<PAGE> 1
                    SECURITIES AND EXCHANGE COMMISSION
                          WASHINGTON, D. C. 20549

                                 FORM 10-K

  (X)        ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF
                    THE SECURITIES EXCHANGE ACT OF 1934
                              (Fee Required)

              For the fiscal year ended March 31, 2002
                                    or

  ( )        TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                  OF THE SECURITIES EXCHANGE ACT OF 1934

                      Commission File Number 0-12757

                         TMBR/SHARP DRILLING, INC.
          (Exact name of registrant as specified in its charter)

                TEXAS                                  75-1835108
      (State of Incorporation)           (I.R.S. Employer Identification No.)

               4607 WEST INDUSTRIAL BLVD., MIDLAND, TEXAS   79703
               (Address of principal executive offices)   (Zip Code)

         Registrant's telephone number (area code) (915) 699-5050

     Securities registered pursuant to Section 12(b) of the Act:  None

        Securities registered pursuant to Section 12(g) of the Act:

                       Common Stock, $.10 Par Value
                             (Title of Class)

     Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.

                                                Yes  X      No

     Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of Registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-
K or any amendment to this Form 10-K. (X)

     The aggregate market value of voting stock held by nonaffiliates of the
registrant at June 7, 2002 was approximately $57,486,671.

     At June 7, 2002, there were 5,400,186 shares of the Registrant's Common
Stock outstanding.

     The information required by Items 11, 12 and 13 of Part III of this Form
10-K are incorporated by reference from the registrant's Proxy Statement to
be filed pursuant to Regulation 14A with respect to the registrant's Annual
Meeting to be held in August, 2002.
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                         TMBR/SHARP DRILLING, INC.

                                 FORM 10-K

                             TABLE OF CONTENTS



Part I                                                            Page

     Item  1.  Business. . . . . . . . . . . . . . . . . . . . . . . .    4
     Item  2.  Properties. . . . . . . . . . . . . . . . . . . . . .     25
     Item  3.  Legal Proceedings . . . . . . . . . . . . . . . . . .     26
     Item  4.  Submission of Matters to a Vote of
                 Security Holders. . . . . . . . . . . . . . . . . .     26

Part II

     Item  5.  Market for Registrant's Common Equity
                 and Related Stockholder Matters . . . . . . . . . .     26
     Item  6.  Selected Financial Data . . . . . . . . . . . . . . . .   28
     Item  7.  Management's Discussion and Analysis
                 of Financial Condition and Results
                 of Operations . . . . . . . . . . . . . . . . . . . .   29
     Item  7A. Quantitative and Qualitative Disclosure
                 About Market Risk . . . . . . . . . . . . . . . . . .   37
     Item  8.  Financial Statements and Supplementary Data . . . . . .   38
     Item  9.  Changes in and Disagreements with Accountants
                 on Accounting and Financial Disclosure. . . . . . . .   66

Part III

     Item 10.  Directors and Executive Officers
                 of the Registrant . . . . . . . . . . . . . . . . . .   67
     Item 11.  Executive Compensation. . . . . . . . . . . . . . . . .   68
     Item 12.  Security Ownership of Certain Beneficial
                 Owners and Management . . . . . . . . . . . . . . . .   68
     Item 13.  Certain Relationships and Related Transactions. . . . .   69

Part IV and signatures

     Item 14.  Exhibits, Financial Statement Schedules
                 and Reports on Form 8-K . . . . . . . . . . . . . . .   69
     Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . .   74









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                                  PART I


     Some statements contained in this Form 10-K report are "forward-looking
statements".  All statements other than statements of historical facts
included in this report, including, without limitation, statements regarding
planned capital expenditures, the availability of capital resources to fund
capital expenditures, estimates of proved reserves, the Company's financial
position, business strategy and other plans and objectives for future
operations, are forward-looking statements.  Forward-looking statements can
be identified by the use of forward-looking terminology like "may," "will,"
"expect," "intend,""anticipate," "estimate," "continue," "present value,"
"future" or "reserves" or other variations of comparable terminology.  The
Company believes the assumptions and expectations reflected in these forward-
looking statements are reasonable.  However, no assurance can be given that
the Company's expectations will prove to be correct or that it will be able
to take any actions that are presently planned.  All of these statements
involve assumptions of future events and risks and uncertainties.  Risks and
uncertainties associated with forward-looking statements include, but are not
limited to:

          fluctuations in prices of oil and gas;

          future capital requirements and availability of financing;

          risks associated with the drilling of wells;

          competition;

          general economic conditions;

          governmental regulations;

          receipt of amounts owed to the Company by purchasers of its
          production and counterparties to its hedging contracts; and

          hedging activities.

     For these and other reasons, actual results may differ materially from
those projected or implied.  Undue reliance should not be placed on forward-
looking statements and projections of any future results should not be based
on such statements.

     Before investing in the Company's common stock, one should be aware that
there are various risks associated with an investment.  Some of these
described in other sections of this annual report and under the Risk Factors
section beginning on page 18.






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Item 1.  BUSINESS

General

     TMBR/Sharp Drilling, Inc. (the "Company") was incorporated under the
laws of Texas in October, 1982 under the name TMBR Drilling, Inc.  In August,
1986, the Company changed its name to TMBR/Sharp Drilling, Inc.

     The principal executive offices of the Company are located at 4607 West
Industrial Blvd., Midland, Texas, 79703 and its telephone number is (915)
699-5050.

     The Company is engaged in two lines of business, which include the
domestic onshore contract drilling  of oil and gas wells, and the
acquisition, exploration for, development, production and sale of oil and
natural gas.

     The Company provides domestic onshore contract drilling services to
major and independent oil and gas companies.  The Company focuses its
operations in the Permian Basin of west Texas and eastern New Mexico.  In
addition to its drilling rigs, the Company provides the crews and most of the
ancillary equipment used in the operation of its drilling rigs.  Rig
utilization for the fiscal year ended March 31, 2002 was approximately 67%
compared to 68% for the year ended March 31, 2001.

     The Company owns 18 drilling rigs.  At June 7, 2002, 1 rig was operating
on behalf of the Company for its own account, 10 were operating for non-
affiliated oil producers, and 7 were "stacked" (non-operating).  All of the
Company's rigs are operational and actively marketed in the Permian Basin of
west Texas and eastern New Mexico.  The Company markets its contract drilling
services to both major oil companies and independent oil producers.  The
depth capabilities of the Company's rigs range from 8,500 feet to 30,000
feet.

     An onshore drilling rig consists of engines, drawworks, mast, pumps to
circulate drilling fluids, blowout preventers, the drillstring and related
equipment.  The size and type of rig utilized for each drilling project
depends upon the location of the well, the well depth and equipment
requirements specified in the drilling contract, among other factors.

     The Company believes it has established a reputation for reliability,
high quality equipment and well-trained crews.  The Company continually seeks
to modify and upgrade its equipment to maximize the performance and
capabilities of its drilling rig fleet, which the Company believes provides
it with a competitive advantage.  The Company has the capability to design,
repair and modify its drilling rig fleet from its principal support and
storage facilities in Midland, Texas, and an additional storage yard in
Odessa, Texas.

     The Company's oil and gas exploration and production operations
complement its onshore drilling operations.  These activities are focused in
the mature producing regions in the Permian Basin of west Texas and eastern
New Mexico.  Oil and gas operations comprised approximately 11% of the
Company's revenues for the fiscal year ended March 31, 2002.  The Company's


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proved reserves, of which approximately 1,594 MBOE (thousand barrels of oil
equivalent) were proved developed producing and approximately 353 MBOE were
proved developed non-producing and approximately 337 MBOE were proved
undeveloped, had a present value of future net revenues of approximately
$21.7 million at March 31, 2002.  At that same date, the Company owned
interests in approximately 23,851 gross (4,714 net) acres of developed oil
and gas properties, and approximately 19,027 gross (4,981 net) acres of
undeveloped properties.

     The contract drilling industry is highly sensitive to oil and gas
industry conditions.  Since the early 1980's, many oil and gas exploration
companies significantly reduced their drilling budgets due to the low oil and
gas prices.  As a result, the Company encountered substantial competition
from other drilling contractors.  In recent years, competition within the
drilling industry has been intense due to depressed demand for contract
drilling services.  Industry conditions began to improve during the second
quarter of fiscal 2000 and have continued to the present, primarily because
of higher crude oil and natural gas prices.

     The Company's profitability and cash flows are highly dependent on the
prices of oil and natural gas.  Low oil and natural gas prices have
historically had a material adverse effect on the Company's cash flows and
profitability.  If prices become depressed for a sustained period of time, a
material adverse effect on the Company's future operations and financial
condition would be expected.

     The Company has no material patents, licenses, franchises, or
concessions which it considers significant to its operations.

     The nature of the Company's business is such that it does not maintain
or require a "backlog" of products, customer orders, or inventory.

     The Company's operations are not subject to renegotiation of profits or
termination of contracts at the election of the federal government.

     The Company has not been a party to any bankruptcy, receivership,
reorganization, adjustment, or similar proceeding.

     Generally, the Company's business activities are not seasonal in nature.
However, weather conditions can hinder drilling activities.













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CONTRACT DRILLING OPERATIONS

Drilling Rigs

     The following table sets forth the type and depth capabilities of the
Company's 18 onshore drilling rigs.

     Rig No.        Depth Capacity      Type
        2                  8,500        Weiss W-45
        3                  8,500        Weiss W-45
        4                  8,500        Unit 15
        6*                12,500        National 75A
        7*                10,000        Unit 15
       10(a)              12,500        National 75A
       12                 11,500        National 50A
       14                 12,500        BDW 650
       17                  9,500        Unit 15
       22*                13,500        Brewster  75
       23*                13,500        National 75A
       24*                13,500        Gardner Denver 700
       27*                13,500        Gardner Denver 700
       28*                16,000        Gardner Denver 800
       29*                16,000        Gardner Denver 800
       30*                16,000        Gardner Denver 800
       31*                16,000        BDW 800
       55                 30,000        Gardner Denver DW-2100
       56*                20,000        National 110-M
     ----------------
     *In active operation at June 7, 2002.

     (a)  On April 12, 2001, this rig was destroyed as a result of an
          explosion, fire and subsequent blow out.  This rig was insured in
          the amount of $750,000.

     Major overhauls, repairs and general maintenance for the drilling rigs
are primarily conducted at the Company's principal support and storage
facilities in Midland, Texas.  The Company emphasizes the maintenance and
periodic improvement of its drilling equipment and believes that its rigs are
generally in good condition.  See "Item 2. Properties".

Drilling Contracts

     The Company's drilling contracts are usually obtained through
competitive bidding or as a result of direct negotiations with customers.
Drilling contracts typically obligate the Company to pay all expenses
associated with drilling an oil or gas well, including wages of drilling
personnel, maintenance expenses and incidental purchases of rig supplies and
equipment.  The majority of the Company's contracts are "daywork" contracts
with the remainder being "footage" or "turnkey" contracts.  Under a footage
contract, the Company charges an agreed price per foot of hole drilled,
whereas a day-work contract permits the Company to charge a per diem fixed
rate for each day the rig is in operation.  A turnkey contract specifies a
total price for drilling a well plus providing other services, materials or
equipment which are typically the responsibility of the operator under


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<PAGE> 7
footage or daywork contracts.  Prices for all contracts vary depending on the
location, depth, duration, complexity of the well to be drilled, operating
conditions and other factors peculiar to each proposed well.  Under footage
and turnkey contracts, the Company manages the drilling operation and the
type of equipment to be used, subject to certain customer specifications.
The Company also bears the risk and expense of mechanical malfunctions,
equipment shortages, and other delays arising from problems caused in
drilling a well.  Daywork contracts permit the operator of the well to manage
drilling operations and to specify the type of equipment to be used.  Under
daywork contracts, the Company generally bears none of the risk due to time
delays caused by unforeseeable circumstances such as stuck or broken drill
pipe or blowouts.  Of the 11 rigs working at June 7, 2002, all were subject
to daywork contracts.

     The Company's operations are subject to many hazards, including well
blowouts and fires that could cause personal injury, suspension of drilling
operations, damage to or destruction of equipment and damage to producing
formations and surrounding areas.  The Company believes it is adequately
insured for public liability and damage to the property of others resulting
from its operations.

Rig Utilization

     The Company's contract drilling revenues depend upon the utilization of
its drilling rigs and the contract rates received for its drilling
operations.  These two factors are affected by a number of variables,
including competitive conditions in the drilling industry and the level of
exploration and development activity conducted by oil and gas producers at
any given time.  The level of domestic drilling activity has historically
fluctuated and cannot be accurately predicted because of numerous factors
affecting the petroleum industry, including oil and gas prices and the degree
of government regulation of the industry.  Contract drilling revenues and rig
utilization rates for the past five years are set forth below.

                      Contract Drilling
       Year Ended         Revenues          Number of      Percent of
        March 31,      (in thousands)       Rigs Owned     Utilization
          1998            $ 34,891              17(a)         78.2%
          1999              12,948              17            26.6%
          2000              15,394              18(b)         35.0%
          2001              36,023              19(c)         68.2%
          2002              46,712              18            66.8%
____________________

     (a)  Of the total number of rigs owned, one was owned only for a portion
          of the fiscal year ended March 31, 1998.
     (b)  Of the total number of rigs owned, one was owned only for a portion
          of the fiscal year ended March 31, 2000.
     (c)  Of the total number of rigs owned, one was owned only for a portion
          of the fiscal year ended March 31, 2001.  On April 12, 2001, this
          rig was destroyed as a result of an explosion, fire and subsequent
          blow out.

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<PAGE> 8
Customers

     During the fiscal year ended March 31, 2002, the Company drilled a total
of 112 wells for approximately 22 customers.  The following table sets forth
certain information with respect to customers for the Company's contract
drilling services that accounted for more than 10% of the Company's total
revenues during the last fiscal year.

                                           Percent of      Number of Wells
Name of Customer                         Total Revenues        Drilled
----------------                         --------------    ---------------
Pure Resources, L.P.                           38%                 40

     The loss of the above customer could have a material adverse effect on
the Company, depending upon the demand for the Company's drilling rigs at the
time of such loss and the Company's ability to attract new customers.

Competition

     The Company encounters substantial competition from other drilling
contractors in its contract drilling operations.  The Company's principal
market areas of west Texas and eastern New Mexico are highly fragmented and
competitive.  Companies compete primarily on the basis of contract rates,
suitability and availability of equipment and crews, experience of drilling
in certain areas, and reputation.  The Company believes it competes favorably
with respect to all of these factors.  Competition is primarily on a well-by-
well basis and may vary significantly at any particular time.  Drilling rigs
can be stacked or moved from one region to another in response to perceived
long-term changes in levels of activity.  In recent years, competition within
the industry has been intense due to the depressed demand resulting from
lower oil and gas prices and excess deliverability of natural gas.

Employees

     At June 7, 2002, the Company had 50 salaried employees and approximately
279 hourly paid employees.  Employees of the Company are not covered by any
collective bargaining agreements and the Company has never experienced a
strike or work stoppage.  The Company considers its employee relations to be
satisfactory.

REGULATION

Oil and Gas

     The Company's operations are regulated by certain federal and state
agencies.  In particular, oil and gas production and related operations are
or have been subject to price controls, taxes and other laws relating to the
oil and gas industry.  The Company cannot predict how existing laws and
regulations may be interpreted by enforcement agencies or court rulings,
whether additional laws and regulations will be adopted, or the effect such
changes may have on its business, financial condition or results of
operations.

     The Company's oil and gas exploration, production and related operations
are subject to extensive rules and regulations promulgated by federal, state


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<PAGE> 9
and local agencies.  Failure to comply with such rules and regulations can
result in substantial penalties.  The regulatory burden on the oil and gas
industry increases the Company's cost of doing business and affects its
profitability.  Because such rules and regulations are frequently amended or
reinterpreted, the Company is unable to predict the future cost or impact of
complying with such laws.

     The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of oil and gas.  Such
states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and gas
properties, the establishment of maximum rates of production from oil and gas
wells and the regulation of spacing, plugging and abandonment of such wells.

     Sales of gas by the Company are not regulated and are made at market
prices.  However, the Federal Energy Regulatory Commission ("FERC") regulates
interstate and certain intrastate gas transportation rates and service
conditions, which affect the marketing of gas produced by the Company, as
well as the revenues received by the Company for sales of such production.
Since the mid-1980s, FERC has issued a series of orders, culminating in Order
Nos. 636,636-A and 636-B ("Order 636"), that have significantly altered the
marketing and transportation of gas.  Order 636 mandates a fundamental
restructuring of interstate pipeline sales and transportation service,
including the unbundling by interstate pipelines of the sales,
transportation, storage and other components of the city-gate sales services
such pipelines previously performed.  One of FERC's purposes in issuing the
orders was to increase competition within all phases of the gas industry.
Order 636 and subsequent FERC orders issued in individual pipeline
restructuring proceedings have been the subject of appeals, the results of
which have generally been supportive of the FERC's open-access policy.  In
1996, the United States Court of Appeals for the District of Columbia Circuit
largely upheld Order No. 636, et seq.  Because further review of certain of
these orders is still possible, and other appeals remain pending, it is
difficult to predict the ultimate impact of the orders on the Company and its
gas marketing efforts.  Generally, Order 636 has eliminated or substantially
reduced the interstate pipelines' traditional role as wholesalers of gas, and
has substantially increased competition and volatility in gas markets.  While
significant regulatory uncertainty remains, Order 636 may ultimately enhance
the Company's ability to market and transport its gas, although it may also
subject the Company to greater competition.

     The sale of oil by the Company is not regulated and is made at market
prices.  The price the Company receives from the sale of oil is affected by
the cost of transporting the product to market.  Effective as of January 1,
1995, FERC implemented regulations establishing an indexing system for
transportation rates for interstate common carrier oil pipelines, which,
generally, would index such rates to inflation, subject to certain conditions
and limitations.  These regulations could increase the cost of transporting
oil by interstate pipelines, although the most recent adjustment generally



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<PAGE> 10
decreased rates.  These regulations have generally been approved on judicial
review.  The Company is not able to predict with certainty what effect, if
any, these regulations will have on it, but, other factors being equal, the
regulations may, over time, tend to increase transportation costs or reduce
wellhead prices for oil.

     The Company is required to comply with various federal and state
regulations regarding plugging and abandonment of oil and gas wells.

