10-K 1 d07008e10vk.txt FORM 10-K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-K (X) ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended March 31, 2003 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) Indicate by check mark whether the Registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes [ ] No [X] The aggregate market value of voting and non-voting common equity held by nonaffiliates of the Registrant at September 30, 2002 (the last business day of the Registrant's most recently completed second fiscal quarter) was approximately $67,604,989 based on the last sale price of the Registrant's common stock on that date. At June 10, 2003, 5,496,636 shares of the Registrant's common stock were outstanding. TMBR/SHARP DRILLING, INC. FORM 10-K TABLE OF CONTENTS

-2- PART I CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS Some statements contained in our 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, our financial position and 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. We believe the assumptions and expectations reflected in these forward-looking statements are reasonable. However, no assurance can be given that our expectations will prove to be correct or that we 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: o fluctuations in prices of oil and gas; o future capital requirements and availability of financing; o risks associated with the drilling of wells; o competition; o general economic conditions; o timing and amount of future production of oil and natural gas; o operating costs and other expenses; o cash flow, anticipated liquidity and prospects for growth; o estimates of proved reserves and exploitation and exploration opportunities; and o marketing of oil and natural gas. 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 our common stock, you should be aware that there are various risks associated with an investment. Some of these are described under the Risk Factors section in Part I of this report and in other sections of this report. -3- ITEM 1. BUSINESS Throughout this report, we refer to some terms that are commonly used and understood in the oil and gas industry. These terms are: Mcf, Bcf, Bbls and EBO. Mcf refers to the quantity of one thousand cubic feet of natural gas. Bcf means one billion cubic feet of natural gas. Bbls means barrels of oil or crude oil condensate. An EBO is an equivalent barrel of oil, or 6 Mcf of natural gas for one barrel of oil. MEBO is one thousand equivalent barrels of oil. ABOUT TMBR/SHARP We are 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. We provide domestic onshore contract drilling services to major and independent oil and gas companies. Our operations are focused in the Permian Basin of west Texas and eastern New Mexico. In addition to our drilling rigs, we provide the crews and most of the ancillary equipment used in the operation of our drilling rigs. Rig utilization for the fiscal year ended March 31, 2003 was approximately 52% compared to 67% for the year ended March 31, 2002. We own 18 drilling rigs. At June 2, 2003, 11 rigs were operating for non-affiliated oil producers, and 7 were "stacked" (non-operating). All of our rigs are operational and actively marketed in the Permian Basin of west Texas and eastern New Mexico. We market our contract drilling services to both major oil companies and independent oil producers. The depth capabilities of our 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. We believe we have established a reputation for reliability, high quality equipment and well-trained crews. We continually seek to modify and upgrade our equipment to maximize the performance and capabilities of our drilling rig fleet, which we believe provides us with a competitive advantage. We have the capability to design, repair and modify our drilling rig fleet from our principal support and storage facilities in Midland, Texas, and an additional storage yard in Odessa, Texas. Our oil and gas exploration and production operations complement our 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 18% of our revenues for the fiscal year ended March 31, 2003. At March 31, 2003, our total proved oil and gas reserves were estimated to be: o 2,868 MBOE of proved developed reserves; and o 456 MBOE of proved undeveloped reserves. -4- At that same date, our total proved reserves were estimated to have an after tax present value of future net revenues, discounted at 10%, of $37.8 million. At March 31, 2003, we owned interests in approximately 28,531 gross (6,107 net) acres of developed oil and gas properties, and approximately 18,596 gross (4,779 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, we 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. Our 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 our cash flows and profitability. If prices become depressed for a sustained period of time, a material adverse effect on our future operations and financial condition would be expected. We have no material patents, licenses, franchises, or concessions which we consider significant to our operations. The nature of our business is such that we do not maintain or require a "backlog" of products, customer orders or inventory. Our operations are not subject to renegotiation of profits or termination of contracts at the election of the federal government. We have not been a party to any bankruptcy, receivership, reorganization or similar proceeding. Sometimes, seasonal conditions affect our business. As an example, weather conditions can hinder our drilling activities. TMBR/Sharp Drilling, Inc. 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. Our principal executive offices are located at 4607 West Industrial Blvd., Midland, Texas, 79703 and our telephone number is (915) 699-5050. AVAILABLE INFORMATION You may read and copy any materials we file with the SEC at the SEC's Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, including TMBR/Sharp, that file electronically with the SEC. We have not created a website yet, so electronic copies of our SEC filings are not available on a website. However, until our website is created, we will provide electronic or paper copies of our SEC filings free of charge upon request made to: Patricia R. Elledge, Controller, PRElledge@aol.com, 915-699-5050. -5- RECENT DEVELOPMENTS On May 26, 2003, we entered into an Agreement and Plan of Merger, dated as of May 26, 2003, with Patterson-UTI Energy, Inc. and Patterson-UTI Acquisition, LLC, a Texas limited liability company and a wholly owned subsidiary of Patterson-UTI Energy, Inc. Under terms of the merger agreement, assuming all of the conditions to the merger are satisfied or waived, we will merge with and into Patterson-UTI Acquisition, LLC, with Patterson-UTI Acquisition, LLC being the surviving company. Subject to the terms and conditions in the merger agreement, each issued and outstanding share of our common stock not owned directly or indirectly by Patterson-UTI Energy, Inc. or by us (except shares of common stock held by persons who object to the merger, and who comply with all of the provisions of Texas law concerning the right of holders of shares of common stock to dissent from the merger and require appraisal of their common stock), will be converted into the right to receive $9.09 in cash and 0.312166 of a share of common stock, $.01 par value per share, of Patterson-UTI Energy, Inc. Patterson-UTI Energy, Inc. will pay each holder cash in lieu of any fractional shares. Under the terms of the merger agreement, we agreed not to solicit competing offers, but we may consider and accept an unsolicited offer if our board of directors determines, after consultation with outside legal counsel, that the unsolicited offer is superior to the terms of the proposed merger. If we accept an unsolicited offer, or our board of directors withdraws its recommendation in light of an unsolicited offer, or our shareholders do not vote to approve the merger because of an unsolicited offer, we would be required to pay to Patterson a breakup fee of $3.5 million. The merger is subject to customary conditions to closing, including approval by our shareholders, as well as any necessary regulatory filings and approvals, such as the anti-trust provisions of the Hart-Scott-Rodino Act. There can be no assurance that the merger will be consummated in accordance with the terms of the merger agreement, if at all. As you read this report, it is important to keep in mind that the information presented, including our financial statements and related statistical data, does not give effect to the proposed merger. -6- DRILLING RIGS The following table describes the type and depth capabilities of our 18 onshore drilling rigs.

--------- *In active operation at June 2, 2003. Major overhauls, repairs and general maintenance for our drilling rigs are primarily conducted at our principal support and storage facilities in Midland, Texas. We emphasize the maintenance and periodic improvement of our drilling equipment and believe that our rigs are generally in good condition. DRILLING CONTRACTS Our drilling contracts are usually obtained through competitive bidding or as a result of direct negotiations with customers. Drilling contracts typically obligate us 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 our contracts are "daywork" contracts with the remainder being "footage" or "turnkey" contracts. Under a footage contract, we charge an agreed price per foot of hole drilled, whereas a day-work contract permits us 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 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, we manage the drilling operation and the type of equipment to be used, subject to certain customer specifications. We also bear the risk and expense of mechanical malfunctions, -7- 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, we generally bear 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 2, 2003, one was subject to a footage contract and 10 were subject to daywork contracts. Our 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. We believe we are adequately insured for public liability and damage to the property of others resulting from our operations. RIG UTILIZATION Our contract drilling revenues depend upon the utilization of our drilling rigs and the contract rates received for our 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.

--------- (a) Of the total number of rigs owned, one was owned for only a portion of the fiscal year ended March 31, 2000. (b) Of the total number of rigs owned, one was owned for only a portion of the fiscal year ended March 31, 2001. On April 12, 2001, one of our rigs was destroyed as a result of an explosion, fire and subsequent blowout. Additional information about our assets, income and revenues from our contract drilling and exploration and production business segments can be found in Note 6 to our financial statements under Item 8 of this report. -8- CUSTOMERS During the fiscal year ended March 31, 2003, we drilled a total of 93 wells for approximately 10 customers. The following table shows certain information regarding customers for our contract drilling services that accounted for more than 10% of our total revenues during the last fiscal year.

