10-K 1 edg10k.txt 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-K (X) ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (Fee Required) For the fiscal year ended March 31, 2002 or ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 0-12757 TMBR/SHARP DRILLING, INC. (Exact name of registrant as specified in its charter) TEXAS 75-1835108 (State of Incorporation) (I.R.S. Employer Identification No.) 4607 WEST INDUSTRIAL BLVD., MIDLAND, TEXAS 79703 (Address of principal executive offices) (Zip Code) Registrant's telephone number (area code) (915) 699-5050 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: Common Stock, $.10 Par Value (Title of Class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10- K or any amendment to this Form 10-K. (X) The aggregate market value of voting stock held by nonaffiliates of the registrant at June 7, 2002 was approximately $57,486,671. At June 7, 2002, there were 5,400,186 shares of the Registrant's Common Stock outstanding. The information required by Items 11, 12 and 13 of Part III of this Form 10-K are incorporated by reference from the registrant's Proxy Statement to be filed pursuant to Regulation 14A with respect to the registrant's Annual Meeting to be held in August, 2002. 2 TMBR/SHARP DRILLING, INC. FORM 10-K TABLE OF CONTENTS Part I Page Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . 4 Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . 25 Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . 26 Item 4. Submission of Matters to a Vote of Security Holders. . . . . . . . . . . . . . . . . . 26 Part II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters . . . . . . . . . . 26 Item 6. Selected Financial Data . . . . . . . . . . . . . . . . 28 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . 29 Item 7A. Quantitative and Qualitative Disclosure About Market Risk . . . . . . . . . . . . . . . . . . 37 Item 8. Financial Statements and Supplementary Data . . . . . . 38 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. . . . . . . . 66 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 and signatures Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . . . . . . . . . . . 69 Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 -2- 3 PART I Some statements contained in this Form 10-K report are "forward-looking statements". All statements other than statements of historical facts included in this report, including, without limitation, statements regarding planned capital expenditures, the availability of capital resources to fund capital expenditures, estimates of proved reserves, the Company's financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. Forward-looking statements can be identified by the use of forward-looking terminology like "may," "will," "expect," "intend,""anticipate," "estimate," "continue," "present value," "future" or "reserves" or other variations of comparable terminology. The Company believes the assumptions and expectations reflected in these forward- looking statements are reasonable. However, no assurance can be given that the Company's expectations will prove to be correct or that it will be able to take any actions that are presently planned. All of these statements involve assumptions of future events and risks and uncertainties. Risks and uncertainties associated with forward-looking statements include, but are not limited to: fluctuations in prices of oil and gas; future capital requirements and availability of financing; risks associated with the drilling of wells; competition; general economic conditions; governmental regulations; receipt of amounts owed to the Company by purchasers of its production and counterparties to its hedging contracts; and hedging activities. For these and other reasons, actual results may differ materially from those projected or implied. Undue reliance should not be placed on forward- looking statements and projections of any future results should not be based on such statements. Before investing in the Company's common stock, one should be aware that there are various risks associated with an investment. Some of these described in other sections of this annual report and under the Risk Factors section beginning on page 18. -3- 4 Item 1. BUSINESS General TMBR/Sharp Drilling, Inc. (the "Company") was incorporated under the laws of Texas in October, 1982 under the name TMBR Drilling, Inc. In August, 1986, the Company changed its name to TMBR/Sharp Drilling, Inc. The principal executive offices of the Company are located at 4607 West Industrial Blvd., Midland, Texas, 79703 and its telephone number is (915) 699-5050. The Company is engaged in two lines of business, which include the domestic onshore contract drilling of oil and gas wells, and the acquisition, exploration for, development, production and sale of oil and natural gas. The Company provides domestic onshore contract drilling services to major and independent oil and gas companies. The Company focuses its operations in the Permian Basin of west Texas and eastern New Mexico. In addition to its drilling rigs, the Company provides the crews and most of the ancillary equipment used in the operation of its drilling rigs. Rig utilization for the fiscal year ended March 31, 2002 was approximately 67% compared to 68% for the year ended March 31, 2001. The Company owns 18 drilling rigs. At June 7, 2002, 1 rig was operating on behalf of the Company for its own account, 10 were operating for non- affiliated oil producers, and 7 were "stacked" (non-operating). All of the Company's rigs are operational and actively marketed in the Permian Basin of west Texas and eastern New Mexico. The Company markets its contract drilling services to both major oil companies and independent oil producers. The depth capabilities of the Company's rigs range from 8,500 feet to 30,000 feet. An onshore drilling rig consists of engines, drawworks, mast, pumps to circulate drilling fluids, blowout preventers, the drillstring and related equipment. The size and type of rig utilized for each drilling project depends upon the location of the well, the well depth and equipment requirements specified in the drilling contract, among other factors. The Company believes it has established a reputation for reliability, high quality equipment and well-trained crews. The Company continually seeks to modify and upgrade its equipment to maximize the performance and capabilities of its drilling rig fleet, which the Company believes provides it with a competitive advantage. The Company has the capability to design, repair and modify its drilling rig fleet from its principal support and storage facilities in Midland, Texas, and an additional storage yard in Odessa, Texas. The Company's oil and gas exploration and production operations complement its onshore drilling operations. These activities are focused in the mature producing regions in the Permian Basin of west Texas and eastern New Mexico. Oil and gas operations comprised approximately 11% of the Company's revenues for the fiscal year ended March 31, 2002. The Company's -4- 5 proved reserves, of which approximately 1,594 MBOE (thousand barrels of oil equivalent) were proved developed producing and approximately 353 MBOE were proved developed non-producing and approximately 337 MBOE were proved undeveloped, had a present value of future net revenues of approximately $21.7 million at March 31, 2002. At that same date, the Company owned interests in approximately 23,851 gross (4,714 net) acres of developed oil and gas properties, and approximately 19,027 gross (4,981 net) acres of undeveloped properties. The contract drilling industry is highly sensitive to oil and gas industry conditions. Since the early 1980's, many oil and gas exploration companies significantly reduced their drilling budgets due to the low oil and gas prices. As a result, the Company encountered substantial competition from other drilling contractors. In recent years, competition within the drilling industry has been intense due to depressed demand for contract drilling services. Industry conditions began to improve during the second quarter of fiscal 2000 and have continued to the present, primarily because of higher crude oil and natural gas prices. The Company's profitability and cash flows are highly dependent on the prices of oil and natural gas. Low oil and natural gas prices have historically had a material adverse effect on the Company's cash flows and profitability. If prices become depressed for a sustained period of time, a material adverse effect on the Company's future operations and financial condition would be expected. The Company has no material patents, licenses, franchises, or concessions which it considers significant to its operations. The nature of the Company's business is such that it does not maintain or require a "backlog" of products, customer orders, or inventory. The Company's operations are not subject to renegotiation of profits or termination of contracts at the election of the federal government. The Company has not been a party to any bankruptcy, receivership, reorganization, adjustment, or similar proceeding. Generally, the Company's business activities are not seasonal in nature. However, weather conditions can hinder drilling activities. -5- 6 CONTRACT DRILLING OPERATIONS Drilling Rigs The following table sets forth the type and depth capabilities of the Company's 18 onshore drilling rigs. Rig No. Depth Capacity Type 2 8,500 Weiss W-45 3 8,500 Weiss W-45 4 8,500 Unit 15 6* 12,500 National 75A 7* 10,000 Unit 15 10(a) 12,500 National 75A 12 11,500 National 50A 14 12,500 BDW 650 17 9,500 Unit 15 22* 13,500 Brewster 75 23* 13,500 National 75A 24* 13,500 Gardner Denver 700 27* 13,500 Gardner Denver 700 28* 16,000 Gardner Denver 800 29* 16,000 Gardner Denver 800 30* 16,000 Gardner Denver 800 31* 16,000 BDW 800 55 30,000 Gardner Denver DW-2100 56* 20,000 National 110-M ---------------- *In active operation at June 7, 2002. (a) On April 12, 2001, this rig was destroyed as a result of an explosion, fire and subsequent blow out. This rig was insured in the amount of $750,000. Major overhauls, repairs and general maintenance for the drilling rigs are primarily conducted at the Company's principal support and storage facilities in Midland, Texas. The Company emphasizes the maintenance and periodic improvement of its drilling equipment and believes that its rigs are generally in good condition. See "Item 2. Properties". Drilling Contracts The Company's drilling contracts are usually obtained through competitive bidding or as a result of direct negotiations with customers. Drilling contracts typically obligate the Company to pay all expenses associated with drilling an oil or gas well, including wages of drilling personnel, maintenance expenses and incidental purchases of rig supplies and equipment. The majority of the Company's contracts are "daywork" contracts with the remainder being "footage" or "turnkey" contracts. Under a footage contract, the Company charges an agreed price per foot of hole drilled, whereas a day-work contract permits the Company to charge a per diem fixed rate for each day the rig is in operation. A turnkey contract specifies a total price for drilling a well plus providing other services, materials or equipment which are typically the responsibility of the operator under -6- 7 footage or daywork contracts. Prices for all contracts vary depending on the location, depth, duration, complexity of the well to be drilled, operating conditions and other factors peculiar to each proposed well. Under footage and turnkey contracts, the Company manages the drilling operation and the type of equipment to be used, subject to certain customer specifications. The Company also bears the risk and expense of mechanical malfunctions, equipment shortages, and other delays arising from problems caused in drilling a well. Daywork contracts permit the operator of the well to manage drilling operations and to specify the type of equipment to be used. Under daywork contracts, the Company generally bears none of the risk due to time delays caused by unforeseeable circumstances such as stuck or broken drill pipe or blowouts. Of the 11 rigs working at June 7, 2002, all were subject to daywork contracts. The Company's operations are subject to many hazards, including well blowouts and fires that could cause personal injury, suspension of drilling operations, damage to or destruction of equipment and damage to producing formations and surrounding areas. The Company believes it is adequately insured for public liability and damage to the property of others resulting from its operations. Rig Utilization The Company's contract drilling revenues depend upon the utilization of its drilling rigs and the contract rates received for its drilling operations. These two factors are affected by a number of variables, including competitive conditions in the drilling industry and the level of exploration and development activity conducted by oil and gas producers at any given time. The level of domestic drilling activity has historically fluctuated and cannot be accurately predicted because of numerous factors affecting the petroleum industry, including oil and gas prices and the degree of government regulation of the industry. Contract drilling revenues and rig utilization rates for the past five years are set forth below. Contract Drilling Year Ended Revenues Number of Percent of March 31, (in thousands) Rigs Owned Utilization 1998 $ 34,891 17(a) 78.2% 1999 12,948 17 26.6% 2000 15,394 18(b) 35.0% 2001 36,023 19(c) 68.2% 2002 46,712 18 66.8% ____________________ (a) Of the total number of rigs owned, one was owned only for a portion of the fiscal year ended March 31, 1998. (b) Of the total number of rigs owned, one was owned only for a portion of the fiscal year ended March 31, 2000. (c) Of the total number of rigs owned, one was owned only for a portion of the fiscal year ended March 31, 2001. On April 12, 2001, this rig was destroyed as a result of an explosion, fire and subsequent blow out. -7- 8 Customers During the fiscal year ended March 31, 2002, the Company drilled a total of 112 wells for approximately 22 customers. The following table sets forth certain information with respect to customers for the Company's contract drilling services that accounted for more than 10% of the Company's total revenues during the last fiscal year. Percent of Number of Wells Name of Customer Total Revenues Drilled ---------------- -------------- --------------- Pure Resources, L.P. 38% 40 The loss of the above customer could have a material adverse effect on the Company, depending upon the demand for the Company's drilling rigs at the time of such loss and the Company's ability to attract new customers. Competition The Company encounters substantial competition from other drilling contractors in its contract drilling operations. The Company's principal market areas of west Texas and eastern New Mexico are highly fragmented and competitive. Companies compete primarily on the basis of contract rates, suitability and availability of equipment and crews, experience of drilling in certain areas, and reputation. The Company believes it competes favorably with respect to all of these factors. Competition is primarily on a well-by- well basis and may vary significantly at any particular time. Drilling rigs can be stacked or moved from one region to another in response to perceived long-term changes in levels of activity. In recent years, competition within the industry has been intense due to the depressed demand resulting from lower oil and gas prices and excess deliverability of natural gas. Employees At June 7, 2002, the Company had 50 salaried employees and approximately 279 hourly paid employees. Employees of the Company are not covered by any collective bargaining agreements and the Company has never experienced a strike or work stoppage. The Company considers its employee relations to be satisfactory. REGULATION Oil and Gas The Company's operations are regulated by certain federal and state agencies. In particular, oil and gas production and related operations are or have been subject to price controls, taxes and other laws relating to the oil and gas industry. The Company cannot predict how existing laws and regulations may be interpreted by enforcement agencies or court rulings, whether additional laws and regulations will be adopted, or the effect such changes may have on its business, financial condition or results of operations. The Company's oil and gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state -8- 9 and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases the Company's cost of doing business and affects its profitability. Because such rules and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such laws. The State of Texas and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the regulation of spacing, plugging and abandonment of such wells. Sales of gas by the Company are not regulated and are made at market prices. However, the Federal Energy Regulatory Commission ("FERC") regulates interstate and certain intrastate gas transportation rates and service conditions, which affect the marketing of gas produced by the Company, as well as the revenues received by the Company for sales of such production. Since the mid-1980s, FERC has issued a series of orders, culminating in Order Nos. 636,636-A and 636-B ("Order 636"), that have significantly altered the marketing and transportation of gas. Order 636 mandates a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. One of FERC's purposes in issuing the orders was to increase competition within all phases of the gas industry. Order 636 and subsequent FERC orders issued in individual pipeline restructuring proceedings have been the subject of appeals, the results of which have generally been supportive of the FERC's open-access policy. In 1996, the United States Court of Appeals for the District of Columbia Circuit largely upheld Order No. 636, et seq. Because further review of certain of these orders is still possible, and other appeals remain pending, it is difficult to predict the ultimate impact of the orders on the Company and its gas marketing efforts. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines' traditional role as wholesalers of gas, and has substantially increased competition and volatility in gas markets. While significant regulatory uncertainty remains, Order 636 may ultimately enhance the Company's ability to market and transport its gas, although it may also subject the Company to greater competition. The sale of oil by the Company is not regulated and is made at market prices. The price the Company receives from the sale of oil is affected by the cost of transporting the product to market. Effective as of January 1, 1995, FERC implemented regulations establishing an indexing system for transportation rates for interstate common carrier oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. These regulations could increase the cost of transporting oil by interstate pipelines, although the most recent adjustment generally -9- 10 decreased rates. These regulations have generally been approved on judicial review. The Company is not able to predict with certainty what effect, if any, these regulations will have on it, but, other factors being equal, the regulations may, over time, tend to increase transportation costs or reduce wellhead prices for oil. The Company is required to comply with various federal and state regulations regarding plugging and abandonment of oil and gas wells. Environmental Various federal, state and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment, health and safety, affect the Company's operations and costs. These laws and regulations sometimes require governmental authorization before certain activities, limit or prohibit other activities because of protected areas or species, impose substantial liabilities for pollution related to Company operations or properties, and provide penalties for noncompliance. In particular, the Company's exploration and production operations, its activities in connection with storage and transportation of oil and other liquid hydrocarbons, and its use of facilities for treating, processing or otherwise handling hydrocarbons and related exploration and production wastes are subject to stringent environmental regulation. As with the industry generally, compliance with existing and anticipated regulations increases the Company's overall cost of business. While these regulations affect the Company's capital expenditures and earnings, the Company believes that such regulations do not affect its competitive position in the industry because its competitors are similarly affected by environmental regulatory programs. Environmental regulations have historically been subject to frequent change and, therefore, the Company is unable to predict the future costs or other future impacts of environmental regulations on its future operations. A discharge of hydrocarbons or hazardous substances into the environment could subject the Company to substantial expense, including the cost to comply with applicable regulations that require a response to the discharge, such as containment or cleanup, claims by neighboring landowners or other third parties for personal injury, property damage or their response costs and penalties assessed, or other claims sought by regulatory agencies for response cost or for natural resource damages. The following are examples of some environmental laws that potentially impact the Company and its operations. Water. The Oil Pollution Act ("OPA") was enacted in 1990 and amends provisions of the Federal Water Pollution Control Act of 1972 ("FWPCA") and other statutes as they pertain to prevention of and response to major oil spills. The OPA subjects owners of facilities to strict, joint and potentially unlimited liability for removal costs and certain other consequences of an oil spill, where such spill is into navigable waters, or along shorelines. In the event of an oil spill into such waters, substantial -10- 11 liabilities could be imposed upon the Company. States in which the Company operates have also enacted similar laws. Regulations are currently being developed under the OPA and similar state laws that may also impose additional regulatory burdens on the Company. The FWPCA imposes restrictions and strict controls regarding the discharge of produced waters, other oil and gas wastes, any form of pollutant, and, in some instances, storm water runoff, into waters of the United States. The FWPCA provides for civil, criminal and administrative penalties for any unauthorized discharges and, along with the OPA, imposes substantial potential liability for the costs of the removal, remediation or damages resulting from an unauthorized discharge. State laws for the control of water pollution also provide for civil, criminal and administrative penalties and liabilities in the case of an unauthorized discharge into state waters. The cost of compliance with the OPA and the FWPCA have not historically been material to the Company's operations, but there can be no assurance that changes in federal, state or local water pollution control programs will not materially adversely effect the Company in the future. Although no assurances can be given, the Company believes that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on the Company's financial condition or results of operations. Air Emissions. Amendments to the Federal Clean Air Act enacted in late 1990 (the "1990 CAA Amendments") require or will require most industrial operations in the United States to incur capital expenditures in order to meet air emissions control standards developed by the Environmental Protection Agency ("EPA") and state environmental agencies. Although no assurances can be given, the Company believes implementation of the 1990 CAA Amendments will not have a material adverse effect on the Company's financial condition or results of operations. Solid Waste. The Company generates non-hazardous solid wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The EPA and the states in which the Company operates are considering the adoption of stricter disposal standards for the type of non-hazardous wastes generated by the Company. RCRA also governs the generation, management, and disposal of hazardous wastes. At present, the Company is not required to comply with a substantial portion of the RCRA requirements because the Company's operations generate minimal quantities of hazardous wastes. However, it is anticipated that additional wastes, which could include wastes currently generated during operations, could in the future be designated as "hazardous wastes". Hazardous wastes are subject to more rigorous and costly disposal and management requirements than are non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses by the Company. Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as "Superfund", imposes liability, -11- 12 without regard to fault or the legality of the original act, on certain classes of persons in connection with the release of a "hazardous substance" into the environment. These persons include the current owner or operator of any site where a release historically occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In the course of its ordinary operations, the Company may have managed substances that may fall within CERCLA's definition of a "hazardous substance". The Company may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites where the Company disposed of or arranged for the disposal of these substances. This potential liability extends to properties that the Company owned or operated, as well as to properties owned and operated by others at which disposal of the Company's hazardous substances occurred. The Company may also fall into the category of a "current owner or operator". The Company currently owns or leases numerous properties that for many years have been used for the exploration and production of oil and gas. Although the Company believes it has utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released by the Company on or under the properties owned or leased by the Company. In addition, many of these properties have been previously owned or operated by third parties who may have disposed of or released hydrocarbons or other wastes at these properties. Under CERCLA, and analogous state laws, the Company could be subject to certain liabilities and obligations, such as being required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. OIL AND GAS OPERATIONS The Company's oil and gas operations involve the acquisition, exploration for, development and production of oil and natural gas. During the fiscal year ended March 31, 2002, the Company's exploration efforts were conducted in west Texas and eastern New Mexico. The Company is actively investing in oil and gas properties for the purpose of exploration, development and production of oil and gas. The Company acquires or participates in these arrangements as a working interest owner and usually provides the contract drilling services for such ventures. Exploration for oil and natural gas requires substantial expenditures, especially for exploration in more remote areas. As is customary in the oil and gas industry, the drilling of oil and gas wells is usually accomplished through participation with other third parties. One of the parties -12- 13 experienced with operations in the area is usually designated as the operator of the property and is responsible for the direct supervision, administration and accounting for wells drilled and completed pursuant to an operating agreement between the parties. The Company typically serves as operator of oil and gas prospects assembled by the Company and participates as a non- operating working interest owner in prospects assembled and generated by third parties. As operator, the Company supervises the drilling and completion of wells and production therefrom and the further development of surrounding properties. The operator of a well has significant control over its location and the timing of its drilling. In addition, the operator of a well receives fees from other working interest owners as reimbursement for the general and administrative expenses attendant to the operation of the wells. The operator will normally receive revenues and pay expenses equal to more than its ownership interest in the wells, and then must remit or collect all but its share to or from the other respective participants in the well. At June 7, 2002 the Company was operator of 42 wells. Oil and Gas Reserves Information concerning the Company's estimated proved oil and gas reserves is included in Note (9) to the Company's financial statements. See "Item 8 - Financial Statements and Supplementary Data". The reserve information included in this report is only an estimate. There are numerous uncertainties inherent in estimating oil and gas reserves and their estimated values, including many factors beyond the control of the Company. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, estimates of reserves are subject to revision due to the results of drilling, testing and production subsequent to the date of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. The accuracy of such estimates is highly dependent upon the accuracy of the underlying assumptions upon which they are based. In general, the volume of production from oil and gas properties declines as reserves are depleted. Except to the extent the Company acquires properties containing proved reserves or conducts successful exploration and development activities, or both, the proved reserves of, and volumes of production by, the Company will decline as reserves are produced. The Company's future oil and gas production is therefore highly dependent upon its level of success in acquiring or finding additional reserves. The Company has no reserves outside the United States. No major discovery or other favorable or adverse event has occurred since March 31, 2002 which is believed to have caused a significant change in -13- 14 the estimated proved oil and gas reserves of the Company. The Company's oil and gas reserves and production are not subject to any long-term supply or similar agreements with foreign governments or authorities. The Company's estimate of reserves has not been filed with or included in reports to any federal agency other than the Securities and Exchange Commission. Productive Wells and Acreage The following tables set forth the gross and net productive oil and gas wells and developed and undeveloped acreage in which the Company owned a working interest as of March 31, 2002. Excluded from the table is acreage in which the Company's interest is limited to royalty or similar interests. Productive Wells ----------------------------------- Gross Net ----------- --------------- Oil Gas Oil Gas --- --- ------ ----- Texas................................... 75 13 11.423 2.571 New Mexico.............................. 26 10 9.259 2.923 Oklahoma............................... -- 3 -- .090 --- --- ------ ----- Total.........................101 26 20.682 5.584 === === ====== ===== Acreage --------------------------------------- Developed Undeveloped --------------- ----------------- Gross Net Gross Net ----- --- ----- --- Texas............................ 15,240 2,763 15,660 4,046 New Mexico....................... 6,691 1,894 1,856 557 Oklahoma......................... 1,920 57 -- -- Kansas........................... -- -- 1,511 378 ------ ----- --------- ------ Total.................. 23,851 4,714 19,027 4,981 ====== ===== ========= ====== Generally, the terms of developed oil and gas leaseholds are continuing and such leases remain in force by virtue of, and so long as, production from lands under lease is maintained. Undeveloped oil and gas leaseholds are generally for a primary term, such as five or ten years, subject to maintenance with the payment of specified minimum delay rentals or extension by production. On September 5, 1995, the Company entered into a 10 year License Agreement with the Government of the Republic of Palau and the State of -14- 15 Kayangel which will allow the Company to explore for oil and natural gas offshore. The license covers approximately 1.1 million acres within the waters of Palau. Pursuant to the amended license agreement, the Company was required to drill two wells by March, 2002. During 2002, the Company decided to abandon this project and accordingly impaired approximately $150,000 which represented the Company's costs related to this leasehold. Drilling Activity The following table sets forth certain information concerning the number of gross and net exploratory and development wells drilled for the Company's account during the periods indicated. Year Ended March 31, ------------------------------------------------------- 2002 2001 2000 --------------- --------------- --------------- Type of Well Gross Net Gross Net Gross Net ------------ ----- ----- ----- ----- ----- ----- Exploratory (1) Oil 4 .895 3 1.162 6 1.680 Gas 2 .528 4 1.262 4 .590 Dry 2 .673 7 1.937 3 .500 Development (2) Oil 4 1.856 4 2.400 2 .160 Gas -- -- 1 .050 -- -- Dry 1 .050 2 .100 1 .100 -------------------------- (1) An exploratory well is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. (2) A development well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. At June 7, 2002, the Company was participating in the drilling of 1 gross (.25 net) development well in Lea County, New Mexico. Substantially all of the equipment used in the Company's drilling operations is owned by the Company; however, certain insignificant items of drilling equipment are leased or rented as needed because such equipment either cannot be purchased or is only necessary for the drilling of certain types of wells located in certain areas. -15- 16 Production, Prices and Costs. The following table sets forth certain information regarding the volumes of the Company's net production of oil and gas, the average sales prices received associated with its sales of oil and gas, and the average production (lifting) cost per equivalent barrel of oil ("EBO"). Year Ended March 31, ------------------------------------ 2002 2001 2000 ------ ------ ------ Net Production Oil (Bbls) 127,353 108,886 78,217 Gas (Mcf) 707,923 428,355 611,901 EBO (1) 245,340 180,279 180,201 Average Daily Production Oil (Bbls) 349 298 214 Gas (Mcf) 1,940 1,174 1,676 EBO 672 494 494 Sales Prices Oil ($/Bbl) $23.19 $31.14 $21.12 Gas ($/Mcf) 3.61 4.82 2.48 EBO 22.45 30.25 17.58 Production (Lifting) Costs per EBO 7.28 7.77 5.13 -------------------- (1) An EBO is one equivalent barrel of oil using the ratio of six Mcf of gas to one barrel of oil. Title to Properties As is customary in the oil and gas industry, a preliminary title examination is conducted at the time oil or gas properties believed to be suitable for drilling are acquired by the operator. Prior to the commencement of operations, curative work determined to be appropriate as a result of a title search is performed with respect to significant defects before the operator commences development. Title examinations have been performed with respect to substantially all of the Company's interests in its producing properties. The Company believes that title to its properties is good and defensible in accordance with standards generally acceptable in the oil and gas industry, subject to such exceptions which, in the Company's opinion, are not so material as to detract substantially from the value of such properties. The Company's properties are subject to royalty, overriding royalty, and other outstanding interests customary in the industry, and are also subject to burdens such as liens incident to operating agreements, current taxes not yet due, development obligations under oil and gas leases, and other encumbrances, easements and restrictions. The Company does not believe that any of these burdens materially interferes with the use of its properties in the operation of its business. -16- 17 Markets and Customers The Company sells its oil and gas at the wellhead on an "as-produced" basis and does not refine petroleum products. Other than normal production facilities, the Company does not own an interest in any bulk storage facilities or pipelines. As is customary in the industry, the Company sells its production in any one area to relatively few purchasers, including transmission companies that have pipelines near the Company's producing wells. Gas purchase contracts are generally on a short-term "spot market" basis and usually contain provisions by which the prices and delivery quantities for future deliveries will be determined. During the year ended March 31, 2002, Navajo Refining and Crude Marketing, Lantern Petroleum Corporation and Pure Resources, L.P. accounted for approximately 24%, 17% and 15%, respectively, of the Company's oil and gas revenues for such period. The loss of any of these purchasers could cease or delay the Company's production and sale of its oil and gas reserves to the extent that alternative purchasers having adequate gathering facilities are not found to replace such purchaser's volume of oil or gas purchased. However, in the event of a loss of any purchaser, the Company believes that, under present circumstances, it would be able to find other purchasers for its oil and gas production. Competition The Company encounters strong competition from major oil companies and independent producers and operators in acquiring properties and leases for exploration for oil and gas. Competition is particularly intense with respect to the acquisition of desirable undeveloped oil and gas leases. The principal competitive factors in the acquisition of undeveloped oil and gas leases include qualified personnel and having access to the data necessary to acquire and develop such leases, as well as the amount of consideration and terms offered. Many of the Company's competitors have financial resources, staffs and facilities substantially greater than those of the Company. In addition, the producing and marketing of natural gas and oil is affected by a number of factors which are beyond the control of the Company, the effect of which cannot be accurately predicted. Of significant importance recently has been the domination and control of oil markets and prices by foreign producers. The principal raw materials and resources necessary for the exploration and development of oil and gas are leasehold prospects under which oil and gas reserves may be discovered, drilling rigs and related equipment to explore for such reserves and knowledgeable personnel to conduct all phases of oil and gas operations. The Company must compete for such raw materials and resources with both major oil companies and independent operators, and the continued availability, without periodic interruption, of such materials and resources to the Company cannot be assured. -17- 18 Risk Factors Declining oil and gas prices may cause the Company to record write-downs in the carrying value of its oil and gas properties. The Company's oil and gas producing activities are accounted for using the successful efforts method of accounting. The costs incurred to acquire oil and gas properties (proved and unproved), all development costs and successful exploratory costs are capitalized, whereas the costs of unsuccessful exploratory wells are expensed. Geological and geophysical costs, including seismic costs, are charged to expense when incurred. In cases where the Company provides contract drilling services related to oil and gas properties in which it has an ownership interest, the Company's proportionate share of costs related to oil and gas properties is capitalized as stated above, net of its working interest share of profits from the related drilling contracts. Capitalized costs of undeveloped properties, which are not depleted until proved reserves can be associated with the properties, are periodically reviewed for possible impairment. This non-cash impairment charge does not affect cash flow from operating activities, but it does reduce earnings. Impairment charges cannot be restored by subsequent increases in the prices of oil and gas. The risk that the Company will be required to write down the carrying value of its oil and gas properties increases when oil and gas prices decline. In addition, write-downs may occur if the Company experiences substantial downward adjustments to its estimated proved reserves. For the year ended March 31, 2002, the Company recognized a non-cash impairment charge of $3,953,421 related to its oil and gas reserves and unproved properties. This impairment of oil and gas assets was primarily the result of the effect of significantly lower oil and gas prices on both proved and unproved oil and gas properties and unsuccessful exploitation efforts to increase production. No assurance can be given that the Company will not experience write-downs in the future. The Company is subject to many restrictions under its loan agreement. As required by the Company's loan agreement with its bank lender, substantially all of the Company's drilling rigs and related equipment, accounts receivable and inventory have been pledged as collateral to secure the payment of its loans. The loan agreement restricts the Company's ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. The Company is also required to comply with certain financial covenants and maintain certain financial ratios. The loan agreement prohibits the Company from declaring or paying dividends on its common stock. Although the Company is currently in compliance with the loan covenants, its ability to comply in the future with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from operations and events or circumstances beyond its control. The Company's failure to comply with any of the restrictions and -18- 19 covenants under the loan agreement could result in a default under the loan agreement. The loan agreement limits the amounts the Company can borrow to a borrowing base amount, based upon the value of the drilling rigs and equipment, accounts receivable and inventory securing repayment of loans made to the Company. The bank can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the loan agreement. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or the Company must pledge other assets as additional collateral. No assurance can be given that the Company would be able to make any mandatory principal prepayments required under the loan agreement. Part of the Company's business is seasonal in nature. Weather conditions affect the demand for and prices of natural gas and can also delay drilling activities, disrupting the Company's overall business plans. Demand for natural gas is typically higher during winter months. The Company's contract drilling and oil and gas operations are subject to many inherent risks. Contract drilling and oil and gas exploration and production activities are subject to many risks and hazards. The Company's oil and gas operations are marked by unprofitable efforts because of dry holes and wells that do not produce oil or gas in sufficient quantities to return a profit. The success of the Company's operations depends, in part, upon the ability of management and technical personnel. The cost of drilling, completing and operating wells is often uncertain. There is no assurance that the Company's oil and gas drilling or acquisition activities will be successful, that any production will be obtained, or that any such production, if obtained, will be profitable. The Company's drilling operations and fleet are subject to many hazards inherent in the onshore drilling industry, such as encountering unusual or unexpected formations and pressures, blowouts, explosions, cratering, well fires and spills. These hazards can result in personal injury and loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage and suspension of operations. Any one of these potential hazards could result in accidents, environmental damage, personal injury, property damage and other harm that could result in substantial liabilities to the Company. The Company generally seeks to obtain indemnity agreements whenever possible from its customers requiring them to hold the Company harmless if loss of production or reservoir damage occurs. Even when the Company obtains contractual indemnification, however, the customer may not maintain adequate insurance to support such indemnification. As is customary in the industry, the Company maintains insurance against some, but not all, of the hazards and risks it encounters. The Company -19- 20 maintains general liability insurance and obtains insurance against blowouts and pollution risks on a well-by-well basis, but does not carry insurance against all operating hazards. No assurance can be given that the Company's insurance or contractual indemnity protection will be sufficient or effective under all circumstances or against all hazards to which it may be subject, and its insurance claims will be subject to retentions and deductibles. The occurrence of a significant event for which the Company is not fully insured or indemnified or the failure of a customer to meet its indemnification obligations could have a material adverse effect on the Company's results of operations and financial condition. No assurance and be given that the Company will be able to maintain insurance in the future at rates that it considers reasonable. Ability to Replace Reserves. The Company's future performance depends in part upon its ability to find, develop and acquire additional oil and gas reserves that are economically recoverable. The Company's proved reserves decline as those reserves are depleted and it must locate and develop or acquire new oil and gas reserves to replace reserves being depleted by production. No assurance can be given that the Company will be able to find and develop or acquire additional reserves on an economical basis. The volatility of the oil and gas industry may have an adverse impact on the Company's operations. The Company's revenues, cash flows and profitability are substantially dependent upon prevailing prices for oil and gas, both with respect to its contract drilling operations and its oil and gas operations. In recent years, oil and gas prices and, therefore, the level of drilling, exploration, development and production, have been extremely volatile. Any significant or extended decline in oil and/or gas prices or land drilling activity in the United States will have a material adverse effect on the Company's financial condition and results of operations and could impair access to future sources of capital. Demand and prices for the Company's contract drilling services depend upon numerous factors over which it has no control, including: the level of oil and natural gas prices, expectations about future oil and natural gas prices and the ability of international cartels to set and maintain production levels and prices, the cost of exploring for, producing and delivering oil and natural gas the level and price of foreign oil and natural gas imports, the discovery rate of new oil and natural gas reserves, available pipeline and other oil and natural gas transportation capacity, -20- 21 weather conditions, international political, military, regulatory and economic conditions and the ability of oil and natural gas companies to raise capital. No assurance can be given that current levels of oil and natural gas exploration activities in the Company's markets will continue or that demand for its contract drilling services will correspond to the level of activity in the industry generally. The Company's expects oil and natural gas prices to continue to be volatile and to affect the demand for and pricing of its contract drilling services. Decreased demand or reduced prices the Company receives for its land contract drilling services could materially adversely affect its financial condition. Any significant decrease in demand for, or the prices received for, the Company's contract drilling services could have a material adverse affect on its results of operations and financial condition. An oversupply of drilling rigs and a large number of drilling contractors have affected adversely the United States land drilling industry for many years. These conditions have resulted in depressed day rates and substantial competition for available contracts. The Company cannot accurately predict either the future level of demand for its contract drilling services or future conditions in the land contract drilling services industry. The Company operates in a highly competitive industry, which includes competitors with greater financial resources. Some of the Company's competitors have significantly greater financial resources than it has, which may enable them to better withstand industry downturns, to compete more effectively on the basis of price, to acquire existing rigs or to build new rigs. The contract drilling industry in which the Company operates is a highly-fragmented, intensely competitive and cyclical business. Competition for services in a particular market is based on price, location, type and condition of available equipment and quality of service. A number of large and small contractors provide competition for drilling contracts in all areas of the Company's business. In addition, certain competitors are present in more than one of those areas and drilling rigs are mobile and can be moved from one region to another in response to market conditions. The Company may incur losses in connection with its footage and turnkey contracts. The Company cannot provide assurance that it will not incur losses on turnkey and footage contracts in the future. The Company performs drilling services pursuant to footage and turnkey drilling contracts under which it agrees to drill a well to a specified depth for a fixed price. The risks -21- 22 associated with a turnkey or footage contract are greater than for wells drilled on a daywork basis because in a turnkey or footage contract the Company, as the contractor, assumes most of the risks associated with drilling operations generally assumed by the operator under a daywork contract, including the risk of blowout, loss of hole, stuck drill string, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors, services, supplies and personnel. As of March 31, 2002, none of the Company's rigs were operating under footage or turnkey contracts. Under such contracts, the Company does not receive payment unless the well is drilled to the specified depth, and it must bear the costs of performing drilling services until the well has been drilled. In addition, profitability of the contract is dependent upon keeping expenses within the estimates the Company uses in determining the contract price and completing the contracts on schedule. September 11 events may adversely affect the Company's business. The full repercussions of the events of September 11 are not known. However, it is not unreasonable to believe, as the Company does, that its business activities and financial condition could be adversely impacted. For instance, the premiums the Company pays for its business insurance coverage could rise significantly, or coverage provided by its insurance carriers could be substantially reduced, forcing the Company to operate without adequate coverage in an industry characterized by high risk to persons and property. In addition, the disruption of the financial markets and the negative impact on the U. S. economy caused by September 11 may undermine the Company's efforts and any success it might have in its contract drilling and exploration and production activities. Although September 11 was not a direct attack on the domestic oil and gas industry, any future similar events, particularly directed at the oil and gas industry, could materially and adversely affect the Company's business, results of operations and financial condition. The oil and gas industry is capital intensive. The oil and gas industry is capital intensive. The company's cash flow from operations and the continued availability of credit are subject to a number of variables, including the number and type of drilling contracts it is able to obtain, the level of oil and gas it is able to produce from existing wells, the prices at which oil and gas are sold and its ability to locate and produce new reserves. The Company cannot provide any assurance that its cash flow from operations and present borrowing capacity will be sufficient to fund its anticipated capital expenditures and working capital requirements. The Company may from time to time seek additional financing, either in the form of bank borrowings, sales of securities or other forms of financing. Except for the Company's loan agreement with its bank lender, it has no agreements for any such financing and there can be no assurance as to the availability of terms of any such financing. To the extent the Company's capital resources and earnings are at any time insufficient to fund its -22- 23 activities or repay any indebtedness as due, it will need to raise additional funds through public or private financings or additional borrowings. No assurance can be given as to the Company's ability to obtain any such capital resources. If the Company is not at any time able to obtain then necessary capital resources, its financial condition and results of operations could be materially adversely affected. If, however, additional funds are raised through the issuance of equity securities, the percentage ownership of the Company's stockholders at that time could be diluted and, in addition, such equity securities may have rights, preferences or privileges senior to those of the common stock. The Company does not pay dividends on its common stock. The Company has never paid dividends on its common stock, and does not intend to pay cash dividends on the common stock in the foreseeable future. Net income from the Company's operations, if any, will be used for the development of its business. Any decision to pay dividends on the common stock in the future will depend upon the Company's profitability at that time. There is a shortage of qualified and experienced labor. The volatility of conditions in the oil and gas industry sometimes results in a shortage of qualified drilling rig personnel in the industry. As a result, and rather than hiring unqualified or inexperienced crews, from time to time the Company may intentionally restrict the number of drilling rigs it has in active operation at any one time. If the Company is unable to attract and retain qualified personnel, its ability to market and operate its drilling rigs will be restricted. In addition, labor shortages could result in wage increases, which could reduce the Company's operating margins and have a material adverse effect on its financial condition and results of operations. The reserve data in this report represent estimates only. Information relating to the Company's proved oil and gas reserves is based upon engineering estimates. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates of economically recoverable oil and gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. Because all reserve estimates are to some degree speculative, the actual quantities of oil and gas that are ultimately recovered, production and -23- 24 operation costs, the amount and timing of future development expenditures and future oil and gas sales prices may all vary from those assumed in these estimates and such variances may be material. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. The present value of proved reserves referred to in this report should not be construed as the current market value of the estimated proved reserves of oil and gas attributable to the Company's properties. In accordance with SEC requirements, the Company has based the estimated discounted future net cash flows from proved reserves on prices and costs as of the date of the estimate, whereas actual future prices and costs may vary significantly. The following factors may also affect actual future net cash flow: the timing of production and related expenses changes in consumption levels; and governmental regulations or taxation. In addition, the calculation of the present value of the future net cash flows using a 10% discount as required by the SEC is not necessarily the most appropriate discount rate based on interest rates in effect from time to time and risks associated with the Company's reserves or the oil and gas industry in general. In addition, the Company may need to revise its reserves downward or upward based upon actual production, results of future development, supply and demand for oil and gas, prevailing oil and gas prices and other factors. Reliance upon financial statements audited by Arthur Andersen LLP. Arthur Andersen LLP was previously the independent accountant for the Company. Representatives for Arthur Andersen LLP are not available to reissue their report on the March 31, 2000 and 2001 financial statements or provide the consent required for the incorporation by reference of their reports on the financial statements and we have dispensed with the requirement to file their consent in reliance upon Rule 437a of the Securities Act of 1933. Because Arthur Andersen LLP has not consented to the inclusion of their report, you will not be able to recover against Arthur Andersen LLP under Section 11 of the Securities Act of 1933 for any untrue statements of a material fact contained in the financial statements audited by Arthur Andersen LLP that are incorporated by reference or any omissions to state a material fact required to be stated therein. -24- 25 Executive Officers Thomas C. Brown, age 75, has served as a Director of the Company since 1982. He is presently Chairman of the Board of Directors and Chief Executive Officer of the Company and has served in such capacities since 1990. Jeffrey D. Phillips, age 41, has been employed by the Company since 1995. He has been President since April 1, 2001. He was Vice President - Production of the Company from 1997 to 2001. Don H. Lawson, age 63, has been employed by the Company since 1967. He has been the Vice President - Operations of the Company since 1992. Patricia R. Elledge, age 44, was employed by the Company from September, 1989 to December, 1993 when she resigned to relocate. Ms. Elledge returned to the Company in September, 1994 in her current capacity as Controller - Treasurer. James M. Alsup, age 65, has been the Secretary of the Company since 1982. He has been a partner in the law firm of Lynch, Chappell & Alsup since 1970. Item 2. PROPERTIES In addition to its drilling rigs and related equipment and its oil and gas properties, the Company owns a 31 acre tract of land in Midland, Texas on which the Company's executive offices are located and on which the principal support and storage facilities for its contract drilling operations are located. These facilities include an office building and fabrication and maintenance shop. The facility allows for open storage of drilling equipment and drill pipe. The Company also owns a 78 acre tract of land in Odessa, Texas, which is presently being utilized as a secondary storage location. From time to time, the Company's rigs are also stored and stacked in the field at the rig's last location site. The Company owns a warehouse and yard facility situated on approximately 4 acres in Midland, Texas. This additional storage is used to complement the existing Midland yard facility. The Company believes that the support and storage facilities for its drilling rigs and related equipment are more than adequate. -25- 26 Item 3. LEGAL PROCEEDINGS The Company is a defendant in various lawsuits generally incidental to its business. The Company does not believe that the ultimate resolution of such litigation will have a significant effect on the Company's financial position or results of operations. Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There was no meeting of security holders of the Company during the fourth quarter of the fiscal year ended March 31, 2002, and no matters were submitted to a vote of security holders during such period. PART II Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The Company's Common Stock is traded on the NASDAQ National Market System under the symbol "TBDI". The following table sets forth, on a per share basis for the periods indicated, the range of high and low last reported sales prices as reported by NASDAQ. The quotations are inter-dealer prices without retail mark-ups, mark-downs or commissions and may not represent actual transactions. Price ----------------- High Low ------ ------ Fiscal 2001 First Quarter $ 12.43 $ 8.75 Second Quarter 15.75 10.50 Third Quarter 14.68 10.00 Fourth Quarter 18.37 13.00 Fiscal 2002 First Quarter 19.05 14.62 Second Quarter 16.95 12.10 Third Quarter 13.61 11.45 Fourth Quarter 15.25 10.40 -26- 27 On June 7, 2002, the last reported sale price of the Company's Common Stock as reported by NASDAQ was $13.88. The transfer agent for the Company's Common Stock is American Stock Transfer & Trust Company, New York, New York. On June 7, 2002, the outstanding shares of the Company's Common Stock were held of record by approximately 1,955 stockholders. The Company has never declared or paid any cash dividends on its Common Stock and has no present intention to pay cash dividends in the future. The Company presently intends to retain all earnings to fund its operations and future growth. Under the terms of the Company's credit facility with its bank lender, the Company is prohibited from paying cash dividends to the holders of Common Stock. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources". -27- 28 Item 6. SELECTED FINANCIAL DATA The following table sets forth certain selected financial data for the Company's operations for each of the five years ended March 31, 2002. The data set forth in this table should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations", and the Company's Financial Statements and related notes included elsewhere herein.
