17,990 19,693 ---------- ---------- Other Long-Term Liabilities (Note 5) 2,301 2,279 ---------- ---------- Long-Term Debt 72,900 54,100 ---------- ---------- Deferred Income Taxes 18,583 17,560 ---------- ---------- Commitments and Contingencies (Note 11) 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 25,514,836 shares issued, respectively 5,113 5,103 Capital in excess of par value 82,187 82,043 Retained earnings 24,121 21,875 Treasury stock, at cost (25,000 and 19,863 shares, respectively) (131) (156) ---------- ---------- Total shareholders' equity 111,290 108,865 ---------- ---------- Total Liabilities and Shareholders' Equity $ 223,064 $ 202,497 ========== ========== The accompanying notes are an integral part of the consolidated financial statements 30 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31, ---------------------------------- 1998 1997 1996 -------- -------- -------- (In thousands except per share amounts) Revenues: Contract drilling $53,528 $46,199 $28,819 Oil and natural gas 39,703 45,581 43,013 Other 106 84 238 -------- -------- -------- Total revenues 93,337 91,864 72,070 -------- -------- -------- Expenses: Contract drilling: Operating costs 43,729 36,419 24,259 Depreciation 5,766 4,216 2,944 Oil and natural gas: Operating costs 14,328 13,201 13,409 Depreciation, depletion and amortization 16,069 12,625 10,807 General and administrative 4,891 4,621 4,122 Interest 4,815 2,921 3,162 -------- -------- -------- Total expenses 89,598 74,003 58,703 -------- -------- -------- Income Before Income Taxes 3,739 17,861 13,367 -------- -------- -------- Income Tax Expense: Current 139 118 4 Deferred 1,354 6,619 5,030 -------- -------- -------- Total income taxes 1,493 6,737 5,034 -------- -------- -------- Net Income $ 2,246 $11,124 $ 8,333 ======== ======== ======== Net Income Per Common Share: Basic $ .09 $ .46 $ .37 ======== ======== ======== Diluted $ .09 $ .45 $ .37 ======== ======== ======== The accompanying notes are an integral part of the consolidated financial statements 31 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY Year Ended December 31, 1996, 1997 and 1998 Capital In Excess Common Of Par Retained Treasury Stock Value Earnings Stock Total -------- -------- --------- -------- --------- (In thousands) Balances, January 1, 1996 $ 4,195 $50,181 $ 2,418 $ (188) $ 56,606 Net income - - 8,333 - 8,333 Activity in employee compensation plans (321,667 shares) 64 615 - 123 802 Issuance of stock on exercise of warrants (2,859,555 shares) 572 11,939 - - 12,511 Purchase of treasury stock (5,000 shares) - - - (42) (42) -------- -------- --------- -------- --------- Balances, December 31, 1996 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 ======== ======== ========= ======== ========= The accompanying notes are an integral part of the consolidated financial statements 32 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, --------------------------------- 1998 1997 1996 --------- --------- --------- (In thousands) Cash Flows From Operating Activities: Net Income $ 2,246 $ 11,124 $ 8,333 Adjustments to reconcile net income to net cash provided (used) by operating activities: Depreciation, depletion, and amortization 22,186 17,199 14,079 Loss (gain) on disposition of assets 17 (94) (185) Employee stock compensation plans 561 244 214 Bad debt expense - 250 - Deferred tax expense (benefit) 1,354 6,619 5,030 Changes in operating assets and liabilities increasing (decreasing) cash: Accounts receivable 6,664 (1,762) (5,444) Materials and supplies 237 (1,233) (254) Prepaid expenses and other (444) (211) (418) Accounts payable 948 2,062 (2,288) Accrued liabilities (27) 1,430 540 Contract advances 218 (1,208) 890 Other liabilities (447) (70) 167 --------- --------- --------- Net cash provided by operating activities 33,513 34,350 20,664 --------- --------- --------- The accompanying notes are an integral part of the consolidated financial statements 33 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED Year Ended December 31, --------------------------------- 1998 1997 1996 --------- --------- --------- (In thousands) Cash Flows From Investing Activities: Capital expenditures (including producing property acquisitions) $(53,654) $(45,115) $(34,111) Cash received on acquisition of drilling company (Note 2) - 1,611 - Proceeds from disposition of property and equipment 964 792 1,009 (Acquisition) disposition of other assets- (93) (314) 215 --------- --------- --------- Net cash used in investing activities (52,783) (43,026) (32,887) --------- --------- --------- Cash Flows From Financing Activities: Borrowings under line of credit 52,700 34,400 31,500 Payments under line of credit (32,900) (25,900) (32,000) Net payments on notes payable and other long-term debt (470) - (20) Proceeds from sale of common stock 59 225 12,798 Acquisition of treasury stock (131) (138) (42) --------- --------- --------- Net cash provided by financing activities 19,258 8,587 12,236 --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents (12) (89) 13 Cash and Cash Equivalents, Beginning of Year 458 547 534 --------- --------- --------- Cash and Cash Equivalents, End of Year $ 446 $ 458 $ 547 ========= ========= ========= Supplemental Disclosure of Cash Flow Information: Cash paid during the year for: Interest $ 4,064 $ 2,910 $ 3,189 Income taxes $ 507 $ 102 $ 63 The accompanying notes are an integral part of the consolidated financial statements 34 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 "Company"). The Company's investment in limited partnerships is accounted for on the proportionate consolidation method, whereby its share of the partnerships' assets, liabilities, revenues and expenses is included in the appropriate classification in the accompanying consolidated financial statements. Nature of Business The Company is engaged in the development, acquisition and production of oil and natural gas properties and the land contract drilling of oil and natural gas wells primarily in the Anadarko, Arkoma and South Texas Basins. These basins are located in Oklahoma, Texas, Kansas and Arkansas. Additional producing properties are located in Canada and other states, including New Mexico, Louisiana, North Dakota, Colorado, Wyoming, Montana, Alabama, Mississippi, Arkansas, Illinois and Nebraska. At December 31, 1998, the Company has an interest in 2,563 wells and served as operator of 524 of those wells. Land contract drilling of oil and natural gas wells is performed for a wide range of customers using the drilling rigs owned and operated by the Company. In 1998, 31 of the Company's 34 rigs were in operation. Drilling Contracts The Company recognizes revenues generated from "daywork" drilling contracts as the services are performed, which is similar to the percentage of completion method. For all contracts under which the Company bears the risk of completion of the wells ("footage" and "turnkey" drilling contracts), 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 the 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" drilling contracts which are still in process and are included in other current assets. Cash Equivalents and Short-Term Investments The Company 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. 