Depending upon the demand for our drilling rigs and our ability to attract new customers, the loss of EOG Resources, Inc. or Pure Resources, L.P. as customers could have a material adverse effect on our financial condition and results of operation. COMPETITION We encounter substantial competition from other drilling contractors in our contract drilling operations. Our principal market areas in west Texas and eastern New Mexico are highly fragmented and competitive. Like us, other companies compete primarily on the basis of contract rates, suitability and availability of equipment and crews, experience of drilling in certain areas, and reputation. We believe we compete favorably in these areas. 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. Based on our primary areas of activity and the depth of wells we typically drill, we compete directly with approximately twelve other drilling contractors. We also encounter 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 for the acquisition of desirable undeveloped oil and gas leases. The principal competitive factors in the acquisition of undeveloped oil and gas leases include the availability of qualified personnel and the availability of access to data necessary to acquire and develop such leases, as well as the amount of consideration and terms offered. Many of our competitors have financial resources, staffs and facilities substantially greater than ours. In addition, the producing and marketing of natural gas and oil is affected by a number of factors beyond our control, 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 include 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. We must compete for these raw materials and resources with major oil companies and independent operators, and the continued availability, without periodic interruption, of such materials and resources cannot be assured. -9- EMPLOYEES At June 2, 2003, we had 53 salaried employees and approximately 287 hourly paid employees. Our employees are not covered by collective bargaining agreements and we have never experienced a strike or work stoppage. We consider our employee relations to be satisfactory. REGULATION Our operations are regulated by 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. We 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 any changes will have on our business, financial condition or results of operations. Our oil and gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with these rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Because these rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. The States of Texas and New Mexico 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 wells. Sales of our gas are not regulated and are made at market prices. However, the Federal Energy Regulatory Commission, or FERC, regulates interstate and certain intrastate gas transportation rates and service conditions, which affect our gas marketing efforts, as well as the revenues we receive from sales of our gas production. Beginning in 1992, the FERC issued Order No. 636 and a series of related orders that have significantly altered the marketing and transportation of gas. Order 636 mandated 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 the FERC's purposes in issuing the orders was to increase competition within all phases of the natural 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 upheld Order No. 636. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines' traditional role as wholesalers of natural gas, and has substantially increased competition and volatility in natural gas markets. Although Order No. 636 does not directly regulate our production and marketing activities, it does affect how buyers and sellers gain access to the necessary transportation facilities and how we and our competitors sell natural gas in the marketplace. The sale of oil we produce is not currently regulated and is made at market prices. Prices we receive from the sale of oil are affected by the cost of transporting the product to market. Effective as of January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for interstate common carrier oil pipelines, which, generally, indexed such rates to inflation. These regulations could increase the cost of transporting oil by -10- interstate pipelines. However, we do not believe that these regulations affect us any differently than other oil producers, gatherers and marketers. We are also 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 our operations and costs. These laws and regulations sometimes require governmental authorization before conducting certain activities or limit or prohibit activities because of protected areas or species, impose substantial liabilities for pollution, and provide penalties for noncompliance. In particular, our exploration and production operations, our activities in connection with storage and transportation of oil and other liquid hydrocarbons, and our 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 our overall cost of business. While these regulations affect our capital expenditures and earnings, we believe that these regulations do not affect our competitive position in the industry because our competitors are similarly affected by environmental regulatory programs. Environmental regulations have historically been subject to frequent change. Consequently, we are unable to predict the future costs or other future impacts of environmental regulations on our future operations. A discharge of hydrocarbons or hazardous substances into the environment could subject us 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 our operations. Water. The Oil Pollution Act, or OPA, was enacted in 1990 and amends provisions of the Federal Water Pollution Control Act, or 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 the spill is into navigable waters, or along shorelines. If an oil spill into such waters occurs, we could face substantial liabilities. States in which we operate have also enacted similar laws. 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 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 historically not been material to our operations, but there can be no assurance that changes in federal, state or local water pollution control programs will not materially adversely effect us in the future. Although no assurance can be given, we believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our business, financial condition or results of operations. -11- Endangered Species. The Endangerd Species Act, or ESA, seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species. Under the ESA, seismic, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species of its habitat. The ESA provides for criminal penalties for willful violations of the Act. Other statutes provide protection to animal and plant species and may apply to our operations. Solid Waste. The federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes govern the disposal of "hazardous wastes." Although the Comprehensive Environmental Response, Compensation, and Liability Act, also known as the Superfund law, or CERCLA, currently excludes petroleum from the definition of "hazardous substances," and the RCRA also excludes certain classes of exploration and production wastes from regulation, such exemptions by Congress under both CERCLA an RCRA may be deleted, limited or modified in the future. If such changes are made to CERCLA and/or the RCRA, we could be required to remove and remediate previously disposed of materials (including materials disposed of or released by prior owners or operators) from properties (including ground water contaminated with hydrocarbons) and to perform removal or remedial actions to prevent future contamination. Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act, also known as the Superfund law, or CERCLA, imposes liability, 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 occurred and companies that disposed of or arranged for the disposal of the hazardous substances at the site. The Superfund 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 ordinary course of our operations, we may have managed substances that may fall within the definition of a "hazardous substance". We may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites where we disposed of or arranged for the disposal of these substances. This potential liability extends to properties that we owned or operated, as well as to properties owned and operated by others at which disposal of our hazardous substances may have occurred. We may also fall into the category of a "current owner or operator". We currently own or lease numerous properties that for many years have been used for the exploration and production of oil and gas. Although we believe that we have utilized operating and disposal practices standard in the industry, hydrocarbons or other wastes may have been disposed of or released by us on or under properties we owned or leased. 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, we 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 Our oil and gas operations involve the acquisition, exploration for, development and production of oil and natural gas. During the fiscal year ended March 31, 2003, our exploration efforts were conducted in west Texas and eastern New Mexico. We actively invest in oil and gas properties for the purpose of exploration, development and production of oil and gas. We acquire and participate in exploration activities as a working interest owner along with other third parties and we usually provide the contract drilling services for these activities. -12- 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 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 under an operating agreement among the parties. We usually serve as operator of oil and gas properties that we assemble into drilling prospects and we participate as a non-operating working interest owner in prospects generated by third parties. As operator, we supervise the drilling and completion of wells and production from the wells 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 2, 2003 we were serving as operator of 52 wells. OIL AND GAS RESERVES Joe C. Neal & Associates, an independent engineering firm, estimated the total proved reserves attributable to our oil and gas properties to be 1.21 million Bbls of oil and 12.64 Bcf of natural gas as of March 31, 2003. Based on oil and gas prices at March 31, 2003 and current operating and development costs, the present value of our pretax future net revenues from our properties, discounted at 10%, was estimated to be approximately $40.6 million as of March 31, 2003. In accordance with applicable SEC requirements, estimates of our proved reserves and future net revenues are made using sales prices and costs, estimated to be in effect as of the date of such reserve estimates, that are held constant throughout the life of the properties, except to the extent a contract specifically provides for escalation. The average realized prices for our reserves as of March 31, 2003 were $28.93 per Bbl of oil and $4.716 per Mcf of natural gas. For additional information concerning our estimated proved oil and gas reserves, you should read Note (9) to our financial statements. You should refer to "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 our control. 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 subsequent revision due to the results of drilling, testing and production after the date of the initial estimate. 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. Unless we acquire properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves, and volumes of production will decline as reserves are produced. Our future oil and gas production is highly dependent upon the level of success we have in acquiring or finding additional reserves. -13- We do not have any oil or gas reserves outside the United States. No major discovery or other favorable or adverse event has occurred since March 31, 2003 which is believed to have caused a significant change in our estimated proved oil and gas reserves. Our oil and gas reserves and production are not subject to long-term supply or similar agreements with foreign governments or authorities. On June 11, 2003, we filed a notice with the Federal Trade Commission and the Department of Justice pursuant to the Hart-Scott Rodino Antitrust Improvements Act of 1976, as amended, because of the proposed merger. Exhibits filed as part of this notice included a summary of a "sale case" model of proved reserves that we used for internal purposes when we were negotiating the merger with Patterson. The contents of the filing, including the reserve reports included in the filing, are confidential and not available to the public. The estimated proved reserves in the sale case model exceeded the estimated proved reserves presented in this report by more than five percent, primarily because of different classifications of certain oil and gas properties and the application of higher prices per Bbl of oil and Mcf of gas. PRODUCTIVE WELLS AND ACREAGE The following tables shows the gross and net productive oil and gas wells and the gross and not developed and undeveloped acreage in which we owned a working interest at March 31, 2003. Excluded from the table is acreage in which our interest is limited to royalty or similar interests.

Generally, the terms of developed oil and gas leaseholds are continuing and remain in force 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 through the payment of specified minimum delay rentals or extension by production. -14- On September 5, 1995, we entered into a ten-year License Agreement with the Government of the Republic of Palau and the State of Kayangel which permitted us to explore for oil and natural gas offshore. The license covered approximately 1.1 million acres within the waters of Palau. Under the license agreement, as amended, we were obligated to drill two wells by March, 2002. However, we never drilled the wells and in 2002 we decided to abandon this project and impaired approximately $150,000 which represented our costs related to this leasehold. DRILLING ACTIVITIES The following table shows information about the number of gross and net exploratory and development wells drilled for our account during the periods indicated.

--------- (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 2, 2003, we were participating in the drilling of 1 gross (.125 net) development well in Lea County, New Mexico. We own substantially all of the equipment we use in our drilling operations. Some insignificant items of drilling equipment are leased or rented as needed because they either cannot be purchased or they are only necessary for the drilling of certain types of wells located in certain areas. -15- PRODUCTION, PRICES AND LIFTING COSTS The following table shows certain information about our production, including the volumes of oil and gas we produced, the average sales prices we received for sales of oil and gas we produced, and the average production (lifting) cost per EBO.