Environmental

     Various federal, state and local laws and regulations governing the
discharge of materials into the environment, or otherwise relating to the
protection of the environment, health and safety, affect the Company's
operations and costs.  These laws and regulations sometimes require
governmental authorization before certain activities, limit or prohibit other
activities because of protected areas or species, impose substantial
liabilities for pollution related to Company operations or properties, and
provide penalties for noncompliance.  In particular, the Company's
exploration and production operations, its activities in connection with
storage and transportation of oil and other liquid hydrocarbons, and its use
of facilities for treating, processing or otherwise handling hydrocarbons and
related exploration and production wastes are subject to stringent
environmental regulation.  As with the industry generally, compliance with
existing and anticipated regulations increases the Company's overall cost of
business.  While these regulations affect the Company's capital expenditures
and earnings, the Company believes that such regulations do not affect its
competitive position in the industry because its competitors are similarly
affected by environmental regulatory programs.  Environmental regulations
have historically been subject to frequent change and, therefore, the Company
is unable to predict the future costs or other future impacts of
environmental regulations on its future operations.  A discharge of
hydrocarbons or hazardous substances into the environment could subject the
Company to substantial expense, including the cost to comply with applicable
regulations that require a response to the discharge, such as containment or
cleanup, claims by neighboring landowners or other third parties for personal
injury, property damage or their response costs and penalties assessed, or
other claims sought by regulatory agencies for response cost or for natural
resource damages.

     The following are examples of some environmental laws that potentially
impact the Company and its operations.

     Water.  The Oil Pollution Act ("OPA") was enacted in 1990 and amends
provisions of the Federal Water Pollution Control Act of 1972 ("FWPCA") and
other statutes as they pertain to prevention of and response to major oil
spills.  The OPA subjects owners of facilities to strict, joint and
potentially unlimited liability for removal costs and certain other
consequences of an oil spill, where such spill is into navigable waters, or
along shorelines.  In the event of an oil spill into such waters, substantial



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<PAGE> 11
liabilities could be imposed upon the Company.  States in which the Company
operates have also enacted similar laws.  Regulations are currently being
developed under the OPA and similar state laws that may also impose
additional regulatory burdens on the Company.

     The FWPCA imposes restrictions and strict controls regarding the
discharge of produced waters, other oil and gas wastes, any form of
pollutant, and, in some instances, storm water runoff, into waters of the
United States.  The FWPCA provides for civil, criminal and administrative
penalties for any unauthorized discharges and, along with the OPA, imposes
substantial potential liability for the costs of the removal, remediation or
damages resulting from an unauthorized discharge.  State laws for the control
of water pollution also provide for civil, criminal and administrative
penalties and liabilities in the case of an unauthorized discharge into state
waters.  The cost of compliance with the OPA and the FWPCA have not
historically been material to the Company's operations, but there can be no
assurance that changes in federal, state or local water pollution control
programs will not materially adversely effect the Company in the future.
Although no assurances can be given, the Company believes that compliance
with existing permits and compliance with foreseeable new permit requirements
will not have a material adverse effect on the Company's financial condition
or results of operations.

     Air Emissions.  Amendments to the Federal Clean Air Act enacted in late
1990 (the "1990 CAA Amendments") require or will require most industrial
operations in the United States to incur capital expenditures in order to
meet air emissions control standards developed by the Environmental
Protection Agency ("EPA") and state environmental agencies.  Although no
assurances can be given, the Company believes implementation of the 1990 CAA
Amendments will not have a material adverse effect on the Company's financial
condition or results of operations.

     Solid Waste.  The Company generates non-hazardous solid wastes that are
subject to the requirements of the Federal Resource Conservation and Recovery
Act ("RCRA") and comparable state statutes.  The EPA and the states in which
the Company operates are considering the adoption of stricter disposal
standards for the type of non-hazardous wastes generated by the Company.
RCRA also governs the generation, management, and disposal of hazardous
wastes.  At present, the Company is not required to comply with a substantial
portion of the RCRA requirements because the Company's operations generate
minimal quantities of hazardous wastes.  However, it is anticipated that
additional wastes, which could include wastes currently generated during
operations, could in the future be designated as "hazardous wastes".
Hazardous wastes are subject to more rigorous and costly disposal and
management requirements than are non-hazardous wastes.  Such changes in the
regulations may result in additional capital expenditures or operating
expenses by the Company.

     Superfund.  The Comprehensive Environmental Response, Compensation, and
Liability Act ("CERCLA"), also known as "Superfund", imposes liability,



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<PAGE> 12
without regard to fault or the legality of the original act, on certain
classes of persons in connection with the release of a "hazardous substance"
into the environment.  These persons include the current owner or operator of
any site where a release historically occurred and companies that disposed or
arranged for the disposal of the hazardous substances at the site.  CERCLA
also authorizes the EPA and, in some instances, third parties to act in
response to threats to the public health or the environment and to seek to
recover from the responsible classes of persons the costs they incur.  In the
course of its ordinary operations, the Company may have managed substances
that may fall within CERCLA's definition of a "hazardous substance".  The
Company may be jointly and severally liable under CERCLA for all or part of
the costs required to clean up sites where the Company disposed of or
arranged for the disposal of these substances.  This potential liability
extends to properties that the Company owned or operated, as well as to
properties owned and operated by others at which disposal of the Company's
hazardous substances occurred.

     The Company may also fall into the category of a "current owner or
operator".  The Company currently owns or leases numerous properties that for
many years have been used for the exploration and production of oil and gas.
Although the Company believes it has utilized operating and disposal
practices that were standard in the industry at the time, hydrocarbons or
other wastes may have been disposed of or released by the Company on or under
the properties owned or leased by the Company.  In addition, many of these
properties have been previously owned or operated by third parties who may
have disposed of or released hydrocarbons or other wastes at these
properties.  Under CERCLA, and analogous state laws, the Company could be
subject to certain liabilities and obligations, such as being required to
remove or remediate previously disposed wastes (including wastes disposed of
or released by prior owners or operators), to clean up contaminated property
(including contaminated groundwater) or to perform remedial plugging
operations to prevent future contamination.


OIL AND GAS OPERATIONS

     The Company's oil and gas operations involve the acquisition,
exploration for, development and production of oil and natural gas.  During
the fiscal year ended March 31, 2002, the Company's exploration efforts were
conducted in west Texas and eastern New Mexico.

     The Company is actively investing in oil and gas properties for the
purpose of exploration, development and production of oil and gas.  The
Company acquires or participates in these arrangements as a working interest
owner and usually provides the contract drilling services for such ventures.

     Exploration for oil and natural gas requires substantial expenditures,
especially for exploration in more remote areas.  As is customary in the oil
and gas industry, the drilling of oil and gas wells is usually accomplished
through participation with other third parties.  One of the parties



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<PAGE> 13
experienced with operations in the area is usually designated as the operator
of the property and is responsible for the direct supervision, administration
and accounting for wells drilled and completed pursuant to an operating
agreement between the parties.  The Company typically serves as operator of
oil and gas prospects assembled by the Company and participates as a non-
operating working interest owner in prospects assembled and generated by
third parties.  As operator, the Company supervises the drilling and
completion of wells and production therefrom and the further development of
surrounding properties.  The operator of a well has significant control over
its location and the timing of its drilling.  In addition, the operator of a
well receives fees from other working interest owners as reimbursement for
the general and administrative expenses attendant to the operation of the
wells.  The operator will normally receive revenues and pay expenses equal to
more than its ownership interest in the wells, and then must remit or collect
all but its share to or from the other respective participants in the well.
At June 7, 2002 the Company was operator of 42 wells.

Oil and Gas Reserves

     Information concerning the Company's estimated proved oil and gas
reserves is included in Note (9) to the Company's financial statements.  See
"Item 8 - Financial Statements and Supplementary Data".

     The reserve information included in this report is only an estimate.
There are numerous uncertainties inherent in estimating oil and gas reserves
and their estimated values, including many factors beyond the control of the
Company.  Reserve engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured in
an exact manner, and the accuracy of any reserve estimate is a function of
the quality of available data and of engineering and geological
interpretation and judgment.  As a result, estimates of different engineers
often vary.  In addition, estimates of reserves are subject to revision due
to the results of drilling, testing and production subsequent to the date of
such estimates.  Accordingly, reserve estimates are often different from the
quantities of oil and gas that are ultimately recovered.  The accuracy of
such estimates is highly dependent upon the accuracy of the underlying
assumptions upon which they are based.

     In general, the volume of production from oil and gas properties
declines as reserves are depleted.  Except to the extent the Company acquires
properties containing proved reserves or conducts successful exploration and
development activities, or both, the proved reserves of, and volumes of
production by, the Company will decline as reserves are produced.  The
Company's future oil and gas production is therefore highly dependent upon
its level of success in acquiring or finding additional reserves.

     The Company has no reserves outside the United States.

     No major discovery or other favorable or adverse event has occurred
since March 31, 2002 which is believed to have caused a significant change in



                                      -13-





<PAGE> 14
the estimated proved oil and gas reserves of the Company.

     The Company's oil and gas reserves and production are not subject to any
long-term supply or similar agreements with foreign governments or
authorities.

     The Company's estimate of reserves has not been filed with or included
in reports to any federal agency other than the Securities and Exchange
Commission.

Productive Wells and Acreage

     The following tables set forth the gross and net productive oil and gas
wells and developed and undeveloped acreage in which the Company owned a
working interest as of March 31, 2002.  Excluded from the table is acreage in
which the Company's interest is limited to royalty or similar interests.


                                                 Productive Wells
                                        -----------------------------------
                                           Gross                  Net
                                        -----------         ---------------
                                        Oil     Gas           Oil      Gas
                                        ---     ---         ------    -----
Texas................................... 75      13         11.423    2.571
New Mexico.............................. 26      10          9.259    2.923
Oklahoma...............................  --       3           --       .090
                                        ---     ---         ------    -----
          Total.........................101      26         20.682    5.584
                                        ===     ===         ======    =====



                                                   Acreage
                                   ---------------------------------------
                                      Developed             Undeveloped
                                   ---------------       -----------------
                                   Gross       Net       Gross         Net
                                   -----       ---       -----         ---
Texas............................ 15,240      2,763       15,660      4,046
New Mexico.......................  6,691      1,894        1,856        557
Oklahoma.........................  1,920         57           --        --
Kansas...........................     --         --        1,511        378
                                  ------      -----     ---------    ------
          Total.................. 23,851      4,714       19,027      4,981
                                  ======      =====     =========    ======

     Generally, the terms of developed oil and gas leaseholds are continuing
and such leases remain in force by virtue of, and so long as, production from
lands under lease is maintained.  Undeveloped oil and gas leaseholds are
generally for a primary term, such as five or ten years, subject to
maintenance with the payment of specified minimum delay rentals or extension
by production.

     On September 5, 1995, the Company entered into a 10 year License
Agreement with the Government of the Republic of Palau and the State of

                                      -14-

<PAGE> 15
Kayangel which will allow the Company to explore for oil and natural gas
offshore.  The license covers approximately 1.1 million acres within the
waters of Palau.  Pursuant to the amended license agreement, the Company was
required to drill two wells by March, 2002. During 2002, the Company decided
to abandon this project and accordingly impaired approximately $150,000 which
represented the Company's costs related to this leasehold.

Drilling Activity

     The following table sets forth certain information concerning the number
of gross and net exploratory and development wells drilled for the Company's
account during the periods indicated.


                                     Year Ended March 31,
                    -------------------------------------------------------
                          2002                2001                2000
                    ---------------     ---------------     ---------------
Type of Well        Gross      Net      Gross      Net      Gross      Net
------------        -----     -----     -----     -----     -----     -----
Exploratory (1)
     Oil              4        .895       3       1.162       6       1.680
     Gas              2        .528       4       1.262       4        .590
     Dry              2        .673       7       1.937       3        .500

Development (2)
     Oil              4       1.856       4       2.400       2        .160
     Gas              --        --        1        .050       --        --
     Dry              1        .050       2        .100       1        .100

--------------------------
(1)  An exploratory well is a well drilled to find and produce oil or gas in
     an unproved area, to find a new reservoir in a field previously found to
     be productive of oil or gas in another reservoir, or to extend a known
     reservoir.

(2)  A development well is a well drilled within the proved area of an oil or
     gas reservoir to the depth of a stratigraphic horizon known to be
     productive.

     At June 7, 2002, the Company was participating in the drilling of 1
gross  (.25 net) development well in Lea County, New Mexico.

     Substantially all of the equipment used in the Company's drilling
operations is owned by the Company; however, certain insignificant items of
drilling equipment are leased or rented as needed because such equipment
either cannot be purchased or is only necessary for the drilling of certain
types of wells located in certain areas.





                                      -15-





<PAGE> 16
     Production, Prices and Costs.  The following table sets forth certain
information regarding the volumes of the Company's net production of oil and
gas, the average sales prices received associated with its sales of oil and
gas, and the average production (lifting) cost per equivalent barrel of oil
("EBO").

                                            Year Ended March 31,
                                   ------------------------------------
                                    2002           2001           2000
                                   ------         ------         ------
Net Production
     Oil (Bbls)                    127,353       108,886         78,217
     Gas (Mcf)                     707,923       428,355        611,901
     EBO (1)                       245,340       180,279        180,201

Average Daily Production
     Oil (Bbls)                        349           298            214
     Gas (Mcf)                       1,940         1,174          1,676
     EBO                               672           494            494

Sales Prices
     Oil ($/Bbl)                    $23.19        $31.14         $21.12
     Gas ($/Mcf)                      3.61          4.82           2.48
     EBO                             22.45         30.25          17.58

Production (Lifting) Costs
     per EBO                          7.28          7.77           5.13

--------------------
     (1)  An EBO is one equivalent barrel of oil using the ratio of six Mcf
of gas to one barrel of oil.


Title to Properties

     As is customary in the oil and gas industry, a preliminary title
examination is conducted at the time oil or gas properties believed to be
suitable for drilling are acquired by the operator.  Prior to the
commencement of operations, curative work determined to be appropriate as a
result of a title search is performed with respect to significant defects
before the operator commences development.  Title examinations have been
performed with respect to substantially all of the Company's interests in its
producing properties.  The Company believes that title to its properties is
good and defensible in accordance with standards generally acceptable in the
oil and gas industry, subject to such exceptions which, in the Company's
opinion, are not so material as to detract substantially from the value of
such properties.  The Company's properties are subject to royalty, overriding
royalty, and other outstanding interests customary in the industry, and are
also subject to burdens such as liens incident to operating agreements,
current taxes not yet due, development obligations under oil and gas leases,
and other encumbrances, easements and restrictions.  The Company does not
believe that any of these burdens materially interferes with the use of its
properties in the operation of its business.




                                      -16-


<PAGE> 17

Markets and Customers

     The Company sells its oil and gas at the wellhead on an "as-produced"
basis and does not refine petroleum products.  Other than normal production
facilities, the Company does not own an interest in any bulk storage
facilities or pipelines.  As is customary in the industry, the Company sells
its production in any one area to relatively few purchasers, including
transmission companies that have pipelines near the Company's producing
wells.  Gas purchase contracts are generally on a short-term "spot market"
basis and usually contain provisions by which the prices and delivery
quantities for future deliveries will be determined.  During the year ended
March 31, 2002, Navajo Refining and Crude Marketing, Lantern Petroleum
Corporation and Pure Resources, L.P. accounted for approximately 24%, 17% and
15%, respectively, of the Company's oil and gas revenues for such period.
The loss of any of these purchasers could cease or delay the Company's
production and sale of its oil and gas reserves to the extent that
alternative purchasers having adequate gathering facilities are not found to
replace such purchaser's volume of oil or gas purchased.  However, in the
event of a loss of any purchaser, the Company believes that, under present
circumstances, it would be able to find other purchasers for its oil and gas
production.

Competition

     The Company encounters strong competition from major oil companies and
independent producers and operators in acquiring properties and leases for
exploration for oil and gas.  Competition is particularly intense with
respect to the acquisition of desirable undeveloped oil and gas leases.  The
principal competitive factors in the acquisition of undeveloped oil and gas
leases include qualified personnel and having access to the data necessary to
acquire and develop such leases, as well as the amount of consideration and
terms offered.  Many of the Company's competitors have financial resources,
staffs and facilities substantially greater than those of the Company.  In
addition, the producing and marketing of natural gas and oil is affected by
a number of factors which are beyond the control of the Company, the effect
of which cannot be accurately predicted.  Of significant importance recently
has been the domination and control of oil markets and prices by foreign
producers.

     The principal raw materials and resources necessary for the exploration
and development of oil and gas are leasehold prospects under which oil and
gas reserves may be discovered, drilling rigs and related equipment to
explore for such reserves and knowledgeable personnel to conduct all phases
of oil and gas operations.  The Company must compete for such raw materials
and resources with both major oil companies and independent operators, and
the continued availability, without periodic interruption, of such materials
and resources to the Company cannot be assured.





                                      -17-





<PAGE> 18

Risk Factors

Declining oil and gas prices may cause the Company to record write-downs in
the carrying value of its oil and gas properties.

     The Company's oil and gas producing activities are accounted for using
the successful efforts method of accounting.  The costs incurred to acquire
oil and gas properties (proved and unproved), all development costs and
successful exploratory costs are capitalized, whereas the costs of
unsuccessful exploratory wells are expensed.  Geological and geophysical
costs, including seismic costs, are charged to expense when incurred.  In
cases where the Company provides contract drilling services related to oil
and gas properties in which it has an ownership interest, the Company's
proportionate share of costs related to oil and gas properties is capitalized
as stated above, net of its working interest share of profits from the
related drilling contracts.  Capitalized costs of undeveloped properties,
which are not depleted until proved reserves can be associated with the
properties, are periodically reviewed for possible impairment.  This non-cash
impairment charge does not affect cash flow from operating activities, but it
does reduce earnings.  Impairment charges cannot be restored by subsequent
increases in the prices of oil and gas.

     The risk that the Company will be required to write down the carrying
value of its oil and gas properties increases when oil and gas prices
decline.  In addition, write-downs may occur if the Company experiences
substantial downward adjustments to its estimated proved reserves.