35 Property and Equipment Drilling equipment, transportation equipment and other property and equipment are carried at cost. The Company provides for depreciation of drilling equipment on 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. The Company 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 the Company's 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 the Company to reduce the carrying value of its 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. 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, based on the estimated undiscounted future cash flow of the acquired entity. Net goodwill reported in other assets at December 31, 1998 and 1997 was $5,818,000 and $6,061,000, respectively with accumulated amortization at December 31, 1998 and 1997 of $264,000 and $20,000, respectively. Oil and Natural Gas Operations The Company 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. The Company's determination of its oil and natural gas reserves are reviewed annually by independent 36 petroleum engineers. The average composite rates used for depreciation, depletion and amortization ("DD&A") were $4.99, $4.49 and $3.90 per equivalent barrel in 1998, 1997 and 1996, respectively. The Company's 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 the Company's oil and natural gas properties. As discussed in Note 14, such estimates are imprecise. Changes in these estimates or declines in oil and natural gas prices could cause the Company in the near-term to reduce the carrying value of its 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 the Company has an interest or on properties in which a partnership, of which the Company is a general partner, has an interest. Accordingly, in 1998 and 1997 the Company recorded $437,000 and $314,000 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 1996. Limited Partnerships The Company's wholly owned subsidiary, Unit Petroleum Company, is a general partner in fourteen oil and natural gas limited partnerships sold privately and publicly. Certain of the Company's officers, directors and employees own interests in most of these partnerships. The Company shares in partnership revenues and costs in accordance with formulas prescribed in each limited partnership agreement. The partnerships also reimburse the Company 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. 37 Natural Gas Balancing The Company uses the sales method for recording natural gas sales. This method allows for recognition of revenue which may be more or less than the Company's share of pro-rata production from certain wells. Based upon the Company's 1998 average spot market natural gas price of $1.90 per Mcf, the Company estimates its balancing position to be approximately $4.6 million on under-produced properties and approximately $2.8 million on over-produced properties. The Company's policy is to expense its pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the Company's balancing position on wells in which the Company has imbalances are not material. Stock Based Compensation The Company applies APB Opinion 25 in accounting for its stock option plans. 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 the Company's grants in 1998, 1997 and 1996 no compensation expense has been recognized. As provided by Financial Accounting Standard No. 123 "Accounting for Stock-Based Compensation," the Company has disclosed the pro forma effects of recording compensation for such option grants based on fair value in Note 8 to the financial statements. Self Insurance The Company 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 the Company to concentrations of credit risk consist primarily of trade receivables with a variety of national and international oil and natural gas companies. The Company 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 the Company's customer base. In addition, at December 31, 1998 and 1997, the Company had a concentration of cash of $1.5 million and $0.3 million, respectively, with one bank. 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. 38 Earnings Per Share In the fourth quarter of 1997, the Company adopted Financial Accounting Standards Board Statement of Financial Accounting Standards No. 128, Earnings Per Share ("FAS 128"). Earnings per share amounts for all previous periods presented give effect to the application of FAS 128. 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). FAS 133 is effective for all fiscal quarters of fiscal years beginning after June 15, 1999 (January 1, 2000 for the Company). 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 the Company anticipates that, due to its limited use of derivative instruments, the adoption of FAS 133 will not have a significant effect on the Company's results of operations or its financial position. NOTE 2 - ACQUISITION OF DRILLING COMPANY - ---------------------------------------- On November 20, 1997, the Company 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. The acquisition is summarized as follows: (In thousands) Current assets net of current liabilities $ 2,072 Property and equipment 23,187 Goodwill 6,081 Deferred tax liability - long-term (7,490) --------- Total acquisition $ 23,850 ========= 39 NOTE 3 - EARNINGS PER SHARE - --------------------------- The following data shows the amounts used in computing earnings per share. For the Year Ended December 31, 1998 -------------------------------------- WEIGHTED INCOME SHARES PER-SHARE (NUMERATOR) (DENOMINATOR) AMOUNT ----------- ----------- ---------- 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, 1997 ------------------------------------- WEIGHTED INCOME SHARES PER-SHARE (NUMERATOR) (DENOMINATOR) AMOUNT ----------- ----------- ---------- 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 =========== =========== ========== 40 For the Year Ended December 31, 1996 -------------------------------------- WEIGHTED INCOME SHARES PER-SHARE (NUMERATOR) (DENOMINATOR) AMOUNT ----------- ----------- ---------- Basic earnings per common share $ 8,333,000 22,463,000 $ 0.37 ========== Effect of dilutive stock options - 302,000 ----------- ----------- Diluted earnings per common share $ 8,333,000 22,765,000 $ 0.37 =========== =========== ========== 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,: 1998 1997 1996 ----------- ---------- ---------- Options 191,000 2,500 161,500 =========== ========== ========== Average exercise price $ 8.60 $ 11.32 $ 8.60 =========== ========== ========== NOTE 4 - WARRANTS - ----------------- In 1987, the Company issued 2.873 million Units, consisting of three shares of the Company's common stock and one warrant, at a price of $10.375 per Unit. Each warrant entitled the holder to purchase one share of the Company's common stock at a price of $4.375. Prior to the warrants expiration on August 30, 1996, 2.86 million warrants were exercised providing $12.5 million in additional capital to the Company. 