--------- 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 our interests in producing properties. We believe that title to our properties is good and defensible in accordance with standards generally acceptable in the oil and gas industry, subject to encumbrances and defects which, in our opinion, are not so material as to detract substantially from the value of the properties. Our 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. We do not believe that any of these burdens materially interferes with the use of our properties in the operation of our business. -16- MARKETS AND CUSTOMERS We sell our oil and gas at the wellhead on an "as-produced" basis and we do not refine petroleum products. Other than normal production facilities, we do not own an interest in any bulk storage facilities or pipelines. As is customary in the industry, we sell our production in any one area to relatively few purchasers, including transmission companies that have pipelines near our 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. For the year ended March 31, 2003, Plains Marketing, L.P. accounted for approximately 25% of our oil and gas revenues and Navajo Refining Company accounted for approximately 20% of our oil and gas revenues for such period. The loss of either one of these purchasers could cease or delay our production and sales if alternative purchasers having adequate gathering facilities are not found to replace such purchaser's volume of oil or gas purchased. However, we believe that under present circumstances we would be able to find other purchasers for our oil and gas production. RISK FACTORS In addition to the other information included in this report, the following risk factors should be considered in evaluating our business and future prospects. The risk factors described below are not necessarily exhaustive and you are encouraged to perform your own investigation with respect to us and our business. We also urge you to read the other information included in this report, including our financial statements and the related notes. Declining oil and gas prices may cause us to record write-downs in the carrying value of our oil and gas properties. Our oil and gas producing activities are accounted for using the successful efforts method of accounting. Under this accounting method, the costs we incur to acquire oil and gas properties (proved and unproved), all development costs and successful exploratory wells are capitalized, but the costs of unsuccessful exploratory wells are expensed. Geological and geophysical costs, including seismic costs, are charged to expense when incurred. In cases where we provide contract drilling services related to oil and gas properties in which we have an ownership interest, our proportionate share of costs related to oil and gas properties is capitalized, net of our 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 we will be required to write down the carrying value of our oil and gas properties increases when oil and gas prices decline. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. For the year ended March 31, 2003, we recognized a non-cash impairment charge of $459,391 related to our oil and gas reserves and unproved properties. This impairment of oil and gas assets was primarily the result of adjustments of forecasts and decline curves for certain wells added in prior years and unsuccessful exploitation efforts to increase production. No assurance can be given that we will not experience write-downs in the future. -17- Part of our business is seasonal in nature. Weather conditions affect the demand for and prices of natural gas and can also delay drilling activities, temporarily disrupting our overall business plans. Demand for natural gas is typically higher during winter months. As a result, our results of operations may be adversely affected by seasonal conditions. We must replace oil and gas reserves that we produce. Failure to replace reserves may negatively affect our business. Our future performance depends in part upon our ability to find, develop and acquire additional oil and gas reserves that are economically recoverable. Our proved reserves decline as they are depleted and we must locate and develop or acquire new oil and gas reserves to replace reserves being depleted by production. No assurance can be given that we will be able to find and develop or acquire additional reserves on an economical basis. If we cannot economically replace our reserves, our results of operations may be materially adversely affected. The volatility of the oil and gas industry may have an adverse impact on our operations. Our revenues, cash flows and profitability are substantially dependent upon prevailing prices for oil and gas, both with respect to our contract drilling operations and our 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 our areas of operation will have a material adverse effect on our business, financial condition and results of operations and could impair access to future sources of capital. Demand and prices for our contract drilling services depend upon numerous factors over which we have no control, including: o 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; o the cost of exploring for, producing and transporting oil and natural gas; o the level and price of foreign oil and natural gas imports; o the discovery rate of new oil and natural gas reserves; o available pipeline and other oil and natural gas transportation capacity; o weather conditions; and o 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 our markets will continue or that demand for our contract drilling services will correspond to the level of activity in the industry generally. We expect oil and natural gas prices to continue to be volatile and to affect the demand for and pricing of our contract drilling services. -18- We operate in a highly competitive industry, which includes competitors with greater financial resources. Some of our competitors have significantly greater financial resources than we have, 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 land drilling industry in which we operate 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 land drilling contractors provide competition for drilling contracts in all areas of our business. In addition, certain competitors are active 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. Terrorist activities may adversely affect our business. Terrorist activities, anti-terrorist efforts and other armed conflict involving the United States or its interests abroad may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. The disruption of the financial markets and the negative impact on the U. S. economy caused by September 11 and other terrorist events may undermine our efforts and any success we might have in our contract drilling and exploration and production activities. Although September 11 was not a direct attack on the domestic oil and gas industry, any similar events in the future, particularly those directed at the oil and gas industry, could materially and adversely affect our business, results of operations and financial condition. If events of this nature occur and persist, the attendant political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on prevailing oil and natural gas prices and causing a reduction in our revenues. Natural gas and oil production facilities, transportation systems and storage facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our operations is destroyed or damaged by such an attack. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain if available at all. The oil and gas industry is capital intensive and we may not have sufficient funding for our capital expenditures. The oil and gas industry is capital intensive. Our 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 we are able to obtain, the level of oil and gas we are able to produce from existing wells, the prices at which oil and gas are sold and our ability to locate and produce new reserves. We cannot provide any assurance that our cash flow from operations and present borrowing capacity will be sufficient to fund our anticipated capital expenditures and working capital requirements. We 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 our loan agreement with our bank lender, we do not have any agreements for any such financing and there can be no assurance as to the availability of any such financing. To the extent our capital resources and earnings are at any time insufficient to fund our activities or repay any indebtedness when due, we will need to raise additional funds through public or private financings or additional borrowings. No assurance can be given as to our ability to obtain any such capital resources. If we are not at any time able to obtain the necessary capital resources, our 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 our shareholders 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. -19- 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 personnel for our drilling rigs, as we are now experiencing. As a result, and rather than hiring unqualified or inexperienced crews, from time to time we may intentionally restrict the number of drilling rigs we have in active operation at any one time. If we are unable to attract and retain qualified personnel, our ability to market and operate our drilling rigs will be restricted. In addition, labor shortages could result in wage increases, which could reduce our operating margins and have a material adverse effect on our financial condition and results of operations. The reserve data in this report represent estimates only. Information relating to our 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 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 our properties. In accordance with SEC requirements, we have 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: o the timing of production and related expenses o changes in consumption levels; and o 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 our reserves or the oil and gas industry in general. In addition, we may need to revise our reserve estimates 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. Our contract drilling activities and oil and gas exploration activities are subject to many inherent risks. Our 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 our operations depends, in part, upon the ability of qualified personnel. The cost of drilling, completing and operating wells is often uncertain. There is no assurance that our oil and gas drilling or -20- acquisition activities will be successful, that any production will be obtained, or that any such production, if obtained, will be profitable. Our drilling operations and our rig 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 us. We generally try to obtain from our customers indemnity agreements requiring them to hold us harmless if loss of production or reservoir damage occurs. Even when we obtain contractual indemnification, however, the customer may not maintain adequate insurance to support such indemnification. If we incur substantial liabilities from our drilling operations, our results of operations may be materially adversely affected. As is customary in the industry, we maintain insurance against some, but not all, of the hazards and risks we encounter. We maintain general liability insurance and obtain insurance against blowouts and pollution risks on a well-by-well basis, but we do not carry insurance against all operating hazards. No assurance can be given that our insurance or contractual indemnity protection will be sufficient or effective under all circumstances or against all hazards to which we may be subject, and our insurance claims will be subject to retentions and deductibles. The occurrence of a significant event for which we are not fully insured or indemnified or the failure of a customer to meet its indemnification obligations could have a material adverse effect on our results of operations and financial condition. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable. Decreased demand or reduced prices we receive for our contract land drilling services could materially adversely affect our financial condition. Any significant decrease in demand for, or the prices received for, our contract drilling services could have a material adverse affect on our business, 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. We cannot accurately predict either the future level of demand for our contract drilling services or future conditions in the land contract drilling services industry. We may incur losses in connection with our footage and turnkey drilling contracts. We cannot provide assurance that we will not incur losses on turnkey and footage drilling contracts. We perform drilling services under our footage and turnkey drilling contracts which require that we drill a well to a specified depth for a fixed price. The risks associated with turnkey and footage contracts are greater than for wells drilled on a daywork basis because turnkey and footage contracts require us to assume most of the risks associated with drilling operations that are normally retained 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. At March 31, 2003, two of our rigs were operating under footage contracts. None were working under turnkey contracts. Under footage and turnkey contracts, we do not receive payment unless the well is drilled to the specified depth, and we 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 we use in determining the contract price and completing the contracts on schedule. -21- We don't pay dividends on our common stock. We have never paid dividends on our common stock, and do not intend to pay cash dividends on the common stock in the foreseeable future. Net income from our operations, if any, will be used for the development of our business. Any decision to pay dividends on the common stock in the future will depend upon our profitability at that time. We are subject to many restrictions under our bank loan agreement. As required by our loan agreement with our bank lender, substantially all of our drilling rigs and related equipment, accounts receivable and inventory have been pledged as collateral to secure the payment of our loans. The loan agreement restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. However, on May 23, 2003, our bank lender consented to the proposed merger with a subsidiary of Patterson-UTI Energy, Inc. We are also required to comply with certain financial covenants and maintain certain financial ratios. The loan agreement also prohibits us from declaring or paying dividends on our common stock. Although we are currently in compliance with the loan covenants, our 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 our control. Failure to comply with any of the restrictions and covenants under the loan agreement could result in a default under the loan agreement, resulting in the acceleration of the due dates of any amounts owed to the bank and the foreclosure by the bank on our pledged assets. The loan agreement limits the amounts we can borrow to a borrowing base amount, based upon the value of our drilling rigs and equipment, accounts receivable and inventory securing repayment of loans made to us. 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 we must pledge other assets as additional collateral. No assurance can be given that we would be able to make any mandatory principal prepayments required under the loan agreement. Our financial statements for the year ended March 31, 2001 were audited by Arthur Andersen LLP. Arthur Andersen LLP was previously our independent accountant. Representatives of Arthur Andersen LLP are not available to reissue their report on the March 31, 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 its 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. ITEM 2. PROPERTIES In addition to our drilling rigs and related equipment and our oil and gas properties, we own a 31 acre tract of land in Midland, Texas on which our executive offices are located and on which the principal support and storage facilities for our 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. We also own a 66 acre tract of land in Odessa, Texas, which is presently being utilized as a secondary storage location. From time to time, we also store and stack rigs in the field at the rig's last location site. -22- We own 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. We believe that the support and storage facilities for our drilling rigs and related equipment are more than adequate for our needs. ITEM 3. LEGAL PROCEEDINGS We are a defendant in various lawsuits generally incidental to our business. We accrue for such items when a liability is both probable and the amount can be reasonably estimated. We do not believe that the ultimate resolution of any of our existing lawsuits will have a material effect on our financial position or results of operations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There were no meetings of our security holders during the fourth quarter of the fiscal year ended March 31, 2003, and no matters were submitted to a vote of security holders during such period. -23- PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Our 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 for our common stock as reported by NASDAQ. The quotations are inter-dealer prices without retail mark-ups, mark-downs or commissions and may not represent actual transactions.

On June 10, 2003, the last reported sale price of our common stock as reported by NASDAQ was $19.86 per share. The transfer agent for our common stock is American Stock Transfer & Trust Company, New York, New York. On June 10, 2003, the outstanding shares of our common stock were held of record by approximately 1,900 shareholders. We have never declared or paid any cash dividends on our common stock and we have no present intention to pay cash dividends in the future. We presently intend to retain all earnings to fund our operations and future growth. Under terms of our loan agreement with our bank lender, we are prohibited from paying cash dividends on the common stock. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources". At March 31, 2003, a total of 613,500 shares of common stock were authorized for issuance upon exercise of outstanding stock options. An additional 276,000 shares remained available for future issuance under our equity compensation plans. In the table on the following page, certain information is described about these shares and the equity compensation plans which provide for their authorization and issuance. To find additional information about our equity compensation plans, you are urged to read Note 3 to our financial statements. -24- RECENT SALES OF UNREGISTERED SECURITIES As described in Item 11 of this report under the caption "Compensation of Directors", TMBR/Sharp has a Directors Fee Stock Plan. Under this plan, nonemployee directors are entitled to receive 300 shares of TMBR/Sharp common stock for each Board meeting attended and 100 shares of common stock for attendance at each meeting of a Board committee. During the fiscal year ended March 31, 2003, Mr. Fitzgerald received 3,400 shares under this plan; Mr. Cone received 3,300 shares; Mr. Taylor received 3,000 shares; and Mr. Batchelor received 2,800 shares. The shares issued were not registered under the Securities Act of 1933, as amended. Such shares were newly issued and were sold for services provided by the directors. There were no underwriters involved. TMBR/Sharp relied upon Section 4(2)of the Securities Act of 1933, as amended, for exemption of such sale and issuance from the registration requirements of such Act as transactions not involving a public offering. EQUITY COMPENSATION PLANS Equity Compensation Plan Information

(1) During the fiscal year ended March 31, 2003 12,500 shares of our common stock were issued to nonemployee Directors under TMBR's Directors Fee Stock Plan, other than upon exercise of options, warrants or rights. This plan is described in Note (3) of the Financial Statements. The plan authorizes the issuance of a total of 25,000 shares of common stock. At March 31, 2003, 6,000 shares of common stock remained available for future payment of nonemployee Directors' fees. -25- ITEM 6. SELECTED FINANCIAL DATA The following table shows selected financial data for our operations for each of the five years ended March 31, 2003. This table should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations", and the Financial Statements and related notes included elsewhere herein.

-26- ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion is intended to assist you in understanding our financial position and results of operations for each year in the three-year period ended March 31, 2003. you should read the following discussion and analysis in conjunction with our financial statements and the related notes. The following discussion contains forward looking statements. For a description of limitations inherent in forward-looking statements, see "Cautionary Statement Regarding Forward-Looking Statements" on page 3. CRITICAL ACCOUNTING POLICIES Our discussion and analysis of our financial condition and results of operation are based upon financial statements which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We have identified below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates, including those related to oil and gas revenues, oil and gas properties, income taxes and contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements: o Revenue Recognition - 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. Due to the nature of turnkey contracts and risks therein, we utilize 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. o Depreciation - Contract Drilling Operations. 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. o Revenue Recognition - Oil and Gas Properties. We follow the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. No receivables, payables or unearned revenue are recorded unless a working interest owner's aggregate sales from the property exceed its share of the total reserves-in-place. o Successful Efforts Accounting. We account for our oil and natural gas operations using the successful efforts method of accounting. Under this method, all costs -27- associated with property acquisition, successful exploratory wells and all development wells are capitalized. Items charged to expense generally include geological and geophysical costs, cost of unsuccessful exploratory wells and oil and natural gas production costs. o Proved Reserve Estimates. Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of: - the quality and quantity of available data; - the interpretation of that data; - the accuracy of various mandated economic assumptions; and - the judgment of the persons preparing the estimate. Our proved reserve information included in this report is based on estimates prepared by Joe C. Neal & Associates. Estimates prepared by others may be higher or lower than our estimates. Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate. Our shareholders should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Our estimates of proved reserves directly impact depletion expense. If the estimates of proved reserves decline, the rate of which we record depletion expense increases, reducing net income. Such a decline may result from property performance or from lower market prices or increases in costs, which may make it uneconomic to drill for and produce higher cost fields. In addition, the decline in proved reserve estimates may impact the outcome of our assessment of our oil and gas producing properties for impairment. o Impairment of Proved Oil and Gas Properties. We review our proved properties whenever management judges that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Management assesses whether or not an impairment provision is necessary based upon management's outlook of future commodity prices and net cash flows that may be generated by the properties. Proved oil and gas properties are reviewed for impairment on a property-by-property basis, which is the lowest level at which depletion of proved properties is calculated. o Impairment of Unproved Oil and Gas Properties. Management periodically assesses individually significant unproved oil and gas properties for impairment, on a project- -28- by-project basis. Management's assessment of the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects impact the amount and timing of impairment provisions. o Valuation of Deferred Tax Assets. We compute income taxes in accordance with SFAS No. 109. "Accounting for Income Taxes." SFAS No. 109 requires an asset and liability approach which results in the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax basis of those assets and liabilities. SFAS No. 109 also requires the recording of a valuation allowance if it is more likely then not that some portion or all of a deferred tax asset will not be realized. OVERVIEW Since 1982, our principal business of has been the contract drilling of domestic onshore oil and gas wells. In 1987, we began acquiring oil and gas properties and participating in the exploration for and development of oil and gas reserves. The contract drilling industry is currently experiencing a slight increase in demand and a firming of prices for contract drilling services due to the recent increase and stability surrounding oil and gas prices. We have been and will continue to be affected by oil and gas industry conditions but cannot predict either the future level of demand for our contract drilling services or future conditions in the contract drilling industry. The contract drilling industry remains highly competitive. We believe we own a sufficient number of drilling rigs to remain competitive within our areas of operation. In addition, we believe we compete favorably with respect to the depth capabilities of our rigs, the experience level of our personnel, our reputation and our relationship with existing customers. However, our operating results will continue to be directly affected by the level of drilling activity in our service areas. The following table sets forth certain information relating to our contract drilling operations for the periods indicated:

Oil and Gas Operations. Our oil and gas producing activities are accounted for using the successful efforts method of accounting. Using this method, we capitalize 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 we provide contract drilling for oil and gas properties in which we have an ownership interest, our proportionate share of costs is capitalized as stated above, net of our working-interest -29- 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 $2,196,000 at March 31, 2003 and $1,967,000 at March 31, 2002. For properties with proved or proved developed oil and gas reserves, depletion, depreciation and amortization of capitalized costs was calculated for fiscal 2003, 2002 and 2001 by applying the units-of-production method to the estimated amount of such reserves. We recognized non-cash charges of approximately $0.5 million for fiscal 2003; $4.0 million for fiscal 2002; and $1.2 million for fiscal 2001. These non-cash charges resulted from writedowns of the carrying value of our oil and gas properties. We assess the need for an impairment of capitalized costs of oil and gas properties on a property-by-property basis. 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. Many assumptions are required for the 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, 2003 were $28.93 per Bbl and $4.716 per Mcf. Future impairment expense may be required on current properties if we change our pricing or cost assumptions in the future or if estimated future recoverable reserves decline. The following table shows certain information relating to our oil and gas operations for the periods indicated:

We have never entered into hedging arrangements and do not have any delivery commitments. While hedging arrangements reduce exposure to losses 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, 2003 TO YEAR ENDED MARCH 31, 2002 Contract drilling revenues for fiscal 2003 decreased by 33% from fiscal 2002. Rig utilization rates in fiscal 2003 were 53%, as compared to 67% in fiscal 2002. The decrease in contract drilling revenues was due to the decrease in utilization and an approximate 14% decrease in the average prices received for contract drilling services. Rig utilization in our 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. -30- Contract drilling expenses were 69% of contract drilling revenues in fiscal 2003 while in fiscal 2002 contract drilling expenses were 57% of contract drilling revenues. The percentage increase in contract drilling expenses was primarily due to the decrease in drilling revenues. Oil and gas revenues increased by approximately 25% when comparing fiscal 2003 to fiscal 2002. Quantities of oil and natural gas produced (on an equivalent barrel of oil basis) increased by approximately 26%, while average sales prices of crude oil and natural gas (on an equivalent barrel of oil basis) increased by approximately 1%. The following table shows certain information relating to our oil and gas revenues:

Oil and gas production expenses increased approximately 12%, primarily the result of an increase in production taxes. We participated as a working-interest owner in the drilling of 21 gross (5.96 net) wells during fiscal 2003, one of which was a dry hole. In fiscal 2002, we participated as a working-interest owner in the drilling of 13 gross (4.00 net) wells, three of which were dry holes. General and administrative expenses increased approximately 56%. This increase is primarily due to an increase in insurance, ad valorem and franchise tax expenses. Depreciation, depletion and amortization expenses increased by approximately 3%. This increase can be attributed to an increase in the quantities of oil and gas produced as oil and gas properties are depleted using the units-of-production method. We recognized a non-cash charge of $0.5 million in fiscal 2003 and a non-cash charge of $4.0 million in fiscal 2002 related to the writedown of the carrying value of our oil and gas properties. Net working capital was $9.3 million at March 31, 2003, as compared to $9.1 million at March 31, 2002. COMPARISON OF YEAR ENDED MARCH 31, 2002 TO YEAR ENDED MARCH 31, 2001 Contract drilling revenues for fiscal 2002 increased by 30% over contract drilling revenues for fiscal 2001. Our rig utilization rate in fiscal 2002 was 67% and our rig utilization rate for 2001 was 68%. The increase in contract drilling revenues was due to an increase in the average prices we received for our contract drilling services. -31- Contract drilling expenses were 57% of contract drilling revenues in fiscal 2002. In fiscal 2001, contract drilling expenses were 63% of contract drilling revenues. 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. Our oil and gas revenues remained relatively flat when comparing fiscal 2002 to and 2001. Although quantities of oil and gas produced (on an equivalent barrel of oil basis) increased by approximately 36%, oil and gas revenues for fiscal 2002 were negatively affected by a decrease in prices we received for oil and natural gas. The following table shows certain information relating to our oil and gas revenues:

Oil and gas production expenses increased by 26%, which was the result of start up expenses for new wells coming on line, coupled with an increase in the number of producing properties. Also, we experienced a general rise in the cost of services and supplies which were included in production expenses. We participated as a working-interest owner in the drilling of 13 gross (4.00 net) wells during fiscal 2002, three of which were dry holes. In fiscal 2001, we participated as a working-interest owner in the drilling of 21 gross (6.91 net) wells, nine of which were dry holes. Depreciation, depletion and amortization expense increased 31% due to several factors. In 2002, we purchased drill pipe and drill collars and updated and refurbished some of our drilling rigs and engines. The depreciable base of our 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 were 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 we owned an interest (a total of 127 wells in fiscal 2002 versus 111 wells in 2001). General and administrative expenses increased approximately 56%. The increase was the result of an increase in payroll and insurance expenses. We recognized non-cash charges of $4.0 million in fiscal 2002 and $1.2 million in fiscal 2001, in each case related to the writedown of the carrying value of our oil and gas properties. -32- Net working capital was $9.1 million at March 31, 2002, as compared to $5.4 million at March 31, 2001. The increase in working capital was attributable to an increase in cash and a decrease in trade payables and other current liabilities. INCOME TAXES At March 31, 2003, we had approximately $33.0 million of unused net operating loss, or NOL, carryforwards for tax purposes. Use of these NOL carryforwards is dependent upon our ability to generate taxable earnings in future periods. These carryforwards began to expire in fiscal 2000 and approximately $10.3 million expired in 2003. Our ability to utilize NOL carryforwards may be substantially limited in the future under the Internal Revenue Code of 1986. If we experience an ownership change under applicable provisions of the Internal Revenue Code, the carryforward would be limited to an annual amount determined by specified interest rates and other variables. We estimate that we will be able to utilize approximately $3.9 million of NOL carryforwards in 2003 to reduce taxable income. As of March 31, 2003, we do not believe an ownership change has occurred. However, if the merger with Patterson is completed, we believe that a change of control would occur and utilization of future NOL carryforwards would be limited. The effective tax rates for fiscal 2003 and 2002 differ from the statutory tax rate of 34% primarily due to the utilization of NOLs. The tax benefit recorded in 2003 results primarily from the reversal of valuation allowance discussed below. We utilize an asset and liability approach for financial accounting and reporting for income taxes. We have a deferred tax asset primarily due to our NOL carryforwards. We assess the need for a valuation allowance against our deferred tax assets based on whether we believe that it is more likely than not that the deferred tax asset is realizable. As of March 31, 2002, we fully reserved our deferred tax asset as we determined that realizability of any portion of the deferred tax asset was not more likely than not. Realization of the deferred tax asset requires us to generate future taxable income. During 2003, after considering increases in commodity prices, recent utilization of operating loss carryforwards to reduce taxable income, and the anticipated expiration of NOL carryforwards, we determined that it was more likely than not that a portion of the deferred tax assets was realizable. Accordingly, a benefit of approximately $6.8 million was recognized during 2003 as the valuation allowance was reduced. In addition, during 2003 the valuation allowance was reduced through the utilization of NOL carryforwards to reduce taxable income as well as the expiration of unused NOL carryforwards. WORKERS COMPENSATION Currently, we are covered under a three year retroactive plan and are providing for our workers compensation claims based upon the most recent information available from our insurance carrier concerning claims and estimated costs. In future years, we may receive retroactive adjustments, both favorable and unfavorable, related to estimates of claim costs for previous years, which may be material to our results of operations. No provision for retroactive adjustments to claim costs is recorded until we receive notification from our insurance carrier because this amount, if any, cannot be estimated. -33- LIQUIDITY AND CAPITAL RESOURCES Cash Flows Cash flow provided by operations was $12.8 million, $20.9 million and $11.9 million in fiscal 2003, 2002 and 2001, respectively. The decrease from fiscal 2002 to 2003 was primarily the result of lower income before taxes in 2003 compared to 2002. Net income in fiscal 2003 included a non-cash deferred tax benefit of $6.8 million. The increase from fiscal 2001 to 2002 was primarily working capital changes due to timing of cash collections and payments. Cash required by investing activities was $12.2 million, $18.3 million and $11.9 million, in fiscal 2003, 2002 and 2001, respectively. Cash flow required by investing activities in all years was primarily for additions to property and equipment. Cash provided (required) by financing activities was $.5 million, $.2 million and ($.7) million in fiscal 2003, 2002 and 2001, respectively. Uses of cash included repayment of bank borrowings of $1.1 million and $1.2 million in fiscal 2002 and 2001, respectively. Sources of cash included proceeds from exercise of stock options and sale of common stock of $.7 million, $1.4 million and $.5 million in fiscal 2003, 2002 and 2001, respectively. In June, 2000, we 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 March 31, 2003. The facility is secured by our 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 4.25% at March 31, 2003. Accrued and unpaid interest on outstanding principal is payable monthly. The loan facility matures on August 31, 2004, at which time all outstanding principal and accrued and unpaid interest will be due and payable in full. At March 31, 2003, 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. We redetermine the borrowing base quarterly, but 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, 2003, the borrowing base amount was approximately $39.6 million. In addition to certain customary affirmative covenants, the loan agreement contains covenants which restrict us from: o incurring additional debt, incurring or permitting liens to exist on any of our property, assets or revenues; o declaring or paying dividends or other distributions on our stock (or acquiring any of our stock); o issuing stock; o entering into transactions with affiliates; o disposing of assets; and o undertaking certain other types of transactions. -34- The loan agreement also contains financial covenants which we must be in compliance with at the end of each fiscal quarter. These requirements include having a tangible net worth of $9.0 million; a current ratio of .80 to 1.00; an interest expense coverage ratio of 3.0 to 1.0; and a debt to worth ratio of 1.0 to 1.0. If the merger with Patterson is not completed, we anticipate that sufficient funds for our capital expenditures in fiscal 2004 will be available from a combination of sources, including: o borrowings under our line of credit; o funds raised through issuances of equity or debt securities in public or private transactions; and o internally generated funds. The following table shows information regarding capital expenditures we made during the last three fiscal years.