     For the year ended March 31, 2002, the Company recognized a non-cash
impairment charge of $3,953,421 related to its oil and gas reserves and
unproved properties.  This impairment of oil and gas assets was primarily the
result of the effect of significantly lower oil and gas prices on both proved
and unproved oil and gas properties and unsuccessful exploitation efforts to
increase production.  No assurance can be given that the Company will not
experience write-downs in the future.

The Company is subject to many restrictions under its loan agreement.

     As required by the Company's loan agreement with its bank lender,
substantially all of the Company's drilling rigs and related equipment,
accounts receivable and inventory have been pledged as collateral to secure
the payment of its loans.  The loan agreement restricts the Company's ability
to obtain additional financing, make investments, lease equipment, sell
assets and engage in business combinations.  The Company is also required to
comply with certain financial covenants and maintain certain financial
ratios.  The loan agreement prohibits the Company from declaring or paying
dividends on its common stock.  Although the Company is currently in
compliance with the loan covenants, its ability to comply in the future with
these restrictions and covenants is uncertain and will be affected by the
levels of cash flow from operations and events or circumstances beyond its
control.  The Company's failure to comply with any of the restrictions and


                                      -18-





<PAGE> 19
covenants under the loan agreement could result in a default under the loan
agreement.

     The loan agreement limits the amounts the Company can borrow to a
borrowing base amount, based upon the value of the drilling rigs and
equipment, accounts receivable and inventory securing repayment of loans made
to the Company.  The bank can unilaterally adjust the borrowing base and the
borrowings permitted to be outstanding under the loan agreement.  Outstanding
borrowings in excess of the borrowing base must be repaid immediately, or the
Company must pledge other assets as additional collateral.  No assurance can
be given that the Company would be able to make any mandatory principal
prepayments required under the loan agreement.

Part of the Company's business is seasonal in nature.

     Weather conditions affect the demand for and prices of natural gas and
can also delay drilling activities, disrupting the Company's overall business
plans.  Demand for natural gas is typically higher during winter months.

The Company's contract drilling and oil and gas operations are subject to
many inherent risks.

     Contract drilling and oil and gas exploration and production activities
are subject to many risks and hazards.

     The Company's oil and gas operations are marked by unprofitable efforts
because of dry holes and wells that do not produce oil or gas in sufficient
quantities to return a profit.  The success of the Company's operations
depends, in part, upon the ability of management and technical personnel.
The cost of drilling, completing and operating wells is often uncertain.
There is no assurance that the Company's oil and gas drilling or acquisition
activities will be successful, that any production will be obtained, or that
any such production, if obtained, will be profitable.

     The Company's drilling operations and fleet are subject to many hazards
inherent in the onshore drilling industry, such as encountering unusual or
unexpected formations and pressures, blowouts, explosions, cratering, well
fires and spills.  These hazards can result in personal injury and loss of
life, severe damage to or destruction of property and equipment, pollution or
environmental damage and suspension of operations.  Any one of these
potential hazards could result in accidents, environmental damage, personal
injury, property damage and other harm that could result in substantial
liabilities to the Company.  The Company generally seeks to obtain indemnity
agreements whenever possible from its customers requiring them to hold the
Company harmless if loss of production or reservoir damage occurs.  Even when
the Company obtains contractual indemnification, however, the customer may
not maintain adequate insurance to support such indemnification.

     As is customary in the industry, the Company maintains insurance against
some, but not all, of the hazards and risks it encounters.  The Company



                                      -19-





<PAGE> 20
maintains general liability insurance and obtains insurance against blowouts
and pollution risks on a well-by-well basis, but does not carry insurance
against all operating hazards.  No assurance can be given that the Company's
insurance or contractual indemnity protection will be sufficient or effective
under all circumstances or against all hazards to which it may be subject,
and its insurance claims will be subject to retentions and deductibles.  The
occurrence of a significant event for which the Company is not fully insured
or indemnified or the failure of a customer to meet its indemnification
obligations could have a material adverse effect on the Company's results of
operations and financial condition.  No assurance and be given that the
Company will be able to maintain insurance in the future at rates that it
considers reasonable.

Ability to Replace Reserves.

     The Company's future performance depends in part upon its ability to
find, develop and acquire additional oil and gas reserves that are
economically recoverable.  The Company's proved reserves decline as those
reserves are depleted and it must locate and develop or acquire new oil and
gas reserves to replace reserves being depleted by production.  No assurance
can be given that the Company will be able to find and develop or acquire
additional reserves on an economical basis.

The volatility of the oil and gas industry may have an adverse impact on the
Company's operations.

     The Company's revenues, cash flows and profitability are substantially
dependent upon prevailing prices for oil and gas, both with respect to its
contract drilling operations and its oil and gas operations.  In recent
years, oil and gas prices and, therefore, the level of drilling, exploration,
development and production, have been extremely volatile.  Any significant or
extended decline in oil and/or gas prices or land drilling activity in the
United States will have a material adverse effect on the Company's financial
condition and results of operations and could impair access to future sources
of capital.  Demand and prices for the Company's contract drilling services
depend upon numerous factors over which it has no control, including:

          the level of oil and natural gas prices, expectations about future
          oil and natural gas prices and the ability of international cartels
          to set and maintain production levels and prices,

          the cost of exploring for, producing and delivering oil and natural
          gas

          the level and price of foreign oil and natural gas imports,

          the discovery rate of new oil and natural gas reserves,

          available pipeline and other oil and natural gas transportation
          capacity,



                                      -20-





<PAGE> 21
          weather conditions,

          international political, military, regulatory and economic
          conditions and the ability of oil and natural gas companies to
          raise capital.

     No assurance can be given that current levels of oil and natural gas
exploration activities in the Company's markets will continue or that demand
for its contract drilling services will correspond to the level of activity
in the industry generally.  The Company's expects oil and natural gas prices
to continue to be volatile and to affect the demand for and pricing of its
contract drilling services.

Decreased demand or reduced prices the Company receives for its land contract
drilling services could materially adversely affect its financial condition.

     Any significant decrease in demand for, or the prices received for, the
Company's contract drilling services could have a material adverse affect on
its results of operations and financial condition.  An oversupply of drilling
rigs and a large number of drilling contractors have affected adversely the
United States land drilling industry for many years.  These conditions have
resulted in depressed day rates and substantial competition for available
contracts.  The Company cannot accurately predict either the future level of
demand for its contract drilling services or future conditions in the land
contract drilling services industry.

The Company operates in a highly competitive industry, which includes
competitors with greater financial resources.

     Some of the Company's competitors have significantly greater financial
resources than it has, which may enable them to better withstand industry
downturns, to compete more effectively on the basis of price, to acquire
existing rigs or to build new rigs.  The contract drilling industry in which
the Company operates is a highly-fragmented, intensely competitive and
cyclical business.  Competition for services in a particular market is based
on price, location, type and condition of available equipment and quality of
service.  A number of large and small contractors provide competition for
drilling contracts in all areas of the Company's business.  In addition,
certain competitors are present in more than one of those areas and drilling
rigs are mobile and can be moved from one region to another in response to
market conditions.

The Company may incur losses in connection with its footage and turnkey
contracts.

     The Company cannot provide assurance that it will not incur losses on
turnkey and footage contracts in the future.  The Company performs drilling
services pursuant to footage and turnkey drilling contracts under which it
agrees to drill a well to a specified depth for a fixed price.  The risks




                                      -21-





<PAGE> 22
associated with a turnkey or footage contract are greater than for wells
drilled on a daywork basis because in a turnkey or footage contract the
Company, as the contractor, assumes most of the risks associated with
drilling operations generally assumed by the operator under a daywork
contract, including the risk of blowout, loss of hole, stuck drill string,
machinery breakdowns, abnormal drilling conditions and risks associated with
subcontractors, services, supplies and personnel.

     As of March 31, 2002, none of the Company's rigs were operating under
footage or turnkey contracts.  Under such contracts, the Company does not
receive payment unless the well is drilled to the specified depth, and it
must bear the costs of performing drilling services until the well has been
drilled.  In addition, profitability of the contract is dependent upon
keeping expenses within the estimates the Company uses in determining the
contract price and completing the contracts on schedule.

September 11 events may adversely affect the Company's business.

     The full repercussions of the events of September 11 are not known.
However, it is not unreasonable to believe, as the Company does, that its
business activities and financial condition could be adversely impacted.  For
instance, the premiums the Company pays for its business insurance coverage
could rise significantly, or coverage provided by its insurance carriers
could be substantially reduced, forcing the Company to operate without
adequate coverage in an industry characterized by high risk to persons and
property.  In addition, the disruption of the financial markets and the
negative impact on the U. S. economy caused by September 11 may undermine the
Company's efforts and any success it might have in its contract drilling and
exploration and production activities.  Although September 11 was not a
direct attack on the domestic oil and gas industry, any future similar
events, particularly directed at the oil and gas industry, could materially
and adversely affect the Company's business, results of operations and
financial condition.

The oil and gas industry is capital intensive.

     The oil and gas industry is capital intensive.  The company's cash flow
from operations and the continued availability of credit are subject to a
number of variables, including the number and type of drilling contracts it
is able to obtain, the level of oil and gas it is able to produce from
existing wells, the prices at which oil and gas are sold and its ability to
locate and produce new reserves. The Company cannot provide any assurance
that its cash flow from operations and present borrowing capacity will be
sufficient to fund its anticipated capital expenditures and working capital
requirements.  The Company may from time to time seek additional financing,
either in the form of bank borrowings, sales of securities or other forms of
financing.  Except for the Company's loan agreement with its bank lender, it
has no agreements for any such financing and there can be no assurance as to
the availability of terms of any such financing.  To the extent the Company's
capital resources and earnings are at any time insufficient to fund its



                                      -22-





<PAGE> 23
activities or repay any indebtedness as due, it will need to raise additional
funds through public or private financings or additional borrowings.  No
assurance can be given as to the Company's ability to obtain any such capital
resources.  If the Company is not at any time able to obtain then necessary
capital resources, its financial condition and results of operations could be
materially adversely affected.  If, however, additional funds are raised
through the issuance of equity securities, the percentage ownership of the
Company's stockholders at that time could be diluted and, in addition, such
equity securities may have rights, preferences or privileges senior to those
of the common stock.

The Company does not pay dividends on its common stock.

     The Company has never paid dividends on its common stock, and does not
intend to pay cash dividends on the common stock in the foreseeable future.
Net income from the Company's operations, if any, will be used for the
development of its business.  Any decision to pay dividends on the common
stock in the future will depend upon the Company's profitability at that
time.

There is a shortage of qualified and experienced labor.

     The volatility of conditions in the oil and gas industry sometimes
results in a shortage of qualified drilling rig personnel in the industry.
As a result,  and rather than hiring unqualified or inexperienced crews, from
time to time the Company may intentionally restrict the number of drilling
rigs it has in active operation at any one time.  If the Company is unable to
attract and retain qualified  personnel, its ability to market and operate
its drilling rigs will be restricted.  In addition, labor shortages could
result in wage increases, which could reduce the Company's operating margins
and have a material adverse effect on its financial condition and results of
operations.

The reserve data in this report represent estimates only.

     Information relating to the Company's proved oil and gas reserves is
based upon engineering estimates.  Reserve engineering is a subjective
process of estimating the recovery from underground accumulations of oil and
gas that cannot be measured in an exact manner, and the accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment.  Estimates of
economically recoverable oil and gas reserves and of future net cash flows
necessarily depend upon a number of variable factors and assumptions, such as
historical production from the area compared with production from other
producing areas, the assumed effects of regulations by governmental agencies
and assumptions concerning future oil and gas prices, future operating costs,
severance and excise taxes, development costs and workover and remedial
costs, all of which  may in fact vary considerably from actual results.
Because all reserve estimates are to some degree speculative, the actual
quantities of oil and gas that are ultimately recovered, production and



                                      -23-





<PAGE> 24
operation costs, the amount and timing of future development expenditures and
future oil and gas sales prices may all vary from those assumed in these
estimates and such variances may be material.  In addition, different reserve
engineers may make different estimates of reserve quantities and cash flows
based upon the same available data.

     The present value of proved reserves referred to in this report should
not be construed as the current market value of the estimated proved reserves
of oil and gas attributable to the Company's properties.  In accordance with
SEC requirements, the Company has based the estimated discounted future net
cash flows from proved reserves on prices and costs as of the date of the
estimate, whereas actual future prices and costs may vary significantly.  The
following factors may also affect actual future net cash flow:

        the timing of production and related expenses

        changes in consumption levels; and

        governmental regulations or taxation.

     In addition, the calculation of the present value of the future net cash
flows using a 10% discount as required by the SEC is not necessarily the most
appropriate discount rate based on interest rates in effect from time to time
and risks associated with the Company's reserves or the oil and gas industry
in general.  In addition, the Company may need to revise its reserves
downward or upward based upon actual production, results of future
development, supply and demand for oil and gas, prevailing oil and gas prices
and other factors.

Reliance upon financial statements audited by Arthur Andersen LLP.

     Arthur Andersen LLP was previously the independent accountant for the
Company.  Representatives for Arthur Andersen LLP are not available to
reissue their report on the March 31, 2000 and 2001 financial statements or
provide the consent required for the incorporation by reference of their
reports on the financial statements and we have dispensed with the
requirement to file their consent in reliance upon Rule 437a of the
Securities Act of 1933.  Because Arthur Andersen LLP has not consented to the
inclusion of their report, you will not be able to recover against Arthur
Andersen LLP under Section 11 of the Securities Act of 1933 for any untrue
statements of a material fact contained in the financial statements audited
by Arthur Andersen LLP that are incorporated by reference or any omissions to
state a material fact required to be stated therein.










                                      -24-





<PAGE> 25
Executive Officers

     Thomas C. Brown, age 75, has served as a Director of the Company since
1982.  He is presently Chairman of the Board of Directors and Chief Executive
Officer of the Company and has served in such capacities since 1990.

     Jeffrey D. Phillips, age 41, has been employed by the Company since
1995.  He has been President since April 1, 2001.  He was Vice President -
Production of the Company from 1997 to 2001.

     Don H. Lawson, age 63, has been employed by the Company since 1967.  He
has been the Vice President - Operations of the Company since 1992.

     Patricia R. Elledge, age 44, was employed by the Company from September,
1989 to December, 1993 when she resigned to relocate.  Ms. Elledge returned
to the Company in September, 1994 in her current capacity as Controller -
Treasurer.

     James M. Alsup, age 65, has been the Secretary of the Company since
1982.  He has been a partner in the law firm of Lynch, Chappell & Alsup since
1970.


Item 2.  PROPERTIES

     In addition to its drilling rigs and related equipment and its oil and
gas properties, the Company owns a 31 acre tract of land in Midland, Texas on
which the Company's executive offices are located and on which the principal
support and storage facilities for its contract drilling operations are
located.  These facilities include an office building and fabrication and
maintenance shop.  The facility allows for open storage of drilling equipment
and drill pipe.

     The Company also owns a 78 acre tract of land in Odessa, Texas, which is
presently being utilized as a secondary storage location.  From time to time,
the Company's rigs are also stored and stacked in the field at the rig's last
location site.

     The Company owns a warehouse and yard facility situated on approximately
4 acres in Midland, Texas.  This additional storage is used to complement the
existing Midland yard facility.  The Company believes that the support and
storage facilities for its drilling rigs and related equipment are more than
adequate.










                                      -25-





<PAGE> 26
Item 3.  LEGAL PROCEEDINGS

     The Company is a defendant in various lawsuits generally incidental to
its business.  The Company does not believe that the ultimate resolution of
such litigation will have a significant effect on the Company's financial
position or results of operations.

Item 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     There was no meeting of security holders of the Company during the
fourth quarter of the fiscal year ended March 31, 2002, and no matters were
submitted to a vote of security holders during such period.




                                  PART II



Item 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
         STOCKHOLDER MATTERS

     The Company's Common Stock is traded on the NASDAQ National Market
System under the symbol "TBDI".  The following table sets forth, on a per
share basis for the periods indicated, the range of high and low last
reported sales prices as reported by NASDAQ.  The quotations are inter-dealer
prices without retail mark-ups, mark-downs or commissions and may not
represent actual transactions.


                                                   Price
                                             -----------------
                                              High       Low
                                             ------     ------
           Fiscal 2001
                  First Quarter             $ 12.43    $  8.75
                  Second Quarter              15.75      10.50
                  Third Quarter               14.68      10.00
                  Fourth Quarter              18.37      13.00

           Fiscal 2002
                  First Quarter               19.05      14.62
                  Second Quarter              16.95      12.10
                  Third Quarter               13.61      11.45
                  Fourth Quarter              15.25      10.40







                                      -26-





<PAGE> 27

     On June 7, 2002, the last reported sale price of the Company's Common
Stock as reported by NASDAQ was $13.88.

     The transfer agent for the Company's Common Stock is American Stock
Transfer & Trust Company, New York, New York.

     On June 7, 2002, the outstanding shares of the Company's Common Stock
were held of record by approximately 1,955 stockholders.

     The Company has never declared or paid any cash dividends on its Common
Stock and has no present intention to pay cash dividends in the future.  The
Company presently intends to retain all earnings to fund its operations and
future growth.  Under the terms of the Company's credit facility with its
bank lender, the Company is prohibited from paying cash dividends to the
holders of Common Stock.  See Item 7, "Management's Discussion and Analysis
of Financial Condition and Results of Operations - Liquidity and Capital
Resources".



































                                      -27-





<PAGE> 28
Item 6.  SELECTED FINANCIAL DATA

     The following table sets forth certain selected financial data for the
Company's operations for each of the five years ended March 31, 2002.  The data
set forth in this table should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations", and
the Company's Financial Statements and related notes included elsewhere herein.