41 NOTE 5 - OTHER LONG-TERM LIABILITIES - ------------------------------------ Other long-term liabilities consisted of the following as of December 31, 1998 and 1997: 1998 1997 --------- --------- (In thousands) Natural gas purchaser prepayment $ 1,759 $ 2,206 Separation benefit plan 1,012 - Rig acquisition 331 800 --------- --------- 3,102 3,006 Less current portion 801 727 --------- --------- $ 2,301 $ 2,279 ========= ========= In March 1988, the Company entered into a settlement agreement with a natural gas purchaser. During early 1991, the Company and the natural gas purchaser superseded the original agreement with a new settlement agreement effective retroactively to January 1, 1991. Under these settlement agreements ("Settlement Agreement"), the Company has a prepayment balance of $1.8 million at December 31, 1998 representing proceeds received from the purchaser as prepayment for natural gas. This amount is net of natural gas recouped and net of certain amounts disbursed to other owners (such owners, collectively with the Company are referred to as the "Committed Interest") for their proportionate share of the prepayments. At December 31, 1997, the Settlement Agreement and the natural gas purchase contracts which were subject to the Settlement Agreement terminated. The December 31, 1997 Prepayment Balance of $2.2 million became payable in equal annual payments over a five year period. The first payment of $441,000 was due and paid on June 1, 1998. The Company has other long-term liabilities of $1,343,000, consisting of $331,000 from the December 9, 1997 acquisition of a Mid-Continent U-36- A, 650 horsepower rig plus additional spare rig equipment and $1,012,000 from the liability accrued for the Company's Separation Benefit Plan. The debt for rig equipment is payable over a maximum of three years from the closing date of the acquisition. 42 NOTE 6 - LONG-TERM DEBT - ------------------------ Long-term debt consisted of the following as of December 31, 1998 and 1997: 1998 1997 --------- --------- (In thousands) Revolving credit and term loan, with interest at December 31, 1998 and 1997 of 6.3 percent and 7.3 percent, respectively $ 68,900 $ 49,100 Notes payable for Hickman Drilling Company acquisition with interest at December 31, 1998 and 1997 of 7.8 percent and 8.5 percent, respectively 5,000 5,000 --------- --------- 73,900 54,100 Less current portion 1,000 - --------- --------- Total long-term debt $ 72,900 $ 54,100 ========= ========= At December 31, 1998, the Company's loan agreement ("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, 1998 was $85 million. The Loan Value under the revolving credit facility is subject to a semi-annual redetermination calculated as the sum of a percentage of the discounted future value of the Company's oil and natural gas reserves, as determined by the banks, plus the greater of (i) 50 percent of the appraised value of the Company'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. 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 .75 to 1.25 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 plus .25 percent or the Libor rate plus 1.0 to 1.5 percent depending on the level of debt as a percentage of the total borrowing base. 43 At the Company'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 Company may not pay in part or in whole the outstanding principal balance of the note to which such Libor Rate option applies. Borrowings under the Prime Rate option may be paid anytime in part or in whole without premium or penalty. The Company 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. Virtually all of the Company's drilling rigs are collateral for such indebtedness and the balance of the Company'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 the Company 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 the Company 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 the Company or any of its subsidiaries, except in favor of its banks. The Loan Agreement also requires that the Company 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, the Company completed its acquisition of Hickman Drilling Company. In association with this acquisition, the Company 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. Estimated annual principal payments under the terms of all long-term liabilities and debt from 1999 through 2003 are $1,801,000, $1,484,000, $1,440,000, $14,837,000 and $23,967,000. Based on the borrowing rates currently available to the Company for debt with similar terms and maturities, long-term debt at December 31, 1998 approximates its fair value. 44 NOTE 7 - INCOME TAXES - --------------------- A reconciliation of the income tax expense, computed by applying the federal statutory rate to pre-tax income to the Company's effective income tax expense is as follows: 1998 1997 1996 -------- -------- -------- (In thousands) Income tax expense computed by applying the statutory rate $ 1,271 $ 6,073 $ 4,545 State income tax, net of federal 150 733 499 Goodwill and other 72 (69) (10) -------- -------- -------- Income tax expense (benefit) $ 1,493 $ 6,737 $ 5,034 ======== ======== ======== Deferred tax assets and liabilities are comprised of the following at December 31, 1998 and 1997: 1998 1997 --------- --------- (In thousands) Deferred tax assets: Allowance for losses $ 1,680 $ 1,348 Net operating loss carryforwards 12,541 15,819 Statutory depletion carryforward 2,260 2,260 Investment tax credit carryforward 530 1,552 Alternative minimum tax credit carryforward 431 167 --------- --------- Gross deferred tax assets 17,442 21,146 Valuation allowance (530) (1,552) Deferred tax liability- Depreciation, depletion and amortization (35,495) (37,154) --------- --------- Net deferred tax liability $(18,583) $(17,560) ========= ========= 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 1998. 