We presently anticipate making capital expenditures of approximately $15.0 million in fiscal 2004. Of this amount, we expect that approximately $5.0 million will be spent for the acquisition of drill pipe, drill collars and related equipment, and approximately $10.0 million for oil and gas exploration and development activities. We intend to fund these capital expenditures with cash flow from operations and available borrowings under our loan agreement. It is our policy, however, to make capital expenditures based on prevailing economic conditions, the results of our drilling activities, and other factors affecting our business. Consequently, the amounts actually spent in fiscal 2004 could differ substantially from the amounts estimated. As of March 31, 2003, we had no amounts due under our loan agreement, no capital leases, no conditional purchase obligations and no significant operating leases. TRENDS AND PRICES The contract drilling industry is currently experiencing a slight increase in demand and a firming of prices for contract drilling services due to the recent increase and stability surrounding oil and gas prices. We will continue to be affected by price fluctuations in the industry, but cannot predict either the future level of demand for our 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 state and local agencies, the U.S. and foreign governments and international cartels. We cannot accurately predict the supply of and demand for oil and gas, domestic or international political events or the effects of any of these factors on the prices we receive for the oil and gas we produce. -35- INFLATION Inflation has not had a significant impact on our financial condition or results of operations. We do not believe that inflation poses a material risk to our business. RECENT ACCOUNTING PRONOUNCEMENTS In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" which establishes requirements for the accounting of removal-type costs associated with asset retirements. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted each period toward its future value, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity reports a gain or loss upon settlement to the extent the actual costs differ from the recorded liability. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Company will adopt SFAS No. 143 on April 1, 2003. Upon adoption of SFAS No. 143, the Company will record a benefit of $59,112 (net of tax) as the cumulative effect of the change in accounting principle. The majority of the asset retirement obligation to be recognized will relate to the projected cost to plug and abandon oil and gas wells. 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 adopted this statement on April 1, 2002. The adoption of this statement had no immediate impact on the Company and may result in discontinued operations presentation for future sales of certain assets. In April 2002, the FASB issued Statement No. 145 "Recission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." Most significantly, this Statement eliminates the requirement under Statement 4 to aggregate all gains and losses from extinguishment of debt, and if material, be classified as an extraordinary item. As a result, gains and losses from extinguishment of debt should be classified as extraordinary items only if they meet the criteria in Opinion 30. Applying the provisions of Opinion 30 will distinguish transactions that are part of an entity's recurring operations from those that are unusual or infrequent or that meet the criteria for classification as an extraordinary item. There is no current impact to the Company as it has no outstanding debt. In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities". The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather that at the date of a commitment to an exit or disposal plan. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. We expect no impact to our financial statements as we do not anticipate exiting or disposing of any of our activities. SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure", amends SFAS No. 123, "Accounting for Stock-Based Compensation". SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. The statement also amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and -36- the effect of the method used on reported results. The statement is required to be adopted for fiscal years ending after December 15, 2002. We currently account for stock-based compensation in accordance with APB Opinion No. 25 which allows us to recognize compensation expense only to the extent that the fair market value is greater that the option price. On April 22, 2003, the FASB announced its decision to require all companies to expense the value of employee stock options. Companies will be required to measure the cost according to the fair value of the options. The new guidelines have not been released but are expected to be finalized and to become effective in 2004. When final rules are announced, we will assess the impact to our financial statements. In November 2002, the FASB issued Financial Interpretation No.45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45). FIN No. 45 requires that a liability be recorded in the guarantor's balance sheet upon issuance of certain guarantees. Initial recognition and measurement of the liability will be applied on a prospective basis to guarantees issued or modified after December 31, 2002. FIN No. 45 also requires disclosures about guarantees in financial statements for interim or annual periods ending after December 15, 2002. We do not expect the adoption of FIN No. 45 to have a material impact on our financial statements. FIN No. 46, "Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51". FIN No. 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without financial support from other parties. We do not expect the adoption of FIN No. 46 to have material impact on our financial statements. In May 2003, the FASB issued Statement No. 150 "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK The primary sources of market risk for us include fluctuations in commodity prices and interest rate fluctuations. At March 31, 2003, we were not a party to any hedge arrangements, commodity swap agreements, commodity futures, options or other similar agreements relating to crude oil and natural gas. Commodity Price Risk. Since we produce and sell crude oil, natural gas and natural gas liquids, our operating results are significantly affected by fluctuations in commodity prices caused by changing market forces. Historically, we have not entered into hedging arrangements for our oil and gas production and we have not had any delivery commitments. We may, in the future, attempt to reduce our exposure to the volatility of oil and gas prices by hedging a portion of our production. In a typical hedge transaction, we 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, we would be required to pay the counterparty this difference multiplied by the quantity hedged. In this case, -37- we would be required to pay the difference regardless of whether we 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 us to make payments under the hedge agreements even though the 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, 2003, we had no borrowings outstanding under our loan agreement. However, when we do have outstanding borrowings, our exposure to changes in interest rates primarily results from short term changes in the bank's prime rate. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

-38- Independent Auditors' Report The Board of Directors TMBR/Sharp Drilling, Inc.: We have audited the accompanying balance sheets of TMBR/Sharp Drilling, Inc. as of March 31, 2003 and 2002, and the related statements of operations, stockholders' equity, and cash flows for the years then ended. In connection with our audits of the financial statements, we also have audited the accompanying financial statement schedule. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. The 2001 financial statements and financial statement schedule of the Company were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements and financial statement schedule in their report dated May 18, 2001. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of TMBR/Sharp Drilling, Inc. as of March 31, 2003 and 2002, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. /s/ KPMG LLP Midland, Texas June 5, 2003 -39- REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS This report was issued by Arthur Andersen LLP in connection with the Company's 2001 Form 10-K, has not been reissued by Arthur Andersen LLP and refers to financial statements not physically included in this document. 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. /s/ ARTHUR ANDERSEN LLP Dallas, Texas, May 18, 2001 -40- TMBR/SHARP DRILLING, INC. Balance Sheets March 31, 2003 and 2002 (In thousands, except share data)

See accompanying notes to financial statements. -41- TMBR/SHARP DRILLING, INC. Balance Sheets March 31, 2003 and 2002 (In thousands, except share data)

See accompanying notes to financial statements. -42- TMBR/SHARP DRILLING,, INC. Statements of Operations Years Ended March 31, 2003, 2002 and 2001 (In thousands, except share data)

See accompanying notes to financial statements. -43- TMBR/SHARP DRILLING, INC. Statements of Stockholders' Equity Years Ended March 31, 2003, 2002 and 2001 (In thousands)

See accompanying notes to financial statements. -44- TMBR/SHARP DRILLING, INC. Statements of Cash Flows Years Ended March 31, 2003, 2002 and 2001 (In thousands)

See accompanying notes to financial statements. -45- 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 $0 for 2003 and $21,000 for 2002 and $270,000 in 2001. Cash payments for taxes due totaled $0,$160,000, and $0, during 2003, 2002 and 2001, 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. These securities were sold during the year ended March 31, 2003 and a gain of approximately $12,000 was recognized. 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. -46- TMBR/SHARP DRILLING, INC. Notes to Financial Statements 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 $2,196,000 and $1,967,000 as of March 31, 2003 and 2002, 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. The Company assesses the need for an impairment of capitalized costs of oil and gas properties on a property-by-property basis. 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 $459,000, $3,953,000, and $1,171,000 were recorded in 2003, 2002 and 2001, 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. Due to the nature of turnkey contracts and risks therein, 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. -47- TMBR/SHARP DRILLING, INC. Notes to Financial Statements 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. Net Income (Loss) Per Share of Common Stock Basic earnings per share ("EPS") 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. Diluted EPS includes all potentially dilutive securities. The following table sets forth certain information concerning EPS.

-48- TMBR/SHARP DRILLING, INC. Notes to Financial Statements

-49- 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, as amended by Statement of Financial Accounting Standards No. 148, "Accounting For Stock-based Compensation, Transition and Disclosure" ("SFAS 148"), 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." The SFAS 123 pro forma information for the years ended March 31, 2003, 2002, and 2001 is as follows:

-50- TMBR/SHARP DRILLING, INC. Notes to Financial Statements Recent Accounting Pronouncements In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" which establishes requirements for the accounting of removal-type costs associated with asset retirements. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted each period toward its future value, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity reports a gain or loss upon settlement to the extent the actual costs differ from the recorded liability. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Company will adopt SFAS No. 143 on April 1, 2003. Upon adoption of SFAS No. 143, the Company will record a benefit of $59,112 (net of tax) as the cumulative effect of the change in accounting principle. The majority of the asset retirement obligation to be recognized will relate to the projected cost to plug and abandon oil and gas wells. 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 adopted this statement on April 1, 2002. The adoption of this statement had no immediate impact on the Company and may result in discontinued operations presentation for future sales of certain assets. In April 2002, the FASB issued Statement No. 145 "Recission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." Most significantly, this Statement eliminates the requirement under Statement 4 to aggregate all gains and losses from extinguishment of debt, and if material, be classified as an extraordinary item. As a result, gains and losses from extinguishment of debt should be classified as extraordinary items only if they meet the criteria in Opinion 30. Applying the provisions of Opinion 30 will distinguish transactions that are part of an entity's recurring operations from those that are unusual or infrequent or that meet the criteria for classification as an extraordinary item. There is no current impact to the Company as it has no outstanding debt. -51- TMBR/SHARP DRILLING, INC. Notes to Financial Statements In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities". The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather that at the date of a commitment to an exit or disposal plan. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. The Company expects no impact to its financial statements as the Company does not anticipate exiting or disposing of any of its activities. SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure", amends SFAS No. 123, "Accounting for Stock-Based Compensation". SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. The statement also amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The statement is required to be adopted for fiscal years ending after December 15, 2002. The Company currently accounts for stock-based compensation in accordance with APB Opinion No. 25 which allows the Company to recognize compensation expense only to the extent that the fair market value is greater that the option price. On April 22, 2003, the FASB announced its decision to require all companies to expense the value of employee stock options. Companies will be required to measure the cost according to the fair value of the options. The new guidelines have not been released but are expected to be finalized and to become effective in 2004. When final rules are announced, the Company will assess the impact to its financial statements. In November 2002, the FASB issued Financial Interpretation No.45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45). FIN No. 45 requires that a liability be recorded in the guarantor's balance sheet upon issuance of certain guarantees. Initial recognition and measurement of the liability will be applied on a prospective basis to guarantees issued or modified after December 31, 2002. FIN No. 45 also requires disclosures about guarantees in financial statements for interim or annual periods ending after December 15, 2002. The Company does not expect the adoption of FIN No. 45 to have a material impact on its financial statements. FIN No. 46, "Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51". FIN No. 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without financial support from other parties. The Company does not expect the adoption of FIN No. 46 to have material impact on it financial statements. In May 2003, the FASB issued Statement No. 150 "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. -52- TMBR/SHARP DRILLING, INC. Notes to Financial Statements (2) Debt Line of Credit 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 March 31, 2003. 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 4.25% at March 31, 2003. Accrued and unpaid interest on outstanding principal is payable monthly. The loan facility matures on August 31, 2004, at which time all outstanding principal and accrued and unpaid interest will be due in full. At March 31, 2003 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, 2003, the borrowing base amount was approximately $39.6 million. In addition to certain customary affirmative covenants, the loan agreement contains restrictions with respect to (i) incurring additional debt, (ii) incurring or permitting liens to exist on any of the Company's property, assets or revenues, (iii) declaring or paying dividends or other distributions on its capital stock (or acquiring any of its capital stock), (iv) issuing capital stock, (v) entering into transactions with affiliates, (vi) disposing of assets, and (vii) 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. (3) Stockholders' Equity Stock Option Plans 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. -53- 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. On November 20, 2002, the Company granted options to purchase 98,000 shares of common stock to non-officer key employees under the 1998 Plan. These incentive options were granted at an exercise price of $15.93 per share which represented the fair market value on the date of the grant. These options become earned and exercisable on November 20, 2003. The following sets forth certain information concerning these options. -54- TMBR/SHARP DRILLING, INC. Notes to Financial Statements