<TABLE>
<CAPTION>
                                                Years ended March 31,
                                     --------------------------------------------
                                     2002      2001      2000      1999      1998
                                     ----      ----      ----      ----      ----
                                       (In thousands, except per share amounts)

<S>                               <C>       <C>       <C>       <C>       <C>
INCOME STATEMENT DATA
Operating revenues:
  Contract drilling               $ 46,712  $ 36,023  $ 15,394  $ 12,948  $ 34,891
  Oil and gas                        5,508     5,454     3,169     1,476     2,126
                                    ------    ------    ------    ------    ------

     Total operating revenues       52,220    41,477    18,563    14,424    37,017

Operating costs and expenses:
  Contract drilling                 26,761    22,767    12,486    10,027    23,163
  Oil and gas production             1,721     1,363       926       803       944
  Dry holes and abandonments         1,657       811       490       840       440
  Exploration                           60       174        19       106        36
  Depreciation, depletion
    and amortization                 6,746     5,137     3,282     2,699     4,080
  General and administrative         2,552     1,918     1,854     1,911     1,863
  Writedown of oil and
    gas properties (a)               3,953     1,171       739     1,304     3,120
                                    ------    ------    ------    ------    ------
     Total operating costs
       and expenses                 43,450    33,341    19,796    17,690    33,646
                                    ------    ------    ------    ------    ------
     Operating income (loss)         8,770     8,136    (1,233)   (3,266)    3,371

Other income (expenses):
  Interest                              11      (216)       17       151       133
  Other                              1,035       558         9       (72)    1,180
                                    ------    ------    ------    ------    ------
     Total other income (expense)    1,046       342        26        79     1,313
                                    ------    ------    ------    ------    ------

Net income(loss) before income
  tax provision                      9,816     8,478    (1,207)   (3,187)    4,684
Provision for income taxes             --       (170)      --        --       (140)
                                    ------    ------    ------    ------    ------
Net income (loss) before
  extraordinary items              $ 9,816   $ 8,308  $ (1,207) $ (3,187) $  4,544
                                    ======    ======    ======    ======    ======




<PAGE> 29
Net income (loss)
  before extraordinary
  items per share:
        Basic                       $ 1.88    $ 1.67    $(0.25)   $(0.68)   $ 0.98
        Diluted                     $ 1.79    $ 1.54    $(0.25)   $(0.68)   $ 0.91
                                    ======    ======    ======    ======    ======

Weighted average number of
  common shares outstanding:
       Basic                         5,220     4,979     4,761     4,711     4,615
       Diluted                       5,474     5,392     4,761     4,711     5,014
                                     =====     =====     =====     =====     =====

BALANCE SHEET DATA
  Cash and cash equivalents       $  3,258  $    301  $    980  $  1,195  $  1,623
  Total assets                      42,635    35,401    23,625    18,923    24,648
  Total debt                            --     1,080     2,250        --        --
  Stockholders' equity              35,832    24,606    15,796    16,735    19,960
</TABLE>
____________________

   (a)   During fiscal years ended March 31, 2002, 2001 and 2000, the Company
         recognized  non-cash charges of approximately $3,953,000, $1,171,000
         and $739,000, respectively, due to a writedown of the carrying value
         of its oil and gas properties.  This charge is a result of the adoption
         of Statement of Financial Accounting Standards No. 121 ("SFAS 121")
         "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
         Assets to Be Disposed Of".  SFAS 121 requires the Company to assess the
         need for an impairment of capitalized costs of oil and gas properties
         on a property-by-property basis in contrast to the Company's prior
         policy of evaluating the undiscounted future net revenues of its oil
         and gas properties in total.  According to SFAS 121, if an impairment
         is indicated based on undiscounted future cash flows, then it is
         recognized to the extent that net capitalized costs exceed discounted
         future cash flows.


















                                      -28-





<PAGE> 30

Item 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
         RESULTS OF OPERATIONS

Overview and Critical Accounting Policies

   Since 1982, the principal business of the Company has been the contract
drilling of domestic onshore oil and gas wells.  In 1987, the Company began
acquiring oil and gas properties and participating in the exploration for and
development of oil and gas reserves.

   Contract Drilling Operations

   Drilling revenues from footage and daywork contracts are recognized as
work is performed utilizing the percentage-of-completion method.  Costs under
footage and daywork contracts are recognized in the period they are incurred.
The Company utilizes the completed contract method to recognize drilling
revenues and expenses relating to turnkey contracts.  Expected losses on all
in-process contracts are recognized in the period the loss can reasonably be
determined.

   Drilling equipment is depreciated on a units-of-production method based
on the monthly utilization of the equipment.  Drilling equipment which is not
utilized during a month is depreciated using a minimum utilization rate of
approximately 25%.  Estimated useful lives range from four to eight years.
Other property and equipment is depreciated using the straight-line method of
depreciation with estimated useful lives of three to seven years.
   The contract drilling industry is currently experiencing a decrease in
demand and downward pressure on prices for contract drilling services due to
the uncertainty surrounding oil and gas prices. The Company has been and will
continue to be affected by oil and gas industry conditions but cannot predict
either the future level of demand for its contract drilling services or
future conditions in the contract drilling industry. The contract drilling
industry remains highly competitive.  The Company believes it owns a
sufficient number of drilling rigs to remain competitive within its areas of
operation.  In addition, the Company believes it competes favorably with
respect to the depth capabilities of its rigs, the experience level of its
personnel, its reputation and its relationship with existing customers.
However, the Company's operating results will continue to be directly
affected by the level of drilling activity in the Company's service areas.













                                      -29-





<PAGE> 31
   The following table sets forth certain information relating to the
Company's contract drilling operations for the periods indicated:

                                              Year Ended March 31,
                                            -------------------------
                                            2002       2001      2000
                                            ----       ----      ----
                                            (In thousands, except %s)

     Contract drilling revenues           $46,712    $36,023    $15,394
     Contract drilling expenses            26,761     22,767     12,486

     Contract drilling expenses as
       a percent of drilling revenues        57.3%      63.2%      81.1%

     Rig utilization                         66.8%      68.2%      35.0%


   Oil and Gas Operations

   The Company's oil and gas producing activities are accounted for using the
successful efforts method of accounting.  Accordingly, the Company
capitalizes all costs incurred to acquire oil and gas properties (proved and
unproved), all development costs, and the costs of successful exploratory
wells.  The costs of unsuccessful exploratory wells are expensed.  Geological
and geophysical costs, including seismic costs, are charged to expense when
incurred.  In cases where the Company provides contract drilling for oil and
gas properties in which it has an ownership interest, the Company's
proportionate share of costs is capitalized as stated above, net of its
working-interest share of profits from the related drilling contracts.
Capitalized costs of undeveloped properties, which are not depleted until
proved reserves can be associated with the properties, are periodically
reviewed for possible impairment.  Such unevaluated costs totaled
approximately $1,967,000 and $845,000 as of March 31, 2002, and March 31,
2001, respectively.

   For properties with proved or proved developed oil and gas reserves,
depletion, depreciation and amortization of capitalized costs was calculated
for fiscal 2002, 2001 and 2000 by applying the units-of-production method to
the estimated amount of such reserves.

   In fiscal 2002, 2001 and 2000, the Company recognized non-cash charges of
approximately $4.0 million, $1.2 million and $.7 million, respectively, due
to  writedowns of the carrying value of its oil and gas properties.  The
writedowns are the result of the adoption in 1996 of Statement of Financial
Accounting Standards No. 121 ("SFAS 121") "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of".  SFAS 121
requires the Company to assess the need for an impairment of capitalized
costs of oil and gas properties on a property-by-property basis.  According
to SFAS 121, if an impairment is indicated based on undiscounted future cash
flows, then it is to be recognized to the extent that net capitalized costs
exceed discounted future cash flows. Many assumptions are required for the


                                      -30-




<PAGE> 32
Company's impairment assessment when impairment indicators are present,
including future prices and expenses, production volumes and drilling
results.  Changes in these assumptions could have a significant impact on
whether specific oil and gas properties fail the impairment test.  Prices
used for the impairment analysis at March 31, 2002 were $23.36 per Bbl and
$3.318 per Mcf.  Future impairment expense may be required on current
properties if the Company changes its pricing or cost assumptions in the
future or if estimated future recoverable reserves decline.

   The following table sets forth certain information relating to the
Company's oil and gas operations for the periods indicated:

                                            Year Ended March 31,
                                         --------------------------
                                         2002       2001       2000
                                         ----       ----       ----
                                               (In thousands)

     Oil and gas revenues               $5,508     $5,454     $3,169
     Production expenses                 1,721      1,363        926
     Dry holes and abandonments          1,657        811        490
     Exploration expenses                   60        174         19
     Depreciation, depletion and
       amortization                      2,430      1,739      1,552
     Writedown of properties             3,953      1,171        739


   The Company has not entered into hedging arrangements and does not have
any delivery commitments.  While hedging arrangements reduce exposure to
losses of resulting from unfavorable price changes, they also limit the
ability to benefit from favorable market price changes.

RESULTS OF OPERATIONS

Comparison of Year Ended March 31, 2002 to Year Ended March 31, 2001

   Contract drilling revenues for fiscal 2002 increased by 30% from fiscal
2001.  Rig utilization rates in fiscal 2002 and 2001 were 67% and 68%,
respectively.  The increase in contract drilling revenues was due to an
increase in the average prices received for contract drilling services.  Rig
utilization in the Company's operating market is difficult to project because
of wide fluctuations in drilling activity.  In addition, the number of rigs
industry wide that are actually available for work cannot be accurately
determined.

   Contract drilling expenses were 57% and 63% of contract drilling revenues
in fiscal 2002 and 2001, respectively.  The increase in contract drilling
expenses was primarily due to higher labor and trucking costs. However, costs
did not increase at the same rate as average rig rates.

   Oil and gas revenues remained relatively flat when comparing fiscal 2002
and 2001.  Although quantities produced of oil and gas (on an equivalent


                                      -31-




<PAGE> 33
barrel of oil basis) increased by approximately 36%, oil and gas revenues for
fiscal 2002 were negatively affected by a decrease in prices received for
crude oil and natural gas.  The following table sets forth certain
information relating to oil and gas revenues:

                                       Fiscal year ended
                                          March 31,
                                       -----------------
                                       2002         2001
                                       ----         ----
         Quantities
         ----------
         Oil (bbls)                  127,353      108,886
         Gas (mcf)                   707,923      428,355

         Average Price
         -------------
         Oil (bbls)                  $ 23.19      $ 31.14
         Gas (mcf)                   $  3.61      $  4.82


   Oil and gas production expenses increased by 26% and is a result of start
up expenses for new wells coming on line coupled with an increase in the
number of producing properties.  In addition, the Company has experienced a
general rise in the cost of services and supplies which are included in
production expenses.

   The Company participated as a working-interest owner in the drilling of
13 wells during fiscal 2002, of which three were dry holes.  In fiscal 2001,
the Company participated as a working-interest owner in the drilling of 21
wells, of which nine were dry holes.

   Depreciation, depletion and amortization expense increased 31% due to
several factors.  The Company has been purchasing drill pipe and drill
collars and has updated and refurbished drilling rigs and engines.  The
depreciable base of the Company's assets increased by approximately $19.0
million in fiscal 2002 and by approximately $12.3 million in fiscal 2001.
Depreciation, depletion and amortization expense on oil and gas properties
increased as a result of the increase in quantities of oil and gas produced
as oil and gas properties are depleted using the units-of-production method.
Also, depreciation, depletion and amortization expense on oil and gas
properties increased as a result of the number of oil and gas producing
properties in which the Company has an ownership interest (a total of 127
wells in fiscal 2002 versus 111 wells in 2001).

   General and administrative expenses increased approximately 56%. This
increase is primarily due to an increase in payroll and insurance expenses.

   The Company recognized a non-cash charge of $4.0 million in fiscal 2002
and $1.2 million in fiscal 2001 related to the writedown of the carrying
value of its oil and gas properties.


                                      -32-





<PAGE> 34

   Net working capital was $9.1 million at March 31, 2002, compared to $5.4
million at March 31, 2001.  The increase in working capital is attributable
to an increase in cash and a decrease in trade payables and other current
liabilities.

Comparison of Year Ended March 31, 2001 to Year Ended March 31, 2000

   Contract drilling revenues for fiscal 2001 increased by 134% from fiscal
2000.  Rig utilization rates in fiscal 2001 and 2000 were 68% and 35%,
respectively.  The increase in contract drilling revenues and utilization
rates was due to an increase in oil and gas prices which in turn positively
impacted demand for contract drilling.  Drilling prices have steadily
increased during the year ended March 31, 2001.  Availability of experienced
personnel has become a problem industry wide and certainly affects rig
utilization.  Historically, rig utilization in the Company's operating market
is difficult to project because of wide fluctuations in drilling activity.
In addition, the number of rigs industry wide that are actually available for
work cannot be accurately determined.

   Contract drilling expenses were 63% and 81% of contract drilling revenues
in fiscal 2001 and 2000, respectively.  The decrease can be attributable to
high start up costs that occurred in 2000.  High start up costs are
associated with putting rigs into service afer being idle or stacked for a
period of time.  Additionally, the decrease is a result of higher revenues
due to increasing drilling prices.

   Oil and gas revenues increased by 72% in fiscal 2001.  This increase is
a result of an increase in prices received for crude oil and natural gas.
The following table sets forth certain information relating to oil and gas
revenues:

                                       Fiscal year ended
                                          March 31,
                                       -----------------
                                       2001         2000
                                       ----         ----
         Quantities
         ----------
         Oil (bbls)                  108,886       78,217
         Gas (mcf)                   428,355      611,901

         Average Price
         -------------
         Oil (bbls)                  $ 31.14      $ 21.12
         Gas (mcf)                   $  4.82      $  2.48







                                      -33-





<PAGE> 35
   The decline in natural gas production from the prior year is due to the
plugging and abandonment of two non-operated natural gas wells in Ward
County, Texas.  Also, a recompletion of one well in Pecos County, Texas has
negatively affected the current year's natural gas production.  In addition,
the Company's interest in a natural gas well in Lea County, New Mexico was
reduced by 25% because the well reached "pay-out" status.

   Oil and gas production expenses increased by approximately 47%.  This
increase in production expenses can be attributed to the increased water
production and workover on one well in Gaines County, Texas.  In addition,
the Company has experienced a general rise in the cost of services and
supplies which are included in production expenses.  Severance taxes
increased along with the increase in oil and gas revenue.  Also, the prior
years results are affected by a recovery of an insurance claim concerning the
loss of a well bore in Lea County, New Mexico.  The production expenses in
the prior year reflect this recovery.

   The Company participated as a working-interest owner in the drilling of
21 wells during fiscal 2001, of which nine were dry holes.  In fiscal 2000,
the Company participated as a working-interest owner in the drilling of 16
wells, of which 4 were dry holes.

   Depreciation, depletion and amortization expense increased due to several
factors.  The increase in rig utilization rates caused an increase in
depreciation expense as drilling equipment is depreciated using the units-of-
production method based on the monthly utilization of the equipment.  During
the year ended March 31, 2001, the Company purchased a BDW-800 rig with a
depth capacity of approximately 16,000 feet.  This rig was put in service on
February 6, 2001.  The addition of the rig brought the Company's available
fleet to 19 rigs.  Unfortunately, on April 12, 2001, an explosion, fire and
subsequent blow-out destroyed one of our National 75A rigs that had a depth
capacity of 12,500 feet.  Three Company employees were injured as a result of
the fire.  Their injuries are covered under the Company's workers'
compensation policy.  The rig was insured in the amount of $750,000.  As a
result of the explosion, fire and subsequent blow-out, the Company has an
available fleet of 18 drilling rigs.  Also, during the year the Company
purchased drill collars and drill pipe.

   During the year ended March 31, 2001, the Company recovered approximately
$384,000 in bad debts that had been reserved in prior years.  This amount is
included in miscellaneous income.

   The Company recognized a non-cash charge of approximately $1.2 million in
fiscal 2001 and $.7 million in fiscal 2000 related to the writedown of the
carrying value of its oil and gas properties.

   Net working capital was $5.4 million at March 31, 2001, compared to $2.8
million at March 31, 2000.  The increase in working capital is attributable
to an increase in accounts receivable which relates to the increase in
drilling activity.



                                      -34-





<PAGE> 36

Income Taxes

   At March 31, 2002, the Company had approximately $47.2 million of unused
net operating loss ("NOL") carryforwards for tax purposes.  Use of these
carryforwards is dependent upon the Company's ability to generate taxable
earnings in future periods.  These carryforwards began to expire in fiscal
2000 and approximately $5.7 million will expire in 2002.  The Company's
ability to utilize its NOL carryforwards may be substantially limited in the
future under the Internal Revenue Code of 1986, as amended (the "Code").  If
the Company experiences an ownership change under applicable provisions of
the Code, the carryforward would be limited to an annual amount determined by
specified interest rates and other variables.  The Company does not believe
an ownership change has occurred to date.

   The effective tax rates for fiscal 2002 and 2001 differ from the statutory
tax rate of 34% primarily due to the utilization of NOLs.  Tax expense is
generally limited to alternative minimum tax.

   The Company utilizes an asset and liability approach for financial
accounting and reporting for income taxes.  The Company has a deferred tax
asset primarily due to its NOL carryforwards.  The Company has provided a
valuation allowance for the entire balance of deferred tax assets as it is
more likely than not that the deferred tax asset will not be realized.

Liquidity and Capital Resources

   In June, 2000, the Company entered into a second amended and restated loan
agreement with Wells Fargo Bank Texas, N.A.  The loan agreement provides for
a $5.0 million revolving line of credit facility, of which $5.0 million was
available at June 7, 2002. The facility is secured by the Company's drilling
rigs and related equipment, accounts receivable and inventory.  Borrowings
under the revolving facility bear interest at an annual rate equal to the
bank's base rate, or 4.75% at June 7, 2002. Accrued and unpaid interest on
outstanding principal is payable monthly.  The loan facility matures on
August 31, 2003, at which time all outstanding principal and accrued and
unpaid interest will be due and payable in full. At March 31, 2002, no
amounts were outstanding under the loan facility. The principal amount
outstanding at any one time may not exceed the lesser of $5.0 million or one-
third of the borrowing base amount.  The borrowing base amount is the sum of
the Company's accounts receivable and the value of its inventory, drilling
rigs, drill pipe and related equipment. The borrowing base amount is
redetermined quarterly by the Company, except that the bank may, in its
discretion, make its own determination of the borrowing base which will be
the controlling borrowing base amount.  At March 31, 2002, the borrowing base
amount was $39,565,779.

   In addition to certain customary affirmative covenants, the loan agreement
contains restrictions with respect to (i) incurring additional debt,
incurring or permitting liens to exist on any of the Company's property,



                                      -35-





<PAGE> 37
assets or revenues, (ii) declaring or paying dividends or other distributions
on its capital stock (or acquiring any of its capital stock), (iii) issuing
capital stock, (iv) entering into transactions with affiliates, (v) disposing
of assets, and (vi) certain other matters.  The loan agreement also contains
financial covenants with respect to minimum tangible net worth, the current
ratio and the ratio of total liabilities to net worth.