45 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, 1998, the Company has net operating loss carryforwards for regular tax purposes of approximately $33,003,000 and net operating loss carryforwards for alternative minimum tax purposes of approximately $19,953,000 which expire in various amounts from 2000 to 2011. The Company has investment tax credit carryforwards of approximately $530,000 which expire from 1999 to 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 8 - 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, the Company'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. No shares were issued under the Plan in 1998, 1997 or 1996. On December 22, 1998, the Board of Directors approved a stock bonus of 87,376 shares of common stock to be issued on January 4, 1999 for payment of the Company's year end bonuses. The Company 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. 46 Activity pertaining to the Stock Option Plan is as follows: WEIGHTED NUMBER AVERAGE OF EXERCISE SHARES PRICE --------- -------- Outstanding at January 1, 1996 865,600 $ 2.23 Granted 149,500 8.75 Exercised (371,200) 1.59 Canceled (7,100) 2.92 --------- -------- Outstanding at December 31, 1996 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 226,000 3.96 Exercised (21,300) 2.71 Canceled (10,500) 7.05 --------- -------- Outstanding at December 31, 1998 768,360 $ 4.19 ========= ======== OUTSTANDING OPTIONS -------------------------------------- WEIGHTED WEIGHTED NUMBER AVERAGE AVERAGE EXERCISE OF REMAINING EXERCISE PRICES SHARES CONTRACTUAL LIFE PRICE ---------------------------------------------------------- $ 2.37 - $ 4.00 614,860 5.7 years $3.07 $ 7.25 - $11.32 153,500 8.1 years $8.67 EXERCISABLE OPTIONS ----------------------- WEIGHTED NUMBER AVERAGE EXERCISE OF EXERCISE PRICES SHARES PRICE ----------------------------------------- $ 2.37 - $ 4.00 374,660 $2.68 $ 8.00 - $11.32 52,000 $8.76 Options for 427,000, 383,000 and 375,000 shares were exercisable with weighted average exercise prices of $3.42, $3.01 and $2.64 at December 31, 1998, 1997 and 1996, respectively. 47 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 the Company's common stock may be issued upon exercise of the stock options. On the first business day following each annual meeting of stockholders of the Company, each person who is then a member of the Board of Directors of the Company and who is not then an employee of the Company 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. Activity pertaining to the Directors' Plan is as follows: WEIGHTED NUMBER AVERAGE OF EXERCISE SHARES PRICE -------- -------- Outstanding at January 1, 1996 42,500 $ 2.96 Granted 12,500 6.88 -------- -------- Outstanding at December 31, 1996 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 ======== ======== OUTSTANDING AND EXERCISABLE OPTIONS --------------------------------------- WEIGHTED WEIGHTED NUMBER AVERAGE AVERAGE EXERCISE OF REMAINING EXERCISE PRICES SHARES CONTRACTUAL LIFE PRICE ---------------------------------------------------------- $ 1.75 - $ 3.75 35,000 4.9 years $ 3.03 $ 6.87 - $ 9.00 37,500 8.3 years $ 8.28 48 The Company applies APB Opinion 25 in accounting for its Stock Option Plan and Non-Employee Director's Stock Option Plan. Accordingly, based on the nature of the Company's grants of options, no compensation cost has been recognized in 1998, 1997 and 1996. 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: 1998 1997 1996 ------- ------- ------- Net Income (In thousands): As reported $ 2,246 $11,124 $ 8,333 ======= ======= ======= Pro forma $ 1,933 $10,748 $ 8,244 ======= ======= ======= Basic Earnings per Share: As reported $ .09 $ .46 $ .37 ======= ======= ======= Pro forma $ .08 $ .44 $ .37 ======= ======= ======= Diluted Earnings per Share: As reported $ .09 $ .45 $ .36 ======= ======= ======= Pro forma $ .07 $ .43 $ .36 ======= ======= ======= The fair value of each option granted is estimated using the Black- Scholes model. The Company's stock volatility was 0.53, 0.52 and 0.51 in 1998, 1997 and 1996, respectively, based on previous stock performance. Dividend yield was estimated to remain at zero with a risk free interest rate of 4.95, 5.80 and 6.55 percent in 1998, 1997 and 1996, 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 1998, 1997 and 1996 under the Stock Option Plan were $527,000, $136,000 and $753,000, respectively, and under the Non-Employee Stock Option Plan were $71,000, $74,000 and $56,000, respectively. Under the Company'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 the Company in full or on a partial basis. The Company made discretionary contributions under the plan of 46,892, 23,892 and 44,686 shares of common stock and recognized expense of $536,000, $329,000 and $268,000 in 1998, 1997 and 1996, respectively. 49 The Company 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 the Company's obligation under the Deferral Plan at December 31, 1998 and 1997 totaled $1,035,000 and $752,000, respectively. The Company recognizes payroll expense and records a liability at the time of deferral. Effective January 1, 1997, the Company adopted a separation benefit plan ("Separation Plan"). The Separation Plan allows eligible employees whose employment with the Company 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 the Company 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 the Company in exchange for receiving the separation benefits. On October 28, 1997, the Company adopted a Separation Benefit Plan for Senior Management ("Senior Plan"). The Senior Plan provides certain officers and key executives of the Company 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. The Company recognized expense of $577,000 and $466,000 in 1998 and 1997, respectively, for benefits associated with anticipated payments from both separation plans. NOTE 9 - TRANSACTIONS WITH RELATED PARTIES - ------------------------------------------ The Company formed private limited partnerships (the "Partnerships") with certain qualified employees, officers and directors from 1984 through 1998, with a subsidiary of the Company 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 the Company in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with the Company in most drilling operations and most producing property acquisitions commenced by the Company for its own account during the period from the formation of the Partnership through December 31 of each year. Amounts received in the years ended December 31 from both public and private Partnerships for which the Company is a general partner are as follows: 1998 1997 1996 -------- -------- -------- (In thousands) Contract drilling $ 180 $ 135 $ 37 Well supervision and other fees $ 415 $ 384 $ 349 General and administrative expense reimbursement $ 133 $ 119 $ 105 50 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 the Company paid the Partnerships, for which the Company or a subsidiary is the general partner, $21,000, $32,000 and $31,000 during the years ended December 31, 1998, 1997 and 1996, respectively, for purchases of natural gas production. During 1997 and 1996 a bank owned by one of the Company's former Directors was a participant in the Company's Loan Agreement. The bank's pro rata share of the Company's line of credit was limited to an amount not to exceed $1.5 million. NOTE 10 - SHAREHOLDER RIGHTS PLAN - -------------------------------- The Company 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 the Company 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 the Company one one- hundredth of a newly issued share of Series A Participating Cumulative Preferred Stock at a price subject to adjustment by the Company 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 the Company learns that an acquiring person (as defined in the Plan) has acquired 15 percent or more of the outstanding common stock of the Company or 10 business days after the commencement of a tender offer which would result in a person owning 15 percent or more of such shares. The Company 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 the Company 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 the Company. 