Years ended March 31, -------------------------------------------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (In thousands, except per share amounts) INCOME STATEMENT DATA Operating revenues: Contract drilling $ 46,712 $ 36,023 $ 15,394 $ 12,948 $ 34,891 Oil and gas 5,508 5,454 3,169 1,476 2,126 ------ ------ ------ ------ ------ Total operating revenues 52,220 41,477 18,563 14,424 37,017 Operating costs and expenses: Contract drilling 26,761 22,767 12,486 10,027 23,163 Oil and gas production 1,721 1,363 926 803 944 Dry holes and abandonments 1,657 811 490 840 440 Exploration 60 174 19 106 36 Depreciation, depletion and amortization 6,746 5,137 3,282 2,699 4,080 General and administrative 2,552 1,918 1,854 1,911 1,863 Writedown of oil and gas properties (a) 3,953 1,171 739 1,304 3,120 ------ ------ ------ ------ ------ Total operating costs and expenses 43,450 33,341 19,796 17,690 33,646 ------ ------ ------ ------ ------ Operating income (loss) 8,770 8,136 (1,233) (3,266) 3,371 Other income (expenses): Interest 11 (216) 17 151 133 Other 1,035 558 9 (72) 1,180 ------ ------ ------ ------ ------ Total other income (expense) 1,046 342 26 79 1,313 ------ ------ ------ ------ ------ Net income(loss) before income tax provision 9,816 8,478 (1,207) (3,187) 4,684 Provision for income taxes -- (170) -- -- (140) ------ ------ ------ ------ ------ Net income (loss) before extraordinary items $ 9,816 $ 8,308 $ (1,207) $ (3,187) $ 4,544 ====== ====== ====== ====== ====== 29 Net income (loss) before extraordinary items per share: Basic $ 1.88 $ 1.67 $(0.25) $(0.68) $ 0.98 Diluted $ 1.79 $ 1.54 $(0.25) $(0.68) $ 0.91 ====== ====== ====== ====== ====== Weighted average number of common shares outstanding: Basic 5,220 4,979 4,761 4,711 4,615 Diluted 5,474 5,392 4,761 4,711 5,014 ===== ===== ===== ===== ===== BALANCE SHEET DATA Cash and cash equivalents $ 3,258 $ 301 $ 980 $ 1,195 $ 1,623 Total assets 42,635 35,401 23,625 18,923 24,648 Total debt -- 1,080 2,250 -- -- Stockholders' equity 35,832 24,606 15,796 16,735 19,960
____________________ (a) During fiscal years ended March 31, 2002, 2001 and 2000, the Company recognized non-cash charges of approximately $3,953,000, $1,171,000 and $739,000, respectively, due to a writedown of the carrying value of its oil and gas properties. This charge is a result of the adoption of Statement of Financial Accounting Standards No. 121 ("SFAS 121") "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of". SFAS 121 requires the Company to assess the need for an impairment of capitalized costs of oil and gas properties on a property-by-property basis in contrast to the Company's prior policy of evaluating the undiscounted future net revenues of its oil and gas properties in total. According to SFAS 121, if an impairment is indicated based on undiscounted future cash flows, then it is recognized to the extent that net capitalized costs exceed discounted future cash flows. -28- 30 Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Overview and Critical Accounting Policies Since 1982, the principal business of the Company has been the contract drilling of domestic onshore oil and gas wells. In 1987, the Company began acquiring oil and gas properties and participating in the exploration for and development of oil and gas reserves. Contract Drilling Operations Drilling revenues from footage and daywork contracts are recognized as work is performed utilizing the percentage-of-completion method. Costs under footage and daywork contracts are recognized in the period they are incurred. The Company utilizes the completed contract method to recognize drilling revenues and expenses relating to turnkey contracts. Expected losses on all in-process contracts are recognized in the period the loss can reasonably be determined. Drilling equipment is depreciated on a units-of-production method based on the monthly utilization of the equipment. Drilling equipment which is not utilized during a month is depreciated using a minimum utilization rate of approximately 25%. Estimated useful lives range from four to eight years. Other property and equipment is depreciated using the straight-line method of depreciation with estimated useful lives of three to seven years. The contract drilling industry is currently experiencing a decrease in demand and downward pressure on prices for contract drilling services due to the uncertainty surrounding oil and gas prices. The Company has been and will continue to be affected by oil and gas industry conditions but cannot predict either the future level of demand for its contract drilling services or future conditions in the contract drilling industry. The contract drilling industry remains highly competitive. The Company believes it owns a sufficient number of drilling rigs to remain competitive within its areas of operation. In addition, the Company believes it competes favorably with respect to the depth capabilities of its rigs, the experience level of its personnel, its reputation and its relationship with existing customers. However, the Company's operating results will continue to be directly affected by the level of drilling activity in the Company's service areas. -29- 31 The following table sets forth certain information relating to the Company's contract drilling operations for the periods indicated: Year Ended March 31, ------------------------- 2002 2001 2000 ---- ---- ---- (In thousands, except %s) Contract drilling revenues $46,712 $36,023 $15,394 Contract drilling expenses 26,761 22,767 12,486 Contract drilling expenses as a percent of drilling revenues 57.3% 63.2% 81.1% Rig utilization 66.8% 68.2% 35.0% Oil and Gas Operations The Company's oil and gas producing activities are accounted for using the successful efforts method of accounting. Accordingly, the Company capitalizes all costs incurred to acquire oil and gas properties (proved and unproved), all development costs, and the costs of successful exploratory wells. The costs of unsuccessful exploratory wells are expensed. Geological and geophysical costs, including seismic costs, are charged to expense when incurred. In cases where the Company provides contract drilling for oil and gas properties in which it has an ownership interest, the Company's proportionate share of costs is capitalized as stated above, net of its working-interest share of profits from the related drilling contracts. Capitalized costs of undeveloped properties, which are not depleted until proved reserves can be associated with the properties, are periodically reviewed for possible impairment. Such unevaluated costs totaled approximately $1,967,000 and $845,000 as of March 31, 2002, and March 31, 2001, respectively. For properties with proved or proved developed oil and gas reserves, depletion, depreciation and amortization of capitalized costs was calculated for fiscal 2002, 2001 and 2000 by applying the units-of-production method to the estimated amount of such reserves. In fiscal 2002, 2001 and 2000, the Company recognized non-cash charges of approximately $4.0 million, $1.2 million and $.7 million, respectively, due to writedowns of the carrying value of its oil and gas properties. The writedowns are the result of the adoption in 1996 of Statement of Financial Accounting Standards No. 121 ("SFAS 121") "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of". SFAS 121 requires the Company to assess the need for an impairment of capitalized costs of oil and gas properties on a property-by-property basis. According to SFAS 121, if an impairment is indicated based on undiscounted future cash flows, then it is to be recognized to the extent that net capitalized costs exceed discounted future cash flows. Many assumptions are required for the -30- 32 Company's impairment assessment when impairment indicators are present, including future prices and expenses, production volumes and drilling results. Changes in these assumptions could have a significant impact on whether specific oil and gas properties fail the impairment test. Prices used for the impairment analysis at March 31, 2002 were $23.36 per Bbl and $3.318 per Mcf. Future impairment expense may be required on current properties if the Company changes its pricing or cost assumptions in the future or if estimated future recoverable reserves decline. The following table sets forth certain information relating to the Company's oil and gas operations for the periods indicated: Year Ended March 31, -------------------------- 2002 2001 2000 ---- ---- ---- (In thousands) Oil and gas revenues $5,508 $5,454 $3,169 Production expenses 1,721 1,363 926 Dry holes and abandonments 1,657 811 490 Exploration expenses 60 174 19 Depreciation, depletion and amortization 2,430 1,739 1,552 Writedown of properties 3,953 1,171 739 The Company has not entered into hedging arrangements and does not have any delivery commitments. While hedging arrangements reduce exposure to losses of resulting from unfavorable price changes, they also limit the ability to benefit from favorable market price changes. RESULTS OF OPERATIONS Comparison of Year Ended March 31, 2002 to Year Ended March 31, 2001 Contract drilling revenues for fiscal 2002 increased by 30% from fiscal 2001. Rig utilization rates in fiscal 2002 and 2001 were 67% and 68%, respectively. The increase in contract drilling revenues was due to an increase in the average prices received for contract drilling services. Rig utilization in the Company's operating market is difficult to project because of wide fluctuations in drilling activity. In addition, the number of rigs industry wide that are actually available for work cannot be accurately determined. Contract drilling expenses were 57% and 63% of contract drilling revenues in fiscal 2002 and 2001, respectively. The increase in contract drilling expenses was primarily due to higher labor and trucking costs. However, costs did not increase at the same rate as average rig rates. Oil and gas revenues remained relatively flat when comparing fiscal 2002 and 2001. Although quantities produced of oil and gas (on an equivalent -31- 33 barrel of oil basis) increased by approximately 36%, oil and gas revenues for fiscal 2002 were negatively affected by a decrease in prices received for crude oil and natural gas. The following table sets forth certain information relating to oil and gas revenues: Fiscal year ended March 31, ----------------- 2002 2001 ---- ---- Quantities ---------- Oil (bbls) 127,353 108,886 Gas (mcf) 707,923 428,355 Average Price ------------- Oil (bbls) $ 23.19 $ 31.14 Gas (mcf) $ 3.61 $ 4.82 Oil and gas production expenses increased by 26% and is a result of start up expenses for new wells coming on line coupled with an increase in the number of producing properties. In addition, the Company has experienced a general rise in the cost of services and supplies which are included in production expenses. The Company participated as a working-interest owner in the drilling of 13 wells during fiscal 2002, of which three were dry holes. In fiscal 2001, the Company participated as a working-interest owner in the drilling of 21 wells, of which nine were dry holes. Depreciation, depletion and amortization expense increased 31% due to several factors. The Company has been purchasing drill pipe and drill collars and has updated and refurbished drilling rigs and engines. The depreciable base of the Company's assets increased by approximately $19.0 million in fiscal 2002 and by approximately $12.3 million in fiscal 2001. Depreciation, depletion and amortization expense on oil and gas properties increased as a result of the increase in quantities of oil and gas produced as oil and gas properties are depleted using the units-of-production method. Also, depreciation, depletion and amortization expense on oil and gas properties increased as a result of the number of oil and gas producing properties in which the Company has an ownership interest (a total of 127 wells in fiscal 2002 versus 111 wells in 2001). General and administrative expenses increased approximately 56%. This increase is primarily due to an increase in payroll and insurance expenses. The Company recognized a non-cash charge of $4.0 million in fiscal 2002 and $1.2 million in fiscal 2001 related to the writedown of the carrying value of its oil and gas properties. -32- 34 Net working capital was $9.1 million at March 31, 2002, compared to $5.4 million at March 31, 2001. The increase in working capital is attributable to an increase in cash and a decrease in trade payables and other current liabilities. Comparison of Year Ended March 31, 2001 to Year Ended March 31, 2000 Contract drilling revenues for fiscal 2001 increased by 134% from fiscal 2000. Rig utilization rates in fiscal 2001 and 2000 were 68% and 35%, respectively. The increase in contract drilling revenues and utilization rates was due to an increase in oil and gas prices which in turn positively impacted demand for contract drilling. Drilling prices have steadily increased during the year ended March 31, 2001. Availability of experienced personnel has become a problem industry wide and certainly affects rig utilization. Historically, rig utilization in the Company's operating market is difficult to project because of wide fluctuations in drilling activity. In addition, the number of rigs industry wide that are actually available for work cannot be accurately determined. Contract drilling expenses were 63% and 81% of contract drilling revenues in fiscal 2001 and 2000, respectively. The decrease can be attributable to high start up costs that occurred in 2000. High start up costs are associated with putting rigs into service afer being idle or stacked for a period of time. Additionally, the decrease is a result of higher revenues due to increasing drilling prices. Oil and gas revenues increased by 72% in fiscal 2001. This increase is a result of an increase in prices received for crude oil and natural gas. The following table sets forth certain information relating to oil and gas revenues: Fiscal year ended March 31, ----------------- 2001 2000 ---- ---- Quantities ---------- Oil (bbls) 108,886 78,217 Gas (mcf) 428,355 611,901 Average Price ------------- Oil (bbls) $ 31.14 $ 21.12 Gas (mcf) $ 4.82 $ 2.48 -33- 35 The decline in natural gas production from the prior year is due to the plugging and abandonment of two non-operated natural gas wells in Ward County, Texas. Also, a recompletion of one well in Pecos County, Texas has negatively affected the current year's natural gas production. In addition, the Company's interest in a natural gas well in Lea County, New Mexico was reduced by 25% because the well reached "pay-out" status. Oil and gas production expenses increased by approximately 47%. This increase in production expenses can be attributed to the increased water production and workover on one well in Gaines County, Texas. In addition, the Company has experienced a general rise in the cost of services and supplies which are included in production expenses. Severance taxes increased along with the increase in oil and gas revenue. Also, the prior years results are affected by a recovery of an insurance claim concerning the loss of a well bore in Lea County, New Mexico. The production expenses in the prior year reflect this recovery. The Company participated as a working-interest owner in the drilling of 21 wells during fiscal 2001, of which nine were dry holes. In fiscal 2000, the Company participated as a working-interest owner in the drilling of 16 wells, of which 4 were dry holes. Depreciation, depletion and amortization expense increased due to several factors. The increase in rig utilization rates caused an increase in depreciation expense as drilling equipment is depreciated using the units-of- production method based on the monthly utilization of the equipment. During the year ended March 31, 2001, the Company purchased a BDW-800 rig with a depth capacity of approximately 16,000 feet. This rig was put in service on February 6, 2001. The addition of the rig brought the Company's available fleet to 19 rigs. Unfortunately, on April 12, 2001, an explosion, fire and subsequent blow-out destroyed one of our National 75A rigs that had a depth capacity of 12,500 feet. Three Company employees were injured as a result of the fire. Their injuries are covered under the Company's workers' compensation policy. The rig was insured in the amount of $750,000. As a result of the explosion, fire and subsequent blow-out, the Company has an available fleet of 18 drilling rigs. Also, during the year the Company purchased drill collars and drill pipe. During the year ended March 31, 2001, the Company recovered approximately $384,000 in bad debts that had been reserved in prior years. This amount is included in miscellaneous income. The Company recognized a non-cash charge of approximately $1.2 million in fiscal 2001 and $.7 million in fiscal 2000 related to the writedown of the carrying value of its oil and gas properties. Net working capital was $5.4 million at March 31, 2001, compared to $2.8 million at March 31, 2000. The increase in working capital is attributable to an increase in accounts receivable which relates to the increase in drilling activity. -34- 36 Income Taxes At March 31, 2002, the Company had approximately $47.2 million of unused net operating loss ("NOL") carryforwards for tax purposes. Use of these carryforwards is dependent upon the Company's ability to generate taxable earnings in future periods. These carryforwards began to expire in fiscal 2000 and approximately $5.7 million will