   The Company anticipates that funds for its capital expenditures in fiscal
2003 will be available from a combination of sources, including (i)
borrowings under the line of credit , (ii) funds raised through issuances of
equity or debt securities in public or private transactions, and (iii)
internally generated funds.

   The following table sets forth information regarding the capital
expenditures made by the Company during the last three fiscal years.


                                                   Year Ended March 31,
                                                 --------------------------
                                                 2002        2001      2000
                                                 ----        ----      ----
                                                        (In thousands)
Oil and gas exploration and development.....    $12,183     $ 7,596   $ 2,904
Drilling rigs, drill pipe and
  related equipment.........................      6,201       4,139     3,149
Other.......................................        703         586       199
                                                 ------      ------    ------
     Total..................................    $19,087    $ 12,321   $ 6,252
                                                 ======      ======    ======

   The Company presently anticipates making capital expenditures of
approximately $11.5 million in its 2003 fiscal year.  Of this amount, the
Company expects that approximately $4.0 million will be spent for the
acquisition of drill pipe, drill collars and related equipment, and
approximately $7.0 million for oil and gas exploration and development
activities.  It is the Company's policy, however, to make capital
expenditures based on prevailing economic conditions, the results of its
drilling activities, and other factors affecting its business.  Accordingly,
the amounts actually spent in fiscal 2003 could differ substantially from the
amounts estimated.

Trends and Prices

   The contract drilling industry is currently experiencing decreased demand
and decreasing prices for contract drilling services due to the instability
of oil and gas prices.  The Company will be affected by price fluctuations in
the  industry, but cannot predict either the future level of demand for its
contract drilling services or future conditions in the contract drilling
industry.

   In recent years, oil and gas prices have been extremely volatile.  Prices
are affected by market supply and demand factors as well as by actions of


                                      -36-




<PAGE> 38
state and local agencies, the U.S. and foreign governments and international
cartels.  The Company has no way of accurately predicting the supply of and
demand for oil and gas, domestic or international political events or the
effects of any such factors on the prices received by the Company for its oil
and gas.


Item 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

   The primary sources of market risk for the Company include fluctuations
in commodity prices and interest rate fluctuations.  At March 31, 2002, the
Company had not entered into any hedge arrangements, commodity swap
agreements, commodity futures, options or other similar agreements relating
to crude oil and natural gas.

   Commodity Price Risk - The Company produces and sells crude oil, natural
gas and natural gas liquids.  As a result, its operating results are
significantly affected by fluctuations in commodity prices caused by changing
market forces.

   Historically, the Company has not entered into hedging arrangements for
its oil and gas production and it does not have any delivery commitments.
The Company may, in the future, attempt to reduce its exposure to the
volatility of oil and gas prices by hedging a portion of its production.  In
a typical hedge transaction, the Company would have the right to receive from
the counterparty to the hedge, the excess of the fixed price specified in the
hedge over a floating price based on a market index, multiplied by the
quantity hedge.   If the floating price exceeds the fixed price, the Company
would be required to pay the counterparty this difference multiplied by the
quantity hedged.  In the case, the Company would be required to pay the
difference regardless of whether it had sufficient production to cover the
quantities specified in the hedge.  Significant reductions in production at
times when the floating price exceeds the fixed price could require the
Company to make payments under the hedge agreements even though such payments
are not offset by sales of production.  Hedging could also prevent the
hedging party from receiving the full advantage of increases in oil and gas
prices above the fixed amount specified in the hedge.

   Interest Rate Risk - At March 31, 2002 the Company had no borrowings
outstanding under its loan agreement.  However, when it does have outstanding
borrowings, the Company's exposure to changes in interest rates primarily
results from short term changes in its bank's prime rate.











                                      -37-





<PAGE> 39

Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                                                                  Page
                                                                  ----
     Reports of Independent Public Accountants                     39

     Balance Sheets, March 31, 2002 and 2001                       41

     Statements of Operations, Years ended
       March 31, 2002, 2001 and 2000                               43

     Statements of Stockholders' Equity,
       Years ended March 31, 2002, 2001 and 2000                   44

     Statements of Cash Flows,
       Years ended March 31, 2002, 2001 and 2000                   45

     Notes to Financial Statements                                 46


































                                      -38-





<PAGE> 40
                       Independent Auditors' Report


The Board of Directors
TMBR/Sharp Drilling, Inc.:

     We have audited the accompanying balance sheet of TMBR/Sharp Drilling,
Inc. as of March 31, 2002, and the related statements of operations,
stockholders' equity, and cash flows for the year then ended.  These
financial statements are the responsibility of the Company's management.  Our
responsibility is to express an opinion on these financial statements based
on our audit.

     We conducted our audit in accordance with auditing standards generally
accepted in the United States of America.  Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement.  An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements.  An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation.  We believe that our
audit provides a reasonable basis for our opinion.

     In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of TMBR/Sharp
Drilling, Inc. as of March 31, 2002, and the results of its operations and
its cash flows then ended in conformity with accounting principles generally
accepted in the United States of America.

     Our audits were made for the purpose of forming an opinion on the basic
financial statements take as a whole.  The supplementary information included
in Schedule II required by the Securities and Exchange Commission is
presented for purposes of additional analysis and is not a required part of
the basic financial statements. Such information has been subjected to the
auditing procedures applied in the audits of the basic financial statements
and, in our opinion, is fairly stated in all material respects in relation to
the basic financial statements taken as a whole.




                                             KPMG LLP

June 24, 2002
Midland, Texas








                                      -39-





<PAGE> 41

                REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

     This report was issued by Arthur Andersen LLP in connection with the
Company's 2001 Form 10-K and has not been reissued by Arthur Andersen LLP.

To the Board of Directors and Stockholders of TMBR/Sharp Drilling, Inc.:

     We have audited the accompanying balance sheets of TMBR/Sharp Drilling,
Inc. (a Texas corporation) as of March 31, 2001 and 2000, and the related
statements of operations, stockholders' equity and cash flows for each of the
three years in the period ended March 31, 2001.  These financial statements
are the responsibility of the Company's management.  Our responsibility is to
express an opinion on these financial statements based on our audits.

     We conducted our audits in accordance with auditing standards generally
accepted in the United States.  Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
financial statements.  An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation.  We believe that our
audits provide a reasonable basis for our opinion.

     In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of TMBR/Sharp
Drilling, Inc. as of March 31, 2001 and 2000, and the results of its
operations and its cash flows for each of the three years in the period ended
March 31, 2001, in conformity with accounting principles generally accepted
in the United States.

     Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole.  The schedule listed in the index at
Item 14(a)2 is presented for purposes of complying with the Securities and
Exchange Commission's rules and is not a part of the basic financial
statements.  This schedule has been subjected to the auditing procedures
applied in the audits of the basic financial statements and, in our opinion,
fairly states in all material respects the financial data required to be set
forth therein in relation to the basic financial statements taken as a whole.






                                          ARTHUR ANDERSEN LLP

Dallas, Texas,
 May 18, 2001



                                      -40-





<PAGE> 42
                           TMBR/SHARP DRILLING, INC.

                                Balance Sheets

                           March 31, 2002 and 2001

                      (In thousands, except share data)




  ASSETS                                        2002            2001
  ------                                        ----            ----

Current assets:
  Cash and cash equivalents               $     3,258       $     301
  Marketable securities                            97              91
  Trade receivables,
    net of allowance for doubtful
      accounts of $1,401 in 2002
      and $1,227 in 2001.                      11,011          13,625
  Inventories                                     162             148
  Deposits                                        346              73
  Other                                         1,018             871
                                               ------          ------
     Total current assets                      15,892          15,109
                                               ------          ------


Property and equipment, at cost:
  Drilling equipment                           61,370          55,599
  Oil and gas properties, based on
    successful efforts accounting              34,616          26,372
  Other property and equipment                  3,531           2,844
                                               ------          ------
                                               99,517          84,815
  Less accumulated depreciation,
    depletion and amortization                (72,947)        (64,696)
                                               ------          ------
     Net property and equipment                26,570          20,119
                                               ------          ------

Other assets                                      173             173
                                               ------          ------

          Total assets                       $ 42,635        $ 35,401
                                               ======          ======


See accompanying notes to financial statements.



                                      -41-





<PAGE> 43
                          TMBR/SHARP DRILLING, INC.

                                Balance Sheets

                           March 31, 2002 and 2001

                      (In thousands, except share data)



  LIABILITIES AND STOCKHOLDERS' EQUITY                     2002          2001
  ------------------------------------                     ----          ----

Current liabilities:
  Trade payables                                         $ 5,193      $  7,414
  Other                                                    1,610         2,301
                                                          ------        ------
     Total current liabilities                             6,803         9,715

Long Term liabilities:
  Borrowings from bank                                        --         1,080
                                                          ------        ------
     Total liabilities                                     6,803        10,795
                                                          ------        ------
Contingencies

Stockholders' equity:
  Common stock, $0.10 par value
    Authorized, 50,000,000 shares;
    issued, 6,667,725 and 6,332,225
    shares at March 31, 2002 and
    2001, respectively                                       667           633
  Additional paid-in capital                              71,492        70,122
  Accumulated deficit                                    (36,187)      (46,003)

  Accumulated other comprehensive
    income (loss)                                             10             4
  Treasury stock-common, 1,268,739 shares
    at March 31, 2002, and 2001, at cost                    (150)         (150)
                                                          ------        ------
     Total stockholders' equity                           35,832        24,606
                                                          ------        ------

       Total liabilities and
         stockholders' equity                           $ 42,635      $ 35,401
                                                          ======        ======

See accompanying notes to financial statements.





                                      -42-





<PAGE> 44
                          TMBR/SHARP DRILLING,, INC.

                           Statements of Operations

                  Years Ended March 31, 2002, 2001 and 2000

                      (In thousands, except share data)

                                            2002         2001        2000
                                            ----         ----        ----
Revenues:
  Contract drilling                      $ 46,712     $ 36,023    $ 15,394
  Oil and gas                               5,508        5,454       3,169
                                           ------       ------      ------
          Total revenues                   52,220       41,477      18,563
                                           ------       ------      ------
Operating costs and expenses:
  Contract drilling                        26,761       22,767      12,486
  Oil and gas production                    1,721        1,363         926
  Dry holes and abandonments                1,657          811         490
  Exploration                                  60          174          19
  Depreciation, depletion and
    amortization                            6,746        5,137       3,282
  Writedown of oil and gas
    properties                              3,953        1,171         739
  General and administrative                2,552        1,918       1,854
                                           ------       ------      ------
          Total operating costs
            and expenses                   43,450       33,341      19,796
                                           ------       ------      ------
          Operating income (loss)           8,770        8,136      (1,233)
                                           ------       ------      ------
Other income (expense):
  Interest                                     11         (216)         17
  Gain on sales of assets                     537          256         137
  Other, net                                  498          302        (128)
                                           ------       ------      ------
          Total other income
            (expense), net                  1,046          342          26
                                           ------       ------      ------
Net income (loss) before
  income tax provision                      9,816        8,478      (1,207)
Provision for income taxes                     --         (170)         --
                                           ------       ------      ------
Net income (loss)                         $ 9,816      $ 8,308    $ (1,207)
                                           ======       ======      ======
Net income (loss) per common share:
     Basic                              $    1.88     $   1.67   $   (0.25)
     Diluted                                 1.79         1.54       (0.25)
                                         =========    =========   =========
Weighted average number of
  common shares outstanding:
     Basic                               5,220,047    4,979,082   4,760,704
     Diluted                             5,473,994    5,391,934   4,760,704
                                         =========    =========   =========

See accompanying notes to financial statements.

                                      -43-
<PAGE> 45
                       TMBR/SHARP DRILLING, INC.

                  Statements of Stockholders' Equity

               Years Ended March 31, 2002, 2001 and 2000

                            (In thousands)

<TABLE>
<CAPTION>
                                                                   Accumulated
                        Common Stock     Additional                   Other      Treasury Stock        Total
                        ------------      Paid-In     Accumulated Comprehensive  ---------------   Stockholders'
                       Shares   Amount    Capital       Deficit   (Loss) Income  Shares   Amount      Equity
                       ------   ------   ----------   ----------- -------------  ------   ------   -------------
<S>                     <C>       <C>      <C>           <C>            <C>       <C>      <C>         <C>
Balance, March 31,
  1999                  5,980     598       69,429       (53,104)       (38)      1,270    (150)        16,735

Exercise of
  Stock Options           247      25          146            --         --          --      --            171

Grant of
  Stock Options            --      --           97            --         --          --      --             97

Net Loss                   --      --           --        (1,207)        --          --      --         (1,207)
                        -----    -----     --------      --------      -----      -----    -----       --------

Balance, March 31,
 2000                   6,227   $ 623     $ 69,672     $ (54,311)      $(38)      1,270   $(150)      $ 15,796

Exercise of
  Stock Options           105      10          450            --         --          --      --            460

Net Income                 --      --           --         8,308         --          --      --          8,308

Other comprehensive
 income, net of tax
 Unrealized gain on
 marketable equity
 securities                --      --           --            --         42          --      --             42
                                                                                                       --------
Comprehensive Income                                                                                     8,350
                        -----    -----     --------      --------      -----      -----    -----       --------
Balance, March 31,
 2001                   6,332   $ 633     $ 70,122     $ (46,003)     $   4       1,270   $(150)      $ 24,606
                        -----    -----     --------      --------      -----      -----    -----       --------

Exercise of
  Stock Options           329      33        1,295           --         --          --      --           1,328

Director Stock Award        7       1           75           --         --          --      --              76

Net Income                 --      --           --         9,816        --          --      --           9,816





<PAGE> 46


Other comprehensive
 income, net of tax
 Unrealized gain on
 marketable equity
 securities                --      --           --            --          6         --      --               6
                                                                                                       --------
Comprehensive Income                                                                                     9,822
                        -----    -----     --------      --------      -----      -----    -----       --------
Balance, March 31,
 2002                   6,668   $ 667     $ 71,492     $ (36,187)     $   10      1,270   $(150)      $ 35,832
                        =====    =====     ========      ========      =====      =====    =====       ========
</TABLE>
See accompanying notes to financial statements.






































                                      -44-





<PAGE> 47
                           TMBR/SHARP DRILLING, INC.
                           Statements of Cash Flows
                    Years Ended March 31, 2002, 2001 and 2000
                                  (In thousands)

                                                   2002       2001       2000
                                                   ----       ----       ----
Cash flows from operating activities:
  Net income (loss)                              $ 9,816    $ 8,308   $ (1,207)
  Adjustments to reconcile net
    income (loss) to net cash provided
    by operating activities:
      Depreciation, depletion and amortization     6,746      5,137      3,282
      Dry holes and abandonments                   1,657        811        490
      Gain on sales of assets                       (537)      (256)      (137)
      Grant of stock options                          --         --         97
      Writedown of properties                      3,953      1,171        739
      Changes in assets and liabilities:
        Trade receivables                          2,615     (7,227)    (2,947)
        Inventories and other assets                (435)      (212)      (246)
        Trade payables                            (2,221)     3,174      2,816
        Accrued payables and other
          current liabilities                       (691)       962        575
                                                 --------   --------   --------
          Total adjustments                       11,087      3,560      4,669
                                                 --------   --------   --------
          Net cash provided
            by operating activities               20,903     11,868      3,462
                                                 --------   --------   --------
Cash flows from investing activities:
  Additions to property and equipment            (19,087)   (12,321)    (6,252)
  Proceeds from sales of property
    and equipment                                    817        484        154
                                                 --------   --------   --------
          Net cash required
            by investing activities              (18,270)   (11,837)    (6,098)
                                                 --------   --------   --------
Cash flows from financing activities:
  Proceeds from exercise of stock options          1,328        460        171
  Proceed from issuance of common stock               76         --         --
  Proceeds (repayments) from bank loan, net       (1,080)    (1,170)     2,250
                                                 --------   --------   --------
          Net cash provided (required)
            by financing activities                  324       (710)     2,421
                                                 --------   --------   --------
          Net increase (decrease) in
            cash and cash equivalents              2,957       (679)      (215)

Cash and cash equivalents at beginning
  of year                                            301        980      1,195
                                                 --------   --------   --------
Cash and cash equivalents at end of year      $    3,258  $     301    $   980
                                                 ========   ========   ========

See accompanying notes to financial statements.

                                      -45-


<PAGE> 48
                         TMBR/SHARP DRILLING, INC.



                       Notes to Financial Statements




(1)  Organization, Nature of Business and Summary of Significant Accounting
     Policies

Nature of Operations

     TMBR/Sharp Drilling, Inc. (the "Company") was incorporated under the
laws of Texas in October, 1982 under the name TMBR Drilling, Inc.  In August,
1986, the Company changed its name to TMBR/Sharp Drilling, Inc.

     The Company's principal businesses are the domestic onshore contract
drilling of oil and gas wells for major and independent oil and gas
producers, and, to a lesser extent, the exploration for, development and
production of oil and natural gas.  The Company's drilling activities are
primarily conducted in the Permian Basin of west Texas and eastern New
Mexico.

Cash and Cash Equivalents

     For purposes of the statements of cash flows, the Company considers
highly liquid debt instruments which have an original maturity of three
months or less to be cash equivalents.  Cash payments for interest expense
were approximately $21,000 for 2002 and $270,000 for 2001 and $15,000 in
2000.  Cash payments for taxes due totaled $160,000,$0, and $0, during 2002,
2001 and 2000, respectively.

Marketable Securities

       Under SFAS No. 115, "Accounting for Certain Investments in Debt and
Equity Securities", marketable securities, such as those owned by the
Company, are classified as available-for-sale securities and are to be
reported at market value, with unrealized gains and losses, net of income
taxes, excluded from earnings and reported as a separate component of
stockholders' equity.  The market value of these securities at March 31, 2002
was approximately $97,000.  An unrealized gain of approximately $6,000 was
added to stockholders equity and was included as a component of other
comprehensive income.








                                      -46-





<PAGE> 49
                         TMBR/SHARP DRILLING, INC.


                       Notes to Financial Statements


Inventories

     Inventories consist primarily of casing and tubing.  The Company values
its inventories at the lower of cost or estimated net recoverable value using
the specific identification method.