51 NOTE 11 - COMMITMENTS AND CONTINGENCIES - --------------------------------------- The Company leases office space under the terms of operating leases expiring through January 31, 2002. Future minimum rental payments under the terms of the leases are approximately $372,000, $104,000, $73,000 and $7,000 in 1999, 2000, 2001 and 2002, respectively. No minimum rental payments are due in 2003. Total rent expense incurred by the Company was $412,000, $373,000 and $323,000 in 1998, 1997 and 1996, respectively. The Company had letters of credit supported by its Loan Agreement totaling $210,000 at December 31, 1998. The Company 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 $950,000 at December 31, 1998). 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 the Company 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. The Company made repurchases of $15,000 and $30,000 in 1998 and 1996, respectively, for such limited partners' interests and did not make any such repurchases in 1997. The Company is a party to various legal proceedings arising in the ordinary course of its business none of which, in the Company's opinion, will result in judgements which would have a material adverse effect on the Company. 52 NOTE 12 - INDUSTRY SEGMENT INFORMATION - -------------------------------------- In 1998, the Company adopted Statement of Financial Accounting Standard No. 131 "Disclosures about Segments of an Enterprise and Related Information." The Company 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). The Company evaluates the performance of its operating segments based on operating income, which is defined as operating revenues less operating expenses and depreciation, depletion and amortization. The Company has natural gas production in Canada which is not significant. 1998 1997 1996 --------- --------- --------- (In thousands) Revenues: Contract drilling $ 53,528 $ 46,199 $ 28,819 Oil and natural gas 39,703 45,581 43,013 Other 106 84 238 --------- --------- --------- Total revenues $ 93,337 $ 91,864 $ 72,070 ========= ========= ========= Operating Income (1): Contract drilling $ 4,033 $ 5,564 $ 1,616 Oil and natural gas 9,306 19,755 18,797 --------- --------- --------- Total operating income 13,339 25,319 20,413 General and administrative (4,891) (4,621) (4,122) Expense Interest expense (4,815) (2,921) (3,162) Other income (expense)- net 106 84 238 --------- --------- --------- Income before income taxes $ 3,739 $ 17,861 $ 13,367 ========= ========= ========= 53 1998 1997 1996 --------- --------- --------- (In thousands) Identifiable Assets (2): Contract drilling $ 69,147 $ 66,188 $ 24,500 Oil and natural gas 150,718 132,332 110,207 --------- --------- --------- Total identifiable assets 219,865 198,520 134,707 Corporate assets 3,199 3,977 3,286 --------- --------- --------- Total assets $223,064 $202,497 $137,993 ========= ========= ========= Capital Expenditures: Contract drilling $ 11,485 $ 35,193 $ 9,910 Oil and natural gas 38,409 33,525 25,644 Other 216 1,464 989 --------- --------- --------- Total capital expenditures $ 50,110 $ 70,182 $ 36,543 ========= ========= ========= Depreciation, Depletion and Amortization: Contract drilling $ 5,766 $ 4,216 $ 2,944 Oil and natural gas 16,069 12,625 10,807 Other 351 358 328 --------- --------- --------- Total depreciation, depletion and amortization $ 22,186 $ 17,199 $ 14,079 ========= ========= ========= (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 the Company's operations in each industry segment. Corporate assets are principally cash and cash equivalents, short-term investments, corporate leasehold improvements, furniture and equipment. 54 NOTE 13 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) - -------------------------------------------------------------- Summarized quarterly financial information for 1998 and 1997 is as follows: Three Months Ended ------------------------------------------------ MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 --------- --------- --------- ------------ (In thousands except per share amounts) Year ended December 31, 1998: Revenues $ 24,249 $ 26,054 $ 23,627 $ 19,407 ========= ========= ========= ========= Gross profit(1) $ 3,471 $ 4,450 $ 3,537 $ 1,881 ========= ========= ========= ========= Income before income taxes $ 1,163 $ 2,053 $ 1,136 $ (613) ========= ========= ========= ========= Net Income $ 725 $ 1,235 $ 654 $ (368) ========= ========= ========= ========= Earnings per common share: Basic (2) $ .03 $ .05 $ .03 $ (.01) ========= ========= ========= ========= Diluted (2) $ .03 $ .05 $ .03 $ (.01) ========= ========= ========= ========= Year ended December 31, 1997: Revenues $ 24,322 $ 19,806 $ 21,585 $ 26,151 ========= ========= ========= ========= Gross profit(1) $ 7,970 $ 4,161 $ 5,227 $ 7,961 ========= ========= ========= ========= Income before income taxes $ 6,219 $ 2,299 $ 3,409 $ 5,934 ========= ========= ========= ========= Net Income $ 3,874 $ 1,432 $ 2,121 $ 3,697 ========= ========= ========= ========= Earnings per common share: Basic $ .16 $ .06 $ .09 $ .15 ========= ========= ========= ========= Diluted (2) $ .16 $ .06 $ .09 $ .15 ========= ========= ========= ========= (1) Gross profit excludes other revenues, general and administrative expense and interest expense. 