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, 2003, 12,500 shares were issued under the Plan and the Company recognized approximately $188,000 as Directors' compensation expense. In connection with a private placement completed in February 1997, the Company issued 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. 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 2003, 2002 and 2001, respectively: dividend yield of 0%, 0% and 0%, expected volatility of 56.0%, 64.7% and 62.53%, risk free interest rate of 3.05%,4.81% and 6.09%, and an expected life of 5.0, 5.0 and 5.0 years. -55- TMBR/SHARP DRILLING, INC. Notes to Financial Statements

(4) Income Taxes At March 31, 2003, the Company had approximately $32,956,000 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 $10.3 million expired in 2003. 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. However, if the merger with Patterson as described in Note 11 is completed, the Company believes a Section 382 change of control will occur as a result of that transaction. -56- TMBR/SHARP DRILLING, INC. Notes to Financial Statements 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:

The Company has provided a valuation allowance for the entire balance of deferred tax assets at March 31, 2002, as it was more likely than not that the deferred tax asset will not be realized. During the year ended March 31, 2003, the Company determined that it was more likely than not that a portion of the deferred tax assets were realizable. Accordingly, the Company has recorded a net deferred tax asset of $6,760,000 at March 31, 2003. A valuation allowance remains against the remaining deferred tax assets. The Company based its assessment of realizability of deferred tax assets after taking into consideration operating results and utilization of operating loss carryforwards over the last several years as well as the current commodity price environment. 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 (in thousands):

-57- TMBR/SHARP DRILLING, INC. Notes to Financial Statements The Company's net operating loss carryforwards at March 31, 2003 expire as follows (in thousands): 2004 $9,601 2005 7,397 2006 5,247 2007 822 2011-2015 9,889 ------- Total $32,956 =======

(5) Related Parties During 2003, 2002 and 2001 the Company sold $29,000, $210,000 and $701,000 and purchased $110,000, $726,000, and $154,000, respectively, of goods and services from entities affiliated with individuals serving as officers and/or directors of the Company. 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 non-interest bearing and are settled in the normal course of business. (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- TMBR/SHARP DRILLING, INC. Notes to Financial Statements The following tables present information related to the Company's reportable segments.

-59- 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, prepaid expenses and deferred tax assets. For the years ended March 31, 2003, 2002 and 2001, contract drilling revenues earned from individual customers constituting 10% or more of total revenues were: (a) three drilling customers in 2003 individually represented approximately 25%, 22%, and 14% of total revenues. (b) one drilling customer in 2002 individually represented approximately 38% of total revenues, (c) two drilling customers in 2001 individually represented approximately 35%, 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) Commitments and Contingencies The Company is a defendant in various lawsuits generally incidental to its business. In addition, in August 2001, the Equal Employment Opportunity Commission ("EEOC") filed suit in the El Paso Division of the United States District Court for the Western District of Texas. The suit involved a claim of hostile work environment made on behalf of four former employees. In May, 2002, the Court transferred the cause to the Midland/Odessa Division. The employees on behalf of whom the Equal Employment Opportunity Commission originally brought suit and one additional employee had recently been allowed to intervene in the litigation on an individual basis. It was expected that these employees would file additional state common law causes of action arising out of the allegations of hostile work environment. The EEOC was seeking back pay, front pay, pecuniary losses and punitive damages of an unspecified amount. The intervenors were seeking unspecified damages. The Company disputed the claims made by the Equal Employment Opportunity Commission and the anticipated claims by the intervenors and intended to defend the lawsuits vigorously. On October 4,2002, these lawsuits, including the lawsuits brought by the EEOC and the five intervenors, were settled within the Company's insurance policy limits. -60- TMBR/SHARP DRILLING, INC. Notes to Financial Statements On May 8, 2002, the Company experienced an uncontrolled flow ("flow") on the Leiman #1 well in Loving County, Texas. The Company has a 25% working interest in this well. The uncontrolled flow was encountered while running a 7 3/4 liner in the well bore. The flow was ultimately controlled with no injury to personnel or damage to the Company's rig or related equipment. The planned total depth of the well was approximately 22,000 feet but the uncontrolled flow was experienced at a depth of 19,115 feet. The well was not salvageable and has been plugged and abandoned. Costs associated with re-gaining control of the well and plugging and abandonment were approximately $1.5 million. The costs to re-drill the well to a depth of 19,115 feet through March 31, 2003 was approximately $9.0 million. The Leiman #1R well was spudded on July 8, 2002. The Company has successfully completed the well and is currently producing the well in a temporary pipeline. The Company has submitted claims for reimbursement from its insurance carrier, St. Paul's Surplus Lines, who has acknowledged coverage under both the control of well and re-drill/replacement well provisions under the Company's Operators Extra Expense insurance. An insurance receivable has been recorded for the Company's portion of the costs of the original Leiman #1 well. The Company's working interest portion of the costs associated with re-drilling this well has been capitalized. 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. Retention Agreements. In November, 2002, we entered into retention agreements with ten of our employees. The retention agreements provide assurance that we will be able to rely on the continued dedication and availability of the services of the employees notwithstanding a change in control or proposed change in control of TMBR/Sharp and the associated personal uncertainties and risks. Generally, a "change in control" occurs on the date: o any person becomes the beneficial owner of more than 50% of the combined voting power of our outstanding securities; o (i) our shareholders approve the consolidation, merger or other business combination of TMBR/Sharp in which we are not the surviving or continuing corporation or pursuant to which shares of our common stock are converted into cash, securities or other property, or (ii) our shareholders approve the sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, of our assets; o our shareholders approve any plan or proposal for the liquidation or dissolution of TMBR/Sharp: o without the approval or recommendation of a majority of our then existing board of directors, a third person causes or brings about (through solicitation of proxies or otherwise) the removal or resignation of a majority of the then existing members of the board of directors or if a third person causes or brings about (through solicitation of proxies or otherwise) an increase in the size of the board of directors such that the then existing members of our board of directors thereafter represent a minority of the total number of persons comprising the entire board; or -61- TMBR/SHARP DRILLING, INC. Notes to Financial Statements o any shares of any class of our stock are purchased pursuant to a tender or exchange offer (other than an offer by us). Under the retention agreements, if (i) a change in control occurs or (ii) we terminate an employee for other than dishonesty, conviction of a felony or the continued failure by the employee to perform the duties assigned to the employee, the employee will receive a bonus equal to the product of the employee's base salary paid by TMBR/Sharp during the preceding twelve months, multiplied by a factor ranging from 1.26 to 2.97. We have no obligation to pay the bonuses required under the retention agreements if an employee dies, becomes disabled, retires, ceases to act in his or her position or voluntarily terminates his or her employment prior to the occurrence of either of the events described in (i) and (ii) of this paragraph. Bonuses payable to a employee may not exceed $1.00 less than three times the employee's "base amount" within the meaning of Section 280G of the Internal Revenue Code. The retention agreements remain in effect through December 31, 2003, and will be automatically extended for additional one year periods thereafter, unless by September 30 of any year we give notice that a retention agreement will not be extended. (8) Supplemental Information Related to Oil and Gas Activities The Company's capitalized cost of oil and gas properties is as follows:

The Company's costs incurred related to oil and gas property acquisition, exploration and development activities are as follows:

-62- TMBR/SHARP DRILLING, INC. Notes to Financial Statements The Company's results of operations from oil and gas producing activities are as follows:

(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. -63- 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, 2003, 2002 and 2001 were as follows: $28.93, $23.36 and $28.16 per barrel of oil, respectively, and $4.716, $3.318 and $5.861 per Mcf for natural gas, respectively. The following sets forth proved oil and gas reserves at March 31, 2003, 2002 and 2001:

The downward revision of previous estimates in crude oil reserves for the year ended March 31, 2003 is due to adjustments of forecasts and decline curves for certain wells added in prior years. The upward revisions of natural gas for the year ended March 31, 2003 is primarily due to the increase in natural gas prices. 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. -64- TMBR/SHARP DRILLING, INC. Notes to Financial Statements

-65- TMBR/SHARP DRILLING, INC. Notes to Financial Statements (10) Supplementary Quarterly Financial Data (Unaudited)

(11) Subsequent Events On May 26, 2003, we entered into an Agreement and Plan of Merger, dated as of May 26, 2003, with Patterson-UTI Energy, Inc. and Patterson-UTI Acquisition, LLC, a Texas limited liability company and a wholly owned subsidiary of Patterson-UTI Energy, Inc. Under terms of the merger agreement, we will merge with and into Patterson-UTI Acquisition, LLC, with Patterson-UTI Acquisition, LLC being the surviving company. Subject to the terms and conditions in the merger agreement, each issued and outstanding share of our common stock not owned directly or indirectly by Patterson-UTI Energy, Inc. or by us (except shares of common stock held by persons who object to the merger, and who comply with all of the provisions of Texas law concerning the right of holders of shares of common stock to dissent from the merger and require appraisal of their common stock), will be converted into the right to receive $9.09 in cash and 0.312166 of a share of common stock, $.01 par value per share, of Patterson-UTI Energy, Inc. Patterson-UTI Energy, Inc. will pay each holder cash in lieu of any fractional shares. -66- Under the terms of the merger agreement, we agreed not to solicit competing offers, but we may consider and accept an unsolicited offer if, based on advice of counsel, we believe we must do so in the exercise of our fiduciary duty. If we accept an unsolicited offer, or our board of directors withdraws its recommendation in light of an unsolicited offer, or the shareholders do not vote to approve the merger because of an unsolicited offer, we would be required to pay to Patterson a breakup fee of $3.5 million. The merger is subject to customary conditions to closing, including approval by our shareholders, as well as any necessary regulatory filings and approvals, such as the anti-trust provisions of the Hart-Scott-Rodino Act. There can be no assurance that the merger will be consummated in accordance with the terms of the merger agreement, if at all. 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 KPMG 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. -67- PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The directors and officers of TMBR/Sharp at June 10, 2003 were as follows:

---------- (1) Member of Compensation Committee. (2) Member of Audit Committee. Officers are appointed annually by the board of directors to serve at the board's discretion and until his successor in office is elected and qualified. Directors hold office until the annual meeting of shareholders following their election or appointment and until their respective successors have been duly elected or appointed. Mr. Brown has served as a director of TMBR/Sharp since 1982. He is presently Chairman of the Board of Directors and Chief Executive Officer and has served in such capacities since 1990. Mr. Fitzgerald has served as a director 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 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 since April, 2001. He has been President of BHC Pipe & Equipment Company since 1987. -68- Mr. Taylor has served as a director 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 TMBR/Sharp 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 TMBR/Sharp since 1982. He has been the Vice President - Operations of the Company since 1992. Ms. Elledge was employed by TMBR/Sharp from September, 1989 to December, 1993 when she resigned to relocate. Ms. Elledge returned to TMBR/Sharp in September, 1994 in her current capacity as Controller - Treasurer. Mr. Alsup has been the Secretary of TMBR/Sharp since 1982. He has been a partner in the law firm of Lynch, Chappell & Alsup, P.C., Midland, Texas, since 1970. There are no family relationships between any of our directors or officers. SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE Section 16(a) of the Securities Exchange Act of 1934 requires TMBR/Sharp's directors and officers to file periodic reports with the SEC. These reports show the directors' and officers' ownership, and the changes in ownership, of TMBR/Sharp's common stock and other equity securities. To our knowledge, all Section 16(a) filing requirements were complied with during the fiscal year ended March 31, 2003. -69- ITEM 11. EXECUTIVE COMPENSATION SUMMARY OF ANNUAL COMPENSATION The table below shows a summary of the types and amounts of compensation paid to the chief executive officer and the only other executive officers whose salary and bonuses for the fiscal year ended March 31, 2003 exceeded $100,000. Summary Compensation Table