Property and Equipment

     Drilling equipment is depreciated on a units-of-production method based
on the monthly utilization of the equipment.  Drilling equipment which is not
utilized during a month is depreciated using a minimum utilization rate of
approximately twenty-five percent.  Estimated useful lives range from four to
eight years.  Other property and equipment is depreciated using the straight-
line method of depreciation with estimated useful lives of three to seven
years.

     Oil and gas properties are accounted for using the successful efforts
method of accounting.  Accordingly, the costs incurred to acquire property
(proved and unproved), all development costs and successful exploratory costs
are capitalized, whereas the costs of unsuccessful exploratory wells are
expensed.  Geological and geophysical costs, including seismic costs, are
charged to expense when incurred.  In cases where the Company provides
contract drilling services related to oil and gas properties in which it has
an ownership interest, the Company's proportionate share of costs related to
these properties is capitalized as stated above, net of the Company's working
interest share of profits from the related drilling contracts.  Capitalized
costs of undeveloped properties, which are not depleted until proved reserves
can be associated with the properties, are periodically reviewed for possible
impairment.  Such unevaluated costs totaled approximately $1,967,000 and
$845,000 as of March 31, 2002 and 2001, respectively.

     Depletion, depreciation and amortization of capitalized oil and gas
property costs is provided using the units-of-production method based on
estimated proved or proved developed oil and gas reserves, as applicable, of
the respective property units.

     Prior to 1996, the Company provided impairments for significant proved
oil and gas properties to the extent that net capitalized costs exceeded
aggregated undiscounted future net cash flows.  During 1996, the Company
adopted Statement of Financial  Accounting  Standards No. 121  ("SFAS 121"),







                                      -47-





<PAGE> 50
                         TMBR/SHARP DRILLING, INC.


                       Notes to Financial Statements


"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of".  SFAS 121 requires the Company to assess the need for an
impairment of capitalized costs of oil and gas properties on a property-by-
property basis.  According to SFAS 121, if an impairment is indicated based
on undiscounted expected future cash flows, then it is recognized to the
extent that net capitalized costs exceed discounted future cash flows.
Impairments of $3,953,000, $1,171,000 and $739,000 were recorded in 2002,
2001 and 2000, respectively.  Management's estimate of future cash flows is
based on their estimate of reserves and prices.  It is reasonably possible
that a change in reserve or price estimates could occur in the near term and
adversely impact management's estimate of future cash flows and consequently
the carrying value of properties.

     Major renewals and betterments are capitalized in the appropriate
property accounts while the cost of repairs and maintenance is charged to
operating expense in the period incurred.  For assets sold or otherwise
retired, the cost and related accumulated depreciation amounts are removed
from the accounts and any resulting gain or loss is recognized.

Drilling Revenues and Costs

     Drilling revenues from footage and daywork contracts are recognized as
work is performed utilizing the percentage-of-completion method.  Costs on
footage and daywork contracts are recognized in the period incurred.  The
Company utilizes the completed contract method to recognize drilling revenues
and expenses relating to turnkey contracts.  Expected losses on all in-
process contracts are recognized in the period the loss can reasonably be
determined.

Risks and Uncertainties

     The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period.  Actual results could differ from those estimates.
Significant estimates with regard to these financial statements include the
estimate of proved oil and gas reserve volumes and the related present value
of estimated future net revenues therefrom (see Note 9), the valuation
allowance for deferred taxes (see Note 4), the provision for doubtful
accounts, and the reserve for the Company's portion of workers compensation
claims.




                                      -48-





<PAGE> 51
                         TMBR/SHARP DRILLING, INC.


                       Notes to Financial Statements



Net Income (Loss) Per Share of Common Stock

     On April 1, 1997, the Company adopted Statement of Financial Accounting
Standards No. 128 ("SFAS 128") "Earnings Per Share" which superseded
Accounting Principles Board Opinion No. 15 ("APB 15") "Earnings Per Share."
SFAS 128 simplifies earnings per share ("EPS") calculations by replacing
previously reported primary EPS with basic EPS which is calculated by
dividing reported earnings available to common shareholders by the weighted
average shares outstanding.  No dilution for potentially dilutive securities
is included in basic EPS.  Previously reported fully diluted EPS is called
diluted EPS which includes all potentially dilutive securities.  The
following table sets forth certain information concerning EPS.

                                           For the Year Ended 2002
                                      ---------------------------------
                                                              Per Share
                                      Income        Shares     Amount
                                      ------        ------    ---------
Income before extraordinary
item and accounting change            $9,816

Basic EPS
Income available to common
stockholders                           9,816       5,220,047    $1.88
                                                                 ====
Effect of Dilutive Securities
Stock Options                                        253,947
                                       -----       ---------

Diluted EPS
Income available to common
stockholders + assumed
conversions                           $9,816       5,473,994    $1.79
                                       =====       =========     ====

     Common stock equivalents for 2000 and 2001 were anti-dilutive.










                                      -49-





<PAGE> 52
                         TMBR/SHARP DRILLING, INC.


                       Notes to Financial Statements




Stock Based Employee Compensation

     In October 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 123 ("SFAS 123") "Accounting
for Stock-Based Compensation," which establishes accounting and reporting
standards for various stock based compensation plans.  SFAS 123 encourages
the adoption of a fair value based method of accounting for employee stock
options, but permits continued application of the accounting method
prescribed by Accounting Principles Board Opinion No. 25 ("Opinion 25"),
"Accounting for Stock Issued to Employees."  The Company has elected to
continue to apply the provisions of Opinion 25.  Under Opinion 25, if the
exercise price of the Company's stock options equals the market value of the
underlying stock on the date of grant, no compensation expense is recognized.
SFAS 123 requires disclosure of pro forma information regarding net income
and earnings per share as if the Company had accounted for its employee stock
options under the fair value method of the statement.  See Note 3
"Stockholders' Equity."

Recent Accounting Pronouncements

     In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Certain Hedging Activities."  In June 2000, the FASB issued
SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain
Hedging Activity, an Amendment of SFAS 133."  SFAS No. 133 and SFAS No. 138
require that all derivative instruments be recorded on the balance sheet at
their respective fair values.  SFAS No. 133 and SFAS No. 138 are effective
for all fiscal quarters of all fiscal years beginning after June 30, 2000;
the Company adopted SFAS No. 133 and SFAS No. 138 on April 1, 2001.  There
was no material impact to the financial statements.

     In July 2001, the FASB issued Statements of Financial Accounting
Standards No. 141, "Business Combinations" and No. 142, "Goodwill and Other
Intangible Assets."  SFAS No. 141 requires that all business combinations
initiated after June 30, 2001 be accounted for under the purchase method and
SFAS No. 142 requires that goodwill no longer be amortized to earnings, but
instead be reviewed for impairment.  The adoption of SFAS 141 and 142 did not
have any impact on the Company.







                                      -50-





<PAGE> 53
                         TMBR/SHARP DRILLING, INC.


                       Notes to Financial Statements



     Also, the FASB has issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" which establishes requirements for the accounting of removal-
type costs associated with asset retirements.  The standard is effective for
fiscal years beginning after June 15, 2002, with earlier application
encouraged.  The Company is currently assessing the impact on its financial
statements.

     On October 3, 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets."  This pronouncement supercedes
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-
Lived Assets to Be Disposed" and eliminates the requirement for SFAS 121 to
allocate goodwill to long-lived assets to be tested for impairment.  The
provisions of this statement are effective for financial statements issued
for fiscal years beginning after December 15, 2001, and interim periods
within those fiscal years.  The Company is currently assessing the impact to
its financial statements.

(2)  Debt

     Line of Credit

     In May, 1998, the Company entered into a loan agreement with its bank
lender which provides for a $5.0 million revolving line of credit secured by
substantially all of the Company's drilling rigs and related equipment,
accounts receivable and inventory.  Borrowings under the line of credit bore
interest at the bank's base rate and accrued interest was payable monthly.
The loan facility originally matured on May 26, 2000 but was extended to July
15, 2000.


















                                      -51-





<PAGE> 54
                         TMBR/SHARP DRILLING, INC.

                       Notes to Financial Statements


     On June 26, 2000, the Company renewed and extended the prior loan
agreements with its bank lender.  The second and restated agreement provides
for a $5.0 million revolving line of credit secured by the Company's drilling
rigs and related equipment, accounts receivable and inventory.  Borrowings
under this line of credit bear interest at the Wells Fargo Bank Texas, N. A.
(formerly Norwest Bank, Texas N.A.) base rate (4.75% at March 31, 2002) and
accrued interest is payable monthly.  The loan facility originally  matured
on August 31, 2002.  On February 12, 2002, the maturity date of the loan
facility was extended to August 31, 2003, at which time all outstanding
principal and interest will be due in full.  At March 31, 2002, no amounts
were outstanding under the loan facility.

(3)  Stockholders' Equity

     (a)  Common Stock

     On February 13, 1997, the Company closed a private placement of 725,000
shares of common stock at a price of $11.00 per share.  The net proceeds from
the placement were approximately $7.4 million.

     (b) Stock Option Plans

1984 Stock Option Plan

     In August, 1984, the Company adopted the 1984 Stock Option Plan (the
"Plan") which initially authorized 375,000 shares of the Company's common
stock to be issued as either incentive stock options or nonqualified stock
options.  This Plan was amended in August 1986 to increase the authorized
shares to 475,000 shares of the Company's common stock.  In January 1988, the
Plan was amended to reduce the option price on certain options issued prior
to March 31, 1986, to reflect the then current fair market value of the
Company's common stock.  The Plan provides that options may be granted to key
employees or directors for various terms at a price not less than the fair
market value of the shares on the date of the grant.  Options to purchase
5,000 shares of common stock are currently exercisable and outstanding under
the Plan.  No additional shares are available for grant as the Plan expired
by its own terms in August 1994.  The options that were granted
prior to the expiration of the Plan, and which are outstanding, remain
subject to the terms of the Plan.









                                      -52-





<PAGE> 55
                         TMBR/SHARP DRILLING, INC.


                       Notes to Financial Statements




1994 Stock Option Plan

     In July 1994, the Company adopted its 1994 Stock Option Plan (the "1994
Plan") which authorized the grant of options to purchase up to 750,000 shares
of the Company's common stock.  These options may be issued as either
incentive or nonqualified stock options.  The 1994 Plan provides that options
may be granted to key employees or directors for various terms at a price not
less than the fair market value of the shares on the date of grant.  The 1994
Plan was ratified and approved by the stockholders at the Company's annual
meeting of stockholders held on August 30, 1994.  In September 1998, options
outstanding under the plan were amended to reduce the option price to $4.125
per share.

     On September 3, 1996, the Company granted 465,000 shares of nonqualified
stock options to key employees under the 1994 Plan.  All of the nonqualified
stock options granted on September 3, 1996 are earned and exercisable as of
May 1, 1997.  On September 1, 1998, the Company granted 240,000 shares of
incentive stock options at a price of $4.125 to key employees under the 1994
Plan.  On March 9, 2002, all of the shares were earned and exercisable.  The
following sets forth certain information concerning these options.

                                     Number            Option Price
                                       of         -----------------------
                                     Shares       Per Share         Total
                                     ------       -----------------------

     Outstanding March 31, 2000     564,500    $4.125-4.5375   $ 2,387,963

     Exercised                      (80,100)    4.125-4.5375      (357,638)
                                    -------     ------------     ---------
     Outstanding March 31, 2001     484,400    $4.125-4.5375   $ 2,030,325

     Exercised                     (234,000)    4.125-4.5375      (994,950)
                                    -------     ------------     ---------
     Outstanding March 31, 2002     250,400    $4.125-4.5375   $ 1,035,375
                                    =======     ============    ==========









                                      -53-





<PAGE> 56
                         TMBR/SHARP DRILLING, INC.


                       Notes to Financial Statements


1998 Stock Option Plan

     In September 1998, the Company adopted, subject to shareholder approval,
its 1998 Stock Option Plan (the "1998 Plan") which authorizes the grant of
options to purchase up to 750,000 shares of the Company's common stock.
These options may be issued as either incentive or nonqualified stock
options.  The 1998 Plan provides that options may be granted to key employees
or directors from various terms at a price not less than the fair market
value of the shares on the date of grant.  The Company granted options to
purchase 50,000 shares of common stock to two outside directors under the
1998 Plan, subject to shareholder approval.  These nonqualified options were
granted at $4.125 per share and became exercisable on August 31, 1999, the
date on which the shareholders of the Company approved and adopted the 1998
Plan.  The fair market value of the Company's common stock on August 31, 1999
was $6.063 per share.  As a result, the Company recognized approximately
$97,000 in compensation expense related to these nonqualified options during
the year ended March 31, 2000.  On June 13, 2001, the Company granted options
to purchase 40,000 shares of common stock to four directors under the 1998
Plan.  The nonqualified options were granted at an exercise price of $17.18
per share which represented the fair market value on the date of the grant.
On October 10, 2001, the Company granted options to purchase 292,000 shares
of common stock to key employees under the 1998 Plan.  These incentive
options were granted at an exercise price of $11.50 per share which
represented the fair market value on the date of the grant.  These options
become exercisable over a two year period ending October 10, 2003.  At March
31, 2002, options to purchase 332,000 shares were outstanding under the 1998
Plan.

Directors' Fee Stock Plan

     On June 13, 2001, the Company adopted the Directors' Fee Stock Plan (the
"Plan") which authorizes the issuance of up to 25,000 shares of the Company's
common stock.  The Plan provides that 300 shares of the Company's common
stock will be issued to each Non-employee Director for each Board of
Directors' meeting attended and 100 shares of common stock to each Non-
employee Director for each committee meeting attended.  During the year ended
March 31, 2002, 6,500 shares have been issued under the Plan and the Company
recognized approximately $95,000 as Directors' compensation expense.

     In connection with a private placement completed in February 1997, the
Company issued and currently has outstanding a warrant to purchase 36,250
common shares with an exercise price of $13.20 per share.  This warrant
became exercisable on February 17, 1998, and expired unexercised on February
17, 2002.



                                      -54-




<PAGE> 57
                         TMBR/SHARP DRILLING, INC.



                       Notes to Financial Statements



     Pursuant to SFAS 123, "Accounting for Stock-Based Compensation," the
Company has elected to account for its stock option plans under Opinion No.
25, "Accounting for Stock Issued to Employees."  Accordingly no compensation
expense has been recognized for these stock option plans.  Pro forma
information regarding net income and earnings per share is required by SFAS
123, and has been determined as if the Company had accounted for its employee
stock options under the fair value method of that statement.  The fair value
of each option grant is estimated on the date of the grant using the Black-
Scholes option pricing model with the following weighted-average assumptions
used for grants in fiscal 2002, 2000 and 1999, respectively: dividend yield
of 0%, 0% and 0%, expected volatility of 64.7%, 62.53% and 54.68%, risk free
interest rate of 4.81%, 6.09% and 4.99%, and an expected life of 5.0, 5.0 and
5.0 years.

        Year of     Option     Exercise     Expected     Fair
         Grant      Shares      Price         Life       Value
        -------     ------     --------     --------     -----
         1999        96,000     $4.125        5.0        $2.17
         1999       144,000     $4.5375       5.0        $2.07
         2000        50,000     $4.125        5.0        $2.15
         2002        40,000    $17.18         5.0       $10.09
         2002       292,000    $11.50         5.0        $6.63

     For purposes of pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period.  The
Company's pro forma information follows:

                          2002              2001              2000
                    ----------------   ---------------   ---------------
                       As       Pro       As      Pro       As      Pro
                    Reported   Forma   Reported  Forma   Reported  Forma
                    --------   -----   --------  -----   --------  -----
                                  (In thousands, except share amounts)

Net income (loss)
  from continuing
  operations        $ 9,816   $ 9,413  $ 8,308  $ 8,217   $(1,207) $(1,309)

Net income (loss)
  from continuing
  operations per
  share (basic)      $ 1.88    $ 1.80   $ 1.67   $ 1.65    $(0.25)  $(0.27)




                                      -55-





<PAGE> 58

                         TMBR/SHARP DRILLING, INC.



                       Notes to Financial Statements



     The effects of applying SFAS 123 in this pro forma disclosure are not
indicative of future amounts, as SFAS 123 does not apply to awards prior to
1995 and additional awards are anticipated in future years.


(4)  Income Taxes

     At March 31, 2002, the Company had approximately $47,209,767 of net
operating loss carryforwards for tax purposes.  Realization of the benefits
of these carryforwards is dependent upon the Company's ability to generate
taxable earnings in future periods.  These carryforwards began to expire in
fiscal 2000 and approximately $5.7 million will expire in 2002.  The
Company's ability to utilize its net operating loss carryforwards may be
substantially limited in the future under Section 382 of the Internal Revenue
Code ("IRC").  If the Company encounters a change of control as defined in
IRC Section 382, the carryforward would be limited to an annual amount
calculated based on market value.  The Company does not believe a change of
control, as defined, has occurred to date.

     The Company utilizes an asset and liability approach for financial
accounting and reporting for income taxes.  The major components of deferred
tax assets and liabilities follows:

                                        March 31, 2002    March 31, 2001
                                        --------------    --------------
     Deferred Tax Assets (Liabilities)
       Federal NOL Carryforwards         $ 16,051,321      $ 24,839,381
       Allowance for Bad Debts                476,347           417,313
       Book over tax depreciation
         and amortization                   1,075,043           961,341
       Accrued Workers Compensation           255,547           320,782
       Other accrued expenses                   5,471             7,695
                                           ----------        ----------
         Total deferred tax assets         17,863,729        26,546,512
         Valuation allowance              (17,863,729)      (26,546,512)
                                           ----------        ----------
           Net deferred tax asset        $     --          $     --
                                           ==========        ==========






                                      -56-





<PAGE> 59
                         TMBR/SHARP DRILLING, INC.



                       Notes to Financial Statements



     The Company has provided a valuation allowance for the entire balance of
deferred tax assets at March 31, 2002 and 2001, as it is more likely than not
that the deferred tax asset will not be realized.

     The effective tax rates for the years ended March 31, 2002, 2001 and
2000 differ from the statutory tax rate of 34% primarily due to utilization
of net operating loss carryforwards.  Tax expense is generally limited to
alternative minimum tax.