55 (2) Due to the effect of price changes of the Company'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. NOTE 14 - OIL AND NATURAL GAS INFORMATION (UNAUDITED) - ----------------------------------------------------- The capitalized costs at year end and costs incurred during the year were as follows: USA CANADA TOTAL ---------- -------- ---------- (In thousands) 1998: Capitalized costs: Proved properties $ 261,299 $ 480 $ 261,779 Unproved properties 9,900 281 10,181 ---------- -------- ---------- 271,199 761 271,960 Less 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 ========== ======== ========== 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 ========== ======== ========== 56 USA CANADA TOTAL ---------- --------- ---------- (In thousands) 1996: Capitalized costs: Proved properties $ 195,528 $ 480 $ 196,008 Unproved properties 4,602 - 4,602 ---------- --------- ---------- 200,130 480 200,610 Less accumulated depreciation, depletion, amortization and impairment (102,463) (389) (102,852) ---------- --------- ---------- Net capitalized costs $ 97,667 $ 91 $ 97,758 ========== ========= ========== Cost incurred: Unproved properties $ 1,640 $ - $ 1,640 Producing properties 2,338 - 2,338 Exploration 1,501 - 1,501 Development 20,150 15 20,165 ---------- --------- ---------- Total costs incurred $ 25,629 $ 15 $ 25,644 ========== ========= ========== 57 The results of operations for producing activities are provided below. USA CANADA TOTAL --------- -------- --------- (In thousands) 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 ========= ======== ========= 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 ========= ======== ========= 1996: Revenues $ 40,432 $ 60 $ 40,492 Production costs (11,195) (14) (11,209) Depreciation, depletion and amortization (10,723) (11) (10,734) --------- -------- --------- 18,514 35 18,549 Income tax expense (6,986) (15) (7,001) --------- -------- --------- Results of operations for producing activities (excluding corporate overhead and financing costs) $ 11,528 $ 20 $ 11,548 ========= ======== ========= 58 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: USA CANADA TOTAL ---------------- --------------- ---------------- NATURAL NATURAL NATURAL OIL GAS OIL GAS OIL GAS BBLS MCF BBLS MCF BBLS MCF ------- -------- ------- ------- ------- -------- (In thousands) 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 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 59 USA CANADA TOTAL ---------------- --------------- ---------------- NATURAL NATURAL NATURAL OIL GAS OIL GAS OIL GAS BBLS MCF BBLS MCF BBLS MCF ------- -------- ------- ------- ------- -------- (In thousands) 1996: Proved developed and undeveloped reserves: Beginning of year 5,428 107,950 - 778 5,428 108,728 Revision of previous estimates (387) (3,822) - 26 (387) (3,796) Extensions, discoveries and other additions 718 34,625 - - 718 34,625 Purchases of minerals in place 67 3,036 - - 67 3,036 Sales of minerals in place (43) (407) - - (43) (407) Production (579) (12,974) - (51) (579) (13,025) ------- -------- ----- ----- ------- -------- End of Year 5,204 128,408 - 753 5,204 129,161 ======= ======== ===== ===== ======= ======== Proved developed reserves: Beginning of year 4,697 94,975 - 350 4,697 95,325 End of year 4,509 107,536 - 326 4,509 107,862 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. The Company utilizes Ryder Scott Company, independent petroleum consultants, to review the Company's reserves as prepared by the Company's reservoir engineers. Proved reserves are those quantities which, upon analysis of geolog- ical and engineering data, appear with reasonable certainty to be recov- erable in the future from known oil and natural gas reservoirs under exist- ing 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 expendi- ture 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 escala- 60 tions or de-escalations have been considered, the results are not neces- sarily indicative of the estimated fair market value of estimated proved reserves nor of estimated future cash flows. 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: USA CANADA TOTAL ---------- -------- ---------- (In thousands) 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 ========== ======== ========== 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 ========== ======== ========== 61 USA CANADA TOTAL ---------- -------- ---------- (In thousands) 1996: Future cash flows $ 626,945 $ 2,735 $ 629,680 Future production and development costs (171,749) (339) (172,088) Future income tax expenses (125,540) (1,422) (126,962) ---------- -------- ---------- Future net cash flows 329,656 974 330,630 10% annual discount for estimated timing of cash flows (129,610) (368) (129,978) ---------- -------- ---------- Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 200,046 $ 606 $ 200,652 ========== ======== ========== 62 The principal sources of changes in the standardized measure of discounted future net cash flows were as follows: USA Canada Total ---------- -------- ---------- (In thousands) 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 ========== ======== ========== 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 ========== ======== ========== 63 USA CANADA TOTAL ---------- -------- ---------- (In thousands) 1996: Sales and transfers of oil and natural gas produced, net of production costs $ (29,237) $ (46) $ (29,283) Net changes in prices and production costs 92,541 738 93,279 Revisions in quantity estimates and changes in production timing (13,390) 58 (13,332) Extensions, discoveries and improved recovery, less related costs 69,942 - 69,942 Purchases of minerals in place 5,821 - 5,821 Sales of minerals in place (514) - (514) Accretion of discount 12,101 71 12,172 Net change in income taxes (44,039) (470) (44,509) Other - net 3,998 (60) 3,938 ---------- -------- ---------- Net change 97,223 291 97,514 Beginning of year 102,823 315 103,138 ---------- -------- ---------- End of year $ 200,046 $ 606 $ 200,652 ========== ======== ========== The Company's SMOG and changes therein were determined in accordance with Statement of Financial Accounting Standards No. 69. Certain infor- mation 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. 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. 64 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 the Company's properties. The future income tax expenses also give effect to permanent differences and tax credits and allowances relating to the Company'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. In early 1999, the oil and natural gas industry has experienced a downturn in natural gas prices. The Company's reserves were determined at December 31, 1998 using an oil and natural gas price of $11.10 per barrel and $2.08 per Mcf. During February 1999, the oil and natural gas prices received by the Company were approximately $11.62 and $1.74, respectively. The decreases in natural gas prices would have a significant effect on the SMOG value of the Company's reserves at December 31, 1998 and would result in a provision to reduce the carrying value of oil and natural gas properties of approximately $22 million before taxes. 