------------ (1) The named executive officers were also provided certain non-cash compensation and personal benefits. However, the aggregate amount of such other compensation did not exceed $50,000 or 10% of the named executive officer's salary during such fiscal year. STOCK OPTIONS We use stock options as part of the overall compensation of directors, officers and employees. Summary descriptions of our stock option plans are included in this report so you can review the types of options we have granted and the significant features of our stock options. No options were granted to officers or directors during the fiscal year ended March 31, 2003. Incentive options to purchase 98,000 shares of common stock were issued to other key employees under our 1998 Stock Option Plan. -70- In the following table, we show certain information about stock option exercises during the fiscal year ended March 31, 2003 and the value of unexpired stock options held by the named executive officers at March 31, 2003. Aggregated Option/SAR Exercises in Last Fiscal Year and Fiscal Year - End Option/SAR Values

--------- (1) The value realized is equal to the fair market value of a share of common stock on the date of exercise, based on the last sale price of our common stock, less the exercise price. (2) The value of in-the-money options is equal to the fair market value of a share of common stock at fiscal year-end, based on the last sale price of our common stock, less the exercise price. COMPENSATION OF DIRECTORS On June 14, 2001, the board of directors adopted the TMBR/Sharp Drilling, Inc. Directors Fee Stock Plan. Under this plan, nonemployee directors are each entitled to receive 300 shares of common stock for each Board meeting that the nonemployee director attends and 100 shares of common stock for attendance at each meeting of any board committee on which he serves. We reserved a total of 25,000 shares of our common stock for issuance under this stock plan. For their attendance at board and committee meetings held during the fiscal year ended March 31, 2003, Mr. Fitzgerald received 3,400 shares; Mr. Cone 3,300 shares; Mr. Taylor 3,000 shares; and Mr. Batchelor 2,800 shares. We also reimburse directors for their travel expenses incurred in connection with attendance at Board meetings and board committee meetings. Directors who are our employees are eligible to participate in all of our stock option plans. Nonemployee directors are eligible to participate only in the 1998 Stock Option Plan. -71- 1994 STOCK OPTION PLAN In July, 1994, the board of directors adopted the TMBR/Sharp Drilling, Inc. 1994 Stock Option Plan, which was ratified and adopted by our shareholders at the 1994 annual meeting of shareholders held on August 30, 1994. Options granted under the 1994 Plan may be either incentive stock options within the meaning of Section 422 of the Internal Revenue Code, or options which do not constitute incentive stock options. Our key employees (including officers and directors who are also key employees) are eligible to receive options under the 1994 Plan. The 1994 Plan is administered by the Compensation Committee of the Board of Directors. The Compensation Committee has the authority to select employees who are to be granted options and to establish the number of shares issuable under each option. Options granted to an employee contain such terms and conditions and may be exercisable for such periods as may be approved by the Compensation Committee. The purchase price of common stock issued under each option will not be less than the fair market value of the stock subject to the option at the time of grant. The Compensation Committee, in its discretion, may provide for the payment of the option price, in whole or in part, in cash at the time of exercise, by the delivery of a number of shares of common stock (plus cash if necessary) having a fair market value on the date of delivery equal to the option exercise price, or any combination of cash and stock. The aggregate number of shares of common stock which may be issued pursuant to the exercise of stock options granted under the 1994 Plan may not exceed 750,000 shares, subject to adjustment in the number of shares with respect to options and purchase prices therefor in the event of stock splits or stock dividends, and for equitable adjustments upon certain recapitalizations, mergers, consolidations or acquisitions. If any outstanding option granted under the 1994 Plan expires or terminates prior to its exercise in full, the shares allocable to the unexercised portion of such option may be subsequently granted under the 1994 Plan. The 1994 Plan provides that to the extent the aggregate fair market value of the common stock (determined at the time of grant) with respect to which incentive options are exercisable for the first time by an individual during any calendar year under all of our incentive stock option plans exceeds $100,000, the incentive stock options will be treated as options which do not constitute incentive stock options. The Compensation Committee determines, in accordance with applicable provisions of the Internal Revenue Code, which of an optionee's incentive stock options will not constitute incentive stock options because of this limitation. No incentive stock option may be granted to an individual if, at the time the option is granted, such individual owns stock possessing more than 10% of the total combined voting power of all of our classes of stock, unless at the time the option is granted the option price is at least 110% of the fair market value of the stock subject to the option and the option by its terms is not exercisable after the expiration of five years from the date of grant. An option may be granted in exchange for an individual's right and option to purchase shares of common stock pursuant to the terms of an agreement that existed prior to the date such option is granted. An option agreement that grants an option in exchange for a prior option must provide for the surrender and cancellation of the prior option. The purchase price of common stock issued under an option granted in exchange for a prior option is determined by the Compensation Committee, and may be equal to the price for which the optionee could have purchased common stock under the prior option. The Board of Directors may amend or terminate the 1994 Plan at any time, but may not in any way impair the rights of an optionee under an outstanding option without the consent of the optionee. In addition, in order to obtain the benefits provided by Section 422 of the Internal Revenue Code, the Board of Directors will determine at the time of making each amendment whether or not it is necessary to submit the amendment to the shareholders for approval. -72- Generally, however, no amendment may be made without shareholder approval if the amendment would materially increase the benefits accruing to employee optionees, materially increase the number of securities issuable under the 1994 Plan, or materially modify the requirements as to eligibility for participation in the 1994 Plan. Unless earlier terminated, the 1994 Plan will terminate upon and no further options may be granted after the expiration of ten years from the date of its adoption by the Board of Directors. At May 23, 2003, options to purchase a total of 240,000 shares of common stock were outstanding under this plan. No additional options are available to be granted under the 1994 Plan. 1998 STOCK OPTION PLAN On September 1, 1998, the board of directors adopted the TMBR/Sharp Drilling, Inc. 1998 Stock Option Plan, which was ratified and adopted by the shareholders at the annual meeting of shareholders held on August 31, 1999. Subject to selection by the Compensation Committee, key employees and nonemployee directors are eligible to receive one or more options under the 1998 Plan. Stock options granted under the 1998 Plan to key employees may be either incentive stock options within the meaning of Section 422 of the Internal Revenue Code, or stock options which do not constitute incentive stock options. Options granted to nonemployee directors will be nonqualified stock options. The Compensation Committee administers the 1998 Plan and has the sole authority to select the employees and nonemployee directors who are to be granted options and to establish the number of shares issuable under each option. The aggregate number of shares of common stock which may be issued pursuant to the exercise of stock options granted under the 1998 Plan may not exceed in the aggregate 750,000 shares, subject to adjustment in the number of shares with respect to options and purchase prices in the event of stock splits or stock dividends, and for equitable adjustments in the event of recapitalizations, mergers, consolidations, acquisitions of more than 50% of the outstanding shares of common stock by any person or entity, dissolution and liquidation, and similar events. If any outstanding option granted under the 1998 Plan expires or terminates prior to its exercise in full, the shares allocable to the unexercised portion of such option may be subsequently granted under the 1998 Plan. Options granted under the 1998 Plan contain such terms and conditions and may be exercisable for such periods as may be approved by the Compensation Committee. The Compensation Committee is empowered and authorized, but is not required, to provide for the exercise of options by payment in cash or by delivery of shares of common stock having a fair market value equal to the purchase price, or any combination of cash or common stock. The purchase price of common stock issued under each option will not be less than the fair market value of the stock subject to the option at the time of grant. Options granted under the 1998 Plan are not transferable other than by will or the laws of descent and distribution and are exercisable during the optionee's lifetime only by the optionee and while the optionee is one of our employees or directors, except that if the optionee ceases to be one of our employees or directors as a result of death or disability, any options held by the optionee may be exercised in full by the optionee's legal representative at any time during the period of one year following such termination. If an optionee ceases to be one of our employees or directors other than for cause, death or disability, options may be exercised within three months thereafter, but -73- only as to the number of shares the optionee was entitled to purchase as of the date the optionee ceased to be an employee or director. The Board of Directors may amend or terminate the 1998 Plan at any time, but may not in any way impair the rights of an optionee under an outstanding option without the consent of the optionee. The 1998 Plan will terminate ten years from the date of its adoption by the Board of Directors. At May 23, 2003, options to purchase a total of 344,250 shares of common stock were outstanding under this plan, and 270,000 shares were available at that same date for future option grants. CHANGE OF CONTROL ARRANGEMENTS Stock Option Plans. Our stock option plans and stock option agreements contain provisions which, upon the occurrence of certain events, could result in additional compensation to the option holders. These events include the following: if (1)we are not the surviving entity in any merger or consolidation, (2) we sell, lease or exchange or agree to sell, lease or exchange all or substantially all of our assets, (3) we are to be dissolved and liquidated, (4) any person or entity, including a "group" as contemplated by Section 13(d)(3) of the Securities Exchange Act of 1934, as amended, acquires or gains ownership or control of more than 50% of the outstanding shares of common stock, or (5) as a result of or in connection with a contested election of directors, the persons who were our directors before the election cease to constitute a majority of the Board (each such event, a "Corporate Change"), then the Compensation Committee will effect one or more of the following alternatives with respect to the then outstanding options held by employees, which may vary among individual employee optionees: (1) accelerate the time at which such options may be exercised so that such options may be exercised in full for a limited period of time on or before a specified date (before or after such Corporate Change) fixed by the Compensation Committee, after which specified date all unexercised options and all rights of employee optionees thereunder will terminate, (2) require the mandatory surrender to us by selected optionees of some or all of such options as of a date specified by the Compensation Committee, in which event the Compensation Committee will cancel such options and pay to each optionee an amount of cash per share equal to the excess of the fair market value, or in the case of stock options granted under the 1994 stock option plan the "Change of Control Value" of the shares subject to such option, over the exercise price(s) under such options for such shares, (3) make such adjustments to the options as the Compensation Committee deems appropriate to reflect such Corporate Change or (4) provide that thereafter upon any exercise of an option theretofore granted the optionee will be entitled to purchase under such option, in lieu of the number of shares of common stock as to which the option will then be exercisable, the number and class of shares of stock or other securities or property to which the optionee would have been entitled pursuant to the terms of the agreement of merger, consolidation or sale of assets and dissolution if, immediately prior to such merger, consolidation or sale of assets and dissolution the optionee had been the holder of record of the number of shares of common stock as to which such option is then exercisable. For purposes of the 1994 stock option plan, the "Change of Control Value" is an amount determined as follows, whichever is applicable: (1) the per share price offered to our shareholders in any merger, consolidation, sale of assets or dissolution transaction, (2) the price per share offered to our shareholders in any tender offer or exchange offer whereby a Corporate Change takes place, or (3) if a Corporate Change occurs other than pursuant to a tender or exchange offer, the fair market value per share of the shares into which the options being surrendered are exercisable, as determined by the Compensation Committee as of the date determined by the Compensation Committee to be the date of cancellation and surrender of such options. If the consideration offered to shareholders consists of anything other than cash, the Compensation Committee will -74- determine the fair cash equivalent of the portion of the consideration offered which is other than cash. Retention Agreements. In November, 2002, we entered into retention agreements with ten of our employees, including Mr. Brown, the Chairman of the Board of Directors and Chief Executive Officer of TMBR/Sharp; Mr. Phillips, the President of TMBR/Sharp; Ms. Elledge, the controller of TMBR/Sharp; and Mr. Lawson, Vice President-Operations of TMBR/Sharp. The retention agreements provide assurance that we will be able to rely on the continued dedication and availability of the services of the employees notwithstanding a change in control or proposed change in control of TMBR/Sharp and the associated personal uncertainties and risks. Generally, a "change in control" occurs on the date: o any person becomes the beneficial owner of more than 50% of the combined voting power of our outstanding securities; o (i) our shareholders approve the consolidation, merger or other business combination of TMBR/Sharp in which we are not the surviving or continuing corporation or pursuant to which shares of our common stock are converted into cash, securities or other property, or (ii) our shareholders approve the sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, of our assets; o our shareholders approve any plan or proposal for the liquidation or dissolution of TMBR/Sharp: o without the approval or recommendation of a majority of our then existing board of directors, a third person causes or brings about (through solicitation of proxies or otherwise) the removal or resignation of a majority of the then existing members of the board of directors or if a third person causes or brings about (through solicitation of proxies or otherwise) an increase in the size of the board of directors such that the then existing members of our board of directors thereafter represent a minority of the total number of persons comprising the entire board; or o any shares of any class of our stock are purchased pursuant to a tender or exchange offer (other than an offer by us). Under the retention agreements, if (i) a change in control occurs or (ii) we terminate an employee for other than dishonesty, conviction of a felony or the continued failure by the employee to perform the duties assigned to the employee, the employee will receive a bonus equal to the product of the employee's base salary paid by us during the preceding twelve months, multiplied by a factor ranging from 1.26 to 2.97. In the case of Mr. Brown, he would receive a bonus payment in an amount equal to 2.92 times his salary for the preceding twelve month period; Mr. Phillips would receive 2.97 times his salary; Ms. Elledge 1.60 times her salary; and Mr. Lawson, 1.80 times his salary. We have no obligation to pay the bonuses required under the retention agreements if an employee dies, becomes disabled, retires, ceases to act in his or her position or voluntarily terminates his or her employment prior to the occurrence of either of the events described in (i) and (ii) of this paragraph. Bonuses payable to a employee may not exceed $1.00 less than three times the employee's "base amount" within the meaning of Section 280G of the Internal Revenue Code. The retention agreements remain in effect through December 31, 2003, and will be automatically extended for additional one year periods thereafter, unless by September 30 of any year we give notice that a retention agreement will not be extended. -75- COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION During the fiscal year ended March 31, 2003, the members of our Compensation Committee were David N. Fitzgerald and Raymond E. Batchelor. Mr. Batchelor, one of our directors since 2001, is the president and controlling shareholder of BHC Pipe and Equipment Company, an oilfield equipment supply company. During the fiscal year ended March 31, 2003, we paid a total of approximately $97,577 to BHC for the purchase of drilling equipment and related oilfield supplies and equipment. We have a long-standing relationship with BHC and have purchased oilfield drilling equipment and related materials from BHC for more than twelve years. We believe our transactions with BHC are as favorable as we could obtain from an unaffiliated third party. During the fiscal year ended March 31, 2003, the largest amount we owed BHC was approximately $34,126, none of which was unpaid at March 31, 2003. Payments for equipment purchased from BHC are made in the regular course of business, without interest, upon receipt of invoices from BHC. -76- ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS This table shows information as of June 10, 2003 (unless otherwise indicated), about the beneficial ownership of our common stock by (1) each person known by us to be the beneficial owner of more than five percent of our outstanding shares of common stock, (2) the executive officers named in the Summary Compensation Table in this report, (3) each director and (4) all directors and executive officers as a group.