     The following table sets forth a reconciliation of the tax provision
using statutory rates to the actual tax provision provided in the statements
of operations:

                                       2002       2001        2000
                                       ----       ----        ----

     Tax provision (benefit)
       utilizing statutory rates     $ 3,338    $ 2,882    $  (410)

     Utilization of NOL               (3,338)    (2,712)       410
                                       -----      -----       -----
     Tax provision                   $   --     $   170    $    --
                                       =====      =====       =====


(5)  Related Parties

     During 2002, 2001 and 2000, the Company sold $210,000, $701,000 and
$1,936,000 and purchased $726,000, $154,000 and $81,000, respectively, of
goods and services from entities affiliated with individuals serving as
officers and/or directors of the Company.  These purchases and sales are
transacted using market rates.  These transactions are included in "contract
drilling revenue" and "contract drilling expense" or "other income or
expense" in the accompanying statements of operations.

     The related party transactions discussed in the preceding paragraph are
noninterest-bearing and are settled in the normal course of business.








                                      -57-





<PAGE> 60
                         TMBR/SHARP DRILLING, INC.



                       Notes to Financial Statements

(6)  Business Segments and Significant Customers

     The Company adopted SFAS No. 131, "Disclosures About Segments of an
Enterprise and Related Information", in 1999 which changes the way the
Company reports information about its operating segments.

     The Company operates in two reportable segments: (i) drilling and (ii)
oil and gas exploration and development.  The long-term financial performance
of each of the reportable segments is affected by similar economic
conditions.  Both reportable segments operate in the Permian Basin of West
Texas and Eastern New Mexico.

     The accounting policies of the segments are the same as those described
in Note (1) of Notes to Financial Statements.  The Company evaluates
performance based on profit or loss from operations before income taxes,
accounting changes, nonrecurring items and interest income and expense.

     The Company accounts for intersegment sales transfers as if the sales or
transfers were to third parties, that is, at current prices.




























                                      -58-





<PAGE> 61
                         TMBR/SHARP DRILLING, INC.


                       Notes to Financial Statements


     The following tables present information related to the Companies'
reportable segments.

                                          Years Ended March 31,
                                ----------------------------------------
                                   2002           2001           2000
                                ----------     ----------     ----------
                                             (In thousands)
Revenues:
  Contract drilling              $ 46,712       $ 36,023       $ 15,394
  Oil and gas                       5,508          5,454          3,169
                                  --------       --------       --------
                                 $ 52,220       $ 41,477       $ 18,563
                                  ========       ========       ========
Net income (loss) (a):
  Contract drilling              $ 14,339       $  8,660       $   (333)
  Oil and gas                      (4,534)            34           (891)
                                  --------       --------       --------
                                    9,805          8,694         (1,224)
  Corporate income
    (expenses) (b)                     11           (216)            17
                                  --------       --------       --------
                                 $  9,816       $  8,478       $ (1,207)
                                  ========       ========       ========
Identifiable assets:
  Contract drilling              $ 23,824       $ 23,414       $ 16,350
  Oil and gas                      14,264         10,551          5,277
                                  --------       --------       --------
                                   38,088         33,965         21,627
  Corporate assets (c)              4,547          1,436          1,998
                                  --------       --------       --------
                                 $ 42,635       $ 35,401       $ 23,625
                                  ========       ========       ========
Depreciation, depletion and
 amortization:
  Contract drilling              $  4,316       $  3,398       $  1,730
  Oil and gas                       2,430          1,739          1,552
                                  --------       --------       --------
                                 $  6,746       $  5,137       $  3,282
                                  ========       ========       ========
Capital expenditures:
  Contract drilling              $  6,904       $  4,725       $  3,348
  Oil and gas                      12,183          7,596          2,904
                                  --------       --------       --------
                                 $ 19,087       $ 12,321       $  6,252
                                  ========       ========       ========

                                      -59-





<PAGE> 62
                         TMBR/SHARP DRILLING, INC.


                       Notes to Financial Statements




     (a)  General and administrative costs and other income are allocated
          between segments based on identifiable assets.

     (b)  Corporate income and expenses consist of interest income and
          expense.

     (c)  Corporate assets are those assets which are not specifically
          identifiable with a segment and consist primarily of cash and
          cash equivalents, short-term investments and prepaid expenses.

     For the years ended March 31, 2002, 2001 and 2000, contract drilling
revenues earned from individual customers constituting 10% or more of total
contract drilling revenues were:

     (a)  one drilling customer in 2002 individually represented
          approximately 38% of total revenues,

     (b)  two drilling customers in 2001 individually represented
          approximately 35%, and 13% of total revenues,

     (c)  two drilling customers in 2000 individually represented
          approximately 17%, and 13% of total revenues.

     The loss of one or more of the above customers could have a material
adverse effect on the Company, depending upon the demand for drilling rigs at
the time of such loss and the Company's ability to find new customers.

(7)  Contingencies

     Currently the Company is covered under a three year retroactive plan and
is providing for its workers compensation claims based upon the most recent
information available from its insurance carrier concerning claims and
estimated costs.  In future years, the Company may receive retroactive
adjustments, both favorable and unfavorable, related to estimates of claim
costs for previous years, which may be material to the Company's results of
operations.   No provision for retroactive adjustments to claim costs is
recorded until the Company receives notification from its insurance carrier
because this amount, if any, cannot be estimated.

     From September 1997 to September 2000, the Company was covered by a
fully insured workers' compensation policy.




                                      -60-





<PAGE> 63
                         TMBR/SHARP DRILLING, INC.


                       Notes to Financial Statements





     The Company is a defendant in various lawsuits generally incidental to
its business.  The Company does not believe that the ultimate resolution of
such litigation will have a significant effect on the Company's financial
position or results of operations.

(8)  Supplemental Information Related to Oil and Gas Activities

     The Company's capitalized cost of oil and gas properties is as follows:

                                                        March 31,
                                                        ---------
                                                     2002        2001
                                                     ----        ----
                                                      (In thousands)

          Oil and gas properties                   $34,616     $26,372

          Accumulated depreciation,
            depletion and amortization             (21,583)    (17,283)
                                                    -------     -------
                                                   $13,033     $ 9,089
                                                    =======     =======

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

                                              Years Ended March 31,
                                              ---------------------
                                          2002        2001        2000
                                          ----        ----        ----
                                                 (In thousands)

          Property acquisition costs    $ 1,290     $   717     $   406

          Exploration costs               8,463       5,300       2,389

          Development costs               2,430       1,579         109
                                         -------     -------     -------
                                        $12,183     $ 7,596     $ 2,904
                                         =======     =======     =======




                                      -61-





<PAGE> 64
                         TMBR/SHARP DRILLING, INC.


                       Notes to Financial Statements


     The Company's results of operations from oil and gas producing
activities are as follows:

                                              Years Ended March 31,
                                              ---------------------
                                          2002        2001        2000
                                          ----        ----        ----
                                                 (In thousands)
     Revenues                           $ 5,508     $ 5,454     $ 3,169

     Production costs                     1,721       1,363         926

     Dry holes and abandonments           1,657         811         490

     Exploration costs                       60         174          19

     Depreciation, depletion and
       amortization                       2,430       1,739       1,552

     Writedown of oil and gas
       properties                         3,953       1,171         739

     Income tax provision                   --          --          --
                                         -------      -------    -------
     Results of operations from
       producing activities
       (excluding corporate
       overhead and interest costs)     $(4,313)     $  196    $   (557)
                                         =======      =======    =======

(9) Unaudited Supplemental Oil and Gas Reserve Information

     The reserve information presented below are only estimates.  There are
numerous uncertainties inherent in estimating quantities of proved reserves
and in projecting future rates of production and timing of development
expenditures, including many factors beyond the control of the Company.
Reserve engineering is a subjective process of estimating underground
accumulations of crude oil and natural gas that cannot be measured in an
exact manner, and the accuracy of any reserve estimate is a function of the
quality of available data and of engineering and geological interpretation
and judgment.  The quantities of oil and gas that are ultimately recovered,
production and operating costs, the amount and timing of future development
expenditures and future oil and gas prices may all differ from those assumed
in such estimates.



                                      -62-





<PAGE> 65
                         TMBR/SHARP DRILLING, INC.


                       Notes to Financial Statements


     In accordance with the Securities and Exchange Commission, the Company's
estimates of future net cash flows from the Company's proved properties and
the representative value thereof are made using oil and natural gas prices in
effect as of the dates of such estimates and are held constant throughout the
life of the properties.  The year end prices used in estimating the future
net cash flows at March 31, 2002, 2001 and 2000 were as follows: $23.36,
$28.16 and $27.08 per barrel of oil, respectively, and $3.318, $5.861 and
$2.467 per Mcf for natural gas, respectively.

     The following sets forth proved oil and gas reserves at March 31, 2002,
2001 and 2000:
<TABLE>
<CAPTION>
                                           2002                    2001                       2000
                                   ---------------------    ---------------------     ---------------------
                                     Oil         Gas          Oil         Gas           Oil         Gas
                                    MBbls        MMcf        MBbls        MMcf         MBbls        MMcf
                                   -------     ---------    -------     ---------     -------     ---------
                                                               (In thousands)
<S>                                <C>        <C>           <C>          <C>           <C>        <C>
Proved Reserves:

  Beginning of Year                1,081.5     6,295.1       605.0       2,948.1       415.4       4,486.1

  Revisions of previous
    estimates                       (192.7)   (1,124.7)      372.2       1,472.4        93.6      (1,801.5)

  Improved recovery                   --          --          --            --           --           --

  Purchases of minerals in
    place and extensions             388.7     2,343.1       213.2       2,303.3       174.2         875.4

  Sales of minerals in place          --          --          --            --           --           --

  Production                        (127.4)     (707.9)     (108.9)       (428.7)      (78.2)       (611.9)
                                   -------     -------     -------       -------       -----       -------
  End of year                      1,150.1     6,805.6     1,081.5       6,295.1       605.0       2,948.1
                                   =======     =======     =======       =======       =====       =======

Proved Developed Reserves:

  Beginning of year                1,081.5     6,295.1       605.0       2,948.1       415.4       4,486.1
                                   -------     -------     -------       -------       -----       -------
  End of year                        994.7     6,013.9     1,081.5       6,295.1       605.0       2,948.1
                                   =======     =======     =======       =======       =====       =======
</TABLE>
     The downward revisions of previous estimates for the year ended March
31, 2002 is primarily due to the decrease in crude oil and natural gas
prices. The upward revisions for the year ended March 31, 2001, is primarily
due to the increase in crude oil and natural gas prices.

                                      -63-

<PAGE> 66
                         TMBR/SHARP DRILLING, INC.

                       Notes to Financial Statements


                                                    March 31,
                                             -----------------------
                                               2002           2001
                                               ----           ----
                                                  (In thousands)

     Standardized Measure

       Future cash inflows                   $45,533        $61,866

       Future production and
         development costs                   (10,614)       (11,808)
                                              -------        -------
       Future net cash flows                  34,919         50,058

       10% discount factor                   (13,165)       (20,739)
                                              -------        -------
       Discounted future net cash flows       21,754         29,319

       Discounted income taxes                   --             --
                                              -------        -------
       Standardized Measure                  $21,754        $29,319
                                              =======        =======


                                     2002       2001          2000
                                     ----       ----          ----
                                            (In thousands)

     Standardized measure,
       beginning of year           $29,319     $10,486      $ 6,449

     Revisions
          Prices and costs         (13,707)     12,646        1,960
          Accretion of discount      2,932       1,049          645
                                    -------     -------     --------
     Net revisions                 (10,775)     13,695        2,605

     Discoveries and additions       6,997       9,229        3,676
     Production                     (3,787)     (4,091)      (2,244)
                                    -------     -------      -------
     Standardized measure,
       end of year                 $21,754     $29,319      $10,486
                                    =======     =======      =======




                                      -64-





<PAGE> 67
                         TMBR/SHARP DRILLING, INC.

                       Notes to Financial Statements


(10) Supplementary Quarterly Financial Data (Unaudited)


<TABLE>
<CAPTION>
                                             First        Second         Third     Fourth     Total
                                           ---------     ---------     ---------  ---------  --------
                                                     (In thousands, except per share amounts)

<S>                                        <C>           <C>           <C>        <C>        <C>
2001
    Total Revenues . . . . . . . . . . .   $  8,262      $  9,509      $ 10,254   $ 13,452   $ 41,477
                                            ========      ========      ========   ========  =========
    Net income attributable
        to common stock  . . . . . . . .   $  1,072      $  1,640      $  2,078   $  3,518   $  8,308
                                            ========      ========      ========   ========   ========

    Net income per share:
        Basic  . . . . . . . . . . . . .   $   0.22      $   0.33      $   0.42   $   0.71   $   1.67
                                            ========      ========      ========   ========   ========
        Diluted  . . . . . . . . . . . .       0.20          0.30          0.38       0.65       1.54
                                            ========      ========      ========   ========   ========

2002
    Total Revenues . . . . . . . . . . .   $ 15,027      $ 15,559      $ 12,110   $  9,524   $ 52,220
                                            ========      ========      ========   ========   ========
    Net income (loss) attributable
        to common stock  . . . . . . . .   $  5,315      $  5,256      $  2,624   $ (3,379)  $  9,816
                                            ========      ========      ========   ========   ========

    Net income (loss) per share:
        Basic  . . . . . . . . . . . . .   $   1.04      $   1.03      $   0.50   $  (0.63)  $   1.88
                                            ========      ========      ========   ========   ========
        Diluted  . . . . . . . . . . . .   $   0.97      $   0.96      $   0.48   $  (0.60)  $   1.79
                                            ========      ========      ========   ========   ========
</TABLE>












                                      -65-





<PAGE> 68




Item 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
         AND FINANCIAL DISCLOSURE

     As reported in our Form 8-K Report dated May 22, 2002, we dismissed
Arthur Andersen, LLP as our independent accountant, effective May 22, 2002.
The decision to dismiss Andersen was recommended by the Audit Committee and
by the Board of Directors on May 21, 2002.  Andersen's reports on our
financial statements for the two fiscal years ended March 31, 2000 and March
31, 2001 did not contain an adverse opinion or disclaimer of opinion and were
not qualified or modified as to uncertainty, audit scope or accounting
principles.  During the two fiscal years ended March 31, 2000 and March 31,
2001 and the period from April 1, 2001 through May 22, 2002, there were no
disagreements between TMBR/Sharp and Andersen on any matter of accounting
principles or practices, financial statement disclosure, or auditing scope or
procedure, which disagreements, if not resolved to the satisfaction of
Andersen, would have caused it to make reference to the subject matter of the
disagreements in connection with its report.  Andersen furnished to
TMBR/Sharp a letter addressed to the SEC stating that it agreed with the
statements made in our Form 8-K Report.

     As further reported in our Form 8-K Report dated June 3, 2002, KPMG LLP
was engaged as our new independent accountant, effective June 3, 2002.  The
decision to engage KMPG was recommended and approved by our Audit Committee
and the Board of Directors on June 3, 2002. During the two fiscal years
ending March 31, 2000 and March 31, 2001 and the period from April 1, 2001 to
June 3, 2002, we did not consult KPMG regarding the application of accounting
principles to a specific transaction, either completed or proposed, or the
type of audit opinion that might be rendered on our financial statements, or
any matter that was either the subject of a disagreement or a reportable
event.



















                                      -66-





<PAGE> 69
                                 PART III

Item 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     The directors and officers of the Company at June 7, 2002 were as
follows:

                                                                   Director
                                                                 or Officer
     Name                 Age        Position with Company          Since
     ----                 ---        ---------------------       ----------
Thomas C. Brown            75   Chairman of the Board of Directors
                                  and Chief Executive Officer        1982

David N. Fitzgerald (1)(2) 79   Director                             1984

Michael M. Cone (2)        64   Director                             2001

Raymond E. Batchelor (1)   68   Director                             2001

James B. Taylor (2)        64   Director                             2001

Jeffrey D. Phillips        41   President                            1997

Don H. Lawson              63   Vice President - Operations          1992

Patricia R. Elledge        44   Controller/Treasurer                 1994

James M. Alsup             65   Secretary                            1982

--------------------------
(1)  Member of Compensation Committee

(2)  Member of Audit Committee

     Directors of the Company serve until the annual meeting of stockholders
to be held in August, 2002, and until their successors in office are elected
and qualified.  Each officer is appointed annually by the Company's Board of
Directors to serve at the Board's discretion and until his successor in
office is elected and qualified.

     Mr. Brown has served as a Director of the Company since 1982.  He is
presently Chairman of the Board of Directors and Chief Executive Officer of
the Company and has served in such capacities since 1990.  Mr. Brown is also
a Director of Tom Brown, Inc., the former parent of the Company.








                                      -67-





<PAGE> 70
     Mr. Fitzgerald has served as a Director of the Company since 1984.  He
is the President and a shareholder of Dave Fitzgerald, Inc., a privately held
oilfield equipment sales company that Mr. Fitzgerald has owned and operated
since 1963.

     Mr. Cone has served as a Director of the Company since April, 2001.
Since 1985, he has been the majority owner and Chairman of Tri-C Resources,
Inc. an independent oil and gas exploration company.

     Mr. Batchelor has served as a Director of the Company since April, 2001.
He has been President of BHC Pipe & Equipment Company since 1987.

     Mr. Taylor has served as a Director of the Company since April, 2001.
He is currently a Director of Willbros Group, Inc.  From 1997 to 2000 he was
Chairman of Solana Petroleum Corporation.  From 1996 to 1998 he was a
Director of Arakis Energy Corporation.  From 1993 to 1996 he was Executive
Vice President of Occidental Oil and Gas Corporation.

     Mr. Phillips has been employed by the Company since 1995.  He has been
President since April 1, 2001.  He was Vice President - Production from 1997
to 2001.  From 1993 to 1995 he was Operations Manager for Staley Operating
Co., a privately held exploration and production company.

     Mr. Lawson has been employed by the Company since 1967.  He has been the
Vice President - Operations of the Company since 1992.

     Ms. Elledge was employed by the Company from September, 1989 to
December, 1993 when she resigned to relocate.  Ms. Elledge returned to the
Company in September, 1994 in her current capacity as Controller - Treasurer.

     Mr. Alsup has been the Secretary of the Company since 1982.  He has been
a partner in the law firm of Lynch, Chappell & Alsup since 1970.

     There are no family relationships between any of the Directors or
officers of the Company.

Item 11.  EXECUTIVE COMPENSATION

     The discussion under "Executive Compensation" in the Company's
definitive proxy statement for the 2002 annual meeting of shareholders is
incorporated herein by reference.