65 REPORT OF INDEPENDENT ACCOUNTANTS The Shareholders and Board of Directors Unit Corporation In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, stockholders' equity and cash flows present fairly in all material respects, the financial position of Unit Corporation and its subsidiaries at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. 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 generally accepted auditing standards 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 23, 1999 66 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 infor- mation concerning each executive officer of the Company. 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 71 Chairman of the Board, Chief Executive Officer and Director John G. Nikkel 64 President, Chief Operating Officer and Director Earle Lamborn 64 Senior Vice President, Drilling and Director Philip M. Keeley 57 Senior Vice President, Exploration and Production Larry D. Pinkston 44 Vice President, Treasurer and Chief Financial Officer Mark E. Schell 41 General Counsel and Secretary ________ Mr. Kirchner, a co-founder of the Company, 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. Mr. Nikkel joined the Company 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. 67 Mr. Lamborn has been actively involved in the oil field for over 45 years, joining the Company'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 the Company 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 the Company 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 the Company in January of 1987, as its Secretary and General Counsel. From 1979 until joining the Company, 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 incorpo- rated by reference from the Company's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company's 1999 annual meeting of stockholders. Item 11. Executive Compensation - --------------------------------- Information required by this item is incorporated by reference from the Company's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company's 1999 annual meeting of stockholders. Item 12. Security Ownership of Certain Beneficial Owners and Management - ------------------------------------------------------------------------ Information required by this item is incorporated by reference from the Company's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company's 1999 annual meeting of stockholders. 68 Item 13. Certain Relationships and Related Transactions - -------------------------------------------------------- Information required by this item is incorporated by reference from the Company's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company's 1999 annual meeting of stockholders. 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 1997 Consolidated Statements of Operations for the years ended December 31, 1998, 1997 and 1996 Consolidated Statements of Changes in Shareholders' Equity for the years ended December 31, 1998, 1997 and 1996 Consolidated Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996 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, 1998, 1997 and 1996: 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 Certificate of Ownership and Merger of the Company and Unit Drilling Co., dated February 22, 1979 (filed as an Exhibit to the Company's Registration Statement No. 2-63702, which is incorporated herein by reference). 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 the Company's Form 8-K dated November 21, 1997, which is incorporated herein by reference). 69 3.1.1 Certificate of Incorporation (filed as Exhibit 3.2 to the Company's Registration Statement on Form S-4 as S.E.C. File No. 33-7848, which is incorporated herein by reference). 3.1.2 Certificate of Amendment of Certificate of Incorporation dated July 21, 1988 (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1989, which is incorporated herein by reference). 3.1.3 Restated Certificate of Incorporation of Unit Corporation dated February 2, 1994 (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1993, which is incorporated herein by reference). 3.2.1 By-Laws (filed as Exhibit 3.5 to the Company's Registration Statement of Form S-4 as S.E.C. File No. 33-7848, which is incorporated herein by reference). 3.2.2 Amended and Restated By-Laws, dated June 29, 1988 (filed as an Exhibit to the Company's Annual Report under cover of Form 10- K for the year ended December 31, 1989, 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 the Company's Form 8-K dated November 21, 1997, which is incorporated herein by reference). 4.2.1 Form of Warrant Agreement between the Company and the Warrant Agent (filed as Exhibit 4.1 to the Company's Registration statement on Form S-2 as S.E.C. File No. 33-16116, which is incorporated herein by reference). 4.2.2 Form of Warrant (filed as Exhibit 4.3 to the Company's Registration Statement of Form S-2 as S.E.C. File No. 33- 16116, which is incorporated herein by reference). 4.2.3 Form of Common Stock Certificate (filed as Exhibit 4.2 on Form S-2 as S.E.C. File No. 33-16116, which is incorporated herein by reference). 4.2.4 First Amendment to Warrant Agreement (filed as an Exhibit to the Company's Quarterly Report under cover of Form 10-Q for the quarter ended March 31, 1992, which is incorporated herein by reference). 4.2.5 Second Amendment to Warrant Agreement (filed as an Exhibit to the Company's Quarterly Report under cover of Form 10-Q for the quarter ended March 31, 1994, which is incorporated herein by reference). 4.2.6 Rights Agreement dated as of May 19, 1995 between the Company and Chemical Bank, as Rights Agent (filed as Exhibit 1 to the Company's Form 8-A filed May 23, 1995, File No. 1-92601 and incorporated herein by reference). 70 10.1.14 Amended and Restated Credit Agreement dated as of January 17, 1992 by and between Unit Corporation and Bank of Oklahoma N.A., F&M Bank and Trust Company, Fourth National Bank of Tulsa and Western National Bank of Tulsa (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1991, which is incorporated herein by reference). 10.1.16 First Amendment to Amended and Restated Credit Agreement dated as of May 1, 1992, by and between Unit Corporation and Bank of Oklahoma, N.A., F&M Bank and Trust Company, Fourth National Bank of Tulsa, and Western National Bank of Tulsa (filed as an Exhibit to the Company's Quarterly Report under cover of Form 10-Q for the quarter ended June 30, 1992, which is incorporated herein by reference). 10.1.17 Second Amendment to Amended and Restated Credit Agreement, dated March 3, 1993 and effective as of March 1, 1993, by and between Unit Corporation and Bank of Oklahoma, N.A., F&M Bank and Trust Company, Fourth National Bank of Tulsa, and Western National Bank of Tulsa (filed as an Exhibit to the Company's Quarterly Report under cover of Form 10-Q for the quarter ended March 31, 1993, which is incorporated herein by reference). 