expire in 2002. The Company's ability to utilize its NOL carryforwards may be substantially limited in the future under the Internal Revenue Code of 1986, as amended (the "Code"). If the Company experiences an ownership change under applicable provisions of the Code, the carryforward would be limited to an annual amount determined by specified interest rates and other variables. The Company does not believe an ownership change has occurred to date. The effective tax rates for fiscal 2002 and 2001 differ from the statutory tax rate of 34% primarily due to the utilization of NOLs. Tax expense is generally limited to alternative minimum tax. The Company utilizes an asset and liability approach for financial accounting and reporting for income taxes. The Company has a deferred tax asset primarily due to its NOL carryforwards. The Company has provided a valuation allowance for the entire balance of deferred tax assets as it is more likely than not that the deferred tax asset will not be realized. Liquidity and Capital Resources In June, 2000, the Company entered into a second amended and restated loan agreement with Wells Fargo Bank Texas, N.A. The loan agreement provides for a $5.0 million revolving line of credit facility, of which $5.0 million was available at June 7, 2002. The facility is secured by the Company's drilling rigs and related equipment, accounts receivable and inventory. Borrowings under the revolving facility bear interest at an annual rate equal to the bank's base rate, or 4.75% at June 7, 2002. Accrued and unpaid interest on outstanding principal is payable monthly. The loan facility matures on August 31, 2003, at which time all outstanding principal and accrued and unpaid interest will be due and payable in full. At March 31, 2002, no amounts were outstanding under the loan facility. The principal amount outstanding at any one time may not exceed the lesser of $5.0 million or one- third of the borrowing base amount. The borrowing base amount is the sum of the Company's accounts receivable and the value of its inventory, drilling rigs, drill pipe and related equipment. The borrowing base amount is redetermined quarterly by the Company, except that the bank may, in its discretion, make its own determination of the borrowing base which will be the controlling borrowing base amount. At March 31, 2002, the borrowing base amount was $39,565,779. In addition to certain customary affirmative covenants, the loan agreement contains restrictions with respect to (i) incurring additional debt, incurring or permitting liens to exist on any of the Company's property, -35- 37 assets or revenues, (ii) declaring or paying dividends or other distributions on its capital stock (or acquiring any of its capital stock), (iii) issuing capital stock, (iv) entering into transactions with affiliates, (v) disposing of assets, and (vi) certain other matters. The loan agreement also contains financial covenants with respect to minimum tangible net worth, the current ratio and the ratio of total liabilities to net worth. The Company anticipates that funds for its capital expenditures in fiscal 2003 will be available from a combination of sources, including (i) borrowings under the line of credit , (ii) funds raised through issuances of equity or debt securities in public or private transactions, and (iii) internally generated funds. The following table sets forth information regarding the capital expenditures made by the Company during the last three fiscal years. Year Ended March 31, -------------------------- 2002 2001 2000 ---- ---- ---- (In thousands) Oil and gas exploration and development..... $12,183 $ 7,596 $ 2,904 Drilling rigs, drill pipe and related equipment......................... 6,201 4,139 3,149 Other....................................... 703 586 199 ------ ------ ------ Total.................................. $19,087 $ 12,321 $ 6,252 ====== ====== ====== The Company presently anticipates making capital expenditures of approximately $11.5 million in its 2003 fiscal year. Of this amount, the Company expects that approximately $4.0 million will be spent for the acquisition of drill pipe, drill collars and related equipment, and approximately $7.0 million for oil and gas exploration and development activities. It is the Company's policy, however, to make capital expenditures based on prevailing economic conditions, the results of its drilling activities, and other factors affecting its business. Accordingly, the amounts actually spent in fiscal 2003 could differ substantially from the amounts estimated. Trends and Prices The contract drilling industry is currently experiencing decreased demand and decreasing prices for contract drilling services due to the instability of oil and gas prices. The Company will be affected by price fluctuations in the industry, but cannot predict either the future level of demand for its contract drilling services or future conditions in the contract drilling industry. In recent years, oil and gas prices have been extremely volatile. Prices are affected by market supply and demand factors as well as by actions of -36- 38 state and local agencies, the U.S. and foreign governments and international cartels. The Company has no way of accurately predicting the supply of and demand for oil and gas, domestic or international political events or the effects of any such factors on the prices received by the Company for its oil and gas. Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK The primary sources of market risk for the Company include fluctuations in commodity prices and interest rate fluctuations. At March 31, 2002, the Company had not entered into any hedge arrangements, commodity swap agreements, commodity futures, options or other similar agreements relating to crude oil and natural gas. Commodity Price Risk - The Company produces and sells crude oil, natural gas and natural gas liquids. As a result, its operating results are significantly affected by fluctuations in commodity prices caused by changing market forces. Historically, the Company has not entered into hedging arrangements for its oil and gas production and it does not have any delivery commitments. The Company may, in the future, attempt to reduce its exposure to the volatility of oil and gas prices by hedging a portion of its production. In a typical hedge transaction, the Company would have the right to receive from the counterparty to the hedge, the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedge. If the floating price exceeds the fixed price, the Company would be required to pay the counterparty this difference multiplied by the quantity hedged. In the case, the Company would be required to pay the difference regardless of whether it had sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require the Company to make payments under the hedge agreements even though such payments are not offset by sales of production. Hedging could also prevent the hedging party from receiving the full advantage of increases in oil and gas prices above the fixed amount specified in the hedge. Interest Rate Risk - At March 31, 2002 the Company had no borrowings outstanding under its loan agreement. However, when it does have outstanding borrowings, the Company's exposure to changes in interest rates primarily results from short term changes in its bank's prime rate. -37- 39 Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Page ---- Reports of Independent Public Accountants 39 Balance Sheets, March 31, 2002 and 2001 41 Statements of Operations, Years ended March 31, 2002, 2001 and 2000 43 Statements of Stockholders' Equity, Years ended March 31, 2002, 2001 and 2000 44 Statements of Cash Flows, Years ended March 31, 2002, 2001 and 2000 45 Notes to Financial Statements 46 -38- 40 Independent Auditors' Report The Board of Directors TMBR/Sharp Drilling, Inc.: We have audited the accompanying balance sheet of TMBR/Sharp Drilling, Inc. as of March 31, 2002, and the related statements of operations, stockholders' equity, and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of TMBR/Sharp Drilling, Inc. as of March 31, 2002, and the results of its operations and its cash flows then ended in conformity with accounting principles generally accepted in the United States of America. Our audits were made for the purpose of forming an opinion on the basic financial statements take as a whole. The supplementary information included in Schedule II required by the Securities and Exchange Commission is presented for purposes of additional analysis and is not a required part of the basic financial statements. Such information has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, is fairly stated in all material respects in relation to the basic financial statements taken as a whole. KPMG LLP June 24, 2002 Midland, Texas -39- 41 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS This report was issued by Arthur Andersen LLP in connection with the Company's 2001 Form 10-K and has not been reissued by Arthur Andersen LLP. To the Board of Directors and Stockholders of TMBR/Sharp Drilling, Inc.: We have audited the accompanying balance sheets of TMBR/Sharp Drilling, Inc. (a Texas corporation) as of March 31, 2001 and 2000, and the related statements of operations, stockholders' equity and cash flows for each of the three years in the period ended March 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of TMBR/Sharp Drilling, Inc. as of March 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended March 31, 2001, in conformity with accounting principles generally accepted in the United States. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index at Item 14(a)2 is presented for purposes of complying with the Securities and Exchange Commission's rules and is not a part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN LLP Dallas, Texas, May 18, 2001 -40- 42 TMBR/SHARP DRILLING, INC. Balance Sheets March 31, 2002 and 2001 (In thousands, except share data) ASSETS 2002 2001 ------ ---- ---- Current assets: Cash and cash equivalents $ 3,258 $ 301 Marketable securities 97 91 Trade receivables, net of allowance for doubtful accounts of $1,401 in 2002 and $1,227 in 2001. 11,011 13,625 Inventories 162 148 Deposits 346 73 Other 1,018 871 ------ ------ Total current assets 15,892 15,109 ------ ------ Property and equipment, at cost: Drilling equipment 61,370 55,599 Oil and gas properties, based on successful efforts accounting 34,616 26,372 Other property and equipment 3,531 2,844 ------ ------ 99,517 84,815 Less accumulated depreciation, depletion and amortization (72,947) (64,696) ------ ------ Net property and equipment 26,570 20,119 ------ ------ Other assets 173 173 ------ ------ Total assets $ 42,635 $ 35,401 ====== ====== See accompanying notes to financial statements. -41- 43 TMBR/SHARP DRILLING, INC. Balance Sheets March 31, 2002 and 2001 (In thousands, except share data) LIABILITIES AND STOCKHOLDERS' EQUITY 2002 2001 ------------------------------------ ---- ---- Current liabilities: Trade payables $ 5,193 $ 7,414 Other 1,610 2,301 ------ ------ Total current liabilities 6,803 9,715 Long Term liabilities: Borrowings from bank -- 1,080 ------ ------ Total liabilities 6,803 10,795 ------ ------ Contingencies Stockholders' equity: Common stock, $0.10 par value Authorized, 50,000,000 shares; issued, 6,667,725 and 6,332,225 shares at March 31, 2002 and 2001, respectively 667 633 Additional paid-in capital 71,492 70,122 Accumulated deficit (36,187) (46,003) Accumulated other comprehensive income (loss) 10 4 Treasury stock-common, 1,268,739 shares at March 31, 2002, and 2001, at cost (150) (150) ------ ------ Total stockholders' equity 35,832 24,606 ------ ------ Total liabilities and stockholders' equity $ 42,635 $ 35,401 ====== ====== See accompanying notes to financial statements. -42- 44 TMBR/SHARP DRILLING,, INC. Statements of Operations Years Ended March 31, 2002, 2001 and 2000 (In thousands, except share data) 2002 2001 2000 ---- ---- ---- Revenues: Contract drilling $ 46,712 $ 36,023 $ 15,394 Oil and gas 5,508 5,454 3,169 ------ ------ ------ Total revenues 52,220 41,477 18,563 ------ ------ ------ Operating costs and expenses: Contract drilling 26,761 22,767 12,486 Oil and gas production 1,721 1,363 926 Dry holes and abandonments 1,657 811 490 Exploration 60 174 19 Depreciation, depletion and amortization 6,746 5,137 3,282 Writedown of oil and gas properties 3,953 1,171 739 General and administrative 2,552 1,918 1,854 ------ ------ ------ Total operating costs and expenses 43,450 33,341 19,796 ------ ------ ------ Operating income (loss) 8,770 8,136 (1,233) ------ ------ ------ Other income (expense): Interest 11 (216) 17 Gain on sales of assets 537 256 137 Other, net 498 302 (128) ------ ------ ------ Total other income (expense), net 1,046 342 26 ------ ------ ------ Net income (loss) before income tax provision 9,816 8,478 (1,207) Provision for income taxes -- (170) -- ------ ------ ------ Net income (loss) $ 9,816 $ 8,308 $ (1,207) ====== ====== ====== Net income (loss) per common share: Basic $ 1.88 $ 1.67 $ (0.25) Diluted 1.79 1.54 (0.25) ========= ========= ========= Weighted average number of common shares outstanding: Basic 5,220,047 4,979,082 4,760,704 Diluted 5,473,994 5,391,934 4,760,704 ========= ========= ========= See accompanying notes to financial statements. -43- 45 TMBR/SHARP DRILLING, INC. Statements of Stockholders' Equity Years Ended March 31, 2002, 2001 and 2000 (In thousands)
Accumulated Common Stock Additional Other Treasury Stock Total ------------ Paid-In Accumulated Comprehensive --------------- Stockholders' Shares Amount Capital Deficit (Loss) Income Shares Amount Equity ------ ------ ---------- ----------- ------------- ------ ------ ------------- Balance, March 31, 1999 5,980 598 69,429 (53,104) (38) 1,270 (150) 16,735 Exercise of Stock Options 247 25 146 -- -- -- -- 171 Grant of Stock Options -- -- 97 -- -- -- -- 97 Net Loss -- -- -- (1,207) -- -- -- (1,207) ----- ----- -------- -------- ----- ----- ----- -------- Balance, March 31, 2000 6,227 $ 623 $ 69,672 $ (54,311) $(38) 1,270 $(150) $ 15,796 Exercise of Stock Options 105 10 450 -- -- -- -- 460 Net Income -- -- -- 8,308 -- -- -- 8,308 Other comprehensive income, net of tax Unrealized gain on marketable equity securities -- -- -- -- 42 -- -- 42 -------- Comprehensive Income 8,350 ----- ----- -------- -------- ----- ----- ----- -------- Balance, March 31, 2001 6,332 $ 633 $ 70,122 $ (46,003) $ 4 1,270 $(150) $ 24,606 ----- ----- -------- -------- ----- ----- ----- -------- Exercise of Stock Options 329 33 1,295 -- -- -- -- 1,328 Director Stock Award 7 1 75 -- -- -- -- 76 Net Income -- -- -- 9,816 -- -- -- 9,816 46 Other comprehensive income, net of tax Unrealized gain on marketable equity securities -- -- -- -- 6 -- -- 6 -------- Comprehensive Income 9,822 ----- ----- -------- -------- ----- ----- ----- -------- Balance, March 31, 2002 6,668 $ 667 $ 71,492 $ (36,187) $ 10 1,270 $(150) $ 35,832 ===== ===== ======== ======== ===== ===== ===== ========