Item 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     The discussion under "Principal Shareholders" and the information
appearing under "Election of Directors" in the Company's definitive proxy
statement for the 2002 annual meeting of shareholders is incorporated herein
by reference.





                                      -68-





<PAGE> 71
Item 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     The discussion under "Executive Compensation - Certain Transactions" in
the Company's definitive proxy statement for the 2002 annual meeting of
stockholders is incorporated herein by reference.




                                  PART IV

Item 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

                                                                        Page
                                                                        ----
  (a)1.   See Index to Financial Statements at Item 8                    38

  (a)2.   Financial Statement Schedules
            Years ended March 31, 2002, 2001 and 2000

          Schedule II - Valuation and Qualifying Accounts . . . .        73

               All other schedules are omitted as the
               required information is inapplicable or the
               information is presented in the Financial
               Statements or related notes.

  (a)3.   Exhibits:

      Exhibit 3.1 - Articles of Incorporation of the Company, as amended.
          (Incorporated by reference to Exhibit 3.1 in Registrant's Annual
          Report on Form 10-K dated June 28, 1991)

      Exhibit 3.2 - Bylaws of the Registrant, as amended.  (Incorporated
          by reference to Exhibit 3.2 in Registrant's Annual Report on Form
          10-K dated June 27, 1994)

          Executive Compensation Plans and Arrangements
          ---------------------------------------------
          (Exhibits 10.1 through and including Exhibit 10.20 constitute
          executive compensation plans and arrangements of the Registrant)

      Exhibit 10.1 - Incentive Stock Option Plan. (Incorporated by
          reference to Exhibit 10.3 in Registrant's Registration Statement on
          Form 10 as amended, effective October 9, 1984)

      Exhibit 10.2 - Nonqualified Stock Option Agreement dated August
          29, 1990, between Thomas C. Brown and the Registrant.
          (Incorporated by reference to Exhibit 10.15 in Registrant's Annual
          Report on form 10-K dated June 25, 1993)



                                      -69-





<PAGE> 72

      Exhibit 10.3 - Nonqualified Stock Option Agreement dated August
          30, 1988, between Joe G. Roper and the Registrant.  (Incorporated
          by reference to Exhibit 10.17 in Registrant's Annual Report on Form
          10-K dated June 25, 1993)

      Exhibit 10.4 - Incentive Stock Option Agreement dated November 16,
          1993 between Joe G. Roper and the Registrant.  (Incorporated by
          reference to Exhibit 10.5 in Registrant's Annual Report on Form 10-
          K dated June 27, 1994)

    Exhibit 10.5 - Incentive Stock Option Agreement dated December 4,
          1992 between Patricia R. Elledge and the Registrant.  (Incorporated
          by reference to Exhibit 10.20 in Registrant's Annual Report on Form
          10-K dated June 25, 1993)

    Exhibit 10.6 - Incentive Stock Option Agreement dated December 4,
          1992 between Don H. Lawson and the Registrant.  (Incorporated by
          reference to Exhibit 10.21 in Registrant's Annual Report on Form
          10-K dated June 25, 1993)

      Exhibit 10.7 - Incentive Stock Option Agreement dated November 16,
          1993 between Don H. Lawson and the Registrant.  (Incorporated by
          reference to Exhibit 10.10 in Registrant's Annual Report on Form
          10-K dated June 27, 1994)

      Exhibit 10.8 - 1994 Stock Option Plan.  (Incorporated by reference
          to Exhibit 10.10 in Registrant's Annual Report on Form 10-K dated
          June 28, 1995)

      Exhibit 10.9 - TMBR/Sharp Drilling, Inc. Employee Retirement Plan.
          (Incorporated by reference to Exhibit 10.11 in Registrant's Annual
          Report on Form 10-K dated June 28, 1995)

      Exhibit 10.10 - 1998 Stock Option Plan (Incorporated by reference to
          Exhibit 10.1 in Registrant's Quarterly Report on Form 10-Q dated
          November 12, 1998)

      Exhibit 10.11 - Incentive Stock Option Agreement dated September 1,
          1998, between Don H. Lawson and the Registrant.  (Incorporated by
          reference to Exhibit 10.18 in Registrant's Annual Report on Form
          10-K dated June 29, 1999)

      Exhibit 10.12 - Incentive Stock Option Agreement dated September 1,
          1998, between Jeffrey D. Phillips and the Registrant.
          (Incorporated by reference to Exhibit 10.19 in Registrant's Annual
          Report on Form 10-K dated June 29, 1999)






                                      -70-





<PAGE> 73
      Exhibit 10.13 - Incentive Stock Option Agreement dated September 1,
          1998, between Patricia R. Elledge and the Registrant.
          (Incorporated by reference to Exhibit 10.20 in Registrant's Annual
          Report on Form 10-K dated June 29, 1999)

      Exhibit 10.14 - Incentive Stock Option Agreement dated September 1,
          1998, between Joe G. Roper and the Registrant.  (Incorporated by
          reference to Exhibit 10.21 in Registrant's Annual Report on Form
          10-K dated June 29, 1999)

      Exhibit 10.15 - Incentive Stock Option Agreement dated September 1,
          1998, between Thomas C. Brown and the Registrant.  (Incorporated by
          reference to Exhibit 10.22 in Registrant's Annual Report on Form
          10-K dated June 29, 1999)

      Exhibit 10.16 - First Amended and Restated Nonstatutory Stock Option
          Agreement dated September 1, 1998, between Patricia R. Elledge and
          the Registrant.  (Incorporated by reference to Exhibit 10.23 in
          Registrant's Annual Report on Form 10-K dated June 29, 1999)

      Exhibit 10.17 - First Amended and Restated Nonstatutory Stock Option
          Agreement dated September 1, 1998, between Jeffrey D. Phillips and
          the Registrant.  (Incorporated by reference to Exhibit 10.24 in
          Registrant's Annual Report on Form 10-K dated June 29, 1999)

      Exhibit 10.18 - First Amended and Restated Nonstatutory Stock Option
          Agreement dated September 1, 1998, between Joe G. Roper and the
          Registrant.  (Incorporated by reference to Exhibit 10.25 in
          Registrant's Annual Report on Form 10-K dated June 29, 1999)

      Exhibit 10.19 - First Amended and Restated Nonstatutory Stock Option
          Agreement dated September 1, 1998, between Thomas C. Brown and the
          Registrant.  (Incorporated by reference to Exhibit 10.26 in
          Registrant's Annual Report on Form 10-K dated June 29, 1999)

      Exhibit 10.20 - Directors' Fee Stock Plan (Incorporated by reference to
          Exhibit 10.20 of Registrant's Annual Report on Form 10-K dated June
          15, 2001)

      Exhibit 10.21 - Form of Stock Purchase Agreement, dated as of February
          13, 1997, between the Registrant and the stockholders named therein
          (Incorporated by reference to Exhibit 10.1 in the Registrant's
          Registration Statement on Form S-3, No. 333-23391)

      Exhibit 10.22 - Second Amended and Restated Loan Agreement dated June
          26, 2000 between Wells Fargo Bank, Texas N. A. and the Registrant.
          (Incorporated by reference to Exhibit 10.1 in Registrant's
          Quarterly Report on Form 10-Q dated August 9, 2000)





                                      -71-





<PAGE> 74
     *Exhibit 23.1 - Consent of Arthur Andersen LLP

     *Exhibit 23.2 - Consent of KPMG LLP

     *Exhibit 23.3 - Consent of Joe C. Neal & Associates

----------------------------------
*Filed herewith

(b)  No reports on Form 8-K were filed during the last quarter of fiscal
2002.










































                                      -72-





<PAGE> 75

                                                                Schedule II
                                                                -----------



                         TMBR/SHARP DRILLING, INC.

                     Valuation and Qualifying Accounts

                 Years ended March 31, 2002, 2001 and 2000

                              (In thousands)



                                                   Recoveries
                         Balance at   Additions    or other     Balance
                         beginning    charged to   reserve      at end
    Description          of year      operations   reductions   of year
---------------------    ----------   ----------   ----------   -------

Allowance for
  doubtful accounts:

          2002            $ 1,227      $  174        $    --    $ 1,401

          2001            $ 1,486      $  125        $   384    $ 1,227

          2000            $ 1,349      $  137        $    --    $ 1,486























                                      -73-





<PAGE> 76
                                SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.

                                        TMBR/SHARP DRILLING, INC.



June 25, 2002                           By /s/ Thomas C. Brown
                                           --------------------------------
                                           Thomas C. Brown, Chairman
                                           of the Board of Directors

     Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities on the dates indicated.


June 25, 2002                               /s/ Thomas C. Brown
                                           --------------------------------
                                           Thomas C. Brown, Chairman
                                           of the Board of Directors
                                           (Principal Executive Officer)


June 25, 2002                               /s/ Jeffrey D. Phillips
                                           --------------------------------
                                           Jeffrey D. Phillips, President


June 25, 2002                               /s/ Patricia R. Elledge
                                           --------------------------------
                                           Patricia R. Elledge, Controller/
                                           Treasurer (Principal Financial
                                           Officer)


June 25, 2002                               /s/ David N. Fitzgerald
                                           --------------------------------
                                           David N. Fitzgerald, Director


June 25, 2002                               /s/ Michael M. Cone
                                           --------------------------------
                                           Michael M. Cone, Director


June 25, 2002                               /s/ Raymond E. Batchelor
                                           -------------------------------
                                           Raymond E. Batchelor, Director


June 25, 2002                               /s/ James B. Taylor
                                           -------------------------------
                                           James B. Taylor, Director

                                      -74-
<PAGE> 77
                             INDEX TO EXHIBITS




                               Description                        Page No.
                               -----------                        --------


Exhibit 3.1    Articles of Incorporation of the Company, as
               amended.  (Incorporated by reference to
               Exhibit 3.1 in Registrant's Annual Report on
               Form 10-K dated June 28, 1991)

Exhibit 3.2    Bylaws of the Company, as amended.  (Incor-
               porated by reference to Exhibit 3.2 in
               Registrant's Annual Report on Form 10-K dated
               June 27, 1994)

               Executive Compensation Plans and Arrangements
               ---------------------------------------------
               (Exhibits 10.1 through and including Exhibit
               10.20 constitute executive compensation plans
               and arrangements of the Registrant)

Exhibit 10.1   Incentive Stock Option Plan (Incorporated by
               reference to Exhibit 10.3 in Registrant's
               Registration Statement on Form 10, as amended,
               effective October 9, 1984)

Exhibit 10.2   Nonqualified Stock Option Agreement dated
               August 29, 1990, between Thomas C. Brown and
               the Registrant.  (Incorporated by reference to
               Exhibit 10.15 in Registrant's Annual Report on
               Form 10-K dated June 25, 1993)

Exhibit 10.3   Nonqualified Stock Option Agreement dated
               August 30, 1988, between Joe G. Roper and the
               Registrant.  (Incorporated by reference to
               Exhibit 10.17 in Registrant's Annual Report on
               Form 10-K dated June 25, 1993)

Exhibit 10.4   Incentive Stock Option Agreement dated
               November 16, 1993 between Joe G. Roper and the
               Registrant.  (Incorporated by reference to
               Exhibit 10.5 in Registrant's Annual Report on
               Form 10-K dated June 27, 1994)






                                      -75-





<PAGE> 78
Exhibit 10.5   Incentive Stock Option Agreement dated
               December 4, 1992 between Patricia R. Elledge
               and the Registrant.  (Incorporated by
               reference to Exhibit 10.20 in Registrant's
               Annual Report on Form 10-K dated June 25,
               1993)

Exhibit 10.6   Incentive Stock Option Agreement dated
               December 4, 1992 between Don H. Lawson and the
               Registrant.  (Incorporated by reference to
               Exhibit 10.21 in Registrant's Annual Report on
               Form 10-K dated June 25, 1993)

Exhibit 10.7   Incentive Stock Option Agreement dated
               November 16, 1993 between Don H. Lawson and
               the Registrant.  (Incorporated by reference to
               Exhibit 10.10 in Registrant's Annual Report on
               Form 10-K dated June 27, 1994)

Exhibit 10.8   1994 Stock Option Plan.  (Incorporated by
               reference to Exhibit 10.10 in Registrant's
               Annual Report on Form 10-K dated June 28,
               1995)

Exhibit 10.9   TMBR/Sharp Drilling, Inc. Employee Retirement
               Plan.  (Incorporated by reference to Exhibit
               10.11 in Registrant's Annual Report on Form
               10-K dated June 28, 1995)

Exhibit 10.10  1998 Stock Option Plan (Incorporated by reference
               to Exhibit 10.1 in Registrant's Quarterly
               Report on Form 10-Q dated November 12, 1998)

Exhibit 10.11  Incentive Stock Option Agreement dated September 1,
               1998, between Don H. Lawson and the
               Registrant.  (Incorporated by reference to
               Exhibit 10.18 in Registrant's Annual Report on
               Form 10-K dated June 29, 1999)

Exhibit 10.12  Incentive Stock Option Agreement dated September 1,
               1998, between Jeffrey D. Phillips and the
               Registrant.  (Incorporated by reference to
               Exhibit 10.19 in Registrant's Annual Report on
               Form 10-K dated June 29, 1999)

Exhibit 10.13  Incentive Stock Option Agreement dated September 1,
               1998, between Patricia R. Elledge and the
               Registrant.  (Incorporated by reference to
               Exhibit 10.20 in Registrant's Annual Report on
               Form 10-K dated June 29, 1999)



                                      -76-





<PAGE> 79
Exhibit 10.14  Incentive Stock Option Agreement dated September 1,
               1998, between Joe G. Roper and the Registrant.
               (Incorporated by reference to Exhibit 10.21 in
               Registrant's Annual Report on Form 10-K dated
               June 29, 1999)

Exhibit 10.15  Incentive Stock Option Agreement dated September 1,
               1998, between Thomas C. Brown and the
               Registrant.  (Incorporated by reference to
               Exhibit 10.22 in Registrant's Annual Report on
               Form 10-K dated June 29, 1999)

Exhibit 10.16  First Amended and Restated Nonstatutory Stock Option
               Agreement dated September 1, 1998, between
               Patricia R. Elledge and the Registrant.
               (Incorporated by reference to Exhibit 10.23 in
               Registrant's Annual Report on Form 10-K dated
               June 29, 1999)

Exhibit 10.17  First Amended and Restated Nonstatutory Stock Option
               Agreement dated September 1, 1998, between
               Jeffrey D. Phillips and the Registrant.
               (Incorporated by reference to Exhibit 10.24 in
               Registrant's Annual Report on Form 10-K dated
               June 29, 1999)

Exhibit 10.18  First Amended and Restated Nonstatutory Stock Option
               Agreement dated September 1, 1998, between Joe
               G. Roper and the Registrant. (Incorporated by
               reference to Exhibit 10.25 in Registrant's
               Annual Report on Form 10-K dated June 29,
               1999)

Exhibit 10.19  First Amended and Restated Nonstatutory Stock Option
               Agreement dated September 1, 1998, between
               Thomas C. Brown and the Registrant.
               (Incorporated by reference to Exhibit 10.26 in
               Registrant's Annual Report on Form 10-K dated
               June 29, 1999)

Exhibit 10.20  Directors' Fee Stock Plan (Incorporated by
               reference to Exhibit 10.20 in Registrant's
               Annual Report on Form 10-K dated June 15, 2001)

Exhibit 10.21  Form of Stock Purchase Agreement, dated as of
               February 13, 1997, between the Registrant and
               the stockholders named therein (Incorporated
               by reference to Exhibit 10.1 in the
               Registrant's Registration Statement on Form S-
               3, No. 333-23391)



                                      -77-





<PAGE> 80
Exhibit 10.22  Second Amended and Restated Loan Agreement dated
               June 26, 2000 between Wells Fargo Bank, Texas
               N. A. and the Registrant.  (Incorporated by
               reference to Exhibit 10.1 in Registrant's
               Quarterly Report on Form 10-Q dated August
               9,2000)

*Exhibit 23.1  Consent of Arthur Andersen LLP                      79

*Exhibit 23.2  Consent of KPMG LLP                                 80

*Exhibit 23.3  Consent of Joe C. Neal & Associates                 81

--------------------
     *Filed herewith






































                                      -78-





<PAGE> 81
                                                                  Exhibit 23.1


                 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS



     As independent public accountants, we hereby consent to the
incorporation by reference of our report dated May 18, 2001 into the
Company's previously filed Registration Statements on Form S-8 (registration
No. 33-46699, No. 33-89878 and No. 333-32028) and the Company's previously
filed registration statement on Form S-3, No. 333-23391.





                                        /s/   ARTHUR ANDERSEN LLP


Dallas, Texas,
  June 15, 2001




This consent was furnished by Arthur Andersen LLP in connection with our 2001
Form 10-K.  We were unable to obtain a currently dated consent from Arthur
Andersen LLP.
























                                      -79-





<PAGE> 82
                                                               Exhibit 23.2


                      CONSENT OF INDEPENDENT AUDITORS



The Board of Directors and Stockholders
TMBR/Sharp Drilling, Inc.

     We consent to the incorporation by reference in the registration
statements (No.33-46699, No. 33-89878 and No.333-32028) on Form S-8 and the
registration statement (No. 333-23391) on Form S-3, of TMBR/Sharp Drilling,
Inc. of our report dated June 24, 2002 with respect to the balance sheet of
TMBR/Sharp Drilling, Inc. as of March 31, 2002, and the related statements of
operations, stockholders' equity, and cash flows for the year then ended,
which appears in the March 31, 2002 annual report on Form 10-K of TMBR/Sharp
Drilling, Inc.





                                             /s/   KPMG LLP

Midland, Texas
June 24, 2002


























                                      -80-





<PAGE> 83
                                                               Exhibit 23.3


                CONSENT OF INDEPENDENT PETROLEUM ENGINEERS



               As independent petroleum engineers, we hereby consent to the
incorporation by reference of our report included in this Form 10-K into the
Company's previously filed Registration Statements on Form S-8 (registration
No. 33-46699, No. 33-898878 and No. 333-32028) and the Company's previously
filed registration statement on Form S-3, No. 333-23391.





                                              /s/  JOE C. NEAL & ASSOCIATES


Midland, Texas
  June 25, 2002































                                      -81-