------------ * Less than 1%. -77- (1) Unless otherwise indicated, all shares of common stock are held directly with sole voting and investment powers. (2) Of the total number of shares shown, 200 shares are held indirectly through Mr. Batchelor's wife and 600 shares are held indirectly through Mr. Batchelor's wife in her capacity as trustee for three minor grandchildren. Mr. Batchelor disclaims beneficial ownership of all shares held in trust for his grandchildren. (3) Includes 209,000 shares of common stock underlying presently exercisable stock options. (4) Includes 10,000 shares of common stock that may be acquired upon exercise of presently exercisable stock options. (5) All of such shares may be acquired upon exercise of presently exercisable stock options. (6) In Schedule 13G, Amendment No. 10, dated May 9, 2003, filed with the SEC by State Street Research & Management Company, State Street reported beneficial ownership of 689,700 shares, of which it reported sole voting power with respect to 685,200 shares and sole dispositive power with respect to 689,700 shares. State Street disclaimed any beneficial interest in these shares. (7) Based on Schedule 13D, dated June 13, 2002, and filed with the SEC on June 21, 2002, Patterson-UTI Energy, Inc. reported sole voting power with respect to 1,058,597 shares; sole dispositive power with respect to 762,597 shares; and shared dispositive power with respect to 265,000 shares. As reported, the total number of shares included an option to purchase all or part of 195,000 shares of common stock (the "option shares") between October 26, 2002 and December 16, 2002. The grantor of the option also had the right to require Patterson-UTI Energy, Inc. to purchase all or any part of such 195,000 shares at any time between October 26, 2002 and December 16, 2002. Also included in the total number of shares are 101,000 shares that Patterson-UTI Energy, Inc. was granted an irrevocable proxy to vote until December 16, 2002. On October 31, 2002, Patterson-UTI Energy, Inc. filed with the SEC Amendment No. 1 to Schedule 13D reporting its purchase of the option shares, the 101,000 shares of stock subject to the irrevocable proxy and an additional 76 shares. (8) Includes 308,000 shares of common stock underlying presently exercisable stock options. CHANGE OF CONTROL If the proposed merger with Patterson is completed, a change of control of TMBR/Sharp will occur at the effective time of the merger. -78- ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Until September, 1984, our company was a wholly owned subsidiary of Tom Brown, Inc. In September, 1984, Tom Brown, Inc. distributed our common stock to the stockholders of Tom Brown, Inc. Mr. Brown, our chairman of the board of directors and chief executive officer, served as a director of Tom Brown, Inc. until May, 2003. Both before and after this spin-off, we have provided contract drilling services to Tom Brown, Inc. in connection with its oil and gas exploration and development activities. However, during the fiscal year ended March 31, 2003, we did not provide any contract drilling services to Tom Brown, Inc. Additionally, from time to time, we acquire interests in leases from Tom Brown, Inc. and participate with Tom Brown, Inc. and other interest owners in the drilling and development of leases where Tom Brown, Inc. acts as operator. We participate in these drilling ventures under standard form operating agreements on the same or similar terms afforded by Tom Brown, Inc. to unaffiliated third parties. Tom Brown, Inc. invoices all working interest owners, including us, on a monthly basis for their respective share of operating and drilling expenses. During the year ended March 31, 2003, Tom Brown, Inc. billed us approximately $12,805 for our proportionate share of drilling costs and related expenses incurred on properties operated by Tom Brown, Inc., approximately $4,570 of which was unpaid and outstanding at March 31, 2003. The largest amount owed by us to Tom Brown, Inc. at any one time during the fiscal year ended March 31, 2003 for our share of drilling costs and related expenses was approximately $4,570. Mr. Batchelor, a director of TMBR since 2001, is the president and controlling shareholder of BHC Pipe and Equipment Company, an oilfield equipment supply company. During the fiscal year ended March 31, 2003, TMBR paid a total of approximately $97,577 to BHC for the purchase of drilling equipment and related oilfield supplies and equipment. TMBR has a long-standing relationship with BHC and has purchased oilfield drilling equipment and related materials from BHC for more than twelve years. We believe TMBR's transactions with BHC are as favorable as TMBR could obtain from an unaffiliated third party. During the fiscal year ended March 31, 2003, the largest amount we owed BHC was approximately $34,126, none of which was unpaid at March 31, 2003. Payments for equipment purchased from BHC are made in the regular course of business, without interest, upon receipt of invoices from BHC. ITEM 14. CONTROLS AND PROCEDURES Mr. Brown, our chairman of the board and chief executive officer, and Ms. Elledge, our controller and chief financial officer (our principal executive officer and principal financial officer, respectively), have concluded, based on their evaluation as of a date within 90 days prior to the date of the filing of this report, that our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in the reports filed or submitted by us under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our chairman of the board and chief executive officer, as appropriate to allow timely decisions regarding required disclosure. As part of their evaluation, Mr. Brown and Ms. Elledge determined that there were no significant changes in internal controls or other factors that could significantly affect internal controls after the date of their evaluation. No corrective actions were required to be taken with regard to significant deficiencies or material weaknesses. Following the signature page of this report, you will find certifications signed by Mr. Brown and Ms. Elledge. -79- PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K Page (a) The following documents are filed as part of this report: (1) See Index to Financial Statements at Item 8 (2) Financial Statement Schedules Years ended March 31, 2003, 2002 and 2001 Schedule II - Valuation and Qualifying Accounts All other schedules are omitted as the required information is inapplicable or the information is presented in the Financial Statements or related notes. (3) Exhibits: The following documents are filed as exhibits to this report:

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----------- *Filed herewith (b) No reports on Form 8-K were filed during the last quarter of fiscal 2003. -83- Schedule II TMBR/SHARP DRILLING, INC. Valuation and Qualifying Accounts Years ended March 31, 2003, 2002 and 2001

-84- 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 26, 2003 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 26, 2003 /s/ Thomas C. Brown ----------------------------- Thomas C. Brown, Chairman of the Board of Directors (Principal Executive Officer) June 26, 2003 /s/ Jeffrey D. Phillips ------------------------------ Jeffrey D. Phillips, President June 26, 2003 /s/ Patricia R. Elledge -------------------------------- Patricia R. Elledge, Controller/ Treasurer (Principal Financial Officer) June 26, 2003 /s/ David N. Fitzgerald ------------------------------ David N. Fitzgerald, Director June 26, 2003 /s/ Michael M. Cone ------------------------- Michael M. Cone, Director June 26, 2003 /s/ Raymond E. Batchelor ------------------------------ Raymond E. Batchelor, Director June 26, 2003 /s/ James B. Taylor ------------------------------ James B. Taylor, Director -85- CERTIFICATIONS I, Thomas C. Brown, certify that: 1. I have reviewed this annual report on Form 10-K of TMBR/Sharp Drilling, Inc. 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) Evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) Presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Dated: June 26, 2003. /s/ Thomas C. Brown ---------------------------------------- Thomas C. Brown, Chief Executive Officer -86- CERTIFICATIONS I, Patricia R. Elledge, certify that: 1. I have reviewed this annual report on Form 10-K of TMBR/Sharp Drilling, Inc. 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) Evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) Presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Dated: June 26, 2003. /s/ Patricia R. Elledge -------------------------------------------- Patricia R. Elledge, Chief Financial Officer -87- INDEX TO EXHIBITS

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TMBR SHARP DRILLING INC 10-K