See accompanying notes to financial statements. -44- 47 TMBR/SHARP DRILLING, INC. Statements of Cash Flows Years Ended March 31, 2002, 2001 and 2000 (In thousands) 2002 2001 2000 ---- ---- ---- Cash flows from operating activities: Net income (loss) $ 9,816 $ 8,308 $ (1,207) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization 6,746 5,137 3,282 Dry holes and abandonments 1,657 811 490 Gain on sales of assets (537) (256) (137) Grant of stock options -- -- 97 Writedown of properties 3,953 1,171 739 Changes in assets and liabilities: Trade receivables 2,615 (7,227) (2,947) Inventories and other assets (435) (212) (246) Trade payables (2,221) 3,174 2,816 Accrued payables and other current liabilities (691) 962 575 -------- -------- -------- Total adjustments 11,087 3,560 4,669 -------- -------- -------- Net cash provided by operating activities 20,903 11,868 3,462 -------- -------- -------- Cash flows from investing activities: Additions to property and equipment (19,087) (12,321) (6,252) Proceeds from sales of property and equipment 817 484 154 -------- -------- -------- Net cash required by investing activities (18,270) (11,837) (6,098) -------- -------- -------- Cash flows from financing activities: Proceeds from exercise of stock options 1,328 460 171 Proceed from issuance of common stock 76 -- -- Proceeds (repayments) from bank loan, net (1,080) (1,170) 2,250 -------- -------- -------- Net cash provided (required) by financing activities 324 (710) 2,421 -------- -------- -------- Net increase (decrease) in cash and cash equivalents 2,957 (679) (215) Cash and cash equivalents at beginning of year 301 980 1,195 -------- -------- -------- Cash and cash equivalents at end of year $ 3,258 $ 301 $ 980 ======== ======== ======== See accompanying notes to financial statements. -45- 48 TMBR/SHARP DRILLING, INC. Notes to Financial Statements (1) Organization, Nature of Business and Summary of Significant Accounting Policies Nature of Operations TMBR/Sharp Drilling, Inc. (the "Company") was incorporated under the laws of Texas in October, 1982 under the name TMBR Drilling, Inc. In August, 1986, the Company changed its name to TMBR/Sharp Drilling, Inc. The Company's principal businesses are the domestic onshore contract drilling of oil and gas wells for major and independent oil and gas producers, and, to a lesser extent, the exploration for, development and production of oil and natural gas. The Company's drilling activities are primarily conducted in the Permian Basin of west Texas and eastern New Mexico. Cash and Cash Equivalents For purposes of the statements of cash flows, the Company considers highly liquid debt instruments which have an original maturity of three months or less to be cash equivalents. Cash payments for interest expense were approximately $21,000 for 2002 and $270,000 for 2001 and $15,000 in 2000. Cash payments for taxes due totaled $160,000,$0, and $0, during 2002, 2001 and 2000, respectively. Marketable Securities Under SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities", marketable securities, such as those owned by the Company, are classified as available-for-sale securities and are to be reported at market value, with unrealized gains and losses, net of income taxes, excluded from earnings and reported as a separate component of stockholders' equity. The market value of these securities at March 31, 2002 was approximately $97,000. An unrealized gain of approximately $6,000 was added to stockholders equity and was included as a component of other comprehensive income. -46- 49 TMBR/SHARP DRILLING, INC. Notes to Financial Statements Inventories Inventories consist primarily of casing and tubing. The Company values its inventories at the lower of cost or estimated net recoverable value using the specific identification method. Property and Equipment Drilling equipment is depreciated on a units-of-production method based on the monthly utilization of the equipment. Drilling equipment which is not utilized during a month is depreciated using a minimum utilization rate of approximately twenty-five percent. Estimated useful lives range from four to eight years. Other property and equipment is depreciated using the straight- line method of depreciation with estimated useful lives of three to seven years. Oil and gas properties are accounted for using the successful efforts method of accounting. Accordingly, the costs incurred to acquire property (proved and unproved), all development costs and successful exploratory costs are capitalized, whereas the costs of unsuccessful exploratory wells are expensed. Geological and geophysical costs, including seismic costs, are charged to expense when incurred. In cases where the Company provides contract drilling services related to oil and gas properties in which it has an ownership interest, the Company's proportionate share of costs related to these properties is capitalized as stated above, net of the Company's working interest share of profits from the related drilling contracts. Capitalized costs of undeveloped properties, which are not depleted until proved reserves can be associated with the properties, are periodically reviewed for possible impairment. Such unevaluated costs totaled approximately $1,967,000 and $845,000 as of March 31, 2002 and 2001, respectively. Depletion, depreciation and amortization of capitalized oil and gas property costs is provided using the units-of-production method based on estimated proved or proved developed oil and gas reserves, as applicable, of the respective property units. Prior to 1996, the Company provided impairments for significant proved oil and gas properties to the extent that net capitalized costs exceeded aggregated undiscounted future net cash flows. During 1996, the Company adopted Statement of Financial Accounting Standards No. 121 ("SFAS 121"), -47- 50 TMBR/SHARP DRILLING, INC. Notes to Financial Statements "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of". SFAS 121 requires the Company to assess the need for an impairment of capitalized costs of oil and gas properties on a property-by- property basis. According to SFAS 121, if an impairment is indicated based on undiscounted expected future cash flows, then it is recognized to the extent that net capitalized costs exceed discounted future cash flows. Impairments of $3,953,000, $1,171,000 and $739,000 were recorded in 2002, 2001 and 2000, respectively. Management's estimate of future cash flows is based on their estimate of reserves and prices. It is reasonably possible that a change in reserve or price estimates could occur in the near term and adversely impact management's estimate of future cash flows and consequently the carrying value of properties. Major renewals and betterments are capitalized in the appropriate property accounts while the cost of repairs and maintenance is charged to operating expense in the period incurred. For assets sold or otherwise retired, the cost and related accumulated depreciation amounts are removed from the accounts and any resulting gain or loss is recognized. Drilling Revenues and Costs Drilling revenues from footage and daywork contracts are recognized as work is performed utilizing the percentage-of-completion method. Costs on footage and daywork contracts are recognized in the period incurred. The Company utilizes the completed contract method to recognize drilling revenues and expenses relating to turnkey contracts. Expected losses on all in- process contracts are recognized in the period the loss can reasonably be determined. Risks and Uncertainties 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. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve volumes and the related present value of estimated future net revenues therefrom (see Note 9), the valuation allowance for deferred taxes (see Note 4), the provision for doubtful accounts, and the reserve for the Company's portion of workers compensation claims. -48- 51 TMBR/SHARP DRILLING, INC. Notes to Financial Statements Net Income (Loss) Per Share of Common Stock On April 1, 1997, the Company adopted Statement of Financial Accounting Standards No. 128 ("SFAS 128") "Earnings Per Share" which superseded Accounting Principles Board Opinion No. 15 ("APB 15") "Earnings Per Share." SFAS 128 simplifies earnings per share ("EPS") calculations by replacing previously reported primary EPS with basic EPS which is calculated by dividing reported earnings available to common shareholders by the weighted average shares outstanding. No dilution for potentially dilutive securities is included in basic EPS. Previously reported fully diluted EPS is called diluted EPS which includes all potentially dilutive securities. The following table sets forth certain information concerning EPS. For the Year Ended 2002 --------------------------------- Per Share Income Shares Amount ------ ------ --------- Income before extraordinary item and accounting change $9,816 Basic EPS Income available to common stockholders 9,816 5,220,047 $1.88 ==== Effect of Dilutive Securities Stock Options 253,947 ----- --------- Diluted EPS Income available to common stockholders + assumed conversions $9,816 5,473,994 $1.79 ===== ========= ==== Common stock equivalents for 2000 and 2001 were anti-dilutive. -49- 52 TMBR/SHARP DRILLING, INC. Notes to Financial Statements Stock Based Employee Compensation In October 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 123 ("SFAS 123") "Accounting for Stock-Based Compensation," which establishes accounting and reporting standards for various stock based compensation plans. SFAS 123 encourages the adoption of a fair value based method of accounting for employee stock options, but permits continued application of the accounting method prescribed by Accounting Principles Board Opinion No. 25 ("Opinion 25"), "Accounting for Stock Issued to Employees." The Company has elected to continue to apply the provisions of Opinion 25. Under Opinion 25, if the exercise price of the Company's stock options equals the market value of the underlying stock on the date of grant, no compensation expense is recognized. SFAS 123 requires disclosure of pro forma information regarding net income and earnings per share as if the Company had accounted for its employee stock options under the fair value method of the statement. See Note 3 "Stockholders' Equity." Recent Accounting Pronouncements In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Certain Hedging Activities." In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activity, an Amendment of SFAS 133." SFAS No. 133 and SFAS No. 138 require that all derivative instruments be recorded on the balance sheet at their respective fair values. SFAS No. 133 and SFAS No. 138 are effective for all fiscal quarters of all fiscal years beginning after June 30, 2000; the Company adopted SFAS No. 133 and SFAS No. 138 on April 1, 2001. There was no material impact to the financial statements. In July 2001, the FASB issued Statements of Financial Accounting Standards No. 141, "Business Combinations" and No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 requires that all business combinations initiated after June 30, 2001 be accounted for under the purchase method and SFAS No. 142 requires that goodwill no longer be amortized to earnings, but instead be reviewed for impairment. The adoption of SFAS 141 and 142 did not have any impact on the Company. -50- 53 TMBR/SHARP DRILLING, INC. Notes to Financial Statements Also, the FASB has issued SFAS No. 143, "Accounting for Asset Retirement Obligations" which establishes requirements for the accounting of removal- type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Company is currently assessing the impact on its financial statements. On October 3, 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This pronouncement supercedes SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long- Lived Assets to Be Disposed" and eliminates the requirement for SFAS 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Company is currently assessing the impact to its financial statements. (2) Debt Line of Credit In May, 1998, the Company entered into a loan agreement with its bank lender which provides for a $5.0 million revolving line of credit secured by substantially all of the Company's drilling rigs and related equipment, accounts receivable and inventory. Borrowings under the line of credit bore interest at the bank's base rate and accrued interest was payable monthly. The loan facility originally matured on May 26, 2000 but was extended to July 15, 2000. -51- 54 TMBR/SHARP DRILLING, INC. Notes to Financial Statements On June 26, 2000, the Company renewed and extended the prior loan agreements with its bank lender. The second and restated agreement provides for a $5.0 million revolving line of credit secured by the Company's drilling rigs and related equipment, accounts receivable and inventory. Borrowings under this line of credit bear interest at the Wells Fargo Bank Texas, N. A. (formerly Norwest Bank, Texas N.A.) base rate (4.75% at March 31, 2002) and accrued interest is payable monthly. The loan facility originally matured on August 31, 2002. On February 12, 2002, the maturity date of the loan facility was extended to August 31, 2003, at which time all outstanding principal and interest will be due in full. At March 31, 2002, no amounts were outstanding under the loan facility. (3) Stockholders' Equity (a) Common Stock On February 13, 1997, the Company closed a private placement of 725,000 shares of common stock at a price of $11.00 per share. The net proceeds from the placement were approximately $7.4 million. (b) Stock Option Plans 1984 Stock Option Plan In August, 1984, the Company adopted the 1984 Stock Option Plan (the "Plan") which initially authorized 375,000 shares of the Company's common stock to be issued as either incentive stock options or nonqualified stock options. This Plan was amended in August 1986 to increase the authorized shares to 475,000 shares of the Company's common stock. In January 1988, the Plan was amended to reduce the option price on certain options issued prior to March 31, 1986, to reflect the then current fair market value of the Company's common stock. The Plan provides that options may be granted to key employees or directors for various terms at a price not less than the fair market value of the shares on the date of the grant. Options to purchase 5,000 shares of common stock are currently exercisable and outstanding under the Plan. No additional shares are available for grant as the Plan expired by its own terms in August 1994. The options that were granted prior to the expiration of the Plan, and which are outstanding, remain subject to the terms of the Plan. -52- 55 TMBR/SHARP DRILLING, INC. Notes to Financial Statements 1994 Stock Option Plan In July 1994, the Company adopted its 1994 Stock Option Plan (the "1994 Plan") which authorized the grant of options to purchase up to 750,000 shares of the Company's common stock. These options may be issued as either incentive or nonqualified stock options. The 1994 Plan provides that options may be granted to key employees or directors for various terms at a price not less than the fair market value of the shares on the date of grant. The 1994 Plan was ratified and approved by the stockholders at the Company's annual meeting of stockholders held on August 30, 1994. In September 1998, options outstanding under the plan were amended to reduce the option price to $4.125 per share. On September 3, 1996, the Company granted 465,000 shares of nonqualified stock options to key employees under the 1994 Plan. All of the nonqualified stock options granted on September 3, 1996 are earned and exercisable as of May 1, 1997. On September 1, 1998, the Company granted 240,000 shares of incentive stock options at a price of $4.125 to key employees under the 1994 Plan. On March 9, 2002, all of the shares were earned and exercisable. The following sets forth certain information concerning these options. Number Option Price of ----------------------- Shares Per Share Total ------ ----------------------- Outstanding March 31, 2000 564,500 $4.125-4.5375 $ 2,387,963 Exercised (80,100) 4.125-4.5375 (357,638) ------- ------------ --------- Outstanding March 31, 2001 484,400 $4.125-4.5375 $ 2,030,325 Exercised (234,000) 4.125-4.5375 (994,950) ------- ------------ --------- Outstanding March 31, 2002 250,400 $4.125-4.5375 $ 1,035,375 ======= ============ ========== -53- 56 TMBR/SHARP DRILLING, INC. Notes to Financial Statements 1998 Stock Option Plan In September 1998, the Company adopted, subject to shareholder approval, its 1998 Stock Option Plan (the "1998 Plan") which authorizes the grant of options to purchase up to 750,000 shares of the Company's common stock. These options may be issued as either incentive or nonqualified stock options. The 1998 Plan provides that options may be granted to key employees or directors from various terms at a price not less than the fair market value of the shares on the date of grant. The Company granted options to purchase 50,000 shares of common stock to two outside directors under the 1998 Plan, subject to shareholder approval. These nonqualified options were granted at $4.125 per share and became exercisable on August 31, 1999, the date on which the shareholders of the Company approved and adopted the 1998 Plan. The fair market value of the Company's common stock on August 31, 1999 was $6.063 per share. As a result, the Company recognized approximately $97,000 in compensation expense related to these nonqualified options during the year ended March 31, 2000. On June 13, 2001, the Company granted options to purchase 40,000 shares of common stock to four directors under the 1998 Plan. The nonqualified options were granted at an exercise price of $17.18 per share which represented the fair market value on the date of the grant. On October 10, 2001, the Company granted options to purchase 292,000 shares of common stock to key employees under the 1998 Plan. These incentive options were granted at an exercise price of $11.50 per share which represented the fair market value on the date of the grant. These options become exercisable over a two year period ending October 10, 2003. At March 31, 2002, options to purchase 332,000 shares were outstanding under the 1998 Plan. Directors' Fee Stock Plan On June 13, 2001, the Company adopted the Directors' Fee Stock Plan (the "Plan") which authorizes the issuance of up to 25,000 shares of the Company's common stock. The Plan provides that 300 shares of the Company's common stock will be issued to each Non-employee Director for each Board of Directors' meeting attended and 100 shares of common stock to each Non- employee Director for each committee meeting attended. During the year ended March 31, 2002, 6,500 shares have been issued under the Plan and the Company recognized approximately $95,000 as Directors' compensation expense. In connection with a private placement completed in February 1997, the Company issued and currently has outstanding a warrant to purchase 36,250 common shares with an exercise price of $13.20 per share. This warrant became exercisable on February 17, 1998, and expired unexercised on February 17, 2002. -54- 57 TMBR/SHARP DRILLING, INC. Notes to Financial Statements Pursuant to SFAS 123, "Accounting for Stock-Based Compensation," the Company has elected to account for its stock option plans under Opinion No. 25, "Accounting for Stock Issued to Employees." Accordingly no compensation expense has been recognized for these stock option plans. Pro forma information regarding net income and earnings per share is required by SFAS 123, and has been determined as if the Company had accounted for its employee stock options under the fair value method of that statement. The fair value of each option grant is estimated on the date of the grant using the Black- Scholes option pricing model with the following weighted-average assumptions used for grants in fiscal 2002, 2000 and 1999, respectively: dividend yield of 0%, 0% and 