10.1.18 Third Amendment to Amended and Restated Credit Agreement effective as of March 31, 1994, by and between Unit Corporation and Bank of Oklahoma, N.A., F&M Bank and Trust Company, Bank IV, Oklahoma, N.A. and American National Bank and Trust Company of Shawnee (filed as an Exhibit to the Company's Quarterly Report under cover of Form 10-Q for the quarter ended March 31, 1994, which is incorporated herein by reference). 10.1.19 Fourth Amendment to Amended and Restated Credit Agreement dated as of December 12, 1994, by and between Unit Corporation and Bank of Oklahoma, N.A., F&M Bank and Trust Company, Bank IV, Oklahoma, N.A. and American National Bank and Trust Company of Shawnee (filed as an Exhibit in Form 8-K dated December 15, 1994, which is incorporated herein by reference). 10.1.20 Loan Agreement dated August 3, 1995 (filed as an Exhibit to the Company's Quarterly Report under cover of Form 10-Q for the quarter ended June 30, 1995, which is incorporated herein by reference). 10.1.21 First Amendment to the Loan Agreement effective as of September 4, 1996, by and between Unit Corporation and Bank of Oklahoma, N.A., The First National Bank of Boston, Bank IV Oklahoma, N.A. and American National Bank and Trust Company of Shawnee (filed as an Exhibit to the Company's Quarterly Report under cover of Form 10-Q for the quarter ended September 30, 1996, which is incorporated herein by reference). 71 10.1.22 Second Amendment to the Loan Agreement effective as of December 16, 1996 by and between Unit Corporation and Bank of Oklahoma, N.A., The First National Bank of Boston, Boatman's National Bank of Oklahoma and American National Bank and Trust Company of Shawnee (filed herewith). 10.1.23 Loan Agreement dated April 30, 1998 (filed as an Exhibit to the Company's Quarterly Report under cover of Form 10-Q for the quarter ended June 30, 1998, 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). 10.2.11 Unit 1984 Employee Oil and Gas Program Agreement of Limited Partnership (filed as an Exhibit 3.1 to Unit 1984 Employee Oil and Gas Program's Registration Statement of Form S-1 as S.E.C. File No. 2-89678, which is incorporated herein by reference). 10.2.12 Unit 1985 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit 3.1 to Unit 1985 Employee Oil and Gas Limited Partnership's Registration Statement on Form S-1 as S.E.C. File No. 2-95068, which is incorporated herein by reference). 10.2.13 Unit 1986 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit 10.11 to the Company's Registration Statement on Form S-4 as S.E.C. File No. 33-7848, which is incorporated herein by reference). 10.2.14 Unit 1987 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1989, which is incorporated herein by reference). 10.2.15 Unit 1988 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1989, which is incorporated herein by reference). 10.2.16 Unit 1989 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1989, which is incorporated herein by reference). 10.2.17 Unit 1990 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1990, which is incorporated herein by reference). 72 10.2.18 Unit 1991 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to the Company'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 the Company'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 the Company'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 the Company'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 the Company'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) 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 the Company'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 the Company'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 the Company'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 the Company'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 the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1995, which is incorporated herein by reference). 73 10.2.30* Separation Benefit Plan of Unit Corporation and Participating Subsidiaries (filed as an Exhibit to the Company's Annual Report under the cover of Form 10-K for the year ended December 31, 1996). 10.2.31 Unit 1997 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to the Company's Annual Report under the cover of Form 10-K for the year ended December 31, 1996). 10.2.32 Unit Corporation Separation Benefit Plan for Senior Management(filed as an Exhibit to the Company'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 the Company'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 herewith). 10.5 Acquisition and Development Agreement, dated September 26, 1991, between Registrant and Municipal Energy Agency of Nebraska (filed as an Exhibit to Form 8-K dated September 30, 1991, which is incorporated herein by reference). 10.6 Purchase and Sale Agreement, dated May 22, 1992, between Esco Exploration, Inc. and Aleco Production Company (as "Seller") and Unit Petroleum Company (a "Buyer") and Helmerich & Payne, Inc. (a "Buyer") (filed as an Exhibit to Form 8-K dated May 21, 1992, which is incorporated herein by reference). 10.7 Asset Purchase Agreement, dated as of November 28, 1994, between the Registrant and Patrick Petroleum Corp of Michigan and American National Petroleum Company (filed as an Exhibit to Form 8-K dated December 15, 1994, which is incorporated herein by reference). 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: No reports under Form 8-K were filed during the quarter ended December 31, 1998. 74 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, 1998 $ 354 $ - $ 80 $ 274 ======== ======== ======== ======== Year ended December 31, 1997 $ 104 $ 250 $ - $ 354 ======== ======== ======== ======== Year ended December 31, 1996 $ 116 $ - $ 12 $ 104 ======== ======== ======== ======== Deferred Tax Asset Valuation Allowance: Balance Balance at at beginning end of Description of period Additions Deductions period ----------- --------- -------- --------- -------- (In thousands) Year ended December 31, 1998 $ 1,552 $ - $ 1,022 $ 530 ======== ======== ======== ======== Year ended December 31, 1997 $ 3,530 $ - $ 1,978 $ 1,552 ======== ======== ======== ======== Year ended December 31, 1996 $ 3,530 $ - $ - $ 3,530 ======== ======== ======== ======== 75 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 17, 1999 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 17th day of March, 1997. 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 76 EXHIBIT INDEX ----------------------- Exhibit No. Description Page ------ ----------------------------------------------- ----- 10.2.34 Unit 1999 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership. 21 Subsidiaries of the Registrant. 23 Consent of Independent Accountants. 27 Financial Data Schedules. 77
Date: 3/18/1999 Form: 10-K - Annual Report