0%, expected volatility of 64.7%, 62.53% and 54.68%, risk free interest rate of 4.81%, 6.09% and 4.99%, and an expected life of 5.0, 5.0 and 5.0 years. Year of Option Exercise Expected Fair Grant Shares Price Life Value ------- ------ -------- -------- ----- 1999 96,000 $4.125 5.0 $2.17 1999 144,000 $4.5375 5.0 $2.07 2000 50,000 $4.125 5.0 $2.15 2002 40,000 $17.18 5.0 $10.09 2002 292,000 $11.50 5.0 $6.63 For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options' vesting period. The Company's pro forma information follows: 2002 2001 2000 ---------------- --------------- --------------- As Pro As Pro As Pro Reported Forma Reported Forma Reported Forma -------- ----- -------- ----- -------- ----- (In thousands, except share amounts) Net income (loss) from continuing operations $ 9,816 $ 9,413 $ 8,308 $ 8,217 $(1,207) $(1,309) Net income (loss) from continuing operations per share (basic) $ 1.88 $ 1.80 $ 1.67 $ 1.65 $(0.25) $(0.27) -55- 58 TMBR/SHARP DRILLING, INC. Notes to Financial Statements The effects of applying SFAS 123 in this pro forma disclosure are not indicative of future amounts, as SFAS 123 does not apply to awards prior to 1995 and additional awards are anticipated in future years. (4) Income Taxes At March 31, 2002, the Company had approximately $47,209,767 of net operating loss carryforwards for tax purposes. Realization of the benefits of these carryforwards is dependent upon the Company's ability to generate taxable earnings in future periods. These carryforwards began to expire in fiscal 2000 and approximately $5.7 million will expire in 2002. The Company's ability to utilize its net operating loss carryforwards may be substantially limited in the future under Section 382 of the Internal Revenue Code ("IRC"). If the Company encounters a change of control as defined in IRC Section 382, the carryforward would be limited to an annual amount calculated based on market value. The Company does not believe a change of control, as defined, has occurred to date. The Company utilizes an asset and liability approach for financial accounting and reporting for income taxes. The major components of deferred tax assets and liabilities follows: March 31, 2002 March 31, 2001 -------------- -------------- Deferred Tax Assets (Liabilities) Federal NOL Carryforwards $ 16,051,321 $ 24,839,381 Allowance for Bad Debts 476,347 417,313 Book over tax depreciation and amortization 1,075,043 961,341 Accrued Workers Compensation 255,547 320,782 Other accrued expenses 5,471 7,695 ---------- ---------- Total deferred tax assets 17,863,729 26,546,512 Valuation allowance (17,863,729) (26,546,512) ---------- ---------- Net deferred tax asset $ -- $ -- ========== ========== -56- 59 TMBR/SHARP DRILLING, INC. Notes to Financial Statements The Company has provided a valuation allowance for the entire balance of deferred tax assets at March 31, 2002 and 2001, as it is more likely than not that the deferred tax asset will not be realized. The effective tax rates for the years ended March 31, 2002, 2001 and 2000 differ from the statutory tax rate of 34% primarily due to utilization of net operating loss carryforwards. Tax expense is generally limited to alternative minimum tax. The following table sets forth a reconciliation of the tax provision using statutory rates to the actual tax provision provided in the statements of operations: 2002 2001 2000 ---- ---- ---- Tax provision (benefit) utilizing statutory rates $ 3,338 $ 2,882 $ (410) Utilization of NOL (3,338) (2,712) 410 ----- ----- ----- Tax provision $ -- $ 170 $ -- ===== ===== ===== (5) Related Parties During 2002, 2001 and 2000, the Company sold $210,000, $701,000 and $1,936,000 and purchased $726,000, $154,000 and $81,000, respectively, of goods and services from entities affiliated with individuals serving as officers and/or directors of the Company. These purchases and sales are transacted using market rates. These transactions are included in "contract drilling revenue" and "contract drilling expense" or "other income or expense" in the accompanying statements of operations. The related party transactions discussed in the preceding paragraph are noninterest-bearing and are settled in the normal course of business. -57- 60 TMBR/SHARP DRILLING, INC. Notes to Financial Statements (6) Business Segments and Significant Customers The Company adopted SFAS No. 131, "Disclosures About Segments of an Enterprise and Related Information", in 1999 which changes the way the Company reports information about its operating segments. The Company operates in two reportable segments: (i) drilling and (ii) oil and gas exploration and development. The long-term financial performance of each of the reportable segments is affected by similar economic conditions. Both reportable segments operate in the Permian Basin of West Texas and Eastern New Mexico. The accounting policies of the segments are the same as those described in Note (1) of Notes to Financial Statements. The Company evaluates performance based on profit or loss from operations before income taxes, accounting changes, nonrecurring items and interest income and expense. The Company accounts for intersegment sales transfers as if the sales or transfers were to third parties, that is, at current prices. -58- 61 TMBR/SHARP DRILLING, INC. Notes to Financial Statements The following tables present information related to the Companies' reportable segments. Years Ended March 31, ---------------------------------------- 2002 2001 2000 ---------- ---------- ---------- (In thousands) Revenues: Contract drilling $ 46,712 $ 36,023 $ 15,394 Oil and gas 5,508 5,454 3,169 -------- -------- -------- $ 52,220 $ 41,477 $ 18,563 ======== ======== ======== Net income (loss) (a): Contract drilling $ 14,339 $ 8,660 $ (333) Oil and gas (4,534) 34 (891) -------- -------- -------- 9,805 8,694 (1,224) Corporate income (expenses) (b) 11 (216) 17 -------- -------- -------- $ 9,816 $ 8,478 $ (1,207) ======== ======== ======== Identifiable assets: Contract drilling $ 23,824 $ 23,414 $ 16,350 Oil and gas 14,264 10,551 5,277 -------- -------- -------- 38,088 33,965 21,627 Corporate assets (c) 4,547 1,436 1,998 -------- -------- -------- $ 42,635 $ 35,401 $ 23,625 ======== ======== ======== Depreciation, depletion and amortization: Contract drilling $ 4,316 $ 3,398 $ 1,730 Oil and gas 2,430 1,739 1,552 -------- -------- -------- $ 6,746 $ 5,137 $ 3,282 ======== ======== ======== Capital expenditures: Contract drilling $ 6,904 $ 4,725 $ 3,348 Oil and gas 12,183 7,596 2,904 -------- -------- -------- $ 19,087 $ 12,321 $ 6,252 ======== ======== ======== -59- 62 TMBR/SHARP DRILLING, INC. Notes to Financial Statements (a) General and administrative costs and other income are allocated between segments based on identifiable assets. (b) Corporate income and expenses consist of interest income and expense. (c) Corporate assets are those assets which are not specifically identifiable with a segment and consist primarily of cash and cash equivalents, short-term investments and prepaid expenses. For the years ended March 31, 2002, 2001 and 2000, contract drilling revenues earned from individual customers constituting 10% or more of total contract drilling revenues were: (a) one drilling customer in 2002 individually represented approximately 38% of total revenues, (b) two drilling customers in 2001 individually represented approximately 35%, and 13% of total revenues, (c) two drilling customers in 2000 individually represented approximately 17%, and 13% of total revenues. The loss of one or more of the above customers could have a material adverse effect on the Company, depending upon the demand for drilling rigs at the time of such loss and the Company's ability to find new customers. (7) Contingencies Currently the Company is covered under a three year retroactive plan and is providing for its workers compensation claims based upon the most recent information available from its insurance carrier concerning claims and estimated costs. In future years, the Company may receive retroactive adjustments, both favorable and unfavorable, related to estimates of claim costs for previous years, which may be material to the Company's results of operations. No provision for retroactive adjustments to claim costs is recorded until the Company receives notification from its insurance carrier because this amount, if any, cannot be estimated. From September 1997 to September 2000, the Company was covered by a fully insured workers' compensation policy. -60- 63 TMBR/SHARP DRILLING, INC. Notes to Financial Statements The Company is a defendant in various lawsuits generally incidental to its business. The Company does not believe that the ultimate resolution of such litigation will have a significant effect on the Company's financial position or results of operations. (8) Supplemental Information Related to Oil and Gas Activities The Company's capitalized cost of oil and gas properties is as follows: March 31, --------- 2002 2001 ---- ---- (In thousands) Oil and gas properties $34,616 $26,372 Accumulated depreciation, depletion and amortization (21,583) (17,283) ------- ------- $13,033 $ 9,089 ======= ======= The Company's costs incurred related to oil and gas property acquisition, exploration and development activities are as follows: Years Ended March 31, --------------------- 2002 2001 2000 ---- ---- ---- (In thousands) Property acquisition costs $ 1,290 $ 717 $ 406 Exploration costs 8,463 5,300 2,389 Development costs 2,430 1,579 109 ------- ------- ------- $12,183 $ 7,596 $ 2,904 ======= ======= ======= -61- 64 TMBR/SHARP DRILLING, INC. Notes to Financial Statements The Company's results of operations from oil and gas producing activities are as follows: Years Ended March 31, --------------------- 2002 2001 2000 ---- ---- ---- (In thousands) Revenues $ 5,508 $ 5,454 $ 3,169 Production costs 1,721 1,363 926 Dry holes and abandonments 1,657 811 490 Exploration costs 60 174 19 Depreciation, depletion and amortization 2,430 1,739 1,552 Writedown of oil and gas properties 3,953 1,171 739 Income tax provision -- -- -- ------- ------- ------- Results of operations from producing activities (excluding corporate overhead and interest costs) $(4,313) $ 196 $ (557) ======= ======= ======= (9) Unaudited Supplemental Oil and Gas Reserve Information The reserve information presented below are only estimates. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the Company. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas prices may all differ from those assumed in such estimates. -62- 65 TMBR/SHARP DRILLING, INC. Notes to Financial Statements In accordance with the Securities and Exchange Commission, the Company's estimates of future net cash flows from the Company's proved properties and the representative value thereof are made using oil and natural gas prices in effect as of the dates of such estimates and are held constant throughout the life of the properties. The year end prices used in estimating the future net cash flows at March 31, 2002, 2001 and 2000 were as follows: $23.36, $28.16 and $27.08 per barrel of oil, respectively, and $3.318, $5.861 and $2.467 per Mcf for natural gas, respectively. The following sets forth proved oil and gas reserves at March 31, 2002, 2001 and 2000:
2002 2001 2000 --------------------- --------------------- --------------------- Oil Gas Oil Gas Oil Gas MBbls MMcf MBbls MMcf MBbls MMcf ------- --------- ------- --------- ------- --------- (In thousands) Proved Reserves: Beginning of Year 1,081.5 6,295.1 605.0 2,948.1 415.4 4,486.1 Revisions of previous estimates (192.7) (1,124.7) 372.2 1,472.4 93.6 (1,801.5) Improved recovery -- -- -- -- -- -- Purchases of minerals in place and extensions 388.7 2,343.1 213.2 2,303.3 174.2 875.4 Sales of minerals in place -- -- -- -- -- -- Production (127.4) (707.9) (108.9) (428.7) (78.2) (611.9) ------- ------- ------- ------- ----- ------- End of year 1,150.1 6,805.6 1,081.5 6,295.1 605.0 2,948.1 ======= ======= ======= ======= ===== ======= Proved Developed Reserves: Beginning of year 1,081.5 6,295.1 605.0 2,948.1 415.4 4,486.1 ------- ------- ------- ------- ----- ------- End of year 994.7 6,013.9 1,081.5 6,295.1 605.0 2,948.1 ======= ======= ======= ======= ===== =======
The downward revisions of previous estimates for the year ended March 31, 2002 is primarily due to the decrease in crude oil and natural gas prices. The upward revisions for the year ended March 31, 2001, is primarily due to the increase in crude oil and natural gas prices. -63- 66 TMBR/SHARP DRILLING, INC. Notes to Financial Statements March 31, ----------------------- 2002 2001 ---- ---- (In thousands) Standardized Measure Future cash inflows $45,533 $61,866 Future production and development costs (10,614) (11,808) ------- ------- Future net cash flows 34,919 50,058 10% discount factor (13,165) (20,739) ------- ------- Discounted future net cash flows 21,754 29,319 Discounted income taxes -- -- ------- ------- Standardized Measure $21,754 $29,319 ======= ======= 2002 2001 2000 ---- ---- ---- (In thousands) Standardized measure, beginning of year $29,319 $10,486 $ 6,449 Revisions Prices and costs (13,707) 12,646 1,960 Accretion of discount 2,932 1,049 645 ------- ------- -------- Net revisions (10,775) 13,695 2,605 Discoveries and additions 6,997 9,229 3,676 Production (3,787) (4,091) (2,244) ------- ------- ------- Standardized measure, end of year $21,754 $29,319 $10,486 ======= ======= ======= -64- 67 TMBR/SHARP DRILLING, INC. Notes to Financial Statements (10) Supplementary Quarterly Financial Data (Unaudited)
First Second Third Fourth Total --------- --------- --------- --------- -------- (In thousands, except per share amounts) 2001 Total Revenues . . . . . . . . . . . $ 8,262 $ 9,509 $ 10,254 $ 13,452 $ 41,477 ======== ======== ======== ======== ========= Net income attributable to common stock . . . . . . . . $ 1,072 $ 1,640 $ 2,078 $ 3,518 $ 8,308 ======== ======== ======== ======== ======== Net income per share: Basic . . . . . . . . . . . . . $ 0.22 $ 0.33 $ 0.42 $ 0.71 $ 1.67 ======== ======== ======== ======== ======== Diluted . . . . . . . . . . . . 0.20 0.30 0.38 0.65 1.54 ======== ======== ======== ======== ======== 2002 Total Revenues . . . . . . . . . . . $ 15,027 $ 15,559 $ 12,110 $ 9,524 $ 52,220 ======== ======== ======== ======== ======== Net income (loss) attributable to common stock . . . . . . . . $ 5,315 $ 5,256 $ 2,624 $ (3,379) $ 9,816 ======== ======== ======== ======== ======== Net income (loss) per share: Basic . . . . . . . . . . . . . $ 1.04 $ 1.03 $ 0.50 $ (0.63) $ 1.88 ======== ======== ======== ======== ======== Diluted . . . . . . . . . . . . $ 0.97 $ 0.96 $ 0.48 $ (0.60) $ 1.79 ======== ======== ======== ======== ========
-65- 68 Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE As reported in our Form 8-K Report dated May 22, 2002, we dismissed Arthur Andersen, LLP as our independent accountant, effective May 22, 2002. The decision to dismiss Andersen was recommended by the Audit Committee and by the Board of Directors on May 21, 2002. Andersen's reports on our financial statements for the two fiscal years ended March 31, 2000 and March 31, 2001 did not contain an adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope or accounting principles. During the two fiscal years ended March 31, 2000 and March 31, 2001 and the period from April 1, 2001 through May 22, 2002, there were no disagreements between TMBR/Sharp and Andersen on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Andersen, would have caused it to make reference to the subject matter of the disagreements in connection with its report. Andersen furnished to TMBR/Sharp a letter addressed to the SEC stating that it agreed with the statements made in our Form 8-K Report. As further reported in our Form 8-K Report dated June 3, 2002, KPMG LLP was engaged as our new independent accountant, effective June 3, 2002. The decision to engage KMPG was recommended and approved by our Audit Committee and the Board of Directors on June 3, 2002. During the two fiscal years ending March 31, 2000 and March 31, 2001 and the period from April 1, 2001 to June 3, 2002, we did not consult KPMG regarding the application of accounting principles to a specific transaction, either completed or proposed, or the type of audit opinion that might be rendered on our financial statements, or any matter that was either the subject of a disagreement or a reportable event. -66- 69 PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The directors and officers of the Company at June 7, 2002 were as follows: Director or Officer Name Age Position with Company Since ---- --- --------------------- ---------- Thomas C. Brown 75 Chairman of the Board of Directors and Chief Executive Officer 1982 David N. Fitzgerald (1)(2) 79 Director 1984 Michael M. Cone (2) 64 Director 2001 Raymond E. Batchelor (1) 68 Director 2001 James B. Taylor (2) 64 Director 2001 Jeffrey D. Phillips 41 President 1997 Don H. Lawson 63 Vice President - Operations 1992 Patricia R. Elledge 44 Controller/Treasurer 1994 James M. Alsup 65 Secretary 1982 -------------------------- (1) Member of Compensation Committee (2) Member of Audit Committee Directors of the Company serve until the annual meeting of stockholders to be held in August, 2002, and until their successors in office are elected and qualified. Each officer is appointed annually by the Company's Board of Directors to serve at the Board's discretion and until his successor in office is elected and qualified. Mr. Brown has served as a Director of the Company since 1982. He is presently Chairman of the Board of Directors and Chief Executive Officer of the Company and has served in such capacities since 1990. Mr. Brown is also a Director of Tom Brown, Inc., the former parent of the Company. -67- 70 Mr. Fitzgerald has served as a Director of the Company since 1984. He is the President and a shareholder of Dave Fitzgerald, Inc., a privately held oilfield equipment sales company that Mr. Fitzgerald has owned and operated since 1963. Mr. Cone has served as a Director of the Company since April, 2001. Since 1985, he has been the majority owner and Chairman of Tri-C Resources, Inc. an independent oil and gas exploration company. Mr. Batchelor has served as a Director of the Company since April, 2001. He has been President of BHC Pipe & Equipment Company since 1987. Mr. Taylor has served as a Director of the Company since April, 2001. He is currently a Director of Willbros Group, Inc. From 1997 to 2000 he was Chairman of Solana Petroleum Corporation. From 1996 to 1998 he was a Director of Arakis Energy Corporation. From 1993 to 1996 he was Executive Vice President of Occidental Oil and Gas Corporation. Mr. Phillips has been employed by the Company since 1995. He has been President since April 1, 2001. He was Vice President - Production from 1997 to 2001. From 1993 to 1995 he was Operations Manager for Staley Operating Co., a privately held exploration and production company. Mr. Lawson has been employed by the Company since 1967. He has been the Vice President - Operations of the Company since 1992. Ms. Elledge was employed by the Company from September, 1989 to December, 1993 when she resigned to relocate. Ms. Elledge returned to the Company in September, 1994 in her current capacity as Controller - Treasurer. Mr. Alsup has been the Secretary of the Company since 1982. He has been a partner in the law firm of Lynch, Chappell & Alsup since 1970. There are no family relationships between any of the Directors or officers of the Company. Item 11. EXECUTIVE COMPENSATION The discussion under "Executive Compensation" in the Company's definitive proxy statement for the 2002 annual meeting of shareholders is incorporated herein by reference. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The discussion under "Principal Shareholders" and the information appearing under "Election of Directors" in the Company's definitive proxy statement for the 2002 annual meeting of shareholders is incorporated herein by reference. -68- 71 Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The discussion under "Executive Compensation - Certain Transactions" in the Company's definitive proxy statement for the 2002 annual meeting of stockholders is incorporated herein by reference. PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K Page ---- (a)1. See Index to Financial Statements at Item 8 38 (a)2. Financial Statement Schedules Years ended March 31, 2002, 2001 and 2000 Schedule II - Valuation and Qualifying Accounts . . . . 73 All other schedules are omitted as the required information is inapplicable or the information is presented in the Financial Statements or related notes. (a)3. Exhibits: Exhibit 3.1 - Articles of Incorporation of the Company, as amended. (Incorporated by reference to Exhibit 3.1 in Registrant's Annual Report on Form 10-K dated June 28, 1991) Exhibit 3.2 - Bylaws of the Registrant, as amended. (Incorporated by reference to Exhibit 3.2 in Registrant's Annual Report on Form 10-K dated June 27, 1994) Executive Compensation Plans and Arrangements --------------------------------------------- (Exhibits 10.1 through and including Exhibit 10.20 constitute executive compensation plans and arrangements of the Registrant) Exhibit 10.1 - Incentive Stock Option Plan. (Incorporated by reference to Exhibit 10.3 in Registrant's Registration Statement on Form 10 as amended, effective October 9, 1984) Exhibit 10.2 - Nonqualified Stock Option Agreement dated August 29, 1990, between Thomas C. Brown and the Registrant. (Incorporated by reference to Exhibit 10.15 in Registrant's Annual Report on form 10-K dated June 25, 1993) -69- 72 Exhibit 10.3 - Nonqualified Stock Option Agreement dated August 30, 1988, between Joe G. Roper and the Registrant. (Incorporated by reference to Exhibit 10.17 in Registrant's Annual Report on Form 10-K dated June 25, 1993) Exhibit 10.4 - Incentive Stock Option Agreement dated November 16, 1993 between Joe G. Roper and the Registrant. (Incorporated by reference to Exhibit 10.5 in Registrant's Annual Report on Form 10- K dated June 27, 1994) Exhibit 10.5 - Incentive Stock Option Agreement dated December 4, 1992 between Patricia R. Elledge and the Registrant. (Incorporated by reference to Exhibit 10.20 in Registrant's Annual Report on Form 10-K dated June 25, 1993) Exhibit 10.6 - Incentive Stock Option Agreement dated December 4, 1992 between Don H. Lawson and the Registrant. (Incorporated by reference to Exhibit 10.21 in Registrant's Annual Report on Form 10-K dated June 25, 1993) Exhibit 10.7 - Incentive Stock Option Agreement dated November 16, 1993 between Don H. Lawson and the Registrant. (Incorporated by reference to Exhibit 10.10 in Registrant's Annual Report on Form 10-K dated June 27, 1994) Exhibit 10.8 - 1994 Stock Option Plan. (Incorporated by reference to Exhibit 10.10 in Registrant's Annual Report on Form 10-K dated June 28, 1995) Exhibit 10.9 - TMBR/Sharp Drilling, Inc. Employee Retirement Plan. (Incorporated by reference to Exhibit 10.11 in Registrant's Annual Report on Form 10-K dated June 28, 1995) Exhibit 10.10 - 1998 Stock Option Plan (Incorporated by reference to Exhibit 10.1 in Registrant's Quarterly Report on Form 10-Q dated November 12, 1998) Exhibit 10.11 - Incentive Stock Option Agreement dated September 1, 1998, between Don H. Lawson and the Registrant. (Incorporated by reference to Exhibit 10.18 in Registrant's Annual Report on Form 10-K dated June 29, 1999) Exhibit 10.12 - Incentive Stock Option Agreement dated September 1, 1998, between Jeffrey D. Phillips and the Registrant. (Incorporated by reference to Exhibit 10.19 in Registrant's Annual Report on Form 10-K dated June 29, 1999) -70- 73 Exhibit 10.13 - Incentive Stock Option Agreement dated September 1, 1998, between Patricia R. Elledge and the Registrant. (Incorporated by reference to Exhibit 10.20 in Registrant's Annual Report on Form 10-K dated June 29, 1999) Exhibit 10.14 - Incentive Stock Option Agreement dated September 1, 1998, between Joe G. Roper and the Registrant. (Incorporated by reference to Exhibit 10.21 in Registrant's Annual Report on Form 10-K dated June 29, 1999) Exhibit 10.15 - Incentive Stock Option Agreement dated September 1, 1998, between Thomas C. Brown and the Registrant. (Incorporated by reference to Exhibit 10.22 in Registrant's Annual Report on Form 10-K dated June 29, 1999) Exhibit 10.16 - First Amended and Restated Nonstatutory Stock Option Agreement dated September 1, 1998, between Patricia R. Elledge and the Registrant. (Incorporated by reference to Exhibit 10.23 in Registrant's Annual Report on Form 10-K dated June 29, 1999) Exhibit 10.17 - First Amended and Restated Nonstatutory Stock Option Agreement dated September 1, 1998, between Jeffrey D. Phillips and the Registrant. (Incorporated by reference to Exhibit 10.24 in Registrant's Annual Report on Form 10-K dated June 29, 1999) Exhibit 10.18 - First Amended and Restated Nonstatutory Stock Option Agreement dated September 1, 1998, between Joe G. Roper and the Registrant. (Incorporated by reference to Exhibit 10.25 in Registrant's Annual Report on Form 10-K dated June 29, 1999) Exhibit 10.19 - First Amended and Restated Nonstatutory Stock Option Agreement dated September 1, 1998, between Thomas C. Brown and the Registrant. (Incorporated by reference to Exhibit 10.26 in Registrant's Annual Report on Form 10-K dated June 29, 1999) Exhibit 10.20 - Directors' Fee Stock Plan (Incorporated by reference to Exhibit 10.20 of Registrant's Annual Report on Form 10-K dated June 15, 2001) Exhibit 10.21 - Form of Stock Purchase Agreement, dated as of February 13, 1997, between the Registrant and the stockholders named therein (Incorporated by reference to Exhibit 10.1 in the Registrant's Registration Statement on Form S-3, No. 333-23391) Exhibit 10.22 - Second Amended and Restated Loan Agreement dated June 26, 2000 between Wells Fargo Bank, Texas N. A. and the Registrant. (Incorporated by reference to Exhibit 10.1 in Registrant's Quarterly Report on Form 10-Q dated August 9, 2000) -71- 74 *Exhibit 23.1 - Consent of Arthur Andersen LLP *Exhibit 23.2 - Consent of KPMG LLP *Exhibit 23.3 - Consent of Joe C. Neal & Associates ---------------------------------- *Filed herewith (b) No reports on Form 8-K were filed during the last quarter of fiscal 2002. -72- 75 Schedule II ----------- TMBR/SHARP DRILLING, INC. Valuation and Qualifying Accounts Years ended March 31, 2002, 2001 and 2000 (In thousands) Recoveries Balance at Additions or other Balance beginning charged to reserve at end Description of year operations reductions of year --------------------- ---------- ---------- ---------- ------- Allowance for doubtful accounts: 2002 $ 1,227 $ 174 $ -- $ 1,401 2001 $ 1,486 $ 125 $ 384 $ 1,227 2000 $ 1,349 $ 137 $ -- $ 1,486 -73- 76 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. TMBR/SHARP DRILLING, INC. June 25, 2002 By /s/ Thomas C. Brown -------------------------------- Thomas C. Brown, Chairman of the Board of Directors 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 on the dates indicated. June 25, 2002 /s/ Thomas C. Brown -------------------------------- Thomas C. Brown, Chairman of the Board of Directors (Principal Executive Officer) June 25, 2002 /s/ Jeffrey D. Phillips -------------------------------- Jeffrey D. Phillips, President June 25, 2002 /s/ Patricia R. Elledge -------------------------------- Patricia R. Elledge, Controller/ Treasurer (Principal Financial Officer) June 25, 2002 /s/ David N. Fitzgerald -------------------------------- David N. Fitzgerald, Director June 25, 2002 /s/ Michael M. Cone -------------------------------- Michael M. Cone, Director June 25, 2002 /s/ Raymond E. Batchelor ------------------------------- Raymond E. Batchelor, Director June 25, 2002 /s/ James B. Taylor ------------------------------- James B. Taylor, Director -74- 77 INDEX TO EXHIBITS Description Page No. ----------- -------- Exhibit 3.1 Articles of Incorporation of the Company, as amended. (Incorporated by reference to Exhibit 3.1 in Registrant's Annual Report on Form 10-K dated June 28, 1991) Exhibit 3.2 Bylaws of the Company, as amended. (Incor- porated by reference to Exhibit 3.2 in Registrant's Annual Report on Form 10-K dated June 27, 1994) Executive Compensation Plans and Arrangements --------------------------------------------- (Exhibits 10.1 through and including Exhibit 10.20 constitute executive compensation plans and arrangements of the Registrant) Exhibit 10.1 Incentive Stock Option Plan (Incorporated by reference to Exhibit 10.3 in Registrant's Registration Statement on Form 10, as amended, effective October 9, 1984) Exhibit 10.2 Nonqualified Stock Option Agreement dated August 29, 1990, between Thomas C. Brown and the Registrant. (Incorporated by reference to Exhibit 10.15 in Registrant's Annual Report on Form 10-K dated June 25, 1993) Exhibit 10.3 Nonqualified Stock Option Agreement dated August 30, 1988, between Joe G. Roper and the Registrant. (Incorporated by reference to Exhibit 10.17 in Registrant's Annual Report on Form 10-K dated June 25, 1993) Exhibit 10.4 Incentive Stock Option Agreement dated November 16, 1993 between Joe G. Roper and the Registrant. (Incorporated by reference to Exhibit 10.5 in Registrant's Annual Report on Form 10-K dated June 27, 1994) -75- 78 Exhibit 10.5 Incentive Stock Option Agreement dated December 4, 1992 between Patricia R. Elledge and the Registrant. (Incorporated by reference to Exhibit 10.20 in Registrant's Annual Report on Form 10-K dated June 25, 1993) Exhibit 10.6 Incentive Stock Option Agreement dated December 4, 1992 between Don H. Lawson and the Registrant. (Incorporated by reference to Exhibit 10.21 in Registrant's Annual Report on Form 10-K dated June 25, 1993) Exhibit 10.7 Incentive Stock Option Agreement dated November 16, 1993 between Don H. Lawson and the Registrant. (Incorporated by reference to Exhibit 10.10 in Registrant's Annual Report on Form 10-K dated June 27, 1994) Exhibit 10.8 1994 Stock Option Plan. (Incorporated by reference to Exhibit 10.10 in Registrant's Annual Report on Form 10-K dated June 28, 1995) Exhibit 10.9 TMBR/Sharp Drilling, Inc. Employee Retirement Plan. (Incorporated by reference to Exhibit 10.11 in Registrant's Annual Report on Form 10-K dated June 28, 1995) Exhibit 10.10 1998 Stock Option Plan (Incorporated by reference to Exhibit 10.1 in Registrant's Quarterly Report on Form 10-Q dated November 12, 1998) Exhibit 10.11 Incentive Stock Option Agreement dated September 1, 1998, between Don H. Lawson and the Registrant. (Incorporated by reference to Exhibit 10.18 in Registrant's Annual Report on Form 10-K dated June 29, 1999) Exhibit 10.12 Incentive Stock Option Agreement dated September 1, 1998, between Jeffrey D. Phillips and the Registrant. (Incorporated by reference to Exhibit 10.19 in Registrant's Annual Report on Form 10-K dated June 29, 1999) Exhibit 10.13 Incentive Stock Option Agreement dated September 1, 1998, between Patricia R. Elledge and the Registrant. (Incorporated by reference to Exhibit 10.20 in Registrant's Annual Report on Form 10-K dated June 29, 1999) -76- 79 Exhibit 10.14 Incentive Stock Option Agreement dated September 1, 1998, between Joe G. Roper and the Registrant. (Incorporated by reference to Exhibit 10.21 in Registrant's Annual Report on Form 10-K dated June 29, 1999) Exhibit 10.15 Incentive Stock Option Agreement dated September 1, 1998, between Thomas C. Brown and the Registrant. (Incorporated by reference to Exhibit 10.22 in Registrant's Annual Report on Form 10-K dated June 29, 1999) Exhibit 10.16 First Amended and Restated Nonstatutory Stock Option Agreement dated September 1, 1998, between Patricia R. Elledge and the Registrant. (Incorporated by reference to Exhibit 10.23 in Registrant's Annual Report on Form 10-K dated June 29, 1999) Exhibit 10.17 First Amended and Restated Nonstatutory Stock Option Agreement dated September 1, 1998, between Jeffrey D. Phillips and the Registrant. (Incorporated by reference to Exhibit 10.24 in Registrant's Annual Report on Form 10-K dated June 29, 1999) Exhibit 10.18 First Amended and Restated Nonstatutory Stock Option Agreement dated September 1, 1998, between Joe G. Roper and the Registrant. (Incorporated by reference to Exhibit 10.25 in Registrant's Annual Report on Form 10-K dated June 29, 1999) Exhibit 10.19 First Amended and Restated Nonstatutory Stock Option Agreement dated September 1, 1998, between Thomas C. Brown and the Registrant. (Incorporated by reference to Exhibit 10.26 in Registrant's Annual Report on Form 10-K dated June 29, 1999) Exhibit 10.20 Directors' Fee Stock Plan (Incorporated by reference to Exhibit 10.20 in Registrant's Annual Report on Form 10-K dated June 15, 2001) Exhibit 10.21 Form of Stock Purchase Agreement, dated as of February 13, 1997, between the Registrant and the stockholders named therein (Incorporated by reference to Exhibit 10.1 in the Registrant's Registration Statement on Form S- 3, No. 333-23391) -77- 80 Exhibit 10.22 Second Amended and Restated Loan Agreement dated June 26, 2000 between Wells Fargo Bank, Texas N. A. and the Registrant. (Incorporated by reference to Exhibit 10.1 in Registrant's Quarterly Report on Form 10-Q dated August 9,2000) *Exhibit 23.1 Consent of Arthur Andersen LLP 79 *Exhibit 23.2 Consent of KPMG LLP 80 *Exhibit 23.3 Consent of Joe C. Neal & Associates 81 -------------------- *Filed herewith -78- 81 Exhibit 23.1 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference of our report dated May 18, 2001 into the Company's previously filed Registration Statements on Form S-8 (registration No. 33-46699, No. 33-89878 and No. 333-32028) and the Company's previously filed registration statement on Form S-3, No. 333-23391. /s/ ARTHUR ANDERSEN LLP Dallas, Texas, June 15, 2001 This consent was furnished by Arthur Andersen LLP in connection with our 2001 Form 10-K. We were unable to obtain a currently dated consent from Arthur Andersen LLP. -79- 82 Exhibit 23.2 CONSENT OF INDEPENDENT AUDITORS The Board of Directors and Stockholders TMBR/Sharp Drilling, Inc. We consent to the incorporation by reference in the registration statements (No.33-46699, No. 33-89878 and No.333-32028) on Form S-8 and the registration statement (No. 333-23391) on Form S-3, of TMBR/Sharp Drilling, Inc. of our report dated June 24, 2002 with respect to the balance sheet of TMBR/Sharp Drilling, Inc. as of March 31, 2002, and the related statements of operations, stockholders' equity, and cash flows for the year then ended, which appears in the March 31, 2002 annual report on Form 10-K of TMBR/Sharp Drilling, Inc. /s/ KPMG LLP Midland, Texas June 24, 2002 -80- 83 Exhibit 23.3 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS As independent petroleum engineers, we hereby consent to the incorporation by reference of our report included in this Form 10-K into the Company's previously filed Registration Statements on Form S-8 (registration No. 33-46699, No. 33-898878 and No. 333-32028) and the Company's previously filed registration statement on Form S-3, No. 333-23391. /s/ JOE C. NEAL & ASSOCIATES Midland, Texas June 25, 2002 -81-